vyEPA


Demonstration of
Wellman-Lord/Allied
Chemical FGD
Technology:
Demonstration Test
First Year Results

Interagency
Energy/Environment
R&D Program Report

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                  RESEARCH REPORTING SERIES


Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional  grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:

    1.  Environmental Health Effects Research

    2.  Environmental Protection Technology

    3.  Ecological Research

    4.  Environmental Monitoring

    5.  Socioeconomic Environmental Studies

    6.  Scientific and Technical Assessment Reports  (STAR)

    7.  Interagency  Energy-Environment Research and Development

    8.  "Special" Reports

    9.  Miscellaneous Reports

This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort  funded  under the 17-agency  Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems.  The  goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the  transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
                        EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.

This document is available to the public through the National Technical Informa-
tion Service. Springfield, Virginia 22161.

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                                         EPA-600/7-79-014b

                                             September 1979
   Demonstration of Wellman-Lord/Allied
Chemical FGD Technology:  Demonstration
              Test First Year Results
                              by

                  R. C. Adams, J. Cotter, and S. W. Mulligan

                           TRW, Inc.
                     201 N. Roxboro Street, Suite 200
                     Durham, North Carolina 27701
                       Contract No. 68-02-1877
                     Program Element No. EHE624A
                   EPA Project Officer: Charles J. Chatlynne
                 Industrial Environmental Research Laboratory
               Office of Environmental Engineering and Technology
                     Research Triangle Park, NC 27711
                           Prepared for

                 U.S. ENVIRONMENTAL PROTECTION AGENCY
                    Office of Research and Development
                       Washington, DC 20460

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                                 ABSTRACT

      A full scale unit to demonstrate the Wellman-Lord/Allied Chemical
process for desulfurizing flue gas was installed at Northern Indiana Public
Service Company's 115 MW coal-fired Unit No. 11 located at the Dean H.
Mitchell Station.  A Test Program was conducted during a year of demonstra-
tion beginning September 16, 1977, to evaluate the capabilities of the
Wellman-Lord/Allied Chemical process.  During the demonstration year,
operating experience was limited due to both boiler and FGD related
operating problems.  The FGD plant had a reliability factor of 50% (hours
operated/hours called upon to operate).  S02 removal efficiency averaged
89%.  Economic performance was distorted by considerable off normal operation
of the boiler which limited utilization of the FGD plant and by partial
operation of the FGD plant during which a substantial part of the operating
costs continued to accrue.  There were two major effects on boiler operation
from retrofit of the FGD plant.  These are (1) a boiler derating of 9% from
the consumption of steam by the FGD plant and (2) the design capacity of the
FGD unit which limits the boiler to no more than 80% of full load except for
short periods of time.

      The Test Program was extended for at least six months following comple-
tion of a number of projects aimed at eliminating or minimizing the problems
that have limited utilization of the FGD plant.
                                     11

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                               CONTENTS

Abstract	   ii
Figures	   iv
Tables   	   v
Executive Summary  	   vii
    1.  Introduction	   1-1
          Background	   1-1
          Program Status 	   1-2
    2.  Demonstration Year Overview   	   2-1
          Program Objectives & Scope  	   2-1
          Process Description  	   2-2
          Performance Evaluation Methodology  	   2-5
          Scope of Follow-On Program	   2-8
    3.  Test Results	   3-1
          Summary	   3-1
          S02 Removal  	   3-4
          FGD Plant Dependability  	   3-8
          Process Economics  	   3-24
          Raw Material & Energy Consumption   	   3-24
          Boiler Performance 	   3-29
    4.  Evaluation Methods 	   4-1
          Evaluation Goals 	   4-1
          The Test System	   4-2
          Methodology	   4-7
          Quality Control	   4-11
Appendices
    A.  Data Base	   A-l
    B.  Instrument Reliability 	   B-l
    C.  Method for Estimating Flue Gas Volume	   C-l
                                    iii

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                                   FIGURES

Number                                                            Page
 2.1    Block Flow Diagram of Major Process Steps                 2-4
 3.1    S0« Removal Performance on a Monthly Basis                3-5
 3.2    S0« Removal Frequency Distribution                        3-7
 3.3    NIPSCO Boiler Availability & FGD Operating Time           3-9
 4.1    Schematic Diagram of Measuring System                     4-3
 4.2    Schematic Diagram of Mitchell  No. 11 Boiler               4-5
        Sampling Positions
 4.3    Schematic Diagram of FGD Plant                            4-6
 4.4    Data Flow for Evaluation                                  4-8
                                      iv

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                                TABLES
Number
Page
 2.1   Demonstration Year Operating Periods                           2-7
 3.1   A Summary of the Boiler and FGD Plant Operating                3-2
       Parameters
 3.2   A Summary of the Boiler and FGD Plant Operating                3-3
       Parameters - Metric Units
 3.3   Definition of Viability Indices                                3-11
 3.4   Hours FGD Plant Available & Called Upon                        3-10
 3.5   Boiler & FGD Plant Operating History                           3-14
 3.6   Plant Improvement Projects                                     3-23
 3.7   Capital Cost                                  *                3-25
 3.8   Projected Annual Operating Cost                                3-27
 3.9   Actual Annual Operating Cost                                   3-28
 3.10  FGD Plant Energy Usage                                         3-29
 3.11  Boiler Load Distribution                                       3-31
 3.12  Flue Gas Characteristics                                       3-33
 3.13  Boiler Outlet Flue Gas Temperatures                            3-33
 3.14  Fly Ash Loading                                                3-34
 3.15  S03 & S02 Removal                                              3-35
 4.1   Test Parameters                                                4-4
 4.2   Evaluation Data Inputs                                         4-9
 4.3   Flue Gas Composition                                           4-10
 4.4   Continuous Analyzer Calibration                                4-11
 4.5   Instrument Calibrations                                        4-12
 A.I   Boiler Performance Data                                        A-2
 A.2   By-Product Production and Raw Material Consumption             A-10

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                            TABLES (Continued)

Number                                                                 Page
 A.3   Natural Gas Consumption for the Month of December 1978          A-ll
 A.4   Natural Gas Consumption for the Month of August 1978            A-12
 A.5   Analytical Results - Purge Solids                               A-13
 A.6   Significance and Source of Data Listed in Table 3.1             A-14
 B.I   Instrument Down Time - S02 Removal                              B-2
 B.2   Instrument Down Time - Water Analyzer                           B-4
 B.3   DAS Channel Down Time                                           B-5
                                   VI

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                             EXECUTIVE SUMMARY

      A full-scale unit to demonstrate the WeiIman-Lord/Allied Chemical
process for desulfurizing flue gas was installed on a coal-fired boiler
belonging to Northern Indiana Public Service Company (NIPSCO).  An Accept-
ance Test for verifying that the performance guarantees could be met was
successfully completed on September 15, 1977.  A scheduled year of
demonstration was begun on September 16, 1977.  This report presents the
results of a Test Program conducted during the demonstration year to
evaluate the capabilities of the Wellman-Lord/Allied Chemical process.
This regenerate process employs sodium sulfite for scrubbing the flue gas
and thermal regeneration for recovery of the SCL.  The recovered SCL is
reduced to produce a molten sulfur product.

      The FGD plant operated a total of about 90 days during the year.
Operation was sporadic due to both boiler and FGD problems.  The principal
boiler problems that prevented FGD operation were unstable flue gas flows
and steam pressures resulting from poor coal quality, coal feeding problems,
and from poor quality of the boiler feedwater.  Major FGD plant interrup-
tions occurred as a result of booster blower failures.  Prominent among the
failures were imbalance of the blower due to flyash buildup on the fan
blades and subsequent corrosion and erosion of the blades.  The problem
was aggravated by frequent operation at flue gas temperatures below the
dew point.  Eventual reblading of the booster blower was required.  The
longest period of sustained operation of the FGD plant was 42 days and
occurred after the coal feeding and the boiler feedwater problems had
been largely solved and after reblading of the booster blower.

      The FGD plant had a reliability factor of 50% (hours operated/hours
called upon to operate) despite only 90 days of total operation.  Reliability
is the ability of the FGD plant to operate within specific limits of boiler
operation.  There was considerable operation of the boiler in an off normal
condition as a result of the coal feeding and boiler feedwater problems.
                                     Vll

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Overall, the boiler was operated a total of 325 days of the year but for only
179 days at stable enough conditions for operation of the FGD plant.

     The SOp removal performance guarantee of 90% was met or exceeded 45% of
the time, based on one-hour averaging times.  The average removal efficiency
was 89% and was met or exceeded 66% of the time.  The operating set point was
for maintaining a 90% reduction in the S02 concentration on a wet volume basis
This equates to about 89% removal, after the dilution effects resulting from
added water in the flue gas are taken into account.

     Economic performance during the Demonstration year was distorted by
considerable off normal operation of the boiler which limited utilization
of the FGD plant and by partial operation of the FGD plant (not counted as
operating time) during which utility and raw material costs continued to
accrue.  The annualized unit cost of operating the FGD plant amounted to
15.81  mills/kWh compared with a projected annual unit cost of 14.86 mills/
kWh.  The high costs despite the low utilization of the FGD plant reflects
fixed charges and standby operating costs such as labor.

     The effect on boiler operation from the FGD installation was threefold.
First, substantial electric power is not available for distribution as a
result of FGD plant energy usage, primarily as steam.  During a 42 day
sustained run of the FGD plant, the power not available amounted to nearly
11 megawatts.   Second, the boiler was limited to a sustained load of 92 gross
megawatts by FGD capacity limitations.   Operation at higher loads is possible
for only limited periods of time.   During the same 42 day run, which was
after correction of the coal feeding and the water quality problems, boiler
gross output averaged 79 MW while the FGD plant was operating.  Without the
FGD plant, the boiler could have generated 89 MW of electric power with the
same heat input.   Third, there is also a lower limit of operation below which
the S02 reduction unit will  not operate.   This establishes minimum limits for
boiler load or for coal  sulfur content.
                                    viii

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     About midway in the demonstration year, booster blower problems prompted
the initiation of a series of improvements to minimize FGD down time.   The
major improvements included boiler air preheater modifications and duct
insulation to raise the flue gas temperature above the dew point and included
rebladlng of the booster blower fan.  Since these projects could not be com-
pleted before the end of the demonstration year, evaluation of the demonstra-
tion unit will continue for at least another six to twelve months.  The results
of the evaluation as well as a more detailed assessment of the first year of
operation will be presented in a subsequent report.
                                      ix

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                                SECTION 1
                              INTRODUCTION

BACKGROUND

     The Environmental Protection Agency (EPA) is actively engaged in a number
of programs to demonstrate sulfur-oxide emission control processes applicable
to stationary sources.  These demonstration programs comprise operation of an
emission control unit of such size and for such duration as to permit valid
technical and economic scaling of operating factors to define the commercial
practicality of the process for potential industrial users.  Among the candi-
date processes being evaluated, which have the potential to become a major SO
                                                                             j\
emission control method, is the Wellman-Lord/Allied Chemical (WL/Allied) pro-
cess developed by Davy Powergas and Allied Chemical.  The Wellman-Lord S02
Removal Process removes the S02 from the flue gas and»recovers the sulfur
values as S02 which in turn can be used to produce (by other processes)
sulfur, sulfuric acid, or liquid S02.  The Allied Chemical Sulfur Reduction
Process reduces the S02 to produce molten sulfur.  The two processes have been
combined to demonstrate flue gas desulfurization (FGD) technology by which the
scrubbing medium is regenerated and reused and by which the product obtained
is sulfur.  This configuration will be referred to as the WL/Allied process,
although the processes are not contingent upon each other and each can be
used in other regenerable FGD configurations.  The demonstration unit has
been constructed by Davy Powergas and is being operated by Allied Chemical
under contract to the Northern Indiana Public Service Company (NIPSCO).  The
EPA shared in the cost of construction of the unit and is conducting a com-
prehensive test program.  The WL/Allied process as developed by the two design
organizations is based upon the recovery of sulfur dioxide (S02) in concentrated
form and its subsequent reduction to elemental sulfur.  The product is to be
sold to partially offset the process costs.  This is the first coal-fired
Wellman-Lord application, as well as the first joint Wellman-Lord/Allied
Chemical installation.
                                    1-1

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PROGRAM STATUS

     The WL/AH1ed F6D facility has been installed at NIPSCO's Dean H. Mitchell
Station in Gary, Indiana.  The FGD plant is designed to treat all of the flue
gas discharged from the Unit No. 11 coal-fired boiler of the Mitchell Station.
Unit No. 11 is hereafter referred to as Mitchell No. 11.  Initial startup of
the FGD plant began on July 19, 1975.  After several delays as a result of
FGD plant and boiler operational problems and boiler shutdowns for repairs,
the FGD plant was ready for acceptance testing on August 29, 1977.  The
Acceptance Test, successfully completed on September 15, 1977, demonstrated.
that the process performance guarantees could be met.'  '

     Immediately following the Acceptance Test, operation of the FGD plant
was continued for a scheduled one year of demonstration.  The intent was to
demonstrate the performance of this FGD unit for an extended period of
operation.   TRW, under contract to EPA, is providing the test services
required for evaluating the performance of the FGD plant.  This report
summarizes the results of the test program carried out during the first
year of demonstration.  A more detailed evaluation will be presented 1n a
subsequent report after all testing has been completed.

     During the demonstration year, operating experience was limited due to
both boiler and FGD related operating problems.  A plant Improvement program
was Initiated during the latter half of the demonstration year for the purpose
of minimizing the major difficulties.  The demonstration test program has been
extended for at least an additional six to twelve months to more fully
evaluate the FGD process.
'''Adams, R. C., S. J. Lutz, and S. W. Mulligan.  Demonstration of Wellman-
   Lord/Allied Chemical FGD Technology:  Acceptance Test Results.
   EPA-600/7-79-014a.  TRW  Inc., Durham, NC  January 1979.
                                   1-2

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                               SECTION 2

                      DEMONSTRATION YEAR OVERVIEW

PROGRAM OBJECTIVES & SCOPE

     The principal objectives of the test program, as originally conceived,
were as follows:

     1.   Verification of the reduction in pollutants achieved by
          the WL/Allied process FGD unit.

     2.   Validation of the estimated technical and economic
          performance of the demonstration unit.
                                                         *

     3.   Assessment of the applicability of the WL/Allied process
          to the general population of utility boilers.

Each of these objectives was partially achieved during the first year of
operation despite limited data availability as a result of several boiler
and FGD plant outages and of several periods of partial operation of the
FGD plant.  Because of the sporadic operation of the FGD plant, the test
program has been extended six to twelve months beyond the scheduled one
year of demonstration.  The additional operating time will provide a more
complete evaluation of the process 1n response to the program objectives.
The scope of the test program extension will be described later.

     This Interim report presents and evaluates the more significant
operating and performance data obtained during the first year of demonstra-
tion immediately following completion of the Acceptance Test.  Of primary
importance are S02 removal performance (Objective No. 1); reliability, energy
and raw material consumptions, product rates, operating costs and boiler
load following (Objective No. 2); and derating and other effects on the boiler
                                   2-1

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(Objective No. 3).  Only a minimum number of special tests for evaluating
the WL/AlHed process at varying boiler operating conditions were completed.
Therefore, only limited data are available for evaluating the applicability
of the process to other utility boilers (Objective No. 3).  Achievement of
Objective No. 2 1s limited with respect to load following capability and to
economic performance.  Operating costs are distorted somewhat by excessive
boiler and FGD plant outages.  The test program is being extended in expecta-
tion of fewer outages and Improved reliability which, 1f achieved, will
provide more representative cost data.

PROCESS DESCRIPTION

     Flue gas from Unit No. 11 of the D. H. Mitchell Station (Mitchell  No.
11) is delivered to the suction of the FGD plant's booster blower.  Mitchell
No. 11 1s a 115 MW pulverized coal-fired, balanced draft boiler with cold
end electrostatic predpltator (ESP) particle control.  The boiler was
designed to use a coal with a nominal sulfur content of a little above  three
percent.  The FGD unit was designed to accept flue gas at S0« concentrations
equivalent to that sulfur level in the coal.

     The WL/All1ed FGD process removes S02 from the flue gas stream by
scrubbing with an aqueous sodium sulfite/b1sulf1te solution and subsequent
thermal regeneration to recover the S02«  The liberated S0« is then reduced
to elemental sulfur which 1s sold.  The FGD unit was designed to remove 90%
of the S02 delivered with the flue gas at flue gas rates equivalent to  a
boiler load of 92 MW (80% of full boiler load).  The absorber 1s designed
to take up to about 388,000 acfm (110 MW equivalent) of flue gas but this
rate can be sustained for only a limited time because of limited capacity
of the solution regeneration part of the FGD plant.
                                   2-2

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     The critical design criteria are approximately as follows:

          Flue gas temperature, °F                 300
          Flue gas pressure, psia                  14.7
          Maximum flue gas flow, acfm            388,000
          Gross MW equivalent, MW                  110
          Steam equivalent, Ib/hr                749,000
          Design flue gas flow, acfm             320,000
          Gross MW equivalent, MW                   92
          Steam equivalent, Ib/hr                603,000
          Inlet S02 at design flow, Ib/hr         4,842
          Equivalent S02 concentration, ppmv      2,185

Any combination of flue gas volume and inlet S02 concentration that results
in an S02 feed rate greater than about 5,000 Ibs/hr for'periods up
to 83 hours is excess capacity for the recovery area.  This means that
sustained operation at excess capacity would lower the performance level  to
below 90% S02 recovery.  The absorber and the recovery area have the turn-
down capability for steady state operation down to 46 MW boiler load.
However, the lower limit for sustained operation of the reduction area is
higher than 46 MW due to operating characteristics of the reduction system.

     The block diagram (Figure 2.1) shows the process steps.  The FGD plant
accepts the total flue gas stream from the discharge of the boiler's induced
draft (ID) fans using a booster blower to force the flue gas stream through
the prescrubber and absorber.

     The prescrubber is a single-stage orifice contactor for removing
additional particulate matter.  A pump recirculates the scrubber water from
a sump back to the contactor.  In order to control a solids buildup in the
liquid stream, a purge stream is withdrawn; makeup water is added to the  pre-
scrubber to compensate for this loss and to humidify the flue gas.  This
purge stream is sent to the power station's fly ash settling ponds.
                                   2-3

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                                              FIGURE  2.1    BLOCK FLOW  DIAGRAM  OF  MAJOR  PROCESS  STEPS
                                                                                                TREATED FLUE GAS
ro
                 COAL
                 AIR
                 HATER
                                     ELECTRICAL
                                       ENERGY
                                          STEAM
MITCHELL NO. 11
   BOILER
                      FLUE
                      6A5
                                                   INLET
                                       NATURAL GAS
                                        SODA ASH
                                                            FED PROCESS BOUNDARY
                                                                                                           PURGE
                                                                                                           SOLIDS
                                                                                                         BY-PRODUCT

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     The cooled, humidified flue gas leaves the prescrubber and enters the
bottom of a three stage absorber where the gas is contacted with the sulfite/
bisulfite solution flowing countercurrently to the gas stream.   The solution
absorbs the SO,, and the treated flue gas is then discharged to the atmosphere
through a stack.

     The spent sulfite/bisulfite solution is removed from the bottom tray
of the absorber and sent to a surge tank for storage prior to regeneration
in the S02 recovery step.  During recovery of the S02, the spent absorbent
is regenerated in a steam-heated, single-effect evaporator and is then returned
to the absorber feed tank.  The surge tank and absorber feed tank provide
surge capacity for operating for limited time periods at flue gas rates in
excess of 92 MW equivalent.  To prevent accumulation of sodium sulfate in
the absorbing solution stream, a purge stream is sent to the purge treatment
area.  Here, the purge stream is crystallized and centrifuged and the solid
product is removed and dried, yielding a salable sulfate by-product.  The
sodium values lost in the purge stream are made up by adding Na^CO^ to the
regenerated sulfite/bisulfite solution.

     S02 released in the evaporator is taken overhead and sent to the S02
reduction area.  The reduction step is a proprietary process developed by
Allied Chemical which utilizes natural gas (CH.) for the reduction of S02
to H«S and, ultimately, to elemental sulfur in molten form.  A small stream
of tail gas is returned after incineration to the inlet of the booster blower.

PERFORMANCE EVALUATION METHODOLOGY

     Evaluation was in response to the test objectives and proceeded in six
steps:

     1.  Collect applicable data and operating information.

     2.  Define hours of operation within each operating mode.
                                    2-5

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      3.   Process the raw data for each consecutive 30-day period
           and for specific periods according to the mode of operation.

      4.   Assess performance with regard to pollutant removal,
           dependability, energy consumption, and costs.

      5.   Assess the response of selected dependent variables to
           changes or fluctuations in the major independent variables.

      6.   Assess the effect of upsets and transients on SOp removal
           capability.

A variety of measurement techniques, described in Section 4.0, were used to
develop the data base.

      The core test system consisted of sensors for various boiler and flue
gas operating variables (with emphasis on the F6D inlet and outlet flue gas
parameters) and accumulation of the sensor analog signals by a data acquisi-
tion system (DAS).  The frequency of analog signal scan by the DAS was six
minutes, from which one-hour averages were computed.  The DAS had the
capability of storing the data on magnetic tape; however, hardware diffi-
culties with the tape transport unit were experienced throughout the demon-
stration year, so that very little automated data reduction was possible.
Backup storage was available on teletype printouts or on charts taken
from strip chart recorders.   These data sources had to be utilized at
considerable penalty in the excessive time required to access the data
and reduce it manually.
                                    2-6

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     The basic time interval was one hour and SCL removal performance was
assessed on the basis of a one-hour averaging time.  Not all of the operating
variables were measurable at one-hour intervals.  Primary examples are coal
composition, coal rates, product rates and raw material rates.  Therefore,
to make the necessary comparisons, one-hour data was accumulated, evaluated
and reported for each 30-day period.  For reporting purposes, periods were
assigned to conform as closely as possible to calendar months.  Starting on
September 16, 1977; periods were as shown (Table 2.1).  It was also desirable
to accumulate data according to operating mode status (FGD plant down, FGD
plant full operation, FGD plant partial operation).

            TABLE 2.1  DEMONSTRATION YEAR OPERATING PERIODS
Period No.
1
2
3
4
5
6
7
8
9
10
11
12
13

0000,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
0800,
Start - End
9/16/77 to 0800,
10/4/77 to 0800,
11/3/77 to 0800,
12/3/77 to 0800,
1/2/78 to 0800,
2/1/78 to 0800,
3/3/78 to 0800,
4/2/78 to 0800,
5/2/78 to 0800,
6/1/78 to 0800,
7/1/78 to 0800,
7/31/78 to 0800,
8/30/78 to 2400,

10/4/77
1V3/77
12/3/77
1/2/78
2/1/78
3/3/78
4/2/78
5/2/78
6/1/78
7/1/78
7/31/78
8/30/78
9/16/78
     Before evaluation, the raw data were assembled according to specific time
periods and the routine calculations were made.  This processing was to have
been done by computer.  However, failure of the tape transport device resulted
in only a minimum of data available to the computer from magnetic tape storage.
Therefore, we were forced to resort to manual processing and reduction of data
from backup teletype hard copy and from strip charts.  This has, for the present,
limited evaluations primarily to S02 removal capability, dependability, rato material
                                    2-7

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and energy consumption, and cost of the FGD plant and to overall performance
of the boiler.  More specific results will be evaluated in a subsequent
report.  Additional correlations, where meaningful, will also be reported.
Several of the correlations expected to be made are not applicable, given
the sporadic operation of the FGD plant.  For example, unit costs per ton
of SOp removed is distorted when the S0« that is removed and recovered must
be vented because the reduction unit is not operating.  Occurrences of this
type were frequent.

SCOPE OF FOLLOW-ON PROGRAM

     This Interim Report evaluates the performance of the FGD unit for the
scheduled one year of demonstration beginning September 16, 1977.  The test
program has been extended for an additional six to twelve months beginning
September 30, 1978.

     The test program as originally planned was to include one year of test
and evaluation during the year immediately following the Acceptance Test,
It became apparent after about six months of sporadic operation that the FGD
plant was not able to operate in a manner acceptable for commercial applica-
tion due to factors not entirely attributable to FGD deficiencies.  During
a mid-year review, it was concluded by the project participants that the
major problems were either boiler related or were problems encountered at
the boiler/FGD interface, in particular booster blower and damper problems.
It was decided at that time that the major problems were probably correctable
and to do this a plant improvement program was initiated.  The improvement
was to be substantially completed before the end of the scheduled boiler
outage in September 1978.  The boiler outage coincided with the end of the
demonstration year.  The test program is continuing for another six to twelve
months beginning with boiler startup following the scheduled shutdown in
September.
                                   2-8

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     The follow-on test program is essentially an extension of the first
year of test and evaluation.  However, emphasis will be placed on reliability
of FGD plant operation first at a constant load condition and then while
following normal swings in boiler load.  As a part of the follow-on program,
boiler baseline data were collected with the FGD plant down and completely
isolated.  The results are expected to show any differences in boiler
operating characteristics compared to the results of the first Baseline Test
performed prior to installation of the FGD plant.   '

     In addition, special tests are proposed to evaluate the FGD system at
its capacity limits and to establish the load following capability of the
FGD unit.  Other non-routine testing will be done to determine the sulfate
formation rate during SfL absorption.
 (  JAdams,  R.  C.,  T.  E.  Eggleston,  J,  L.  Haslbeck,  R.  C,'  Jordan  and  Ellen
   Pulaski.   Demonstration  of Wellman-Lord/Allied  Chemical  FGD  Technology:
   Boiler  Operating  Characteristics.   EPA-600/7-77-014.   TRW, Inc., Vienna,
    Va.  February 1977.
                                      2-9

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                                 SECTION 3
                               TEST RESULTS
SUMMARY
      Test data were collected during the demonstration year, which extended
from 0000, September 16, 1977, to 0000, September 16, 1978.  Monthly summaries
of various operating parameters for both the boiler and the FGD plant have
been compiled (Table 3.1).  Part of the data base is appended (Appendix A).

      During the demonstration year, the boiler operated a total of 7,800
hours out of a possible 8,760 hours for a boiler utilization factor of 89';.
The mean power output of the boiler during the period of operation was 76
MWG;* included in this figure are 372 hours of power output at less than 46
MWG.  The boiler capacity factor (kWh generated/generating capacity) was
0.585.  An average of 33,900 kg (74,700 Ibs) of coal per hour was burned
with a mean heating value of 24,400 kJ/kg (10,500 BTU/lb).  The gross heat
rate of the boiler averaged 11,000 kJ/kWh (10,400 BTU/kWh).

      The FGD plant operated a total of 2,155 hours.  Flue gas and steam at
conditions at which stable operation of the FGD plant was possible were
delivered a total of 3,949 hours.  Partial operation, with reduction area
down and minimal recovery of S02 or with the bypass damper open, occurred a
total of 1,681 hours, for a total operating time for the absorber/evaporator
of 3,836 hours.  Removal efficiency averaged 89% during those hours at an
average inlet S02 concentration of 2,081 ppm.  Average steam usage of the
FGD plant was 26,000 kg (58,000 Ib) per hour (this  is equivalent to a loss
of available generating capacity of 8.7 megawatts gross).  The annualized
unit cost of operating the FGD plant amounted to 15.81 mills/kWh.
*In this report, the symbol MWG refers to the gross megawatts generated
 by the boiler.
                                    3-1

-------
                                                                     TA3LE 3.1 - A SUMMARY OF THE BOILER AND FGO PLANT OPERATING PARAMETERS
CO
PERIOD 1
START/END 9/16-10/4
Mrs, Total
Mrs Boiler Operated
Hrs Boiler Operated
<46 HW
Hrs of FGO Absorber/
Evaporator Operation
Hrs of FGO Full
Operation
Avg Load, HU (Gross)
Avj Load. HU (Net)
Avg Load, MUG, FGO
Down
FGO Avg Steam usage.
Lb/hr
Avg Coal Rate. Lb/hr
Coal HHV, Btu/hr
Boiler Heat Input,
10* Btu/hr
Gross Heat Rate,
Btu/kUh
MU Equlv. of FGD
Steam Usage
Avg Inlet SO,. PPM
Kax Inlet SO,, PPM
Mln Inlet SO;, PPH
;/S Outlet SO,, PPM
Kax Outlet SO,, PPM
Nln Outlet SO,. PPM
Avg SO, Rate/In, Lb/hr
Avg SOf Rate, Out. Lb/hr
Avg '. SO, Removal
Electricity, MM,
Natural Gas, 10° Btu/hr
Steam. 10° Btu/hr
Soda Ash Consumed, Tons
Sulfur Produced, Long
Tons
ty-Product Salt Pro-
duced. Tons
440
415
198

83

83

54
45
38

58996

53157
9890
526

9684

8.7

2178
2513
988
218
314
72
3218
348
89
0.741
9.5
77.9
19
39

4

2
10/4-11/3
721
685
39

274

131

66
NA
78

52489

87032
10326
899

13616

7.2

2374
2995
1757
221
682
134
6196
620
90
0.677
7.4
69.3
86
91

9

3
11/3-12/3
720
660
1

473

447

75
NA
66

56426

78060
10409
813

10T.34

8.1

2297
3101
685
241
566
106
5324
559
90
0.659
11.2
74.5
171
285

50

4
12/3-1/2
720
631
22

183

0

70
NA
66

54518

71309
10062
718

10250

8.0

1790
2727
552
163
322
48
3871
406
90
0.684
0.8
72.0
97
0

11.5

5
1/2-2/1
720
628
2

0

0

81
NA
81

-

85060
10307
877

10849

-











0
0

0

6
2/1-3/3
720
522
0

301

0

92
NA
97

51528

91218
10334
943

10302

6.6

1365
2525
740
164
352
46
2974
402
87
0.750
1.0
68.0
34.7
0

0

7 8
3/3-4/2 4/2-5/2
720
629
13

448
(11
215*"

73
NA
74

57112

69358
10398
721

9920

8.3

2498
3349
492
223
680
64
6380
615
90
0.785
5.9
75.4
212
135

0

719
576
33

0

0

77
70
77

-

68135
10803
736

10053

-

'
.
-
-
-
-
-
-
>
—
?2.8
0

0

9
5/2-6/1
720
658
64

619

268

78
NA
87

64325

77483
10687
828

10684

9.1

1905
2591
NA
188
685
NA
4371
466
89
0.718
5.5
84.9
243
191

44

10
6/1-7/1
720
720
0

102

4

77
70
77

60300

70943
10735
762

9981

8.6

2206
2800
1600
>470
>500
250
3959
>910
<77
0.754
1.2
79.6
53
0

40

11
7/1-7/31
720
633
0

320

0

68
59
66

55470

65905
10796
712

10573

8.2

1946
2300
700
211
>500
70
3756
438
88
0.723
6.0
73.2
106.5
8.5

25.7

12
7/31-8/30
720
720
0

720

715

78
71
-

62233

75812
10766
816

10411

8.8

2071
3000
1550
215
365
145
4527
507
89
0.771
. 11.2
82.1
262.5
504.5

58

13
8/30-9/16
400
323
0

313

311

BO
72
-

59331

71629
11104
795

9955

7.4

2197
2450
2000
220
265
165
4875
537
89
0.780
10.1
78.3
123.5
202

40.3

Totals
8760
7800
372
3836


2174

























1431
1456

282.5

                          M - Not Available
                                  bypass  damper open.

-------
CO
 I
CO
TABLE 3.2 -
PERIOD 1
START/END 9/16-10/4
rirs. Total 440
Mrs Boiler Operated 415
Hrs Boiler Operated 198
<46 HM
Hri of FGO Absorber/ 83
Evaporator Operation
Hrs of FGD Full 83
Operation
Avg Load. MM (Gross) 54
Avg Load, MW (Net) 45
Avg Load, I-M(G), FGD Down J8
F3D Avg Steam Usage, 26760
kg/Hr
Avg Coal, Rate, kg/hr 24112
Coal HHV. kJ/lb , 10443
Boiler Heat Input, 10° 555
kJ/hr
Gross Heat Rate, 10225
U. nr
MU tqjiv. of FGD 8.7
Steam Usage
Avg Inlet SO,, PPH 2178
Ma« Inlet SO,. PPH 2513
Hin Inlet SO,, PPH 988
Avg Outlet SO,. PPH 218
Max Outlet SO,. PPH 314
Kin Outlet SO,, PPM 72
Avg SO, Rate/In, kg/hr 1460
Avg SOl Rate, Out, kg/hr 158
Avg '. SO, Removal 89
Electricity. MW, 0.741
natural Gas. 10° kJ/hr 10.0
Stean, 106 kJ/hr 82.3
Soda Ash Consuned, 17. 2
Metric Tons
Sulfur Produced, Metric 39.6
Tons
By-Product Salt Pro- 3.6
duced, Metric Tons
•>A - Not Available
* 'with bypass damper open.
2
10/4-11/3
721
685
39

274

131

66
NA
78
23809

39477
10903
949

14377

7.2

2374
2995
1757
221
682
134
2810
281
90
0.677
7.8
73.2
78.0

92.5

8.2



3
11/3-12/3
720
660
1

473

447

75
NA
66
25594

35407
10991
858

11439

8.1

2297
3101
685
241
566
106
2415
254
90
0.659
11.8
78.7
155.1

289.6

45.4



A SUMMARY
4
12/3-1/2
720
631
22

183

0

70
NA
66
24729

32345
10624
758

10823

8.0

1790
2727
552
163
322
48
1756
184
90
0.684
0.8
76
88.0

0

10.4



OF THE BOILER AND
5
1/2-2/1
720
628
2

0

0

81
NA
81
.

38583
10883
926

11455

.

.
„
_
_
.
.
.
.
.
.
-
.
0

0

0



6
2/1-3/3
720
522
0

301

0

92
NA
97
23373

41376
10911
996

10878

6.6

1365
2525
740
164
352
46
1349
182
87
0.750
1.1
71.8
31. S

0

0



FGD PLANT
7
3/3-4/2
720
629
13

448

.,_

73
NA
74
25906

31460
10979
761

10474

8.3

2498
3349
492
223
680
64
2894
279
90 ,
0.785
6.2
79.6
19?. 3

137.2

0



OPERATING PARAMETERS - HETRIC UNITS
8
4/2-5/2
719
576
33

0

0

77
70
77
.

30906
11407
777

10615

-

-
.
_
.
.
.
.
-
.
-
-
-
20.7

0

0



9
5/2-6/1
720
658
64

619

268

89
NA
87
29177

35146
11284
874

11281

9.1

1905
2591
NA
188
685
NA
1983
211
89
0.718
S.H
89.6
220.4

194.1

39.9



10
6/1-7/1
720
720
0

102

4

77
70
77
27352

32179
11335
805

10539

8.6

2206
2800
1600
>470
>500
250
1796
413
<77
0.754
1.3
84.1
4R.1

0

36.3



11
7/1-7/31
720
633
0

320

0

68
59
66
25162

29894
11399
752

11164

8.2

19/6
2300
700
211
>500
70
1704
199
88
0.723
6.3
77.3
96.6

0.6

23.3



12
7/31-8/30
720
720
0

720

715

78
71
.
28228

34388
11367
862

10993

8.8

2071
3000
1550
215
365
145
2053
230
89
0.771
11.8
86.7
239.1

512.6

52.6



13
8/30-9/16
400
323
0

313

311

80
72

26912

32490
11724
839

10511

7.4

2197
2450
2000
220
265
165
2211
244
89
0.700
10.7
82.7
112.0

20'.. 2

36.6




ICUAL
8760
7800
372



2174


























1298.0

1479 4

. ob . 3




-------
S02 REMOVAL

     The performance guarantee of 90^ S02 removal  for the WL/Allied process
does not specify an averaging time.  However, it was demonstrated during
acceptance testing that the FGD plant could operate continuously at design
capacity and meet the guaranteed SCL removal performance requirement based
on a two-hour averaging time.  In this report, one hour averages are used to
evaluate S02 removal performance.  This is a more stringent averaging time
requirement placed on the process than was required for acceptance testing
(two-hour averages) or for the proposed Federal New Source Performance Stand-
ards^ ' (24-hour averages).  In a subsequent report, S0« removal performance
will be assessed at averaging times other than one hour.  For the time being
test results are being compared to a higher standard of performance (one-
hour averaging time) than that required for acceptance testing or for Federal
emission standards under consideration.

     During the demonstration year (9/16/77 to 9/16/78), the S02 removal
performance guarantee of 90% was met or exceeded only 45% of the time (based
on 2,572 hours of valid data out of a total absorber/evaporator operating
time of 3,836 hours, one-hour averages).  For longer averaging times, 89%
or greater S02 removal was easily attained for most of the 30-day reporting
periods (Figure 3.1).  The absorption and S0« recovery steps of the process
are such that 1t would not have been difficult to achieve 90% or higher
removal, even for one-hour averaging periods.  However, each additional
Increment of S02 removal Incurs a penalty 1n higher evaporator duty and in
higher soda ash make-up.  Costs are thus minimized by operating very close
to the performance guarantee level of sulfur removal.  In practice, the FGD
plant was operated to limit the concentration of S02 emitted to 10% or less
of the inlet concentration.  To determine percent removal, the outlet con-
centration must be corrected for dilution of the flue gas due to its becoming
saturated before leaving the absorber.  Flue gas dilution 1s typically 9%-10%,
which 1s equivalent to about one percent of S02 removal.  On the assumption
that the operating goal was to achieve 89% removal or better, this goal was
      CFR Part 60, Vol. 43 No. 182, 42154-42184 (Federal Register),
                                   3-4

-------
                                                                FIGURE 3.1

                                               S0? REMOVAL  PERFORMANCE ON  A MONTHLY BASIS

                                                   (ALL MODES OF FGD  PLANT  OPERATION)
              100
               80
UJ
I
tn
               60
        CM
       O
       CO
               40
               20
                          1      2
                       Sept.'77 Oct
 3456
Nov.   dec.   Jan. '7ft  Ob.
 10
June
11
 12
Auq.
 13
Sont
                                                                PtRIOD

-------
achieved for 66% of the hours of valid data (Figure 3.2).   Furthermore,
the data indicate that percent removal was 79% or better for 96% of the
time.  Overall, for the one year period, S0« removal efficiency averaged
89% (average of hourly averages).

     In the preceding discussion, we have reported on the ability of the
absorber to remove S0« without regard to whether or not the FGD plant was
operating as a fully integrated, regenerable unit.  For part of the time,
only partial operation of the plant was attained.  Two modes of partial
operation are identified:

     1.   The S0« reduction unit was down for about 1,680 hours out
          of a total of 3,836 hours of absorber/evaporator operation.
          This necessitated venting the S0« recovered at the evapora-
          tor to the atmosphere.  Thus, only the small portion of S02
          removed in the sulfate purge stream was prevented from
          being emitted.

     2.   For short periods, the FGD plant was operated with the
          bypass damper open.  In this mode, it is not known with
          certainty how much of the untreated flue gas has bypassed
          the absorber.  Also, two directional flow past the bypass
          damper is possible.  That is, air or flue gas from the
          bypass stack which is shared with Unit No. 6 may be drawn
          into the absorber through the open bypass.

There were also times that the FGD plant was operated outside of the design
range of the input streams (flue gas rates equivalent to boiler loads in the
range 46 MW to 92 MW and steam at design temperature and pressure conditions)
S02 removal efficiency averaged 89% during the hours of full operation for
which valid data are available.

-------
                                                               FIGURE 3.2
              2000
                                                   S02  REMOVAL FREQUENCY DISTRIBUTION
                                              NO. OF  HOURLY  READINGS VS. PERCENTILE  RANGES
                                                PERIOD  0800, 9/16/77 THRU 0800, 9/17/78
                                                                                   1690
CO
I
       t/J
       CO
       o
       2
       oe
       ce.
       o
1500
1000:
                                                                                               NOTE:  TOTAL READINGS=2572
       o
       o
               500
                                                    783
                              37
                             _•• .
                             69%>
                                                62
                                  79%>
                                 >69%
 89%>
>79%
                                              REMOVAL PERCENTILE RANGES

-------
FGD PLANT DEPENDABILITY

     Dependability of the FGD plant was assessed at two levels:

     1.  Its ability to operate when called upon without regard to
         pollutant removal performance (Viability Indices).

     2.  Its ability to meet performance standards for S02 removal
         when called upon.

The Viability Indices are those used to report FGD viability in the EPA
                   (A\
Utility FGD Survey.v '  S02 removal performance is described in the preceding
subsection.

     Certain design decisions were made which have limited the ability of the
FGD plant to follow the full range of normal boiler operation (operability).
Doubtless, design changes could be made or redundancy provided on another
installation that would maximize the FGD unit's ability to follow boiler
operation.  In this report, dependability is assessed relative to the specific
design features of this FGD unit.  Accordingly, the reliability of the FGD
plant is defined as its ability to follow boiler operation only when specific
design criteria are met.   Thus, the FGD plant reliability is determined only
for those hours that it is "called upon" to operate due to essential feed
streams being available simultaneously (Figure'3.3):

     1.  flue gas at rates not less than 46 MUG equivalent
                                              o
     2.  boiler steam at pressures >37.3 kg/cm  gauge (530 psig)
     3.  electricity
     4.  natural gas
     5.  soda ash
     6.  boiler stable within limits of greater than 46 MWG and coal
         sulfur content greater than 2.82» and less than 3.5%.

Also, the FGD plant cannot operate for sustained periods at flue gas rates
above the equivalent of 92 MWG.
(4)Laske, B., et al.   EPA Utility FGn Survey.   EPA-600/7-78-051d, U.  S.
   Environmental Protection Agency, Research Triangle Park, NC  1978.
                                    3-8

-------
                                                           FIGURE 3.3  NIPSCO BOILER AVAILABILITY & FGD OPERATING TIME
        u>
CO

o
                              700
                              600
                              500
                              100
                               300
                               200
                               100  '
                          LEGEND:

                            BOILER  AVAILABLE TO FGD AT
                            DESIGN  CONDITIONS
D
                            FGD  FULL  OPERATION (ABSORPTION
                            &  REDUCTION  UNITS)
                                                  ABSORBER OPERATING  (WITH OR
                                                  WITHOUT REDUCTION UNIT
                                                  OPERATING)
                 1
                SEP
                1977
                                                 OCT
 3
NOV
DEC
 5
JAN
1978
 6  -T
FEB
 7
MAR
 8    I     9    |    10   "I""" 11
APR       MAY       JUN        JUL
12
AUG
~ 13
  SEP
                                                                                                                                                                 vv^
                                                                                                                                                                 \ A ',
                                                                                            PERIOD

-------
Viability Indices

     These indices are defined in the FGD Survey reports (Table 3.3).  However,
the various parameters have been more precisely defined to conform with the
specific operating configuration of this FGD process.  Primarily, the specific
definitions needing clarification are "FGD plant called upon" (defined above)
and "FGD plant available":

     FGD plant available - defined as time all equipment required for
     accepting total flue gas, removing SOg, recovering captured SQy
     as S02 or purge solids, and reducing SOg to elemental sulfur is
     in shape to operate and solution is in shape to operate with no
     more than 48 startup hours required from time steam of greater than
               2
     37.3 kg/cm  gauge (530 psig) is available.

Available and called upon hours are presented below (Table 3.4).
            TABLE 3.4  HOURS FGD PLANT AVAILABLE AND CALLED UPON

1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.

Period
9/16-10/3
October
November
December
January
February
March
April
May
June
July
August
9/5-9/15
Total
Hours FGf)
Plant/i\
Avail ableu'
440
131
531
496
720
720
720
0
368
97
43
720
321
5307
Hours FGD
Plant
Called Upon
165
357
319
131
53
107
283
216
495
499
353
679
292
3949
(1)
   Hours FGD plant available obtained from Allied reports.
                                      3-10

-------
                                      TABLE 3.3   DEFINITION OF VIABILITY  INDICES
                                                                                  (5)
CO
I
           Boiler Capacity Factor
           Boiler Utilization Parameter
           Efficiency - Fly Ash
           - S02

FGD Availability Factor

FGD Reliability Factor

FGD Operability Factor

FGD Utilization Factor
FGD Status - Category 1
           - Category 2
           - Category 3
(kWh generation in year)/(maximum continuous generating capacity in KW x
8760 hr/yr).
Hours boiler operated/hours in period, expressed as a percentage.
Operational - The actual percentage of fly ash removed by the FGD
system and the particle control devices from the untreated flue gas.
All others - The design efficiency (percentage) of fly ash removed
by the FGD system and the particle control devices.
Operational - The actual percentage of S0« removed from the flue gas.
All others - The design efficiency.
Hours the FGD system was available for operation (whether operated or not)/
hours in period, expressed as a percentage.
Hours the FGD system operated/hours FGD system was called upon to operate,
expressed as a percentage.
Hours the FGD system was operated/boiler operating hours in period,
expressed as a percentage.
Hours FGD system operated/hours in period, expressed as a percentage.
Operational - Unit has been or is in service removing S02«
Under Construction - Ground has been broken for installation of FGD
system has not become operational.
Planned, Contract Awarded - Contract has been signed for purchase of FGD
system but ground has not been broken for installation.
            (5)
   Laske, B., et al.  EPA Utility FGD Survey.  EPA-600/7-78-OSld, U. S. Environmental  Protection Agency,
   Research Triangle Park, NC  1978.

-------
     Overall dependability for the demonstration year (8,760 hours) was as
follows:

     Boiler Utilization.  The boiler was operated for a total of 7,800
     hours for a utilization factor of 89%.

     Boiler Capacity.  The boiler generated a total of 589.7 x 10  kWh
     of electricity for a capacity factor of 0.582 kWh actual/kWh
     maximum capacity (based on a nameplate maximum load of 115.6 MVIG).

     FGD Reliability.  Flue gas and steam within design limits were
     delivered by the boiler for a total of 3,949 hours.  Full operation
     of the FGD plant was achieved for a total of 2,153 hours.  Of these
     hours, the FGD plant operated outside of the design limits for steam
     pressure for 346 hours.  Thus, the plant is capable of operating at
     times at reduced steam pressures.  The reliability factor, determined
     on actual capability, is as follows:
                          2153
         Reliability = 	X 100 = 50%
                       3949 + 346

     FGD Operability.  The operability factor was 28% (hours FGD plant
     operated/hours boiler operated).

     FGD Utilization.  The utilization factor was 25% (hours FGD plant
     operated/hours in year).

Reliability is the ability of the FGD plant to operate within specific limits
of boiler operation.  Operability is the ability to follow boiler operation,
but only if the swings in boiler operation are normal.  The FGD plant should
not be expected to operate during every conceivable off normal excursion of
the boiler.  The FGD plant achieved operability only 56% of the time that it
achieved reliability.  The wide disparity in these two indices was due to
considerable operation of the boiler in an unstable and off normal condition.
                                    3-12

-------
In other words, the operability factor would have been higher with more
stable boiler operation.  An account of boiler and FGD plant operating
problems are given in the next subsection.

Operating Problems

     A whole series of problems were encountered right from the start of the
demonstration year which prevented consistent operation of the FGD plant
until the last two months of the year (Table 3.5).  The problems were primarily
boiler related or problems at the boiler/FGD plant interface.  The major prob-
lems and corrective measures are summarized as follows:

     0  Coal Feeding and Coal Quality.  Inability to maintain consis-
        tent feed rates to the coal mills and coal mill failures
        resulted in unstable flue gas rates and steam pressures.
        The FGD plant was unable to operate when these excursions
        from normal boiler operation were excessive.  It appears
        that the major problem was the quality of the coal (a rela-
        tively new source of coal for Mitchell No. 11) which contained
        unmillable material and contributed to coal mill failures.
        With the use of Captain coal beginning on a permanent basis
        in Period 8 (April 1978), the coal feeding problems were
        minimized substantially.  Other corrective actions were
        enlargement of the coal mill feed chutes and overhaul of
        the four coal mills and associated primary air fans.

     0  Boiler Feed Water Problems.  Silica levels must be limited
        to prevent turbine blade fouling and erosion.  Silica
        concentrations are maintained by limiting silica in the
        makeup water to parts per billion levels.  If silica excur-
        sions occur, boiler blowdown is increased or the boiler is
        operated at a lower steam pressure.  Fluctuations in boiler
        main steam pressure affected the pressure of the steam
                                    3-13

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                   TABLE 3.5 BOILER & F6D PLANT OPERATING HISTORY
                                                                         -Hours-
Event
Period
Boiler Operated
Boiler Operated
 Within Design
    Limits
                                                                                                              FGD Plant
                                                                                                            Full  Operation
1.  The Demonstration year commenced at
    0000 on 9/16/77.   The FGD plant
    operated until 1100 on 9/19/77.

2.  The FGD plant was taken down due to
    unstable flue gas and steam flows
    due to coal feeding problems caused
    by wet coal.  Due to the feeding
    problems, the wet coal had to be
    worked off at minimum loads.  This
    was accomplished by 10/3.  The FGD
    plant remained down until 10/7 to
    conduct flow tests at baseline
    conditions to verify the flow rates
    of the Acceptance Test.

3.  The FGD plant operated with inter-
    ruptions due to booster fan speed
    control repairs and had some partial
    operation (reduction unit not oper-
    ating or bypass damper open) as a
    result of fluctuations in steam
    delivered by boiler.

4.  The FGD plant went down for repair
    of the evaporator circulating pump.
    The plant was available on 10/21
    but remained down for an expected
    boiler outage to make tube repairs.
    However, the boiler outage could
    not be scheduled due to power
    demand.
                            9/16/77 to 9/19/77
                               9/19 to 10/7
                           83
                          413
                         75
                         83
                        114
                                                                                 (1)
                               10/7 to 10/19
                          272
                        188
                        131
                              10/19 to 10/28
                          223
                         44
                                                                                 (2)

-------
                                                     TABLE 3.5 (Continued)
                                                                                             -Hours-
                    Event
                                                    Period
Boiler Operated
Boiler Operated
 Within Design
    Limits
  FGD Plant
Full  Operation
u>
i
01
5.   An FGD plant startup was attempted
    but was delayed due to an Inoperative
    isolation damper and to problems with
    controls on the booster fan.   After
    startup, FGD plant operation  was
    interrupted by the boiler shutdown
    and by booster fan vibration  caused
    by flyash buildup on the blades.

6.   The FGD plant operated despite boiler
    load and main steam fluctuations.
    The major problem was high silica 1n
    the boiler feed water which was
    thought to be due to condenser leaks.
    Boiler main steam pressures had to be
    reduced to accommodate the high
    silica.  This affected pressure
    control of steam to FGD plant.  Some
    FGD plant partial operation occurred.

7.   Boiler down to repair condensers.

8.   Boiler startup on November 26.  FGD
    plant not available due to evaporator
    repairs and booster blower being out
    of balance.

9.   Boiler down 81 hours for condenser
    and precipitator repairs and to
    remove clinkers.  Boiler was returned
    to service but high silica problem
    had not been corrected.  Also, there
    were recurring coal feed problems.
    FGD plant was not operated due to
    boiler operating at low loads,
                                                  10/28 to 11/5
      151
      142
        0
                                                   11/5 to 11/23
      450
      278
      428
                                                  11/23 to 11/26

                                                  11/26 to 12/10
        0

      329
      100
                                                  12/10 to 2/23
      234
       30

-------
                                                      TABLE 3.6 (Continued)
                                                                                             -Hours-
                    Event
Period
                  Boiler Operated
                   Within Design
Boiler Operated	Limits
  FGD Plant
Full  Operation
u>
I
    reduced steam pressure and operating
    with low sulfur coal.   The absorber
    accepted flue gas for  114 hours.
    Reduction unit was not operated due
    to insufficient amount of S0« avail-
    able (due to minimum boiler Toads
    and low sulfur coal).

10.  FGD on standby at request of NIPSCO
    until  coal  mill and high silica
    problems are resolved.  During this
    period, boiler was down for con-
    denser repairs, predpitator repairs,
    boiler tube leaks, and turbine
    repairs.  Low sulfur coal was
    burned for much of this period.

11.  FGD plant on at partial operation
    (reduction unit down and bypass
    damper open), S0« level in flue gas
    was low and pressure of steam
    delivered to FGD plant was unstable.
    FGD plant down 16 hours to balance
    booster blower.

12.  FGD plant at full operation with
    bypass damper open. It was deter-
    mined that the high silica levels
    in the boiler feed water were not
    due to condenser leaks as suspected
    but were a combination of high
    makeup water rates and higher than
    acceptable silica levels in the
    makeup water.  Corrective steps
    were underway.
                                               12/23/77 to 2/19/78
                         1102
                         81
        0
                                                   2/19 to 3/6
                          368
                        125
        0
                                                    3/6 to 3/15
                          215
                        212
      215
                                                                                                                       (3)

-------
                                                   TABLE  3.5  (Continued)
                                                                                           -Hours-
                 Event
   Period
                  Boiler Operated
                   Within. Design      FGD Plant
Boiler Operated	Limits	Full Operation
 13.  Boiler  down  for  repairs  and mainte-
     nance on  coal mills,  turbine,
     precipitator.

 14.  Full operation of  FGD plant not
     possible  due to  erratic  coal feed
     and  resulting fluctuations in
     pressure  of  steam  delivered to FGD
     plant,  recurring imbalance of
     booster blower,  and  isolation
     damper  malfunction.   Boiler also
     switched  to  low  sulfur coal due  to
     difficulty with  feeding  high sulfur
     coal.

|15.  FGD  plant down to  r,eblade the  booster
     blower  and for  isolation damper
     malfunction. Boiler down on 5/3
     for  isolation damper repairs and
     back up on 5/6.  FGD plant up  on
     5/6  at  partial operation (reduction
     area down and bypass damper open).
     Full operation not achieved due  to
     bypass  damper problems and erratic
     steam pressure.   Inlet SOo was under
     the  design limit part of time.

 16.  FGD  plant full operation.

 17.  FGD  plant at partial operation
     (reduction unit  down) due to  shift
     to low  sulfur coal.
                                                3/15 to  3/18
                                                3/18 to  3/28
                             252
                         26
                    0
                                                 3/28  to  5/11
                             816
                        314
                    0
                                                 5/11  to  5/14

                                                 5/14  to  5/19
                              65

                             119
                         56

                         38
                   65

                    0
18.  FGD plant full  operation.
5/19 to 5/27
      203
203
                                                                                                                   203

-------
                                                    TABLE  3.5  (Continued)
                  Event
Period
Boiler Operated
—Hours	
 Boiler Operated
  Within  Design
     Limits
                                                                                                              FGD  Plant
                                                                                                            Full Operation
19. FGD plant at partial operation due
    to reduction unit and booster
    blower repairs and erratic steam
    pressure.  Booster blower repairs
    requiring a boiler shutdown were
    delayed due to power demand.

20. Boiler down to repair ID fans,
    isolation damper and booster blower.

21. FGD plant at partial operation due
    to booster blower and steam pressure
    relief valve problems.

22. FGD plant at full operation except
    for short outages of reduction unit
    (4 hours total).

23. Boiler scheduled down for routine
    maintenance and to continue with FGD
    plant improvement projects.
                                                 5/27 to 7/6
                          948
                        737
                          0
                                                  7/6 to 7/10


                                                 7/10 to 7/31



                                                 7/31 to 9/12



                                                 9/12 to 9/15
                            0


                          516



                         1046



                            0
                        218
                        968
                           0
                        1028
Notes:   (1)   Hours to conduct flow tests not included.
        (2)   Hours FGD in standby for boiler shutdown not included.
        (3)   With bypass damper open.

-------
delivered to the FGD plant, causing unstable operation.
The high silica levels were found to be due to a high level
of silica in the makeup water from a portable water treatment
facility being used to supplement the power station's permanent
makeup water supply.  The condition was exacerbated because  a
considerable amount of the condensate returned from the FGD
plant was being discarded due to apparent poor quality, which
added more silica to the system by way of increased makeup
water requirements.  However, much of the condensate from the
FGD plant was being dumped automatically as a result of false
signals from the conductivity and pH monitors.  Defects in
this control system were corrected.  Also, more stringent
control of silica in the makeup water is in effect.  As a
result, control of silica in the boiler ^eedwater was imoroved
and, as a result, boiler steam pressure became more stable.   It
took several months to determine the cause of the problem and
correct it.  This was because considerable time was lost while
it was thought that the high silica levels were caused by
cooling water leaking into the boiler feed water system at the
condensers.  Corrective actions were therefore at first directed
toward stopping condenser leaks.

Booster Blower.  The primary problems were rapid deterioration
of the fan blades from contact with the wet flue gas and flyash,
imbalance of the fan due to flyash buildup and problems with
blower and turbine controls and the lubrication system.  This
part of the FGD system was designed for a flue gas temperature
above the dew point.  However, flue gas temperatures below the
dew point were common.  The liquid phase is a weak acid, primarily
sulfuric, which is corrosive.  After several unsuccessful attempts
to balance the blower, it was decided to reblade the fan in  May
1978 (Period 9).  These repairs were done in 31 days.  To maintain
                            3-19

-------
   the flue gas temperatures above the dew point, the air heaters
   were modified during the scheduled shutdown In September-
   October 1978 to raise the flue gas temperature.   However, this
   resulted in additional  heat lost in the exiting  flue  gas  for a
   loss in boiler efficiency.  Also, flue gas ducts inlet and
   outlet the booster blower were insulated and a system for
   cleaning the fan blades while in run is being installed.

0  Isolation Damper.  A guillotine damper, installed in  the  flue
   gas duct upstream of the booster blower, isolates the FGD plant
   from the boiler.  Fly ash hardens in the damper tracks and
   prevents opening or closing when needed.  This has either
   delayed startups or maintenance of the booster blower has had
   to be delayed until a boiler shutdown could be scheduled.  The
   primary corrective action has been to provide another means of
   isolating the FGD plant from the boiler.

0  Steam Pressure Reducing Valve.  The valve has required a  sub-
   stantial amount of maintenance.

0  Evaporator Circulating Pump.  The pump for circulating the
   spent absorber solution through the evaporator heater is  driven
                                     2
   by a steam turbine, using 40 kg/cm  (550 psig) steam  supplied
   from the boiler.  Loss of this steam supply when the  boiler was
   shut down required that the evaporator be drained immediately
   to prevent solidification of the solution components  in the
   evaporator and the heater.  The solution would then be diluted
   for storage.  This resulted in evaporator startup delays.  The
   corrective action has been to provide an electric drive for the
   circulating pump.
                              3-20

-------
     0  Absorber Leaks.  Leaks at the bottom collector tray of the
        absorber resulted in absorber solution losses which probably
        required additional soda ash makeup at an added cost.   This
        is the solution from which sodium sulfate is removed from the
        process stream in the purge treatment area and dried to make
        a salable by-product.  Purge treatment rates were less than
        normal as a result of the leaks.  This prevented a full
        evaluation of purge treatment capacity.  The corrective action
        was to make absorber repairs to eliminate the leaks during the
        scheduled boiler shutdown of September 1978.

Boiler Operation Outside of FGD Design Limits

     During the demonstration year, the boiler did not operate  within FGD
plant design limits all of the time (Table 3.4) and by definition the FGD
plant was "called upon" to operate only when the boiler was operating within
the design limits.  The essential streams that NIPSCO provided for operation
of the FGD plant were:

     0  Flue gas (from Mitchell No. 11)
     0  Steam (from Mitchell No. 11)
     0  Electricity (from Mitchell No. 11)
     0  Cooling water (Mitchell Station source)
     0  Natural gas (Mitchell Station source)
     0  City water (Mitchell Station source)

Thus, the FGD plant was dependent on Mitchell Mo. 11 for flue  gas, steam  and
electricity.  Adequate supplies of electric power were not a problem but
delivery of flue gas and steam in amounts and of a quality suitable for
meeting the S0« removal performance requirements of the FGD plant contributed
substantially to the problems encountered during this demonstration year.
                                    3-21

-------
Steam Supply

     The FGD plant is designed to take up to 32,000 kg/hr (70,000 Ib/hr) of
39 kg/cm2 (550 psig) steam at. 400°C (750°F).  Boiler main steam at 130
kg/cm  (1800 psig) and 540°C (1000°F) is desuoerheated and the pressure is
reduced to deliver this steam.  There were no limits specified in the design
for the steam pressure and temperature.  As reported above, unstable or low
steam pressure limited operation of the FGD plant.  The causes were unstable
or low boiler main steam pressure resulting from coal feeding and boiler feed-
water problems as well as inadequate control at the steam reducing station.
Initially, operating experience indicated that a steam pressure of about
        2
37 kg/cm  (530 psig) was the lower limit of stable operation.  In practice,
the FGO plant was sometimes able to operate at moderately less steam
pressures.

Flue Gas Supply

     The FGD plant is designed to operate continuously at a rate of 9,100
am3/m (320,000 acfm) of flue gas at 150°C (300°F).  The absorber is designed
                             o
to take up to about 11,000 am /m (388,000 acfm) of flue gas.  For a lower
limit, Davy Powergas expects that the absorber can sustain operation down
to 46 MW equivalent gross load.   The FGD plant design is also limited to
treating flue gas from high sulfur coal in a range of about 2.8 to 3.5%
sulfur.  Specific test data have not yet been collected to indicate what
the lower limits are for sustained flue gas and inlet S02 rates.  However,
there were times that the FGD plant was not operated because, as a result
of low inlet SO,, rates, there was not enough recovered S02 available to
sustain operation of the reduction unit.
                                   3-22

-------
Plant Improvement Projects


     A program was initiated in June 1978 to undertake several  projects for
the purpose of eliminating or minimizing the various operating problems dis-
cussed above.  The projects and approximate completion time are presented
(Table 3.6).
                     TABLE 3.6   PLANT IMPROVEMENT PROJECTS
     Item

Coal supply


Air heater



Duct insulation


Blanks
Booster blower
steam blowing
Evaporator pump
Absorber
Booster blower
turbine

Sulfur condenser
Expect to Complete

Completed June 78
During September
shutdown
After September
shutdown

During September
shutdown
After September
shutdown
During September
shutdown

During September
shutdown

After September
shutdown

During September
shutdown
                Action

An uninterrupted supply of Captain  coal
available for Mitchell No. 11  use.

Part of baskets which provide  heat
storage removed to raise inlet duct
temperature.

Insulate duct before and after booster
blower.

Provision to install blanks rapidly at
inlet of booster fan as an alternative
to the isolation damper.

Install a sparger pipe in the  booster
blower to periodically steam clean
blades while in run.

Electrify pump.
Recoat and repair leaks.
Provide enclosure to protect against
S0« and weak acid attack.

Plug leaking tubes.
                                    3-23

-------
PROCESS ECONOMICS

     Tables 3.7 and 3.8 show the capital costs of installation and the pro-
jected operating costs of the FGD unit.

     Actual annualized operating costs, adjusted to the projected unit costs
and prices, were very nearly the same as the projected costs (Table 3.9)
despite the substantially lower utilities and raw materials costs that resulted
from the low utilization (25%) of the FGD plant.  Detailed cost breakdown for
identifying the significant variances are not available but it is known that
maintenance costs for the booster blower and other repairs were high.  The
actual costs are not typical of satisfactory operation that would be indicated
by high utilization and operability factors.  It is apparent that annualized
costs were not affected substantially by low operability because fixed costs
and labor charges continued to accrue.

RAW MATERIAL & ENERGY CONSUMPTION

     The raw materials are sodium carbonate (soda ash) and natural gas.  Soda
ash consumption averaged 8,200 kq/day (9.0 tons/day)  for the days of
absorber/evaporator operation.  The FGD unit is designed to consume 6,000 kg
day (6.6 tons/day) at design rates of 9,100 am3/m (320,000 acfm) of flue gas
containing 2,185 ppm of S02«  A leak past the bottom collector tray of the
absorber resulted in a loss of absorber solution in unknown amounts which
probably contributed to the excess consumption of soda ash.

     Natural gas consumption averaged 483 m /Tonne (17,072 cf per ton) of
sulfur produced for the periods of absorber/evaporator operation.  The FGD
                                                              o
unit is expected to produce one ton of sulfur with about 394 m  (13,900 cubic
feet) of natural gas.  Some gas was burned at the tail gas incinerator when
the S0£ reduction unit was pot operating.  Thus, part of the excess was con-
sumed during the 1,683 hours that the reduction unit was not operating.

     The total energy supplied by the boiler as steam and electricity averaged
lOxlO10 J/hr (95x10° Btu/hr), referred to boiler heat input (Table 3.10).
This is 12% of the average heat input to the boiler.   The energy equivalent
of the natural gas averaged 74x10  J/hr (7xl06 Btu/hr) during the time that
the absorber/evaporator was operating.

                                    3-24

-------
                        TABLE 3.7  CAPITAL COST
       Direct Capital Costs                        Cost,  $
Absorber & related equipment "'                   7,082,140
    (9\
Fans^'                                             399,130
      (3)
Reheatvo;                                           262,550
By-product recovery:  purge treatment             1,495,270
By-product recovery:  S02 reduction               1,143,750
Utilities & services^                           1,181,040
Stack requirements                                  146,020
System modi f i cati ons '  '                             241 , 930
Unidentified                                         60.000
    Direct cost subtotal                         11,891,830     oi
          Indirect Costs
Engineering                                         199,100
In-house construction expense                       322,230
Allowance for funds used during                     775,680
  construction
Allowance for start-up                            J3,700,510
Spares, off site, taxes, freight, etc.               284,000
Other(7)                                            958,680
    Indirect cost subtotal                        6.240.210
    Total capital cost                           18,132,040
    Cost per kilowatt of generating                156.85
      capacity, $/kW

   FGD plant receives flue gas -from an existing ESP at a normal
   dust loading of 0.09 grams/nT (0.04 grains/acf).  This cost item
   includes an orifice contactor for additional flyash removal  and
   for cooling and saturation of the gas prior to S02 absorption.
   This cost item also includes all equipment for SO, recovery
   and all equipment for soda ash storage and handling.
   Forced draft booster fan.
       natural gas-fired reheater for the absorber exit gas has
   not been operated due to natural gas restrictions.
   Included in this cost item are a 2,000 KVA transformer, natural
   gas lines, power lines, steam lines, and water lines.
                               3-25

-------
*  'The stack is erected atop the absorber.   The  top  of the
   stack is 51.2 meters (168 feet)  above grade.

^  'Extensive modifications,  primarily for winterizing, were
   made following a winter freeze-up.

*  'Administrative and overhead costs.
                               3-26

-------
         TABLE 3.8   PROJECTED ANNUAL OPERATING COST

        Variable Costs                             Cost. $
Operating labor                                     750,000
Maintenance labor and supplies                      853,000
Utilities:^   p
               1 j f • ^*
  (a)  Steam @ $2 .-35/1,000 lb^                     1,222,000
  (b)  Electric power @ $0*£-16/kWh                  126,000
  (c)  City water                                     7,000
  (d)  Treated water                                 30,000
         Utilities subtotal                       1,385,000
Raw Materials:
  (a)  Natural gas @ $1.60/106 Btu                  216,000
  (b)  Sodium carbonate., 2,317 tons                 204,000
  (c)  Other^                                      86,000
         Raw materials subtotal                     506,000
By-product creditsv°;                               (323,000)
Overhead                                            837,000
         Total variable costs                     4,008,000
        Fixed Charges
Interest                                          1,925,623
Annual depreciation                               1,813,204
Taxes                                             1.465,069
         Total fixed charges                      5,230,896
Total Annual Operating Cost                       9,211,896
Unit operating cost, mills/kWIr                     14.86

' 'No funds included for reheat fuel
^ 'Includes operating supplies
   Based on 7754 metric tons (7632 LT) of sulfur (S35.56/metric tons)($35/LT) *>
   1128 metric tons (1244 tons) of sodium sulfate ($40.82/metric tons)($46/ton)
   Based on 6.2xlOb kWh.  This is based on a projected load            ^°
   factor of 76.9% of a FGD plant capacity of 92 MW.
                               3-27

-------
                                         TABLE  3.9   ACTUAL  ANNUAL  OPERATING COST
CO
ro
oo
Item Description
VARIABLE COSTS
Utilities:
(a) Steam @ $2.35/1,000 Ibs
(b) Electric power Q $0.016/kWh
(c) City water
Utilities subtotal
Raw materials:
(a) Natural gas @ $1.60/106 Btu
(b) Sodium carbonate @ $88.04/ton^
Raw materials subtotal
Sulfur credit $35/LT(1)
Sodium sulfate credit @ $45/ton^
By-product credits subtotal
All other costs*2)
Total variable costs
TOTAL FIXED COSTS
TOTAL ANNUAL OPERATING COSTS
Unit operating cost, mills/kWh
Cost
Projected
520, OOOxl O3 Ibs
7,875,000 kWh
$7,000
130,814xl03 cf,
1,032 Btu/cf
2,317 tons
7,623 LT
1,244 tons

6.2xl08 kWh
Basis
Actual

224,1 38x1 O3 Ibs
2,813,000 kWh
$7,000 (assumed)
27,393xl03 cf,
1 ,025 Btu/cf
1 ,431 tons
1,456 LT
282.5 tons

5.9xl08 kWh
Cost
Projected
1,222,000
126,000
7,000
1,355,000
216,000
204,000
420,000
(267,120)
(55,980)
(323,100)
2,556,000
4,007,900
5.£03.$9§
9,211,796
14.86
, $
Actual

526,724
45,008
7,000
578,732
44,925
125,925
170,910
(50,960)
(12,713)
(63,673)
3,440,117
4,126,086
5.203.896
9,329,982
15.81
            '  'At year end,  raw material and  product  values were  as  follows:   Soda ash
                                                                                Sulfur
                                                                        Sodium sulfate
$82.28/metric tons ($90.70/ton)
$33.53/metric tons ($33/LT)
$12.33/metric tons ($13.59 ton)
            (2)
               Includes some estimate  due  to  billing  lags.

-------
                   TABLE 3.10  FGD PLANT ENERGY USAGE
     Heat input to boiler^                     786.2xl06 Btu/hr
     Hours of boiler operation                       7,800
     Hours of absorber/evaporator operation          3,836
     Average heat rate^1'                        10,400 Btu/kWh
     Total steam consumed^                     224,138xl03 Ibs
     Total  electric power consumecr ;              2,813,280 kWh
     Average energy equivalent of steanr ' '      87.6x10  Btu/hr
     Average energy equivalent of electricity* '   7.6x10  Btu/hr
       Average energy supplied by boiler         95.2x10  Btu/hr
       Total natural gas consumed* '              27,392,711 cf
       Average energy equivalent                  7.3x10  Btu/hr
       Total energy consumed                    102.5x10  Btu/hr

'  'For hours of boiler operation.
   For hours of absorber/evaporator operation.
^Approximated, using an enthalpy of 3,073 J/gram (1,320 Btu/lb).
^ 'Referred to heat input of boiler.
lc\                                  o
v 'Average heating value, 38.220 tf.J/m  (1,025 Btu/cf).

BOILER PERFORMANCE

     Boiler capacity factor was 0.585 (actual kilowatt hours generated per
maximum possible at a nameplate rating of 115.6 MWG) for an average of 68 HW
of power produced.  The boiler was operated 7,800 hours.  Average load was
76 MW for this operating time.  The gross heat rate averaged 11,000 kJ/kWh
(10,400 Btu/kWh) which was somewhat higher than a design heat rate of around
9700 kJ/kWh (9,200 Btu/kWh).  However, heat rate during the Baseline Test
(years 1974 and 1975) was 10,700 kJ/kWh) (10,100 Btu/kWh) at 92 MWG load.
                                    3-29

-------
Operating Problems

     The major boiler operating problems have been described in a preceding
section of this report.   Operating problems that limited boiler capacity are
summarized herein:

     0  Coal quality and associated coal feeding problems were a factor
        until Period 8 (April 1978) when burning of a better quality
        coal (Captain) was started (overhaul and modifications to the
        coal mills had also been partially completed by that time).

     0  Boiler operation was interrupted or limited due to high silica
        levels in the boiler feed water.  Although a boiler-related
        problem, the effect on boiler operation was compounded by the
        inadvertent loss of returned condensate from the FGD plant.

     0  Operation was also interrupted for turbine, precipitator, and
        ID fan repairs.   None of these interruptions were extensive
        but there was an overall effect on capacity.

The boiler was taken down nearly at the end of the demonstration year
(September 12, 1978) for a scheduled three week period for routine maintenance.
Three days of operation were lost as a result of this outage.  Unscheduled
outages amounted to a total of 37 days.

Retrofit Effects

     The FGD plant affected boiler operation in two ways.  First, boiler
load was limited by a FGD plant capacity limitation of about 2,300 kg/hr
(5,000 Ib/hr) of S02-  This equates to about 9,100 am3/m (320,000 acfm) of
flue gas at 150°C (300°F), 5% 02> and a coal sulfur level slightly above 3%.
With the boiler operating efficiently, this limits its capacity to 92 MWg or
80% of full capacity.  The FGD absorber 1s designed to take full boiler
capacity but the S02 recovery system was designed for the 92 MW of equivalent
                                    3-30

-------
boiler load.  With surge capacity provided, the FGD plant will operate above
92 MW for a limited time.  However, the average gross power output experienced
during the demonstration year was 76 MW for 7,800 hours of boiler operation
but was 79 MW during the 3,836 hours that the absorber/evaporator were
operating.  Therefore, on the average, the boiler operated substantially
below the 92 MW level whether the FGD plant was operating or not.  But boiler
operation was not typical, given the numerous"interruptions and unstable
operation of the boiler largely as a result of coal and water quality problems.
After correction of these problems, the FGD plant was operated with minimal
interruption for 1,028 hours (Periods 12 & 13, Auaust-September 1978).  Boiler
load history is shpwn (Table 3.11).
                TABLE 3.11 BOILER LOAD DISTRIBUTION
(1)
Gross Megawatts
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87

% of Time
0.3
0.3
1.4
3.1
6.8
13.3
16.6
23.7
17.1
9.2
5.0
1.5
1.4
0.1
0
0.2
100.0
               ' 'Based on 1,000 hours of data during
                  the period July 31-September 22, 1978.
                                     3-31

-------
This  is more typical of expected operation.  Also, the boiler was in better
condition than earlier in the year and, without the FGD plant, probably would
have  exceeded the 92 MW capacity limitation if required to by power demand.
The average load of 79 MWg reflects further derating of the boiler due to the
energy consumed by the FGD plant.
     There is also a lower limit of operation below which the StL reduction
unit will not operate.  This establishes minimum limits on boiler load or
on coal sulfur.

     The second major effect further limits boiler capacity to below 92 MW due to
the energy demands of the FGD plant.  For Periods 12 & 13, with the FGD plant
operating, steam consumption averaged 28,000 kg/hr (61,000 Ib/hr).  FGO electric
power usage averaged 774 kW.  The steam and electric power consumption repre-
sent direct derating of the boiler output.  The loss of available generating
capacity from FGD steam consumption is 10 MW.  Thus, 89 MW of power could
have been generated from the same boiler heat input during Periods 12 & 13,
had the FGD plant not been there.  Including nearly one megawatt of electrical
power consumed, this amounts to a boiler derating of 9% of nameplate capacity.

Flue Gas Characteristics

     Flue gas characteristics which affect FGD operation are primarily SOg
mass rate, flue gas volume and temperature,  ^rain loading may also be trouble-
some if excessive.  Volume 1s a function nf holler load; however, volume
as well as temperature will also be a function of the excess air carried by
the flue gas.  Obtaining a complete description of these characteristics has
been hampered by lack of reliable flue gas flow and moisture measurements
and by sporadic problems with the data acquisition system (DAS), resulting
in an incomplete record of some parameters.  The most stable period of
operation occurred from July 31 to September 12, 1978 (Table 3.12).
                                    3-32

-------
         TABLE 3.12  FLUE GAS CHARACTERISTICS   7/31/78 to 9/12/78
         Average load, MWG                                      79
         Average load (including steam equivalent), MWG         89
         Average coal rate, Ib/hr                           74,517
         Average sulfur in coal, %                           3.26
         S02 in flue gas, ppm ave.                           2,109
         Average flue gas volume, acfm                        (1)
         Flue gas temperature range, °F                       (2)
         Oxygen in flue gas, %                                (2)

         *  Not measured.
         (2)
         v 'Data on strip charts, not accessed.

The DAS was not operating during this period, preventing access of the data
for determining the flue gas temperature and the level of oxygen in the flue
gas.  Spot checks of temperature data for other periods of operation are
presented (Table 3.13). The oxygen data are being further analyzed before
reporting.

             TABLE 3.13  BOILER OUTLET FLUE GAS TEMPERATURES


9/16/77-9/19/77
11/5/77-11/23/77
12/10/77-12/23/77
FGD
Operated
yes
yes
no
Min. Temperature
°F
244
212
235
°C
118
100
113
Load, MWg
61
62
60
Max. Temperature
°F
280
304
309
°C
138
151
154
Load, MWg
85
61
95
                                    3-33

-------
Results of Special Tests

     Tests were conducted from November 16 to November 22, 1977, to measure
the performance variables that are not measured by the continuous monitoring
system.  The FGD performance with respect to possible flyash and SO, removal
are particularly of interest.

     Flyash concentrations at the inlet and outlet of the absorber are
reported in Table 3.1 Altogether with flue gas flowrates measured at the
time that a  particle   stack test was conducted.  The flyash removal rates
ranged from 40% to 96%, depending on the inlet particle loading.

                       TABLE 3.14  FLY ASH LOADING
DATE &
POSITION
11/16, Inlet
11/16, Outlet
11/18, Inlet
11/18, Outlet
11/19, Inlet
11/19, Outlet
11/21, Inlet
11/21, Outlet
11/21, Inlet
11/21, Outlet
11/22, Inlet
11/22, Outlet
11/22, Inlet
11/22, Outlet
GAS FLOWRATE^1)
(ACFM)
279,150
332,578
321,618
258,869
401,412
348,286
424,443
LOADING^
gm/m3 (Std.)
0.065
0.044
0.093
0.079
0.093
0.76
0.115
0.034
0.331
0.014
0.087
0.047
0.232
0.028
kg/hr
21.53
10.50
36.45
27.85
35.16
21.16
35.26
20.74
157.35
6.14
35.63
13.43
116.06
11.53
(1)
(2)
Corrected to 150°C (300°F)
Std. conditions  21°C,  29.92 in.Hg,
                                    3-34

-------
                     TABLE 3.15   SO,  AND  S02  REMOVAL
DATE
11/16
11/17
11/18
11/19
11/21
11/21
11/22
11/22
GAS FLOWRATE
(ACFM)
279,150
326,037
332,578
321,618
258,869
401,412
348,286
424,443
so?,
IN *•
2280
1987
2893
2777
2526
2185
2514
2259
ppm
OUT
193
140
245
257
96
264
215
199
SO.
IN ~
33
80
11
4
5
6
7
18
, ppm
S OUT
1
2
2
3
1
2
7
2
(1)
Corrected to 150°C
A pattern of SO, reduction is evident, although at these low concentrations
there is potential for considerable error.
                                     3-35

-------
                                SECTION 4
                            EVALUATION METHODS
EVALUATION GOALS
     Evaluation was in response to the test objectives and proceeded in six
steps:

     1.  Collect applicable data and operating information.

     2.  Define hours of operation within each operating mode.

     3.  Process the raw data and accumulate for each 30-day
         elapsed period and for specific periods according to
         the mode of operation.

     4.  Assess performance with regard to pollutant removal,
         dependability, energy consumption, and costs.

     5.  Assess the response of selected  dependent  variables to
         changes or fluctuations in the major independent variables.

     6.  Assess the effect of upsets and transients on S0« removal
         capability.

     The evaluation goals were dependent on a variety of measurement tech-
niques which provided the basis for reporting S02 removal efficiency,
operating load, FGD energy consumption, and cost of utilities.  In addition,
manual records were used to establish bulk materials consumption and by-
product production.  The operating status of the boiler and the FGD plant
was an equally important evaluation goal, leading to some rather detailed
determinations of the dependability of the two units.
                                    4-1

-------
THE TEST SYSTEM

     The core test system (Figure 4.1) consisted of sensors for various boiler
and flue gas operating variables (with emphasis on the FGD inlet and outlet
flue gas parameters) and accumulation of the sensor analog signals by a data
acquisition system (DAS).  The frequency of analog signal scan by the DAS
was three or six minutes, from which one-hour averages were computed.  The
DAS had the capability for storing the data on magnetic tape.  However, hard-
ware difficulties with the tape transport unit were experienced throughout
the demonstration year, so that very little automated data reduction was
possible.  Backup storage was available on teletype printouts or on charts
taken from strip chart recorders.  These data sources had to be utilized at
considerable penalty in the excessive time required to access the data and
reduce it manually.

     It was essential  that the test system data be correlated with opera-
tional disruptions or limitations.  Daily meetings were scheduled with NIPSCO
and Allied Chemical representatives to receive reports on the operating
status of the boiler and the FGD plant.  Use was also made of NIPSCO and
Allied reports to obtain raw material rates, product rates and costs.

     The parameters to be measured at each sampling position are shown on a
matrix (Table 4.1).  The numbered data items represent the DAS data channels
sampled every three or six minutes.  The X's indicate less frequent sampling,
at frequencies of every 24 hours, every 6 days, every 30 days, or for special
tests at least once during the test program.  The sampling positions are
located as shown (Figure 4.2 & Figure 4.3).
                                     4-2

-------
^—"^ 
-------
                                   TABLE 4.1   TEST PARAMETERS
I  •Vtmuft
'1 MJ/NCl*


  loo U »'
                                       f J:


ii

           lOtf ••••US tM^llPf




 f| -ijf!  =  |!
. Ail" J1 iiLiJJ ii
 11 ' 11  It I  >1 I 11 I
                                                                                                    l

-------
 I
on
                                                                                                                                                 ELECTRICAL
                                                                                                                                                  POWER  TO
                                                                                                                                                  FGO  PLANT
                                                                                                                ,TO ..TO .
                                                                                                                M2FM12G'
                                                                                                                          (120)       (12E)
                                                                                                                       HEATER'4  HEATER'S
                                                                                                 DEAERATOR
                                                                                                 HEATER-3
                                                                                                                HP STEAM
                                                                                                                   TO
                                                                                                                PGD PLANT
                                                                                                               FIGURE 4.3
                                  (36)
                                COOLING
                                 WATER
                                           CONDENSATE PUMPS
                                                                                                                                         ( )  SAMPLING POSITIONS
                                                                                                                                                 BYPASS
                                                                                                                                                TO  STACK
                                                                                                                 ELECTROSTATIC
                                                                                                                 PRECIPITATOR
                                                                                                                                                FLUE GAS
                                                                                                                                              TO  FGD PLANT
                                                                                                                                               FIGURE  4.3
                    A	
             FEEDER I    . I
                                                                                        TEMPERING
                                                                                    -0   AIR
                                                                                                                                                TO  FLY ASH
                                                                                                                                                 01 IPOs Al
OAL CRUSHER.  SCREEN
   & ELEVATOR
                                                                     PRIMARY AIR
                                                                        FANS
                                                                                                                                      1.0. TANS
                                                 FIGURE  4-2   MITCHELL  NO.  11  BOILER SAMPLING POSITIONS

-------
                                             FIGURE 4.3  SCHEMATIC DIAGRAM OF FGD PLANT
FlfrURE.
                  BOOSTER PAH

-------
METHODOLOGY

     The evaluation data flow is shown schematically on Figure 4.4 and the
data inputs are summarized in Table 4.2 with respect to measurement type,
frequency of recording and utilization.  The three or six minute values
stored by the DAS were used to determine one-hour averages.  The basic time
interval was one hour and S02 removal performance was assessed on the basis
of a one-hour averaging time.  Not all of the operating variables were
measurable at one-hour intervals.  To make the necessary comparisons; one-
hour data were accumulated, evaluated and reported for each 30-day period
and when possible according to operating mode status (FGD plant down, FGD
plant full operation, FGD plant partial operation).  The Demonstration year
reporting periods are shown in Table 2.1.

Data Reduction Procedures & Problems

     Most of the data were manually reduced from the DAS backup teletype hard
copy or from strip charts, and project logs.  Coal feed rates were obtained
from the NIPSCO coal scale totalizers.  FGD natural gas consumption was also
determined from daily totalizer readings.  Electrical energy consumption was
scanned by the DAS.  The other consumables and products were taken from the
Allied monthly summaries.  The intent was to do most data reduction
automatically, as described in the Demonstration Test Plan.^   Data obtained
on the DAS were stored on magnetic tape for subsequent processing by a batch
computer program.  Hardware difficulties with the tape drive and controller
were experienced throughout most of the demonstration year so that very little
automated data reduction was possible.  Hardware failures occurred with the
DAS and its analog signal interface occasionally, but these were corrected
as soon as possible for acceptable data recovery.  In one case of extended
DAS downtime, data were taken from backup recorder strip charts.  Therefore,
the only periods of complete data loss were during sensor failures.
        Inc., Environmental Engineering Division.  Program for Test and Evalua-
   tion of the NIPSCO/Davy/Allied Demonstration Plant.  Demonstration Test Plan.
   Prepared for Control Systems Laboratory, Office of Research and Monitoring,
   Environmental Protection Agency, Research Triangle Park, MC  April 8, 1975.
                                    4-7

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00
                                                                                                             FlGUtt«.«  DATA FIW FW EVULUA1IM

-------
                        TABLE 4.2   EVALUATION DATA INPUTS
      Measurement Type
Coal feed rate (belt weigher)

Coal analysis (laboratory)

Boiler load (gross MW)

Inlet flue gas S02 cone.
Inlet flue gas C0« cone.
Inlet flue gas 02 cone.
Flue gas temp. & pressure
FGD stack S02 cone.
FGD stack C02 cone.
FGD stack 02 cone.
FGD stack temp. & pressure
FAR sulfate (lab analysis)^)

FAR chlorides (lab analysis)

FAR total solids (lab
  analysis)
FGD steam rate (uncorrected)

FGD steam pressure

FGD steam temperature
FGD power use
FGD .soda ash use
FGD natural gas use
Purge salts production
Sulfur production
                             Sampling Frequency
                                Daily total

                              6-day composite &
                                 spot check
                               Hourly average
                               Hourly
                               Hourly
                               Hourly
                               Hourly
                               Hourly
                               Hourly
                               Hourly
                               Hourly
                                 Spot
average
average
average
average
average
average
average
average
tests
                                 Spot tests

                                 Spot tests

                               Hourly average

                               Hourly average

                               Hourly average
                               Hourly average
                             Monthly inventory
                                Daily total
                             Monthly inventory
                             Monthly inventory
        Utilization
Flue gas volume, boiler heat
  input
Flue gas volume, design
  limit check
Design limit check, flue gas
  corrections
S02 removal, FGD loading
Flue gas volume & dilution
Flue gas volume & dilution
Flue gas volume & characterization
S02 removal, S02 emissions
Flue gas dilution
Flue gas dilution
Relative humidity of stack gas
Sulfur balance, water medium
  effects
Chloride removal, water medium
  effects
Flyash removal, water medium
  effects
Economics, energy consumption,
  boiler derating
Design limit check, correct
  steam flow
Correct steam flow
Economics, energy consumption
Economics
Economics, energy consumption
Economics
Economics
(1)
FAR:  Flyash Purge
                                         4-9

-------
Measurement and Estimating Techniques

     The mass rate of S02 at the inlet or outlet of the absorber was deter-
mined by,
SO  mass rate  Ib/hr = (volume fraction SOJ(SCFH of flue gas)(f).  .
5U2 mass rate, lD/hr              (CF/mol r(mol/lb S02)            wnere
f is a factor correcting for the dilution resulting from saturation of the
flue gas with respect to water.  The factor was found to be a function of
boiler load.  This correlation was necessary as moisture measurements of flue
gas were not reliable.  The flue gas flowrate was estimated from known coal
firing rates and coal analyses.  The details of this calculation are given"
in Appendix C.  Another aspect of data estimation involved the values which
were used for time periods shorter than those actually observed.  Daily coal
feed rates, for example, were spread over the course of a day by making each
hourly coal feed rate estimate be proportional to MW generation by the boiler
for a given hour.   Six-day coal composite analyses were assumed to be repre-
sentative of their respective period of operation (Table 4.3).

                    TABLE 4.3  FLUE GAS COMPOSITION
MW Range (gross)
Parameters
H20 in
H20 out
C02 1n
C02 out
02 in
60-70

8.52
11.93
11.66
11.26
7.66
70-80

9.23
12.51
12.61
11.69
7.51
80-90

8.62
13.64
12.64
11.95
6.41
90-100

8.68
14.08
12.93
12.21
5.60
     FGD energy consumption calculations were all measurable, Including
electric power, steam, and natural gas.  FGD steam rates were corrected
for temperature and pressure as indicated in Appendix C.
                                   4-10

-------
QUALITY CONTROL

     Calibration of instruments using a known standard was the predominant
method employed for validating data accuracy.  Comparison of data obtained
by different methods and of the test data with a known standard was also
employed.

Cali brati on Procedures

     In order to ensure valid data measurements, the continuous analyzers
were calibrated routinely with known calibration gases for both zeroing
and spanning the instruments.  The following table illustrates the gas com-
positions for both the zero gas and span gas for the respective analyzer
(Table 4.4).

              TABLE 4.4  CONTINUOUS ANALYZER CALIBRATION
ANALYZER
S02 (Low Range)
S02 (High Range)
co2
H20
°2
RANGE OF
ANALYZER
0-500 PPMV
0-5000 PPMV
0-20 Volume
Percent
0-25 Volume
Percent
0-25 Volume
Percent
ZERO GAS SPAN GAS
N~ 260 PPMV S0?
in N2
N 2690 PPMV S02
^ in Np
N9 15% Volume
L C02 in N2
N2 100% C2H6 gives
instrument span
of 15.625;,
N2 Ambient Air (21%
02 by volume)
The S02 calibration gases are traceable to NBS standards.

     Certain other information was needed for determining performance.  The
source of these data and the calibration records are shown in Table 4.5.
The instruments installed for the acceptance and demonstration tests were
                                    4-11

-------
the major sources of data.  Other sources were coal scales, steam flow
meters, steam pressure, natural gas flow meters, and kilowatt-hour meter.
Steam flow, steam pressure and electrical energy consumption were transmitted
to the DAS.  Therefore, continuous real time data were available for analysis
from all instruments except the coal scales and the natural gas flow meters.
Totalized readings of coal and natural gas feed rates were taken at 0800
each day.

                  TABLE 4.5   INSTRUMENT CALIBRATIONS

                    ITEM                         CALIBRATED BY
         Coal  Scales                                NIPSCO
         FGD Inlet Temperature                        TRW
         FGD Inlet Static Pressure                    TRW
         FGD Outlet Temperature                       TRW
         FGD Outlet Static Pressure                   TRW
         Steam Flow Meter
         Steam Flow Transmitter                       TRW
         Steam Pressure
         Steam Temperature Transmitter                TRW
         Steam Pressure Transmitter                   TRW
         Natural Gas Flow Meters (2)
         Kilowatt-Hour Meter                        NIPSCO

Accuracy Verification of the Calibration Standard

     These verifications have been described in the Acceptance Test report.' '
For SOo, the standard gases were analyzed by EPA Method 6.  It was found
that the span gases, traceable to NBS standards were only 2 to 3% higher
than the mean value of repetitive Method 6 analyses.
I 'Adams, R. C., S. J. Lutz, and S. W. Mulligan.  Demonstration of We11man•
   Lord/Allied Chemical FGD Technology:  Acceptance Test Results.
   EPA-600/7-79-014a.  TRW, Inc., Durham, NC  January 1979.
                                   4-12

-------
     The accuracy of the span gases was also verified against a standard
gas supplied by Research Triangle Institute in conjunction with their quality
assurance program for EPA.  This gas was analyzed by the continuous analyzer
after calibration with the following results:

                Analyzer Reading, ppm              1275
                Actual Gas Analysis, ppm        1262   1264
                Apparent Error, %                 +0.95

     During the Acceptance Test, a modified version of EPA Method 6 was used
to determine S02 concentration entering and leaving the absorber.  The effect
of the method modification was to extend the sampling time to coincide with
particulate matter sampling (4-5 hours per day).  The average removal effi-
ciency determined by the continuous analyzer was less than one percent higher
than the comparable average of Method 6 results.

Instrument Reliability

     Most of the problems affecting data acquisition were associated with
the flue gas sampling and analysis system.  The parameters needed for deter-
mining SOp removal performance are flow and the concentrations of SC^, CC^
or 02, and H,,0.

     The test program was hampered by the lack of a dependable measurement
of two of these flue gas parameters:  flow rate and moisture content.
Annubars placed in the FGD stack did not provide a dependable or accurate
flow measurement.  Accuracy was poor due to unidentified disturbances that
dictated more than the eight traverse points available with the Annubars.
Also, signal resolution was lost due to inherent instability of the sensor
signals.  The water analyzer was a non-dispersive infrared (NDIR) type.
Stable operation was never achieved after the Acceptance Test and the
instrument was finally abandoned as not suitable for the application
intended.  Without reliable flow and moisture measurements, estimating
                                   4-13

-------
techniques were resorted to for determining StL removal.  System uptime
for S02 content and (L or C02 content was 80% of the hours of absorber
operation (Appendix A).  Either 02 or C02 absorber inlet and outlet values
along with H^O inlet and outlet values are used to determine the amount of
flue gas dilution during absorption.  The S02 analyzer, at 89% uptime,
was somewhat more reliable.
Variability in SOp Removal Result

     The removal performance, expressed as a percentage was determined as
fol1ows:

                    S02 Removal = ^2 in " |gg ff * f

where f is a factor to correct for dilution effects:
                    <: _ OL in    (1 - HoO in)
                    T ~ CO^'out x (l - HJO out)
The same instruments used for measuring the inlet concentration also measured
the outlet concentrations.  If it is assumed that the instruments are in
error in one direction only, the errors tend to compensate.  Therefore, it
is probable that the variability of the SO* removal results were quite small.
However, it is true that sampling errors would not necessarily be compensating
since inlet and outlet samples are collected and conditioned by separate
sampling systems.  No attempt has been made to estimate the magnitude of
sampling errors, but these types of errors have been minimized in the design
and operation of the sampling systems.
                                   4-14

-------
APPENDIX A.  DATA BASE
            A-l

-------
                    TABLE A.I   BOILER  PERFORMANCE DATA
   DATE

 9/16/77
 9/17
 9/18
 9/19
 9/20
 9/21
 9/22
 9/23
 9/24
 9/25
 9/26
 9/27
 9/28
 9/29
 9/30

10/01/77
10/02
10/03
10/04
10/05
10/06
10/07
10/08
10/09
10/10
10/11
10/12
10/13
10/14
10/15
10/16
10/17
10/18
10/18
10/20
10/21
10/22
10/23
10/24
10/25
10/26
10/27
10/28
10/29
10/30
10/31
COAL USAGE
 (Ibs/hr)

   95833
   93779
   71467
   35521
   39679
   51541
   30842
    9842
   20533
   34629
   27600
   26096
   38938
   53946
   87696

   86167
   77108
   93325
   90558
   90358
   87621
   94933
   90242
   88888
   91629
   96529
   80150
   70621
   77504
   66442
   74600
   78942
  101129
   98950
   89979
   74058
   75829
   81038
  111817
  138929
   75021
   76067
   86450
   37675
   97450
       0
HEATING VALUE
   (BTU/lb)

     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890

     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
     9890
    10527
    10527
    10527
    10527
    10527
    10527
    10581
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
    10571
BOILER HEAT
    INPUT
(IP6 BTU/HR)

   947.79
   927.47
   706.81
   351.30
   392.43
   509.74
   305.03
    97.34
   203.07
   342.48
   272.96
   258.09
   385.10
   533.53
   867.31

   852.19
   762.60
   922.98
   895.61
   893.64
   866.57
   938.89
   892.49
   879.10
   964.58
  1016.16
   843.74
   743.43
   815.88
   699.43
   788.60
   934.50
  1069.03
  1046.00
   951.17
   782.87
   801.59
   856.55
  1182.02
  1468.62
   793.05
   804.10
   913.86
   398.26
  1030.14
   HEAT
   RATE
 (BTU/KWHl

    11465
    11808
    11904
     9184
    10349
    15564
     4386
    10716
    32930
    74722
     9851
     8473
     9577
     9722
    11197

    11620
    11439
    11159
     7174
    10793
    24099
    11449
    10884
    10720
    11763
    12224
    12865
    13672
    13311
    14094
    13635
     7384
    24411
    11908
    12078
    11967
    12253
    12481
    11771
    14928
     8061
    12229
    12104
    10727
    11846
(Boiler Down)
                                    A-2

-------
  DATE

11/01/77
11/02
11/03
11/04
11/05
11/06
11/07
11/08
11/09
11/10
11/11
11/12
11/13
11/14
11/15
11/16
11/17
11/18
11/19
11/20
11/21
11/22
11/23
11/24
11/25
11/26
11/27
11/28
11/29
11/30

12/01/77
12/02
12/03
12/04
12/05
12/06
12/07
•12/08
12/09
12/10
12/11
12/12
12/13
12/14
12/15
12/16
12/17
12/18
12/19
12/20
COAL USAGE
 (Ibs/hr)

   83867
   68417
   81792
   73783
   83958
   88400
   82858
   78208
   83804
   80650
   83538
   56475
   97596
   73813
   73646
   80921
   87817
   66142
   67042
   69538
   78475
   79625
   36683
   85696
       0
       0
   79508
   80758
   77658
   70388

   76713
   71142
   86850
   80600
   74429
   79463
   19350
   55308
   55308
   15800
       0
   70383
   87821
   88550
   91567
   49563
   253.63
   78602
   78602
   75308
HEATING VALUE
   (BTU/lb)

    10571
    10571
    10571
    15071
    10571
    10571
    10571
    10571
    10271
    10271
    10271
    10271
    10271
    10271
    11011
    11011
    non
    noii
    non
    non
     9653
     9653
     9653
     9653
     9653
     9653
     9653
     9653
     9653
     9653

     9653
     9653
    10556
    10556
    10556
    10556
    10556
    10556
    10118
    10118
    10118
    10118
    10118
    10118
    10064
    10064
    10064
    10064
    10064
    10064
BOILER HEAT
    INPUT
(IP6 BTU/HR)

   886.56
   723.24
   964.62
   779.96
   887.52
   934.48
   875.89
   826.76
   860.75
   828.36
   858.02
   580.05
  1002.41
   758.13
   810.92
   891.02
   966.95
   728.29
   738.20
   765.68
   757.52
   768.62
   354.10
   827.22
        0
        0
   767.49
   777.36
   749.63
   674.46

   740.51
   686.73
   916.79
   850.81
   785.67
   838.81
   837.62
   503.83
   559.61
   159.36
        0
   712.14
   888.57
   895.95
   921.53
   498.80
   255.25
   791.05
   791.05
   171.90
   HEAT
   RATE
 (BTU/KWH)

    12291
    12829
     7806
    34536
    11588
    11501
    12039
    11035
    11489
    10752
    10758
     9262
    12071
    10895
    11932
    12353
    12578
     9942
    11177
    11689
    10033
     9960
     9463
     9689
(Boiler  Down)
(Boiler  Down)
     9745
     9888
     9667
     9973

     9967
    10653
    11376
    11275
    11575
    11490
    11243
    11182
    10718
     9837
(Boiler  Down)
     9936
    10078
    10407
    10159
     5496
    85083
    12539
    12539
    10898
                                     A-3

-------
  DATE

12/21/77
12/22
12/23
12/24
12/25
12/26
12/27
12/28
12/29
12/30
12/31

 1/01/78
 1/02
 1/03
 1/04
 1/05
 1/06
 1/07
 1/08
 1/09
 1/10
 1/11
 1/12
 1/13
 1/14
 1/15
 1/16
 1/17
 1/18
 1/19
 1/20
 1/21
 1/22
 1/23
 1/24
 1/25
 1/26
 1/27
 1/28
 1/29
 1/30
 1/31

 2/01
 2/02
 2/03
 2/04
 2/05
 2/06
 2/07
 2/08
 2/09
COAL USAGE
 (Ibs/hr)

   87758
   84033
   57488
   60292
   56075
   59204
   39329
   45867
   49429
   53571
   69733

   57025
   63367
   64933
   59746
   62708
   27288
   71108
       0
       0
   80858
   54488
   67917
   80100
   81279
   33879
   86592
   97133
   88775
  107488
  102767
   47833
   13229
  106796
   93408
  114800
  104167
   92900
   87379
   87717
  103079
   94004

   91629
  104308
   85563
   36004
   16100
   99233
   99233
  110908
   62063
HEATING VALUE
  (BTU/lb)

    10097
    10097
    10097
    10097
    10097
    10097
     9637
     9637
     9637
     9637
     9637

     9637
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10457
    10690
    10690
    10690
    10690
    10690
    10690
    10341
    10341
    10341
    10341
    10341
    10341
     9953
     9953
     9953
     9953
     9953
     9953

    10922
    10922
    10922
    10922
    10922
    10922
    10122
    10122
    10122
BOILER HEAT
   INPUT
  0* BTU/HR)
   273.43
   580.46
   608.77
   566.19
   597.78
   379.01
   442.02
   476.35
   516.26
   672.02

   549.55
   662.63
   679.00
   624.76
   655.74
   285.35
   743.58
        0
        0
   845.53
   569.78
   110.21
   837.61
   868.87
   896.62
   925.67
  1038.35
   949.00
  1149.05
  1062.71
   494.64
   136.80
  1104.36
   965.93
  1137.15
  1036.77
   924.63
  '869.68
   873.05
  1025.95
   935.62

  100.77
  1139.25
   934.52
   393.24
   175.84
     1084
     1084
  1122.61
   628.20
   HEAT
   RATE
 CBTU/KWH)

    10288
    10667
    10015
     9772
     9940
     9956
    10186
     9514
     9080
     5391
    29112

    10784
    11499
    11070
    10960
    10891
     9714
    11077
(Boiler flown)
(Boiler Down)
    10156
    10069
     9779
     9839
    10704
     7275
    20251
    10366
    10118
     9959
    10197
     9167
    16751
    10066
     9603
    10223
    10884
    10179
    10530
    10625
    10178
    10006

    11181
    11256
    11186
    11709
    10343
     8661
     8661
    15127
    10024
                                    A-4

-------
  DATE

2/10/78
2/11
2/12
2/13
2/14
2/15
2/16
2/17
2/18
2/19
2/20
2/21
2/22
2/23
2/24
2/25
2/26
2/27
2/28

3/1/78
3/2
3/3
3/4
3/5
3/6
3/7
3/8
3/9
3/10
3/11
3/12
3/13
3/14
3/15
3/16
3/17
3/18
3/19
3/20
3/21
3/22
3/23
3/24
3/25
3/26
3/27
3/28
3/29
3/30
3/31
COAL USAGE
 (Ibs/hr)

  59433
      0
      0
      0
      0
      0
      0
  86835
  86835
  93671
  87838
  67075
  85467
  87779
  99942
 105075
 102192
 103379
  97700

  63021
  52700
  67488
  64033
  64533
  73275
  72483
  68763
  72096
  71717
  71075
  69263
  67863
  66938
  37038
  17479
      0
  68692
  67913
  74146
  81800
  75621
  59075
  74529
  53221
  48213
  85783
  58129
  66292
  78242
  42058
HEATING VALUE
  (BTU/lb)

    10122
    10122
    10122
    10122
    10122
    10122
    10122
    10122
    10122
    10122
    10367
    10367
    10367
    10367
    10367
    10159
    10159
    10159
    10159

    10159
    10159
    10691
    10691
    10691
    10691
    10691
    10691
    10691
    10711
    10711
    10711
    10711
    10711
    10711
    10711
    10711
    10711
    10711
    10711
     9633
     9633
     9633
     9633
     9633
     9633
    10885
    10885
    10885
    10885
    10885
BOILER HEAT
  INPUT
(IP6 BTU/hr)
(BTU/KWH)
601.58
0
0
0
0
0
0
878.94
878.94
948.14
910.62
695.37
886.04
910.00
1036.10
1067.46
1038.17
1050.23
992.53
649.23
535.38
721.51
684.58
189.92
783.38
774.92
735.15
770.78
768.16
761.78
741.88
726.88
716.97
396.71
187.22
0
735.76
727.42
794.18
787.98
728.45
569.06
717.93
512.67
464.43
933.74
632.73
721.58
851.66
457.80
3246
(Boiler Down)
ii ii
it ii
ii n
n n
n n
50647
50647
11371
11156
12408
10989
11205
7630
17643
10283
10200
10214
10340
10213
10108
10565
10361
11450
11257
9818
7017
30573
11174
11479
11545
11372
11161
10188
(Roller Down)
10961
11014
10897
6278
22299
99038
10052
7680
8437
10049
12013
11491
10803
10605
                                   A-5

-------
  DATE

4/1/78
4/2
4/3
4/4
4/5
4/6
4/7
4/8
4/9
4/10
4/11
4/12
4/13
4/14
4/15
4/16
4/17
4/18
4/19
4/20
4/21
4/22
4/23
4/24
4/25
4/26
4/27
4/28
4/29
4/30

5/1
5/2
5/3
5/4
5/5
5/6
5/7
5/8
5/9
5/10
5/11
5/12
5/13
5/14
5/15
5/16
5/17
5/18
5/19
5/20
COAL USAGE
 (Ibs/hr)

   8745
      0
  72017
  53842
  52479
  53562
  72001
  72001
  72001
  72001
  72001
  72001
  72001
  15467
      0
      0
      0
      0
  74600
  70504
  77553
  77553
  77553
  59988
  51542
  57596
  59796
  64799
  64799
  64799

  74025
  79617
  31229
      0
      0
      0
      0
  64275
  79929
  78258
  80575
  81729
  84895
  81954
  74958
  63296
  62258
  77675
  79738
  79121
HEATING VALUE
  CBTU/lb)

    10885
    10885
    10885
    10885
    10885
    10885
    10885
    10097
    10097
    10097
    10097
    10097
    10097
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10990
    10867
    10867
    10867
    10867
    10867

    10867
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10483
    10828
    10828
    10828
    10828
    10828
    10828
    10828
BOILER HEAT
  INPUT
(IP6 BTU/hr)

    95.29
     0
   783.91
   586.07
   571.23
   583.02
   783.73
   726.99
   726.99
   726.99
   726.99
   726.99
   726.99
   169.97
     0
     0
     0
     0
   818.85
   774.84
   852.30
   852.30
   852.30
   659.26
   566.44
   625.89
   646.80
   704.17
   704.17
   704.17

   804.43
   834.62
   327.38
     0
     0
     0
     0
   673.79
   837.90
   820.38
   844.67
   856.77
   889.96
   887.40
   811.65
   685.37
   674.13
   841.06
   863.40
   856.72
 (BTU/KWH)

   10490
(Boiler Down)
   10337
    9836
   24051
    9097
   10443
    9687
    9687
    9687
    9687
    9687
    9687
   10459
(Boiler Down)
   10100
    4725
   15025
   15025
   15025
    9784
    9614
    9318
    9169
   10180
   10180
   10180

    9915
    9435
    4224
(Boiler Down)
    8694
   10339
   10619
   10754
   10726
   11078
   12100
   11451
   11312
   11401
   14225
   10975
   10960
                                    A-6

-------
  DATE

5/21/78
5/22
5/23
5/24
5/25
5/26
5/27
5/28
5/29
5/30
5/31

6/1/78
6/2
6/3
6/4
6/5
6/6
6/7
6/8
6/9
6/10
6/11
6/12
6/13
6/14
6/15
6/16
6/17
6/18
6/19
6/20
6/21
6/22
6/23
6/24
6/25
6/26
6/27
6/28
6/29
6/30

7/1/78
7/2
7/3
7/4
7/5
7/6
111
7/8
7/9
7/10
COAL USAGE
 (Ibs/hr)

  79125
  80504
  79942
  83963
  83304
  79113
  81946
  82125
  79100
  72938
  77125
  77596
  76590
  76590
 100796
  47613
  75021
  67404
  66750
  64125
  70858
  65825
  71342
  69471
  69646
  71292
  71029
  68007
  68007
  68007
  65788
  70954
  67413
  56463
  58238
   5588
HEATING VALUE
  (BTU/lb)

    10900
    10900
    10900
    10900
    10900
    10255
    10255
    10255
    10255
    10255
    10255

    10255
    10329
    10329
    10329
    10329
    10329
    10779
    10779
    10779
    10779
    10779
    10779
    10779
    11083
    11083
    11083
    11083
    11083
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
BOILER HEAT
   .INPUT
(106 BTU/hr)

   862.46
   877.50
   871.36
   915.19
   908.02
   811.30
   840.35
   842.19
   811.17
   747.97
   790.92
   836.41
   825.56
   825.56
  1086.48
   513.22
   808.65
   726.55
   739.79
   122.83
   785.32
   629.54
   790.68
   746.12
   748.00
   765.68
   762.85
   730.40
   730.40
   730.40
   706.56
   762.05
   724.02
   606.41
   625.48
    60.02
(BTU/KWH)

  11027
  10974
  10943
  10341
  11512
  10324
  10460
  10599
  10483
  10522
                                                     No  data
                                                     sheet  for
                                                     days 6/1
                                                     thru 6/6
  10903
  10116
  10116
  13399
   6336
  10155
  10067
  10209
   1702
  10210
   9776
  11007
   9992
   9890
  10158
  10126
  10327
  10327
  10327
  10172
  10076
  10067
  10432
No data
sheet for
days 7/1
thru 7/4
   9459
   9667
No data
sheet for
days 7/8
thru 7/10
                                    A-7

-------
  DATE

7/11/78
7/12
7/13
7/14
7/15
7/16
7/17
7/18
7/19
7/20
7/21
7/22
7/23
7/24
7/25
7/26
7/27
7/28
7/29
7/30
7/31

8/1/78
8/2
8/3
8/4
8/5
8/6
8/7
8/8
8/9
8/10
8/11
8/12
8/13
8/14
8/15
8/16
8/17
8/18
8/19
8/20
8/21
8/22
8/23
8/24
8/25
COAL USAGE
 (Ibs/hr)

  71142
  62767
  62767
  69525
  75975
  68450
  74658
  71079
  62913
  63404
  64083
  61292
  54467
  55563
  63838
  74167
  69792
  77904
  74825
  76225
  77054

  78721
  78521
  79779
  74129
  75383
  73017
  74029
  73642
  76546
  73413
  77029
  74221
  74221
  73488
  75000
  77379
  75871
  74871
  80613
  72125
  74058
  77142
  75600
  76375
  76329
HEATING VALUE
  (BTU/lb)

    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10740
    10854
    10854
    10854
    10854
    10854
    10854
    10854
    10854
    10854
    10854
    10854

    10854
    10854
    10854
    10854
    10854
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10741
    10952
    10952
    10952
    10952
    10952
    10952
    10952
    10796
BOILER HEAT
   cINPUT
(10° BTU/hr)

   764.07
   674.12
   674.12
   746.70
   815.97
   735.15
   801.83
   763.39
   675.69
   680.96
   695.56
   665.26
   591.18
   603.08
   692.90
   805.01
   757.52
   845.57
   812.15
   827.35
   836.34

   854.44
   852.27
   865.92
   804.60
   818.21
   784.28
   795.15
   790.99
   822.18
   788.53
   827.37
   797.21
   797.21
   789.33
   805.58
   831.13
   814.93
   819.99
   882.89
   789.91
   811.08
   844.86
   837.97
   836.46
   824.05
(BTU/KWH)

  12290
  10374
  10374
  11517
  11261
  11427
  11072
  11144
  11168
  11388
  10917
  10658
  10651
   9779
  10605
  10540
  10490
  10951
  10610
  11314
  10873

  10873
  10880
  10801
  10775
  10678
  10616
  10631
  10767
  10841
  11080
  11168
  10611
  10611
  10472
  10629
  10730
   9784
  11645
  11623
   8448
  13527
  11366
  10900
  10928
  10807
                                   A-8

-------
  DATE

8/26/78
8/27
8/28
8/29
8/30
8/31

9/1/78
9/2
9/3
9/4
9/5
9/6
9/7
9/8
9/9
9/10
9/11
COAL USAGE
 (Ibs/hr)

  76683
  76050
  75067
  77996
  74096
  74729

  78196
  76669
  76669
  74108
  73546
  74525
  74408
  73525
  75446
  75250
  71638
HEATING VALUE
  (BTU/lb)

    10796
    10796
    10796
    10796
    10796
    11379

    11379
    11379
    11379
    11379
    11379
    11379
    11379
    11379
    11379
    11379
    11379
BOILER HEAT
   ,INPUT
(10° BTU/hr)

   827.87
   821.04
   810.42
   842.04
   799.94
   850.34

   889.79
   872.42
   872.42
   850.10
   836.88
   848.02
   846.69
   836.64
   858.50
   856.22
   815.17
(BTU/KWH)

   10659
   10785
   10687
   11073
   10272
   11269

   11198
   11247
   11247
   10268
   12085
   10954
   10954
   11014
   10017
   12124
(Data up
 9/11/78)
to
                                    A-9

-------
                         TABLE A.2  BY-PRODUCT PRODUCTION AND RAW MATERIAL CONSUMPTION
     PERIOD
Natural Gas, MM Btu
Steam, MM Btu
Soda ash,
   consumed, tons
Sulfur produced,
   tons
                (1)
Purge salts      /-.x
   produced, tonsv ;
                      1234

                     10.4    7.4    10.3
                     77.9   69.3    74.5   72.0
                     19     87     171      97
                     39

                      4
91

 9
285

 50
 0
11.5
                                        8
                                               10     11
                                                     12     13
                            	    10.8    1.2    2.1    11.1    10.1
                           68.0  75.4   —    84.9   79.6   73.2    82.1    78.3
                           34.7 212    22.8  243     53    106.5   262.5   123.5
0   135
            0
191
 44     40
 8.5  504.5  202
25.7   58
40.3
 (1)
From Allied Chemical  summary reports.

-------
   TABLE A.3  NATURAL  GAS CONSUMPTION
     FOR THE MONTH  OF  DECEMBER  1977

DATE                        (CF X  IP5)
12/1                            .972
12/2                           1.067
12/3                           1.102
12/4                            .909
12/5                            .975
12/6                            .989
12/7                            .986
12/8                            .995
12/9                            -995
12/10                           .952
12/11                           .952
12/12                           .956
12/13                          1.013
12/14                           .950
12/15                           -930
12/16                           -935
12/17                           .945
12/18                           -932
12/19                           .932
12/20                           -988
12/21                          1-092
12/22    .                       -990
12/23                           -922
12/24                          1-002
12/25                          I-062
12/26                           -995
12/27                          1-059
12/28                          1-087
12/29                          I-033
12/30                          I-001
12/31                           I-069
  1/1                            -818
  1/2                            .952

                    A-ll

-------
  TABLE A.4  NATURAL GAS CONSUMPTION
    FOR THE MONTH OF AUGUST 1978


DATE                        (CF X IP5)
7/31                           2.10
8/1                            2.401
8/2                            2.356
8/3                            2.360
8/4                            2.272
8/5                            2.477
8/6                            2.354
8/7                            2.414
8/8                            2.326
8/9                            2.410
8/10                           2.266
8/11                           2.531
8/12                           2.254
8/13                           2.254
8/14                           2.362
8/15                           2.196
8/16                           2.337
8/17                           2.403
8/18                           2.467
8/19                           2.353
8/20                           2.345
8/21                           2.384
8/22                           2.364
8/23                           2.361
8/24                           2.363
8/25                           2.383
8/26                           2.396
8/27                           2.451
8/28                           2.523
8/29                           2.565
8/30                           2.508

                     A-12

-------
                    TABLE A.5  ANALYTICAL RESULTS - PURGE SOLIDS


                 % Sodium     % Sodium      % Sodium        % Sodium
Date Sampled      Sulfate      Sulfite     Pyrosulfite     Thiosulfate     %  Moisture

   5/22/78         93.16         6.54         1.9             .03             .11
   5/23/78         96.64         8.00         1.9             .03             .18
   5/24/78         93.56         7.43         1.14            .06             .12
   5/25/78         94.28         8.52         1.14            .13             .09
   5/26/78         96.25         9.15          .38            .06             .06
   5/28/78         92.48        10.08          .76  '        >.03             .10
   5/29/78         94.95        10.20          .57            .09             .10
   5/30/78         93.83        13.21          .38            .09             .04
   5/31/78         81.98        12.02          .72            .09             .23
    6/1/78         82.52        12.13          .57            .06             .18
    6/2/78         86.43        11.40         1.06            .09             .13
    6/3/78         89.73         9.52          .61             0              .20
    6/4/78         84.07        10.28          .61             0              .05
    6/5/78         90.29         9.28         1.18             0              .03
    6/6/78         83.99         9.55          .68             0              .19
                   73.40        14.46          .51             0              .02
    6/7/78         91.87          -            -              .06             .13
    6/8/78         79.69         9.53          .38            .10             .13
    6/9/78         92.19         9.43          .30             0              .09
   6/10/78         92.47        11.13          .15             0              .06
   6/11/78         68.25        10.03          .22             0              .17
   6/12/78         90.48         9.81          .19            .03             .26
   6/13/78         92.49        11.09          .19             0              .05
   6/14/78         90.17        11.01          .34            .03             .09
   6/15/78         92.48        10.70          .22            .025            .15
   6/16/78         92.19        10.36          .23            .05             .16
   6/17/78         80.99         9.99          .32            .05             .04
   6/18/78         93.19         9.84          .30            .05             .17
   6/20/78         93.49        11.04          .21            .05             .09
   6/21/78         91.17        10.11          .51            .25             .09
                                          A-13

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      TABLE A.6  SIGNIFICANCE AND SOURCE OF DATA LISTED IN TABLE 3.1

Start/End - Period length, dates are shown.  The hour, 0800 CST or CDT is
            implicitly a part of all entries except substitute 0000 CDT for
            the initial 9/16 and 2400 CDT for the final 9/15.  Comes from
            schedule.

Mrs. Total - Elapsed hours per operating period.  Comes from schedule.

Mrs. Boiler Operated - Entire hours boiler is fired per operating period.
            Calculated from the daily status report.

Mrs. Boiler Operated <46 MW - Hours per operating period when generator
            output is less than 46 MW.  Calculated from DAS teletype print-
            out or strip chart records.

Mrs. FGD Operated - Hours per operating period when the absorber and
            evaporator ran.  Calculated from the daily status report.

Avg. Load, MWG - Overall average hourly power production of the generator.
            Calculated from DAS teletype printout or strip chart records.

Avg. Load, MWG - Avg. load MWG above reduced by the overall average hourly
            power requirements of the boiler auxiliaries and the FGD.
            Calculated from DAS teletype printout or strip chart records.

Avg. Load, MWG, FGD Down - Average hourly power production of the generator.
            Calculated from daily status reports and DAS teletype printout
            or strip chart records.

Avg. Load, MWG, FGD Down - Avg. load, MWG, FGD down above reduced by average
            hourly power requirements of the boiler auxiliaries only.
            Calculated from daily status reports and DAS teletype printout
            or strip chart records.
                                    A-14

-------
 Net/Gross - Overall average fraction of generated power delivered to trans-
             mission network.  Calculated from above data.

 Net/Gross, FGD Down - Average fraction of generated power delivered to trans-
             mission network when the absorber and evaporator are not running.
             Calculated from above data.

 FGD Avg. Steam Usage, Lb/Hr - Average hourly steam usage of FGD plant when
             absorber and evaporator are running.  Calculated from the daily
             status report and DAS teletype printout or strip chart records.

 Avg. Coal Rate, Lb/Hr - Overall average hourly coal usage of boiler.
             Calculated from totalized coal usage meter readings for the four
             boiler coal mills collected once a day.

MW Equiv. of FGD Steam Usage (Condensate Returned) & (Condensate Not Returned) •
            Power equivalent of the average FGD hourly steam usage.  Calculated
            from above data and using a rounded boiler efficiency of 88°- cal-
            culation method:

             S  = FGD hourly average steam usage, Ibs.
             E.  = Boiler efficiency, fraction & dimensionless
             H  = Gross heat rate, BTU/KWH
             H. = Boiler heat loss in steam, BTU/lb
             P  = Equivalent power loss as FGD steam, MW

             p  = IU-JTIS     Note:  HI$ = 1370.7 BTU/lb with condensate
                   b  9                   returned, 1480.4 BTU/lb without

% Derating (Condensate Returned) *< ( Condensate Not Returned) - Percentage that
            steam power equivalent represents of boiler gross generation
            capability with no FGD operation.  Calculated as 100 times the
            quotient of the respective power equivalent and the sum of the
            respective power equivalent plus the gross power generated.
                                    A-15

-------
Coal HHV, Btu/Lb - Average heating value of the wet coal fired.  Calculated
            from laboratory analyses reported for composite samples taken
            during 6-day subintervals in the period.

Boiler Heat Input Rate, 106 Btu/Hr - Overall average hourly heat supplied to
            boiler.  Calculated as product of coal usage and heating value
            described above.
                              4
Gross Heat Rate, Btu/KWH - Overall average heat supplied to boiler for each
            kilowatt-hour of power generated.  Calculated from above data.

Net Heat Rate, Btu/KWH   Overall average heat supplied to boiler for each
            kilowatt-hour of power delivered to transmission network.
            Calculated from above data.

Avg. Inlet S02, PPM by Vol. - Average S02 inlet flue gas concentration.
            Calculated from DAS teletype printout or strip chart records.

Max. Inlet S02> PPM by Vol. - Highest hourly averaged inlet S02 concentration
            existing in the period.  Directly taken from DAS teletype printout
            or strip chart records.

Min.Inlet S02» PPM by Vol. - Lowest hourly average inlet S0« concentration
            existing in the period.  Directly taken from DAS teletype printout
            or strip chart records.

Avg. Outlet S02, PPM by Vol. - Average S02 outlet flue gas concentration.
            Calculated from DAS teletype printout or strip.

Max.Outlet S02, PPM by Vol. - Highest hourly averaged inlet S02 concentration
            existing in the period.  Directly taken from DAS teletype printout
            or strip chart records.
                                    A-16

-------
Min Outlet S02, PPM by Vol. - Lowest hourly averaged outlet S02 concentration
            existing in the period.  Directly taken from DAS teletype print-
            out or strip chart records.

Avg. S02 Rate in, Lbs/Hr - Average hourly weight of S02 fed to FGD plant by
            flue gas while absorber and evaporator were operating.  Calculated
            from hourly inlet flue gas flow rates derived from daily coal
            usage rates of the four mills, the-elemental analysis of 6-day
            period coal composite sample, and the DAS readings for inlet S0?
            and oxygen.

Avg. S02 Rate Out, Lbs/Hr - Average hourly weight of S02 rejected by FGD in
            effluent flue gas while absorber and evaporator were operating.
            Calculated from hourly outlet flue gas flow rates derived from
            the inlet flow rates above adjusted for air in-leakage using DAS
            inlet and outlet C02 concentrations and DAS reading for outlet S02.
Avg. t S02 Removal = 100 (Avfl. SO^Rate^n ^Avfl.^ Rate Out) . Calculated

            from above values.

Electricity, MWh - Average hourly FGD plant electrical usage.  Calculated
            from DAS channel reading.

Natural Gas  106Btu/hr Equiv.   Average hourly thermal heating value enuivalent
            of process and incinerator usage of natural gas.  Calculated
            from Allied data and daily reported gas heating value.

Steam  106Btu/hr Equiv. (With & Without Tondensate Returned)   Averaae hourly
            heat loss of boiler from FRO steam.  Calculated from steam usage
            above.  Calculation mode:
                                    A-17

-------
            Definitions:

            Hg* =  Equivalent heat in steam, 106 Btu/hr
            S   =  Steam usage, Lbs/Hr.
            H * =  Heat in steam leaving boiler system, Btu/Lb.
            H * =  Heat in condensate entering boiler system,  Btu/Lb,

            Equation:
            He* '  su 
            *Referred to heat content of liquid water at 32°F under
             atmsopheric pressure as 0 Btu/Lb.
            Note:  If condensate is returned,  Hr = 0.93 X (150  -  32)  =  109.74*
                   Btu/Lb.  based on estimate that 93% is returned at  150°F and
                   14.696 PSIG.   From NIPSCO design data,  HQ  =  1480.4*
                   Btu/Lb.   Hf = 0 for no return.
Soda Ash Consumed, Tons
Sulfur Produced, Long Tons
By-Product Salt Produced, Tons
Taken directly from Allied's summary report.
                                    A-18

-------
APPENDIX B.  INSTRUMENT RELIABILITY
                 B-l

-------
TABLE B.I INSTRUMENT DOWN TIME -
S02 REMOVAL
TIME DOWN
DATE
9/16/77
9/16/77
9/17/77
10/10/77
10/12/77
10/14/77
11/7/77

11/11/77
11/12/77
11/13/77
11/14/77
11/15/77
11/16/77
11 /1 7/77
11/18/77
11/20/77
2/26/78
2/27/78
2/27/78
2/28/78
3/14/78
3/21/78
3/22/78
3/23/78
3/24/78
5/6/78
5/7/78
5/8/78
5/9/78
5/10/78
5/11/78
5/12/78
5/13/78
5/14/78
5/15/78
5/16/78
5/17/78
5/18/78
5/19/78
5/20/78
5/21/78
5/22/78
so2
_
1505-1805
1030-1145
0800-0900
0805-0905
1115-1310
0945-1040
1105-1140
1200-0800
0800-0800
0800-0800
0800-0800
0800-1012
0800-0800
0800-0800
0800-1602
1403-1433
1300-0800
0800-1200
0100-0800
0800-1300
1400-1458
-
-
-
-
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-1905
-
-
-
-
-
-
-
-
-
o2 & co2
1030^1150
1430-1800
1030-1145
0800-0900
0805-0905
1115-1250
0945-1040
1105-1140
-
-
-
-
-
0800-0800
0800-0800
0800-1602
-
2300-0800
0800-0800
-
0800-1300
1400-1458
0800-0800
0800-0800
0800-0800
0800-1530
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
0800-0800
so2
_
3
1
1
1
2
-
1
20
24
24
24
2
24
24
8
1
19
4
7
5
1
0
0
0
0
24
24
24
24
24
24
24
11
0
0
0
0
0
0
0
0
0
HOURS DOWN
o2 & co2
_
5
1
1
1
2
-
1
0
0
0
0
0
24
24
8
0
9
24
-
5
1
24
24
24
8
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24

SYSTEM
_
3
1
1
1
2
-
1
20
24
24
24
2
24
24
8
1
19
24
-
5
1
24
24
24
8
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24
24
                       B-2

-------
      TABLE B.I  INSTRUMENT DOWN TIME   SCL REMOVAL (CONTINUED)
DATE
5/23/78
5/24/78
5/30/78
8/1/78
8/2/78
8/6/78
8/7/78
8/16/78
8/22/78
8/23/78
8/27/78
8/28/78

TIME
so2
—
0900-1405
-
1800-0800
0900-1100
0900-2200
0900-1000
0800-1130
NA
-
0415-0800
0800-1352

DOWN
o2 & co2
0800-0800
0900-1405
0905-1010
-
-
-
-
0800-1130
-
0800-1530
0415-0800
0800-1352


so2
0
5
0
14
3
13
1
4
2
0
4
6
Totals 427
HOURS DOWN
o2 & co2
24
5
1
0
0
0
0
4
0
8
4
6
646

SYSTEM
24
5
1
14
2
13
1
4
2
8
4
6
781
NA - Not Available
                                   B-3

-------
             TABLE B.2  INSTRUMENT  DOWN TIME - WATER ANALYZER
                   Date                   Down Time

                 9/16/77            1030-1150, 1430-1800
                 9/17/77                 0830-1145
                10/10/77                 0800-1403
                10/12/77                 0805-1202
                10/14/77                 1115-1250
                10/16/77                 1005-0900
                10/17/77                 0800-1005
                 11/7/77            0945-1040, 1105-1140
                11/11/77                 1200-0900
                11/12/77                 0800-0800
                11/13/77                 0800-0800
                11/14/77                 0800-0800
                11/16/77                 0800-0800
                11/17/77                 0800-0800
                11/18/77                 0900-1602
                2/26/78                 2300-0900
                2/27/78                 0900-0800
                2/28/78                 0800-1300
                3/14/78                 1400-1458
                3/21/78                 0800-0800
                3/22/78                 0800-0800
                3/23/78                 1900-0900
                3/24/78                 0900-1530
                3/26/78    .            0905- *
* As of 3/26, H20 analyzer not operating satisfactorily  and  it was determined
  not to repair it for the remainder of demonstration year.
                                   B-4

-------
                    TABLE B.3 DAS CHANNEL DOWN TIME
         Parameter             Channel No.            Date & Down Time
Steam Drum Pressure                07          ^3/19/78 to 3/21/78
Gross Load                         38          3/1/78,0905 to 3/2/78,0900
Net Load                           39          2/16/78, 1100 to 3/8/78,1630
Flue Gas Inlet Temperature         45          11/7/77,^)800 to 11/19/78,^1440
                                    B-5

-------
                              APPENDIX C
                 METHOD FOR ESTIMATING FLUE GAS VOLUME

     Flue gas volumes were calculated based on the coal ultimate analysis,
quantity of coal burned and percentage of oxygen contained in the flue gas.
The required data are listed below:

                    DATA                     SYMBOL
            Coal (Ib/hr)                      COAL
            Ultimate Analysis (%):
                -  Carbon                      C
                -  Sulfur                      S
                - Hydrogen                     H
                -  Water                      H20
                -  Oxygen                      0
                - Nitrogen                     N
           Percent 02 in Flue Gas              02

     The calculation procedure is shown below.  The first step is the flue
gas volume calculation.  These procedures were followed:

     1.  Calculation of dry, excess air free flue gas (Mole/Hr).
         This was accomplished by calculating the quantities of
         C0«, S02, and N2 resulting from the carbon, sulfur and
         nitrogen contained in the coal.   In addition, nitrogen
         associated with the stoichiometric quantity of combustion
         oxygen is included.

     2.  Calculation of dry flue gas with excess air (Mole/Hr).
         Based on the excess oxygen contained in the flue gas,
         the quantity of excess air is computed.

     3.  Calculation of flue gas with water and excess air (Mole/Hr).
         Water contained in this flue gas resulting from:   The
         hydrogen and water content of the coal  and atmospheric
         humidity is added giving the total  flue gas flow rate
         in moles per hour.
                                   C-l

-------
4.  Calculation of flue gas volume (SCFM).  The total flow
    rate (in moles/hr) is converted to a volumetric flow rate
    (SCFM).

Equations are as follows:

1.  Flue Gas (FGD), mol/hr., excess air free, dry
    MC02, mol/hr. = '0^65 x C x COAL

    MS02, mol/hr. = ^- x S x COAL

    MN2, mol/hr. =     x N x COAL
    Stoichiometric Air:
         - C.02665C + 0.019$ + .07936H - .01(0)] COAL
            -  -    --
    MN2S = 3.762 x M02S
    FGD mol/hr. = MC02 + MS02 + MN2 + MN2S

2.  Flue Gas (FGDX) , mol/hr., with excess air, dry

    ™2*> mol/hr- = 1 - (4:762(02) x. 01) x FGD
    FGDX, mol/hr. = FGD + M02X •§• 3.762 MOZX

3.  Flue Gas (FGWX). mol/hr., wet
    Assume abs. Humidity =
    Total Dry Air (TDA) mol/hr., = M02S •§• MN2S + 4.762 M02X
    MH20A = 0.013 x    TDA
    MH20 = (0.08936H + 0.01 H90) COAL
                             *    18
    FGWX, mol/hr. = FGDX + MH20A + MH20
4.  Flue Gas (KVSTD), scfm wet
      at 70°F,
      KVSTD, mscfm = ^|^- x FGWX
                              C-2

-------
                                 REFERENCES


1.   Adams, R. C., S. J. Lutz, and S.  W.  Mulligan.   Demonstration  of Wellman-
     Lord/Allied Chemical FGD Technology:  Acceptance Test Results.
     EPA-600/7-79-014a.  TRW Inc., Durham, NC  January 1979.

2.   Adams, R. C., T. E. Eggleston, J. L. Haslbeck, R. C.  Jordan and
     Ellen Pulaski.  Demonstration of WeiIman-Lord/Allied  Chemical  FGD
     Technology:  Boiler Operating Characteristics.  EPA-600/7-77-014.
     TRW Inc., Vienna, Va.  February 1977.

3.   40 CFR Part 60, Vol. 43 No. 182, 42154-42184 (Federal Register).

4.   Laske, B., et al.  EPA Utility FGD Survey.  EPA-600/7-78-051d, U.  S.
     Environmental Protection Agency, Research Triangle Park, NC  1978.

5.   Same as 4.

6.   TRW Inc., Environmental Engineering Division.   Program for Test and
     Evaluation of the NIPSCO/Davy/Allied Demonstration Plant.   Demonstration
     Test Plan.  Prepared for Control  Systems Laboratory,  Office of Research
     and Monitoring, Environmental Protection Agency, Research Triangle Park,
     NC  April 8, 1975.

7.   Same as 1.
                                     c-3

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                                TECHNICAL REPORT DATA
                         (Please read Instructions on the reverse before completing)
 1. REPORT NO.
 EPA-600/7-79-014b
                           2.
                                                      3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE Demonstration of Wellman-Lord/
Allied Chemical FGD Technology:  Demonstration Test
 First Year Results
              5. REPORT DATE
              September 1979
              6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)

 R.C.Adams, J.Cotter, and S.W.Mulligan
                                                     8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
 TRW, Inc.
 201 N. Roxboro Street, Suite 200
 Durham, North Carolina 27701
              10. PROGRAM ELEMENT NO.
              EHE624A
              11. CONTRACT/GRANT NO.

              68-02-1877
 12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC  27711
              13. TYPE OF REPORT AND PER
              Annual;  9/78 -  8/79
                                                                       ERIOD COVERED
              14. SPONSORING AGENCY CODE
               EPA/600/13
15. SUPPLEMENTARY NOTES IERL-RTP project officer is Charles J. Chatlynne, Mail Drop 61,
 919/541-2915.
  . ABSTRACT
                     gjves results of the first year of a comprehensive test program
 to demonstrate the capabilities of a full-scale plant using the Wellman-Lord/Allied
 Chemical process for desulfurizing flue gas. The FGD unit is retrofitted to Northern
 Indiana Public Service Company's  115 MW coal-fired unit No.  11 at the Dean H. Mit-
 chell Station. During the demonstration, which began in September 1977, operating
 experience was limited by boiler-  and FGD- related operating problems. The FGD
 plant had a 50% reliability factor (hours operated/hours called upon to operate).  SO2
 removal efficiency averaged 89%.  Economic performance was distorted by consid-
 erable off-normal boiler operation (which limited use of the FGD plant) and by par-
 tial operation of the  FGD plant during which operating costs were not substantially
 less than costs during full operation.  A major effect on boiler operation from retro-
 fit of the  FGD plant was a boiler derating of 9% resulting from the consumption of
 steam by the FGD plant, a value that will be reduced by design changes at future
 Wellman-Lord installations. At least 1 year of additional testing will follow comple-
 tion of a number of design improvements that will eliminate or minimize the pro-
 blems that have limited FGD plant use.
 7.
                             KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
  b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATi Field/Group
 Pollution
 Flue Gases
 Des ulf ur ization
 Coal
 Combustion
 Boilers
  Pollution Control
  Stationary Sources
  Wellman-Lord Process
  Allied Chemical Process
13B
2 IB
07A,07D
21D

13A
 8. DISTRIBUTION STATEMENT
 Release to Public
                                          19. SECURITY CLASS (This Report)
                                          Unclassified
                          21. NO. OF PAGES
                              96
  20. SECURITY CLASS (Thispage)
  Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
C-4

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