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United
Environmema Pi
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Demonstration of
Wellman-Lord/Allied
Chemical FGD Technology:
Acceptance Test Results
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
ii
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EPA-600/7-79-014a
January 1979
Demonstration of Wellman-Lord/
Allied Chemical FGD Technology:
Acceptance Test Results
by
R.C. Adams, S.J. Lutz, and S.W. Mulligan
TRW, Inc.
201 North 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 Energy, Minerals, and Industry
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
Process performance guarantees were met or exceeded as confirmed by
Acceptance Testing which began on 29 August 1977 and ended on 14 September
1977. The Acceptance Test consisted of two test periods. The Design Load
test period was to be a 12-day period during which the FGD plant was to be
operated at the design condition of a boiler flue gas output rate equivalent
to 80% of the maximum boiler load of 115 megawatts gross. The High Load test
period was to be an 83-hour period during which the FGD plant treated flue
gas volumes equivalent to 95% of maximum boiler load.
Specific performance criteria were met or exceeded as follows:
(a) S02 removal of 90% or better was achieved at Design Load
conditions and at High Load conditions.
(b) Particulate emissions did not exceed 0.1 lb/10 Btu
of boiler heat input at either Design Load or High
Load conditions.
(c) The consumption of steam, natural gas and electrical
power was less than the performance guarantee require-
ments at Design Load conditions.
(d) Soda ash consumption was less than the limit set by
the performance guarantees.
(e) Sulfur product purity was greater than 99.5% at both
Design Load and High Load conditions.
111
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CONTENTS
Figures iv
Tables iv
Executive Summary v
1. Introduction 1-1
Background 1-1
Process Description 1-2
Performance Requirements 1-6
Test Criteria 1-7
Methods Summary 1-10
2. Test Results 2-1
Test Lengths and Interruptions 2-1
S02 Removal Performance 2-2
Particulate Emissions Performance 2-4
Utility and Natural Gas Consumption 2-4
Analysis of Demonstration Plant Steam Consumption 2-5
Raw Material Consumption 2-5
Sulfur Product Purity 2-6
Data Recovery 2-6
3. Data Validation 3-1
Introduction 3-1
Data Accuracy 3-1
Validation of Flue Gas Flow Rates 3-5
Test Precision 3-11
4. References 4-1
Appendices
A. Test Results A- 1
B. Test Methods B- 1
C. Flue Gas Flow Comparisons C- 1
iv
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FIGURES
Number Page
1-1 Block Flow Diagram of Major Process Steps. Location
of Sampling Positions for Acceptance Testing 1-3
2-1 Daily Minimum and Maximum SCL Removal Efficiencies-
Two Hour Averages 2-3
TABLES
Number Page
2-1 Interruptions During Design Load (12-Day) Test 2-2
2-2 Sulfur Product Purity, Wt. # 2-6
2-3 Instrument Downtime 2-8
2-4 Summary of Performance Results 2-9
3-1 Continuous Analyzer Calibration 3-2
3-2 Instrument Calibrations 3-3
3-3 S02 Span Gases Concentration by EPA Method 6 3-4
3-4 Comparison of Methods for Measuring S02 Concentrations. . . 3-6
3-5 Calculated Flue Gas Flow Rates 3-7
3-6 Revised Estimates of Particulate Matter Emission Rates. . . 3-10
3-7 Variability of Particulate Matter Emission Rates 3-13
3-8 Variability in Operating Costs 3-14
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EXECUTIVE SUMMARY
Process performance guarantees were met or exceeded as confirmed by
Acceptance Testing which began on 29 August 1977 and ended on 14 September
1977. The Acceptance Test consisted of two test periods. The Design Load
test period was to be a 12-day period during which the FGD plant was to be
operated at the design condition of a boiler flue gas output rate equivalent
to 80% of the maximum boiler load of 115 megawatts gross. The FGD plant was
actually operated for 265 hours at this load condition. The High Load test
period was to be an 83-hour period during which the FGD plant treated flue
gas volumes equivalent to 95% of maximum boiler load. Actual operating time
was 36 hours at this load condition.
Specific performance criteria were met or exceeded as follows:
(a) SCk removal of 90% or better was achieved for 261
hours of the 265 hours of operation at Design Load
conditions and was achieved for 84 hours of the 86
hours of operation at High Load conditions.
(b) Particulate emissions did not exceed 0.1 Ib./lO
Btu of boiler heat input at either Design Load
or High Load conditions.
(c) The consumption of steam, natural gas and electrical
power averaged 76% of the performance guarantee
requirements at Design Load conditions.
(d) Soda ash consumption averaged less than 6.6 tons
of Na9CO, per day which was the limit set by the
£ *3
performance guarantees not to be exceeded during
the Design Load period.
(e) Sulfur product purity was greater than 99.5%
at both Design Load and High Load conditions. As
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a check to ensure that the sulfur product was
acceptable for burning in a contact acid plant,
impurities in the sulfur were compared with
bright sulfur purchase specifications. All
impurities were less than specified.
During the Design Load period, a S02 removal efficiency of 90% or better,
based on two hour averages, was achieved for all but four hours of the 265
hour operating period. S02 removal was 88% and 89% two hour averages,
two two-hour periods. Four hours were added to the 12-day test period for
these failures. During the High Load period, there was one two hour period
during which SOg removal was 89%. Three hours were added to the 83-hour test
period for this failure.
vli
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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
A
emission control method, is the Wellman-Lord/Allied Chemical (WL/Allied) pro-
cess developed by Davy Powergas and Allied Chemical. The Wellman-Lord (WL)
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 (Allied) 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. For the remainder of this report, we will refer
to this configuration 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 (NIPSC). The EPA is sharing in the cost of construction
of the unit and is conducting a comprehensive 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/All led Chemical installation.
1-1
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The WL/Allied FGD 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, 1976. 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 reasons
for the delays have been explained in some detail elsewhere^ '^ '.
The Acceptance Test is to verify that the process performance guarantees
have been met. The performance guarantees are a contractual requirement
placed on Davy by NIPSCO and EPA. Over a period totaling more than 15 days,
the FGD plant must meet the minimum SCL removal requirements of the perform-
ance guarantees at two specified levels of boiler load, and must not exceed
the specified amounts of raw materials and utilities consumption.
TRW, under contract to EPA, is providing the test services required for
evaluating the performance of the FGD plant, including its ability to meet
the performance guarantees during acceptance testing. Preceding the Accep-
(3)
tance Test, a Test Planv ' was prepared based on the performance requirements
specified in EPA's contract with NIPSCO (EPA Contract No. 68-02-0621).
PROCESS DESCRIPTION
The process employs sodium sulfite scrubbing of the flue gas to remove
S02 with thermal regeneration of the scrubbing solution to recover the S02
and subsequent reduction of the S02 to produce marketable sulfur in molten
form. The block diagram (Figure 1-1) shows the major process steps.
Mitchell No. 11 is a 115 MW pulverized coal fired boiler, balanced draft,
with cold end electrostatic precipitator particle controls. The FGD plant
accepts the total flue gas from the discharge of the boiler's induced draft
(ID) fans. A booster fan is used to force the flue gas through the pre-
scrubber and the absorber. The prescrubber is expected to remove additional
particulate matter such that the New Source Performance Standard of 0.1 Ib
particulate matter emitted from the absorber 710 Btu heat input is met if
particulate matter out of the ESP does not exceed 0.2 Ib/ACF or that 80%
removal is achieved if inlet grain loading exceeds 0.2 Ib/ACF.
Cooled, humidified flue gas leaves the prescrubber and enters the bottom
of a multistage absorber and is contacted with sulfite solution fed to the top
1-2
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FIGURE 1-1. BLOCK FLOW DIAGRAM OF MAJOR PROCESS STEPS. LOCATION OF
SAMPLING POSITIONS FOR ACCEPTANCE TESTING
COAL
AIR
WATER
ELECTRICAL
ENERGY
STEAM
MITCHELL NO. 11
BOILER
FLUE
GAS
INLET SO,
NATURAL GAS
SODA ASH
TREATED FLUE GAS
INCINERATED TAIL GAS
( GRAIN LOADING.
FLOW)
FGO PROCESS BOUNDARY
(CUTLET soz. GRAIN LOADING. FLOW)
PURGE
SOLIDS
BY-PRODUCT
SULFUR
BY-PRODUCT
LEGEND
SAMPLING POSITION
FOR
ACCEPTANCE TESTING
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stage of the absorber tower. S0« is absorbed by the sulfite solution and the
treated flue gas is discharged from the top of the absorber tower through a
stack to the atmosphere. The spent sulfite solution is removed from the
bottom stage of the tower and sent to a surge tank for storage prior to re-
generation in the S02 recovery step. The absorber is designed to remove 90%
of the incoming SO,, continuously from the volume of flue gas expected (320,000
acfm) at 80% of full load (92 MWG). Thus, the performance guarantees
require an extended test period (12 days) at this flue gas rate to show con-
tinuous S02 removal capability. Because S02 removal performance is a function
of the S02 levels at the inlet to the absorber, the performance guarantees
require the level of sulfur in the coal to be within specific limits.
During the S02 recovery step, the spent sulfite solution is regenerated
in a steam-heated evaporator and returned to the absorber feed tank. S02 is
recovered from the evaporator overhead. The S02 recovery area was not design-
ed for recovery of all of the SO* removed from the flue gas at boiler loads in
excess of 80% because the boiler is normally not operated for extended periods
in excess of 80% load. However, surge capacity was provided in the form of
surge tank and absorber feed tank capacity to allow for a limited period of
operation at full load. The performance guarantees require that S02 and
particle removal requirements be met during an 83 hour period when accepting
flue gas equivalent to a 110 MWG load.
A purge stream from the S02 recovery area is processed in the purge
treatment area to produce a dry sodium sulfate by-product. The sodium values
lost in the purge stream must be made up by adding Na/>C03 to the regenerated
sodium sulfite solution. The performance guarantees limit the amount of
Na/jCOg make-up during the 12 day test period.
The S02 which was recovered in the S02 recovery step is sent to the S02
reduction area. The reduction step is a proprietary process developed by
Allied Chemical which utilizes natural gas for the reduction of S02 to H2S
and finally elemental sulfur in molten form. A small stream of tail gas is
returned after incineration to the inlet of the booster fan. The performance
requirement is to produce a sulfur product of high purity and of a quality
which can be used to make sulfuric acid, the major market for sulfur.
1-4
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Limits on the consumption of utilities and natural gas are also a per-
formance requirement. Natural gas is used as a reductant of S02 and for in-
cineration of the tail gas. The major use of steam is in the SO- recovery
area for evaporation but steam is also used in the purge treatment area and
for steam turbine drives. Electrical energy is consumed to drive pumps and
auxiliaries, for line tracing, for instrumentation and for lighting.
The Sections of EPA Contract Mo. 68-02-0621 which set forth the perfor-
mance requirements are given in the next section of this report.
1-5
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PERFORMANCE REQUIREMENTS
The EPA/NIPSCO Contract No. 68-02-0621 specifies that an acceptance test
be performed in accordance with the specified performance guarantees. Arti-
cle XIX, Paragraphs A.I and A.2, of the Contract is quoted as follows:
"ARTICLE XIX - PROCESS PERFORMANCE GUARANTEE
A. Performance Guarantee
1. The Contractor (NIPSCO) guarantees that during the
acceptance testing the system will perform on Unit Mo.
11 as follows:
(a) The system when operated with 3.15 to 3.5%
sulfur in the coal shall achieve 90% sulfur
removal from the flue gas or no more than
200 ppm of S02 in the outlet gas stream from
the absorber, (which shall be the only source
of S02 emissions from the system to the atmo-
sphere during normal operations) whichever is
the lesser. For fuels containing less than
3.15% sulfur the absorber outlet stream shall
contain no more than 200 ppm S02- For fuels
containing more than 3.5% sulfur the absorber
outlet stream will achieve no less than 90%
sulfur removal from the flue gas.
(b) The system shall be capable of producing by-
product sulfur having a sulfur assay of 99.5%
minimum and shall be suitable for use in a
sulfur burning contact acid plant.
(c) Based on the following costs, the net oper-
ating cost per hour shall not exceed $56.OO/
hour.
Electric Power $0.007 per KWH
Steam $0.50 per 1,000 Ib. at
550 psig & 750°F
Natural Gas $0.55 per 1,000,000
Btu
(d) The system's particulate emission rate shall
not exceed the Federal flew Source Performance
Standard for Fossil-Fuel Fired Steam Generators
that is current at the completion of Phase I.
(e) The average chemical make-up over a twelve (12)
day operating period at an average of 92 MW
shall be no greater than 6.6 tons per day of
1-6
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The value of antioxidant used during
the 12-day period shall not exceed an average
of $400 per day.
2. The Guarantees in paragraphs (a) - (e) hereof, shall be
demonstrated in accordance with paragraph D of Phase II
in the Scope of Work."
Paragraph D of Phase II in the Scope of Work cites the provisions by which
the unit will be operated during an acceptance test. This paragraph states
that:
"NIPSCO shall hold Davy Powergas responsible for this Phase
of the project; accordingly, Davy Powergas shall be required
to maintain technical staff available until such time as the
performance guarantees have been fulfilled in an acceptance
test as follows:
The test period shall consist of 12 days operation at an
average load of 92 MW followed by 83 hours operation at an
average load of 110 MW. During the test period the average
sulfur content of the coal will be 3.16% S. Interruptions
totalling less than 24 hours will not be considered as a
break in continuous operation except that the test period
will be extended by this period of interruption. Further-
more, if, for reasons beyond Contractor's control, there
is either a reason to separate the 92 MW and 110 MW test
runs, having completed no less than 10 days of the 92 MW
test, or else the 110 MW test portion of the test has not
been completed, then the 110 MW test can be restarted pre-
ceded by 3 days at 92 MW operation.
Should, for reasons beyond Contractor's control, it becomes
necessary to adjust the basis for the guarantee run, then
Davy Powergas will prepare new guarantee procedures consis-
tent with the guarantees in this contract. In no event will
the emission guarantees be changed."
TEST CRITERIA
Except for the particle emission rate, the performance guarantees do
not specify the criteria or methodology for determining performance or the
penalties to be assessed in case of performance failure. Thus, specific
criteria were established and included in the Acceptance Test Plan. The
criteria of the Test Plan were then used as a guide for final criteria selec-
tion acceptable to the contractual parties (EPA, NIPSCO, Davy). These final
criteria are detailed as follows.
Specific changes were made in these performance guarantees and agreed
to by the contractual parties. However, they do not reflect a contract
1-7
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change. The specific changes are described in the following paragraphs.
Sulfur Removal
Sulfur removal was designated to mean S02 removal. The FGD plant was to
remove 90% of the inlet S02 at the inlet flow conditions at 92 MWG and 110
MWG (flue gas volume equivalents) with sulfur in the coal between 3.0% and
3.5%. If the sulfur in the coal exceeded 3.5% during any two hour period
that period was treated as an inlet stream interruption and the results dis-
carded without adding the interruption period to the end of the test. The
official test results were by the TRW SOg analyzer or manual sampling except
in the case of an instrument failure, at which time the FGD plant analyzer
results were to be used provided that the SOg removal results of both instru-
ments complement each other for the time period preceding the failure. The
SOg removal guarantees were based on twelve two-hour averages per day. Any
sequential two hour period failure to meet SOg removal performance guarantees
was added to the end of the Acceptance Test. This applied to both the 92 MWG
(Design) and 110 MWG (High Load) test periods.
Due to the unpredictability of flue gas dilution levels, it was decided
to limit sulfur removal criteria to that of 90% removal efficiency alone with-
out any requirement for meeting a concentration level of 200 ppm.
Sulfur in Coal
A sample was collected each hour of each test period. A composite was
created for each 24-hour period and analyzed to determine if the percent
sulfur was within the range of 3.0-3.5% set forth in the performance require-
ments. However, each one hour increment was retained for possible analysis
if requested by any of the contractual parties.
Operating Levels
The FGD plant was designed to remove better than 90% of the SQy contin-
uously when the boiler is burning coal of 3.15% sulfur content and is devel-
oping flue gas volumes of 320,000 acfm (at 300°F) at a gross generating out-
put of 92 MW. Pre-acceptance testing indicated that the flue gas volume was
much higher than 320,000 acfm at 92 MW gross. Therefore, instead of testing
at 92 MWG and 110 MWG, flue gas volume equivalents were set as the operating
levels. These were 320,000 acfm for the design (92 MWG) test period and
1-8
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380,000-390,000 acfm for the High Load (110 MWG) test period, without correc-
tions for temperature or air dilution.
Interruptions
Interruptions were defined as the loss of any feed stream to the FGD
plant from the moment a stream is lost to the time that the plant is back to
the original operating conditions. Interruptions of less than 24 hours were
to be added to the end of the respective test periods. However, since actual
interruptions during the Design Test Phase totaled less than 24-hours, the
contractual parties agreed to waive the extensions. There were no inter-
ruptions of any kind during the High Load Test Phase. Available performance
data during interruptions were not included in the performance results.
By-Product Sulfur
Sulfur purity requirements were determined on composites created from
samples of each sulfur shipment (about one a day). Sulfur purity was deter-
mined for both the Design test period and the High Load test period. The
criteria for suitability for use in a sulfur burning contact acid plant were
Allied Chemical's sulfur purchase specifications. Penalties for failure to
meet the performance requirements were to be by agreement among the con-
tractual parties.
Operating Costs
Since cost performance guarantees had to be set far in advance of the
Acceptance Test period, it was intended that these performance requirements
reflect utility and natural gas consumptions rather than the current costs
for these items. Consumption performance, reported in dollars per hour based
on the specified unit costs, was determined as the total consumptions divided
by the total uninterrupted hours operated during the Design (12-day) test
period. Consumptions during periods of interruption were excluded. Daily
measurements of natural gas heating value of gas being fed to NIPSCO's gas
distribution system were obtained from NIPSCO. Penalties for any overrun were
to be by agreement among the contractual parties.
1-9
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Particle Emissions
EPA Method 5 was the procedure used with only the catch up to and includ-
ing the filter catch considered to be particulate matter. One test a day,
averaging in excess of three hours per test, was used to determine particulate
control performance. Alternative performance criteria were used. If the in-
let particle concentration was greater than 0.2 grain/ACF, the FGD plant
particle controls must remove an average of 80% or more of the particulate
matter. If the inlet concentration was 0.2 grain/ACF or less, the particle
emissions must meet the New Source Performance Standards (NSPS) of 0.1 lb/10
Btu heat input. One day was to be added to the test for each three hour test
failed.
Chemical Make-Up
Following adoption of the initial performance guarantees, Davy determined
that oxidation rates could be controlled without feeding an antioxidant. Thus,
the only chemical make-up during the Acceptance Test was soda ash. Average
soda ash consumption for the Design (12-day) test period was determined from
measurements provided by Allied. Total consumption was determined from in-
ventories at the start and end of the 12-day period plus shipments. Soda ash
as NagCOg was determined from an analysis certificate supplied by Allied. Davy
had the option to either include or exclude the Soda ash consumption during
periods of interruption but had to explain their choice in writing. There was
to be no penalty for violations.
METHODS SUMMARY
The test methods are described in detail in Appendix B. However, in order
to completely understand the test results and their significance, brief de-
scriptions of the more significant methodologies are needed.
To the extent possible, continuous high frequency test data were used.
The TRW continuous monitoring system was utilized to accomplish this. The
continuous monitoring system samples each flue gas composition parameter (S02,
C0£, $2* ^2°) every six minutes (alternating every three minutes between
inlet and outlet of the absorber). All other high frequency data sampling was
done every three minutes. The data were collected and stored by the data ac-
quisition system (DAS) and hourly averages were computed and printed out.
Strip chart backup was provided in case of DAS failure. Annubars are
1-10
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installed 1n the absorber stack to measure the flue gas flow every three
minutes. However, attempts to calibrate the Annubars were unsuccessful, and
other means of estimating flue gas flows had to be found. The flue gas flow
measurement problem and its solution are treated in detail in Section 3.0.
The test parameters that were not amenable to continuous monitoring
are briefly described as follows:
(a) Particulate matter concentration in the flue gas
was from tests performed for a limited period no
more than once a day. Tests were run simultaneous-
ly at the inlet and outlet of the absorber using
EPA Method 5 (impinger train catch discarded).
Outlet sampling had to be done downstream of tail
gas and tank vent returns and of the booster fan.
It was assumed that any increase or decrease in
grain loading contributed by the FGD plant tail
gas stream and tank vents were negligible.
(b) Totalizer readings were taken only at the begin-
ning of each day, the beginning and end of each
grain loading test, the beginning and end of each
interruption, and the beginning and end of the
Design and High Load test periods. These were
for:
- Coal feed rate
- Natural gas and kWh consumptions
- Generator total gross energy output in
megawatts (Power output was also measured
every three minutes).
Booster fan speed and outlet pressure, for
validating flue gas flow, was also read at
these frequencies.
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(c) Average coal compositions and heating values
were restricted to each 24-hour period and each
period of particle sampling. However, coal
samples were available for determining averages
of each two hour period.
(d) Soda ash feed rates were determined from inven-
tory and shipments data supplied by Allied.
(e) The heating value of natural gas, determined
daily, was obtained from HIPSCO.
To correct for dilution in the determination of the percentage SO,, re-
moval, relative mass rates of S02 at the inlet and outlet of the absorber
were calculated. The calculations were based on a C02 balance; that is, it
was assumed that any differences in C02 mass rates inlet and outlet the
absorber were negligible. A dilution factor, f, was calculated:
f = a (100-c
F (100-d
where a = C02 inlet, vol. % of dry flue gas
b = C02 outlet, vol. % of dry flue gas
c = H20 inlet, vol. % of wet flue gas
d = H20 outlet, vol. % of wet flue gas
The dilution factor was then used to correct outlet SOg to the same relative
mass rate basis as the inlet S02 as follows:
% S02 Removal = (SOp in, ppmv) - (SOo out, ppmv) (f)
S02 in, ppmv
Coal was sampled once every hour throughout the Acceptance Test except
during particle sampling periods when higher frequency sampling was em-
ployed. Sample increments, about one pound each, were kept separate by
placing each increment in a plastic bag which was sealed to prevent moisture
loss. Composites were created by mixing equal portions of each sample Incre-
ment, using a riffler.
1-12
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Test days began and ended at 0800 hours and were cross referenced with
calendar dates for the day ending at 0800. Thus, Test Day No. 1 beginning
at 0800 on August 29th was assigned a day ending date of August 30th.
1-13
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SECTION 2
TEST RESULTS
Test results are divided into two test periods - a 12 day test with the
boiler flue gas flow rate held constant at about 320,000 acfm (8,960 cubic
meters per minute) and an 83 hour test with the boiler flue gas output main-
tained at about 388,000 acfm (10,864 cubic meters per minute); both flow
rates were at about 300°F and one atmosphere pressure.
Performance requirements for S02 removal efficiency; particle emission
rate; natural gas, electrical, and steam consumptions; soda ash consumption;
and sulfur product purity were all met in both phases of the Acceptance Test.
The performance results are summarized at the end of this section (Table 2-3).
Detailed test results are appended.
TEST LENGTHS AND INTERRUPTIONS
The 12-day test commenced at 0800 on 29 August 1977 and ended at 1200
on 10 September 1977. Operating time totaled 265 hours out of an elapsed time
of 292 hours. Performance guarantees for S02 removal were not met during two
2-hour periods. Thus, the test was extended four hours. A total of 27 hours
qualified as interruptions (Table 2-1). Of these hours, 10 hours were boiler
interruptions and 17 hours were FGD plant interruptions. In addition, the
boiler feed water pump went down on Day 11 from 1830 to 0800 causing a load
reduction to about 60 megawatts. This was not considered to be an interrup-
tion for determining S0« removal performance. However, data collected during
this period was not used for determining consumption of utilities.
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TABLE 2-1. INTERRUPTIONS DURING DESIGN LOAD (12-DAY) TEST
DAY
3
4
4
5
6
7
7
10
TIME OF
INTERRUPTION
0120-0415
1450-1555
1645-2240
0240-0545
1005-1300
0900-1630
0330-0545
0845-1100
HOURS
CHARGED
3
1
6
3
3
7
2
2
CHARGED
TO
Boiler
FGD
FGD
FGD
FGD
Boiler
FGD
FGD
NATURE OF INTERRUPTION
Booster fan tripped
Booster fan tripped;
bypass damper opened
Booster fan tripped
Reduction area down,
Claus bed plugging
Reduction area down to
burn sulfur off Claus
bed
Boiler interruption;
boiler feed water
pump repairs
Reduction area down to
rake Claus bed
Reduction area down,
incinerator trip
solenoid unable to be
reset after releasing
The 83-hour test commenced at 0800 on 11 September 1977 and ended at
2200 on 14 September 1977. Operating time totaled 86 hours out of an elapsed
time of 86 hours. Performance guarantees for SOg removal were not met during
one 2-hour period. The test was extended two hours plus one additional hour
to assure sequential two hour averages. No interruptions were experienced.
S02 REMOVAL PERFORMANCE
Test failures occurred on only two days - one day of the Design Load
test and one day of the High Load test (Figure 2-1). During the fifth day
of the Design Load test, the absorber failed to meet the 90% S02 removal
2-2
-------
94
92
90
l\> CM
86
DESIGN LOAD
HIGH LOAD
1 2 3 4 5 6 7 8 9 10 11 12
DAY
FIGURE 2-1. DAILY MINIMUM AND MAXIMUM S02 REMOVAL EFFICIENCIES - TWO HOUR AVERAGES
-------
performance requirement during two 2-hour periods - from 0800 to 1000 hours
and 1000 to 1200 hours. In addition, the absorber did not satisfy the
90% removal guarantee for one 2-hour period during the High Load test. This
occurred from 0200 to 0400 hours on the second day of the High Load test.
Each test series was extended for the hours failed and performance guarantees
were met during the test extensions. When performance guarantees were met,
SOo removal varied within the 90 to 93% band. The percentage of two hour
averages at each incremental level of S02 removal was as follows:
2-HOUR AVERAGES, 56-
S02 REMOVAL. % DESIGN LOAD HIGH LOAD
88 0.7 0.0
89 0.7 2.3
90 33.4 44.2
91 56.3 39.6
92 8.2 11.6
93 0.7 2.3
PARTICLE EMISSION PERFORMANCE
Inlet particulate matter did not exceed 0.2 gr/acf for either test phase.
Therefore, absorber emissions were required not to exceed the NSPS of 0.1 lb/
10 Btu of boiler heat input. A total of 8 samples during the 12-day test
and 3 samples during the High Load test were taken for grain loading
both at the inlet and outlet of the absorber. For the 12-day test, valid
samples were obtained on test days 1, 2, 5, 6, 8, 9, 10, and 11 while, for
the High Load test, useful data were obtained on days 1, 2, and 4. At no time
during either test period was the inlet grain loading greater than 0.2 gr/acf
or the outlet particle emissions rate greater than 0.1 lbs/10 Btu input.
UTILITY AND NATURAL GAS CONSUMPTION
Utility and natural gas consumptions averaged only 76% of the performance
guarantee for the 12-day test period. Furthermore, the maximum single day
average during the 12-day period was only 79% of the performance requirement..
Based on consumption costs of $0.007 per kWh for electricity, $0.50 per
1000 Ib of steam (550 psig and 750°F), and $0.55 per 1,000,000 Btu for natu-
ral gas, the average cost for utilities and natural gas during the 12-day
2-4
-------
test period was $42.74/hour of operation. The average heating value of the
natural gas was 1029 Btu/scf.
Utility and natural gas consumptions for the 12-day test were as follows:
Electric Consumption: 186,640 kWh for 246.3 hours
Natural Gas Consumption: 2,793,720 ft for 249.3 hours
Steam Consumption: 15,442,518 Ibs for 248.3 hours
It should be noted that the number of hours for each parameter is less than
the 261 hours which make up the 12-day test. This is due to exclusion of
certain hourly averages on account of invalid data as well as exclusion of
data received during an interruption (see interruption schedule earlier in
this section) or during the period of low power plant output (from 1830 to
0800 hours during test day 11).
ANALYSIS OF DEMONSTRATION PLANT STEAM CONSUMPTION
Steam usage, steam temperature and pressure, and the range for each of
these parameters is given for the Design test period:
STEAM
CONSUMPTION
(Ibs/hr)
62,139
+ 6,134
,720 - 65,510
STEAM
TEMPERATURE
(°F)
724
+ 7
711 - 730
STEAM
PRESSURE
(psig)
551
^23
518 - 573
AVERAGE VALUE
95% CONFIDENCE LIMITS
RANGE OF VALUES
RAW MATERIAL CONSUMPTION
Soda ash consumption was determined by Allied Chemical personnel by
measuring the decrease in volume of stored soda ash, taking into account
shipments received over the duration of the 12-day test. Daily soda ash con-
sumption figures were not computed because the performance guarantee was
based on a maximum quantity consumed over the 12-day test period.
Over the 12-day test, an average of 6.2 tons of Na2C03 per day was con-
sumed, the performance guarantee required that no more than 6.6 tons per
day be consumed. The soda ash assay was 99.79% as Na2C03-
2-5
-------
SULFUR PRODUCT PURITY
Sulfur analyses were performed on composites of samples of product sulfur
shipped from the sulfur recovery plant for both the Design Load test and the
High Load test. The composite samples were made up by thoroughly mixing equal
portions of representative samples taken from every shipment of product sulfur.
Product purity exceeded the guarantee of 99.5% sulfur assay. For analyses for
the impurities, the laboratory first determined that the product did not meet
the impurities specifications for carbon and As203. One of these samples was
sent to a second independent laboratory which found that these components were
well below the impurities specifications. Based on the results from the second
laboratory, it was concluded that the sulfur was suitable for burning in a
contact sulfuric acid plant. Complete analytical results are included in
Appendix A.
DATA RECOVERY
Various problems were encountered with the continuous sampling instru-
mentation which required the acquisition of data from other sources
(either other instrumentation or manual sampling). The use of supplemental
data sources during short periods of instrument downtime made it possible to
report S02 removal for a total of 336 hours out of 351 total operating hours
(96%). Data recovery from the TRW operated analyzers for obtaining the
primary test data was as follows:
2-6
-------
DATA CHANNEL PERCENT DATA RECOVERY
S02 Inlet/Outlet 95
H20 Vapor Inlet/Outlet 94
C02 Inlet/Outlet 95
02 Inlet/Outlet 89
Static Pressure FGD Inlet 100
Gas Temperature FGD Inlet 100
Demo Steam Temperature 100
Demo Steam Pressure 100
Demo Steam Flow 100
Power to Demo Plant 100
Specific outages of Instruments as well as the source of supplementary
data Is given (Table 2-2). In addition to the downtime experienced by these
instruments, the DAS was down less than 10% of the total operating time
during which data was extracted from strip chart recorders.
2-7
-------
TABLE 2-2. INSTRUMENT DOWNTIME
DAY
1
1
1
3
3
5
6
6
6
10
10
11
11
11
2 (High Load)
TIME
0800-1000
1900-2000
2000-2100
0000-0120
0000-0120
0600-0700
2100-0800
2100-0800
2100-0400
1100-1400
1100-1400
0900-1000
1500-1900
1500-1700
0100-0200
INSTRUMENT
so2
H20, C02, 02
so2
so2
H20, C02, 02
H20
so2
H20, C02
°2
so2
H20, C02, 02
°2
H20, C02
°2
°2
SUPPLEMENTAL SOURCE
Allied Analyzer
Average of 1800-1900
and 2000-2100
Average of 2100-2200
None
None
Average of 0700-0800
Allied Analyzer
Manual Sample
Manual Sample
Allied Analyzer
Manual Sample
Average of 0800-0900
and 1000-1100
Average of 1400-1500
and 1900-2000
Average of 1400-1500
and 2000
Average of 0000-0100
and 0200-0300
2-8
-------
TABLE 2-3. SUMMARY OF PERFORMANCE RESULTS
DAY
1
2
3
4
5
6
7
8
9
10
11
12
13
1 HL
2 HL
3 HL
4 HL
HOURS
UNIT
PASSED
ACCEPTANCE
TEST
24
24
21
17
21
17
IS
24
24
22
24
24
4
24
22
24
14
so2
REMOVAL
REMOVAL)
90.6
90.3
90.9
90.6
90.3
90.1
90.5
90. B
90.5
90.9
91.2
90.8
90.9
91.3
90.2
90.3
90.3
PART1CULATE
EMISSION RATE
(POUNDS/
MILLION BTU)
.01
.03
INVALID SAMPLE
NO TEST
.08
.07
NO TEST
.03
.04
.05
.04
NO TEST
NO TEST
.04
.05
NO TEST
.03
COST OF
UTILITIES
(S/HOUR)
43.05
38.91
41.59
39.44
43.78
44.50
42.46
44.22
43.96
43.91
43.07
43.39
42.09
42.20
44.03
44.45
42.06
SODA ASH
CONSUMPTION
(TONS/DAY)
6.2
DATA NOT
COLLECTED
DURING
TEST
SULFUR
PRODUCT
PURITY
(X PURE)
COMPOSITE
ANALYSIS
99 76
COMPOSITE
99.91
COAL
FEED
RATE
(POUNDS/
HOUR)
83.000
82.400
81 .500
82.200
84.400
86,300
83.700
91.200
83.900
81 .500
74.700
79.800
78,400
94,000
103,600
100,300
99,700
BOILER
HEAT
INPUT
(MILLION
BTU/HOUR)
880
866
871
863
886
908
683
970
893
873
780
853
847
998
1.072
1,036
1.066
BOILER
OUTPUT
(MEGAWATTS)
71.5
70.8
71.1
70.1
71.2
71.4
71.4
73.8
72.8
72.8
65.6
71.7
72.2
84.8
90.2
89.5
88.7
r\»
-------
SECTION 3
DATA VALIDATION
INTRODUCTION
In this section, calibration procedures are described and the accuracy
and precision of the test results are quantified to the extent possible.
The limitations affecting the quality of the data are discussed. In partic-
ular, validation of the flue gas flow determinations was a major problem.
The action taken to assure that the flue gas flows were not less than the
performance requirements are described in detail.
DATA ACCURACY
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.
Calibration Procedures
In order to ensure valid data measurements, the continuous analyzers
were calibrated once each day with known calibration gases for both zeroing
and spanning the instruments. The following table illustrates the gas compo-
sitions for both the zero gas and span gas for the respective analyzer
(Table 3-1).
3-1
-------
TABLE 3-1. CONTINUOUS ANALYZER CALIBRATION
ANALYZER
RANGE OF
ANALYZER
ZERO GAS
SPAN GAS
SO, (LOW RANGE)
0-500 PPMV
260 PPMV SO,
IN No
SO, (HIGH RANGE)
0-5000 PPMV
2690 PPMV SO,
IN No
CO,
H20
0-20 VOLUME
PERCENT
0-25 VOLUME
PERCENT
N,
15% VOLUME
C02 IN N2
100% C2H6
GIVES INSTRU-
MENT SPAN OF
15.625%
0-25 VOLUME
PERCENT
N,
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 summarized (Table 3-2).
The instruments installed for the Acceptance and Demonstration Tests were 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 and
at the beginning and end of manual sampling of the flue gas and at the
beginning and end of each interruption.
3-2
-------
TABLE 3-2. INSTRUMENT CALIBRATIONS
ITEM
CALIBRATED
CALIBRATED BY
COAL SCALES
FGD INLET TEMPERATURE
FGD INLET STATIC PRESSURE
FGD OUTLET TEMPERATURE
FGD OUTLET STATIC PRESSURE
STEAM FLOW METER
STEAM FLOW TRANSMITTER
STEAM PRESSURE
STEAM TEMPERATURE TRANSMITTER
STEAM PRESSURE TRANSMITTER
NATURAL GAS FLOW METERS (2)
KILOWATT-HOUR METER
ONCE OR TWICE/YEAR
PRECEDING TEST
PRECEDING TEST
PRECEDING TEST
PRECEDING TEST
APRIL 1976
PRECEDING TEST
APRIL 1976
PRECEDING TEST
PRECEDING TEST
APRIL 1976
NOVEMBER 1976
NIPSCO
TRW
TRW
TRW
TRW
TRW
TRW
TRW
NIPSCO
Samples of coal and participate matter were collected manually and
laboratory analyses were performed. One-hour sample increments of coal were
collected continuously, whereas particulate matter was collected once a day,
weather conditions permitting, for a 4-5 hour period. During the same 4-5
hour period, S02 concentrations were determined by manual methods to help in
verifying the accuracy of the continuous analyzer. A modified version of
EPA Method 6^ was used for the S02 measurements. Calibrations for manual
particulate matter and S02 measurements are necessary for verifying the
accuracy of duct flow and sample flow measurements. Dry gas meters for
sample flow were calibrated in August 1977 and pitot tubes for duct flow
were last calibrated 1n September 1976.
Agreement Between Methods
Comparison of results by different methods was limited to the determina-
tion of S02 concentrations and of flue gas flow. For S02, comparison of the
3-3
-------
continuous analyzer output was made with EPA Method 6 results. These com-
parisons were made both on the standard calibration gas prior to the Accept-
ance Test and on samples of flue gas collected during the Acceptance Test.
Both of these investigations were done to help validate the accuracy of the
SOg measurements and results are described in following subsections. Flue
gas flow comparisons will be discussed separately.
Accuracy Verification of the Calibration Standard—
The high range and low range standard gases, certifiable as traceable
to NBS standards, were analyzed by EPA Method 6 during June-July, 1977. The
bottle labels were 2690 ppm S02 and 244 ppm SO^. Results are presented as
follows (Table 3-3).
TABLE 3-3. S00 SPAN GASES CONCENTRATION BY EPA METHOD 6
fc-
LABEL, PPM
ANALYSIS, PPM
AVERAGE
HIGH RANGE
2690
2579
2726
2546
2648
2530
2672
2729
2628
2632
LOW RANGE
244
236
242
242
232
235
237
Confidence limits were calculated for the analytical results. For the high
range, the confidence range was 2568 to 2696 ppm or only + 2.4% of the sample
mean. Confidence limits are statistical parameters which in this case tell
us that there is a 95% probability that the true mean value of the results is
within the confidence limits. This indicates acceptable precision for the
analytical method. Also, for the low range span gas, confidence limits of
231 ppm and 243 ppm (+_ 2.5% of the sample mean) were an indication of
3-4
-------
acceptable precision. However, averages for the analytical results tend to
be slightly lower than the span gas bottle labels:
HIGH RANGE LOW RANGE
SPAN GAS LABEL, PPM 2690 244
ANALYSIS AVERAGE, PPM 2632 237
Since span gas concentrations were only 4 to 6% higher than the lower
confidence limits and only 2 to 3% higher than the means of the Method 6
results, it was concluded that the method comparisons tended to verify the
accuracy of calibrations.
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. 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
Method Comparisons of Actual Flue Gas Samples--
A modified version of EPA Method 6 was used to determine S02 concentra-
tion 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 efficiency determined by the con-
tinuous analyzer was less than one percent higher than the comparable average
of Method 6 results (Table 3-4).
VALIDATION OF FLUE GAS FLOW RATES
Just prior to the Acceptance Test, it was found that the apparent flue
gas rates at 92 MWG (FGD design load) were much higher than expected. As a
consequence, it was necessary to test FGD performance during the Acceptance
Test at the design flue gas rate of 320,000 acfm rather than at 92 MWG load.
The resulting gross load was only 72 MW. Adding the steam consumed by the
FGD plant to the steam equivalent of 72 MWG, the load equivalent of the total
steam produced by the boiler was 81 MWG or only 88% of the design load.
3-5
-------
TABLE 3-4. COMPARISON OF METHODS FOR MEASURING S00 CONCENTRATIONS
Ol
en nnmi
DAY
1
2
3
4
5
6
7
8
9
10
11
12
13
1 HL
2 HL
3 HL
4 HL
CONTINUOUS
INLET
2158
2036
2525
2385
2169
2051
2246
1987
2278
2615
ANALYZER METHOD
OUTLET INLET
161
176
—
259
204
—
180
190
—
190
—
—
141
183
—
228
2137
2123
2146
2481
2296
2147
2246
2098
2315
2703
6
OUTLET
162
187
—
—
272
235
—
193
203
—
218
—
—
144
197
—
250
*;n DFMfiWAI V
CONTINUOUS ANALYZER
92.5
91.0
89.5
91.2
90.9
89.4
91.2
92.2
91.4
91.2
MEAN 91 . 1
METHOD 6
92.3
90.6
86.3
90.1
90.8
89.3
90.1
92.4
90.9
90.7
90.4
-------
Furthermore, during the Acceptance Test, it was necessary to rely on flow
estimates derived from the fan curves for the booster fan. This was
necessary because of an apparent bias error in the flow measurements which
was a result of limited lengths of straight duct available for measurement.
These uncertainties have brought into question whether or not enough gas was
being treated during the Acceptance Test to provide a fair test of the per-
formance of the F6D process.
Simultaneous flow measurements at inlet and outlet the absorber were
contradictory. Flow measurements at the inlet appeared to be in error on
the high side whereas the measurements at the outlet showed apparent errors
on the low side. As soon as coal analyses were available following start of
the Acceptance Test, flows were calculated from the coal compositions and
rates and the flue gas excess oxygen levels. Calculated values were at least
as high as the flows estimated from the fan curve (Table 3-5).
TABLE 3-5. CALCULATED FLUE GAS FLOW
DESIGN LOAD
DAY NO.
1
2
3
4
5
6
7
8
9
10
11
12
13
AVERAGE
MEDIAN
ELOW
10"3 ACFM
349
—
337
344
374
357
351
387
372
387
320
328
324
353
354
HIGH LOAD ELOW
DAY NO. 10J ACFM
1 393
2 380
3 376
4 391
AVERAGE 385
MEDIAN 385
AT 300°F, 29.92 in. Hg.
3-7
-------
All flue gas rates reported in this section are corrected to 300°F and
29.92 in. Hg.
In an effort to further validate the flue gas flow measurements, a
limited series of flue gas measurements were made, after completion of the
Acceptance Test, with the F6D plant completely isolated from the boiler.
The objective was to compare present day flue gas rates with those obtained
during the Baseline Tesv . Measurements were made at the same location as
the Baseline Test. However, the upstream duct had been redesigned to in-
clude the louvered bypass damper and the elimination of an expansion tran-
sition of the portion of the duct collecting flue gas from the two induced
draft fans of the boiler. The test results are summarized as follows:
(a) At a gross load on the boiler of 92 MW, the flue
3
gas flow was 400x10 CFM compared to an average of
369x1O3 CFM during the Baseline Test in 1974, an
increase of about 7% after correcting for load
differences. The increase seems to be largely
due to an increase in heat input to the boiler,
which was 12% higher than during the Baseline
Test, and the corresponding increase in fuel
rate.
(b) At a gross load of 81 MW, which is the megawatt
equivalent of total main steam produced by the
boiler during the design load phase of the
Acceptance Test, the measured values averaged
399 MCFM which was virtually the same as the
flue gas volume measured at 92 MWG. However,
flows calculated from fuel composition and rate
and excess air levels correlated fairly well
with load. Using calculated values, flow rates
during the Acceptance Test were slightly higher
but within 5% of the Baseline Test measurements.
(c) It 1s concluded from these results that actual
flow rates during the Acceptance Test were higher
3-8
-------
than the 320x1O3 CFM and 388x1O3 CFM specified
for the performance runs and also were not less
than the flue gas volumes experienced during the
Baseline Test.
(d) The data collected to determine boiler heat input
during these flow tests and during the Acceptance
Test suggest a loss of boiler efficiency since
the baseline testing in 1974. Increased flue gas
flows would be one result of a decrease in effi-
ciency. The combined data of the flow tests and
the Acceptance Test show that heat input is
about 7% higher than during the Baseline Test.
(e) Based on samples of ash collected from the pre-
cipitator hoppers, heat losses due to unburned
carbon were found to be less than 0.5% of the
total heat input.
Results of these tests were reported on November 1, 1977^ . The full
report is appended (Appendix C).
While these investigations tend to confirm that flue gas volumes were
at least as high as those required for meeting the performance guarantees,
they did not provide a very accurate measure of the actual flue gas volumes.
Actually, the error in the flue gas flow measurements did not affect any of
the performance parameters except particle emission rates. Inlet grain
loading was less than 0.2 gr/ACF throughout the Acceptance Test. Therefore,
the performance requirement was that the mass rate of 0.1 lb/10 Btu not be
exceeded. To calculate a mass rate from the measured grain loadings, the
flue gas volume must be known. It was suspected and later confirmed that the
outlet flue gas rates were in error on the low side and the inlet flue gas
rates were in error on the high side. The particle emission rates calcu-
lated from the outlet flue gas rates and reported were thus in error on the
low side. Flow rates calculated from coal rates and compositions are be-
lieved to be a more accurate measure of the true flows. The mass rates have
been recalculated from the higher flue gas rates obtained by calculation
(Table 3-6).
3-9
-------
TABLE 3-6. REVISED ESTIMATES OF PARTICULATE MATTER EMISSION RATES
00
I
TEST DAY
1
2
3
5
6
8
9
10
11
1 (HIGH LOAD)
2 (HIGH LOAD)
4 (HIGH LOAD)
MEASURED
ACFM
234,973
233,056
235,976
237,756
237,756
233,350
243,641
234,470
239,841
280,360
280,417
279,533
CALCULATED^1 *
MACFM
269
226
277
309
—
—
321
307
269
318
303
802
A
MACFM
+ 34
- 7
+ 41
+ 71
+ 77
+ 73
+ 29
x = + 45
a = 30
CL = + 45 + 28
+ 38
+ 23
+ 22
x = + 28
a = 9
CL = + 28 + 22
lb/106
REPORTED
0.01
0.03
0.08
0.07
0.03
0.04
0.05
0.04
0.04
0.045
0.033
BTU
REVISED
0.02
0.04
0.10
0.10
0.04
0.05
0.07
0.05
0.05
0.05
0.04
(1)
ADJUSTED TO OUTLET TEMPERATURES AND WATER CONTENTS.
-------
The revised estimates do not exceed the performance limit of 0.1 lb/106 Btu.
The correction was made out to the upper confidence limit (95% probability)
of the average difference between the measured and calculated flue gas flow.
Therefore, there is a low probability that the revised estimate would ever be
as high as indicated.
TEST PRECISION
Precision in this case refers to the repeatability of the data. That
is, it is a measure of the variability of measurements on the same sources
of data made by a single test team with the same equipment over a short
period of time. The expected maximum instrument errors and the expected
maximum procedural errors in sampling and analysis have been used to esti-
mate variabilities expressed as the standard deviation of a mean value. The
variabilities for S02 removal, particle emission control, and'operating
costs have been estimated.
S00 Removal
The removal performance, expressed as a percentage was determined as
fol1ows:
S02 Removal = SOo in - SOp out x f
S02 in
where f is a factor to correct for dilution effects:
f = COo in v (1 - HoO in)
£ X - £.
C02 out (1 - H20 out)
The same instruments used for measuring the inlet concentrations 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 prob-
able that the variability of the S02 removal results were quite small. How-
ever, 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 sam-
pling errors, but these types of errors have been minimized in the design and
operation of the sampling systems.
3-11
-------
Particle Emission Control
The variability in participate matter emission rates from random errors
was smaller compared to the inaccuracies in the flue gas flow measurements,
the effects of which have been discussed earlier. Considerable work has
been done by EPA in an attempt to define the accuracy and precision of the
EPA method (Method 5) and errors and expected variabilities for every step of
the procedure have been estimated* '. Standard deviations determined from
expected errors have been estimated for each measurement parameter and can be
used to estimate a probable error of the method as follows:
where,
222 2
m = al + a2 + * ' ' +an
a = repeatability standard deviation of the method
a(l,2,n) = repeatability standard deviation of each
measurement parameter.
To put each standard deviation on a common basis, the Coefficient of Varia-
tion (CV), which is the standard deviation expressed as a percentage, is
substituted. Thus, for particulate matter emission rate, as lb/10 Btu heat
Input, the probable error is estimated as follows:
2 222
pmrhv ~ hr cr pmr
Where,
pmrhv = emission rate, lb/10 Btu
pmr = emission rate, Ib/hr
hr = heating value of coal, 10 Btu/lb
cr = coal rate, Ib/hr
CV = coefficient of variation and
probable error, %
CV's were estimated based on the mean values of the measurements of the
Acceptance Test (Table 3-7).
3-12
-------
TABLE 3-7. VARIABILITY OF PARTICULATE MATTER EMISSION RATES
VARIABLE
pmr
CR
hr
pmrhv
MEAN
39 lb/hr(1)
83,300 lb/hr"'
0.0104 x 106 Btu/lb^2^
0.06 lb/106 Btu(2)
cr
3.5
83.3
31 Btu Ib
0.005
CV
8.9%
0.1%
0.3%
8.9%
(^DESIGN LOAD SERIES.
(^DESIGN LOAD AND HIGH LOAD SERIES.
The data indicates a probable error of about 9% versus as much as a 31% error
due to flow Inaccuracies.
Operating Costs
Measurements subject to error include:
Maximum
Expected Error
Kilowatt-hours by meter 1.0%
Natural gas flow (2 meters) 5.0%
Natural gas heating value 0.3%
Steam flow by meter 5.6%
Steam temperature 2.0%
Steam pressure 11.0%
The performance result was a 12-day average of a combined cost performance
not to exceed $56.00/hour based on individual utility rates as follows:
Electric Power $0.007 per kWh
Steam $0.50 per 1000 Ib.
Natural Gas $0.55 per 1,000,000 Btu
3-13
-------
Thus, each utility consumption variable was determined by accumulating hourly
values over the 12-day period and dividing by the total operating hours. By
applying the maximum expected errors to each of the measurement parameters,
a probable error in operating costs can be estimated by the same method used
for particle emission control. In this case, standard deviations for the
natural gas, electricity and steam consumptions can be expressed in dollars
(Table 3-8).
TABLE 3-8. VARIABILITY IN OPERATING COSTS
VARIABLE
ELECTRICITY
NATURAL GAS
STEAM
TOTAL COSTS
CUMULATIVE
TOTALS
186,640 kWh
2,875 x 106 BTU
15,442.5 x 103 LBS
PROBABLE
%
1.0
7.0
12.5
ERROR
$/HR
0.05
0.44
3.89
3.92
A probable error of $3.92/hr., added to reported costs of $42.72, is still
well within the performance requirement of $56.00/hr.
3-14
-------
SECTION 4
REFERENCES
1. U.S. Environmental Protection Agency, Office of Research and Develop-
ment Prototype Demonstration Facility. EPA Technology Transfer Capsule
Report. First Progress Report: Wellman-Lord SO? Recovery Process-
Flue Gas Desulfurization Plant. EPA-625/2-77-01T.
2. Link, F. William, and Wade H. Ponder. Status Report on the Wellman-
Lord/Allied Chemical Flue Gas Desulfurization Plant .at Northern
Indiana Public Service Company's Dean H. Mitchell Station. Prepared
for Presentation at the Flue Gas Desulfurization Symposium Sponsored
by the Environmental Protection Agency, Hollywood, Florida, November
8-11, 1977. 18 pp.
3. TRW, Inc., Transportation & Environmental Engineering Operation.
Program for Test and Evaluation of the NIPSCO/Davy/Allied Demonstra-
tion Plant. Acceptance Test Plan. Prepared for Control Systems
Laboratory, Office of Research and Monitoring, Environmental Protection
Agency, Research Triangle Park, N.C. April 8, 1975.
4. 42FR37936, July 25, 1977 (Federal Register).
5. Adams, 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-bOO/7-77-014. TRW, Inc.,
Vienna, Va. February 1977.
6. Adams, R.C., and S.W. Mulligan. Appendix C - Demonstration of Wellman-
Lord/Allied Chemical FGD Technology: Flue Gas Flow Comparisons. TRW,
Inc., Environmental Engineering Division, Vienna, Va.
7. Smith, Franklin and Denny E. Wagoner. Guidelines for Development of a
Quality Assurance Program: Volume IV - Determination of Particulate
Emissions from Stationary Sources. Research Triangle Institute,
Research Triangle Park. EPA-650/4-74-005-d. August, 1974. 182 pp.
4-1
-------
APPENDIX A
TEST RESULTS
REPORT NO. 2 - SULFUR
Sulfur Removal
1
OPERATING TIME:
Test Day No.
Mrs. Operation (Cumulative)
Mrs. Interrupted Hone
24
TEST PERIOD: Design
Day Ending 0800 8/30/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24_
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
so2
Time
0800-1040
1040-1200
1200-1400
1400-1600
1600-1800
1800-2000
2100-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
Inlet
No data
4929
4861
4942
4897
4928
4682
4637
4500
4482
4655
4831
Outlet
No Data
420
403
381
411
452
475
477
456
454
471
503
J Removal
No Data
92
92
92
92
91
90
90
90
90
90
90
REMARKS:
Period 0800 to 1040 1s assumed to be >90Z by agreement of EPA Project
Officer.
'31/77
itt
UL-
'Test Director
A-l
-------
REPORT NO. 3 - ASH
Participate Control
TEST PERIOD: Design
OPERATING TIKE:
Test Day Ho. T_
Hrs. Operation (Cumulative)_
Hrs. interrupted Hone
24
Day Ending 0800 8/30/77
Hrs. Operation (This Day) 24
Hrs. Boi 1 er Aval labi 1 ity_
24
PERFORMANCE:
Paniculate 3-Hr. Avg.. Lb/Hr.
Gr./Acf
Emission Rate / Ib'
Inlet
0.01
0.006
0.01
REMARKS: Test passed based on lb/10 Btu value.
9/01/77
te
..
Test
irector
A-2
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 1
Mrs. Operation (Cumulative) 24
Mrs. Interrupted 0
Day Ending 0800 8/30/77
Hrs. Operation CThls Day) 24
Hrs. Boiler Availability 24
PERFORMANCE:
Electric Energy, KUH/hr.
Steam, mlbs./hr.
Total Natural Gas, tncf./hr.
Avg. Dally Cost, $
63.119
11.046
43.05
Cumulative
755
63.119
11.046
43.05
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
. C
Date
Test Director
A-3
-------
REPORT NO. 4 - COST
(Continued}
TEST DAY NO. 1
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
1
2
3
4
5
6
7
8
9
10
11
12.
13
14
15
16
17
18
19
20
21
22
23
24
Pressure PSIG
550
549
548
548
548
549
552
551
550
549
548
548
548 •
548
548
549
549
548
548
547
548
540
548
548
Temperature °F
730
730
730
729
729
728
726
727
726
726
727
726
727
728
728
728
728
727
726
727
729
720
720
720
A-4
-------
REPORT NO. 2 = SULFUR
Sulfur Removal
TEST PERIOD: Cesiqn
OPERATING TIME:
Test Day No. 2_
Hrs. Operation (Cumulative)_
Hrs. Interrupted ilone
48
Day Ending 0800 S/31/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR,
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet
4684
4691 .
4675
4719
4443
4576
4587
4592
4806
4743
48H
4840
Outlet
459
467
452
458
422
457
437
457
487
461
457
455
% Removal
90
90
90
90
91
90
91
90
90
90
91
91
REMARKS:
9/01/77
Date
Test Director
A-5
-------
REPORT HO. 3 - ASH
Particulate Control
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 2
Hrs. Operation (Cumulative) 48
Hrs. Interrupted None
Day Ending 0800 8/31/77
Hrs.
Hrs.
Operation (This Day)
Boiler Availability
24
24
PERFORMANCE:
Particulate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate / !b>
Inlet
0.02
0.01
0.03
REMARKS: Test passed based on lb/106 Btu value.
9/03/77
Date
« C,
Test Dlrec
A-6
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 2
Hrs. Operation (Cumulative) 48
Hrs. Interrupted 0
Day Ending 0800 8/31/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
PERFORMANCE:
Electric Energy, KHH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
56.198
10.004
38.91
Cumulative
750
59.659
10.525
40.98
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
vt.
[fate
Test Director
A-7
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 2
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
720
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
548
548
548
548
548
548
548
548
548
548
548
548
548
540
540
540
540
540
540
540
540
540
540
540
720
720
711
711
711
720
720
720
720
720
720
720
720
720
720
720
720
720
720
720
720
720
720
A-8
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 3
Mrs. Operation (Cumulative) 69
Hrs. Interrupted 3
Hrs.
Hrs.
TEST PERIOD : Design
Day Ending 0800 9/01/77
Operation (This Day) 21
Boiler Availability Z.1
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0300
so2
Inlet
4741
4818 .
4831
4801
4797
4774
4790
4763
____
4856
4959
Outlet
425
445
451
443
401
462
453
449
...
_._
443
431
% Removal
91
91
91
91
92
90
91
91
—
—
91
91
REMARKS: 0000 to 0120:
0120 to 0415: Boiler interruption.
Invalid S02 data.
9/02/77
9/0
"Da"
te
Jf.
£
Test Director
A-9
-------
REPORT NO'. 3 - ASH
Particulate Control
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 3
Hrs. Operation (Cumulative) 69
Hrs. Interrupted 3
Day Ending 0800 9/01/77
Hrs. Operation (This Day) 2_1_
Hrs. Boiler Availability 21
PERFORMANCE:
Parttculate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate / Ib'
Inlet
Outlet
0.05
REMARKS: Outlet sample invalid.
9/05/77
Date
(. a,
Test Director
A-10
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 3
Hrs. Operation (Cumulative) 69
Hrs. Interrupted 3
Day Ending 0800 9/01/77
Hrs. Operation (This Day) 21
Hrs. Boiler Availability 21
PERFORMANCE:
Dally Cumulative
Electric Energy, KHH/hr. 749 749
Steam, mlbs./hr. 60.460 59.894
Total Natural Gas, mcf./hr. 10.850 10.621
Avg. Dally Cost, $ 41.59 41.17
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77 W, C.
'J<,
Date Test Director
A-ll
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 3
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
719
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
540
540
540
540
540
544
540
540
540
540
540
540
518
518
518
518
518
18
19
20
21
22
23
24
540
540
540
540
719
719
711
711
711
711
711
719
719
720
720
720
720
720
720
720
720
720
720
720
A-12
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIf€:
Test Day No. 4
Hrs. Operation (Cumulative) 86
Hrs. Interrupted 7
TEST PERIOD: Deslan
Day Ending 0800 9/02/77
Hrs. Operation (This Day) 17
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
ll)1400-1500
1450-1555
1600-1700
1645-2240
U '2300-2400
0000-0200
0200-0400
0400-0600
0600-0300
so2
Inlet
5203
5101 •
5490
5579
5530
5855
5710
5711'
3G24
Outlet
470
455
485
464
:GD Interruption
Invalid Data
:GD Interruption
509
537
512
591
596
% Removal
91
91
91
92
91
?1
91
90
yo
REMARKS:
0)
One hour average.
g/03/77
Date
Test Director
A-13
-------
REPORT KO. 3 - ASH
Particulate Control
TEST PERIOD: Design
OPERATING TIKE:
Test Day Ho. 4
Hrs. Operation (Cumulative),
Hrs. Interrupted 7_
86
Day Ending 0800 9/02/77
Hrs. Operation (This Day) ]7_
Hrs. Boiler Ava1labil1ty_
24
PERFORMANCE:
Inlet
Outlet
Participate 3-Hr. Avg., Lb/Kr.
6r./Acf
Emission Rate / !b*
10° Btu
REMARKS: Test not run - rain.
9/05/77
J<. C.
Date
Test Director
A-14
-------
REPORT HO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 4
Hrs. Operation (Cumulative) 36
Hrs. Interrupted 7
Day Ending 0800 9/02/77
Hrs. Operation (This Day) 17
Hrs. Boiler Availability 24
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
56.762
10.238
39.44
Cumulative
749
59.295
10.544
40.83
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
Q/13/77
est Director
A-15
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 4
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
720
1
2
3
4
5
6
7
no
543
543
543
543
543
543
8
9
543
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
546
547
546
546
544
544
546
543
543
ND - data not available
A-16
720
720
720
720
720
720
716
724
720
720
720
722
720
720
722
722
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 5
Mrs. Operation (Cumulative) 107
Hrs. Interrupted 3
TEST PERIOD; Design
Day Ending 0800 9/03/77
Hrs. Operation (This Day) 21
Hrs. Boiler Availability ^4
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0240-0545
0600-0800
so2
Inlet
6322
6250 •
621 G
5879
5767
5764
5520
5301
5109
4891
Outlet
755
663
636
564
531
496
436
492
472
FGD Interruptioi
445
% Removal
88
89
90
90
91
91
91
91
91
91
REMARKS: Test failed 0800-1200 (4 hours).
9/03/77
Date
J<
Test Director
A-17
-------
REPORT NO. 3 - ASH
Participate Control
TEST PERIOD: Design
OPERATING TIME:
Test Day Mo. 5
Hrs. Operation (Cumulative)_
Hrs. Interrupted 3
107
Day Ending 0800 9/03/77
Hrs. Operation (This Day) 21
Hrs. Boiler Availability 24_
PERFORMANCE:
Participate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Inlet
0.04
0.03
Emission Rate /
10° Btu
0.08
REMARKS:
9/05/77
Date
est Oi«
A-18
-------
REPORT HO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 5
Hrs. Operation (Cumulative) 107
Hrs. Interrupted 3
Day Ending 0800 9/03/77
Hrs. Operation (This Day) 21
Hrs. Boiler Availability 24
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Dally Cost, $
63.184
12.163
43.78
Cumulative
751
60.069
10.863
41.41
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
3P
Da
J\ . C.
J
te
Test Director
A-19
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 5
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
720
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
5-14
542
542
544
542
543
545
547
547
545
545
544
544
545
546
547
546
535
546
20
21
22
23
24
530
546
720
720
720
720
720
721
728
724
721
723
720
724
726
724
724
726
725
724
723
724
A-20
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 6
Mrs. Operation (Cumulative)_
Hrs. Interrupted 3_
128
Day Ending 0800 9/04/77
Hrs. Operation (This Day) 21_
Hrs. Boiler Availability ?&
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1300
UJ1300-1400
1400-1600
1600-1800
1800-2000
(ZJ2000-2200
^2200-2400
(2)0000-0200
tZ)0200-0400
^0400-0600
tZ)0600-OSOO
so2
Inlet
5301
5296
5423
5698
5488
5363
5218
5126
5104
5241
5152
Outlet
496
FGD Interrupt! oi
531
505
509
566
562
540
517
4G4
529
509
% Removal
91
90
91
90
90
90
90
SO
91
90
90
REMARKS: Total test hours failed to date: 4
^ '
^ '
One hour average
Invalid S0? data. Allied analyzer used.
9/C6/77
ate
Test Director
A-21
-------
REPORT NO. 3 ASH
Particiilate Control
TEST PERIOD: Design
OPERATING TIKE:
Test Day No. 6
Hrs. Operation (Cumulative^
Mrs. interrupted 3_
128
Day Ending 0800 9/04/77
Hrs. Operation (This Day) 21
Hrs. Boiler Availability 24
PERFORMANCE:
Inlet
Outlet
Partlculate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate / -4^—
10b Btu
0.04 0.03
0.07
REMARKS:
9/07/77
Ite
est Director
A-22
-------
REPORT NO. 4 COST
Operating Costs
TEST PERIOD- Desian
OPERATING TIME:
Test Day No. 6
Hrs. Operation (Cumulative),
Hrs. Interrupted 3_
128
Day Ending 0800 9/04/77
Hrs. Operation (This Day) 21_
Hrs. Boiler Availability 2±
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
63.995
12.481
Cumulative
60.723
11.131
44.50
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
J.C. <
te
Test Director
A-23
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO.
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
544 728
2
545
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
546
547
546
546
546
544
544
543
544
545
545
545
545
545
546
546
546
5^7
547
723
725
724
725
723
723
723
724
726
727
726
726
726
727
727
726
727
727
727
727
A-24
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
TEST PERIOD: Deslcn
OPERATING TIME:
Test Day No. 7
Hrs. Operation (Cumulative) 143
Hrs. Interrupted 9
Day Ending 0800 9/05/77
Hrs. Operation (This Day) 15
Hrs. Boiler Availability 17
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES
2-Hr. Averages
Time
0800-0900
0900-1630
1630-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0330
0330-0545
0545-0800
so2
Inlet
4953
. Bo
5246
5157
5315
5349
4982
4877
5037
Outlet
429
11 er Interrupt! o
477
514
510
529
495
479
:GD Interruption
448
, LBS/HR.
% Removal
91
,
91
90
90
90
90
90
91
REMARKS: Total test hours failed to date: 4
9/06/77
. c. ait
Date
Test Director
A-25
-------
REPORT NO. 3 - ASH
Parti cul ate Control
TEST PERIOD : Design
OPERATING TIME:
Test Day No. 7
Hrs. Operation (Cumulative) 143
Mrs. Interrupted 9
Day Ending 0800 9/05/77
Hrs. Operation (This Day) 15
Hrs. Boiler Availability ]]_
PERFORMANCE:
Participate 3-Hr. Avg., Lb/Hr.
6r./Acf
Emission Rate / lb< .
Inlet
Outlet
REMARKS: No test - boiler Interruption.
9/06/77
Iff
Test Director
A-26
-------
REPORT HO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 7
Hrs. Operation (Cumulative) 143
Hrs. Interrupted 9
Day Ending 0800 9/05/77
Hrs. Operation CThls Day) 15
Hrs. Boiler Availability 17
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Dally Cost, $
61.174
11.292
42.46
Cumulative
757
60.769
11.147
41.98
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
ate
Test Director
A-27
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO.
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
725
1
548
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
544
543
543
543
543
542
542
543
545
549
552
551
21
22
23
24
543
542
ND - data not available.
A-28
722
ND
725
725
726
726
728
728
726
723
722
723
725
722
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 8
Hrs. Operation (Cumulative) 167
Mrs. Interrupted Hone
Hrs.
Hrs.
TEST PERIOD; Design
Day Ending 0800 9/6/77
Operation (This Day) 24
Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
oaoo-iooo
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet.
4966
4991
4923
4950
4929
4954
4899
4833
4885
4819
4C36
4397
Outlet
426
448
445
480
459
449
448
438
459
458
454
457
% Removal
91
91
91
90
91
91
91
91
91
31
91
91
REMARKS: Total hours test failed to date: 4
9/06/77
Date
lest Director
A-29
-------
REPORT NO. 3 - ASH
Parti cul ate Control
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 8_
Hrs. Operation (Cumulative)
Mrs. Interrupted Hone
167
Day Ending 0800 9/06/77
Hrs. Operation (This Day) £4
Hrs. Boiler Availability.
24
PERFORMANCE:
Participate 3-Hr. Avg.. Lb/Hr.
6r./Acf
Inlet
95.3
0.07
Outlet
29.7
0.01
Emission Rate /
0.03
10° Btu
REMARKS:
9/09/77
•A
te
/L6
Direc
Test Director
A-30
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 8
Mrs. Operation (Cumulative) ]67
Hrs. Interrupted o
Day Ending 0800 9/06/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability £4
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
64.310
11.618
44.22
Cumulative
761
61.286
11.215
42.30
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
ate
est Director
A-31
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. a
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
542 724
725
2 543
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
544 -
543
544
544
544 .
543
543
544
546
547
547
547
546
544
543
544
544
544
543
543
546
545
726
727
726
726
726
726
727
727
726
726
726
726
726
726
726
726
725
726
728
728
728
727
A-32
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
TEST PERIOD; Design
OPERATING TIME:
Test Day No. 9
Mrs. Operation (Cumulative)
Hrs. Interrupted None
191
Day Ending 0800 9/07/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability Z£
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
16CO-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet
4810
4722 .
4732
4679
4581
4796
4674
4644
4694
4722
4847
4880
Outlet
419
473
483
486
454
465
430
430
425
433
444
449
% Removal
91
90
90
90
90
90
91
91
91
91
91
31
REMARKS: Total hours test failed to date: 4
9/08/77
te
. £,/!
Test Dir
est Director
A-33
-------
REPORT HO. 3 - ASH
Participate Control
TEST PERIOD : Design
9
OPERATING TIME:
Test Day No._
Hrs. Operation (Cumulative) 191
Hrs. Interrupted None
Day Ending 0800 9/Q7/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24_
PERFORMANCE:
Inlet
Participate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate / Ib>
0.02
0.02
0.04
REMARKS:
9/09/77
Date
Test Director
A-34
-------
REPORT HO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 9
Hrs. Operation (Cumulative) 191
Hrs. Interrupted Hone
Day Ending 0800 9/07/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability -4
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Dally Cost, $
63.943
11.529
43.96
Cumulative
763
61.625
11.255
42.52
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
Date
J\,C- wa^-
Test Director
A-35
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 9
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSIG Temperature °F
726
1
2
3
4
5
G
7
8
9
10
n
12
13
14
15
16
17
18
19
20
21
22
23
24
545
546
547
548
546
544
547
548
547
547
548
547
545
543
546
547
546
546
547
546
546
546
547
547
726
726
725
727
727
725
726
724
724
725
725
726
726
726
725
725
724
722
725
725
724
724
725
A-36
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 10
Hrs. Operation (Cumulative) 212
Mrs. Interrupted 2
TEST PERIOD : Design
Day Ending 0800 S/08/77
Hrs. Operation (This Day) 22
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-0845
0845-1100
1100-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0803
so2
Inlet
4849
4951
4940
4854
4733
4729
4664
4643
46C7
4676
4705
4C19
Outlet
460
FGD Interruption
488
475
432
423
437
418
417
430
343
422
472
% Removal
91
90
90
91
91
91
21
91
91
m
£1
jO
REMARKS: Total test hours failed to date: 4
q/ns/77
Bff
LL
Test Director
A-37
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD; Design
OPERATING TIME:
Test Dav No. 10
Hrs. Operation (Cumulative),
Hrs. Interrupted 2_
213
Day Ending 0800 9/08/77
Hrs. Operation (This Day)_
Hrs. Boiler Availability_
22
PERFORMANCE:
Inlet
Participate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate / ]b'
0.02
0.02
0.05
REMARKS:
9/10/77
Date
(LA
t Dtri
Test Director
A-38
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD: Desian
OPERATING TIME:
Test Day No. 10
Hrs. Operation (Cumulative) 213
Hrs. Interrupted 2
Day Ending 0800 9/08/77
Hrs. Operation (This Day) 22
Hrs. Boiler Availability 24
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost. $
64.110
11.292
43.91
Cumulative
765
61.885
11.259
42.66
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
J?.C.
Date
Test Director
A-39
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 10
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
1
Pressure PSIG
547
j>
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
•i™
566
567
567
567
566
567
567
566
565
565
565
565
567
566
566
566
566
566
565
564
565
Temperature °F
725
722
722
722
723
723
722
722
723
723
723
723
723
723
723
723
723
723
724
724
725
725
A-40
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
TEST PERIOD: Design •
OPERATING TIME:
Test Day No. n
Hrs. Operation (Cumulative) 237
Hrs. Interrupted Hone
Day Ending 0800 9/09/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet
4870
4935
4783
4796
4675
4438
4424
4415
4426
4431
4538
4674
Outlet.
486
474
440
411
396
367
369
372
380
387
324
398
, LBS/HR.
% Removal
90
90
91
91
92
92
92
92
91
SI
92
91
REMARKS: Total test hours failed to date: 4
One boiler feed pump down from about 1830 to 0800. Load at about 60 MU.
9/09/77
Date
Direc
Test Director
A-41
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD: Design.
OPERATING TIME:
Test Day No. 3J_
Hrs. Operation (Cumulative) 237
Hrs. Interrupted Hone
Day Ending 0800 9/09/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability
24
PERFORMANCE:
Inlet
Participate 3-Hr. Avg., Lb/Hr.
6r./Acf
Emission Rate / Ib'
0.018
0.015
0.04
REMARKS:
9/10/77
Date
Test Director
A-42
-------
REPORT NO. 4 - COST
Operating Costs
OPERATING TIME:
Test Day No. n
Mrs. Operation (Cumulative) 237
Hrs. Interrupted None
Hrs.
Hrs.
Day Ending 0800 9/09/77
Operation (This Day) 24
Boiler Availability 24
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
62.932
11.449
43.07
Cumulative
763
61.932
11.268
42.68
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
t'K. C,
Date
Test Director
A-43
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 11
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSI6 Temperature °F
726
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
567
567
567
569
569
571
571
569
569
570
571
571
568
569
570
570
568
567
568
569
.573
572
573
573
725
726
725
725
725
725
724
725
726
725
726
727
727
727
727
727
727
727
725
727
727
727
726
A-44
-------
REPORT NO. 2 SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 12
Hrs. Operation (Cumulative) 261
Hrs. Interrupted "one
TEST PERIOD: Design
Day Ending 0800 9/10/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL Z HR. AVERAGES, LBS/HR.
2-Hr. Averages
so2
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
Inlet
4714
4712 .
4732
4767
4787
4853
4819
4810
4906
4872
4872
4886
Outlet
426
443
411
428
464
455
464
448
422
438
444
452
% Removal
91
91
91
91
90
91
90
91
91
91
91
91
REMARKS: Test 1s being extended four additional hours to make up four hours
failure.
9/10/77
ate
Te
est Director
A-45
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 12_
Hrs. Operation (Cumulative) 261
Hrs. Interrupted None
Day Ending 0800 9/10/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability
24
PERFORMANCE:
Paniculate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate /
Inlet
Outlet
REMARKS: No test. High winds - unsafe test conditions.
9/10/77
Date
Test Director
A-46
-------
REPORT HO. 4 - COST
Operating Costs
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 12_
Hrs. Operation (Cumulative) 261
Hrs. Interrupted Hone
Day Ending 0800 9/10/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 2£_
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Daily Cost, $
64.560
10.875
43.39
Cumulative
758
62.191
11.229
42.75
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
13/77
1
J(.t
te
Test Director
A-47
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 12
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSI6 Temperature °F
726
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
572
572
572
563
567
568
569
568
568
567
566
566
566
565
565
564
563
563
562
561
566
565
567
572
725
724
725
724
724
723
723
723
723
724
724
725
724
725
725
725
726
726
726
726
726
727
727
A-48
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 13
Hrs. Operation (Cumulative) 265
Hrs. .Interrupted None
TEST PERIOD: Deslqn
Day Ending 0800 9/11/77
Hrs. Operation (This Day) 4
Hrs. Boiler Availability 4
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
•
Time
0800-1000
1000-1200
so2
Inlet
4890
4918 .
Outlet
449
439
% Removal
91
91
REMARKS: Four hour .test to makeup four hours failure. Design test period
completed.
9/11/77
. C,
Date
_
Test Director
A-49
-------
REPORT NO. 4 - COST
Operating Costs
TEST PERIOD : Design
OPERATING TIf€:
Test Day No. 13
Mrs. Operation (Cumulative) 265
Hrs. Interrupted None
Day Ending 0800 9/11/77
Hrs. Operation (This Day) *
Hrs. Boiler Availability 4
PERFORMANCE:
Electric Energy, KWH/hr.
Steam, mlbs./hr.
Total Natural Gas, mcf./hr.
Avg. Dally Cost. $
62.340
9.808
42.09
Cumulative
758
62.193
11.206
42.74
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/13/77
Jr. C,
Date
Test Director
A-50
-------
REPORT NO. 4 - COST
(Continued)
TEST DAY NO. 13
SEQUENTIAL HOURLY DEMONSTRATION
PLANT STEAM PRESSURES AND TEMPERATURES
Pressure PSI6 lemperature °F
1 571 725,
?. 572 725
3 57] 724
4 572 724
5
6
7
8
9
10
11
12 \
13
14
15
16
17
18
19
20
21
22
23
24
A-51
-------
REPORT NO. 4 - COST
Operating Costs
12-DAY AVERAGE-COSTS
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 1-13 Day Ending 0800 9/11/77
Hrs. Operation (Cumulative) 265 Mrs. Operation (This Day) 4_
Hrs. Interrupted 27 Hrs. Boiler Availability 2C2
PERFORMANCE:
Daily Cumulative
Electric Energy, KWH/hr. 757.8
Steam, mlbs./hr. 62.193
Total Natural Gas, mcf./hr. 11.206
Avg. Dally Cost, $ 43
(HOURLY STEAM PRESSURE AND TEMPERATURE ATTACHED)
REMARKS:
9/11/77 j \.
Date Test Director
A-52
-------
REPORT NO. 6 PRODUCT
By-Product Sulfur Assay
12-DAY AVERAGE
TEST PERIOD
OPERATING TIKE:
Test Day No. 1-12
Hrs. Operation (Cumulative) 265
Hrs. Interrupted 27
Day Ending 0800 9/11/77
Hrs. Operation (This Day) a.
Hrs. Boiler Availability :;,2
PERFORMANCE:
Sulfur Assay, Wt. ZS 99.76
Wt. % Ash 0.007
<5 ppm
Ht. % Carbon Mi
Ht. % Chlorides O.^OZ
Wt. % Acidity as H2S04 0.0'jJS
REI4ARKS:
10/3/77 .](,
Date Test Director
^M
: Dirt
A-53
-------
REPORT NO. 5 - SODA
Soda Ash Feed Rate
12-DAY AVERAGE
TEST PERIOD: Design
OPERATING TIME:
Test Day No. 13
Hrs. Operation (Cumulative) 265
Hrs. Interrupted None
Day Ending 0800 9/11/77
Hrs. Operation (This Day) 4
Hrs. Boiler Availability •+
PERFORMANCE:
Avg. Soda Ash Consumed, Tons/Day 6.2
REMARKS:
9/11/77
Date
Test Director'
A-54
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 1
Hrs. Operation (Cumulative) 24
Hrs. Interrupted 0)
TEST PERIOD: High Load
Day Ending 0800 9/12/77
Hrs. Operation (This Day) 24
Hrs . Boil er Aval 1 abi 1 i ty £4 ^ '
CONTIGUOUS DATA SEQUENTIAL 2 HR. AVERAGES
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet
5665
5554 •
5467
5513
5647
5825
5778
5806
5879
5S6C
6029
5782
Outlet
491
419
433
442
469
495
502
551
590
5C6
S4C
435
, LBS/HR."
% Removal
91
93
92
92
92
92
91
91
90
90
91
93
REMARKS: (^Boiler down to 55-60 HW for about one hour, 0600-0700. iio
Interruption is charged.
9/13/77
te
J(. C, frL^.
Test Director
A-55
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD: High Load
OPERATING TIME:
Test Day No. 1
Hrs. Operation (Cumulative) 23
Hrs. Interrupted 1
Hrs.
Hrs.
Day Ending 0800 9/12/77
Operation (This Day) 23
Boiler Availability 23
PERFORMANCE:
Particulate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate /
Inlet
0.04
0.02
0.04
REMARKS:
9/14/77
Date
J\ t: QJi
Test Director
A-56
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
TEST PERIOD: Hi oh Load
OPERATING TIME:
Test Day No. 2
Mrs. Operation (Cumulative) 48
Mrs. Interrupted '(one
Day Ending 0800 9/13/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR. '
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-0600
0600-0800
so2
Inlet
6163
6239
6568
7058
7232
7218
7153
7210
7213
7010
7319
7469
Outlet
553
577
655
660
678
682
713
722
704
775
729
764
% Removal
91
91
90
91
91
91
90
90
90
G3
ilO
90
REMARKS: jest failed two hours, 0200-0400.
9/13/77
Date
f)\t C, i
Test Director
A-57
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD; High Load
OPERATING TIME:
Test Day Ho. 2
Mrs. Operation (Cumulative)_
Mrs. Interrupted None
47
Day Ending 0800 9/13/77
Hrs. Operation (This Day) 24_
Hrs. Boiler Availability
24
PERFORMANCE:
Inlet
Participate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Ib.
Emission Rate /
0.05
0.02
0.05
REMARKS:
9/14/77
te
Tes
rector
A-58
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 3
Hrs. Operation (Cumulative) 72
Hrs. Interrupted ilone
TEST PERIOD : High Load
Day Ending 0800 9/14/77
Hrs. Operation (This Day) 24
Hrs. Boiler Availability 24
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averages
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
2200-2400
0000-0200
0200-0400
0400-060U
0600-0800
so2
Inlet
7199
7169 .
7013
6937
6071
5790
6639
6405
6693
6d&0
7094
7394
Outlet
724
723
688
670
652
623
632
632
654
681
673
712
% Removal
90
90
90
90
91
91
91
90
90
90
91
90
REMARKS:
9/14/77
Date
!X.
Te
est Director
A-59
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD: High Load
OPERATING TI::F:
Test Day No. 3
Hrs. Operation (Cumulative) 71
Hrs. Interrupted None
Day Ending 0800 9/14/77
Hrs. Operation (This Day) 1:4
Hrs. Boiler Availability 24
PERFORMANCE:
Inlet
Outlet
Participate 3-Hr. Avg., Lb/Hr.
Gr./Acf
Emission Rate /
10" Btu
REMARKS: No sample collected - rain.
Id/77
j{. d.fj
Test Dire
irector
A-60
-------
REPORT NO. 2 - SULFUR
Sulfur Removal
OPERATING TIME:
Test Day No. 4
Mrs. Operation (Cumulative) 85
Mrs. Interrupted None
Day Ending 0800 9/15/77
Hrs. Operation (This Day) 14
Hrs. Boiler Availability 14
CONTINUOUS DATA SEQUENTIAL 2 HR. AVERAGES, LBS/HR.
2-Hr. Averaqes
Time
0800-1000
1000-1200
1200-1400
1400-1600
1600-1800
1800-2000
2000-2200
so2
Inlet
7401
7253
7079
6695
6428
648T
6448
Outlet
755
711
675
625
612
605
G31
% Removal
90
90
91
91
91
91
90
REMARKS:
9/14/77
IJate
1
A
Test Director
A-61
-------
REPORT NO. 3 - ASH
Particulate Control
TEST PERIOD: High Load
OPERATING TIME:
Test Day Ho. 4
Hrs. Operation (Curaulative)_
Mrs, Interrupted itone
85
Day Ending 0800 9/15/77
Hrs. Operation (This Day) 14
Hrs. Boiler Availability
14
PERFORMANCE:
Inlet
Participate 3-Hr. Avg., Lb/Hr.
Sr./Acf
Emission Rate / ]b'
0.04
0.01
0.03
REMARKS:
9/15/77
Test Director
A-62
-------
REPORT HO. 6 - PRODUCT
By-Product Sulfur Assay
TEST PERIOD: High Load
OPERATING TIME:
Test Day No. 1-4
Hrs. Operation (Cumulative)
Mrs. Interrupted Hone
85
Day Ending 0800 9/15/77
Hrs. Operation (This Day) 14
Hrs. Boiler Availability 85
PERFORMANCE:
Sulfur Assay, Wt. IS
Wt. X Ash
As-0,
Wt. X Carbon
Ht. X Chlorides
Ht. X Acidity as H.SO.
99.61
0.005
<5 DOT!
0.11
0.0002
0.0005
Corrected
99.99
0.004
Not detected
0.004
.
.
REMARKS:
10/3/77
Date
U\. t.
Test Direc
A-63
-------
COAL ANALYSIS
Ol
Test Period
Desian
Design
Design
Design
Design
Design
Design
Design
Design
Desian
Design
Design
Design
Design
Design
Design
Deslnn
Design
Design
Design
•Design
Design
• Design
Test
Day
1
Spot
2
Spot
3
Spot
4
5
Spot
6
Spot
7
8
Spot
9
Spot
5
5
10
Spot
11
Snot
12
Day
Ending
0800
8/30/77
8/30/77
8/31/77
8/31/77
9/01/77
9/01/77
9/02/77
9/03/77
9/03/77
9/04/77
9/04/77
9/05/77
9/06/77
9/07/77
9/07/77
1000-1200
0800-1000
9/08/77
9/08/77
9/09/77
9/09/77
9/10/77'
t
C
59.50
58.87
58.88
56.41
60.07
60.30
59.09
58.78
58.30
59.29
57.71
59.29
59.42
59.25
59.91
59.20
59.09
59.03
60.34
60.09
58.81
60.12
60.09
H
4.10
4.22
4:04
3.72
4.12
4.04
4.01
3.97
3.97
4.11
3.99
4.04
4.11
4.12
. 4.08
4.07
4.07
4.11
4.06
3.99
3.79
4.16
4.09
Wt.
N
1.14
1.12
0.76
0.66
1.21
0.82
1.20
1.00
1.18
1.03
1.06
1.05
1.12
0.83
1.01
1.01
0.78
0.97
0.74
0.76
1.08
1.04
1.02
%
0
7.55
8.19
7.60
7.51
7.50
7.58
6.56
7.21
6.42
7.15
7.77
7.55
7.58
7.99
7.53
7.48
10.23
7.03
4.50
7.17
7.17
7.25
7.34
S
2.61
2.75
2.64
2.33
2.91
2.94
3.20
3.23
3.38
2.77
2.93
2.59
2.80
2.67
2.75
2.74
2.83
3.21
3.20
2.81
2.45
2.87
2.60
j.
H?0
15.62
14.48
14.88
13.66
13.06
13.23
12.78
13.50
12.23
14.95
14.75
14.90
15.46
15.68
14.75
15.76
12.60
13.39
14.26
14.18
15.34
15.00
. 14.74
Btu/Lb.
HHV
10614
10566
10509
9980
10G92
10735
10506
10491
10351
10524
10387
10546
10637
10594
10642
10540
10569
10527
10708
10616
10441
10756
10678
Ut. X
Ash
9.47
10.31
11.16
15.67 .
11.09
11.05
13.13
12.27
14.49
10.67
11.76
10.47
9.48
9.43
9.94
9.71
10.37
12.23
12.87
10.98
11.35
9.56
10.09
-------
COAL ANALYSIS (CONTINUED)
:>
en
Test Period
High Load
High Load
Design
High Load
High Load
High Load
High Load
High Load
Test
Day
1
Spot
13
2
Spot
3
Spot
4
Day
Ending
0800
9/12/77
9/12/77
9/11/77
9/13/77
9/13/77
9/14/77
9/15/77
9/15/77
C
60.19
59.78
60. 46
57.79
58.41
57.81
58.09
59.68
H
4.15
4.09
4.04
3.85
4.06
3.99
4.09
4.10
1,14.
N
1.04
0.85
1.11
1.01
1.01
1.01
0.80
0.80
V
if - - --
0
7.68
7.90
7.80
7.44
7.66
6.84
7.63
7.24
t
S
2.76
2.75
2.84
3.11
2.66
3.31
3.05
3.20
H20
14.15
14.31
13.40
11.90
13.48
13.02
12.67
13.19
Btu/Lb.
HHV
10624
10600
10307
10350
10422
10321
10413
10696
Wt. 2
Ash
10.00
10.29
10.32
14.80
12.69
14.00
13.65
11.77
-------
»t*» AlK/wl • UnniSTRIAL. CHEMICALS Division
j-^VS AIII8Q
^s,. Li Chemical ANALYSIS CERTIFICATION
^>§
FROM . LABORATORY
Green River Works
Si. JT
Soda Ash Analysis
''Allied Chemical Corporation' ~*
Industrial Chemicals Division
PO Box 2006
Hasoond IN 46323
Attn; Mike McCoy
L. J
DATCSAUTLI RECEIVED
July 20. 1977
ANALYSIS PATE
July 26, 1977
SOURCE
Railroad Car Loaded
RErtRENCI NO.
NO.SAUTLEI
2
D SAMPLC rHOTERLY TAKEN
D SAUTLf SAID TO REPRESENT
UARKIO
CRDX 6456
Screen Analysis
U. S. Screen
120
30
40 .
60
• 100
200
-200
T, Retained
.1
3.0
23.3
54.7
17.1
1.6
.2
TOTAL :...-. 100.0
Density. : 1024 GPL
Color , 96
Assay as Ma.2C03 99.79
Impurities
Sodium Chloride (as NaCl).
Soluble Silica (as SiOa)..
Organic Matter (as C)
Iron (as Fe)
.0067 %
.0155 1
.0153 1
.0003 t
ICCRTIHED BY:
A-66
-------
APPENDIX B
TEST METHODS
I. S02 REMOVAL EFFICIENCY DETERMINATION
A) Analysis methods used by continuous analyzers to measure gaseous
components which determine the removal efficiency:
1. S02 (in/out) was determined by using a split
beam ultraviolet photometric detector.
2. C02 (in/out) was determined by non-dispersive
infrared detection using nitrogen as the
reference gas.
3. H20 (in/out) was determined by non-dispersive
infrared detection using nitrogen as the
reference gas.
B) Sulfur in coal analysis was done using ASTM Standard
Method D271.
C) Calibration of the three continuous analyzers used to
determine S0« removal efficiencies was performed on a daily
basis using the following calibration gases:
Zero Span
S02 N2 260 ppmv S02 in N2 (low span)
2690 ppmv S02 in N2 (high span)
C02 N2 75% by volume C02 in N2
H20 N2 Pure C2Hg giving 62.5% of full scale
D) Manual sampling of the inlet flue gas stream (sample point was
at the discharge of the boiler ID fans) was done using a modified
EPA Method 6 testing procedure whereby one point, non-isokinetic
sampling was used for S02 determination.
B-l
-------
E) F6D plant analyzer was calibrated daily using ambient air as
the source of zero gas and an optical filter system for span-
ning the instrument.
F) Calculation of the S02 removal efficiency for the Design
Test was performed using the following method:
1. Average gas concentrations were calculated
for inlet and outlet S02, inlet and outlet
COp, and inlet and outlet H20 for each 2-
hour period, beginning at 0800 hours each
day.
2. Average stack temperatures and static pressures
were found for the same 2-hour periods.
3. Flue gas flow rates (assumed to be at the
measured inlet conditions to the scrubber)
were corrected to 70°F and 29.92" Hg. for
each 2-hour period.
4. SO/> mass rates at the inlet for each 2-hour
period were calculated by multiplying the
average inlet S02 concentration by the
corresponding flue gas flow rate and then
multiplying this quantity by the density of
S02 (0.1655 lb/ft3 0 70° F and 1 atm.)
5. Flue gas flow rates at the outlet for each
2-hour period were corrected for air in-
leakage and water pickup by using the follow-
ing equation:
VSTD = (VSTDI) (COol) (100-HoOI)
(C020) (100-H200)
where: ..
VSTD = outlet flow rate, ftj/hr
VSTDI = inlet flow rate, ft3/hr
C02I = inlet C02 concentration, vol. %
B-2
-------
C020 = outlet C02 concentration, vol. %
H2OI = Inlet H20 concentration, vol. %
H200 = outlet H20 concentration, vol. %
6. S02 mass rates at the outlet for each 2-hour
period were calculated by multiplying the
average outlet S02 concentration by the corres-
ponding flue gas flow rate and then multiplying
this quantity by the density of S02 (0.1655 lb/
ft3 e 70°F, 1 atm.).
7. S02 removal efficiency for any 2-hour period
was then given by:
% removal = 1 - ^S03 mass rate> Q"t1et)
(S02 mass rate, inlet)-
II. PROCESS CONSUMABLES
A) Natural gas flow rates were measured using the FGD plant factory-
calibrated flow nozzles and pressure differential transducers
which were calibrated on a routine basis. Natural gas heating
values were obtained from NIPSCO from calorimetric analysis.
B) Kilowatt-hour measurements were taken from the FGD plant meter
which were calibrated by the NIPSCO Meter Department.
C) Steam flow rates were measured using pressure differential
transducers and factory-calibrated flow nozzles. The transducers
were calibrated by applying known pressure differentials across
the transducer and verifying correct output.
D) Steam temperature and pressure were measured using thermo-
couples and differential pressure sensors, respectively.
Temperature sensors were calibrated by thermocouple disconnect
at the recorder input, application of a known DC potential
across the input, and verifying correct output. Pressure
sensor calibration was performed using dead weight testers.
B-3
-------
E) Steam temperature, pressure, and flow were reported on an
hourly basis derived from twenty 3-minute averages taken
during the hour.
F) A correction to steam flow rate based on measured temper-
ature and pressure was derived empirically. The equation
for determining corrected steam flow, in lb/hr., is as
follows:
(-1.3759 x IP"6 T2) + (2.3391 x IP"3 T) + .11237
W = W
c
-\/ (1.25 x 10"3 T) - (2.21 x 10"3 p) + 1.5525
where:
W = corrected flow rate, lb/hr
W = indicated flow rate, lb/hr
T = steam temperature, °F
p = steam pressure, psig
III. SODA ASH
A) Soda ash consumption figures were provided by Allied Chemical
along with a certificate of analysis for Na^CO., content. Based
on this analysis, the soda ash consumption rate was converted
to a pure Na^CO? consumption rate and reported as ^COg
consumed.
IV. SULFUR PRODUCT PURITY
A) A sample from each truck shipment was collected by Allied
Chemical personnel. Shipments were at a frequency of about one
a day. To prepare a laboratory sample; portions from each
sample increment were split off, pulverized, and mixed by
quartering. Two samples were prepared in this fashion; one
for the Design Load phase and one for the High Load phase.
B) The samples were analyzed by Commercial Test and Engineering
Company laboratories, using methods for bright sulfur supplied
by Allied Chemical.
B-4
-------
V. PARTICULATE MATTER
A) Sampling was done both at the Inlet and outlet of the absorber
in accordance with EPA Method 5, Federal Register. August 18,
1977 using 24 traverse points.
B) Sampling during both the Design Load test and the High Load
test was normally scheduled to begin between 0800 and 0900 hours
with completion usually 4.5 hours after commencement. During
the period of manual sampling, coal samples were taken every
7.5 minutes with a composite sample made up at the end. Also,
boiler and FGD process readings were taken both at the beginning
and end of the manual sampling period.
C) Particulate matter was determined by the following methodology:
1. Dessicate needed quantity of Gelman, Type A-E,
Glass-Fiber filter paper for at least 24 hours.
2. Weigh each filter and obtain weight to nearest
0.0001 gram.
3. Place weighed filter in labeled holder.
4. Transport filters and holders in dessicator
to sampling site, avoiding any contamination
of filter.
5. After use in sampling train, dessicate filter
for at least 24 hours.
6. Weigh filter and obtain weight to nearest
0.0001 gram.
7. Obtain subtotal of particle weight by differ-
ence.
8. Add to this, weight of particulate matter
washed out of sampling line from probe inlet
to the filter using acetone (acetone was driven
off by heating on hot plate set to 40°C).
B-5
-------
VI. S02 BY MANUAL METHODS
A) Sampling was carried out by a modified EPA Method 6 (42 FR 41754,
August 18, 1977). The method was modified to increase the
absorbing reagent supply so that the sampling could cover the
entire period of particulate matter sampling, about 4.5 hours.
The collecting hardware was modified from a midget impinger
train to a full sized impinger train in order to use the
Method 5 EPA train for both particulate and sulfur oxides.
Instead of distilled water in the impingers, the first im-
pinger contains 80% isopropanol (SO, absorption), the second
and third impingers contain 3% hydrogen peroxide (S02 absorp-
tion), and a fourth impinger is for silica gel.
B) The analysis for S02 is a barium-perch!orate titration with
thorin end-point indicator after the SOy is oxidized to S03
by the peroxide absorbing solution.
C) Flow determination was accomplished in accordance with EPA
Method 2, Federal Register. August 18, 1977.
D) Moisture and dry molecular weight determinations were per-
formed by gas chromatograph analysis (using an AID GC-TC)
which is an accepted substitute method for both EPA Methods
4 and 3, Federal Register, August 18, 1977.
VII. FLUE GAS SAMPLING BY THE CONTINUOUS SAMPLING TRAIN
A) Flue gas was sampled at both the NIPSCO outlet and the absorber
outlet. In-stack filters, with a filter surface of a porous
metal removed particulates of 5 micron diameter or greater.
To prevent degradation of the gaseous sample, the sample was
delivered to the sensor system in a heated process line. At
the NIPSCO outlet, the line was mainteined at 300°F. At the
absorber outlet, a temperature of 150QF was maintained. The
sample line was 3/8" TFE. The chemical inactivity of this
line prevented degradation of the flue gas. The electrically
traced process line interfaced with the in-stack filter at
B-6
-------
the duct and interfaced with the S02 analyzer in the continu-
ous monitor installation. Blowback of the sample lines was
initiated at the S02 analyzer to occur once every 6 minutes.
B) Flow control through the continuous sampling system was on a
dual-pressure basis. The S02 and H20 vapor analyzers operated
on a partial vacuum flow system, while the remainder of the
instruments used a positive pressure flow system. Wet sample
gas was supplied to the S02 analyzer at a rate of 5 scfh and
was pressure-controlled internally at the analyzer to ensure
proper readings. Wet sample gas was supplied to the H20 vapor
analyzer at the rate of 10 scfh and flow to the analyzer was
controlled internally by a separate pump. The sample gas
stream not used by the H20 vapor analyzer then was pumped under
positive pressure through a condenser and then supplied to the
C02 and 02 analyzers on a dry basis.
VIII. COAL SAMPLING
A) Coal was sampled by the NIPSCO coal handler from the coal hoppers
to make composites of raw coal, using sampling probes designed by
NIPSCO. One gross sample per 4-hour spot test was composited
from increments taken every 7.5 minutes, while one gross sample
per 24-hour period was composited from increments taken every
hour over the 24-hour sampling period, except the hours when a
manual sample was being run. During the hours of manual sampling,
the hourly increment for the 24-hour composite was made up of
equal portions of the sample taken at 7.5 minutes after the hour
and the sample taken at 22.5 minutes after the hour. Each incre-
mental sample taken was stored in a plastic bag and sealed with
ties to minimize moisture loss. To make the composite sample,
equal quantities from each incremental sample were riffled
together, forming a composite sample. Portions of the compos-
ite were then stored in mason jars, one of which was submitted
for analysis. The coal handler was instructed when to begin
and end the manual test period, thus ensuring continuous
sampling even when the manual testing took longer than the
planned time frame.
B-7
-------
APPENDIX C
FLUE GAS FLOW COMPARISONS
DEMONSTRATION OF WELLMAN-LORD/ALLIED
CHEMICAL FGD TECHNOLOGY:
Flue Gas Flow Comparisons
by
R. D. Adams and S. W. Mulligan
TRW, Inc.
Environmental Engineering Division
800 Follin Lane, S.E.
Vienna, Virginia 22180
Contract No. 68-02-1877
EPA Project Officer: Wade H. Ponder
Prepared for
Utilities and Industrial Power Division
Industrial Environmental Research Laboratory
U. S. Environmental Protection Agency
Research Triangle Park, N. C. 27711
C-l
-------
SECTION 1
SUMMARY AND CONCLUSIONS
A limited series of flue gas measurements were made with the FGD plant
completely isolated from the boiler. The objective was to compare present
day flue gas rates with those obtained during the Baseline Test. These
data would be of help in confirming that the flows during the Acceptance
Test were providing a fair test of the performance of the FGD unit.
Test results are summarized as follows:
(a) At a gross load on the boiler of 92 MW, the flue
gas flow was 400 MCFM compared with an average of
369 MCFM during the Baseline Test in 1974, an
increase of about 7% after correcting for load
differences. The increase seems to be largely
due to an increase in heat input to the boiler,
which was 12% higher than during the Baseline
Test, and the corresponding increase in fuel
rate.
(b) At a gross load of 81 MW, which is the megawatt
equivalent of total main steam produced by the
boiler during the design load phase of the
Acceptance Test, the measured values averaged
399 MCFM which was virtually the same as the flue
gas volume measured at 92 MUG. However, flows cal-
culated from fuel composition and rate and excess
air levels correlated fairly well with load. Using
calculated values, flow rates during the Acceptance
Test were slightly higher but within 5% of the Base-
line Test measurements.
(c) It is concluded from these results that actual
flow rates during the Acceptance Test were higher
C-2
-------
than the 320 MCFM and 388 MCFM specified for the
performance runs and also were not less than the
flue gas volumes experienced during the Baseline
Test.
(d) The data collected to determine boiler heat input
during these flow tests and during the Acceptance
Test suggest a loss of boiler efficiency since
the baseline testing in 1974. Increased flue gas
flows would be one result of a decrease in efficien-
cy. The combined data of the flow tests and the
Acceptance Test show that heat input is about 7%
higher than during the Baseline Test.
(e) Based on samples of ash collected from the pre-
cipitator hoppers, heat losses due to unburned
carbon were found to be less than 0.5% of the
total heat input.
C-3
-------
SECTION 2
TEST RATIONALE
The flow measurements were made to compare present flue gas flow rates
with the baseline flue gas flow rates. Oust prior to the Acceptance Test, it
was found that the apparent flue gas rates at 92 MW (FGD design load) were
much higher than expected. As a consequence, it was necessary to test FGD per-
formance during the Acceptance Test at the design flue gas rate of 320,000
acfm rather than at 92 MW load. The resulting gross load was only 72 MW.
Adding the steam consumed by the FGD plant to the steam equivalent of 72 MW,
the load equivalent of the total steam produced by the boiler was 81 MW or
only 88% of the design load. Furthermore, during the Acceptance Test, it was
necessary to rely on flow estimates derived from the speed and fan curves of
the booster fan. This was necessary because of an apparent bias error in the
flow measurements which was a result of limited lengths of straight duct avail-
able for measurement. These uncertainties have brought into question whether
or not enough gas was being treated during the Acceptance Test to provide a
fair test of the performance of the FGD process.
The testing described in this report was designed to determine if at
a given load the flue gas flow rates of the Baseline Test could be repeated.
This was accomplished by completely isolating the FGD plant from the boiler
and then making the flow measurements at the location used for baseline
testing. At the same time, coal rates and compositions, steam and feed water
rates, and other pertinent boiler operating data were collected with the
assistance of NIPSCO's Results Department personnel. The Results Department
also collected data for a boiler heat balance and for air heater inleakage
tests but these results are not a part of this report. Fly ash samples were
also collected to determine the amount of unburned carbon present.
C-4
-------
SECTION 3
RESULTS AND DISCUSSION
RESULTS AT 92 MEGAWATTS GROSS
Flue gas flow measurements were made at two levels of load; about 92 MW
(FGD design load) and about 81 MW. The latter load represents the Acceptance
Test design load operating condition. At 91.3 MW gross, the flue gas rate
was 400 MCFM. (All flue gas rates in this report are corrected to 300°F and
29.92" Hg absolute pressure.) For six tests during the Baseline Test, the
flue gas rate varied from 297 MCFM to 411 MCFM at an average load of 90.0 MWG.
Of this data, the measurements made in conjunction with ASME particulate
matter sampling were more consistent and varied from 357 MCFM to 385 MCFM for
an average value of 369 MCFM. The present operating condition at a nominal
92 MWG compared with the ba'seline condition are summarized in Table 1:
TABLE 1. PRESENT OPERATING CONDITIONS VS. BASELINE AT 92 MW GROSS
Average of Six
Baseline Tests Present Condition Percent
(1974) (10/5/77) Diff.
Flue Gas Rate, MCFM
(300°F, 29.92 in. Hg) 369 400 +8.4
Gross Load, MW 90.0 91.3 +1.4
Coal Rate, Ib/hr. 81,000 96,800 +19.5
Boiler Heat Input,
MM Btu/hr. 908 1016 +11.9
The data of Table 1 show that more fuel is being consumed now than during the
Baseline Test. 'It is apparent that flue gas volumes would have to increase
with the fuel rates. How much increase is dependent on the combustible com-
ponent and water contents of the coal and on the amount of excess air. The
C-5
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Baseline Test flue gas rates have been calculated from the measured coal
compositions and excess air levels and plotted on Figure 1. For 91.3 MMG,
the baseline flue gas rate is calculated to be 350 MCFM compared to a
calculated rate of 412 MCFM at 91.3 MWG during the recent flow tests. The
corresponding measured values agree within 10% of these calculated flue gas
rates.
RESULTS AT 81 MEGAWATTS GROSS
Flows were also measured at about 81 MW which was the operating level
for performance testing at the design rate of the FGD plant. The average of
two flow measurements at 81.8 MWG was 399 MCFM, or virtually the same as the
flow measured at 91.3 MWG. Obviously, there should be a decrease in flue gas.
rate with decreasing load. However, we were attempting to measure flows at
two levels which varied by only about ten percent and a measurement error
band of +_ 10% is to be expected for the method used. Table 2 compares the
operating conditions at the two load levels.
TABLE 2. PRESENT OPERATING CONDITIONS AT TWO LOAD LEVELS
Gross Load, MW
Flue Gas Rate, MCFM
Coal Rate, Ib/hr.
Boiler Heat Input,
MM Btu/hr.
Baseline Test
Compari son
91.3
400
96,800
1016
12-Day Acceptance Percent
Test Comparison Diff.
81.8 -10.4
399 <1.0
87,900 -9.2
898 -11.6
Better correlation at varying operating levels is obtained with calculated
flue gas flows, see Figure 2. Both measured and calculated flue gas rates are
plotted as functions of the measured heat input to the boiler. These correla-
tions show that present flue gas rates are not substantially greater than the
Baseline Test results but that all flue gas volumes, including the baseline
results, are substantially above the 320 MCFM and 388 MCFM specified for the
Acceptance Test. For example, the average boiler heat input during the
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FIGURE 1. BASELINE TEST FLUE GAS FLOWS - CALCULATED
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FIGURE 2. FLUE GAS FLOW VERSUS BOILER HEAT INPUT
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Acceptance Test at design load was 885 MM Btu/hour. At this boiler heat input,
baseline flue gas flow rate was 365 MCFI1 and present flow rates are slightly
higher but within 5% of the baseline value.
BOILER PERFORMANCE
The higher than expected flue gas rates are due in part to a higher than
expected input heat requirement for the level of megawatts generated. The
gross megawatts as a function of heat input are shown on Figure 3. On the
average, the combined flow test and Acceptance Test heat input data are about
7% higher than the boiler heat inputs encountered in 1974 during the baseline
testing.
HEAT LOSSES DUE TO UNBURNED CARBON
To determine if there was a significant loss of heating value due to un-
burned fuel, two samples of ash were collected from the precipitator hopper
and analyzed for combustible content. Loss on ignition was 1.4% and 2.9% of
the ash for the two ash samples. Assuming that the corresponding combustible
content is carbon, the associated heat loss would be less than 0.5% of the
total heat input.
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FIGURE 3. MEGAWATTS GENERATED VERSUS BOILER HEAT INPUT
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-014a
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Demonstration of Wellman-Lord/Allied Chemical FGD
Technology: Acceptance Test Results
. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
R.C. Adams, S.J.Lutz, and S.W. Mulligan
B. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
201 North Roxboro Street, Suite 200
Durham, North Carolina 27701
10. PROGRAM ELEMENT NO.
E HE 62 4 A
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 ,
Phase; 8-9/77
T AND PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES
project officer is Charles J. Chatlynne, Mail Drop 61,
919/541-2915. EPA-600/7-77-014 is an earlier report in this series.
i6. ABSTRAciThe report gives results of acceptance tests of Wellman-Lord/Allied Chem-
ical flue gas desulfurization (FGD) technology. Process performance guarantees
were met or exceeded. During the 12-day Design Load test, the plant was operated
at the design condition of a boiler flue gas output rate equivalent to 80% of the maxi-
mum boiler load of 115 MW gross. During the 83-hour High Load test, the plant
treated flue gas volumes equivalent to 95% of maximum boiler load. SO2 removal of
90% or better was achieved. Particulate emissions did not exceed 0.1 Ib/million Btu
of boiler heat input. The consumption of steam, natural gas, and electrical power
was less than the performance guarantee requirements at Design Load conditions.
Soda ash consumption was less than the limit set by the performance guarantees.
Finally, sulfur product purity was greater than 99. 5%.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Dust
Sodium Carbonates
Air Pollution Control
Stationary Sources
Particulate
Wellman Lord
Allied Chemical
13B
21B
07A,07D
11G
07B
19. SECURITY CLASS (ThisReport)
Unclassified
18. DISTRIBUTION STATEMENT
Unlimited
21. NO. OF PAGES
129
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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