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)
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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
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mental issues.
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This report has been reviewed by the participating Federal Agencies, and approved
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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.
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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.
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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
-------
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
-------
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
-------
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
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APPENDIX B. INSTRUMENT RELIABILITY
B-l
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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
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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
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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
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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
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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
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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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