United States
Environmental Protection
Agency
Office Of Industrial Environmental Research EPA-600/7-77-014
Reseach and Laboratory
Development Research Triangle Park, North Carolina 27711 February 1977
DEMONSTRATION OF
WELLMAN-LORD/ALLIED
CHEMICAL FGD TECHNOLOGY
Boiler Operating
Characteristics
Interagency
Energy-Environment
Research and Development
Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of,Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
These seven broad categories were established to facilitate further
development and application of environmental technology. Elimination
of traditional grouping was consciously planned to foster technology
transfer and a maximum interface in related fields. The seven 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
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 systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses 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 environmental issues.
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 recommen-
dation for use.
This document is available to the public through the National Technical
Information Service, Springfield, Virginia 22161.
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EPA-600/7-77-014
February 1977
DEMONSTRATION OF
WELLMAN-LORD/ALLIED CHEMICAL
FGD TECHNOLOGY:
BOILER OPERATING CHARACTERISTICS
by
R.C. Adams, T.E. Eggleston, J.L. Haslbeck,
R. C. Jordan, and Ellen Pulaski
TRW, Inc.
800 Follin Lane, SE
Vienna, Virginia 22180
Contracts No. 68-02-0235 and -1877
Program Element No. EHE624A
EPA Project Officer: Wade H. Ponder
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
-------
Approval of this report, by EPA, does not signify
that the contents necessarily reflect the views
and policies of the Environmental Protection
Agency, nor does mention of trade names or commer-
cial products constitute endorsement or recommen-
dation for use.
m
-------
EXECUTIVE SUMMARY
The Environmental Protection Agency (EPA) is actively engaged in an
extensive program of technology development in the area of flue gas desul-
furization (FGD). A major element of this program is the demonstration of
candidate FGD processes which are nearing commercial applicability. These
demonstration projects comprise operation of an FGD unit of such size and
for such duration as to permit valid determinations of the technical and
economic practicality of the process for potential industrial users. Among
the candidate processes selected for demonstration is the Wellman-Lord/
Allied Process, a regenerable process based on the removal of sulfur diox-
ide from flue gases by a sodium sulfite scrubbing solution and on the sub-
sequent recovery and reduction of the sulfur dioxide to elemental sulfur.
The Wellman-Lord/Allied demonstration unit has been installed at Northern
Indiana Public Service Company's (NIPSCO) D.H. Mitchell Power Station and
is designed to treat the total flue gas from NIPSCO's 115MW coal-fired
Boiler No. 11. This report presents the results of the Baseline Test, an
intensive examination and characterization of Boiler No. II conducted prior
to installation of the Wellman-Lord/Allied FGD Unit.
TEST OBJECTIVES AND SCOPE
Demonstration goals include an evaluation showing that the Wellman-
Lord/Allied Process has widespread applicability among the total population
of utility boilers. Effects, if any, on boiler operation from retrofit of
the FGD unit must also be determined. Based on these goals, the major ob-
jectives of the Baseline Test were:
1. A detailed profile of Boiler No. 11 as a base-
line for comparison with other boiler design
and operating conditions.
iv
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2. A detailed profile of Boiler No. 11 as a base-
line for comparing operating performance before
and after retrofit of the FGD unit.
3. Baseline operation of Boiler No. 11 at operating
conditions other than normal which have the poten-
tial for affecting the performance of the FGD
demonstration unit.
The test program initiated for the attainment of these objectives focused
on the following three major test categories:
1. Boiler operating performance was examined with
emphasis on its economic performance and on its
overall energy balance. Included also were
evaluations of the performance of the major
auxiliaries such as coal pulverizers, air pre-
heaters, and the electrostatic precipitator.
2. The properties of the flue gas at the proposed
boiler/FGD unit interface were characterized at
both normal and off-normal operating conditions
of the boiler. Off-normal operation included
operation with a low sulfur coal, with higher
than normal combustion air, with higher than
normal air inleakage to the flue gas simulated,
and with higher than normal flue gas grain
loadings.
3. Relationships were established between boiler
control settings and the dependent flue gas
properties.
BASELINE BOILER PERFORMANCE
Economic Performance
Steam side pressures and temperatures were in fairly good agreement
with design values, indicating that the boiler was being operated close to
-------
che design control settings. The fuel burned was essentially the same as
-he design fuel employed for the boiler acceptance tests. Despite this,
boiler efficiency calculated by the heat loss method was 1% to 3% less
than the manufacturer's efficiency rating. Heat rates were thus corre-
spondingly higher than the design heat rates. Below 92MW, differences
between actual and design efficiencies increased with a decrease in load.
The major loss affecting efficiency and heat rate was the heat exhausted
to the stack due to higher than design dry flue gas volumes.
The overall energy balance of the boiler, in percent of input ener-
gy, was as follows:
Boiler Losses 15.1-20.7
Auxiliaries Energy Consumption 1.9- 2.5
Net Output 28.3-32.2
Turbine and generator losses and heat rejection to the turbine condenser
make up the remainder of the energy balance. The net output is that per-
centage of total input energy as electrical energy available for distribu-
tion. During baseline testing, net output was below design as a result of
higher than design boiler losses. Auxiliary energy consumption was not
excessive compared to design.
Energy available from the steam averaged 3.9% higher than the aver-
age design energy requirements. The WeiIman-Lord/Allied FGD Unit will
consume about 8% of the boiler main steam output, thus derating the boiler.
Performance of Auxiliaries
Particle size of the pulverized coal was within design specifica-
tions. However, maintenance requirements on the coal mills were rather
severe during the test period. Operation with one or more mills out of
service was required during several tests. Capacity of the mills seemed
vi
-------
to be sufficient to handle loads up to 92MW (80% of full load) during
periods of limited equipment availability.
The air heaters were washed just prior to the start of the field
test work. Heat recovery was from 9.9% to 17.2% of the total heat input
to the boiler, with recoveries substantially higher at minimum load. The
higher excess air requirements at a low load factor seems to improve the
heat recovery performance.
Particulate collection efficiencies of the electrostatic precipi-
tator at 92MW and 115MW (full load) were substantially below a design
efficiency of 98.5%. At 46MW, design collection efficiencies were
achieved.
BASELINE FLUE GAS CHARACTERIZATION
Tests were conducted to obtain a physical-chemical profile of the
flue gas at normal operating conditions and at selected off-normal opera-
ting conditions. Much of the data collected was for documentation of
baseline conditions for later comparison during operation with the retro-
fitted FGD unit. Measurements were also made to compare the flue gas
parameters with the corresponding design parameters of the Wellman-Lord/
Allied Unit, the boiler, and with a typical regulatory performance standard.
Potential Effect on FGD Unit
Flue gas properties having the potential to affect the performance
of the FGD unit were determined. The test results are summarized as fol-
lows:
• Higher than design flue gas rates were found to
have a dilution effect on S02 concentration whi
might adversely affect absorber efficiency.
vi 1
-------
t S02 concentrations at 92MW were higher than design
despite dilution effects. This should not affect
absorber performance but there would be an in-
creased demand on the S02 recovery and reduction
units.
t Rates and concentrations of oxygen and SO^ were
higher than design. Sulfate purge rates are a
function of oxidation rates due to the oxygen
levels in the flue gas and a function of the SO^
levels in the flue gas.
t Particulate emission rates and grain loadings were
significantly higher than specified for the Wellman-
Lord/ Allied design, primarily as a result of low
dust collector efficiencies. Higher than design
grain loadings at the inlet of the absorber might
be expected at these conditions. Additionally,
higher grain loadings will result in an increase
in the fly ash purge rates.
t Fluoride and chloride were found in the flue gas.
Concentration of the chloride by recirculation of
the fly ash collection stream or in the absorber
recirculating stream could present corrosion
problems.
Effect of Off-Normal Operation
Special tests were conducted at selected off-normal operating con-
ditions. The tests will be repeated after retrofit of the FGD unit to
observe these effects:
• High grain loading - to simulate effect of grain
loading on Demonstration Unit performance.
• Excess of air inleakage - to maximize flue gas
volume.
viii
-------
• Low sulfur coal - to examine effect of a low
concentration of SC^ in the flue gas.
The effects of high grain loadings, flue gas volumes, and low SCL concen-
trations were observed. An attempt to maximize NOx formation by increasing
the combustion air was not successful.
DEPENDENCY ON BOILER CONTROL SETTINGS
During testing at normal operation, the only independent variables
which were varied which might change the flue gas profile were load and
soot blowing. Major effects on flue gas volume and concentration of the
flue gas components occurred from variations in the excess air, which is
load dependent. Thus, emission rates of S02> NOx, and fly ash increased
with load whereas concentrations of these components were dependent on the
amount of excess air, assuming a linear variation in flue gas volume with
load. Concentrations of S02 and particulate matter and the ratio of S02
to 02 increased with load due to lower volume as a result of decreasing
amounts of excess air with increasing load. Particle emissions showed more
dependence on load than would have occurred with the electrostatic precip-
itator performing at design efficiency. Flue gas volume at actual temper-
ature and pressure was also dependent on load due to an increase in temper-
ature with load.
Particulate rates at the inlet to the air heaters (upstream of the
electrostatic precipitator) were noticeably higher during soot blowing.
These comparisons were made at 92MW. However, no effect from soot blowing
was apparent on the downstream side of the electrostatic precipitator.
Composition of the coal is another boiler control setting affecting
the flue gas profile. However, there were no noticeable effects on the
flue gas on a dry basis from variations in coal composition. Moisture in
the coal varied more than any other component of the coal and this would
have a volume effect. However, since the volume effect due to excess air
was much greater, the effect of coal moisture was not the controlling
variable affecting flue gas volume.
IX
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TABLE OF CONTENTS
EXECUTIVE SUMMARY .......................... iv
.1ST OF FIGURES ........................... xii
LIST OF TABLES ........................... xv
METRIC EQUIVALENTS ......................... xix
ACKNOWLEDGEMENTS .......................... xx
1.0 INTRODUCTION .......................... 1-1
1.1 Background ........................ 1-1
1.2 Report Synopsis ...................... 1-3
2.0 TEST SUMMARY .......................... 2-1
2.1 Baseline Test Objectives ................. 2-1
2.2 Baseline Boiler Performance ................ 2-3
2.3 Baseline Flue Gas Characterization ............ 2-5
3.0 DISCUSSION OF RESULTS ..................... 3-1
3.1 Efficiency and Heat Rates ................. 3-1
3.2 Flue Gas Characterization - Normal Operation ....... 3-33
3.3 Flue Gas Characterization - Off Normal Operation ..... 3-72
3.4 Precipitator Performance ................. 3-75
3.5 Cyclical and Trend Effects ................ 3-80
3.6 Flue Gas Characterization - Low Sulfur Coal ........ 3-97
4.0 TEST PROBLEMS .......................... 4-1
4.1 Operating Problems .................... 4-2
4.2 Adverse Weather Problems ................. 4- 4
4.3 Data Collection and Reduction Problems .......... 4-4
5.0 RECOMMENDATIONS ........................ 5_ -,
5.1 Scope ........................... 5_ !
5.2 Test Techniques and Methodology .............. 5_ 2
5.3 Test with High Sulfur Coal ................ 5_ 3
-------
TABLE OF CONTENTS (CONTINUED)
Page
5.4 Calibration of Steam and Feedwater Meters 5-3
5.5 Introduction of Off Normal Excess Combustion Air 5-3
5.6 Data Reduction 5-3
6.0 REFERENCES 6-1
APPENDIX A - BOILER DESCRIPTION A- 1
APPENDIX B - BASELINE DATA BASE B- 1
APPENDIX C - TEST METHODS C- I
APPENDIX D - FIELD TEST LOGS D- 1
APPENDIX E - GLOSSARY OF TERMS E- 1
-------
LIST OF FIGURES
Figure 3- 1
Figure 3- 2
Figure 3- 3
Figure 3- 4
Figure 3- 5
Figure 3- 6
Figure 3- 7
Figure 3- 8
Figure 3- 9
Figure 3-10
Figure 3-11
Figure 3-12
Figure 3-13
Figure 3-14
Figure 3-15
Figure 3-16
Figure 3-17
Figure 3-18
Figure 3-19
Figure 3-20
Figure 3-21
Figure 3-22
Pa^e
Boiler Efficiency vs. Gross Load, 3% Sulfur 3- 4
Tests - Test Series 1 & 3
Heat Rate vs. Gross Load, 3% Sulfur Tests - 3-7
Test Series 1 & 3
Feedwater Rate vs. Gross Load - Test Series 1 & 3 3-13
Fuel Distribution to Burners - Test No. 1 3-21
Fuel Distribution to Burners - Test No. 16, 17 3-22
Fuel Distribution to Burners - Test No. 2, 3, 4, 3-23
5, 6, 7
Fuel Distribution to Burners - Test No. 8, 9, 10, 3-24
11, 12, 13, 14, 15, 18, 19, 20, 21
% Reduction vs. % Moisture Content in Raw Coal - 3-25
Test Series 1, 2 & 3
Amps as a Function of Coal Feed Rate - Test Series 3-27
1 & 3
% 0? Inlet Air Heater vs. Gross Load - Test Series 3-28
1 & 3
Excess Air Contribution to Total Heat Loss vs. Air/ 3-30
Coal Ratio - Test Series 1 & 3
Inlet (Theoretical & Measured) Mass Rate vs. Gross 3-39
Load - Test Series 1
Inlet & Outlet Flue Gas Volume Flow Rate vs. Gross 3-40
Load - Test Series 1
S02 Emissions (Theoretical & Measured) vs. Gross 3-49
Load - Test Series 1
Measured S02 Emissions vs. Heat Input - Test Series 3-52
S02/02 vs. Gross Load - Test Series 1 3-54
Particulate Emissions (Lb/Hr) Inlet APH vs. Gross 3-59
Load - Test Series 1 & 3
Particulate Emissions (Lb/Hr) Outlet ID Fan vs. 3-60
Gross Load - Test Series 1 & 3
Particulate Emissions (Gr/Scf) Outlet ID Fan vs. 3-61
Gross Load - Test Series 1 & 3
Collector Efficiency (%) vs. Useful Corona Power 1-7R
(watts/1000 cfm) - Test Series 1, 2 & 3
Migration Velocity vs. $03 Concentration - Test 1 7Q
Series 1, 2, & 3
High Heating Value of Raw Coal (MMBTU/LB) on a Dry, 3-84
Ash Free Basis
xi i
-------
LIST OF FIGURES (Continued)
Figure 3-23
Figure 3-24
Figure 3-25
Figure 3-26
Figure 3-27
Figure 3-28
Figure 3-29
Figure 3-30
Figure 3-31
Figure 3-32
Figure A- 1
Figure A- 2
Figure A- 3
Figure A- 4
Figure A- 5
Figure B- 1
Figure B- 2
Figure B- 3
Figure B- 4
Figure B- 5
Figure B- 6
Figure B- 7
Figure B- 8
Page
Weight Percent Sulfur in Raw Coal on a Dry, Ash 3-85
Free Basis
Weight Percent Carbon in Raw Coal on a Dry, Ash 3-86
Free Basis
Weight Percent Hydrogen in Raw Coal on a Dry, Ash 3-87
Free Basis
Weight Percent Oxygen in Raw Coal on a Dry, Ash 3-88
Free Basis
Weight Percent Ash in Raw Coal on a Dry Basis 3-89
Weight Percent Water in Raw Coal on an Ash Free 3-90
Basis
Gross Heat Rate (MBTU/KWH) 3-92
Air Heater Temperatures (°F) 3-93
Useful Corona Power (Watts/1000 CFM) 3-95
Inlet Air Temperature (°F) - Humidity (LB/MLB 3-96
Air)
Mitchell No. 11 Boiler A- 4
Fuel Distribution to Burners A-11
Oxygen vs. Load Ramp A-15
Northern Indiana Public Service Company - Mitchell A-17
Station - Unit No. 11, Gary, Indiana, B&W Contract
No. RB-456
Soot Blowers A-18
Particle Diameter vs. Cumulative Percent Less B-58
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-59
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-60
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-61
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-62
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-63
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-64
Than Stated Size
Particle Diameter vs. Cumulative Percent Less B-65
Than Stated Size
xi ii
-------
LIST OF FIGURES (Continued)
Figure B- 9
Figure B-10
Figure B-ll
Figure B-12
Figure B-13
Figure B-14
Figure B-15
Figure B-16
Figure C- 1
Particle Diameter
Than Stated Size
Particle Diameter
Than Stated Size
Particle Diameter
Than Stated Size
Particle Diameter
Than Stated Size
Particle Diameter
Than Stated Size
Fuel Distribution
Fuel Distribution
34
Fuel Distribution
29, 30, 33, 35
Modified EPA Sampling Train
vs. Cumulative Percent Less
vs. Cumulative Percent Less
vs. Cumulative Percent Less
vs. Cumulative Percent Less
vs. Cumulative Percent Less
to Burners - Test No. 31
to Burners - Test No. 28, 32,
to Burners - Test No. 24, 25,
j>age
B-66
B-67
B-68
B-69
B-70
B-71
B-72
B-73
C- 5
xiv
-------
LIST OF TABLES
Page
Table 3- 1 Boiler Efficiencies and Heat Rates - Normal 3- 3
Operating Conditions
Table 3- 2 Energy Distribution Design Values 3- 8
Table 3- 3 Energy Distribution - Normal Operating Con- 3-10
ditions
Table 3- 4 Summary of Coal Quality and Variability - As 3-17
Fired Coal - Test Series 1, 2 & 3
Table 3- 5 Summary of Coal Quality and Variability - Raw 3-18
Coal Sample - Test Series 1, 2 & 3
Table 3- 6 Draft Losses at 100% Load, in. W.C. - Normal 3-32
Operating Conditions
Table 3- 7 Flue Gas Characterization Summary - Normal 3-35
Operating Conditions
Table 3- 8 Particle Size Data - Normal Conditions 3-36
Table 3- 9 Particle Size Data - Off-Normal Conditions 3-37
Table 3-10 Theoretical Boiler Operating Parameters For 3-38
Calculating Flue Gas Rates
Table 3-11 HgSO/j. Condensation Effect - Normal Operating 3-43
Conditions
Table 3-12 H2S04 Condensation Effect - Off Normal Opera- 3-44
ting Conditions
Table 3-13 Sulfur Mass Balance, LB/HR 3-46
Table 3-14 Sulfur Balance Effects 3-47
Table 3-15 Rationale for Trace Element Selection 3-65
Table 3-16 Trace Metals Concentration Effect - Test Series 1 3-67
Table 3-17 Trace Metals Concentration in Coal, PPM 3-68
Table 3-18 Trace Metals Concentration in the Flue Gas, PPM 3-69
Table 3-19 Precipitator Specifications 3-76
Table 3-20 Field Test Schedule - Normal Fuel (3% Sulfur) 3-81
Table 3-21 Field Test Schedule - Low Sulfur Fuel (1% 3-82
Sulfur)
Table 3-22 Flue Gas Characterization Summary - Off Normal 3-98
Operating Conditions (Low Sulfur Coal)
Table 3-23 Particle Size Data - Off Normal Conditions (Low 3-104
Sulfur Coal)
Table A- 1 Mitchell No. 11 Nominal Values A- 3
Table A- 2 Coal Used at NIPSCO Mitchell No. 11, December A- 7
13/15, 1972
Table A- 3 Pulverized Coal Equipment Data A-10
xv
-------
LIST OF TABLES (Continued)
Table A- 4
Table A- 5
Table A- 6
Table B- 1
Table B- 2
Table B- 3
Table B- 4
Table B- 5
Table B- 6
Table B- 7
Table B- 8
Table B- 9
Table B-10
Table B-ll
Table B-12
Table B-13
Table B-14
Table B-15
Table B-16
Table B-17
Table B-18
Table B-19
Table B-20
Table B-21
Fans and Pumps Information
Regenerative Air Heater (Design Conditions)
Mitchell No. 11 Precipitator Specifications
Heat Balance (MMBTU/HR) - Normal Operating Con-
ditions
Auxiliary Amperages - Normal Operating Conditions
Auxiliary Amperages - Off Normal Operating Con-
ditions
Load Sensitive Pressure and Temperature Values -
Normal Operating Conditions
Coal Quality - Raw Coal - Normal Operating Condi-
tions
Coal Quality - As Fired Coal - Normal Operating
Conditions
Coal Quality - Raw Coal - Off Normal Condi tons
Coal Quality - As Fired Coal - Off Normal Oper-
ating Conditions
Coal Quality Data - Composites of 3% Sulfur Tests -
Normal Operation
Coal Quality Data - Composites of 3% Sulfur Tests -
Off Normal Operation
Pulverizer Performance - Normal Operating Conditions
Pulverizer Performance - Off Normal Operating Con-
ditions
Air Heater Performance - Normal Operating Conditions
Draft Losses (in. W.C.) - Normal Operating Condi-
tions
Draft Losses (in. W.C.) - Off Normal Conditions
Draft Losses (in. W.C.) - Off Normal Conditions -
(Low Sulfur Coal)
Measured and Calculated Flue Gas Rates - Normal
Operating Conditions
Measured and Calculated Flue Gas Rates - Off Normal
Operating Conditions (Low Sulfur Coal)
Flue Gas Pressure, Volume, and Temperature Data -
Normal Operating Conditions
Sulfur Oxides, Emission Rates and Concentrations -
Normal Operating Conditions
Sulfur Oxides, Emission Rates and Concentrations -
Off Normal Operating Conditions
Page,
A-12
A-21
A-22
B- 2
B- 3
B- 4
B- 5
B- 6
B- 7
B- 8
B- 9
B-10
B-ll
B-12
B-13
B-14
B-15
B-16
B-17
B-18
B-19
B-20
B-21
B-22
xvi
-------
LIST OF TABLES (Continued)
Page
Table B-22 Particulate Emission Rates and Concentrations - B-23
Normal Operating Conditions
Table B-23 Trace Metals in Outlet Flue Gas Particulate - B-24
ppm Dry Weight Basis - Normal Operation
Table B-24 Trace Metals in Outlet Flue Gas Particulate - B-25
ppm Dry Weight Basis - Off Normal Operation
Table B-25 Trace Elements in As Fired Coal - ppm Dry Weight B-26
Basis - Normal Operation
Table B-26 Trace Elements in As Fired Coal - ppm Dry Weight B-27
Basis - Off Normal Operation
Table B-27 Trace Elements in Raw Coal Composites - ppm Dry B-28
Weight Basis - 3% Sulfur
Table B-28 Trace Elements in Raw Coal Composites - ppm Dry B-29
Weight Basis - 3% Sulfur
Table B-29 Flue Gas Characterization Summary - Off Normal B-30
Operating Conditions
Table B-30 Particulate Emission Rates and Concentrations - B-31
Off Normal Operating Conditions
Table B-31 Flue Gas, Pressure, Volume and Temperature Data - B-32
Off Normal Operating Conditions
Table B-32 Electrostatic Precipitator Performance - Normal B-33
Operating Conditions
Table B-33 Electrostatic Precipitator Performance - Off B-34
Normal Operating Conditions
Table B-34 Measured and Calculated Flue Gas Rates - Off Normal B-35
Operating Conditions (Low Sulfur Coal)
Table B-35 Flue Gas Pressure, Volume and Temperature Data - B-36
Off Normal Operating Conditions (Low Sulfur Coal)
Table B-36 Sulfur Oxides, Emission Rates and Concentrations - B-37
Off Normal Operating Conditions
Table B-37 Particulate Emissions, Rates and Concentrations - B-38
Off Normal Operating Conditions (Low Sulfur Coal)
Table B-38 Electrostatic Precipitator Performance - Off Normal B-39
Operating Conditions (Low Sulfur Coal)
Table B-39 Trace Elements in As Fired Coal - ppm Dry Weight B-40
Basis - Off Normal Operation (Low Sulfur Coal)
Table B-40 Trace Metals in Outlet Flue Gas Particulate, ppm B-41
Dry Weight Basis - Off Normal Operation (Low Sulfur
Coal)
Table B-41 Trace Elements in Raw Coal Composites - Low Sulfur B-42
Tests
xvn
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LIST OF TABLES (Continued)
Page
Table B-42 Boiler Efficiencies and Heat Rates - Off Normal B-43
Operating Conditions
Table B-43 Heat Balance (MMBTU/HR) - Off Normal Operating B-44
Conditions
Table B-44 Energy Distribution - Off Normal Operating Condi- B-45
tions
Table B-45 Load Sensitive Pressure and Temperature Values - B-46
Off Normal Operating Conditions
Table B-46 Air Heater Performance - Off Normal Operating Con- B-47
ditions
Table B-47 Boiler Efficiencies and Heat Rates - Off Normal B-48
Operating Conditions (Low Sulfur Coal)
Table B-48 Heat Balance (MMBTU/HR) - Off Normal Operating B-49
Conditions (Low Sulfur Coal)
Table B-49 Energy Distribution - Off Normal Operating Condi- B-50
tions (Low Sulfur Coal)
Table B-50 Auxiliary Amperages - Off Normal Operating Condi- B-51
tions (Low Sulfur Coal)
Table B-51 Load Sensitive Pressure and Temperature Values - B-52
Off Normal Operating Conditions (Low Sulfur Coal)
Table B-52 Coal Quality, As Fired Coal - Off Normal Operating B-53
Conditions (Low Sulfur Coal)
Table B-53 Coal Quality, Raw Coal - Off Normal Operating Con- B-54
ditions (Low Sulfur Coal)
Table B-54 Coal Quality Data - Composites of 1% Sulfur Tests - B-55
Off Normal Operation (Low Sulfur Coal)
Table B-55 Pulverizer Performance - Off Normal Operating Con- B-56
ditions (Low Sulfur Coal)
Table B-56 Air Heater Performance - Off Normal Operating Con- B-57
ditions (Low Sulfur Coal)
Table C- 1 Flue Gas Sampling Methods C_ 3
Table C- 2 Atomic Absorption Analytical Parameters C-12
xviii
-------
METRIC EQUIVALENTS
To Convert From;
Tons SOx/year
Pounds/square inch (psi)
Cubic feet/minute (cfm)
862 parts per million (ppm by weight)*
Inches mercury (in. Hg)
2. Inches water (in. H,0 at 60°F)
x <-
Grains/standard cubic foot (gr/scf)
Pounds/hour (Ibs/hr.)
BTU/pounds (BTU/lbs.)
BTU/hour (BTU/hr.)
To:
Kilograms SOx/year
2
Kilograms/square centimeter (Kg/cm )
o
Cubic meter/minute (m /min)
o
Micrograms/cubic meter (yg/m by weight)
Millimeters mercury (mm Hg)
Millimeters mercury (mm Hg at 15.6 °C)
o
Grams/normal cubic meter (gm/Nm )
Kilograms/hour (Kg/hr.)
Calories/gram (Cal./gm.)
Kilogram-Calories/hour (Kg-Cal/hr.)
Multiply By:
907
.0703
.0283
2620
25.4005
1.8663
2.288
0.4536
0.556
0.252
*S02 normally reported as ppm by volume.
-------
ACKNOWLEDGEMENTS
The authors wish to express appreciation to Messrs. Mann, McGrath,
Matteizzi, and Thalman of Northern Indiana Public Service Company and mem-
bers of their staff for their assistance in the collection of the field test
data and their cooperation in operating Unit No. II of the D.H. Mitchell
Station at the desired operating conditions for testing.
xx
-------
1.0 INTRODUCTION
1.1 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 de-
fine the commercial practicality of the process for potential industrial
users. Among the candidate processes being evaluated, having the potential
to become a major SOx emission control method, is the WeiIman-Lord/Allied
(WL/Allied) process developed by Davy Powergas (formerly Wellman-Power Gas)
and Allied Chemical. The demonstration unit is being constructed by Davy
Powergas and operated by Allied Chemical under contract to the Northern
Indiana Public Service Company (NIPSCO) and to the Environmental Protection
Agency (EPA). The WL/Ailied process as developed by the two design organi-
zations 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, also the first joint Wellman-Lord/Allied installa-
tion.
Environmental Engineering Division of TRW Inc. , under contract to the
Industrial Environmental Research Laboratory - RTP of the EPA, will provide
the test services required for an in-depth evaluation of the demonstration
unit. The tests will be performed on the NIPSCO boiler No. 11 and on a
retrofitted demonstration unit, located at D.H. Mitchell Power Station, Gary,
Indiana. Unit No. 11 is hereafter referred to as Mitchell No. 11. The Test
and Evaluation (T&E) program consists of three major test phases:
• The Baseline Test
• The Acceptance Test
• The Demonstration Test and Evaluation
This report describes the results of the Baseline Test.
1-1
-------
Preceding tasks of the T&E Program include:
Job No. 1: Preparation of Work Plan Manual (completed)
Job No. 2: Preparation of User Survey/Test Criteria
report (completed)
Job No. 3: Preparation of Baseline Test Plan (completed)
Job No. 4: The Baseline Test. The Baseline Test was
conducted according to the procedures speci-
fied in the Baseline Test Plan
Job No. 5: Preparation of Acceptance Test Plan (com-
pleted)
Job No. 6: Preparation of Demonstration Test Plan
(completed)
1-2
-------
1.2 REPORT SYNOPSIS
The Baseline Test was performed in order to fully characterize the
outlet flue gas of the boiler and to obtain boiler material and energy
balances. The Baseline Test was the first leg of the T&E program, to be
followed by the Acceptance Test and the Demonstration Test and Evaluation.
The Plan of the two latter test programs are reported under separate
covers*1"").
Details of the Baseline Test objectives are discussed in Section 2.0,
along with a summary of the test data. The following parameters were the
major ones treated as independent variables in order to determine their
effect on the outlet flue gas:
1. Boiler load
2. Soot blowing status
3. Coal composition (especially % sulfur in coal)
4. Inleakage and excess air
5. ESP field strength
Sets of tests were typically performed in replicates of three in
order to thoroughly develop the effect of each parametric variation sepa-
rately. Parameters 1, 2 and 3 represent parameters which are ordinarily
varied during normal operations; the extent of their planned alteration
during the Baseline Test was thus determined by examining actual plant
operation. Parameters 4 and 5, which are usually dependent on such in-
dependent variables as boiler load and maintenance cycle, were examined
chiefly because of their effects on grain loading and percent oxygen in the
flue gas.
The test data is then discussed in detail in the next section of
the report (Section 3.0). The problems encountered in conducting the test
are described in Section 4.0. Based on the site-dependent experience gained
during the Baseline Test, recommendations are submitted for initiating im-
provements in the subsequent Acceptance and Demonstration test phases of the
1-3
-------
T&E program (Section 5.0). Following a description of Mitchell No. 11
(Appendix A), complete test results are documented in Appendix B. Test
methods (Appendix C) and the field test logs (Appendix D) are also appended.
Trends and correlations of the various parameters examined are indi-
cated in graphs and tables throughout the report. Properly used, the data
in this report can and has acted as a powerful tool for making T&E design
and operating decisions critical to the program's success.
1-4
-------
2.0 TEST SUMMARY
2.1 BASELINE TEST OBJECTIVES
The Work Plan Manual^ ' lists the three primary objectives of the T&E
program. These are:
1. Verification of the reduction in pollutants achieved by
the WL/Allied process demonstration unit.
2. Validation of the estimated technical and economic per-
formance of the demonstration unit.
3. Assessment of the applicability of the WL/Allied process
to the general population of utility boilers.
Demonstration goals include an evaluation showing that the WL/Allied
Process has widespread application among the total population of utility
boilers (Objective No. 3 above). Effects, if any, on boiler operation from
retrofit of the demonstration desulfurization unit must also be demonstrated.
Based on these goals, the Baseline Test objectives were to:
1. Establish a detailed profile of Mitchell No. 11 as a base-
line for comparison with other boiler design and operating
conditions.
2. Establish a detailed profile of Mitchell No. 11 as a base-
line for comparing operating performance before and after
retrofit.
3. Where possible, under controlled test conditions, vary
Mitchell No. 11 operating variables which have the poten-
tial for affecting the performance of the demonstration
unit.
The technical approach taken in baseline testing of Mitchell No. 11
was as follows:
1. Define the relationship between control settings and opera-
ting conditions for Mitchell No. 11, and flue gas properties
at the demo./steam generator interface.
2-1
-------
2. Characterize existing (baseline) performance of the unit
in terms of emission levels and economics (heat rate).
3. Obtain quantitative baseline data which when combined
with control system demonstration data can be used to
support the establishment of realistic pollution control
performance standards.
4. Obtain site-dependent experience in manual testing and
measurement procedures to be used in the subsequent
Acceptance and one-year Demonstration phases.
5. Obtain quantitative information on the overall oper-
ability and reliability of Mitchell No. 11.
2-2
-------
2.2 BASELINE BOILER PERFORMANCE
2.2.1 Economic Performan ce
Steam side pressures and temperatures were in fairly good agreement
with design values, indicating that the boiler was being operated close to
the design control settings. The fuel burned was essentially the same as
the design fuel employed for the boiler acceptance tests. Despite this,
boiler efficiency calculated by the heat loss method was 1% to 3% less than
the manufacturer's efficiency rating. Heat rates were thus correspondingly
higher than the design heat rates. Below 92MW, differences between actual
and design efficiencies increased with a decrease in load. The major loss
affecting efficiency and heat rate was the heat lost due to dry flue gas
volumes in excess of design.
The overall energy balance of the boiler, in percent of input energy,
was as follows:
Boiler Losses 15.1-20.7
Auxiliaries Energy Consumption 1.9- 2.5
Net Output 28.3-32.2
Heat rejection to the turbine condenser and turbine and generator losses make
up the remainder of the energy balance. The net output is that percentage of
total input energy as electrical energy available for distribution. During
baseline testing, net output was below design as a result of higher than de-
sign boiler losses. Auxiliary energy consumption was not excessive compared
to design.
Energy available from the steam averaged 3.9% higher than the average
design energy requirements. The Demonstration Unit will consume 8% of the
boiler steam output.
2-3
-------
2.2.2 Performance of Auxiliaries
Particle size of the pulverized coal was within design specifications.
However, maintenance requirements on the coal mills were rather severe during
the test period. Operation with one or more mills out of service was required
during several tests. Capacity of the mills seemed to be sufficient to handle
loads up to 92MW (80%) with the limited availability of equipment.
The air heaters were washed just prior to the start of the field test
work. Heat recovery was from 9.9% to 17.2% of the total heat input, with
recoveries substantially higher at minimum load. The higher excess air re-
quirements at a low load factor seems to improve the heat recovery performance.
Particulate collection efficiencies of the electrostatic precipitator
at 92MW and 115MW (full load) were substantially below a design efficiency of
98.5%. At 46MW, design collection efficiencies were achieved.
2-4
-------
2.3 BASELINE FLUE GAS CHARACTERIZATION
Tests were conducted to obtain a physical-chemical profile of the flue
gas at normal operating conditions and at selected off normal operating con-
ditions. Much of the data collected was for documentation of baseline con-
ditions for later comparison during operation with the retrofitted Demonstra-
tion Unit. Flue gas parameters were also measured in order to compare them
with corresponding design parameters of the Demonstration Unit, the boiler,
and with a typical regulatory performance standard.
2.3.1 Potential Effect on Demo. Unit
Test flue gas variables having the potential to affect the performance
of the desulfurization unit are summarized as follows:
• Higher than design flue gas rates were found to have
a dilution effect on SCk concentration which might
adversely affect absorber efficiency.
• S02 concentrations at 92MW were higher than design
despite dilution effects. This should not affect
absorber performance but there would be an increased
demand on the SC^ recovery and reduction units.
• Rates and concentrations of oxygen and SCL were higher
than design. Sulfate purge rates are a function of
the oxygen and the SO- rates.
• Particulate emission rates and grain loadings were sig-
nificantly higher than called for in the Demo. Unit
design, primarily as a result of low dust collector
efficiencies. Higher than design grain loadings inlet
the absorber might be expected at these conditions.
Additionally, higher grain loadings will result in an
increase in the fly ash purge rates.
• Fluoride and chloride were found in the flue gas. Con-
centration of the chloride by recirculation of the fly
2-5
-------
ash collection stream or in the absorber recirculating
stream could present corrosion problems.
2.3.2 Dependency on Boiler Control Settings
During testing at normal operation, the only independent variables
which were varied which might change the flue gas profile were load and soot
blowing. Major effects on flue gas volume and concentration of the flue gas
components occurred from variations in the excess air, which is load dependent.
Thus, emission rates of S02, NOx, and fly ash increased with load whereas con-
centrations of these components were dependent on the amount of excess air,
assuming a linear variation in flue gas volume with load. Concentrations of
S02 and particulate and the ratio of S02 to 02 did increase with load due to
lower volume as a result of decreasing amounts of excess air with increasing
load. Particulate emissions showed more dependence on load than would have
occurred with the electrostatic precipitator performing at design efficiency.
Flue gas volume at actual temperature and pressure were also dependent on load
due to an increase in temperature with load.
Particulate rates at the inlet to the air heaters were noticeably high-
er during soot blowing. These comparisons were made at 92MW. However, no
effect from soot blowing was apparent after the electrostatic precipitator.
Composition of the coal is another boiler control setting affecting the
flue gas profile. However, there were no noticeable effects on the flue gas
from variations in coal composition. Moisture in the coal varied more than
any other component of the coal and this would have a volume effect. However,
since the volume effect due to excess air was much higher, the effect of coal
moisture was not the controlling variable on volume effect.
2.3.3 Effect of Off Normal Operation
Special tests were conducted at selected off normal operating conditions.
These tests will be repeated after retrofit of the Demo. Unit to observe these
effects:
2-6
-------
• High grain loading - to simulate effect of grain
loading on Demo. Unit performance
• Excess of air inleakage - to maximize flue gas
volume
• Low sulfur coal - to examine effect of a low con-
centration of S02 in the flue gas
The effects of high grain loadings, flue gas volumes and low SO^ concentra-
tions were observed. An attempt to maximize NOx formation by increasing
the combustion air was not successful.
2-7
-------
THIS PAGE INTENTIONALLY LEFT BLANK
2-8
-------
3.0 DISCUSSION OF RESULTS
3.1 EFFICIENCY AND HEAT RATES
This section describes the results obtained for evaluating the opera-
ting and economic performance of the boiler/turbine generator combination
(efficiencies and heat rates) as it compares to design performance at three
levels of load. The purposes of the evaluation were:
• To establish a baseline performance profile for later
comparison with performance during the Demonstration.
• To define the relationship between control settings and
operating conditions.
• To provide operating data for comparison with other ex-
isting boiler configurations for which the WL/Allied
process has applicability.
A total of 35 tests were completed. Four series of tests were run as
follows:
Test Series 1 & 3: 14 tests with boiler operating normally.
Test Series 2: 9 special tests with boiler at off normal
operating conditions.
Test Series 5: 12 special tests during which boiler was
burning low sulfur coal (nominal 1% sulfur content).
Test Series 4, special tests during which boiler would burn a high sulfur coal
of four to five percent sulfur content, was cancelled due to inability to pur-
chase a suitable coal. This section will focus on results obtained when the
boiler was operating normally (Test Series 1 & 3). In addition, fuel quality
and its effect on the performance of the coal mills will be discussed for Test
Series 2.
3.1.1 Boiler Efficiency
3.1.1.1 Definitions
Boiler efficiency is determined by two methods:
3-1
-------
1) Heat Loss Method (HLE Method) - ratio; heat input
less measured heat losses to heat input:
Fff - heat input - heat losses
~ heat input
2) Input/Output Method (I/O Method) - ratio; heat absorbed
by water and steam to heat in the fuel:
Fff - heat available
heat input
Of the two methods, use of the HLE method for determining efficiencies usually
results in the higher values. Within the limits of measurement error, results
by the two methods would be identical if all heat losses could be accounted
for. The distribution of losses is discussed in 3.1.1.2 and 3.1.3.
The performance guarantees for Mitchell No. 11 were based on the HLE
method using the Abbreviated Efficiency Test procedure of the ASME Power Test
Code PTC 4.P '. The same procedures were used for the tests reported herein
for both the I/O and the HLE efficiency determinations.
3.1.1.2 Observed Efficiency Vs. Design Efficiency
Relevant data are shown in Table 3-1, Table B-l and on Figure 3-1.
Measured efficiency calculated by the HLE method was less than the
manufacturer's efficiency rating by about 1 to 3 percent, depending on load.
The range of measured efficiency was 84.9% to 88.3% for load factors of 40%
to 100% compared to design values in the range of 88.0% to 88.3%. The ob-
served and design efficiencies are plotted on Figure 3-1 as a function of
load. The HLE efficiency values for Tests 7, 22 and 23 are assumed to be
outliers and are not included in the correlation. Tests 22 and 23 (Test
Series 3) were performed primarily to obtain miscellaneous information about
the flue gas. Due to boiler scheduling problems they were delayed nearly a
full year after the other tests at normal operation. Table B-l shows the
energy from the fuel distributed to the steam and shows the various compo-
nents of loss. The losses for one test at full load (11 BMW) are compared
with the design basis losses as follows:
3-2
-------
TABLE 3-1
BOILER EFFICIENCIES AND HEAT RATES
NORMAL OPERATING CONDITIONS
CO
co
TEST NO.
LOAD, GROSS (HW)
LOAD, NET (MM)
HEAT INPUT, I"MBTU/HR(1'
GROSS HEAT RATE, BTU/KWH
HET HEAT RATE, BTU/KHH
BOILER EFFICIENCY -
- INPUT/OUTPUT EFFICIENCY, %
- HEAT LOSS EFFICIENCY, %
COAL RATE, MLB/HR
EXCESS AIR (INLET APH), %
INLET AIR (FD FAN), °f
'''
'"H - Thousands
1
44.5
40.8
472
10605
11567
84.06
85.09
43.2
80
62
16
45.5
42.2
506
11120
11990
81.72
84.87
43.9
73
61
17
46.2
42.3
511
11060
12079
79.34
85.29
44.2
78
57
2
90.3
84.6
940
10408
11109
83.93
87.04
83.6
43
55
-'
3
89.6
83.7
910
10165
10881
82.49
87,30
81.5
30
53
4
91.2
85.3
940
10313
11 027
81.07
87.18
81.2
29
59
5
89.0
83.4
891
10011
10683
84.12
87.03
79.0
22
55
6
90.9
85.1
910
10016
10699
84.20
86.97
80.5
29
62
7
89.0
83.1
855
9946
10653
84.50
88.25
80.4
29
67
8
114.4
107.7
1141
9970
10591
84.54
87.14
103.8
12
71
9
115.1
108.3
1177
10226
10868
83.01
87.03
104.9
14
74
10
114.9
108.1
1162
10116
10752
83.65
86.65
102.7
19
76
22
111.2
104.3
1114
10022
10685
84.84
85.87
103.2
50
73
23
111.9
104.6
1123
10037
10737
84.92
86.17
103.5
26
71
-------
90
FIGURE 3-1
BOILER EFFICIENCY vs. GROSS LOAD
3% SULPHUR TESTS
TEST SERIES 1&3
GO
I
45.
&a
>-
O
03
8&
86-
84
82
80-
78
76
74
72
70,
• - Design
A - Inlput - Output Efficiency
O - Heiat Loss Efficiency
© - Outliers (Not Included in Correlation)
40
60
70
80 90
GROSS LOAD (MW)
100
110
120
-------
Dry Gas
Coal Moisture and Hydrogen
Moisture in Air
Carbon in Refuse
Radiation
Flue Dust Sensible Heat
NO in Flue Gas
Observed^ ^ '
6.66
4.62
0.71
0.44
0.50
0.03
0.01
Sub Total 12.97
Design^1 ^'
4.48
5.08
0.11
0.30
0.23
10.20
Manufacturer's Margin for
Unaccounted for Losses
Unaccounted for Losses,
from I/O Method
1.50
Total
4.02
16.98
11.70
(1)
(2)
(3)
As percent of heat input.
Test No. 9, 115.1MW Gross Load.
Estimated losses for design basis efficiency of 88.3% at 115MW.
The percent of total heat input unaccounted for, 4.02%, is also the margin of
difference between HLE efficiency and I/O efficiency and explains the higher
results obtained by the HLE method. The HLE method is usually expected to
yield the more accurate results. This is due to a fourfold or greater sig-
nificance of the measurement errors of the I/O method compared to the HLE
method. The magnified errors in the I/O method are the result of error com-
ponents on 80% or more of the heat input versus for the HLE method errors on
only 20% or less of the heat input.
The unaccounted for losses which make up the margin between the effi-
ciencies calculated by the two methods (see Figure 3-1) might consist of the
following:
3-5
-------
• Slowdown losses
• Radiation to ash pit, sensible heat in slag, latent
heat of fusion of slag and unburned carbon in ash pit.
• Heat in pulverizer rejects.
• Unburned CO, hydrogen and hydrocarbons in flue gas.
3.1.2 Heat Rates
3.1.2.1 Definitions
Heat rate is the ratio of the heat input in the coal to the electrical
energy output, and is expressed in units of Btu/KWH. It is the reciprocal of
a corresponding efficiency term. Two heat rates are reported, gross heat
rate and net heat rate, which are determined on gross and net electrical ener-
gy output respectively. The net heat rate describes the economic performance
of the boiler as determined from the utilization of the total input energy.
3.1.2.2 Comparison With Design Heat Rates
Relevant data are included in Table 3-1 and on Figure 3-2.
Higher than design heat rates were observed which correspond with the
lower than design efficiencies measured. Gross and net heat rates are in-
cluded in Table 3-1.
3.1.3 Energy Distribution
3.1.3.1 Definitions
Relevant data are included in Table 3-2.
The performance of the boiler has been described in terms of the boiler
efficiencies and the heat rates. The boiler efficiency is the efficiency for
the conversion of the chemical energy of the coal/air mixture to the heat en-
ergy as represented by an increase in enthalpy of the working fluid when it
3-6
-------
FIGURE 3-2
HEAT RATE vs. GROSS LOAD
3% SULPHUR TESTS
TEST SERIES 1&3
12 H
(A)
-------
TABLE 3-2
ENERGY DISTRIBUTION DESIGN VALUES
Gross Load, MW
Heat Input, MMBTU/HR^
Total Available Heat, MMBTU/HR
From Main Steam, MMBTU/HR
Main Steam AH, BTU/LB
Feedwater Flow, MLB/HR
From Reheat Steam, MMBTU/HR
Reheat Steam AH, BTU/LB
Reheat Steam Flow, MBTU/HR
Auxiliary Energy Consumption, MMBTU/HR
Heat Rejected Turbine & Generator
Losses, MMBTU/HR
Net Power Output, MMBTU/HR
Boiler Losses, %
Auxiliary Energy, %
Heat Rejected Turbine & Generator
Losses, %
Net Power Output, %
46
442.5
389.3
331.2
1133.2
292.3
58.0
214.7
270.2
13.5
232.0
143.8
12.0
3.1
52.4
32.5
92_
849.8
750.0
643.2
1066.8
602.9
106.8
194.7
548.3
21.0
435.9
293.1
11.7
2.5
51.3
34.5
111.5*"
1031.6
910.8
787.8
1043.7
755.4
123.0
180.6
682.8
24.4
529.8
356.6
11.7
2.3
51.4
34.6
115
1064.2
939.7
813.8
1039.6
782.8
125.9
178.1
706.9
25.0
546.7
368.0
11.7
2.3
51.4
34.6
("
Design values for this load estimated.
M - Thousands
3-8
-------
is converted from heated, pressurized water to high pressure, superheated
steam. The net heat rate is a reciprocal efficiency term describing the net
energy output in KWH as a fraction of the total energy input supplied by the
coal. The comparison of design boiler efficiency and an efficiency corres-
ponding to the reciprocal of the design net heat rate (overall efficiency)
is as follows:
Load Boiler Efficiency. % Overall Efficiency, %
46MW 88.0 32.5
92MW 88.3 34.5
115MW 88.3 34.6
In other words, only about one-third of the chemical energy of the coal is con-
verted to electrical energy. The remaining energy is distributed as follows:
• Boiler heat losses (subsection 3.1.1} - about 12%
• Heat rejected to the turbine condenser (entropy increase) -
about 50%
t Energy not recovered required to drive auxiliaries - about
2.5%
~s
• Turbine and generator losses - about 2%
The energy distribution determined from the tests are compared with the design
energy distribution in the following subsection. Table 3-2 is a compilation
of design values at the test load levels.
3.1.3.2 Net Energy Conversion
Relevant data are included in Table 3-3.
The weighted average net energy output (net MW-hour) was 31.3% of the
input energy of the coal for the normal series of tests. Design overall effi-
ciency varies from 32.5% to 34.6% depending on load. Energy distribution com-
pared with design values is summarized as follows, in percent of input energy:
3-9
-------
TABLE 3-3
ENERGY DISTRIBUTION
NORMAL OPERATING CONDITIONS
CO
I
TEST NO.
LOAD, GROSS (MW)
TOTAL HEAT INPUT, MMBTU/HR">
TOTAL HEAT AVAILABLE, MMBTU/HR
MAIN STEAM, MMBTU/HR
ATTEMPERATOR SPRAYS, MMBTU/HR
REHEAT STEAM, MMBTU/HR
AUXILIARIES, MMBTU/HR
AUXILIARY ENERGY CONSUMPTION, I
NET POWER OUTPUT, MMBTU/HR
IET POWER OUTPUT, X
IOILER LOSSES, t
IEAT REJECTED, TURBINE AND
GENERATOR LOSSES, «
IEAT REJECTED, TURBINE AND GENERA-
TOR LOSSES, MMBTU/HR
IAIN STEAM, MLB/HR
IEHEAT STEAM, MLB/HR
:EEDWATER(2), MLB/HR
"H - Thousands
2)
'Includes Sprays
1
44.5
471.94
396.71
323.85
22.14
50.72
12.62
2.7
139.3
29.5
15.9
51.9
244.9
314.2
279.9
303.1
16
45.5
505.98
413.49
322.48
24.92
66.09
11.3
2.2
144.1
28.5
1B.3
51.0
25B.O
324.5
301.5
317.3
17
46.2
510.95
405.41
335.27
14.84
55.30
13.3
2.5
144.4
28.3
20.7
48.5
247.8
324.5
292.0
312.0
2
90.3
939.82
788.82
669.09
21.58
98.15
19.5
2.0
288.9
30.7
16.1
51.2
481.2
645.2
587.4
627.2
3
89.6
910.77
751.25
642.67
14.31
94.27
20.2
2.2
285.8
31.4
17.5
48.9
445.4
645.7
568.6
618.5
4
91.2
940.57
762.54
637.24
24.69
100.61
20.2
2.1
291.3
31.0
18.9
46.0
451.5
647.7
573.3
621.7
5
89.0
890.97
749.48
644.26
12.46
92.76
19.1
2.0
284.8
32.0
15.9
50.1
446.4
642.0
568.0
617.7
6
90.9
910.45
766.59
646.00
22.12
98.47
19.8
2.1
290.6
31.9
15. 8
50.2
457.0
649.5
577.2
627.6
7
89.0
885.24
748.07
637.83
18.14
92.10
20.2
2.2
283.7
32.0
16.5
50.3
446.3
641.5
566.4
616.1
8
114.4
140.62
964.28
826.83
19.82
117.60
22.9
1.9
367.7
32.2
15.5
50.4
574.9
844.0
727.7
812.1
9
115.1
176.97
977.04
822.63
30.38
124.03
23.2
1.9
369.8
31.4
17.0
49.7
585.0
846.0
741.8
817.8
10
14.9
62.33
72.31
812.03
38.69
21.59
23.2
1.9
369.1
31.8
16.3
50.0
581.2
845.7
737.4
817.3
22
111.2
114.39
945.50
797.76
24.09
123.65
23.55
2.0
356.0
31.9
15.2
50.9
567.2
B18.0
710.6
789.3
23
11.9
23.10
53.74
12.88
16.40
24.46
24.91
2.0
357.0
31.8
15.1
51.1
574.0
880.0
715.7
795.0
-------
Actual
Boiler Losses
Auxiliaries Energy Consumption
Net Output
15.1 -
1.9 -
28.3 -
20.7
2.5
32.2
Design
11.7
2.3
32.5
- 12.0
- 3.1
- 34.6
Heat rejection to the turbine condenser and turbine and generator losses make
up the remainder of the energy balance.
3.1.3.3 Available Energy Of Steam
Relevant data are included in Table 3-3.
i
Actual heat in Btu/hr. available from the steam averaged 3.9% more
than the average design values. Available energy of the steam compared with
design values is summarized as follows, in MMBtu/hr.:
Actual Design
Main Steam^ 346.0 - 853.0 331.2 - 813.8
Reheat Steam 50.7 - 124.5 58.0 - 125.9
"'Includes attemperator sprays
These comparisons show that the energy available from the main steam (super-
heated steam) was higher than design whereas the energy available from reheat
steam was lower than design.
3.1.3.4 Energy For Auxiliaries
Relevant data are included in Tables 3-1, 3-3, B-2, and B-3.
Table 3-3 shows that 1.9% to 2.7% of the available energy is used by
the auxiliaries. A small amount of this energy is returned to the process.
For example, a small increase in enthalpy results from flow work done by the
boiler feedwater pumps.
3-11
-------
The average current drain by each of the major pieces of auxiliary
machinery has been recorded in Tables B-2 and B-3 for comparison with the
equivalent data to be collected during the Demonstration.
The auxiliary power requirement is one reason for the decreasing heat
rate when going from 46MW to 11 BMW (full load), indicated as follows:
Auxiliary Power Consumption
% of Gross Load
46MW 8.0
92MW 6.5
11 BMW 5.9
The relative ranking of the major auxiliaries in decreasing order of
rated power requirement is as follows:
Total HP
Boiler Feedwater Pumps (2) 3500
ID Fans (2) 1800
FD Fans (2) 1400
Circ. Water Pumps (2) 700
Coal Mills (4) 600
Condensate Pumps (2) 300
3.1.4 Feedwater Rates
Relevant data are included in Table 3-3 and on Figure 3-3.
The average feedwater flow rate was 4.1% higher than design flow rates.
Steam rates were consistently higher than feedwater rates by substantial amounts,
indicating a meter error. The steam rates appear to be unreasonably high. Thus,
feedwater rates were used for all efficiency and energy balance determinations.
3-12
-------
FIGURE 3-3
FEEDWATER RATE vs. GROSS LOAD
TEST SERIES 1&3
co
i
850
800
750
I" 700
£
g
^ 650
Ul
i
a* 600
3 550
500
450
400
350
300
200
- Actual
- Design
80 90
GROSS LOAD (MW)
100
110
120
-------
Reheat steam is not metered and must be calculated from the feedwater rates
and estimates of extraction flows.
The Demo. Unit will consume about 8% of the Mitchell No. 11 steam, thus
derating the boiler. Figure 3-3 shows the design and actual feedwater rates
as a function of load. Actual feedwater and steam rates during the Demonstra-
tion will be compared with these values.
3.1.5 Load Sensitive Pressure And Temperature Values
Relevant data are shown in Table B-4.
Temperatures of hot reheat steam and secondary superheater outlet steam
are controlled independently of boiler load, as is pressure of secondary super-
heater outlet steam. All other PT levels of steam and water are sensitive to
load primarily due to pressure losses in piping. Table B-4 shows the load
sensitive PT levels for the series of tests during normal boiler operations.
With some exceptions, the measurements were in fairly good agreement with these
design values:
BFW Inlet Economizer, °F
No. 4 Extraction, °F
BFW Exit No. 3, °F
BFW Exit No. 4, °F
Cold Reheat, psig
Hot Reheat, psig
No. 4 Extraction, psig
46MW
372
789
269
310
172
153
74
Design Values
92MW
434
835
314
363
363
325
163
115MW
459
835
331
383
471
423
213
3-14
-------
3.1.6 Fuel Quality
3.1.6.1 Fuel Sources
A single source of 3% sulfur coal was not available during the Baseline
tests. However, this lack of homogeneity did not result in any excessive var-
iability in coal composition (see 3.1.6.2). Origins of the coal used were as
follows:
Mine
Tests 1-3 River King and/or Fidelity
Tests 4-5 Fidelity and/or Reclaimed
Tests 6-7 Burning Star
Tests 8-15 River King and/or Fidelity
Tests 16-19 Undetermined
Tests 20-21 River King and/or Fidelity
Tests 22-23 Reclaimed
The mines are located on the No. 6 bed located in Southwest Illinois. The
coal is a high volatile bituminous, H.V.C. rank (ASTM D388 designation). Re-
claimed coal is the coal taken from areas of the storage yard where a mixture
of various types of coal would be expected.
Performance guarantees for Mitchell No. 11 were based on the River
King coal, analysis as follows:
3-15
-------
High Heating Value, Btu/lb
Fixed Carbon, wt. %
Volatile Matter, wt. %
Oxygen, wt. %
Sulfur, wt. %
Ash (Dry Basis), wt. %
Ash (Wet Basis), wt. %
H20, wt. %
Carbon, wt. %
Hydrogen, wt. %
As Received
11.267
41.64
37.43
8.72
3.17
11.05
9.82
11.11
61.65
4.43
Dry, Ash Free
14,249
52.66
47.34
11.03
4.01
77.97
5.60
Concentrations of components which are active in the combustion
reaction are represented by the dry, ash free analysis. The dry, ash free
values are useful for making comparisons between coal samples and for deter-
mining the variability of the coals.
3.1.6.2 Coal Composition
Relevant data are shown in Tables 3-4, 3-5, B-5, B-6, B-7 and B-8.
Tables 3-4 and 3-5 show the 95% confidence limits determined from the
measurements for the true means of the active components for combustion:
these being heating value, carbon, hydrogen and oxygen. Comparable coal
parameters specified for the performance guarantees are outside these 95%
confidence limits, indicating some differences between the coal used for
testing and the guarantee basis coal. The heating value of the guarantee
basis coal is above the higher limit of confidence. Slightly higher effi-
ciencies might be expected from the guarantee basis coal due to lower stoi-
chiometric air requirements as a result of higher oxygen content and a lower
carbon to hydrogen ratio of the guarantee basis coal. "Raw" coal was sampled
between the Mitchell No. 11 storage bunker and the coal scales. "As fired"
coal Is pulverized coal sampled between the coal mills and the burners.
3-16
-------
TABLE 3-4
SUMMARY OF COAL QUALITY & VARIABILITY - AS FIRED COAL
TEST SERIES 1, 2 & 3
High Heating Value
'*
(0
Oxygerr ', wt. %
Sulphur^1 ), wt. %
Ash, (Dry Basis),
wt. %
Ash, (Wet Basis),
wt. %
H20, wt.
Carton^1
Hydrogen , wt. %
Carton^1 ^, wt.
Mean
9.91
4.06
12.60
11.91
Mean
Standard
Range Deviation
14.14 14.01-14.28
9.87-13.14
0.1
9.52-10.79 0.5
3.22- 4.49 0.3
10.40-13.84 0.9
0.8
95%
Confidence
Limits of
the Mean
14.1-14.2
9.8-10.2
4.0- 4.2
12.0-12.8
11.4-12.2
5.45
79.04
5.45
4.59- 6.31
76.91-79.50
5.40- 5.68
0.5
0.3
0.3
5.1- 5.5
78.7-79.0
5.3- 5.6
(1)
Dry, ash free basis
M - thousands
3-17
-------
TABLE 3-5
SUMMARY OF COAL QUALITY & VARIABILITY - RAW COAL SAMPLE
TEST SERIES 1, 2 & 3
High Heating Value*1),
MBtu/lb(2)
Oxygen^1', wt. %
Sulphur^, wt. %
Ash, (Dry Basis),
wt. %
Ash, (Wet Basis),
wt. %
H20, wt. %
Carbon^, wt. %
Hydrogen^, wt. %
Mean
14.17
9.83
4.08
11.92
10.69
10.35
79.21
5.41
Range
14.06-14.36
8.02-10.66
3.37- 4.90
10.50-13.91
9.30-12.65
8.11-11.83
77.64-81.48
5.15- 5.58
Mean
Standard
Deviation
0.1
0.7
0.4
1.0
0.9
1.2
0.8
0.1
95%
Confidence
Limits of
the Mean
14.1-14.2
9.5-10.1
3.9- 4.3
11.5-12.3
10.3-11.1
9.4-10.4
78.7-79.5
5.4- 5.5
(1)
Dry, ash free basis
- thousands
3-18
-------
On a dry, ash free basis the between sample variability was not ex-
cessive, see Tables 3-4 and 3-5. Heating value, carbon content and hydrogen
content were particularly stable. The lack of any excess variability was
welcome in view of the wide variety of coals used during the tests. No coal
composition values were rejected as outliers based on standard statistical
tests.
3.1.6.3 Demonstration Test Comparisons
Heat rate, efficiency, and loss calculations are based on raw coal
analyses since coal rates are raw coal rates. Continuous sampling of raw
coal is not feasible and therefore as fired coal samples will have to be
used during the Demonstration. The major difference between raw coal and
as fired coal composition is a decrease in the moisture content, but the
moisture lost from the raw coal will enter the furnace entrained in the air.
It is assumed that the coal rejected at the mills is minimal and thus it is
assumed that the rate of as fired coal plus entrained moisture is the same
as the raw coal rate. A t-test was run to determine if there are significant
differences between pairs of dry basis raw coal and of as fired coal composi-
tion values. On the basis of the statistical t-test, the differences between
heating values were significant at the 95$ probability level but the differ-
ences between sulfur contents were not signifcant at a 95% probability level.
However, the mean heating value of the raw coal was only 0.7% higher than the
comparable mean for the as fired coal. It is believed, thus, that as fired
coal composition adjusted for moisture can be used to determine the coal com-
ponent rates without significant error. Probably the major problem will be
obtaining a representative sample, considering that a large number of gross
sample increments must be combined and then reduced to laboratory size.
Analysis of composites created from selected groups of coal samples do not
agree very well with averages of the individual samples, see Tables B-5, B-6,
6-7, B-8, B-9 and B-10. Strict adherence to sample preparation procedures
will be required for the continuous sampling during the Demonstration.
3-19
-------
3.1.7 Pulverizer Performance
3.1.7.1 Operating Problems
Relevant data are shown in Figures 3-4, 3-5, 3-6 and 3-7.
Series One tests were started with only two of four mills available.
Mill 2 had been forced down prior to the start of the test series due to a
fire. Mill 3 was down with a broken retainer ring. One 46MW test was run
with these two units out of service. Repair on Mill 2 was then completed
and all of the 92MW tests and the remaining two 46MW tests were run with
three mills. All four mills were available and operated for the 115MW tests
of Test Series One, Two and Three.
The net effect on performance from using only two or three mills was
not determined. Power consumption per unit of coal fired increases when more
mills are added but the firing patterns are changed as shown in Figure 3-4
3-5, 3-6 and 3-7.
3.1.7.2 Size Reduction
Tables B-ll and B-12 present the relevant pulverizer performance data
at both normal and off-normal operating conditions.
The screen size of the pulverized coal entering the burners was in the
range of 74% to 81% passing a 200 mesh screen. The pulverizers are expected
to grind to 70% passing a 200 mesh screen. Pulverizer reject rates were not
measured but are believed to be very low. The coal entering the pulverizer
has been screened to a nominal 1-1/4 inch size.
3.1.7.3 Moisture Reduction
Relevant data are shown in Tables B-5, B.-6, EL-7 and B~8 and on Figure
3-8.
Moisture is liberated from the coal in significant quantities by the
heated primary air during the pulverizing process. Weighted average moisture
reduction was 49.3% during Test Series 1, 2 and 3 (see Figure 3-8). The
3-20
-------
c
Boi ler
o o • o
1-1 1-2 22 1-3
• • • •
2-1 3-1 3-2 2-3
O O O •
4-1 4-2 4-3 3-3
n n n
ii
PULVERIZERS
lit
Burners
- Out of Service
- In Service
FIGURE 3-4 FUEL DISTRIBUTION TO BURNERS
Test NO. 1
3-21
-------
c
c
Boiler
o o o o
1-1 1-2 2-2 1-3
O O O O
2-3
O
4-1 4-2 4-3 3-3
2-1 3-1 3-2 2-3
.i.1.1 ririw Ann
Hi Hf 4H
1
2
3
i
PULVERIZERS
Burners
I- Out of Service
(**"')- In Service
FIGURE 3-5 FUEL DISTRIBUTION TO BURNERS
Test No. 16, 17
3-22
-------
c
D
c
Boiler
o o o o
1-1 1-2 2-2 1-3
O • • O
2-1 3-1 3-2 2-3
O O O •
4-1 4-2 4-3 3-3
wri
t»t
i
ttt
Burners
- Out of Service
- In Service
PULVERIZERS
FIGURE 3-6 FUEL DISTRIBUTION TO BURNERS
Test No. 2, 3, 4, 5, 6, 7
3-23
-------
c
X
Boiler
\
o o o o
1-1 1-2 2-2 1-3
O O O O
2-1 3-1 3-2 2-3
O O O O
4-1 4-2 4-3 3-3
D
/
C
Burners
- Out of Service
In Service
S22 SSS SSS 555
Iff fff 4f4 Iff
1
2
3
4
PULVERIZERS
FIGURE 3-? FUEL DISTRIBUTION TO BURNERS
Test No. 8, 9, 10, 11, 12, 13, 14, 15, 18, 19, 20, 21
3-24
-------
FIGURE 3-8
% REDUCTION VS. % MOISTURE CONTENT IN RAW COAL
TEST SERIES 1, 2• & 3
70-
60
PC
en
2 50
t—
o
1=1
*«
40
30
20
9.0
TO TO
MOISTURE CONTENT RAW COAL
TTTo
-------
magnitude of moisture reduction for individual tests was a function of the
level of moisture in the raw coal. Higher levels of moisture in the raw coal
probably reflect more surface moisture and thus the higher drying rate. The
efficiencies and heat rates reported in 3.1.1 and 3.1.2 were calculated on
the rates and compositions of the raw coal. Reduction in moisture content
appeared to be independent of boiler load.
3.1.7.4 Power Requirements
Relevant data are shown in Tables B-ll and B-12 and on Figure 3-9.
The power requirements for driving the four primary air fans and the
four pulverizers affect the net generating output of the boiler and thus its
overall operating performance characterized by the net heat rate. The rela-
tive energy consumed is reported as the average current draw of each unit in
Tables B-ll and B-12. Figure 3-9 shows the total power requirements, expres-
sed in amps, for the primary air fan set and the coal mill set as a function
of coal rate. Less power is required per ton of coal fired if fewer than
four coal mills are utilized, but this changes the firing pattern as indica-
ted earlier in the discussion.
3.1.8 Heated Air Requirements
3.1.8.1 Excess Air Levels
Relevant data are shown in Table B-13 and on Figure 3-10.
The amount of excess air is controlled to maintain 4% excess oxygen in
the flue gas inlet the air preheater at steaming rates of 600,000 Ib/hr. and
higher and to maintain increasing concentrations of oxygen with decreasing
load below 600,000 Ib/hr. steaming rate, see Figure 3-1Q. For the 46MW load
level, the excess air operating set point is about 6.2% oxygen in the flue gas.
From 92MW to 115MW load level, the set point is 4.0% excess oxygen. The dif-
ference between the excess oxygen levels and the set point values during Test
Series 1 and 3 is shown on Figure 3-TO. The data are summarized as follows:
3-26
-------
FIGURE 3-9
AMPS AS A FUNCTION OF COAL FEED RATE
TEST SERIES 1&3
ro
105
100
95
90
85
80
i
: 75
70
65
60
55
50
45
40
- Pulverizer
- Primary Fan
35
To1
45
50
55
COAL FEED RATE, TONS/HR
-------
10.Ol
9.0J
FIGURE 3-10
0? INLET AIR HEATER vs. GROSS LOAD
TEST SERIES 1&3
co
ro
co
8.0-1
7.0-1
6.0-1
4.0-J
LOAD RAMP
2.0^
1.0-
40
50
60
70 80 96 100 110 120
GROSS LOAD, MW
-------
46MW
92MW
111MW
11 BMW
% Oxygen
Actual
9.3 - 9.6
3.9 - 6.6
4.5 - 6.1
2.4 - 3.4
Set Point
6.2
4.0
4.0
4.0
The oxygen levels were consistently high only during the 46MW tests. The
oxygen levels were either very near or above the set point during the 92MW
and 111MW tests and were below the set point during the 115MW tests. The
oxygen levels were determined from spot Orsat measurements by GC with thermal
conductivity detection. The Mitchell station continuous oxygen analyzer was
in service for only two tests (46MW) during Test Series 1.
3.1.8.2 Effect Of Excess Air On Efficiency
Relevant data are shown in Table B-13 and on Figures 3-10 and 3-11.
Excess air is a sink for the heat discharged to the stack and there-
fore contributes to the total heat loss and the resultant effect on efficiency.
Even within the operating load settings, the contribution to the total losses
from the excess air required to maintain complete combustion is substantial.
Table B-13 and Figure 3-11 show these effects for Test Series 1. From 12% to
30% of the total heat loss was due to heat required for heating the excess air.
3.1.8.3 Air Heater Performance
Relevant data are shown in Table B-13.
The function of the air heaters is to recover heat from the flue gas
through heat exchange with the incoming air. Performance data are summarized
as follows:
3-29
-------
FIGURE 3-11
EXCESS AIR CONTRIBUTION TO TOTAL HEAT LOSS vs. AIR/COAL RATIO
TEST SERIES 1&3
30-
to
tO
o
CO
o
o
o
§
K-(
I—
I—4
£X
O
O
•20
to
to
UJ
o
X
LU
10
Not Included in Linear
Regression (Tests 22, 23)
11
12
13 14 15
AIR/COAL RATIO, w/w
16
17
18
-------
Air AT Across Air Heater, °F : 397
Heat Recovery, MMBTU/hr. : 69-132
Heat Recovery, % of Total Heat Input : 9.9-17.2
Air/Coal Ratio, w/w : 10.9-17.8
Somewhat better heat recovery was experienced at 46MW over the heat recovery
at 92MW and 11 BMW. At 46MW, the heat recovery varied from 14.6% to 17.2%
whereas the heat recovery at the higher loads was in the range of 9.9% to
11.4%. This appears to be an effect of the higher excess air at loads
below 92MW.
3.1.9 Boiler Drafts
Relevant data are included in Table 3-6 and Tables B-14, B-15 and B-16.
The boiler was designed for a total gas and air resistance of 18.7
inches W.C. pressure differential at full load between the FD fan discharge
and air heater outlet. Table 3-6 summarizes the draft losses for the normal
full load tests. The total resistance design value was exceeded during only
one test (Test 10) of the three replicate test set. An excess draft loss of
one inch W.C. was found, attributable to resistances on both the air and the
gas side of the air heater.
3.1.10 Soot Blowing Effects
Relevant data are included in Table 3-1.
Tests with soot blowers operating were conducted during the 92MW (80%
load) test set (Tests 2 thru 7) alternately with tests without soot blowing.
Soot blowing normally requires about two hours but the period was extended to
three hours during these tests to attain correspondence with the flue gas sam-
pling period. There was no noticeable affect on efficiency and heat rate from
soot blowing, see Table 3-1. The soot blower air compressor requires auxiliary
power but it is not a major power user.
3-31
-------
TABLE 3-6
DRAFT LOSSES AT 100% LOAD, in. W.C.
NORMAL OPERATING CONDITIONS
Air, Air Heater
Ducts and Dampers A.P.M. to
Burners, Burners and Windbox
Total Air Resistance
Furnace and Convection Banks
Flues to Air Heater
Gas, Air Heater
Total Gas Resistance
Total Boiler Resistance
Design
3.7
3.2
6.9
5.0
1.0
5.8
11.8
18.7
8
4.8
1.5
6.3
5.0
1.0
5.6
VL6
17.9
Test
9
4.4
2.0
6.4
3.6
2.4
.5.9
1U9
18.3
10
4.8
2.5
7.3
5.0
1.1
6.3
12.4
19.7
3-32
-------
3.2 FLUE GAS CHARACTERIZATION - NORMAL OPERATION
This section describes the results of a comprehensive test program
for characterizing the outlet flue gas to:
• Establish pre-retrofit (baseline) performance of Mitchell
No. 11.
• Provide a data base which can be used to compare this
flue gas with the flue gas from other utility boiler con-
figurations for which the WL/Allied process has appli-
cability.
• Establish relationships between flue gas parameters and
boiler control settings in order to determine the effect,
if any, of the retrofit on boiler operation and perfor-
mance.
• Compare measured values of the flue gas parameters with
the corresponding values upon which the design of the
Demo. Unit is based.
3.2.1 Scope Of Characterization
Tests were conducted to obtain a physical-chemical profile of the flue
gas at normal operating conditions and at selected off normal operating con-
ditions. Normal operation included an examination of effects on flue gas by
varying the load from 40% to 100% and of soot blowing. Off normal operation
included an examination of effects of high grain loading, excess combustion
air, excess air inleakage, and low sulfur fuel.
The remainder of section 3.2 is devoted to a summary of the flue gas
characterization results and to an evaluation of the data collected during
normal operation and, as appropriate, off normal operation. The results and
evaluations are presented as follows:
0 A detailed physical-chemical profile is presented and
summarized.
t Measured flue gas parameters are compared with the
corresponding design parameters.
3-33
-------
• Baseline emission levels are documented.
• Flue gas conditions are correlated with boiler control
settings.
• Flue gas conditions having a potential effect on Demo.
Unit performance are discussed.
3.2.2 Flue Gas Profile
Relevant data are included in Tables 3-7, 3-8, 3-9, B-17 and B-18.
Table 3-7 is a summary of the flue gas characterization data at nor-
mal operating conditions. This data provides the documentation of pre-retro-
fit (baseline) flue gas conditions. It also will be referenced in the suc-
ceeding subsections in which the flue gas characterization data is evaluated
for each major pollutant, trace emissions, and physical characteristics.
The data has been examined to determine as far as possible which ob-
servations are outliers (invalid measurements). The outliers are not used in
the correlations but the outlying observations are included in the tabulations
and on the figures for correlating the flue gas properties with their indepen-
dent variables. Examples of outliers are as follows:
Inlet flue gas mass rate - Test 2
Flue gas volume - Test 2
S02 mass rate - Tests 2, 9
NOx mass rate - Test 10
Particulate mass rate and grain loading - Soot blowing tests
3.2.3 Volume, Temperature, Pressure
3.2.3.1 Measured Volume Vs. Design
Relevant data appear in Tables 3-10, B-19 and Figures 3-12 and 3-13.
3-34
-------
TABLE 3-7
FLUE GAS CHARACTERIZATION SUMMARY
NORMAL OPERATING CONDITIONS
co
co
01
TEST NO.
LOAD, GROSS (HW)
SOOT BLOWING STATUS
RAW COAL FEED RATE, MLB/HR^1'
RAW COAL MOISTURE, %
RAW COAL ASH, %
RAW COAL SULFUR, %
RAH COAL HIGH HEATING VALUE,
BTU/LB
RAM COAL SULFUR, LB/HR
RAW COAL ASH, LB/HR
TEMP (OUTLET ID FAN), °F
STATIC PRESSURE (OUTLET ID FAN),
1 Hg
:LUE GAS VOL (OUTLET ID FAN),
•ISCFMD
502. PPM
502, LB/HR
K)x/S02, MOL N02/MOL S02
'ART (OUTLET ID FAN), Gr/ACF
(Ox, PPM
lOx, LB/HR
EXCESS AIR (OUTLET ID FAN), X
1
45.5
Off
43.2
11.8
11.1
3.3
10900
1426
4795
261
0.10
159
1757
2776
0.07
0.067
129
146
104
16
44.5
Off
43.9
8.8
10.2
3.2
11500
1408
4488
245
0.04
171
1742
2949
0.05
0.020
84
102
102
17
46.2
Off
44.2
8.3
10.4
3.2
11600
1414
4597
243
0.04
169
1B06
3031
0.04
0.022
71
85
101
2
9Q.3
Off
83.. 6
9-7
10.8
3.2
11200
2675
9029
273
0.18
248
1278
3142
0.13
0.215
171
302
53
3
89.6
On
81..5
9,7
11.0
3,8
11200
3101
8976
268
0.18
236
2402
5615
0.04
0.320
93
156
56
4
91.2
Off
81.2
8.6
9.8
3.3
11600
2680
7958
267
0.18
230
2679
6107
0.04
0.130
111
182
47
5
89.0
On
79.0
11.5
9.3
2.8
11300
2212
7347
263
0.18
213
2516
5328
0.04
0.130
105
159
44
6
90.9
Off
80.5
10.2
9.7
3.0
11300
2418
7818
259
0.18
226
1952
4381
0.05
0.127
103
166
49
7
89.0
On
80.4
9.1
12.7
3.8
11000
3055
10211
279
0.18
223
2373
5243
0.04
0.175
103
164
48
8
114.4
Off
103.8
11.3
10.9
3.2
11000
3322
11314
293
0.18
249
2809
6930
0.05
0.273
131
233
30
9
115.1
Off
104.9
11.3
10.0
3.2
11200
3360
10500
295
0.04
256
4044
10257
0.03
0.236
100
182
31
10
114.9
Off
102.7
9.8
10.0
3.2
11300
3290
10280
298
0.04
273
2718
7358
0.09
0.247
234
455
41
22
111.2
Off
103.2
11.5
11.9
2.6
10800
2E83
12280
J2>
-.Cs>
265
--?=!
-J2)
-.M
.-(2)
50
23
111.9
Off
103.5
11.7
12.0
3.0
10800
3105
12420
.J»
-W
264
-J2'
-J2)
-12)
..is)
36
' JM - Thousands (2>No sample taken
-------
TABLE 3-8
PARTICLE SIZE DATA
Normal Conditions
TEST
NO.
1
2
3
6
10
LOAD
GROSS
ML i
44.5
90.3
89.6
90.9
114.9
MASS MEDIAN
DIAMETER (MICRONS)
3.2
2.9
1.1
3.4
1.4
AS FIRED COAL
SOOT BLOWING SIZE, % THRU
STATUS 200 MESH
Off
Off 73.9
On 78.3
Off 78.6
Off 76.7
3-36
-------
TABLE 3-9
PARTICLE SIZE DATA
Off-Normal Conditions
LOAD AS FIRED COAL
TEST GROSS MASS MEDIAN SOOT BLOWING SIZE, % THRU
NO. (MM) DIAMETER (MICRONS) STATUS 200 MESH
11 115.1 0.9 Off 73.7
12 114.7 1.5 Off 76.0
13 114.8 2.2 Off 79.3
18 108.9 3.0 Off 75.3
3-37
-------
TABLE 3-1Q
THEORETICAL BOILER OPERATING PARAMETERS FOR
CALCULATING FLUE GAS RATES
Coal Composition -
- Ash, wt. % 9.89
- Sulfur, wt. % 3.15
- Hydrogen, wt. % 4.39
- Carbon, wt. % 61.18
- Moisture, wt. % 11.64
- Oxygen, wt. % 8.65
- Nitrogen, wt. % 1.09
- High Heating Value, Btu/lb 11299
Heat Rate, Btu/KWH, at -
- 46MW 9604
- 69MW 9320
- 92MW 9237
- 11 BMW 9247
Oxygen in Flue Gas, %, at -
- 46MW 6.4
- 69MW 5.2
- 92MW , 4.0
- 115MW 4.0
3-38
-------
FIGURE 3-12
INLET (THEORETICAL & MEASURED) MASS RATE vs. GROSS LOAD
TEST SERIES 1
CO
IQ
iioo-
1 COO-
CO
600-
500,
- Measured
- Theoretical (Design Coal)
- Outlier (Not included in
linear regression)
15"
60
80 90
GROSS LOAD (MW)
100
no
120
-------
FIGURE 3-13
INLET & OUTLET FLUE GAS VOLUME FLOW RATE vs. GROSS LOAD
TEST SERIES 1
30C
5250
o
200
150
• - Inlet
©- Outlet
Q- Outlier (Outlet) - Not Included in Linear Regression
£- Outlier (Inlet) - Not Included in Linear Regression
100
40
50
60
70 80
GROSS LOAD (MW)
90
100
110
120
-------
Measured flue gas mass rates are compared with the boiler design
values over the range of operating loads on Figure 3-12. Predicted perfor-
mance of the new boiler at full load, supplied by the boiler vendor, was
extrapolated to other loads by calculation from the design coal composition,
predicted heat rates and the excess oxygen values shown in Table 3-10. The
theoretical flue gas rate is not a linear function of load. However, the
degree of non-linearity is small and a linear function is assumed for presen-
tation on Figure 3-12. Measured values at inlet the air heaters were in ex-
cess of design from 46MW to about 110MW. This is attributed to higher than
design coal rates as affected by high heat rates and to higher than design
excess air levels. High measured values at the outlet are additionally at-
tributed to inleakage at the air heaters and beyond.
The Demo. Unit design flue gas rates at 92MW are 1.02 MMlb/hr. and
320,000 acfm (300°F, 14.7 psia). Baseline results at about 92MW averaged
1.10 MMlb/hr. and 336,000 acfm (268°F, 14.6 to 14.7 psia). Dry gas rates are
also of interest as far as Demo. Unit operation is concerned. Demo. Unit
design is based on dry gas rates of 0.98 MMlb/hr. at 92MW. Baseline data at
92MW averaged 1.06 MMlb/hr.
3.2.3.2 Flue Gas Rate Dependency On Boiler Control Settings
Relevant data are included in Table B-19 and on Figure 3-13.
Flue gas volume differences at the outlet are dependent primarily on
coal rate and excess air. Additional independent variables might be coal
moisture, carbon to hydrogen ratio and humidity of the air. Coal rate is de-
pendent on the boiler efficiency. Excess air is also dependent on coal rate
as well as on inleakage occurring primarily at the air heaters. Coal moisture
and moisture in the air contributed about one to two percent of the total out-
let flue gas. Carbon/hydrogen ratio was relatively constant. Its effect on
flue gas volume was to increase it only three percent within the minimum and
maximum limits of the carbon/hydrogen ratio. From 9% to 21% of the total flue
gas was contributed by the excess air. Flue gas volume varied inversely with
load factor. Figure 3-13 shows this dependency on load.
3-41
-------
3.2.3.3 Temperature Vs. Design
Flue gas temperatures measured during the Baseline Test are listed
in Table B-19. Examination of averages compared with boiler design values
at the air heater outlet is presented as follows:
Avg. Gross Load, MW
45
61
90
115
Avg. Temperature
°F
275
—
289
320
Design Temperature, °F,
Corrected for Inleakage
276
—
286
The average temperatures measured at the outlet of the ID fans as a
function of gross load were as follows:
Gross Load, MH Temperature. °F
45 250
90 268
115 295
The Demo. Unit design specifications specify 300°F as the design temperature
at a gross load of 92MW.
3.2.3.4 HpS04 Condensation
Relevant data are shown in Tables 3-11 and 3-12.
Dew Points for H2S04 condensation are determined graphically by the
method of Martin, et. al/ ' In essence, this work correlates S03 concen-
trations with dew point temperatures as a function of the partial pressure
of water in the flue gas. Martin's work indicates that below 100 ppm S0~,
dew point temperature changes with S03 concentration at a much reduced rate.
3-42
-------
TABLE 3-11
H2SO,, CONDENSATION EFFECT
NORC.AL OPERATING CONDITIONS
CO
TEST NO.
LOAD, GROSS (MW)
AV6 TEMP (OUTLET ID FAN), 'f
S03, PPM
MOISTURE (OUTLET ID FAN). %
H2S04 DEW POINT, °F
DUCT TEMP MINIMUM, °F
DUCT TEMP MAXIMUM, "F
1
44.5
261
18
5.2
280
255
265
16
45.5
245
104
5.5
270
240
250
17
46.2
243
55
4.9
250
240
250
2
90.3
273
40
3.4
240
260
290
3
89.6
268
54
6.6
260
240
285
4
91.2
267
74
6.6
260
235
280
5
89.0
263
40
6.3
253
200
280
6
90.9
259
48
6.2
255
250
290
7
89.0
279
63
5.8
260
230
300
8
114.4
293
32
7.2
253
250
305
9
115.1
295
73
8.0
270
240
300
10
114.9
298
107
7.1
290
250
310
-------
TABLE 3-12
H2S04 CONDENSATION EFFECT
OFF NORMAL OPERATING CONDITIONS
TEST NO.
LOAD, GROSS (MM)
AV6 TEMP (OUTLET ID FAN). °f
S03, PPM
MOISTURE (OUTLET ID FAN). *
HjS04 DEW POINT, °F
DUCT TEMP MINIMUM, °F
DUCT TEMP MAXIMUM. "F
No sample
11
115.1
302
91
7.6
265
220
310
12
114.7
288
123
7.1
305
230
300
13
114.8
289
102
7.1
270
240
290
14
110.1
289
92
8.0
273
..(1)
..(1)
15
110.1
288
88
6.3
255
250
295
18
108.9
298
47
7.5
260
280
300
19
114.8
284
63
7.2
262
280
290
20
118.1
276
56
7.5
260
250
285
21
114.4
279
43
7.9
262
270
285
-------
Comparison of the dew point temperature with the minimum duct temper-
ature indicates that there is probable ^SO^ condensation at 40% load condi-
tions and possible H2SO^ condensation at 80% load. Minimum duct temperatures
were usually found near the duct walls.
3.2.3.5 Pressures
Static pressures of the flue gas at inlet the air heaters and outlet
the ID fans and the corresponding barometric pressures are tabulated in
Table B-19 for Test Series 1.
3.2.4 Sulfur Oxides Emission Levels
3.2.4.1 Sulfur Mass Balance
Relevant data are included in Tables 3-7, 3-13, 3-14, and B-20.
The sulfur balance across the boiler was in excess of full closure by
about 12% for the tests in which 3% sulfur coal was burned. Closure averaged
about 108% for the tests in which one percent sulfur coal was burned. The mass
balance was computed by equating sources and sinks. The sole source was assum-
ed to be the sulfur content of the coal, since the highest expected concentra-
tion of sulfur in the ambient air would contribute only negligible amounts.
The sulfur sinks are:
• SOx in flue gas
a S in rejects
• S in bottom ash
t S in fly ash
Normally, sulfur in the rejects, bottom ash, and fly ash account for about 5%
of the input. The sulfur mass balance of these tests includes only an esti-
mate of sulfur in the fly ash and the measured SOx in the flue gas, calculated
as follows:
3-45
-------
TABLE 3-13
SULFUR MASS BALANCE, LB/HR
st No/1)
1
16
17
2
3
4
5
6
7
8
9
10
11
12
13
28
29
30
31
32
34
!IIL
1426
1408
1414
2675
3101
2680
2212
2418
3055
3322
3360
3290
3251
3066
3522
902
1150
1026
615
657
987
Sout
1535
1606
1612
1725
3028
3289
2866
2377
2858
3655
5412
3990
3482
3526
4216
2074
1018
698
762
776
987
% Closure
107.6
114.1
114.0
64.5
97.6
122.7
129.6
98.3
93.6
110.0
161.1
121.3
107.1
115.0
119.7
229.9
88.5
68.0
123.9
118.1
100.0
diff
109
198
198
-950
-73
609
654
-41
-197
333
2052
700
231
460
694
1172
-132
-328
147
119
0
% diff
7.4
13.1
13.1
-48. 2^2)
-2.4
20.4
25.8
-1.7
-10.1
9.5
46.8<2)
19.2
3.4
14.0
17.9
78.8^)
-12.2
-38.1^)
21.4
16.6
__
(1Hests 1-17, 3% S coal. Test 28-34, 1% S coal.
Outlier values.
3-46
-------
TABLE 3-14
SULFUR BALANCE EFFECTS
Observed Corrected to 100%
(At 112% of Closure) Closure
S02 at 92MW, Ib/hr average 5335 4763
S02 at 92MW, Ib/hr range 4381-6107 3912-5453
S02 at 92MW, ppmv average 2384 2129
S02 at 92MW, ppmv range 1952-2679 1743-2392
S02 All Tests, ppmv range 1742-2809 1555-2508
SOj at 92MW, ppmv average 58 52
S02 + S03 at 92MWS Ib/hr average 5135 4585
Lb S02/MMBTU, average All Tests^ 5.9 5.3
(^Excluding outliers.
3-47
-------
% Closure = " \
5 coal
where:
- 1b s - x coal rate
s flu. 9.1.0.5x^+0.4x1*52*
1b S 1b ash , te
TFlsTf x Ib coal x coal rate
Table 3-13 shows the mass balance for tests on which complete data are avail-
able (sulfur in ash was not measured for every test). For the high sulfur
tests during which closure exceeded 100%; possible errors may be in the flue
gas volume measurement, sample metering, or in the analytical standards used.
Any errors associated with the sulfur mass balance are likely to be in combi-
nation since any single source of error is not expected to be large enough to
contribute an average of 12% or more of the total sulfur. Major errors in the
inlet sulfur parameters are discounted. Sulfur in coal values agree with those
expected. A substantial coal rate error is not reasonable because it would
result in lower than reasonable boiler efficiencies. The coal scales were re-
calibrated prior to these tests and different analytical standards were used
for the low sulfur tests.
In the discussion to follow on sulfur oxide emissions, the results will
be discussed with the assumption of no closure error. The data presented in
the tables and figures assumes no closure error. To have a common basis for
comparison with later tests to be conducted during the Demonstration, the more
important results are corrected to 100% closure basis and presented in Table
3-14.
3.2.4.2 Measured SOp vs. Design SOo
Relevant data are included in Tables 3-7, B-20 and on Figures 3-12
and 3-14.
3-48
-------
vo
8000 •
7000
6000 n
§ 5000
4000 -J
3000 -
2000
FIGURE 3-14
S02 EMISSIONS (THEORETICAL & MEASURED) vs. GROSS LOAD
TEST SERIES 1
A - Measured
• - Theoretical
O - Outliers (Not included in
.ftegresiion Analysis)
40
50
60
70
80
90
GROSS LOAD (MW)
100
110
120
-------
Figure 3-14 compares the measured S02 emissions with theoretical emis-
sions which are based on design basis coal composition. Linear regression
techniques were used to plot the S02 emissions as a function of load. Figure
3-14 shows that S02 mass emission rates were 20% higher than the theoretical
basis emission rates used for boiler design. These effects are due to higher
than design coal rates which are due to less than design boiler efficiencies,
slightly higher than design coal sulfur, and other fuel composition effects.
The WL/Allied Demonstration Unit design was based on the following ex-
pected conditions:
Gross Load (MW)
S in Coal (wt. 35)
S02 in flue gas (ppmv)
S02 in flue gas (Ib/hr)
SO, in flue gas (ppmv)
2 in flue gas (Ib/hr)
SO
92 (80% load)
3.2
2185
4842
35
97
Baseline Test data at normal operating conditions and 92MW averaged about
5574 Ib/hr S02 or about 15% higher than design. Individual test results varied
from 5243 Ib/hr to 6107 Ib/hr. The data scatter is discussed in subsection
3.2.4.3. Concentration of S02 is an equilibrium driving force in the absorp-
tion step of the WL/Allied process. At an average of 90MW for six tests, the
concentration of S02 averaged 2493 ppmv compared with 2185 ppmv design con-
centration at 92MW. The individual concentrations varied from 2373 ppmv to
2679 ppmv. Over the full operating load range, the individual concentrations
varied from 1742 ppmv to 2809 ppmv. The greater variations in the latter case
are due to the effect of load on flue gas volume. At 92MW, concentration of
S03 was 52 ppmv average compared to 35 ppmv used for the Demo. Unit design.
Total sulfur (S02 + S03) rates averaged 5742 Ib/hr.
3.2.4.3 Sulfur Dioxide Emissions Compared to the New Source Performance
Standard """ ~~~~ ——• —
For solid fossil fuel, the standard requires that emissions of 1 2 Ibs
S02/MMBTU not be exceeded. Measured rates at normal operating conditions
3-50
-------
averaged 6.1 Ibs S02/MMBTU. Based on these data, absorber efficiencies of
better than 80% are required to keep 50^ emissions below the New Source Stan-
dard/ ' (The above comparison is not made to show whether or not Mitchell
No. 11 is in compliance with an applicable standard. Throughout the Test and
Evaluation program, emissions will be compared with the applicable National
standards only for the purpose of illustrating one facet of applicability of
the WL/Allied process to the total population of utility boilers).
The standard deviation from the mean was 4^0.4 Ibs S02/MMBTU, after re-
jection as outliers of the data of Tests 2 and 9. There was no apparent varia-
tion with load in the emission rate values when expressed as Ibs SCWMMBTU.
Values which exceeded two standard deviations were rejected as outliers.
3.2.4.4 Dependency on Load
Relevant data are shown in Table B-20 and on Figures 3-14 and 3-15.
The mass rate of S02 correlated linearly with gross load and with
heat input according to the following relationships:
y = 55.5 x + 379.5
y = 5.956 x' - 40.69
where:
y is S02 emission in Ibs/hr
x is gross load in megawatts
x1 is heat input in MMBTU/HR
The data of Tests 2 and 9 were rejected as outliers, see 3.2.4.3.
Concentrations of S02 and SO^ in the flue gas increased with increas-
ing load from 46MW to 92MW.
3-51
-------
FIGURE 3-15
MEASURED SOg EMISSIONS vs. HEAT INPUT
TEST SERIES ]
O
8000
on
ro
O- Outliers (Not included in
Regression Analysis)
500
600
700
800 900 1000
HEAT INPUT (MMBTU/HR)
100
1ZOO
-------
3.2.4.5 Dependency on Other Boiler Control Settings
Relevant data are included in Tables 3-4 and B-20.
Other independent variables with the potential for affecting S02 emis-
sions are sulfur in coal and excess air levels. Confidence limits (95%) of
sulfur in the coal were 3.90% sulfur to 4.26% sulfur (dry, ash free basis),
see Table 3-4. Based on those confidence limits, at a coal rate of 103,800
Ib/hr, the true mean input sulfur would be expected to be within the limits
of 3200 Ib/hr to 3500 Ib/hr with a corresponding variation in the true mean
emission rate of sulfur. As an approximation, the mean emission rate as S02
would not be expected to vary beyond the limits of 6400 Ib/hr to 7000 Ib/hr
at full load.
Excess air will affect emission concentrations due to dilution effects.
The major effects on S02 concentrations were excess air and load factor. At
the 46MW load level, S02 + S03 concentrations averaged 1827 ppmv versus 2548
ppmv at 92MW and 2834 ppmv at 115MW. The major effect appears to be from
dilution by excess air.
3.2.4.6 Potential Effects on Demo. Unit Operation
Relevant data are included in Tables B-20, B-21 and on Figure 3-16.
Increasing levels of sulfur trioxide (S03) entering the absorber with
the flue gas will form more sulfate in the absorber solution which will re-
quire higher purge rates. Higher oxygen levels could result in the formation
of more of the inactive sodium salts in the absorber solution, which would in
turn result in higher purge rates or higher antioxidant feed rates with subse-
quent higher raw material costs. Table B-20 shows ratios of S03 and of oxygen
to S02. The observed S03/S02 ratios are summarized as follows:
3-53
-------
FIGURE 3-16
S02/02 vs. GROSS LOAD
TEST SERIES 1
CO
en
- Outliers (Not included in
Regression Analysis)
50
60
70
80 90 100
GROSS LOAD (MM)
TO
120
-------
Load S03/SQo
46MW 0.033
92MW 0.022
115MW 0.025
The boiler is operated at higher combustion air levels at loads below 92MW.
Also, there may be temperature differences in the furnace affecting reaction
rates at varying loads. An attempt was made to show the effect of increased
combustion air on the SO^/SOp ratio by running a set of special tests during
which an excess over normal of combustion air was used. The results are
summarized as follows:
Mean
Mean Excess Combustion Air, %
Mean Gross Load, MW
so?/:
Test No's. Normal
8, 14 0.011
15
10, 16 0.039
0.025
15
114.7
j\Jfy
Off Normal
0.034
0.033
0.018
0.028
26
109.7
While the off-normal mean of the S03/S02 ratio is slightly larger than the
mean of that ratio at normal operation, the hypothesis that excess air in-
creases the SOo/SOn ratio can only be claimed to a confidence level of 57%
on the basis of this data. This is far below the classical 95% or 99% con-
fidence level usually required in making a definite conclusion.
Ratios of S02/02 are shown on Figure 3-16 as a function of load at
normal operation. As expected, oxygen levels relative to the S02 levels
increase with decreasing load factor.
3-55
-------
The results from the special tests during which an excess over normal
of combustion air was used showed no decrease in the S02/02 ratio when com-
pared with results during normal operation.
3.2.5 NOx Emission Levels
Relevant data are found in Table 3-7.
Table 3-7 lists the volumetric concentration and mass emission rates
for Test Series One (normal operation). Design values for NOx emissions were
not available. Thus, discussion of the results has been limited to comparison
with the emission standard, dependence on boiler control settings, and poten-
tial effects on Demo. Unit performance.
3.2.5.1 NQx Emissions Compared to the New Source Performance Standard
The emission standard for solid fossil fuel is 0.7 pounds per million
Btu heat input. NOx emissions were below this standard for all of the tests
at normal operation. The data of one test, at full load level, was rejected
as an outlier based on emissions (Ib NOx/MMBTU) being greater than two
standard deviations from the calculated mean.
3.2.5.2 Dependency on Boiler Control Settings
The mass emission rates are expected to be dependent primarily on load
and on excess air. The rates increased with load and decreased with excess
combustion air during tests at normal operation, see Table 3-7. However,
since excess air is controlled at higher rates for the lower load levels, it
is possible that the variations in NOx rates are due entirely to load effects.
3.2.5.3 Potential Effects on Demo. Unit Performance
The oxidizing character of nitrogen dioxide (N02) may result in the for-
mation of inactive sodium salts in the absorber in addition to potential for-
mation from excess oxygen in the flue gas (see 3.2.4.6). In Table 3-7, con-
centrations of nitrogen oxides are expressed as the mol ratio, N0x/S02. No
3-56
-------
variation of this ratio with variations of excess combustion air is apparent
from examination of these data. It should be noted that the NOx used in the
ratio is the total mols of nitrogen oxides assumed to be NC^ when in fact the
NOx is expected to include some nitric oxide (NO). The NO is readily oxidized
but the rate of formation of NO^ in the flue gas is said to be very low, resul-
ting in only 5%-10% of the NOx as N02 at the stack outlet^5). The oxidizing
potential for NO is significantly lower than that for N02. Thus, the NOx/SO-
ratio will serve as only a general indication of the potential for oxidizing
effects.
The formation of NO is dependent on firing temperatures and on the
concentration of oxygen within the flame zone of the boiler. Thus, one would
predict that a variation in the excess air for combustion would cause a vari-
ation in NOx formation. The effect of increased combustion air was examined
by running a set of special tests at full load. The results are summarized
as follows:
N0x/S00
Mean
Mean Excess Air, %
Test No's. Normal
8, 14 0.047
9, 15 0.025
10, 16 0.086
0.053
15
i_
Off Normal
0.021
0.019
0.039
0.026
25
The decrease in relative NOx concentration with an increase in excess air was
unexpected. A possible explanation is that the NOx concentration may be de-
pendent on the change in operating procedure employed to increase the excess
air level.
3-57
-------
3.2.6 Parti cul ate Emissions
Particulate matter was sampled simultaneously at both the inlet to the
air preheaters and the outlet of the ID fans. Particulate sampling and analy-
ses were done in accordance with Federal Register6' methods at the outlet and
ASME^7' methods inlet and outlet. ASME sampling at the inlet was necessary
because of the high grain loadings expected. ASME sampling at the outlet was
performed to obtain corresponding data for evaluating precipitator (ESP) per-
formance.
3.2.6.2 Comparison with Boiler and Demo. Unit Design
Relevant data are shown in Table B-22 and on Figures 3-17, 3-18 and
3-19.
The Mitchell No. 11 design is based on coal containing 9.89 wt. per-
cent ash. Boiler specifications assume that 10% of the total ash is collect-
ed ahead of the air heater outlets. ESP is designed to be 98.5% efficient.
Because of dust configuration, sampling ports at the air heater outlets could
not be used. Thus, particulate emissions were measured at the inlet duct to
the air heaters. To calculate theoretical emissions, design coal ash content
of 9.89%, 90% of total ash at the air heater inlet, and an ESP efficiency of
98.5% were assumed.
Figures 3-17, 3-18, and 3-19 compare measured emission rates with the
corresponding theoretical values over the operating load range. Without soot
blowing, measured particulate rates before the precipitator were lower than
theoretical rates by as much as one-third. However, inlet particulate matter
was sampled by the ASME method only. Clasically, the ASME method gives lower
results than those obtained with approved EPA methods; this phenomena may be
observed by comparing ASME method results obtained at the outlet with EPA
method results obtained simultaneously at the same sampling position. Aver-
age particulate emission rates by the EPA method are almost double the aver-
age results obtained by the ASME method. With soot blowing, the particulate
3-58
-------
FIGURE 3-17
PARTICULATE EMISSIONS (LB/HR) INLET APH vs. GROSS LOAD
TEST SERIES 1 & 3
nooo-
O - WITHOUT SOOT BLOWING
9- WITH SOOT BLOWING, NOT INCLUDED IN LINEAR REGRESSION
A- THEORETICAL
CO
i
en
CC
x:
9000-
o
»—i
in
LU
7000'
5000-
3000'
O
O
1000;
50
60
70 80 90
GROSS LOAD (MW)
100
110
120
-------
en
o
o
in
•z.
o
1300
1200
1100
1000
900
800
700
600
500-
400-
300-
200-
100-
FIGURE 3-18
PARTICIPATE EMISSIONS (LB/HR) OUTLET ID FAN vs. GROSS LOAD
TEST SERIES 1 & 3
A- ASME METHOD
A - ASME WITH SOOT BLOWING
O- EPA METHOD
• - EPA WITH SOOT BLOWING
D- THEORETICAL
• - DEMO UNIT DESIGN
(9
50
70
80
GROSS LOAD
90
130
12C
-------
co
CTi
u
c/i
0.60-
0.50-
K 0.40-
to
y 0.30-
0.20-
0.10-
•'0
FIGURE 3-19
PARTICULATE EMISSIONS (GR/SCF) OUTLET ID FAN vs. GROSS LOAD
TEST SERIES 1 » 3
A - ASME METHOD
A - ASME WITH SOOT BLOWING
O- EPA METHOD
• - EPA WITH SOOT BLOWING
D - DEMO UNIT DESIGN
• - THEORETICAL
Theoretical Linear Regression
60
70 80 90
GROSS LOAD (MW)
TOO
120
-------
rates before the precipitator were higher than theoretical when operating at
90% load factor (92MW).
Outlet particulate emission rates by the method were higher than the-
oretical at 92MW and 11 BMW and about equal to theoretical at 46MW. ESP
efficiency is discussed in 3.2.6.6. The poor collection efficiency resulted
in particulate emissions higher than Demo. Unit design. At 92MW load, par-
ti cul ate emission rates averaged 708 Ib/hr by the EPA method compared to
Demo. Unit design values of 550 Ib/hr. Measured grain loading was 0.24 gr/
ACF vs. 0.20 gr/ACF design.
3.2.6.3 Comparison with the New Source Performance Standard
Relevant data are included in Table B-22.
All tests exceeded the Federal New Source Performance Standard of 0.10
Ib/MMBTU maximum two-hour average. The emissions at loads of about 46MW were
only slightly higher than the standard whereas the emissions at 92MW and
115MW were much higher than the standard.
3.2.6.4 Dependency on Load
Relevant data are included in Table B-22 and on Figures 3-17, 3-18 and
3-19.
Load dependency is illustrated on Figures 3-17, 3-18 and 3-19. Par-
ticulate emissions increased with load at inlet the air heater as expected.
At the outlet the emissions were more dependent on load than would have
occurred with the ESP performing at design efficiency.
3.2.6.5 Dependency on Other Boiler Control Settings
Relevant data are included in Table B-22 and on Figures 3-17 and 3-18.
3-62
-------
Figure 3-17 shows that the mass emission rates inlet the air heaters
were significantly higher with soot blowing than without soot blowing at 92MW.
However, no effect from soot blowing is apparent after the precipitator.
No definite correlation with ash content of the coal can be discerned.
Figure 3-17 indicates that measured values of particulate rates inlet the air
heaters by the ASME method were substantially less than theoretical values at
all loads.
Dependency on collector efficiency is discussed in the following
subsection.
3.2.6.6 Collector Efficiency
Relevant data are included in Table B-22.
The dust collector efficiency varied from 89.3% to 98.9% and averaged
94.7% with normal operation of the boiler. The highest efficiencies were
experienced at 46MW (96.5%) and the lowest efficiencies were experienced at
115MW (90.0% to 92.4%). Design efficiency is 98.5%. There was no apparent
affect on the efficiency from soot blowing at 92MW. Operating performance
of the collector is discussed in Section 3.4.
3.2.6.7 Particle Size
Relevant data are shown in Tables 3-8 and 3-9 and on Figures B-l thru
B-9.
Size distribution of the particulate matter was determined at the pre-
cipitator outlet location by an in-situ Brinks Cascade Impactor. The cascade
impactor has the capability to separate particles into six different size
categories, varying from greater than seven microns (y) in diameter to less
than O.ly. However, at the higher sampling rates required to insure adequate
loading of the last stages, the minimum diameter of particles trapped in the
first stage decreases to 3.5y. On the average, 50% of the particulate mass
3-63
-------
was less than 3.0y diameter. Tables 3-8 and 3-9 include the pulverized coal
s':ze for comparison.
The particle sizing results in some cases are biased by sample carry-
over from the first stage of the sampler. The effect of this is to shift the
mass median diameter results downward. In a few cases the carry-over was sig-
nificant enough to invalidate the test results. For Test Series One, tests No.
16 and 17 were invalidated due to inadequate sample. The results of test No.
10 were affected by carry-over from the first stage of the sampler.
The overloading of the first stage of the impactor was due to having
to collect a large enough sample to insure adequate loading on the last
stages to weigh accurately. The heavy loading on the first stage is sugges-
tive of a significant fraction of the particulate matter being larger than
5y in diameter. The result is to insure a slight conservative bias error;
that is, a bias error toward larger fractions of smaller size particles.
3.2.6.8 Potential Effects on Demo. Unit Performance
Particulate will be removed from the flue gas by an orifice contactor
located ahead of the absorber. A removal efficiency of 70% is expected at
particulate rates of 550 Ib/hr. Higher than design inlet grain loadings might
result in higher grain loadings in the gas to the absorber. Additionally,
higher grain loadings will increase fly ash purge rates with a subsequent in-
crease in purge water requirements. Increased grain loadings to the absorber
will require more frequent washings of the fly ash filter. Also, there are
potential effects on operation of the Demo. Unit from some of the trace metals
present in the particulate matter. Particulate particle size could also affect
the removal efficiency of the orifice contactor and result in higher grain load-
ings to the absorber. The grain loading and particle size measurements have
been documented in the preceding subsection. Trace element emissions are re-
ported in 3.2.7.
3.2.7 Trace Element Emissions
Relevant data re included in Table 3-15.
3-64
-------
TABLE 3-15
RATIONALE FOR TRACE ELEMENT SELECTION
Antimony
Arsenic
Beryllium
Cadmi urn
Calcium
Chlorine
Chromium
Copper
Fluorine
Iron
Lead
Magnesium
Manganese
Mercury
Nickel
Selenium
Tin
Vanadi um
Zinc
Toxicity and concentration
Toxicity
Toxicity
Toxicity
Potential process effect
Potential process effect
Potential process effect
Potential oxidation catalyst
Pollutant
Potential oxidation catalyst
Toxicity and concentration
Potential process effect
Potential oxidation catalyst
Toxicity
Toxicity
Toxicity and concentration
Toxicity and concentration
Potential oxidation catalyst
Toxicity
3-65
-------
A group of 19 trace elements were selected for analysis. The selection
was based on initial characterization testing (performed by TRW, July 6-13,
1973) to define concentrations, on a literature review, and on other TRW stud-
ies. The rationale for selection are indicated in Table 3-15.
3.2.7.1 Concentration Effects
Relevant data are included in Table 3-16.
Table 3-16 ranks the trace metals (those present as particulate in the
flue gas) by concentration effect (C.E.). Concentration effect shows the de-
gree of concentration of an element in the fly ash emissions over its concen-
tration in ash in the coal. The ranking indicates that the higher the C.E.
number the greater the tendency of the element to escape collection due to as-
sociation with fine particulate and/or association with high resistivity par-
ti cul ate. Concentration effects greater than one were indicated for 10 out pf
16 particulate species analyzed. Similar concentration effects were observed
during off normal operating conditions (Test Series 2).
3.2.7.2 Concentrations in Flue Gas Particulate
Tables 3-17 and 3-18 show the concentrations of trace elements in the
coal and in the fly ash at the precipitator outlet.
3.2.7.3 Emission of Halogens
Relevant data are included in Tables B-5, B-6, B-7, B-8, B-23, B-24,
B-25, B-26, B-27 and B-28.
Fluoride and chloride concentrations were determined in the coal, col-
lected fly ash, and the flue gas. Because of sampling constraints, the halo-
gens in the emissions were determined only during Test Series 3 (Tests 22 and
23). The results are summarized as follows:
3-66
-------
TABLE 3-16
TRACE METALS CONCENTRATION EFFECT
TEST SERIES 1
As Fired Flue Gas
Se 8.38
Cd 4.15
As 5.75
Ni 135
Sn 33.80
V 186
Cr 474
Be 8.46
Cu 102
Pb 152
Zn 305
Ca 20800
Fe 72900
Sb 271
Mn 338
Mg 635
Parti culate^
850
65.5
77.8
452
88.0
415
971
15.4
141
191
298
17400
58600
203
218
155
C.E.(2)
101.43
15.78
13.53
3.35
2.60
2.23
2.05
1.82
1.38
1.26
0.98
0.84
0.80
0.75
0.64
0.24
^ 'ib trace element 1n6
Ib ash > IU
Concentration Effect, ratio of element concentra-
tion in flue gas particulate to element concentration
in coal ash.
3-67
-------
TABLE 3-17
TRACE METALS CONCENTRATIONS IN COAL, PPM
As Fired Coal
(Test Series 5)
(1)
As Fired
(Test Series 1)
Fe
V
Mn
Ca
Ni
Sn
Mg
Zn
Cr
Cu
Pb
Be
Sb
Se
As
Cd
126914
65778
35024
26906
21995
10699
91 2T
316
138
118
110
0.806
0.806
0.806
0.399
0.073
72900
186
338
20800
135
34
635
305
474
102
152
8.46
271
8.38
5.75
4.15
(1)
Ib Trace Element 1n6
Tb~A~shx IU
3-68
-------
TABLE 3-18
TRACE METALS CONCENTRATIONS IN THE FLUE GAS, PPM
Flue Gas Parti oil ate
(Test Series 5)
Flue Gas Particulate^
(Test Series 1)
Fe
Mg
Ca
Zn
Sn
Ni
Cr
Pb
Cu
Mn
Be
Sb
Se
V
As
Cd
225787
10006
9149
2180
587
352
179
176
160
131
0.106
0.106
0.106
0.106
0.052
0.011
58600
155
17400
298
88.0
452
971
191
141
218
15.4
203
337
415
77.8
65.5
(1)
Ib Trace Element In6
TFIsfi x IU
3-69
-------
Test
F" in Coal, ppm
F" in Ash, ppm
F" in Flue Gas, ppm w/w dry
F" in Flue Gas, Ib/hr
Cl~ in Coal , ppm
Flue Gas Total, Mlb/hr dry
Cl~ in Ash, ppm
Cl~ in Flue Gas, ppm w/w dry
Cl" in Flue Gas, Ib/hr
22_
125
143
7.0
9.3
300
1326
Nil
9.2
12.2
23
116
134
9.9
12.1
300
1223
303
13.2
16.1
Fluorides and chloride were determined on the as fired coal and on
the collected ash for the applicable tests during which 3% S coal was burned.
Average concentrations in the coal were 95 ppm F" and 300 ppm Cl~ for 17
tests. Chloride is reported only to the nearest 100 ppm. Average concentra-
tions in the collected fly ash were 100 ppm F" and less than 100 ppm Cl" for
15 tests. No chloride was detected in the ash for eight of the tests. As a
rough approximation, about 10% of the fluoride was removed with the collected
fly ash. A corresponding approximation of chloride removal was not possible
because of the large number of tests showing no chloride in the ash.
3.2.7.4 Emission of HpS. Mercury
Hydrogen sulfide and mercury emissions were determined during Test
Series 3. Less than the minimum detectable quantity of H^S was being emitted,
i.e., less than 0.3 Ib/hr (0.19 pptnv). Indicated presence of mercury was also
less than the minimum detectable quantity, or less than 0.001 Ib/hr (0.001
ppmv).
3-70
-------
3.2.7.5 Carbon Monoxide and Hydrocarbons
Carbon monoxide and total hydrocarbons were monitored continuously
during Test Series 3. Ambient air Inleakage into the sampling system
aborted these tests. Carbon monoxide and hydrocarbons will be monitored
continuously during the Demonstration.
3-71
-------
3.3 FLUE GAS CHARACTERIZATION - OFF NORMAL OPERATION
This section describes the results of the characterization of outlet
flue gas at operating conditions other than normal (Test Series 2). Outlet
flue gas volume, physical characteristics, emission concentrations and rates
of SOx, NOx and particulate matter as well as other flue gas constituents
were measured and the data evaluated.
3.3.1 Scope of Characterization
Testing was performed in triplicate at approximately 100% load (115MW),
with 3.2% S coal and without soot blowing to examine the following effects:
• High grain loading (test no's. 11-13) - to simulate
effect of other boilers on Demo. Unit performance
• Excess of combustion air (test no's. 14, 15, 18) - to maxi-
mize NOx formation
• Excess of air inleakage (test no's. 19-21) - to maximize
flue gas volume
Twelve additional tests were performed using a low sulfur coal. The
results are discussed in Section 3.6. The purposes of the characterizations
are those described in 3.2.1.
3.3.2 Flue Gas Profile
Relevant data are summarized in Table B-29.
Table B-29 is a summary of the flue gas characterization data for Test
Series 2 during which grain loading, combustion air and air inleakage were
increased. This data provides documentation of the baseline flue gas pro-
file for later comparison with the results for determining the effects of the
stated off normal conditions on Demo. Unit performance.
3-72
-------
3.3.3 High Grain Loading
Relevant data are included in Table B-29 and B-30.
In order to simulate the effect of other boilers on Demo. Unit perfor-
mance, the last of three ESP fields was not energized. All tests were at
100% load. At this operating condition, the design dust collection efficiency
drops from 98.5% to 95.6%. Measured collection efficiencies were as follows:
Test 11 51.6%
Test 12 82.0%
Test 13 82.1%
Average efficiency with all three fields in operation was 96.2%.
Particulate emissions averaged 1843 Ib/hr compared to an average of
807 Ib/hr at full load with all three fields in operation. Grain loading was
0.52 gr/ACF with two fields versus 0.25 gr/ACF with three fields. Within the
limits of the test procedure, there was no apparent difference in the particle
size distribution between two field and three field operation. Stage to stage
carryover was indicated during tests 12 and 13 but not enough to invalidate
the tests (see 3.2.6.7).
3.3.4 Excess Combustion. Air
Relevant data are included in Table B-29.
An excess of air above normal was added to the combustion zone to at-
tempt to change the NOx concentration relative to SOg. The purpose was to
provide another level of NOx concentration relative to S0« concentration and to
examine its effect on Demo. Unit performance. The Baseline results are repor-
ted in 3.2.5.3. The relative NOx concentration decreased at the higher level
of excess combustion air whereas just the reverse was expected.
3-73
-------
3.3.5 Excess Flue Gas Volume
Relevant data are included in Table B-29 and B-31.
An excess of inleakage air was added by opening access doors at the
air heater outlets at full load. During the first test of the three repli-
cate test set, the doors were only partially opened with only a minimum in-
crease in flue gas rate resulting. The doors were wide open during the other
two tests and about a 15% increase over normal operation of flue gas volume
occurred. Affect on the more important flue gas parameters are summarized as
follows:
Normal Volume Excess Volume
Volume, Macfm 403 468
Mass Rate, Mlb/Hr. 1273 1510
S02, ppm 2764 2247
Particulate, gr/ACF 0.25 0.19
Excess Air, % 34 57
3-74
-------
3.4 PRECIPITATOR PERFORMANCE
3.4.1
Relevant data are shown in Table 3-19.
The flue gas from Mitchell No. 11 is removed by a cold end electro-
static precipitator (ESP) manufactured by American Standard Company. The
specifications for this ESP are listed in Table 3-19. The measured ESP
efficiencies were discussed in 3.2.6.6 and 3.3.3. In the discussion to fol-
low, the performance of the ESP as it affects the parti cul ate removal effi-
ciency is assessed. The parameters selected for indicating effects on per-
formance are specific corona power and migration velocity. The specific
corona power may be expressed either as watts per gas flow rate or as watts
per collector plate area. A loss in efficiency results from an inability to
maintain design specific power levels. Possible causes are:
t High dust resistivity
• Dust accumulation on the electrodes
t Unusually fine particle size
• Improper rectifier and control operation
e Internal failures such as broken wires, insulator fail-
ure, dust accumulation above hopper levels
The other critical parameter is the migration velocity w, a rate constant
describing the particle velocity component in the direction of the collection
electrode. Its effect on efficiency is expressed in the Deutsch-Anderson
Eff . = 1 - exp(- w)
equation^ ' as follows:
where,
Eff. = collection efficiency
A = electrode area
Vg = rate of gas flow
w = particle migration velocity
3-75
-------
TABLE 3-19
PRECIPITATOR SPECIFICATIONS
Design CFM 410,000
VF 290
Inlet,gr/SCFD 3.5 to 6.5
AP,"H20 O-4
Removalt% 98.5
Rate Constant, Ft./Sec. 0.5
Plates, Ft.2 58,240
Treatment Length, Ft. 17.3
# Fields 3
# Ducts 56 (99")
Wire Ft. 40,320 (07")
Wire Rating, ma./Ft. 0.08
Treatment Time, Sec. 3.2
Delivery July 1969
# Plate Rappers 32
# Wire Vibrators 12
Hopper Ash Capacity Minimum 8 hrs.
# Bus Sections 6
Plate Height, Ft. 30
Energization Half Wave
Rating KV 70
Rating ma. 1800, 800, 600
Provision in the unit for another field, 6' treatment length
above hopper #2, can be added later
Expected removal w/field #1 only 87.7%
Expected removal w/fields #1-2 only 95.6%
Expected hopper #3 collects 2.8% of the dust
Ash removal pneumatically by 3 lines (fields 1, 2, 3)
No. ash hoppers - 12
3-76
-------
The migration velocity varies with resistivity, particle size, gas velocity
distribution, reentrainment losses and other factors. It is being determined
experimentally by inserting efficiencies and gas flow into the Deutsch-Ander-
son equation.
To evaluate performance, the efficiencies are correlated with specific
corona power to assess the power level effects. The efficiencies are then
used to calculate migration velocity which will be correlated with such vari-
ables as specific corona power and sulfur content of the flue gas. Particle
size distribution and resistivity are not known.
3.4.2 Operating Performance
Relevant data are included in Tables B-32 and B-33 and on Figures 3-20
and 3-21.
Figure 3-20 indicates some increase in efficiency with specific corona
power, although the data are widely scattered. Figure 3-21 is a plot of mi-
gration velocity vs. the concentration of S03 in the flue gas. No correlation
can be discerned within the limits of S03 concentrations observed. Also, there
appears to be no correlation of migration velocity with specific corona power.
3-77
-------
FIGURE 3-20
Collector Efficiency (X) vs. Useful Corona Power (watts/1000 cfln)
Test Series 1, 2 & 3
991
98-
97
96'
95'
94-
oo*l
-------
FIGURE 3-21
MIGRATION VELOCITY vs. SO, CONCENTRATION
TEST SERIES 1, 2/& 3
0.5-
LU
t
" — '
£0.4-
OJ E
-tj 3
>•
•z.
0
ce
o
s
0.2"
o.r
On
A
* A
A
A A A
.
A
A
A A
A
ih on vi an Rn fih 7h an qn inn
S03 (ppm)
-------
3.5 CYCLICAL AND TREND EFFECTS
3.5.1 Scope
Relevant data are included in Tables 3-2Q and 3-21.
A limited number of parameters were selected for displaying trends or
cycles in the measurements. Selection was of those parameters which:
• Are expected to impact boiler operating performance and
emission levels (fuel characteristics).
• Show the thermal efficiency (heat rate).
• Show performance of air heaters.
• Show performance of ESP.
Boiler age and maintenance history are also important trend effects.
Sixty percent of the tests were performed during May 1974 and the remaining
tests were performed during April and May 1975. This gap of nearly a full
year in the field testing allows the examination of the data for long term ef-
fects due to boiler age and maintenance history. Tables 3-20 and 3-21 present
the date and time of testing and the operating conditions specified for testing.
The parameters examined for cyclical and trend effects are as follows:
• Coal parameters -
- HHV, dry, ash free basis
- S, dry, ash free basis
- C, dry, ash free basis
- H, dry, ash free basis
- 0, dry, ash free basis
- Ash, dry basis
- H20
• Air temperature -
- air humidity, Ib/lb dry air
t Heat rate
3-80
-------
TABLE 3-20
FIELD TEST SCHEDULE
Normal Fuel (3% Sulfur)
Test
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Date
5/15/74
5/17/75
5/17/74
5/19/74
5/19/74
5/20/74
5/20/74
5/22/74
5/22/74
5/23/74
5/23/74
5/24/74
5/24/74
5/25/74
5/25/74
5/26/75
5/26/74
5/27/74
5/27/74
5/28/74
5/28/74
4/17/75
4/18/75
Start Time,
Hours
1142
0903
1500
0847
1347
0846
1332
1333
1900
0955
1500
0855
1420
0923
1415
0855
1340
0850
1530
0940
1500
1540
1308
Load, Gross
(MW)
46
92
92
92
92
92
92
115
115
115
115
115
115
115
115
46
46
115
115
115
115
115
115
Soot Blowing
Status
Off
Off
On
Off
On
Off
On
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Off
Coal Sulfur,
%
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Off Normal
Condition
None
None
None
None
None
None
None
None
None
None
Ash
Ash
Ash
XSA
XSA
None
None
XSA
VOL
VOL
VOL
None
None
CO
00
ASH - High grain loading; XSA - Excess combustion air; VOL - Excess air inleakage
-------
TABLE 3-21
FIELD TEST SCHEDULE
Low Sulfur Fuel (1% Sulfur)
Test
No.
24
25
26
27
28
29
30
31
32
33
34
35
Date
4/25/75
4/25/75
4/26/75
4/26/75
4/28/75
4/28/75
4/29/75
4/29/75
4/30/75
5/01/75
5/01/75
5/02/75
Start Time,
Hours
0945
1500
0938
1500
0915
1405
0900
1345
0845
0945
1430
0835
Load, Gross
(MW)
111
111
46
46
92
92
92
92
92
111
92
111
Soot Blowing
Status
Off
Off
Off
Off
Off
On
Off
On
Off
Off
On
Off
Coal Sulfur,
%
1
1
1
1
1
1
1
1
1
1
1
1
Off Normal
Condition
None
None
None
None
None
None
None
None
None
None
None
None
co
i
00
ro
-------
• Air Heater Temperatures -
- gas out ID fan
- gas out APH
- gas in APH
- air out APH
t ESP Specific Power, Overall
Tests 1-23 were run during operation with normal fuel (3% S). Tests 24-35
were run during operation with low sulfur fuel (]% S). Short term trends,
if any, are indicated by plotting 6-point running averages. A limited assess-
ment of long term trends was possible by comparing 1974 and 1975 data.
3.5.2 Fuel Characteristics
Relevant data are shown in Figures 3-22, 3-23, 3-24, 3-25, 3-26, 3-27
and 3-28.
Trend and cycle history is shown on the indicated figures. With the
exception of ash and water content, the composition parameters for the coal
are presented on a dry, ash free basis. Significant observations are as fol-
lows:
a. Heating value was stable with time. The low sulfur coal
showed the highest cyclical variations.
b. Sulfur in the high sulfur coal was stable with time. One
high value for sulfur in the low sulfur coal (Test 27)
suggests contamination with a higher sulfur coal.
c. A slight upward trend in the carbon content of the high
sulfur coal was indicated. Also, Tests 22 and 23, per-
formed one year later than the other tests, were signif-
icantly higher in carbon content. The low sulfur coal
showed the highest cyclical variations.
d. Hydrogen was stable with time except for lower concen-
trations during Tests 22 and 23.
3-83
-------
FIGURE 3-22
HIGH HEATING VALUE OF RAW COAL (HBTU/LB) ON A DRY, ASH FREE BASIS
CO
i
14.'4
14.3
14.2
14.1
14.0
13.9
13.8-
13.7:
»J_^__l__^_^__l_^^i_la
27 28 29 30 31 32 33 34
10
11 12 13 14 15
16
17 18 19
Test No.
20 21 22 23
24 25 26
35
Running Average
-------
FIGURE 3-23
WEIGHT PERCENT SULFUR IN RAW COAL ON A DRY, ASH FREE BASIS
CO
CO
en
10
11 12 13 14 15 16 17 18 19 20 21
Test No.
22 23
24 25 26 27 28 29 30 31 32 33
Running Average
-------
FIGURE 3-Z4
HEIGHT PERCENT CARBON IN RAM COAL ON A DRY, ASK FREE BASIS
GO
CO
en
24 25 26 27 28 29 30 31 32 33 34 35
17 18 19
Test No.
Running Average
-------
CO
00
FIGURE 3-25
HEIGHT PERCENT HYDROGEN IN RAW COAL ON A DRY, ASH FREE BASIS
10 11 12 13 14 15 16
17 18 19
Test No.
20 21 22 23
24 25 26 27 28 29 30 31 32 33 34 35
Running Average
-------
FIGURE 3-26
WEIGHT PERCENT OXYGEN IN RAH COAL ON A DRY, ASH FREE BASIS
LO
I
03
oa
Z 34 5 6 / 8 9 IU II \i 3 14 15 It) II IB It) ZU Z
-------
FIGURE 3-27
WEIGHT PERCENT ASH IN RAW COAL ON A DRY BASIS
15
14
13
OJ
00
vo
11
10
2 3
11 12 13
18 19 ZO Zl
Test No.
34
Running Average
-------
FIGURE 3-28
WEIGHT PERCENT WATER IN RAW COAL ON AN ASH FREE BASIS
co
10
o
10 11 12 13 14 15 16
17 18 19 20 21
Test No.
22 23
24 25 26 27 28
I I
29 30 31
32 33 34 35
Running Average
-------
e. A slight downward trend in the oxygen content of the
high sulfur coal was indicated (Tests 17 thru 23).
Oxygen values for Tests 22 and 23 were lower than for
the other high sulfur tests. Oxygen in the low sulfur
coal was higher than in the high sulfur coal and also
showed the highest cyclical variation. Oxygen in coal
is determined by difference and the downward trend may
indicate a dependence on the upward trend of the carbon
content.
f. Ash in the high sulfur coal was stable with time except
for higher ash contents during Tests 22 and 23. Ash in
the low sulfur coal was slightly higher than in the high
sulfur coal.
g. Moisture in the high sulfur coal showed a slight down-
ward trend but increased during Tests 22 and 23. Mois-
ture in the low sulfur coal was significantly higher.
It was pointed out in earlier discussions that scatter of the high sulfur
coal component data was minor. Thus, the indicated trends and cycling have
probably had minimum impact.
3.5.3 Heat Rates
Relevant data are shown on Figure 3-29.
The cycling is due primarily to load effects. Because of the depen-
dence on load, no trend analysis was attempted.
3.5.4 Air Heater Performance
^
s
Figure 3-30 includes the trend lines for inlet and outlet air preheater
temperatures as well as the stack temperature (outlet ID fan). Of interest is
the outlet air temperature approach to inlet flue gas temperatures and the
overall AT of the flue gas across the air heaters. There was no apparent long
term trend over the one year period encompassing the field tests. The air
heaters were washed just prior to start of the field tests in May 1974.
3-91
-------
FIGURE 3-29
GROSS HEAT RATE (MBTU/KHH)
ro
1 34 6
b id i^ 12! is 14 ib ie iV ii il> 26 21
24 25 2^ h 28 29 3|) 31* 32 s's 314 35'
-------
FIGURE 3-30
AIR HEATER TEMPERATURES (°F)
CO
I
00
200
-111 MW—
Inlet APH,
Gas
Outlet APH, Air
Outlet ID Fan,
Gas
9 10 11 12 13 14 15 16 17 18 19 20 21
Test No.
24 25 26 27 28 29 30 32 32 33 34 35
-------
3.5.5 Precipltator Performance
Trend and cyclical plots of useful corona power in watts per 1000 cfm of
flue gas are shown on Figure 3-31. Significant observations are as follows:
a. An upward trend during the high sulfur tests reflects in-
creased specific power requirements during the 46MW tests
and during the high excess air and high air inleakage
tests. Power was reduced during Tests 11, 12 and 13 due
to operation with only two fields.
b. Somewhat more specific power was consumed during the low
sulfur tests. Again, higher power use reflects operation
at 46MW (Tests 26 and 27).
3.5.6 Ambient Conditions
Figure 3-32 includes the trend and cyclical plots of the humidity and
temperature of the inlet air during testing. Significant observations are
as follows:
a. Air temperature varied from 53°F to 79°F during the high
sulfur tests. No definite upward trend was indicated dur-
ing a test period extending through most of the month of
May.
b. Humidity varied from 0.0045 Ib/lb dry air to 0.0135 Ib/lb
dry air during the high sulfur tests. No trend was in-
dicated.
c. Temperature varied from 48°F to 69°F during the low sul-
fur tests. An upward trend occurred during the test
period extending from April 25 to May 2.
d. Humidity varied from 0.0045 Ib/lb dry air to 0.0088 Ib/lb
dry air during the low sulfur tests. A slight upward
trend was indicated.
3-94
-------
FIGURE 3-31
USEFUL CORONA POWER (WATTS/1000 CFM)
vo
Ol
300
250
200'
isd
sd
12 345 6 78 9 lo 11 iz 13 14 15 li 17 18 19 20 21
Test No.
24 25 26 27 28 29 30 31 32 33 34 35
Running Average
'HIGH GRAIN LOADING TESTS
-------
FIGURE 3-32
INLET AIR TEMPERATURE (°F)
HUMIDITY (LB/MLB AIR)
ID
01
ul 70-
o
| 60-'
S-
5 50-
4J
OJ
"c
" 40-
3 4
10 11 12 13 14 15
16 T7 IB 15
Test No.
ZO 2T
•5?
Running Average
-------
3.6 FLUE GAS CHARACTERIZATION - LOW SULFUR COAL
This section describes the results of a comprehensive test program for
characterizing the outlet flue gas when a low sulfur coal is burned. The sul-
fur in the coal varied from 0.7% to 1.8% for this test series (Test Series 5).
The purpose was to establish a baseline profile of the flue gas with the same
low sulfur coal which will be burned while conducting special tests during
the Demonstration. The special tests to be conducted during the Demonstration
are to establish the operating performance of the Demo. Unit when treating gas
with low inlet concentrations of S02.
3.6.1 Scope of Characterization
All operating conditions were normal with the exception of the coal
burned. Test Series One (normal operation) was repeated so that data was col-
lected at three levels of load plus an additional test set with soot blowing
at one level of load (80% load factor).
The remainder of section 3.6 is devoted to a summary of the flue gas
characterization results and their comparison with results when 3% S coal was
burned. The results are presented as follows:
• A detailed physical-chemical profile is presented and
summarized. The detailed data base fsr included in Appen-
dix B.
o Measured flue gas parameters are compared with the corres-
ponding Demo. Unit design parameters.
t Flue gas conditions having a potential effect on Demo. Unit
performance are discussed.
0 Baseline emission levels are documented.
3.6.2 Flue Gas Profile
Relevant data are included in Tables 3-22 and B-34, and in Figures
B-10, B-ll, B-12 and B-13.
3-97
-------
TABLE 3-22
RUE GAS CHARACTERIZATION SUMMARY
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
TEST NO.
LOAD, GROSS (MW)
SOOT BLOWING STATUS
RAW COAL FEED RATE, MLB/HR^
RAW COAL MOISTURE, X
RAW COAL ASH, %
RAW COAL SULFUR, t
RAW COAL HIGH HEATING VALUE,
BTU/LB
RAW COAL SULFUR, LB/HR
RAW COAL ASH, LB/HR
TEMP (OUTLET ID FAN), "F
STATIC PRESSURE (OUTLET ID FAN),
" Hg
FLUE GAS VOL (OUTLET ID FAN),
MSCFMD
S02, PPM
S02, LB/HR
N0x/S02, MOL N02/MOL SOj
PART {OUTLET ID FAN), Gr/ACF
NOx, PPM
NOx, LB/HR
EXCESS AIR (OUTLET ID FAN), X
26
44.1
Off
46.9
15,5
10. 1
1.1
10600
516
4761
249
0.07
131
1028
1331
0.24
0.180
265,
247
56
27
44.5
Off
47.4
14.7
12.5
1.8
10300
482
5925
275
0.07
125
2974
3701
0.09
0.158
279
249
53
28
89.8
Off
90.2
18.7
9.7
1.0
9900
902
8722
272
0.07
231
772
1767
0.63
..(2)
515
847
51
29
88.7
On
88.5
16.6
11.0
1.3
10400
1150
9719
273
0.07
300
636
1890
0.68
0.206
465
993
94
30
87.5
Off
85.5
17.5
10.2
1.2
10200
1026
8711
273
0.07
216
580
1243
0.73
0.231
452
696
48
31
88.2
On
87.9
21.2
8.3
0.7
9600
615
7330
273
0.07
233
604
1396
0.59
0.107
380
631
53
32
82.5
Off
82.1
16.8
10.1
0.8
10500
657
8294
271
0.10
229
642
1459
0.55
0.175
353
577
59
34
90.4
On
89.7
17.1
10.9
1.1
10300
987
9748
252
0.08
226
834
1873
0.31
0.161
2B5
412
46
24
111.2
Off
109.2
14.8
10.4
1.2
10700
1310
11346
218
0.08
278
668
1843
0.80
0.173
565
1121
43
25
111.6
Off
109.7
15.0
10.5
1.2
10600
1316
11518
219
0.12
279
814
2252
0.63
0.137
545
1084
42
33
108.9
Off
107.5
17.3
9.7
1.0
10300
1075
10416
276
0.07
280
875
2426
0.29
0.203
256
510
50
35
no.i
Off
110.9
15.7
10.5
1.0
10300
1109
11624
296
0.08
268
556
1480
0.53
0.296
295
564
48
10
00
U)
M - Thousands
(2)
Sajr.p].e Lost
-------
Table 3-22 is a summary of the flue gas characterization data. This
data provides the documentation of pre-retrofit (baseline) flue gas condi-
tions. It also will be referenced when evaluating the flue gas character-
ization data in the succeeding subsections. The data has been examined to
determine which observations are outliers (invalid measurements). The out-
liers are not used in the correlations but the outlying observations are
included in the tabulations. Examples of outliers are as follows:
Flue gas volume and mass rates - Test 29
Concentration and mass rates
of S02 in the flue gas - Test 27
Concentrations and mass rates
of S03 in the flue gas - Tests 24, 27, 28, 35
3.6.3 Volume, Temperature, Pressure
Relevant data are included in Tables 3-22 and B-35.
Flue gas volume varied from 183,000 acfm to 438,000 acfm over a load
range of 44MW to 111.5MW. Average flue gas rates at an average load of about
92MW compared with normal operation and with Demo. Unit design were as fol-
lows:
1% Sulfur 3% Sulfur Design
Average Load, MW 87.9 90.0 92
Mass Rates, MMlb/hr. 1.09 1.10 1.02
Volume, acfm 336,000 336,000 320,000
3-99
-------
Outlet duct temperatures as a function of the nominal gross load were
as follows, in °F:
46MW
92MW
11 BMW
1% Sulfur
262
269
303
3% Sulfur
250
268
295
Static pressures are tabulated in Table B-35.
3.6.4 Sulfur Oxides Emission Levels
Relevant data are included in Table B-36.
3.6.4.1 Comparison with Design
The data of Test 27 was not included in the analysis because of an
apparent contamination of the coal by a higher sulfur content coal. Measured
rates for comparison with the New Source Performance Standard average 1.9 Ibs
S02/MMBTU. The standard is 1.2 Ib S02/MMBTU heat input and the difference is
about what was expected for the coal sulfur content of these tests (1.135
average). The parameters critical to Demo. Unit performance compared with
normal operation and Demo. Unit design were as follows:
Average Load, MW
S02 in flue gas (ppmv)
S02 in flue gas (Ib/hr)
S03 in flue gas (ppmv)
S03 in flue gas (Ib/hr)
1% Sulfur
87.9
678
1605
52
96
3% Sulfur
90.0
2493
5670
52
155
Design
92
2185
4842
35
97
The data from Tests 24, 27, 28, and 35 were not used for averaging the SO
rates and concentrations.
3-100
-------
3.6.4.2 Potential Effects on Demo. Unit Performance
A reduced equilibrium driving force, due to the lower concentrations
of S02 may affect absorber performance. Also, sulfate purge rates are depen-
dent on S03 levels in the inlet flue gas. However, the major effects are ex-
pected to be reduced evaporator load and reduced S02 rates to the reduction
area. The concentration of S02 during the low sulfur tests was only 31% of
the design value at 92MW. The ratios of S03 to S02 as a function of nominal
gross load were as follows:
Load
46MW
92MW
115MW
S0,/S0o
]% Sulfur
0.028
0.052
0.027
3% Sulfur
0.033
0.022
0.025
The S03/S02 ratios were not much different from those at normal sulfur levels
except for the 92MW tests. At 92MW, mass rates of S03 averaged 92 Ib/hr with
low sulfur coal compared to 155 Ib/hr at the normal sulfur level in the fuel.
Thus, sulfate purge levels as affected by S03 should be less than at normal
operation.
3.6.5 NOx Emission Levels
Relevant data are included in Table 3-22.
3.6.5.1 Comparison with Design
Measured rates for comparison with the New Source Performance Standard
averaged 0.71 Ib/MMBTU but the data were widely scattered. The standard is
0.7 Ib per million BTU of heat input. On a heat input basis, the NOx levels
of the emissions were substantially higher with the low sulfur coal than with
the coal with normal sulfur content. The parameters having a potential impact
on Demo. Unit performance compared with those at normal operation are as fol-
lows:
3-101
-------
Average Load, MW
NOx in Flue Gas, ppmv
NOx in Flue Gas, Ib/hr
N0x/S02, mol N02/mol S02
]% Sulfur
87.9
403
693
0.580
3% Sulfur
90.0
114
188
0.059
3.6.5.2 Potential Effects on Demo. Unit Performance
A ten-fold increase over the normal sulfur tests of the mol ratio,
N0x/S02, was indicated for the low sulfur tests. However, it was pointed out
in section 3.2 that only 5-10% of the NOx may be N02. Therefore, oxidation in
the absorber to the more inactive sodium salts might not be significantly in-
creased by the increase in relative NOx levels as represented by the N0x/S02
ratio. During the Demonstration, NO and NOx concentrations will be monitored
continuously and a better indication of oxidation effects by N02 will be gained
at that time.
3.6.6 Particulate Emission Levels
Relevant data are included in Table B-37.
3.6.6.1 Comparison with Design
All tests exceeded the Federal New Source Performance Standard of 0.10
Ib/MMBTU. On an equivalent heat input basis, the particulate levels for the
low sulfur test series were only slightly lower than for the test series at
normal operating conditions (0.60 Ib/MMBTU versus 0.70 Ib/MMBTU). Comparison
with normal operation and with Demo. Unit design conditions is as follows:
Average Load, MW
Grain Loading, gr/acf
Mass Rate, Ib/hr.
1% Sulfur
87.9
0.18
54.3
3% Sulfur
90.0
0.24
708
Desicin
92
0.20
550
3-102
-------
3.6.6.2 Collector Efficiency
Relevant data are shown in Table B-38.
Efficiencies were to be determined by the ASME sampling method which
employs an in-situ filter for collection of the particulate followed by an
unheated probe. Complete data was collected for only one test due to the
condensation of and pluggage by solid material of the unheated section of
probe outside the duct. Table B-38 is a compilation of the performance data
of the ESP. Specific corona power, in watts/1000 cfm, was slightly higher
than the corresponding results for the tests at normal sulfur levels. The
comparisons are summarized as follows:
Specific Corona Power, watts/1000 cfm
Nominal Load 1% Sulfur 3% Sulfur
46MW
92MW
11 BMW
133
65
61
101
41
47
For a given flue gas profile, collector efficiency is normally expected to
increase with specific corona power requirements. However, lower collection
efficiencies are suspected.
3.6.6.3 Particle Size
Relevant data are included in Table 3-23 and on Figures B-1Q through
B-13.
Size distribution of the particulate matter outlet the precipitator was
determined by the same in-situ method employed during the normal sulfur tests.
On the average, 50% of the particles were less than 3.0 micron diameter. This
approximates results of the normal sulfur tests. Sampling difficulties were
discussed in 3.2.6.7.
3-103
-------
TABLE 3-23
PARTICLE SIZE DATA
Off-Normal Conditions
(Low Sulfur Coal)
TEST
NO.
27
28
29
30
31
24
25
33
35
LOAD
GROSS
(MM) 1
44.5
89.8
88.7
87.5
88.2
111.2
111.6
108.9
110.1
MASS MEDIAN
DIAMETER (MICRONS)
3.6
3.0
1.9
1.6
3.9
4,3
4.0
3.0
1.8
SOOT BLOWING
STATUS
Off
Off
On
Off
On
Off
Off
Off
Off
AS FIRED COAL
SIZE, % THRU
200 MESH
63.9
59.8
65.0
62.5
64.2
68.6
66.8
65.8
68.6
3-104
-------
3.6.7 Trace Element Emissions
Relevant data are included in Tables 3-17, 3-18, B-39, B-40 and B-41.
Concentrations of 16 metals were determined on ash in the coal and on
the fly ash in the outlet duct. Table 3-17, included in section 3.2, shows
comparative tabulations in decreasing order of concentration in the 1% sulfur
coal. Differences in the trace metal content of the two coals are readily
apparent. Table 3-18, included in section 3.2, provides the same comparison
for the fly ash in the outlet flue gas. Again, several differences exist in
the emission concentrations from burning the two coals.
No concentrations of mercury or the halogens (F and Cl) were deter-
mined on the flue gas for the low sulfur coal tests. However, these concen-
trations were analyzed on the coal. The concentrations compared with the
corresponding concentrations in the 3% sulfur coal were as follows:
1% Sulfur 3% Sulfur
Hg, ppmw <0.001 0.165
F", ppmw 132 93
Cl", ppmw 800 400
3-105
-------
THIS PAGE INTENTIONALLY LEFT BLANK
3-106
-------
4.0 TEST PROBLEMS
The problems encountered can be assigned to three general categories:
• Operational
• Adverse weather conditions
'\
• Data collection and data reduction problems
The involved NIPSCO personnel cooperated fully with TRW field test personnel
to see that the Mitchell No. 11 boiler was operating at the test conditions
requested, was operating at steady state, and that the NIPSCO instrumentation
used to collect Baseline Test data was calibrated as requested. Thus, opera-
tional problems impacting on the test schedule or test results were largely
unavoidable. Field tests were conducted during the spring of 1974 and 1975
and delays caused by adverse weather conditions were due entirely to heavy
rains or electrical storms. Several testing and data reduction problems were
encountered, although considering the large amount of data collection involved,
problems in these areas were to be expected.
In the following subsections, the problems encountered and their effect
on schedule and on test results are discussed. The information is presented
as part of the documentation of the test data but it will also be useful as
part of the site-dependent experience to be utilized in the performance of the
subsequent Acceptance Test and Demonstration Test.
4-1
-------
4.1 OPERATING PROBLEMS
The field test log is shown in Appendix D.
4.1.1 General
A major problem encountered was power demand which severely limited
availability of the boiler operating at 46MW. Due to this, it was necessary
to alter the test schedule and to cancel one of the 46MW tests for Test Se-
ries 5 (low sulfur). A delay of one-half day occurred due to the low load
limitation. The other major problem was the unavailability of a high sulfur
coal (4-5% S) for testing at that operating condition. NIPSCO has been re-
quested to continue its search for high sulfur coal supplies for the Demon-
stration Test. Unavailability of the boiler for the full scheduled test
period resulted in the field tests being carried out in two phases. Thus,
Test Series 1 and 2 were conducted during May 1974 and Test Series 3 and 5
were conducted during April 1975. Although this had a significant impact on
test scheduling and reporting, it was not considered a major problem. Minor
differences in operation and their effects on the test results are described
in section 3.0.
4.1.2 Test Delays
Delays caused by the boiler not being available were as follows:
a. Coal mill problems - 1.5 days
b. FD fan damper - 0.5 day
c. Low load limitation - 0.5 day
d. Loss of coal reclaiming hopper due to coal slide -
4.0 days
Following availability of the reclaiming hopper (item d), it was decided to
begin filling the bunkers with one percent sulfur coal. This resulted in the
cancellation of one test of Test Series 3 (miscellaneous tests) which was to
be run with normal coal (3% S).
4-2
-------
4.1.3 Boiler Limitations
Not all boiler limitations had discernable effects on test performance.
However, for documentation purposes, all limitations are included in the dis-
cussion to follow.
Test 1 was run at 46MW with only two of the four coal mills operating.
No effect on test results was noticed.
Tests 2 through 7 (92MW) were run with only three coal mills operating.
Again, no effect on test results was noticed but it was an objective of the
Test Plan to evenly distribute coal firing by using all four mills.
Tests 8 through 21 were run without complete control of the FD fan dam-
pers. This resulted in a load limitation of 110MW for the special tests using
a high excess of combustion air (Tests 14, 15, 18).
Tests 14 through 21 were run with hot bearing temperatures and more than
normal vibration on the west ID fan. This fan was finally forced down follow-
ing Test 21. Because of an impending labor contract deadline at NIPSCO, test-
ing was interrupted. This resulted in delay of the miscellaneous tests for a
full year. Completion of the miscellaneous tests as scheduled would have pre-
vented the need to change coal types between Test Series 3 and Test Series 5.
All tests of Test Series 3 and Test Series 5 which were scheduled to be
at full load were limited to about 111MW due to a feedwater pump limitation.
During Tests 26 and 27 (46MW), BFP 11W, FD fan 11W, and Mills 3 and 4
were down. The gas recirculating damper was open 20% to control temperatures.
During Test 27; coal sulfur content was significantly higher than one
percent, suggesting contamination.
During Tests 28 through 31, short outages of the coal mills occurred
due to feed hopper pluggage by wet coal. Test 30, scheduled at 92MW, was
load limited to 80MW for 35 minutes due to wet coal.
4-3
-------
4.2 ADVERSE WEATHER PROBLEMS
Delays totalling five days were caused by heavy rains or electrical
storms. The heavy rains also contributed to a coal slide into the reclaiming
hopper which delayed testing an additional four days.
4.3 DATA COLLECTION AND REDUCTION PROBLEMS
4.3.1 General
The only scheduled delays due to test equipment problems were delays
at the beginning of each test phase totalling one day. Data collection
problems resulted in the loss of samples or in aborted elements of a test
during several tests. However, no tests were completely aborted or delayed
by as much as one-half day as a result of sampling or data collection problems.
The problems associated with data collection and reduction are categorized as
follows:
• Data collection
t Analytical
• Data reduction
4.3.2 Data Collection
Comparison of the results of analyses of coal composite samples with
the corresponding results of individual samples shows poor agreement. The
best explanation for these differences is that the composite sample lacked
representativeness due to improper reduction of the gross samples to a labor-
atory sample size, see 3.1.6.3.
Steam flow measurements were consistently higher than feedwater flow
measurements, as described in 3.1.4. As a result, it became necessary to use
feedwater rates for all efficiency and energy balance determinations.
During Test Series 5, with low sulfur coal, paniculate collection by
the ASME method had to be abandoned due to pluggage of the unheated section
4-4
-------
of the sampling probe with a non-ferrous solid material. Since the ASME
method employs an in-situ filter upstream of the plugged section, it is
assumed that the solid formation is in a gaseous state at the duct tempera-
tures. Problems were encountered primarily at the air heater inlet at 627
to 690°F duct temperature but also at the ID fan outlet at duct temperatures
of 290 to 340°F. Without particulate results by the ASME method, the dust
collector performance could not be evaluated adequately.
Some sulfur oxide samples were lost due to sample blowback created by
the stack pressure pressurizing the sample collection apparatus after pump
shutdown. The sample was then pushed back through the Impingers when they
were disconnected from the probe. This problem was solve'd by slowly bleeding
the pressure off before disconnecting from the probe. Purging was accomplish-
ed using ambient air drawn through activated charcoal to avoid sample bias due
to the high ambient SOg levels.
Particle sizing results were influenced by stage to stage carryover of
the sample. There was a significant fraction of large particles overloading
the first stage during several of the tests. Although an inherent problem
with the Brink cascade impactor (as well as other inertial impactors), stage
overloading is not so serious a problem as to justify a change in methodology.
The alternatives have significant problems which detract from their use. Any
method that bases the results on a physical count (optical microscopy, scan-
ning electron microscopy, automatic optical counters) does not really identify
the mass diameter, which is critical in the effectiveness of most particulate
collection devices such as scrubbers and inertial collectors. Additionally,
in most cases there is the problem of taking a portion of a sample and assum-
ing it to be representative of the original source of the sample.
To perform a set of off normal tests at higher than normal flue gas
volumes, access doors were opened at the air heater outlets to simulate addi-
tional inleakage. During the first of three replications (Test 19), the doors
were only partially open and the amount of excess inleakage was inadequate.
Thus, only two out of the three tests were at the desired operating conditions.
4-5
-------
Measurements of CO and total hydrocarbons during Test Series 3 were
not valid dye to ambient air leakage into the sampling system.
The physical locations of the flue gas sampling positions were less
than ideal. The most obvious problem arising from these factors has been the
flow data. Values at the outlet are believed to be relatively accurate, es-
pecially when Boiler No. 6 was down or at reduced load, and this is confirmed
by theoretical and calculated values, see Table B-32. The inlet measurements
of velocity are not at all reliable and, in fact, many of the points tested
gave negative flow values, an indication of the extreme turbulence at this
location. In one particular test, test 26, the west FD fan was down and dur-
ing this test the1velocity profile of the majority of the points tested on
the west side pf ^he inlet APH duct were negative. Due to these erratic flow
measurements, calculated values were used for analysis of the data.
Additional problems at the outlet location were encountered:
)
a. Fluje gas leaks. Due to the positive pressure in the duct at
this location and the leaks around the dampers in the immed-
iat$ area of the sampling location, as well as escaping flue
gas during £he opening of ports to change probe locations,
high ambient SQ2 levels were encountered. The test team
members used respirators to combat the problem, but eye
irritation and respiratory irritation remained a signifi-
cant problem throughout the tests.
b. Vertical sampling/long probes. This problem area is not
upcommon in source tests, and had little effect on re-
SM]ts, but does make the test performance more difficult
and demanding.
4.3.3 Analytical Problems
A problem was encountered in the analytical procedure for S02/S0, due
to the relatively high sulfur content in the sample. The end-point was very
indistinct and difficult; to reproduce. This was overcome by two steps:
4-6
-------
1. Using a smaller sample aliquot, thus diluting it by
a factor of approximately 5.
2. Diluting the titrant 1:10, to make the amount of titrant
used significant enough to more easily read from the
buret.
These changes produced a much more distinct end-point and no further problems
were encountered in analysis.
Fluorides and chlorides in the coal, ash or flue gas were analyzed by
different methods and at resultant different degrees of accuracy depending
on the sample source. The varying levels of sensitivity from coal to ash to
flue gas prevented the estimate of close approximations of the true distribu-
tions of fluoride and chloride between the ash and the flue gas.
4.3.4 Data Reduction Problems
The problems encountered in obtaining a valid sulfur mass balance are
described in detail in 3.2.4.1.
Certain assumptions had to be made for calculating ash mass balances.
This was due in part to lack of sampling access between the air heaters and
the ESP and to the generally poor sampling locations for particulate and for
velocity traversing at the air heater inlet and at the ID fan outlet.
The computer program was developed primarily for efficiency and heat
rate results. A number of additional calculations which were needed for eval-
uation of the data had to be done manually, which was time consuming and
labor intensive. These additional calculations can easily be incorporated
into the existing computer programs. Some minor errors in the computer pro-
gram turned out to be troublesome due to their effects on a large number of
calculated results. For example, as fired coal analyses were used incorrectly.
This affected practically every result of the computer program.
4-7
-------
THIS PAGE INTENTIONALLY LEFT BLANK
4-8
-------
5.0 RECOMMENDATIONS
5.1 SCOPE
As part of the approach to the baseline testing of the T&E program, it
was intended to utilize the site-dependent experience gained during the Base-
line Test for initiating improvements in the subsequent Acceptance and Demon-
stration tests. Benefits from the experience gained might include limited
changes in the test plans as well as improvements in technique or methodology.
In section 4.0 the problems encountered during the Baseline Test are describ-
ed. Recommendations will follow which are intended to minimize or eliminate
several of these problems.
5-1
-------
5.2 TEST TECHNIQUES AND METHODOLOGY
Attention will be focused prior to further testing on improvements in
the techniques for preparing composite samples. It is recommended that sig-
nificant modifications in the methodology be employed. These are:
1) Modify the ASME particulate sampling method to provide a
heated probe which would feed a set of impingers in hopes
of avoiding aborted tests due to probe pluggage during
operation with off normal coals. Conduct a pretest with
this modified sample train. If not successful, discon-
tinue use of the ASME method.
2) Modify the method for determining NOx according to recom-
mendations recently described in the literature^ . The
modifications include evaporating the sample in new un-
etched borosilicate dishes; adding only enough sodium hy-
droxide to neutralize the acidic solution of nitrates;
adding excess of ammonium hydroxide prior to the spectro-
photometric measurement; and reading the absorbance at
405nm as opposed to 420nm.
3) Review test procedures for chloride to see if more con-
sistent levels of sensitivity are possible for coal,
ash and flue gas.
4} Analyze samples prior to the Acceptance Test to
obtain optimum agreement of oxygen concentrations be-
tween the Orsat determination and by analyzer.
5) Expedite turnaround of coal sample results in order to
calculate efficiencies, flow rates, sulfur balance,
etc. in the field.
5-2
-------
5.3 TESTS WITH HIGH SULFUR COAL
The Demonstration Test Plan calls for a series of 12 tests with a high
sulfur coal (4-5% S). The high sulfur coal was not available for the Baseline
Test. It is recommended that every effort be made to obtain a coal of this
type in time for the Demo. No. 2 spot test, scheduled for the sixth month of
the Demonstration.
5.4 CALIBRATION OF STEAM AND FEEDWATER METERS
It is recommended that NIPSCO recalibrate the total steam and feed-
water meters. Significant differences in flow rates measured by these meters
were found.
5.5 INTRODUCTION OF OFF NORMAL EXCESS COMBUSTION AIR
Improved methods for obtaining higher than normal excess combustion
air will be explored.
5.6 DATA REDUCTION
It is recommended that the computer program for evaluation of the spot
test results be expanded and upgraded. It is possible to incorporate a num-
ber of additional calculations into the computer program, thus reducing the
time and the labor for the data reduction.
5-3
-------
THIS PAGE INTENTIONALLY LEFT BLANK
5-4
-------
6.0 REFERENCES
1. Program for Test and Evaluation of the NIPSCO/Davy/AIHed Demonstra-
tion Nant Work Nan-Manual, Prepared by TRW transportation and
Environmental Operations, McLean, Virginia, (1973).
2. ASME Power Test Codes, Test Code for Steam Generating Units, PTC 4.1-
1964, American Society of Mechanical Engineers, New York, New York,
(1964).
3. Martin, R., Watch for Elevated Dew Points in SOa - Bearing Stack Gases,
Hydrocarbon Processing, June 1974.
4. Standards of Performance for New Stationary Sources, 40 CFR 60, 36 FR
24876, 23 December 1971.
5. Abatement of Nitrogen Oxides Emissions from Stationary Sources, National
Academy of Engineering, 28, (1972).
6. Standards of Performance for New Stationary Sources, 40 CFR 60, 36 FR
24876, 23 December 1971.
7. ASME Power Test Codes, Test Code for Dust-Separating Apparatus, PTC
21-1941, American Society of Mechanical Engineers, New York, New York,
(1941).
8. Oglesby, S., et al, A Manual of Electrostatic Precipitator Technology -
Part I - Fundamentals, Prepared for National Air Pollution Control Admin-
instration, APTD - 0610, (1970).
9. Deutsch, W., Ann. der Physik, 68, 335, (1922).
10. Robertson, D., Improvements in Phenodisulfonic Acid Method for Determin-
ation of NOx, Environmental Science and Technology, Vol. 9 No. 10, Octo-
ber 1975.
11. Acceptance Test Plan for the Test and Evaluation Program for the NIPSCO/
Davy/Allied Demonstration Plant, Prepared by TRW. Transportation and
Environmental Engineering Operations, Vienna, Virginia, (1975).
12. Weinstein, L.H., et al. "A Semi-Automated Method for the Determination
of Fluorine in Air and Plant Tissues," Contrib. Boyce Thompson Inst.,
22 (4), 207-220 (Oct.-Dec. 1963).
13. Instruction Manual for Fluoride Electrode, Orion Research, Inc.,
Cambridge, Mass.
14. "Colorimetric Method for Arsenic in Coal," U.S. Bureau of Mines Report
7184 (1968).
6-1
-------
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6-2
-------
APPENDIX A. BOILER DESCRIPTION
A-1
-------
BOILER DESCRIPTION
TYPE AND EXPECTED CONDITIONS
Unit No. 11 is a balanced draft wet bottom radiant wall-fired reheat
boiler which was manufactured by Babcock and Wilcox and placed into service
in 1969. The unit can develop a maximum continuous steam capacity of 821,000
Ibs/hr with a corresponding turbo-generator output of 115 megawatts. The
steam parameters controlled are 1870 psi, 1005°F secondary superheater outlet,
1005°F reheat. Nominal operating values at several load levels are shown in
Table A-l. A flow configuration of the boiler unit and major auxiliaries is
shown in Figure A-l.
A-2
-------
TABLE A-l
MITCHELL NO. 11 NOMINAL VALUES
£ 1 h. £ P I i f_ P. I
Uni*s |SSIG op RT||/1h 1(13lh ,hp PSTR °F BTU/lb. 103lb./hr. PSIG °F
% Load
Location: Sec. S.H. Outlet
R.H. Inlet
R.H. Outlet
Extraction to #4 Htr.
BFW Entering Econ.
BFW #6
BFW After BFW Purrp
BFW #7 Entering #5 Htr.
Drain #18
Drain #19 from #5 Htr.
Absorption
Absorption - R.H.
Absorption - S.H. Spray
Absorption - R.H. Spray
Stm. To #5 Htr.
Radiation Loss
Carbon Loss
Margin
TOO
1800
485.8
437.6
227.2
104.8
2152
215.8
461.5
0.23%
0.3%
1.5%
1000
683
1000
458.8
331.2
336.4
383.2
346.4
393.2
683
1480.4
1343.3
1521.4
1442.4
440.8
302.0
310.8
359.5
317.8
367.7
1039.6
178.0
1169.6
1210.6
1343.3
782.79
706.92
706.92
31.00
782.79
96.24
65.23
80
1800
377.5
339.8
177.3
82.1
2070
168.4
358.6
1000
1000
434
313.8
319.3
362.7
325.2
368.6
Legend:
1480.4
1329.4
1524.1
1444.9
413.6
283.9
293.1
337.8
295.7
341.3
1066.8
194.7
1187.3
1231.
1 329 . 4
602.92
548.3
548.3
21.62
602.92
67.87
46.25
40
1800
186.6
168
88.4
41.2
1980
84
177.3
1000
1000
371.8
269
274.1
310.4
275.5
311.8
h_ F_
BTU/lb. 103lb./hr.
1480.4
1314.2
1528.9
1449.1
347.2
237.8
247.
283.8
244.4
281.8
1133.2
214.7
1233.4
1281.9
1 TI4 ">
\ J 1 *T . f.
292.31
270.16
270.16
8.37
292.31
26.32
1 7 QC
1 / . 33
CO
P = Pressure
T = Temperature
h = Enthalpy
F = Flow rate
Source: From B&W diagrams (sprays for superheat/reheat attemperation
not shown)
-------
FIGURE A-l
MITCHELL NO. 11 BOILER
ELECTROSTATIC
PRECtPlTATQR
TO ASH DISPOSAL
I.D. FANS
-------
LOCATION
The D. H. Mitchell Station is located near the extreme northwest city
limits of Gary, Indiana and fronts on Lake Michigan near its extreme south-
ern end. Unit No. 11 is the easternmost of four (4) coal fired boilers at
the station. Access to the station is by Clark Road which intersects U.S.
Highway 12.
Lake Michigan is the source and receiving body for the cooling water.
Elevation at grade is 586.5 feet above mean sea level. Elevation above
normal lake level at grade is eight feet. Atmospheric temperatures are as
fol1ows:
Summer average 75°F, Peak 100°F
Winter average 30°F, Low -8°F
A-5
-------
FUEL
Generally, Mitchell No. 11 burns a mixture of pulverized coal and
petroleum coke. To correspond to general practice of the utility industry
and to avoid homegenity problems, coal only is recommended for the baseline
test series. The coal normally burned is a high volatile bituminous, H.V.C.
rank (ASTM D388 designation) obtained from the No. 6 bed located in South-
west Illinois*. Typical analyses, shown in Table A-2, is believed repre-
sentative of the type coal normally burned.
*St. Clair, Perry and Jackson Counties (4 mines),
A-6
-------
TABLE A-2
COAL USED AT NIPSCO MITCHELL NO. 11, DECEMBER 13/15, 1972
AS REC'D
#1
#3
AV6.
H20%
Ash
Vol.
F.C.
HHV, Btu.
S
Alk.
C
H
N ,
Cl
0
In Ash:
P2o5%
Si02
Fe2°3
A1203
Ti02
CaO
MgO
so3
K20
Na20
Undetermined
ppm in Ash:
Mn
Cu
Zn
Ni
Cr
Pb
ppm in Coal:
Hg
14.00
10.32
34.87
40.81
10656
2.81
0.16
59.98
4.23
0.23
0.09
8.33
0.14
45.12
17.45
17.59
0.86
7.85
1.00
6.86
1.76
0.39
0.98
825
610
375
500
475
650
0.24
12.00
9.01
31.23
47.76
11273
3.12
0.14
60.47
4.27
0.72
0.07
10.34
0.10
45.42
17.70
19.09
0.93
7.00
1.00
6.41
1.76
0.44
0.15
610
520
365
550
335
675
0.25
13.60
9.53
33.94
42.93
10958
2.95
0.16
58.49
4.16
0.22
0.03
11.02
0.10
47.82
16.90
19.09
0.82
6.45
1.00
5.15
1.82
0.50
0.35
575
495
300
500
335
620
0.36
14.90
9.05
32.13
43.92
10859
2.88
0.13
60.48
4.20
0.30
0.06
8.13
0.14
46.92
17.00
19.43
0.93
6.75
1.00
5.48
1.82
0.20
0.33
530
515
990
500
335
610
0.27
13.62
9.48
33.04
43.85
10936
2.94
0.15
59.85
4.21
0.37
0.06
9.45
0.12
46.32
17.26
18.80
0.88
7.01
1.00
5.97
1.79
0.38
0.45
635
535
507
512
370
639
0.28
Reference: "Dust Collector Studies"
Northern Indiana Public Service Company
D.H. Mitchell Station No. 11
P.O. No. 5955-54 - December 13-15, 1972
F.R. Kin & Associates, Incorporated
P. 0. Box 655
Chicago Heights, Illinois 60411
A-7
-------
FUEL HANDLING
Coal is transferred from rail cars or storage piles through a crusher
to screens which classify to one inch maximum. This coal is transported by
conveyor to a bunker of about 2000 tons capacity. Coal flows by gravity
through four fill pipes, 24 inch diameter, to four coal feeders,. Raw coal
will be sampled from the gravity feed pipes.
The four fill pipes run full and thus act as a seal leg for press uri-
zation of the feeders and pulverizers. The raw coal flows across four weigh
feeders and then by gravity to four pulverizers.
A-8
-------
FUEL FIRING
General
The boiler front wall contains 12 circular burners. Four pulverized
coal mills each feed coal-air (77% through 200 U. S. mesh) to three burners.
Excess combustion air is normally 19% (design value) but higher at low loads,
Each coal pulverizer receives coal from a separate gravimetric coal feeder
mounted on the operating floor between the overhead coal bunkers and the
coal pulverizers. At low load, the option exists of turning off one feeder.
The normal operating capacity of Mitchell No. 11 ranges from 46 to
115 megawatts and the 1972 annual average load factor was about 80 percent*
or 92 megawatts. During normal operating conditions, the load is changed
at the rate of 1.0 megawatts per minute. The load can be changed from a
hot initial condition at the faster rate of 3.3 megawatts per minute up or
down if required. From a warm initial condition, the load can be changed
at the rate of 1.6 megawatts per minute up or down if required.
Equipment Descriptions
Coal Feeders(4). These units are Stock Equipment gravimetric coal
feeders, pressurized, which gravimetrically measure coal feed rate.
Maximum capacity of each is 60,000 Ibs/hr.
Pulverizers(4). B&W Model EL70 ball mills, ball and race type,
medium speed. New ball diameters are 11 1/4" and wear is to 7".
Primary air is supplied by a blower for each mill. Power input,
including blower, is 14 KW hr/ton coal. Additional relevant data
is listed in Table A-3.
Burners(12). B&W circular register, 36" diameter with steaming
capacities of 91,200 lb/hr., each burner. Igniters are gas fired.
The fuel feeding pattern is shown in Figure A-2. Connections for
sampling "as fired" coal are available on each feed pipe.
Air Supply. Two forced draft fans are provided as well as four
primary fuel-air fans. See Table A-4 for fan information. In
*1972 historical data.
A-9
-------
TABLE A-3
PULVERIZED COAL EQUIPMENT DATA
Number of mills per boiler 4
Type of mills EL-70
Size (manufacturer's rating), tons per hour 17.03 - 50 grind
70%/200 Mesh
Type of fans (blower or exhauster) Blower
R.P.M. of blowers 1,800
Assumed grindability of coal 50
Maximum temperature of preheated air that can be used in
mill 650°F
A-1Q
-------
c
c
Boiler
o o o o
1-1 1-2 2-2 1-3
O O O O
2-1 3-1 3-2 2-3
O O O O
4-1 4-2 4-3 3-3
V w «- CN « «-rM«
•- ,i ^- eg ri ri cocbro
1
2
3
4
Burners
PULVERIZERS
FIGURE A-2 FUEL DISTRIBUTION TO BURNERS
A-11
-------
TABLE A-4
FANS AND PUMPS INFORMATION
Forced Draft Fans:
Manufacturer
Number of Fans
Capacity @ 132°F
Discharge Static Head
Driver
American Standard
2
203,000 c.f.m.
17.3 inches ti^Q
A.C. 700 H.P. - 1185 R.P.M,
Induced Draft Fans:
Manufacturer
Number of Fans
Capacity @ 289°F
Static Head
Dri ver
Variable Speed Drive
American Standard
2
228,000 c.f.m.
-18.2 inches H20
Elliot 900 H.P. - 887 R.P.M.
American Blower Corporation
Boiler Feed Pumps:
Manufacturer
Number
Type
Capacity
Net Developed Head
Variable Speed Drive
Driver
Ingersoll-Rand Company
2
10-Stage Barrel
452,000 Ib/hr. (1013 gpm)
2096
American Blower Corporation
West. 1750 H.P. - 3573 R.P.M.
A-12
-------
case of draft unbalance due to malfunction, the boiler trips
at one inch hLO positive pressure with a two second time
delay.
A-13
-------
COMBUSTION CONTROL
The 721 analog system supplied by Bailey Meter is used.
Fuel Control
1. MW output change affects turbine demand.
2. Turbine demand change affects steam control valves.
3. Change in steam control valve affects boiler pressure
(measured as secondary superheater outlet pressure) and
steam flow rates.
4. Change in summation of steam header pressure and flow rate
affects mill demand.
Air Control
Primary combustion air flow is controlled by summation of steam flow
and header pressure. Relevant sensors include air flow, air temperature,
flue gas oxygen, steam temperature, steam flow and header pressure. Secon-
dary combustion air is manually controlled by the control room operator.
Figure A-3 is typical of the "load ramp" used for controlling excess air.
A-14
-------
FIGURE A-3
OXYGEN VS. LOAD RAMP
10
cn
I/I
-------
FIRE SIDE CHARACTERISTICS
The furnace configuration is shown in the elevation drawing (Figure A-4),
The furna.ce volume is 76,126 cu. ft. with effective heating surface as follows:
Reheat surface - 15,818 sq. ft.
Superheater - 54,130 sq. ft.
Reheater - 18,226 sq. ft.
Economizer - 9,550 sq. ft.
Air heater - 132,200 sq. ft.
Nominal flue gas temperatures at full load are 2,230°F (furnace exit), 1,9QQ°F
(superheater exit), 1,810°F (entering reheater), 1,290°F (leaving reheater),
695°F (leaving economizer). Gas recirculation from outlet the economizer,
used mainly for startups, is provided.
The boiler is provided with a United Conveyor Co. ash handling system
with a water-flooded ash hopper beneath the boiler. Pyrites rejection is
combined with bottom ash and sluiced to the ash pond. Dust collector hoppers
are emptied through rotary feeders and pneumatically conveyed out of the unit,
and sluiced to the ash pond. Means for obtaining representative samples of
pyrites and bottom ash are not available. The boiler is provided with a
Copes-Vulcan Div. air energized wall deslagger and retractable soot blower
system operating on a programmed daily cycle. The cycle is initiated by the
control room operator. Wall blowers may be actuated independently at any
time, to maintain steam superheat/reheat temperatures. Figure A-5 shows
the relative positions of retracts and wall blowers. The normal soot blowing
cycle requires about two hours to execute and is performed once a day, after
midnight. For the test program, soot blowing can be scheduled at other hours
and the cycle extended to three hours using manual actuation.
A-16
-------
FIGURL A-4
NORTHERN INDIANA PUBLIC SERVICE COMPANY
MITCHELL STATION-UNIT NO. II
GARY. INDIANA
B8W CONTRACT NO. RB-456
A-17
-------
FIGURE A-5
SOOT BLOWERS
o
—
3 O 5O 7O
4 o eo sc
1 O
J-**
2VI
<
\
O8 O9
O14 Q13
01 02
O7 O6
V X
^ "W"
^
010
012
O3
O5
>^-"R"
I1
O9 O1Q
O11 O12
O13 O14
Q15 Q16
r
O4
\
_l
, , ^
V
\ i
o o
AMI AH2
"R" - RETRACTS ARE BLOWN IN
ORDER, ONCE PER SHIFT.
"W" - WALL BLOWERS ARE
BLOWN WHEN THEY
NEED IT OR IF
SCHEDULED, BEFORE
RETRACTS, IN ORDER.
EVEN NUMBERED ARE RIGHT.
ODD NUMBERED ARE LEFT.
A-18
-------
STEAM SIDE CHARACTERISTICS
Steam conditions, superheat and reheat vs. load have been summarized
in Table A-5. Heating surface areas are 54,130 sq. ft. (superheater),
18,226 sq. ft. (reheater). Boiler feed water pumps have been described in
Table A-4. BFW is heated by a series of three water heat exchangers, de-
aerated, heating continued in two extraction-steam heaters, and then
fed to the economizer. The secondary superheater outlet steam rate vs. KW
relationship is as follows:
Full load 6.8 Ib/KWH
92 MWG 6.55 Ib/KWH
46 MWG 6.35 Ib/KWH
Attemperation spray water is withdrawn after the BFW rate meter and
enters (1) hot reheat steam (2) primary superheated steam as controlled by
the relevant sensors and controls. Nominal condenser exhaust pressure is
1.5" Hg. The condenser is a horizontal single-pass Ingersoll Rand unit
with vertically divided water boxes, of phosphorized admiralty construction.
Tube length is 30 ft. and surface area is 63,000 sq. ft. Once through cool-
ing water from Lake Michigan is used.
The turbine-generator set is made by General Electric Co., is of the
tandem compound single-flow reheat type, carries a nameplate rating of
115.1 MW, runs at 3600 RPM and has 5 extraction steam openings.
A-19
-------
FEED WATER TREATMENT
Feed water treatment is of the conventional type with sodium sulfite
deoxygenation and sodium phosphate alkalinity control. A deaerating feed
water heater is provided. Water conductivity is monitored continuously
and maintained at a low level by blowdown as needed. Blowdown rate can be
measured by observing change in levels of demineralized water feed tanks.
AIR PREHEATERS
Two Ljungstrom type rotary air heaters, data shown in Table A-5,
are provided. Flue gas and air inlet and outlet conditions are shown.
ELECTROSTATIC PRECIPITATOR
A cold end electrostatic precipitator, manufactured by American
Standard Co., is in the flue gas stream between the air heaters and the
induced draft fans. Descriptive data are shown in Table A-6.
A-20
-------
TABLE A-5
REGENERATIVE AIR HEATER (DESIGN CONDITIONS)
MAKE: AIR PREHEATER CORP. TYPE: LJUNGSTROM SIZE: 22-VIR-66
HEATING SURFACE/UNIT SQ. FT.: 66,100 NO./BOILER: 2
% of Full Load 100 53 100
Typical
Evaporation, Lb. Steam/Hr. 821,000 437,400 821,000
Ambient Air Temp. °F. 80 80
Air Leaving Heater Lb/Hr. 900,000 491,000
Air Entering Heater Lb/Hr. 991,500 562,000
Gas Entering Heater Lb/Hr. 1,091,000 633,000
Gas Leaving Heater Lb/Hr. 1,182,500 704,000
Temp, of Air Entering °F. 100 100 150
Temp, of Air Leaving °F. 602 607
Temp, of Gas Entering °F. 697 668
Temp, of Gas Leaving
Uncorrected °F. 303 294 309
Temp, of Gas Leaving
Corrected °F. 289 276
Resistance, Air Side "H20 3.55 1.25 (Draft Loss)
Resistance, Gas Side "H20 5.80 2.35
Total Pressure Diff.
Across Heater "H20 16.85 9.10
A-21
-------
TABLE A-6
MITCHELL NO. 11 PRECIPITATOR SPECIFICATIONS
Design C.F.M. 410j000
T oc
1 h 290
Inlet gr/SCFD 3.5 to 6.5
AP "H20 0.4
Removal % 98.5
Rate Constant, Ft./Sec. 0.5
Plates, Ft.2 58,240
Treatment Length, Ft. 17.3
# Fields 3
# Ducts 56 (@ 9")
Wire Ft. 40,320 (@ 7")
Wire Rating, ma./Ft^ 0.08
Treatment Time, Sec. 3.2
Delivery July 1969
# Plate Rappers 32
# Wire Vibrators 12
Hopper Ash Capacity Minimum 8 hrs.
# Bus Sections 6
Plate Height, Ft. 30
Energization Half Wave
Rating KVP 70
Rating ma. 1800, 800, 600
Provision in the unit for another field, 6' treatment length
above hopper can be added later
Expected removal w/field #1 only 87.7%
Expected removal w/fields #1-2 only 95.6%
Expected hopper #3 collects 2.8% of the dust
Ash removal pneumatically by 3 lines (fields 1, 2, 3)
No. ash hoppers - 12
A-22
-------
FLUE GAS OUTLET
Description
Two induced draft fans are provided discharging into a common horizon-
tal duct entering the base of the 235 ft. high stack shared with Unit No. 6.
See Table A-4 for fan information. With retrofit of the WL/Allied unit, a
quick acting damper, normally closed, is being installed in the common hori-
zontal duct discharging to the stack. Part of the horizontal duct work is
being replaced and redirected to the WL/Allied unit.
Sampling Conditions
Economizer exit gas samples are available at a position on a horizon-
tal duct between a 90° turn after the economizer and a 90° turn before the
air heater. Stack gas samples are available as described in Section 4.0.
A-23
-------
THIS PAGE INTENTIONALLY LEFT BLANK
A-24
-------
APPENDIX B. BASELINE DATA BASE
B-l
-------
TABLE B-1
XI),
HEAT BALANCE (MMBTU/HRUJ)
NORMAL OPERATING CONDITIONS
ca
ro
TEST NO.
LOAD, GROSS (W)
INPUT COAL
STEAM ABSORPTION
COAL MOISTURE 8 HYDROGEN*2'
RADIATION ESTIMATED
CARBON IN REFUSE12'
DRY GAS HEAT LOSS*2'
H20 IN RUE GAS*2'
FLUE DUST SENSIBLE HEAT*2'
NO IN FLUE GAS*2'
CO IN FLUE GAS*2'
HYDROCARBONS IN FLUE GAS(2'
TOTAL ACCOUNTED FOR LOSSES
TOTAL UNACCOUNTED FOR LOSSES
UNACCOUNTED FOR LOSS, %
"M - Thousands
Accounted for Losses
1
41.5
471.94
396.71
21.93
2.80
2.07
40.75
2.59
0.11
0.13
0.00
0.00
70.38
4.85
6.5
16
45.5
505.98
413.49
22.40
2.80
1.89
46.26
3.00
0.11
0.09
0.00
0.00
76.55
15.94
17.2
17
46.2
510.95
405.41
21.99
2.80
1.67
45.72
2.81
0.11
0.07
0.00
0.00
75.17
30.37
28.8
2
90.3
939.82
788.82
42.32
4.70
1.80
67.04
5.45
0.22
0.26
0.00
0.00
121.79
29.21
19.3
3
89.6
910.77
751.25
40.35
4.55
1.79
63.65
4.97
0.20
0.14
0.00
0.00
115.65
43.87
27.5
4
91.2
940.57
762.54
41.22
4.70
3.41
65.54
5.33
0.20
0.16
0.00
0.00
120.56
57.47
32.3
5
89.0
890.97
749.48
41.15
4.45
2.16
61.90
5.57
0.19
0.14
0.00
0.00
115.56
25.93
18.3
6
90.9
910.45
766.59
40.82
4.55
1.83
65.79
5.32
0.21
0.15
0.00
0.00
118,67
25.19
17.5
7
89.0
885.24
748.07
39.83
4.43
1.78
52.96
4.68
0.21
0.14
0.00
0.00
104.03
33.14
24.2
8
114.4
140.62
964.28
52.15
5.70
3.68
76.76
7.80
0.35
0.20
0.00
0.00
146.64
29.70
16.8
9
115.1
176.97
977.04
54.40
5.88
5.19
78.35
8.30
0.33
0.16
0.00
0.00
152.61
47.32
23.7
10
114.9
162.33
972.31
52.14
5.81
2.35
86.60
7.48
0.33
0.40
0.00
0.00
155.11
34.91
18.4
22
111.2
114.39
945.50
50.36
5.57
9.45
83.72
7.33
0.42
0.61
0.00
0.00
157.46
11.43
6.8
23
111.9
123.10
953.74
50.40
5.62
8.94
81.51
7.81
0.40
0.60
0.00
0.00
155.28
14.08
8.3
-------
TABLE B-Z
AUXILIARY AMPERAGES
NORMAL OPERATING CONDITIONS
D3
CO
TEST NO.
LOAD. GROSS (Ml)
LOAD, NET (MW)
AUXILIARY POWER (MW)
UNACCOUNTED FOR (MW)
AUXILIARY POWER, I
CIRC H20 PUMP EAST, AMPS
ID FANS (2) TOTAL, AMPS
:D FANS (2) TOTAL, AMPS
'RIM AIR FANS (4) TOTAL, AMPS
1ILLS (4) TOTAL, AMPS
BAS RECIRC PUMP, AMPS
1AIN FEED H20 PUMPS (2) TOTAL, AMP
SOOT BLOWER AIR COMP, AMPS
SLUICE PUMP NORTH, AMPS
1
44.5
40.8
2.9
0.8
8.3
38
115
92
40
46
25
175
Q
30
16
45.5
42.2
3.2
0.1
7.3
38
109
91
55
59
26
180
0
30
17
46.2
42.3
3.0
0.9
8.4
39
110
91
57
60
25
170
0
30
2
90.3
84.6
4.6
1.1
6.3
38
170
104
63
75
0
355
0
0
3
89.6
83.7
4.7
1.2
6.6
38
170
105
66
76
0
355
31
29
4
91.2
85.3
4.6
1.3
6.5
38
157
105
64
75
0
356
0
29
5
89.0
83.4
4.4
1.2
6.3
38
160
102
64
75
0
351
0
27
6
90.9
85.1
4.6
1.2
6.4
38
166
101
64
75
0
356
0
29
7
89.0
83.1
4.6
1.3
6.6
38
170
101
64
75
0
355
28
30
8
114.4
U7.7
5.5
1.2
5.9
38
210
101
82
98
0
426
0
30
9
115.1
108.7
5.1
1.7
5.9
38
210
102
81
100
0
425
0
31
10
114.9
108.1
5.3
1.5
5.9
38
205
105
84
99
0
424
0
17
22
111.2
104.3
5.3
1.6
6.2
39
172
100
81
104
0
406
21
10
23
111.9
104.6
5.2
2.1
6.5
39
175
100
79
105
0
402
21
0
-------
TABLE B-3
AUXILIARY AMPERAGES
OFF NORMAL OPERATING CONDITIONS
00
TEST NO.
LOAD, GROSS (MW)
LOAD NET (MW)
AUXILIARY POWER (MW)
UNACCOUNTED FOR (MW)
AUXILIARY POWER, %
CIRC H20 PUMP EAST, AMPS
ID FANS (2) TOTAL, AMPS
FD FANS (2) TOTAL, AMPS
PRIM AIR FANS (4) TOTAL. AMPS
(ILLS (4) TOTAL, AMPS
GAS RECIRC PUMP, AMPS
IAIN FEED HjO PUMPS (2) TOTAL, AMP
SOOT BLOWER AIR COMP, AMPS
SLUICE PUMP NORTH, AMPS
11
115.1
107.9
5.5
1.7
6.2
38
208
105
83
98
0
425
22
30
12
114.7
107.9
5.3
1.5
5.9
38
193
102
81
98
0
425
22
0
13
114.8
107.8
5.4
1.6
6.1
38
193
105
82
98
0
425
0
30
14
110.1
103.6
5.3
1.2
5.9
38
185
103
83
98
0
445
0
0
15
110.1
103.4
5.3
1.4
6.1
38
195
106
82
98
0
408
0
0
18
108.9
102.4
5.5
1.0
6.0
44
195
106
81
98
0
400
0
0
19
114.8
107.8
5.6
1.4
6.1
44
199
103
SI
98
0
430
0
0
20
118.1
108.1
5.6
4.4
8.5
44
215
104
84
99
0
440
0
0
21
114.4
107.1
5.8
1.5
6.4
44
213
102
88
98
0
435
0
31
-------
TABLE B-4
LOAD SENSITIVE PRESSURE AND TEMPERATURE VALUES
NORMAL OPERATING CONDITIONS
O3
I
Ol
TEST NO.
LOAD, GROSS (HW)
BOILER FEED HjO IN, °F
HEATER « EXTRACTION STEAM, *F
BOILER FEED H,0 LEAVING HEATER
«. °F Z
BOILER FEED H.O ENTERING HEATER
15, °F z
DRAIN HEATER 14, °F
DRAIN HEATER K. °F
STEAM DRUM, PSIG
REHEAT IN, PSIG
REHEAT OUT, PSIG
HEATER *4 EXTRACTION STEAM, PSIG
1
44.5
.174.0
790.8
274.1
309.8
310.0
369.3
1753.3
188.3
162.8
82.0
16
45.5
38B.8
800.8
275.5
335.5
301.0
369.8
1760.0
197.3
170.8
84.5
17
46.2
386.5
803.0
276.0
336.3
311.0
370.5
1760.0
197.0
171.5
85.0
2
90.3
407.5
810.8
319.3
357.8
336.0
376.8
1816. 0
375.3
348.5
173.8
3
89.6
442.0
799.0
313.0
377.5
320.3
376.5
1816.5
373.0
346.3
172.5
4
9U2
442.0
804.9
312.8
379.8
313.0
379.0
1820.5
377.8
350.8
175.0
5
89.0
440.8
804.9
311.5
376.5
313.5
376.0
1819.8
370.5
343.8
171.5
6
90.9
441.8
804.9
312.3
377.0
314.8
379.3
1821.5
376.8
350.8
175.3
7
89.0
439.8
804.9
311.8
375.8
313.0
377.0
1820.0
370.3
344.0
172.3
8
114.4
460.5
827.0
336.4
383.2
346.0
458.8
1865.0
478.5
447.8
227.5
9
115.1
461.5
824.0
325.0
393.0
345.8
394.0
1871.0
482. 0
451.5
230.3
10
114.9
465.0
815.0
329.0
394.0
346.5
394.5
1873.8
. 482.0
451.0
230.3
22
111.2
465.8
502.3
345.0
395.0
355.0
433.8
1900.0
463.0
436.0
227.0
23
111.9
465.0
516.7
330.0
395.0
345.0
450.0
1900.0
470.0
440.0
225.0
-------
TABU B-5
COAL QUALITY - RAW COAL
NORMAL OPERATING CONDITIONS
CO
I
TEST NO.
LOAD, GROSS (HW)
HIGH HEATING VALUE, BTU/LB
MOISTURE, %
VOLATILE MATTER, *
FIXED CARBON, %
ASH, *
CARBON, %
HYDROGEN, X
OXYGEN, %
NITROGEN, t
SULPHUR, %
HOI C/ MOL H2
CHLORINE, %
Insufficient Sample
1
44.5
10927
11.83
32.16
44.90
11.11
60.40
4.14
8.00
1.21
3.28
2.43
0.03
16
45.5
11523
8.75
33.87
47.19
10.19
64.19
4.51
7.58
1.55
3.20
2.37
0.03
17
46.2
11547
8.28
33.91
47.44
10.37
63.59
4.42
8.67
1.45
3.18
2.40
0.04
2
90.3
11246
9.73
33.30
46.13
10.84
62.58
4.36
7.99
1.26
3.19
2.39
0.05
3
89.6
11170
9.70
33.52
45.78
11.00
61.98
4.24
8.02
1.26
3.80
2.44
-JD
4
91.2
11580
8.59
33.73
47.93
9.75
64.42
4.50
8.13
1.31
3.25
2.39
0.05
5
89.0
11272
11.45
32.70
46.55
9.30
62.61
4.32
8.29
1.24
2.76
2.41
0.03
6
90.9
11305
10.22
33.64
46.49
9.65
63.21
4.31
8.30
1.28
3.00
2.44
0.03
7
89.0
11004
10.80
32 .BO
45.46
12.65
61.48
4.31
7.34
1.30
3.80
2.38
0.03
8
114.4
10985
11.30
32.27
45.57
10.86
61.55
4.14
7.60
1.27
3.24
2.48
0.04
9
115.1
11216
11.33
32.59
46.11
9.97
62.16
4.31
7.80
1.19
3.21
2.40
0.03
10
114.9
11315
9.75
33.41
46.80
10.04
63.17
4.37
8.06
1.34
3.22
2.41
0.05
22
111.2
10794
11.52
33.28
43.28
11.92
61.95
3.96
6.72
1.27
2.58
2.61
0.06
23
111. 9
10847
11.69
32.55
43.76
12.00
62.18
3.93
6.12
1.04
3.00
2.64
0.04
Average
11195
10.35
33.12
45.96
10.69
62.53
4.27
7.76
1.28
3.19
2.44
0.04
-------
TABLE B-6
COAL QUALITY - AS FIRED COAL
NORMAL OPERATING CONDITIONS
03
TEST NO.
LOAD, GROSS (MM)
HIGH HEATING VALUE, BTU/LB
MOISTURE, %
VOLATILE MATTER, X
FIXED CARBON. %
ASH, %
CARBON, %
HYDROGEN, %
OXYGEN, *
NITROGEN, %
SULFUR, %
MOL C/MOL H2
CHLORINE, %
^'insufficient Sample
1
44.5
11567
5.05
34.28
47.53
13.14
64.29
4.42
8.24
1.32
3.52
2.42
0.03
16
45.5
11 605
5.14
35.35
47.85
11.66
65.44
4.47
8.98
0.76
3.47
2.44
0.03
17
46.2
11803
4.82
35.56
47.68
11.94
65.80
4.64
7.93
1.32
3.52
2.36
0.04
2
90.3
11473
5.97
34.39
46.71
12.93
63.40
4.38
8.41
1.34
3.54
2.41
0.05
3
89.6
11431
6.31
34.24
46.89
12.56
63.78
4.40
8.03
1.37
3.51
2.42
..U)
4
91.2
11818
5.58
34.82
48.64
10.96
66.25
4.49
8.02
1.38
3.27
2.46
0.05
5
89.0
11958
6.01
34.40
49.46
10.13
66.68
4.57
8.02
1.40
3.11
2.43
0.03
6
90.9
11843
6.13
34.28
49.72
9.87
66.78
4. SB
8.54
1.35
2.70
2.43
0.03
7
89.0
11567
6.01
33.71
48.41
11.87
64.73
4.42
8.23
1.43
3.24
2.44
0.03
8
114.4
11582
5.35
34.36
47.85
12.44
64.94
4.51
7.94
1.37
3.41
2.40
0.04
9
115.1
11610
5.48
34.18
48.18
12.16
65.06
4.47
7.84
1.40
3.55
2.43
0.03
10
114.9
11786
4.77
34.40
49.12
11.71
65.85
4.50
8.38
1.32
3.43
2.44
0.05
22
111.2
11547
4.59
35.04
47.38
12.99
65.66
4.51
8.29
1.13
2.80
2.43
0.03
23
111.9
11783
5.13
35.91
46.61
12.35
65.83
4.69
7.84
1.15
2.99
2.34
0.02
Average
....
11684
5.45
34.64
48.00
11.91
65.32
4.50
8.19
1.29
3.29
2.42
0.03
-------
TABLE B-7
XOAl QUALITY - RAW COAL
OFF NORMAL CONDITIONS
03
I
CO
TEST NO.
LOAD, GROSS (MW)
HIGH HEATING VALUE, BTU/LB
MOISTURE, %
VOLATILE HATTER, %
FIXED CARBON, %
ASH, %
CARBON, %
HYDROGEN, %
OXYGEN, %
NITROGEN, -%
SULFUR, %
m. C/MOL H?
CHLORINE, X
"'NO Sample
11
115.1
11389
9.11
33.73
46.87
10.29
63.70
4.38
8.01
1.27
3.21
2.42 "
"0.03
12
114.7
11297
10.55
33.31
46.41
9.73
63.08
4.33
7.99
1.33
2.96
2.43
0.03
13
114.8
11142
10.03
32.63
45.81
10.53
62.03
4.28
7.36
1.34
3.40
2.41
0.03
14
110.1
11265
9.12
33.03
46.61
11.24
61.83
4.37
8.27
1.30
3,78
2.36
0.03
15
110.1
11286
10.30
32.99
46.79
9.92
63.49
4.38
7.39
1.39 -•
3.10
2.42
O.TJ3
18
108.9
11303
B.97
32.73
47.30
11.00
63.38
4.40
7.84
1.25
3.13
2.40
0;03
19
114.8
11303
8.99
32.83
46.68
11.50
63.27
4.35
7.06
1.16
3.64
2.42
0.03
20<"
118.1
--
--
-
--
--
-- '
--
--
-
-
--
--
21
114.4
11394
8.11
33.75
46.84
11.30
64.10
4.50
7.38
1.34
3.21
2.37
0.06
Average
--
11297
9.40
33.13
46.66
10.69
63.11
4.37
7.66
1.30
3.30
2.40
0.03
-
-------
TABLE B-8
COAL QUALITY - AS FIRED COAL
OFF NORMAL OPERATING CONDITIONS
CO
I
IO
TEST NO.
LOAD, GROSS (HW)
MOISTURE, *
CARBON, %
HYDROGEN, %
NITROGEN, I
CHLORINE, %
SULFUR, %
ASH, *
OXYGEN, %
VOLATILE MATTER, %
FIXED CARBON, %
HIGH HEATING VALUE, BTU/LB
MOL C/MOL H2
11
115.1
4.57
66.78
4.64
1.37
0.04
3.34
10.91
8.35
35.16
49.36
11957
2.40
12
114.7
B.03
66.18
4.48
1.41
0.04
3.31
11.07
8.48
35.02
48.88
11847
2.46
13
114.8
5.23
65.55
4.48
1.37
0.05
3.39
11.90
8.03
34.78
48.09
11697
2.44
14
110.1
5.17
65.58
4.50
1.38
0.06
3.44
11.59
8.28
34.40
48.84
11803
2.43
15
110.1
5.24
66.55
4.64
1.04
0.07
3.35
11.40
8.71
34.07
49.29
11762
2.35
18
108.9
5.25
63.85
4.68
1.23
0.06
3.42
11.72
9.79
35.65
47.38
11731
2.27
19
114.8
5.50
65.29
4.75
1.29
0.03
3.40
11.56
8.18
35.49
47.45
11782
2.29
20
118.1
5.08
65.26
4.61
1.32
0.03
3.49
11.93
8.28
34.94
48.05
11760
2.36
21
114.4
4.78
65.58
4.65
1.23
0.05
3.72
12.14
7.85
35.37
47.71
11713
2.35
Avg.
...
5.09
65.51
4.60
1.29
0.05
3.43
11.58
8.44
34.99
48.34
11784
2.37
-------
TABLE B-S
COAL QUALITY DATA
COMPOSITES OF 3% SULFUR TESTS
NORMAL OPERATION
TEST
SAMPLE
High Heating Value,
Btu/Lb
H20, wt. %
Ash, wt. %
Volatile Matter, wt. %
Fixed Carbon, wt. %
Sulfur, wt. %
Carbon, wt. %
Hydrogen, wt. %
Nitrogen, wt. %
Oxygen, wt. %
Chlorine, wt. %
Fluorine, ppm
1-10, 16, 17
RAW COAL
11300
10.2
10.1
32.3
47-4
2.9
63.4
4.4
1.3
7.7
0.03
1.15
1-10, 16, 17
AS FIRED COAL
11700
5.3
11.8
35.0
47.9
3,3
65.8
4.6
1,4
7.8
0.02
0.76
B-10
-------
TABLE B-10
COAL QUALITY DATA
COMPOSITES OF 3% SULFUR TESTS
OFF-NORMAL OPERATION
TEST 11-15. 18-21 11-13
SAMPLE RAM COAL AS FIRED COAL
High Heating Value,
Btu/Lb 11400 11700
H20, wt % 8.5 5.5
Ash, wt. % 11.2 11.2
Volatile Matter, wt. % 33.5 35.1
Fixed Carbon, wt. % 46.8 48.2
Sulfur, wt. % 3.2 3.3
Carbon, wt. % 64.1 65.7
Hydrogen, wt. % 4.5 4.5
Nitrogen, wt. % 1.3 1-4
Oxygen, wt. % 7.2 8.8
Chlorine, wt. % 0.06 0.04
Fluorine, ppm 0.95 0.76
B-ll
-------
TABLE B-ll
PULVERIZER PERFORMANCE
NORMAL OPERATING CONDITIONS
I
ro
TEST NO.
LOAD, GROSS (MW)
MOISTURE (RAW COAL), %
MOISTURE (AS FIRED COAL), %
SCREEN SIZE (AS FIRED COAL)
PERCENT THRU 200 MESH
*1 MILL TEMP, "f
K MILL TEMP, "F
}3 MILL TEMP, °F
H MILL TEMP, °F
»] PRIMARY FAN, AMPS
K PRIMARY FAN, AMPS
}3 PRIMARY FAN, AMPS
14 PRIMARY FAN, AMPS
*1 MILL FAN, AMPS
K MILL FAN, AMPS
K MILL FAN, AMPS
#4 MILL FAN, AMPS
NO. OF MILLS IN SERVICE
COAL FEED RATE, MLB/HR"'
(1)Ho sample
'2!Not in service
' M - Thousands
1
14.5
11.83
5.05
..CD
H6
-_tt)
--(«
14E
19
_-<2>
--<2>
21
23
— (2)
..(2)
23
2
43.2
IE
45.5
8.75
5.14
79.6
146
148
146
..(2)
18
20
17
__(2)
20
21
17
__<2>
3
43.9
17
46.2
8.28
4.82
80.6
147
148
147
.-<2>
18
20
18
_-(2>
21
22
17
__C2>
3
44.2
2
90.3
9.73
5.97
73.9
147
147
--W
140
20
20
--<2>
22
25
26
~m
24
3
83.6
3
89.6
9.70
6.31
78.3
147
147
--(2)
141
20
22
__<2)
24
26
26
«<2>
24
3
81.5
4
91.2
8.59
5.58
-C"
148
148
-C2>
144
20
22
__C2)
22
25
26
--(2)
24
3
81.2
5
89.0
11.45
6.01
..(1)
147
147
.-(2)
144
20
22
__(2)
22
25
26
~
24
3
79.0
6
90.9
10.22
6.13
78.6
147
147
-_<2>
144
20
22
__(2)
22
25
26
— (2)
24
3
80.5
7
89.0
9.09
6.01
78.6
148
147
_-(2>
144
20
22
_.<2)
22
25
26
--W
24
3
80.4
8
114.4
11.30
5.35
77.3
147
148
147
147
20
21
19
22
25
26
23
24
4
103.8
S
115.1
11.33
5.48
75.8
147
148
146
146
20
21
19
21
26
26
23
25
4
10B.O
10
114.9
9.75
4.77
76.7
148
148
147
146
21
22
19
22
25
26
23
25
4
102.8
22
111.2
11.62
4.59
77.4
151
150
146
124
19
20
19
23
26
25
27
28
4
103.2
23
111.9
11.69
5.13
73.8
150
150
148
134
19
19
19
22
26
24
27
29
4
103.6
-------
TABLE B-12
PULVERIZER PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
co
i
co
TEST NO.
LOAD, GROSS (MM)
MOISTURE (RAW COAL), %
MOISTURE (AS FIRED COAL), %
SCREEN SIZE (AS FIRED COAL)
PERCENT THRU 200 MESH
#1 MILL TEMP, °F
12 MILL TEMP, "F
*3 MILL TEMP, "F
*4 MILL TEMP, °F
*1 PRIMARY FAN, AMPS
R PRIMARY FAN, AMPS
03 PRIMARY FAN, AMPS
#4 PRIMARY FAN, AMPS
#1 MILL FAN, AMPS
K MILL FAN, AMPS
#3 MILL FAN, AMPS
#4 MILL FAN, AMPS
NO. OF MILLS IN SERVICES
COAL FEED RATE, MLB/HR^2'
(I'NO sample
'M - Thousands
11
115.1
9.11
4.57
73.7
148
147
147
146
21
22
19
22
25
26
23
24
4
101.7
12
114.7
10.55
5.03
76.0
147
148
146
146
20
21
18
21
25
26
23
24
4
102.4
13
114.8
10.03
5.23
79.3
147
148
146
146
20
21
19
22
25
26
23
24
4
103.5
14
110.1
9.12
5.17
80.8
147
148
147
146
20
22
19
22
25
27
23
23
4
98.9
15
110. 1
10.30
5.24
80.4
147
148
146
145
20
22
19
22
25
26
23
24
4
99.2
ie
108.9
8.97
5.25
75.3
147
149
146
149
20
21
19
21
25
26
23
24
4
99.9
19
114.8
8.99
5.50
75.3
147
150
147
150
20
21
19
21
25
26
23
24
4
104.4
20
118.1
..(1)
5.08
79.8
147
148
146
149
20
22
20
22
25
26
23
25
4
103.9
21
114.4
8.11
4.78
76.0
147
148
146
150
21
21
20
22
25
26
23
24
4
103.1
-------
TABLE B-13
AIR HEATER PERFORMANCE
NORMAL OPERATING CONDITIONS
00
I
TEST NO.
LOAD, GROSS (MW)
AIR INLET TEMP, °F
AIR OUTLET TEMP, °F
GAS INLET TEMP, °F
GAS OUTLET TEMP, °F
GAS OUTLET, TEMP-ADJUSTED, °F
INLEAKAGE, %
INLET 02, VOL %
OUTLET 02, VOL %
EXCESS AIR INLET, %
EXCESS AIR OUTLET, %
AIR A, °F
GAS A, "F
FLUE GAS INLET, (WET) MLB/W
FLUE GAS OUTLET, (WET) MLB/HR
TOTAL HEAT INPUT, MMBTU/KR
TOTAL HEAT LOSS, MHBTU/HR
STOICHIOMETRIC 0^, L8/LB COW.
AIR/COAL RATIO, W/W
HEAT RECOVERY ACROSS AIR
HEATER . MMBTU/HR
HEAT RECOVERY, % Of TOTAL
HEAT INPUT
HEAT LOSS DUE TO EXCESS AIR,
I Of TOTAL LOSS
HEAT LOSS DUE TO EXCESS AIR,
% OF TOTAL HEAT INPUT
(1)
« - Thousands
1
44.5
155
544
635
274
290
12.9
9.6
11.1
80
105
389
361
677
763
472
70.6
1.88
16.8
69
14.6
29.9
4.3
16
45.5
117
567
647
275
302
7.2
9.3
11.0
73
102
449
372
712
820
506
76.5
2.02
17.8
87
17.2
30.0
4.5
17
46.2
114
571
652
276
298
18.6
9.4
10.9
78
101
456
376
721
809
511
75.2
1.98
17.4
87
17.0
30.0
4.4
2
90.3
171
546
665
294
302
8.5
6.6
7.6
43
53
374
371
1098
1171
940
121.8
1.96
13.1
102
10.9
19.1
2.4
3
89.6
170
540
654
291
291
17.9
5.0
7.8
30
56
369
363
973
1153
910
115.7
1.94
13.3
99
10.9
19.7
2.5
4
91.2
172
550
664
293
310
17.7
4.9
7.0
29
47
378
370
999
1126
940
12D.fi
2.02
13.0
98
10.4
17.4
2.2
5
89.0
146
540
648
291
313
21.8
3.9
6.7
22
44
371
357
893
1040
891
115.6
1.95
12.3
89
10,0
16.2
2.1
6
90.9
170
S55
666
299
319
15.3
4.9
7.2
29
49
385
367
965
1103
910
11B.7
1.97
12.8
98
10. 8
18.1
2.3
7
89.0
166
552
655
266
280
18.2
4.9
7.1
29
48
386
389
953
1079
855
104.0
1.94
12.5
97
11.3
16.3
2.0
8
114.4
160
560
669
319
344
25.0
2.4
5.1
12
30
399
350
1075
1226
1141
146.6
1.92
10.9
113
9.9
11.9
1.5
9
115.1
155
565
675
318
343
26.3
2.6
5.3
14
31
410
357
1115
1269
1177
152.6
1.94
11.2
120
10.2
12.0
1.5
10
114.9
157
583
686
322
354
23.5
3.4
6.4
19
41
427
364
1146
1344
1162
155.1
1.98
12.2
132
11.4
16.1
2.1
22
111.2
198
575
675
327
353
8.6
6.1
7.2
40
51
378
348
1293
1385
1114
163.8
1.91
12.5
121
10.9
17,8
2.7
23
111.9
190
575
675
320
346
7.9
4.5
5.8
27
37
385
355
1194
1286
1123
155.3
1.92
11.5
114
10,2
18.2
2.5
-------
TABLE B-14
DRAFT LOSSES (in. W.C.)
NORMAL OPERATING CONDITIONS
CO
Test
Air, Air Heater
Ducts and Dampers A.P.H. to
Burners, Burners and Windbox
Total Air Resistance
Furnace and Convection Banks
Flues to A.H.
Gas, Air Heater
Total Gas Resistance
Total Boiler Resistance
1
2.2
1.1
3.3
2.5
0.5
3.0
6.0
9.3
2
4.7
2.1
6.8
2.9
1.6
4.6
9.1
15.9
3
4.5
2.1
6.6
3.5
0.6
5.1
9.2
15.8
4
4.0
2.8
6.8
2.8
1.2
4.5
8.5
15.3
5
4.6
2.0
6.6
3.3
1.2
4.4
8.9
15.5
6
4.1
2.5
6.6
2.8
1.2
4.5
8.5
15.1
7
4.0
2.3
6.3
3.5
0.5
4.4
8.4
14.7
8
4.8
1.5
6.3
5.0
1.0
5.6
11.6
17.9
9
4.4
2.0
6.4
3.6
2.4
5.9
11.9
18.3
10
4.8
2.5
7.3
5.0
1.1
6.3
12.4
19.7
16
1.9
1.0
2.9
3.2
..0)
3.0
..(2)
-J2)
17
1.8
1.0
2.8
2.4
0.6
3.0
6.0
8.8
not available.
Incomplete data.
-------
TABLE B-15
DRAFT LOSSES (in. W.C.)
OFF NORMAL CONDITIONS
co
CD
Test
Air, Air Heater
Ducts and Dampers A.P.H. to
Burners, Burners and Windbox
Total Air Resistance
Furnace and Convection Banks
Flues to A.H.
Gas, Air Heater
Total Gas Resistance
11
4.7
2.9
7.6
5.0
1.0
6.0
12.0
12
4.7
1.8
6.5
4.2
1.7
5.9
11.8
13
4.5
_LZ
6.2
4.2
1.6
6.0
11.8
14
5.3
1.9
7.2
4.7
1.2
JLJ-
12.0
15
5.2
2.2
7.4
4.8
1.2
6.2
12,2
18
4.6
2.6
7.2
4.5
1.6
5.7
11.8
19
4.3
1.9
6.2
4.5
1.5
5.5
11.5
20
4.4
2.2
6.6
3.8
1.7
5.9
11.4
21
4.6
2.5
7.1
3.8
1.7
5.4
10.9
Total Boiler Resistance 19.6 18.3 18.0 19.2 19.6 19.0 17.7 18.0 18.0
-------
TO
I
TABLE B-16
DRAFT LOSSES Cin. W.C.)
OFF NORMAL CONDITIONS
(Low Sulfur Coal)
Test
Air, Air Heater
Ducts and Dampers A.P.H. to
Burners, Burners and Windbox
Total Air Resistance
Furnace and Convection Banks
Flues to A.H.
Gas, Air Heater
Total Gas Resistance
Total Boiler Resistance
26
5.0
0.0
5.0
2.7
0.3
1.7
4.7
9.7
27
5.0
0.0
5.0
2.7
0.3
1.7
4.7
9.7
28
3.4
2.2
5.6
3.2
0.8
3.9
7.9
13.5
29
2.9
1.3
4.2
3.5
0.7
4.2
8.4
12.6
30
4.0
0.8
4.8
3.8
0.8
4.7
9.3
14.1
31
1.5
1.5
3.0
4.0
1.0
4.0
9.0
12.0
32
3.3
2.0
5.3
3.8
0.5
4.0
8.3
13.6
34
2.3
1.8
4.1
3.7
0.5
4.0
8.2
12.3
24
4.1
2.2
6.3
4.5
1.5
4.5
10.5
16.8
25
4.1
2.1
6.2
4.0
1.1
5.6
10.7
16.9
33
3.2
2.0
5.2
4.7
1.0
5.0
10.7
15.9
35
4.9
2.3
7.2
4.3
1.8
4.5
10.6
17.8
-------
TABU B-17
MEASLRED AND CALCULATED FLUE GAS RATES
NORMAL OPERATING CONDITIONS
03
00
TEST NO.
LOAD, GROSS (MW)
MEASURED -
- OUTLET FLUE GAS VOLUME, MSCFM(1)
- OUTLET FLUE GAS VOLUME, MACFMW
CALCULATED -
- OUTLET FLUE GAS VOLUME, TISCFM
- OUTLET FLUE GAS VOLUME, MACFMH
MEASURED -
- INLET FLUE GAS VOLUME, MSCFM
- INLET FLUE GAS VOLUME, MACFMW
CALCULATED -
- IHLET RUE GAS VOLUME, MSCFM
- INLET FLUE GAS VOLUME, MACFMW
-M - Thousands
'NO sample taken
1
44.5
184
270
159
232
Z54
584
141
319
16
45.5
267
384
171
243
243
566
148
335
17
46.2
243
345
169
239
240
563
151
344
2
90.3
273
397
248
358
319
753
232
517
3
89.6
268
401
236
350
325
764
199
457
4
91.2
210
311
230
335
326
768
204
467
5
89.0
206
304
213
312
310
720
183
413
6
90.9
194
284
226
328
344
811
198
452
7
89.0
235
352
223
331
361
853
197
445
8
114.4
214
344
249
386
287
702
218
518
9
115.1
251
400
256
403
307
766
225
542
10
114.9
300
462
273
419
323
779
233
548
22(2)
111.2
--
-
284
390
--
--
—
--
23(2)
111.9
--
--
264
362
--
—
—
—
-------
TABLE B-18
MEASURED AND CALCULATED FLUE GAS RATES
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
CO
I
TEST NO.
LOAD, GROSS (MU)
MEASURED -
- OUTLET FLUE GAS VOLUME,«SCFM(1)
- OUTLET FLUE GAS VOLUME, MACFMH
CALCULATED -
-, OUTLET FLUE GAS VOLUME, MSCFM
- OUTLET FLUE GAS VOLUME, MACFMW
MEASURED -
- INLET FLUE GAS VOLUME, MSCFM
- INLET FLUE GAS VOLUME, MACFMW
CALCULATED -
- INLET FLUE GAS VOLUME, MSCFM
- INLET FLUE GAS VOLUME, MACFMW
(1)M - thousands
'2'l(o Sanple
11
116.1
256
407
209
426
431
1053
231
553
12
114.7
285
438
264
549
3B3
905
230
532
13
114.6
2B1
434
260
399
335
322
232
353
14
110.1
-.(2)
--(2)
265
410
351
850
227
541
15
110.1
333
509
270
409
365
877
242
565
18
108.9
313
492
283
442
373
900
236
541
19
114.8
343
529
277
423
306
744
229
543
20
118.1
356
545
302
460
312
761
225
535
21
114.4
370
572
310
476
163
406
241
578
-------
TABLE B-19
FLUE GAS PRESSURE, VOLUME, AND TEMPERATURE DATA
NORMAL OPERATING CONDITIONS
D3
I
ro
o
TEST NO.
LOAD, GROSS (MW)
TEMP (OUTLET APH) , °F
TEMP (OUTLET ID FAN), °F
STATIC PRESSURE (INLET APH),
in H20
STATIC PRESSURE (OUTLET ID FAN),
in' H20
BAROMETRIC PRESSURE, in HG
FLUE GAS VOLUME (OUTLET ID FAN),
(WET) MACFM^
FLOE GAS VOLUME (OUTLET ID FAN),
MSCFMD
FLUE GAS MASS RATE (DRY), MLB/HR
FLUE GAS MASS RATE (WET) , MLB/HR
OUTLET ID FAN - 02, X
- COg (DRY), t
- H20, *
- MW(2) (DRY)
- MM (MET)
EXCESS AIR (OUTLET ID FAN) , %
1
44.5
Z73.5
261.0
-4.2
1.4
29.33
232
159
723
763
11.1
8.5
5.2
29.88
29.27
104
16
45.5
275.3
245.0
-3.3
0.5
29.50
243
171
775
820
11.0
8.1
5.5
29.92
29.26
102
17
46.2
276.4
243.0
-3.3
0.5
29.52
239
169
769
809
10.9
8.6
4.9
29.88
29.30
101
2
90.3
293.6
273.0
-3.3
2.5
29.50
358
248
1131
1171
7.6
11.2
3.4
29.83
29.43
53
3
89.6
291 .3
268.0
-4.2
2.5
29.46
350
236
1077
1153
7.8
12.3
6.6
30.26
29.45
56
4
91.2
293.3
267. D
-3.3
2.5
29.70
335
230
1052
1126
7.0
12.4
6.6
30.29
29.48
47
5
89.0
290.9
263.0
-4.5
2.5
29.63
312
213
974
1040
6.7
11. B
6.3
30.19
29.43
44
6
90.9
298.9
259.0
-3.9
2.5
29.65
328
226
1035
1103
7.2
11.8
^.2
30.23
29.47
49
7
89.0
265.5
279.0
-4.5
2.5
29.60
555
223
1016
1079
7.1
11.5
5.8
30.11
29.41
48
8
114.4
318.8
293.0
-4.J
2.5
29.36
386
249
1138
1226
5.1
12.9
7.2
30.37
29.48
30
9
115.1
317.9
295.0
-3.9
0.5
27.35
403
256
1167
1269
5.2
13.4
8.0
30.37
29.41
31
10
114.9
322.3
298.6
-5.2
0.5
29.98
419
273
1249
1344
6.4
12.6
7.1
30.37
29.49
41
22
111.2
326.7
364
265
1299
13B5
6.1
14.9
6,2
30.19
29.44
40
23
111.9
320.0
362
264
1206
1286
5.8
14.9
6.2
30.20
29.45
37
'M - Thousands l 'MW - Molecjlar Weight
-------
TABLE B-20
SULFUR OXIDES. EMISSION RATES AND CONCENTRATIONS
NORMAL OPERATING CONDITIONS
TEST NO.
LOAD, GROSS (MW)
Sulfur In AF Coal, Ib/lb coal
Outlet ID fan:
SOo, ppro
S03, ppm
S03/S02, (v/v)
S02/02, (v/v)
S02, Ib/hr
S03, Ib/hr
S02, lb/MMBtu'2'
S02 + S03, Ib/hr
1
44.5
0.033
1757
18
0.01
0.02
2776
35
5.9
2807
(2) Outl
W H-th
16
45.5
0.032
1742
104
0.06
0.02
2949
220
5.8
3162
ir values
jsands
17
46.2
0.032
1806
55
0.03
0.02
3031
115
5.9
3142
not used
2(1)
90.3
0.032
1278
40
0.03
0.02
3142
123
3.3
3259
in data a
3
89.6
0.038
2402
54
0.02
0.03
5616
158
6.2
5789
alyses
4
91.2
0.033
2679
74
0.03
0.04
6107
211
6.5
6335
5
89.0
0.028
2516
40
0.02
0.04
5328
106
6.0
5454
6
90.9
0.030
1952
48
0.03
0.03
4381
135
4.8
4510
7
89.0
0.038
2373
53
0.02
0.03
5243
146
5.9
5390
8
114.4
0.032
2809
32
0.01
0.06
6230
99
6.1
7061
9(D
115.1
0.032
4044
73
0.02
0.08
10257
231
8.7
10494
10
114.9
0.032
2719
107
0.04
0.04
7358
362
6.3
7704
co
i
ro
-------
TABLE B-21
SULFUR OXIDES, EMISSION RATES AND CONCENTRATIONS
OFF NORMAL OPERATING CONDITIONS
CO
I
ro
TEST NO.
LOAD, GROSS (MW)
Sulfur 1n AF Coal, Ib/lb coal
Outlet ID fan:
S02, ppm
S03, ppm
S03/S02, (v/v)
S02/02> (v/v)
S02, Ib/hr
S03, Ib/hr
S02, Ib/MMBtu'1'
S02 + S03, Ib/lb coal
(1)M - thousands
11
115.1
0.032
2495
91
0.036
0.040
6655
303
5.7
0.068
< HI «
12
114.7
0.030
2522
123
0.049
0.042
660B
403
5.7
0.068
rain Load
13
114.8
0.034
2968
102
0.034
0.051
6059
329
7.0
0.081
14
110.1
0.038
2686
92
0.034
0.038
7075
303
6.3
0.075
15
110.1
0.031
2641
88
0.033
0.040
7076
295
6.3
0.074
lombustlori
18
108.9
0.031
2613
47
0.016
0.035
7346
165
6.5
0.075
19
114.8
0.036
2590
63
0.024
0.040
7120
216
6.0
0.070
20
11B.1
0.034
2502
56
0.022
0.032
7505
210
5.8
0.074
21
114.4
0.032
1991
43
0.022
0.025
6121
165
5.2
0.061
-------
TABLE B-22
PAITICULATE EMISSION RATES AND CONCENTRATIONS
NORMAL OPERATING CONDITIONS
CO
INS
CO
TEST NO.
LOAD, GROSS (HW)
SOOT BLOWING STATUS
INLET APH^1', GR/ACF
INLET APh'1', GR/SCF
INLET APH(1 ' , LB/HR
OUTLET ID FAN'", GR/ACF
OUTLET ID FAN(1), GR/SCF
OUTLET ID FAN(1), LB/HR
OUTLET ID FAN(2>. GR/ACF
OUTLET ID FAN^2', GR/SCF
OUTLET ID FAN(2), LB/HR
OUTLET ID FAN'2', LB/MMBTu'3'
DUST COLLECTOR EFF. , 2
ASH IN RAM COAL, %
'''ASIC Method
'2*EPA Method
'3'M - Thousands
1
44.5
Off
0.469
1.071
1298
0.025
0.037
50
0.085
0.124
169
0.36
96.5
11.1
16
45.5
Off
0.911
2.110
2675
0.021
0.029
42
0.064
0.092
134
0.26
98.6
10.2
17
46.2
Off
0.985
2.290
2966
o.oie
0.026
38
0.033
0.047
68
0.13
98.9
10.4
2
90.3
Off
1.091
2.555
5087
0.190
0.274
582
0.244
0.353
750
0.80
B9.3
10.8
3
89.6
On
2.463
5.750
9802
0.166
0.249
503
0.458
0.680
1373
1.51
95.7
11.0
4
91.2
Off
1.643
3.835
6706
0.087
0.130
256
0.261
0.384
756
0.80
96.6
9.8
5
89.0
On
1.837
4.235
6659
0.106
0.157
287
0.143
0.205
382
0.43
96.3
9.3
6
90.9
Off
1.387
3.242
55D3
0.086
0.131
254
0.132
0.191
370
0.41
96.0
9.7
7
89.0
On
2.297
5.384
9080
0.178
0.262
500
0.217
0.323
617
0.70
95.1
12.7
8
114.4
Off
1.497
3.638
6807
0.233
0.363
774
0.332
0.515
1098
0.96
90.0
10.9
9
115.1
Off
1.902
4.716
9084
0.224
0.359
787
0.385
0.608
1332
1.13
92.4
10.0
10
114.9
Off
1.684
4.036
8047
0.239
0.368
860
0.277
0.426
996
0.86
90.9
10.0
-------
TABLE B-23
TRACE METALS IN OUTLET FLUE GAS PARTICULATE
ppm DRY WEIGHT BASIS
Normal Operation
Test
Test Condition
Arsenic
Selenium
Lead
Zinc
Silver
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
1,16,17
46-3-WO
87
1055
326
0
59
747
2,4,6 3,5,7
92-3-WO 92-3-WI
62
106
85
115
142 1 137
114
12
97
227 215
968 293
77 1 108
178 | 30
2763
10870
0
494
55
4719
65136
409
21855
23
372
175
535
54489
777
6
131
205
307
44
33
338
17498
20
417
185
0
56313
8,9,10
115-3-WO
68
43
142
274
7
76
204
204
116
16
286
17886
18
316
190
258
53140
1-10,16,17
All (avg.)
76
830
187
291
21
138
213
442
86
64
949
17027
15
405
157
198
57257
B-24
-------
TABLE B-24
TRACE METALS IN OUTLET FLUE GAS PARTICULATE
ppm DRY WEIGHT BASIS
Off Normal Operation
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Fluorine
Silver
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
11,12,13
115-3-WO
64
163
139
»_ _
387
•»•••.
8
79
269
194
58
21
259
15950
20
284
175
564
47385
B-25
-------
TABLE B-25
TRACE ELEMENTS IN AS FIRED COAL
ppm DRY WEIGHT BASIS
Normal Operation
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Fluorine
Silver
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
1-10,16,17
All
0.68
<1
18
0.16
36
68
2
12
40
16
4
<0.5
56
2462
1
22
75
32
8615
1,16,17
46-3-WO
0.90
<1
12
0.14
68
__
2
19
50
14
12
<.5
66
2113
<.5
18
102
39
8819
2,4,6
92-3-WO
2.2
<1
12
0.13
52
__
2
14
42
15
7
<.5
43
2100
2
22
83
69
8239
3,5,7
92-3-WI
1.8
<1
12
0.10
56
__
2
13
42
11
5
<1
46
1700
3
12
88
65
8328
8-10
115-3-WO
2.6
<1
9
0.11
47
--
2
12
43
15
7
<.6
45
2625
2
17
68
72
7332
B-26
-------
TABLE B-26
TRACE ELEMENTS IN AS FIRED COAL
ppm DRY WEIGHT BASIS
Off Normal Operation
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Fluorine
Silver
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryl 1 i urn
Vanadium
Magnesium
Antimony
Iron
11,12,13
115-3-WO
1.9
<1
14
0.1
54
.__
2
11
48
11
11
<0.5
50
2425
2
12
68
40
10282
B-27
-------
TABLE B-27
TRACE ELEMENTS IN RAW COAL COMPOSITES
ppm DRY WEIGHT BASIS
3% SULFUR
Test
Metal
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Fluorine
Silver
Copper
Manganese
Nickel
Tin
Cadmi um
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
11-15,18-21
Off Normal
1.5
<1
20
0.5
21
___
1
14
40
18
0
<.5
53
2762
2
17
83
26
8555
B-28
-------
TABLE B-28
TRACE ELEMENTS IN RAW COAL COMPOSITES
ppm DRY WEIGHT BASIS
3% SULFUR
Test
Metal
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Fluorine
Silver
Copper
Manganese
Nickel
Tin
Cadmium
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
1-10,16,17
Normal
1.5
<1
20
.89
58
71
4
12
53
18
5
<.5
60
3575
7
18
170
46
10558
B-29
-------
TABLE B-29
FLUE GAS CHARACTERIZATION SUMMARY
OFF NORMAL OPERATING CONDITIONS
CO
I
co
o
TEST NO.
LOAD, GROSS (MW)
SOOT BLOWING STATUS
RAW COAL FEED RATE, MLB/HRCl)
RAH COAL MOISTURE, %
RAW COAL ASH, %
RAW COAL SULFUR, %
RAW COAL HIGH HEATING VALUE,
BTU/LB
RAW COAL SULFUR, LB/HR
WW COAL ASH, LB/HR
TEMP (OUTLET ID FAN), °F
STATIC PRESSURE (OUTLET ID FAN),
" Hg
:LUE GAS VOL (OUTLET ID FAN),
1SCFMD
S02, PPM
S02, LB/HR
I0x/S0j, MOL N02/MOL SOj
'ART (OUTLET ID FAN), Gr/ACF
(Ox, PPM
IOX, LB/HR
iXCESS AIR (OUTLET ID FAN), %
11
115.1
Off
101.7
9.1
10.3
3.2
11400
3251
10465
302
0.04
269
2495
6655
0.049
0.642
123
236
40
12
114.7
Off
102.3
10.6
9.7
3.0
11300
3066
9913
288
0.17
264
2522
6609
0.030
0.400
76
143
37
13
114.8
Off
103.5
10.0
11.5
3.4
11100
3522
11914
289
0.17
260
2968
8059
0.030
0.530
94
174
36
14
110.1
Off
98.9
9.1
11.2
3.8
11300
3762
11088
289
0.1B
266
2686
7075
0.021
-.(2)
56
106
47
15
11Q.1
Off
99.2
10.3
9.9
3.1
11300
3770
9821
288
0.18
270
2641
7076
0.019
0.178
50
96
43
18
108.9
Off
98.9
9.0
11.0
3.1
11300
3094
10978
298
0.11
283
2612
7346
0.039
0.140
103
208
52
19
114.8
Off
104.4
9.0
11.5
3.6
11300
3758
12006
264
0.11
277
2585
7120
0.032
0.142
83
164
41
20
118.1
Off
103.9
8.6
11.5
3.4
12400
-_<2)
..&
276
0.12
302
2502
7505
0.047
0.186
117
2il
21
114.4
Off
103.1
8.1
11.3
3.2
11400
3296
11639
279
0.15
310
1991
6121
0.068
0.176
136
3?g
'Sample Lost
-------
TABLE B-30
PARTICULATE EMISSION RATES AND CONCENTRATIONS
OFF NCRMAL OPERATING CONDITIONS
CO
I
CO
TEST HO.
LOAD, GROSS (HW)
SOOT BLOWING STATUS
INLET APH(1), GR/ACF
INLET APH(1), GR/SCF
INLET APH(1), LB/HR
OUTLET ID FAN(1), GR/ACF
OUTLET ID FAN(1), GR/SCF
OUTLET ID FAN(1), LB/HR
OUTLET ID FAN(2), GR/ACF
OUTLET ID FAN(2), GR/SCF
OUTLET ID FAN<2), LB/HR
OUTLET ID FAN(2), LB/MMBTU(I°
DUST COLLECTOR EFF., X
ASH IN RAW COAL, %
'^ASME Method
[Pl
' 'EPA Method
'3 'sample lost
d)
M - Thousands
11
115.1
Off
0.954
2.312
4576
0.704
1.118
2576
0.642
1.015
2339
2.02
51.6
10.3
12
114.7
Off
1.529
3.584
7051
0.426
0.646
1463
0.399
0.609
1379
1.19
82.0
9.7
13
114.8
Off
1.622
3.950
7849
0.455
0.706
1574
0.530
0.813
1812
1.57
82.1
11.5
14
110.1
Off
1.650
3.980
7756
0.067
0.104
237
--(3)
..(3)
-_<3)
-<3)
97.4
11.2
15
110.1
Off
1.B30
4.360
9048
0.068
0.105
243
0.178
0.270
625
0.56
97.6
9.9
IB
108.9
Off
1.350
3.230
6S46
0.061
0.096
233
0.140
0.219
532
0.47
97.0
11.0
19
114.8
Off
1.440
3.480
6839
0.069
0.105
249
0.142
0.217
515
0.44
97.0
11.5
20
118.1
Off
1.694
4.100
7914
0.139
0.214
554
0.186
0.283
733
0.57
94.8
11.5
21
114.4
Off
1.062
2.617
5402
0.109
0.168
446
0.176
0.271
720
0.61
93.6
11.3
-------
TABLE B-31
FLUE GAS, PRESSURE, VOLUME AND TEMPERATURE DATA
OFF NORMAL OPERATING CONDITIONS
co
i
co
ro
TEST NO.
LOAD, GROSS (MW)
TEMP (OUTLET APH), °F
TEMP (OUTLET ID FAN), °F
STATIC PRESSURE (INLET APH),
in H20
STATIC PRESSURE (OUTLET ID FAN),
in HG
BAROMETRIC PRESSURE, in HG
FLUE GAS VOLUME (OUTLET ID FAN),
(WET) MACFMll)
FLUE GAS VOLUME (OUTLET ID FAN),
MSCFMD
FLUE GAS MASS RATE (DRY), MLB/HR
FLUE GAS MASS RATE (WET) , MLB/HR
OUTLET ID FAN - 02, %
- COj (DRY), t
- H20, *
- MW<2) (DRY)
- MW (WET)
EXCESS AIR (OUTLET ID FAN), %
11
115.1
324.8
302.0
-4.1
0.04
29.40
425
269
1232
1333
6.3
13.1
7.6
30.47
29.52
40
12
114.7
311.9
288.0
-4.1
0.17
29.68
549
264
1210
1302
6.0
12.9
7.1
30.40
29.52
37
13
114.8
312.5
289.0
-4.1
0.17
29.50
399
260
1192
1283
5.8
13.0
7.1
30.43
29.55
36
14
110.1
312.0
289.0
-4.1
0.18
29.60
410
265
1215
1321
7.0
12.6
8.0
30.50
29.50
47
15
110.1
312.3
288.0
-3.9
0.18
29.57
409
270
1237
1320
6.6
12.3
6.3
30.28
29.51
43
18
108.9
313.1
298.0
-5.0
0.11
29.55
442
283
1296
1401
7.5
11.2
7.5
3Q.39
29.46
52
19
114.8
308.1
284.0
-5.0
0.11
29.51
423
277
1270
1369
6.4
12.5
7.2
30.45
29.56
41
20
118.1
297.2
275.8
-5.0
0.12
29.39
460
302
1377
1489
7.8
11.5
7.5
30.29
29.37
55
21
114.4
298.8
279.0
-5.0
0.15
29.32
476
310
1410
1531
8.0
11.5
7.9
30.31
29.34
58
TTTM - Thousands UJMW - Molecular Weight
-------
TABLE B-32
ELECTROSTATIC PRECIPITATOR PERFORMANCE
NORMAL OPERATING CONDITIONS
CO
CO
TEST NO.
LOAD, GROSS (MW)
AVG CURRENT, raA
AV6 VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
AVG CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
AVG CURRENT, raA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
DUST COLLECTOR EFFICIENCY, %
EFFICIENCY FACTOR
OVERALL CORONA POWER, WATTS
SPECIFIC POWER (OVERALL),
WATTS/FT?
SOOT BLOWING STATUS
FLOW, MACFM (WET)(2)
APPLICATION FACTOR
MIGRATION VELOCITY, FT/SEC
CORONA POWER, KW
USEFUL CORONA POWER, WATTS/MACFM
'^Partial data
M - Thousands
\
41.5
60/60
29/23
3120
0.107
100/100
27/29
5670
0.390
100/100
24/29
5300
0.364
96.5
33.5
14090
0.242
Off
232
133
0.2
14.1
60.8
16
45.5
300/310
26/28
16480
0.566
143/143
24/25
7065
0.485
120/120
29/23
6204
0.426
98.6
42.7
Z9749
0.511
Off
Z43
178
0.3
29.7
122.2
17
46.2
300/310
26/29
16688
0.573
115/115
24/26
5750
0.395
120/120
29/24
6360
0.437
98.9
45.1
Z8798
0.495
Off
239
130
0.2
28.8
120.5
2
90.3
150/150
10/10
3000
0.103
90/90
30/32
5526
0.380
100/100
27/30
5730
0.394
89.3
22.3
14Z56
0.245
Off
358
137
0.2
14.3
39.9
3
89.6
150/150
10/10
3000
0.103
90/90
29/31
5454
0.375
100/100
27/30
5760
0.396
95.7
31.5
14214
0.244
On
350
189
0.3
14.2
40.6
4
91.2
60/30
60/24
3222
0.111
100/100
27/29
5540
0.381
100/100
25/28
5530
0.380
96.6
33.8
14292
0.245
Off
335
195
0.3
14.3
42.7
5
89.0
60/60
29/24
31 80
0.109
100/26
100/28
5400
0.371
100/100
25/27
5740
0.353
96.3
33.0
137ZO
0.236
On
312
177
0.3
13.7
44.0
6
90.9
60/60
29/24
31 S3
0.108
90/80
26/28
4556
0.313
93/1.00
25/28
5123
0.352
96.0
32.2
12832
0.220
Off
328
181
0.3
12.8
39.1
7
89.0
59/60
30/25
3?7n
0.112
80/80
26/27
4264
0.293
90/100
25/28
5050
8
114.4
125/125
29/25
6750
0.232
117/117
37/38
8775
0.603
85/100
30/33
5921
0.347 \ 0.407
95.1
30.2
12584
0.216
On
331
171
0.3
12.6
38.0
90.0
23.0
21446
0.368
Off
386
152
0.3
21.4
53.2
9
115.1
50/45
27/24
2452
0.084
98/95
38/40
7529
0.517
90/100
31/33
6142
0.422
92.4
25.8
16123
0.277
Off
403
178
0.3
16.1
40.0
10
114.9
122/128
17/11
3445
0.118
130/120
37/38
9391
0.645
on/11'
32/(1)
32/(D
-J1'
90.9
24.0
12836(1)
.- (1)
Off
419
173
0.3
12.0'1'
-.(1)
-------
TABLE B-33
ELECTROSTATIC PRECIPITATOR PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
CO
TEST NO.
LOAD, GROSS (I*)
AVG CURRENT, roA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
AVG CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
AVG. CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
DUST COLLECTOR EFFICIENCY, %
EFFICIENCY FACTOR
OVERALL CORONA POWER, WATTS
SPECIFIC POWER (OVERALL),
WATTS/FT2
SOOT BLOWING STATUS
FLOW, MACFM (WET)'2)
APPLICATION FACTOR
MIGRATION VELOCITY, FT/SEC
CORONA POWER, KM
USEFUL CORONA POWER, WATTS/HACFM
•"•'Out of service '2'M - Thousands
Hot used in correlation of effi
11
115.1
117/102
21/18
4297
0.148
110/107
36/38
7917
0.544
..(1)
__(H
51.6
7.3
12214
0.210
Off
426
53
0.1
12.2
28.7(3)
.ency vs .
12
114.7
88/83
38/32
5992
0.206
113/113
33/36
7818
0.537
..(1)
-<1>
82.0
17.1
13810
0.237
Off
549
161
0.3
13.8
24.013'
useful coi
13
114.8
135/130
40/34
9778
0.336
110/110
34/37
7755
0.533
..(1)
..(1)
82.1
17.2
17533
0.301
Off
399
118
0.2
17.5
44.0(3)
ona power
14
110,1
119/118
40/34
8754
0.301
120/120
33/35
8166
0.561
290/320
34/35
20995
1.44
97.4
36. S
37915
0.651
Off
410
257
0.4
37.9
92.5
IE
110.1
118/117
39/32
8340
0.286
125/125
33/35
8438
0.580
288/320
33/34
20304
1.40
97.6
37.3
37082
0.637
Off
409
262
0.4
37.1
90.6
18
108.9
120/120
39/32
8520
0.293
118/118
31/33
7491
0.515
285/300
31/33
18855
1.30
97.0
35.1
34866
0.599
Off
442
266
0.4
34.9
78.9
19
114.8
109/109
39/33
7919
0.272
105/108
31/34
6921
0.475
280/300
31/34
18950
1.30
97.0
35.1
33790
0.580
Off
423
255
0.4
33.8
79.8
20
118.1
280/300
31/32
18286
0.628
120/120
32/34
7920
0.544
98/107
40/33
7453
0.51
94.8
29.6
33659
0.578
Off
460
234
0.4
33.7
73.2
21
114.4
2SO/300
30/32
18000
0.618
120/120
30/33
7600
0.522
111/110
39/32
7816
0.54
93.6
27.5
33416
0.574
Off
476
225
0.4
33.4
70.Z
-------
MEASURED AND CALCULATED FLUE GAS RATES
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
CD
tn
TEST NO.
LOAD, GROSS (MW)
MEASURED -
- OUTLET FLUE GAS VOLUME,
MSCFMt2)
- OUTLET FLUE SAS VOLUME, MACFMW
CALCULATED -
- OUTLET FLUE GAS VOLUME, MSCFM
- OUTLET FLUE SAS VOLUME, MACFMW
'•"•'Outlier (Hot used in Data Analy
M - Thousands
Mo Sample
26
44.1
151
213
131
183
iia)
27
44.5
147
216
125
183
•
28
89.8
-.(3)
-.(3)
231
344
29U)
88.7
252
380
300
447
30
87.5
228
351
216
330
31
88.2
246
358
233
336
32
82.5
255
384
229
342
34
90.4
251
365
226
326
24
111.2
275
383
278
385
25
111.6
330
453
279
380
33
108.9
301
456
279
420
35
110.1
259
426
268
438
-------
TABLE B-35
FLUE GAS PRESSURE, VOLUME AND TEMPERATURE DATA
OFF NORMAL OPERATING CONDITIONS
LOU SULFUR COAL)
to
TEST NO.
LOAD, GROSS (MW)
TEMP (OUTLET APH), "F
TEMP (OUTLET ID FAN), °F
STATIC PRESSURE (INLET APH),
In H20
STATIC PRESSURE (OUTLET ID FAN),
In H20
BAROMETRIC PRESSURE, in HG
RUE GAS VOLUME (OUTLET ID FAN),
(WET) MACFH(2)
FLUE GAS VOLUME (OUTLET ID FAN),
MSCFMD
FLUE GAS MASS RATE (DRY), MLB/HR
FLUE GAS MASS RATE (WET), MLB/HR
OUTLET ID FAN - 02, *
- C02 (DRY), %
- H20, %
- mw (DRY)
- MW (WET)
EXCESS AIR (OUTLET ID FAN) , %
26
44.1
328
249
-30
14
29.83
183
131
594
625
7.7
13.3
4.83
29.95
29.37
56
27
44.5
340
275
-27
14
29. 8Z
183
125
572
603
7.4
13.2
5.16
30.03
29.41
53
28
89.8
293
272
..(1)
..CD
29.25
344
231
-.13)
..(3)
7.3
-13)
..(31
-.(3>
-.(3)
51
2cP>
88.7
298
273
..(1)
14
29.22
447
300
1355
1437
10.5
9.3
5.71
29.84
29.16
94
30
87.5
303
273
--U)
14
29.21
330
216
982
1062
6.9
14.2
7.51
30.22
29.30
48
31
88.2
305
273
..(I)
14
29.20
336
233
1055
1076
7.4
12.8
1.97
29.40
29.18
53
32
82.5
303
272
-d)
19
29.34
342
229
1039
1105
8.0
12.7
5.95
29.94
29.23
59
34
90.4
290
252
..(1)
15
29.67
326
226
1030
1099
6.8
13.9
6.24
30.09
29.34
46
24
111.2
293
218
-34
15
29.51
385
278
1270
1361
6.4
14.8
6.70
30.25
29.43
43
25
111.6
295
219
-34
22
29.59
380
279
1275
1353
6.4
14.4
5.77
30.15
29.45
42
33
106.9
308
276
..U)
14
29.68
420
280
1273
1368
7.2
13.8
6.96
30.19
29.34
50
35
110.1
316
296
..(1)
15
29.67
438
268
1221
1389
7.0
14.5
12.14
30.90
29.34
48
'NO Data ™'M - Thousands ' 'sample Lost I*'M» _ ftolecular Weight '^'Outlier not used in. Data Analyses
-------
TABLE B-36
SULFUR OXIDES, EMISSION RATES AND CONCENTRATIONS
OFF NORMAL OPERATING CONDITIONS
03
I
co
•-J
TEST NO.
LOAD, GROSS (MW)
SULFUR IN AF COAL, LB/LB COAL
OUTLET ID FAN -
- S02, PPM
- S03> PPM
- so3/so2, (v/v)
- so2/o2, (v/v)
- S02, LB/HR
- S03, LB/HR
- S02, LB/MMBTU12'
- S02 + SOj, LB/HR
(1'outlier Value, Wot Used in Dat<
(2)
v 'M - Thousands
26
44.1
o.on
1029
36
0.035
0.013
1333
58
2.7
1391
Analysis
27U>
44.5
o.oie
2974
296
0.099
0.040
3701
460
7.6
4161
28
89.8
0.010
772
1B3
0.237
0.011
1767
524
2.0
2291
29
88.7
0.013
636
31
0.049
0.006
1890
115
2.0
2005
30
87.5
0.012
580
66
0.114
0.008
1243
177
1.4
1420
31
88.2
0.007
604
47
0.078
0.008
1396
136
1.6
1532
32
82.5
0.008
642
20
0.031
0.008
1459
57
1.7
1516
34
90.4
0.011
834
35
0.042
0.013
1873
98
2.0
1971
24
111.2
0.012
668
10
0.015
0.010
1843
34
1.6
1877
25
111.6
0.012
814
40
0.049
0.013
2252
138
1.9
2390
33
108.9
0.010
875
15
0.017
0.012
2426
52
2.2
2478
35
110.1
0.010
556
274
0.493
0.008
1480
911
1.3
2391
-------
TABLE B-37
PARTICULATE EMISSIONS, RATES AND CONCENTRATIONS
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
co
CO
00
TEST NO.
LOAD, GROSS (HW)
SOOT BLOWING STATUS
INLET APH(1>, GR/ACF
INLET APH(l1, GR/SCF
INLET APH(1), LB/HR
OUTLET ID FANts), GR/ACF
OUTLET ID FAN(5), GR/SCF
OUTLET ID FAN(5), LB/HR
OUTLET ID FAN(5), LB/NMBTU(6)
ASH IN RAM COAL, %
(1)ASME Method (5)ZPA Method
Partial Sample ' 'u - Thousands
U;Sample aborted
No Data
26
44.1
Off
6.765
3.086
3067
0.180
0.252
282
0.57
10.1
27
44.5
Off
4.997
..W
..(3)
-.(3)
..(3)
-.(3)
9.7
29
88.7
On
-CO
-.CO
-CO
0.206
0.307
788
0.85
11.0
30
87.5
Off
--CO
..CO
..Ci)
0.231
0.353
654
0.75
10.2
31
88.2
On
--CO
..CO
..CO
0.107
0.154
307
0.36
8.3
32
82.5
Off
-CO
..CO
..Ci)
0.175
0.261
512
0.60
10.1
34
90.4
On
-.CO
--CO
-CO
0.161
0.233
452
0.49
10.9
24
111.2
Off
5.506
2.350
4610
0.173
0.239
570
0.49
10.4
25
111.6
Off
7.959
3.479
6838
0.137
0.187
447
0.38
10.5
33
108.9
Off
_co
_co
-.CO
0.203
0.305
731
0.66
9.7
35
110.1
Off
__(>0
-CO
-CO
0.296
0.484
1113
0.97
10.5
-------
TABLE B-3B
ELECTROSTATIC PRECIP1TATOR PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
DO
I
GO
vo
TEST NO.
LOAD, GROSS (MM)
AVG CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, HATTS/FT2
AVG CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
AV6 CURRENT, mA
AVG VOLTAGE, KV
CORONA POWER, W
SPECIFIC POWER, WATTS/FT2
SPECIFIC POWER (OVERALL),
WATTS/ FT2
OVERALL CORONA POWER, WATTS
FLOW, MACFM (WET)(2)
CORONA POWER, KW
USEFUL CORONA POWER, WATTS/HACFM
SOOT BLOWING STATUS
'^Ho data available
'2'H - Thousands
26
44.1
80/80
20/24
3520
0.121
160/160
21/24
7200
0.495
190/205
26/29
10855
0.748
0.371
21605
183
21.6
118.0
Off
27
44.5
95/95
20/23
4085
0.140
290/270
16/18
9500
0.653
230/275
25/28
13450
0.924
0.464
27035
183
27.0
147.5
Off
28
89.8
-Ja>
..W
..(1)
.-(1)
..CD
-U)
..CD
-Jl>
344
..U)
.-(1)
Off
29
88.7
70/70
24/28
3640
0.125
125/130
29/24
6745
0.463
195/175
34/31
12055
0.828
0.385
22440
447
22.4
50.1
On
30
87.5
70/70
23/26
3430
0.118
128/121
23/26
6090
0.418
163/199
26/30
10208
0.701
0.339
19728
330
19.7
59.7
Off
31
88.2
70/70
23/26
3430
0.118
120/120
24/28
6240
Q.429
200/238
28/31
12978
0.892
0.389
22648
336
22.6
67.3
On
32
82.5
70/70
20/24
3080
0.106
128/130
26/22
6188
0.425
240/200
31/28
13040
0.896
0.383
22308
342
22.3
65.2
Off
34
90.4
70/70
22/24
3220
0.111
130/130
24/20
5720
0.393
233/200
30/28
12590
0.865
0.370
21530
326
21.5
65.9
On
24
111.2
70/70
24/28
3B4D
0.125
120/120
30/26
67?n
0.462
185/175
33/30
11355
0.780
0.373
21715
385
21.7
56.4
Off
25
111.6
70/70
24/26
3500
0.120
120/122
29/26
6652
0.457
190/165
34/30
11410
0.784
0.370
21562
380
21.6
56.8
Off
33
108.9
70/70
24/27
3570
0.123
125/130
28/24
6620
0.455
225/200
32/30
13200
0.907
0.402
23390
420
23.4
55.7
Off
35
110.1
70/70
22/25
3290
0.113
195/225
22/19
8565
0.589
400/350
27/26
19900
1.367
0.545
31755
438
31.7
72.4
Off
-------
TABLE B-39
TRACE ELEMENTS IN AS FIRED COAL
ppm DRY WEIGHT BASIS
Off Normal Operation
(Low Sulfur Coal)
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Copper
Manganese
Nickel
i Tin
Cadmi urn
Chromium
Calcium
Beryl 1 i urn
Vanodium
Magnesium
Antimony
Iron
24-25,33,35
115-5-WO
<100
<200
16
<10
38
14
36
32
1405
<10
17
2950
<10
13880
1335
<10
12500
30,32 i 29-31,34
92-5-WO
<100
<200
22
<10
37
16
43
28
1625
<10
12
3665
<10
14010
1365
<10
19200
92-5-WI
<100
<200
17
<10
48
13
50
27
1485
<10
11
3355
<10
600
950
<10
30550
26-27
46-5-WO
<100
<200
<10
<10
33
16
44
22
740
<10
11
3245
<10
3820
830
<10
90
B-40
-------
TABLE B-40
TRACE METALS IN OUTLET FLUE GAS PARTICULATE
ppm DRY WEIGHT BASIS
Off Normal Operation
(Low Sulfur Coal)
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryl 1 i urn
Vanadium
Magnesium
Antimony
Iron
24-25,33,35
115-5-WO
<100
<200
107
<10
1120
66
130
120
510
<10
90
3000
<100
<100
5390
<100
84800
30,32
92-5-WO
<100
<200
69
<10
640
51
140
50
100
<10
39
11890
<100
<100
1390
<100
68500
29,31,34
92-5-WI
<100
<200
90
<10
800
10
140
96
230
<10
89
2110
<100
<100
4420
<100
97100
26-27
46-5-WO
<100
<200
392
<10
5580
470
780
1050
1450
<10
45
17160
<100
<100
26160
<100
592600
24-35
All (avg.)
<100
<200
165
<10
2035
149
298
329
573
<10
66
8540
<100
<100
9340
<100
210750
B-41
-------
TABLE B-41
TRACE ELEMENTS IN RAW COAL COMPOSITES
LOW SULFUR TESTS
Test
Test Condition
Arsenic
Selenium
Lead
Mercury
Zinc
Copper
Manganese
Nickel
Tin
Cadmi urn
Chromium
Calcium
Beryllium
Vanadium
Magnesium
Antimony
Iron
24-35
Off Normal
<100
<200
17
<10
20
13
22
, 35
h 1340
<100
18
3420
<100
7930
870
<10
9630
B-42
-------
TABLE 6-42
BOILER EFFICIENCIES AND HEAT RATES
OFF NORMAL OPERATING CONDITIONS
cn
I
to
TEST NO.
LOAD, GROSS (HH)
LOAD, NET (MW)
HEAT INPUT, WBTU/HR'1'
GROSS HEAT RATE, BTU/KWH
NET HEAT RATE, BTU/KHH
BOILER EFFICIENCY -
- INPUT/OUTPUT EFF, X
- HEAT LOSS EFF, %
COAL RATE, MLB/HR
EXCESS AIR (INLET APH), %
INLET AIR (FD FAN), "F
"'M - Thousands
11
115.1
107.9
1158
10100
10732
84.6
86.7
101.7
19
74
12
114.7
107.9
1156
10100
10717
84. 2
86. 9
102.4
18
60
13
114.8
107.8
1153
10000
10688
84.5
87.0
103.5
20
60
14
110.1
103.6
1114
10100
10747
85.9
86.4
98.9
25
60
15
110.1
103.4
1120
10200
10821
83.3
86.5
99.2
25
57
18
108.9
102.4
1129
10400
11026
82.4
86.0
99.9
25
65
19
114.8
107.8
1181
10300
10951
82.4
86. 9
104.4
15
72
20
118.1
108.1
1287
10900
11907
76.4
87.3
103.9
13
75
21
114.4
107.1
1175
10300
1096B
82.9
86.2
103.1
20
79
-------
TABLE B-43 ...
HEAT BALANCE (MMBTU/HFT '')
OFF NORMAL OPERATING CONDITIONS
03
TEST NO.
LOAD, GROSS (MW)
INPUT COAL
STEAM ABSORPTION
COAL MOISTURE & HYDROGEN'2'
RADIATION ESTIMATE'21
CARBON IN REFUSE'2'
DRV GAS HEAT LOSS(2)
H20 IN FLUE GAs'2'
FLUE DUST SENSIBLE HEAT'2'
NO IN FLUE GAs'2'
CO IN FLUE GAs'2'
HYDROCARBONS IN FLUE GAs'2'
TOTAL ACCOUNTED FOR LOSSES
TOTAL UNACCOUNTED FOR LOSSES
UNACCOUNTED FOR LOSS, %
( UM - Thousands
Accounted for Losses
11
115.1
1157.93
979.87
51.02
5.79
2.14
86.72
7.30
0.34
0.21
0.00
0.00
153.52
24.54
13.78
12
114.7
1156.31
973.62
52.42
5.78
1.99
83.79
7.29
0.29
0.13
0.00
0.00
151.69
31.00
16.97
13
114.8
1153.27
974.23
51.97
5.77
3.14
81.39
6.96
0.35
0.15
0.00
0.00
149.73
29.31
16.37
14
110.1
1114.48
957.18
49.56
5.57
3.09
86.07
6.88
0.33
0.10
0.00
0.00
151.60
39.70
25.24
15
110.1
1119.95
933.19
51.02
5.60
2.73
84.64
6.90
0.29
0.08
0.00
0.00
151.26
35.50
19.01
IB
108.9
1129.06
930.78
50.16
5.65
3.05
91.69
7.21
0.34
0.19
0.00
0.00
158.29
39.99
20.17
19
114.8
1180.55
972.27
51.99
5.90
3.34
85.61
6.80
0.36
0.15
0.00
0.00
154.15
54.13
25.99
20
118.1
1287.12
983.65
52.11
6.44
3.32
93.29
7.95
0.37
0.22
0.00
0.00
163.70
139.77
46.06
21
114.4
1174.67
973.81
51.81
5.87
3.24
92.43
7.87
0.35
0.27
0.00
0.00
161.84
39.02
19.43
-------
TABLE B-44
ENERGV DISTRIBUTION
OFF NORMAL OPERATING CONDITIONS
ca
01
TEST NO.
LOAD, GROSS (MW)
TOTAL HEAT INPUT, HMBTU/HR^1'
TOTAL HEAT AVAILABLE, MMBTU/HR
MAIN STEAM, MMBTU/HR
ATTEMPERATOR SPRAYS, MMBTU/HR
REHEAT STEAM, MMBTU/HR
AUXILIARIES, MMBTU/HR
AUXILIARY ENERGY CONSUMPTION, t
NET POWER OUTPUT, MMBTU/HR
NET POWER OUTPUT, *
BOILER LOSSES, *
HEAT REJECTED, TURBINE AND
GENERATOR LOSSES, %
HEAT REJECTED, TURBINE AND GENERA-
TOR LOSSES, MMBTU/HR
MAIN STEAM, MLB/HR
REHEAT STEAM, MLB/HR
FEEDWATER(2) , MLB/HR
"'M - Thousands
^ 'includes Sprays
11
115.1
1157.93
979.87
819.19
36.48
124.20
24.57
2.1
368.3
31.8
15.4
50.7
587.1
842.7
739.3
822.9
12
114.7
1156.31
973.62
828.21
22.24
123.17
23.21
2.0
368.3
31.9
15.8
50.5
583.9
800.0
734.0
818.6
13
114.8
1153.27
974.23
826.37
24.40
123.46
23.89
2.1
368.1
31.9
15.5
50.7
584.7
800.0
732.7
319.2
14
110.1
1114.48
957.18
774.03
56.11
127.04
22.18
2.0
353.8
31.7
14.1
52.2
581.8
800.2
710.5
795.9
15
110.1
1119.95
933.19
770.84
40.43
121.92
22.87
2.0
353.1
31.5
16.7
49.8
557.7
801.5
698.7
779.1
18
108.9
1129.06
930.78
768.02
40.34
122.42
22.18
2.0
349.5
31.0
17.6
49.4
557.7
797.5
696.0
776.7
19
114.8
1180.55
972.27
825.78
21.94
124.55
23.89
2.0
367.9
31.2
17.6
49.2
580.8
846.7
735.7
B21.1
20
118.1
1287.12
983.65
823.48
34.25
125.92
34.13
2.6
368.8
28.7
23.6
44.7
575.3
848.0
740.7
828.9
21
114.4
1174.67
973.81
826.12
23.80
123.89
24.91
2.1
365.6
31.1
17.1
49.7
584.0
845.0
736.6
822.3
-------
TABLE B-45
LOAD SENSITIVE PRESSURE AND TEMPERATURE VALUES
OFF NORMAL OPERATING CONDITIONS
cn
TEST NO.
LOAD, GROSS (MW)
BOILER FEED HgO IN, °F
HEATER #4 EXTRACTION STEAM, °F
BOILER FEED H,0 LEAVING HEATER
*3, °T i
BOILER FEED H,0 LEAVING HEATER
K, °F Z
DRAIN HEATER #4, °F
DRAIN HEATER #5, "F
STEAM DRUM, PSIG
REHEAT IN, PSIG
REHEAT OUT, PSIG
HEATER #4 EXTRACTION STEAM, PSIG
11
115.1
465.0
812.8
329.0
394.0
346.0
394.0
1873.5
481.8
451.3
230.0
12
114.7
464.8
813.3
328.3
393.3
345.5
393.5
1873.8
482.5
450.3
229.3
13
114.8
464.8
813.3
328.0
392.8
345.5
392.8
1876.3
483.0
451.3
229.5
14
110.1
465.8
813.0
330.0
395.3
342.3
392.0
1860.8
463.5
431.8
220.5
15
110.1
465.0
813.0
329.5
395.0
341.0
390.5
1859.0
460.8
429.8
218.5
18
108.9
464.8
813.3
329.3
394.3
341.3
390.8
1861.3
460.0
429.3
218.0
19
114.8
469.5
811.8
332.3
396.8
345.0
393.8
1877.0
484.0
452. B
230.5
20
118.1
470.0
813.0
333.0
398.0
345.7
394.7
1874.7
486.7
454.7
231.7
21
114.4
469.3
813.3
332.3
396.8
345.3
394.3
1875.0
483.8
453.0
230.5
-------
TABLE B-46
AIR HEATER PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
00
-F»
-•4
TEST NO.
LOAD, GROSS (MM)
AIR INLET TEMP, °F
AIR OUTLET TEMP, °F
GAS INLET TEMP, °F
GAS OUTLET TEMP, °F
GAS OUTLET, TEMP-ADJUSTED, "F
INLEAKAGE, %
INLET 02, VOL *.
OUTLET 02 VOL I
EXCESS AIR INLET, %
EXCESS AIR OUTLET, *
AIR A, °F
GAS i, °F
FLUE GAS INLET (WET), HLB/HR^1'
FLUE GAS OUTLET (MET), MLB/HR
TOTAL HEAT INPUT, MMBTU/HR
TOTAL HEAT LOSS, MMBTU/HR
STOICHIOMETRIC 02, LB/LB COAL
AIR/COAL RATIO, W/W
HEAT RECOVERY ACROSS
AIR HEATER, MM8TU/HR
HEAT RECOVERY, % OF TOTAL
HEAT INPUT
HEAT LOSS DUE TO EXCESS AIR, %
OF TOTAL LOSS
HEAT LOSS DUE TO EXCESS AIR, X
OF TOTAL HEAT INPUT
"'M - Thousands
11
115.1
158
5B7
690
325
354
£2.9
3.5
6.3
19
40
429
365
1148
1333
1158
153.5
1.99
12.2
132
11.4
15.8
2.1
12
114.7
154
567
673
312
338
23.1
3.3
6.0
18
37
413
361
1133
1302
1156
151.7
1.97
11.8
123
10.6
14.7
1.9
13
114.6
153
572
680
312
334
17.7
3.6
5.8
20
36
419
368
1136
1283
1153
149.7
1.95
11.5
123
10.7
14.0
1.8
14
110.1
156
572
680
312
340
18.4
4.3
7.0
24
47
416
368
1131
1321
1114
151.6
1.94
12.5
126
11.4
17.8
2.4
15
110.1
155
572
682
312
333
16.7
4.6
6.6
27
43
417
370
1161
1320
1120
151.3
1.99
12.4
127
11.3
16.4
2.2
18
108.9
161
572
682
313
346
26.2
4.3
7.5
24
52
411
369
1174
1401
1129
158.3
1.98
13.1
133
11.8
19.3
2.7
19
114.8
165
575
678
308
341
26.6
2.8
6.4
15
41
410
370
1157
1369
1180
154.1
1.99
12.2
129
11.0
15.8
2.1
20
118.1
171
577
682
297
345
39.4
2.4
7.8
13
55
406
385
1172
1489
1287
163.7
1.97
13.4
141
10.9
19.9
2.5
21
114.4
171
577
681
299
339
29.8
3.6
8.0
20
58
406
382
1227
1531
1175
161.8
2.02
14.0
145
12.4
20.5
2.8
-------
TABLE B-47
BOILER EFFICIENCIES AND HEAT RATES
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
ro
-F»
CO
TEST NO.
LOAD, GROSS (HW)
LOAD, NET (MW)
HEAT INPUT, MHBTU/HR^1'
GROSS HEAT RATE, BTU/KMH
NET HEAT RATE, BTU/KWH
BOILER EFFICIENCY -
- INPUT/OUTPUT EFF, *
- HEAT LOSS EFF, %
COAL RATE, MLB/HR
EXCESS AIR (INLET APH), I
INLET AIR (FD FAN), °F
" 'M - Thousands
26
14.1
40.7
49B
11287
12230
77.67
83. SO
46.9
37
48
27
44.5
41.0
488
10972
11908
84.76
82.10
47.4
23
48
28
89.8
84.1
890
9915
10587
84.90
84.45
90.2
26
53
29
88.7
82.7
923
10403
11158
80.32
80.83
88.5
36
56
30
87.5
81.5
873
9980
10715
84.81
85.59
85.5
33
68
31
88.2
82.4
84B
9619
10296
87.63
84.81
87.9
53
68
32
82.5
77.8
858
10404
11033
. 84.15
84.18
82.1
33
69
34
90.4
84.4
924
10218
10944
78.80
84.93
89.7
23
57
24
111.2
104.1
1164
10468
11182
81.68
85.32
109.2
16
48
25
111.6
104.6
1166
10449
11148
82.11
85.37
109.8
15
48
33
108.9
101.4
1108
10172
10924
83.46
84.53
107.5
29
53
35
110.1
103.2
1141
10368
11061
82.26
85.09
110.7
32
69
-------
TABLE B-48 ,,,
HEAT BALANCE (HHBTU/HR1'')
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
TEST NO.
LOAD, GROSS (MM)
INPUT COAL
STEAM ABSORPTION
COAL MOISTURE & HYDROGEN^2*
RADIATION ESTIMATE'2'
CARBON IN REFUSED
DRV GAS HEAT LOSS*2'
H20 IN FLUE GAS'2'
FLUE OUST SENSIBLE HEAT(2)
NO IN FLUE GAS*2'
CO IN FLUE GAS*21
HYDROCARBONS IN FLUE GAS^2'
TOTAL ACCOUNTED FOR LOSSES
TOTAL UNACCOUNTED FOR LOSSES
UNACCOUNTED FOR LOSS, %
(1)M - Thousands
^Accounted for Losses
26
44.1
497.76
386.64
25.02
2.80
4.46
45.69
3.80
0.17
0.20
0.00
0.00
82.14
28.98
26.1
27
44.5
488.24
413.85
24.13
2.80
5.56
50.25
4.18
0.25
0.20
0.00
0.00
87.37
(3)
(3)
28
89.8
890.40
755.91
49.79
4.45
9.03
67.74
6.48
0.27
0.68
0.00
0.00
138.44
(3)
(3!
29
88.7
922.75
741.14
49.90
4.61
8.97
104.18
8.01
0.38
0.80
0.00
0.00
176.85
4.76
2.6
30
87.5
873.24
740.60
47.14
4.37
5.61
61.80
6.06
0.25
0.57
0.00
0.00
125.80
6.84
5.2
31
88.2
848.36
743.43
51.96
4.24
4.17
61.28
6.48
0.21
0.49
0.00
0.00
128.83
C3)
_.L3>
32
82.5
858.35
722.32
45.72
4.29
13.19
65.66
6.18
0.27
0.50
0.00
0.00
135.81
(3)
(3)
34
90.4
923.71
727.90
49.29
4.62
12.77
65.69
6.22
0.29
0.36
0.00
0.00
139.24
56.57
28.9
24
111.2
1164.04
950.76
58.25
5.82
10.65
87.13
7.77
0.34
0.93
0.00
0.00
170.89
42.39
19.9
25
111.6
1166.09
957.45
57.30
5.83
10.81
87.64
7.74
0.36
0.88
O.QQ
0.00
170.56
38.08
18.3
33
108.9
1107.71
924.45
58.87
5.54
9.77
88.42
8.00
0.33
0.45
0.00
0.00
171.38
11.88
6.5
35
110.1
1141.49
938.93
59.67
5.71
10.92
85.12
7.90
0.37
0.52
0.00
0.00
170.21
32.35
16.0
(3)Hegative
-------
TABLE B-49
ENERGY DISTRIBUTION
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
Ul
o
TEST NO.
LOAD, GROSS {!*)
TOTAL HEAT INPUT, MMBTU/HR<"
TOTAL HEAT AVAILABLE, MMBTU/HR
MAIN STEAM, MMBTU/HR
ATTEHPERATOR SPRAYS, MMBTU/HR
REHEAT STEAM, MMBTU/HR
AUXILIARIES, MMBTU/HR
AUXILIARY ENERGY CONSUMPTION, %
NET POWER OUTPUT, MMBTU/HR
NET POWER OUTPUT, %
BOILER LOSSES, X
HEAT REJECTED, TURBINE AND
GENERATOR LOSSES, %
HEAT REJECTED, TURBINE AND GENER-
ATOR LOSSES, MMBTU/HR
MAIN STEAM, MLB/HR
REHEAT STEAM, MLB/HR
FEEDWATER'Z', MLB/HR
l'JM - Thousands
(21
1 'Includes Spr«ys
26
44.1
497.76
386.64
327.76
7.12
51.76
11.60
2.3 ,
138.9
27.9
22.3
47.5
236.4
340.0
275.8
293.3
27
44.5
488.24
413.85
347.31
10.18
56.36
11.94
2.4
139.9
28.7
15.2
53.7
262.2
343.3
297.7
300.0
28
89.8
890.40
755.91
636.07
24.48
95.36
19.45
2.2
287.0
32.2
15.1
50.6
450.5
688.0
565.3
620.0
29
88.7
922.75
741.14
630.43
17.70
92.91
20.48
2.2
282. 2
30.6
19.7
47.4
437.4
682.5
558.4
610.7
30
87.5
873.24
740.60
628.34
19.91
92.35
20.48
2.2
278.2
31.9
15.2
50.7
442.7
676.7
550.7
601.7
31
88.2
848.36
743.43
634.16
15.91
93.36
19.79
2.3
281.2
33.1
12.4
52.2
442.8
682.3
560.7
613.3
32
82.5
858.35
722.32
609.20
21.00
92.12
1.6.04
1.9
265.5
30.9
15.8
51.4
441.2
655.4
535.3
582.3
34
90.4
923.71
727.90
645.16
18.45
64.59
20.48
2.2
28B.1
31.2
21.2
45.4
419.4
688.6
572.7
626.4
24
111.2
1164.04
950.76
806.66
19.13
124.97
24.23
2.1
355.3
30.5
18.3
49.1
571.5
874.7
710.8
789.9
25
111.6
1166.09
957.45
797.97
32.44
127.04
23.89
2.0
357.0
30.6
17.9
49.5
577.2
874.7
708.9
792.'6
33
108.9
1107.71
924.45
766.38
39.50
118.57
25.60
2.3
346.1
31.2
16.5
50.0
553.8
846.1
690.6
770.5
35
110.1
1141.49
938.93
789.64
28.89
120.40
23.55
2.1
352.2
30.9
17.7
49.3
562.7
B62.8
703.3
784.5
-------
TABLE B-50
AUXILIARY AMPERAGES
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
DO
Ol
TEST NO.
LOAD, GROSS (MW)
LOAD, NET (MH)
AUXILIARY POWER (MW)
UNACCOUNTED FOR (MW)
AUXILIARY POWER, %
CIRC H20 PUMP EAST, AMPS
ID FANS (2) TOTAL, AMPS
FD FANS (2) TOTAL, AMPS
PRIM AIR FANS (4) TOTAL, AMPS
MILLS (4) TOTAL, AMPS
GAS RECIRCULATION PUMP, AMPS
MAIN FEED H20 PUMPS (2) TOTAL, AMPS
SOOT BLOWER AIR COMP, AMPS
SLUICE PUMP NORTH, AMPS
26
44.1
40.7
2.7
0.7
7.7
39
87
39
36
49
32
162
0
0
27
44.5
41.0
2.7
0.8
7.9
39
90
39.
36
49
32
167
0
15
28
89.8
84.1
4.5
1.2
6.3
39
129
99
55
80
0
353
0
31
29
88.7
82.7
3.9
2.1
6.8
39
140
94
76
99
0
346
0
21
30
87.5
81.5
4.5
1.5
6.9
39
129
91
73
98
0
322
0
0
31
88.2
82.4
4.5
1.3
6.6
39
141
91
57
,82
0
350
0
23
32
82.5
77.8
4.4
0.3
5.7
39
130
95
58
78
20
334
0
21
34
90.4
84.4
4.6
1.4
6.6
41
127
97
56
77
14
348
28
0
24
111.2
104.1
5.4
2.0
6.6
39
174
102
77
104
0
405
0
15
25
111.6
104.6
5.2
1.4
5.9
39
174
102
77
104
0
407
Q
0
33
108.9
101.4
5.2
2.3
6.9
39
170
101
76
106
0
395
0
10
35
110.1
103.2
5.3
1.6
6.3
40
174
101
78
103
0
407
24
0
-------
TABLE B-51
LOAD SENSITIVE PRESSURE AND TEMPERATURE VALUES
OFF NORMAL OPERATING CONDITIONS
(LOU SULFUR COAL)
Ul
ro
TEST NO.
LOAD, GROSS (MW)
BOILER FEED H?0 IN, °F
HEATER #4 EXTRACTION STEAM, °F
BOILER FEED H,0 LEAVING HEATER
K, °f
BOILER FEED H,0 LEAVING HEATER
15, °F i
DRAIN HEATER *4, °F
DRAIN HEATER 15, °F
STEAM DRUM, PSIG
REHEAT IN, PSIG
REHEAT OUT, PSIG
HEATER ft EXTRACTION STEAM, PSIG
26
44.1
375.0
495.0
285.0
330.0
308.3
363.3
1763.3
180.0
160.0
80.0
27
44.5
326.7
503.3
285.0
330.0
313.3
365.0
1786.7
180.0
160.0
85.0
^
28
89.8
445.0
814.0
314.0
376.7
327.3
429.0
1330.0
375.0
348.3
177.0
29
88.7
445.0
808.3
315.0
380.0
334.3
428.7
1808.3
373.3
346.7
180.0
30
87.5
445.0
511.7
315.0
380.0
341.7
426.7
1866.7
375.0
346.7
178. 3
31
88.2
445.0
508.3
315.0
380.0
343.3
426.7
1833.3
373.3
340.0
180.0
32
82.5
435.0
506.7
311.7
373.3
345.0
423.3
1805.0
373.3
346.7
180.0
34
90.4
445.0
511.7
315.0
380.0
338.3
430.0
1850.0
376.7
350.0
180. 0
24
111.2
463.3
517.0
333.0
393.3
350.0
450.0
1900.0
463.3
418.0
230.0
25
111.6
461.7
513.3
323.3
390.0
348.3
448.3
1900.0
466.7
418.7
231.7
33
108.9
463.3
520.0
323.3
393.3
345.0
446.7
1886.7
456.7
420.0
225.0
35
110.1
464.0
517.7
326.3
394.0
352.7
450.0
1876.7
461.7
431.7
230.0
-------
I
Ol
co
TABLE B-52
COAL QUALITY, AS FIRED COAL
OFF NORMAL OPERATING CONDITIONS
t\ nu sin PI a rnai 1
TEST NO.
LOAD, GROSS (MW)
MOISTURE, *
CARBON, %
HYDROGEN, %
NITROGEN, %
CHLORINE, %
SULFUR, %
ASH, %
OXYGEN, %
VOLATILE MATTER, %
FIXED CARBON, %
HIGH HEATING VALUE, BTU/LB
MOL C/MOL H2
26
44.1
6.98
64.35
4.45
1.12
0.07
1.38
11.96
9.69
31.82
49.24
11457
2.68
27
44.5
6.86
64.63
4.42
0.98
0.08
1.43
12.12
9.48
31.31
49.71
11442
2.69
28
89.8
8.24
64.18
4.33
1.27
0.08
1.28
11.35
9.27
31.98
48.43
11378
2.67
29
88.7
8.77
63.42
4.13
1.34
0.08
1.32
12.14
8.80
31.17
47.92
11244
2.64
30
87.9
6.98
64.81
4.43
1.40
0.08
0.93
12.29
9.08
33.38
47.35
11348
2.70
31
88.2
8.31
64.22
4.72
0.95
0.09
1.26
12.15
8.30
32.52
47.02
11348
2.68
32
82.5
10.91
62.58
4.40
0.87
0.08
1.12
12.43
7.61
31.54
45.12
10995
2.61
34
90.4
7.76
64.94
4.46
1.13
0.10
1.29
12.30
8.02
31.98
47.96
11325
2.71
24
111.2
7.05
64.00
4.37
1.18
0.08
1.64
12.28
9.40
33.05
47.62
11357
2.67
25
116.6
8.13
63.84
4.44
1.18
0.07
1.54
11.91
8.89
32.34
47.62
11266
2.66
33
108.9
7.20
65.63
4.50
1.28
0.09
1.21
12.45
7.64
32.54
47.81
11526
2.73
35
110.1
6.54
62.17
4.52
1.26
0.07
0.97
14.00
10.47
34.76
44.70
10885
2.59
Avg.
-
7.81
64.06
4.43
1.16
0.08
1.28
12.28
8.89
32.37
47.54
11298
2.67
-------
TABLE B-53
COAL QUALITY - RAW COAL
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
CO
cn
TEST NO.
LOAD, GROSS (MH)
HIGH HEATING VALUE, BTU/LB
MOISTURE, %
VOLATILE MATTER, %
FIXED CARBON, %
ASH, %
CARBON, t
HYDROGEN, %
OXYGEN, %
NITROGEN, I
SULFUR, %
MOL C/MOL H2
CHLORINE, %
26
44.1
10607
15.52
30.5]
43.84
10.13
60.12
4.00
8.14
0.87
1.12
2,50
0.10
27
44.5
10303
14.74
29.40
43.36
12.50
58.50
3.83
7.42
1.07
1.84
2.55
0:10
28
89.8
9868
18.74
30.85
40.74
9.67
56.91
3.84
8.65
1.11
0.99
2.47
0.09
29
88.7
10421
16.57
29.38
43.08
10.97
58.39
4.21
7.33
1.18
1.25
2.31
0.10
30
87.5
10215
17.46
29.39
42.95
10.20
58.08
3.98
7.80
1.24
1.16
2.43
0.08
31
88.2
9646
21.24
29.83
40.60
8.33
55.40
3.98
5.38
0.88
0.74
2.32
0.05
32
82.5
10452
16.80
29.00
44.11
10.09
59.11
4.11
9.74
1.02
0.84
2.40
0.09
34
90.4
10300
17.10
27.66
44.36
10.88
58.47
4.00
7.05
1.33
1.09
2.37
0.08
24
111.2
10662
14.75
29.97
44.89
10.39
60.73
4.09
7.53
1.18
1.22
2.47
0.11
25
111.6
10625
14.99
29.40
45.12
10.49
60.69
3.94
7.50
1.12
1.18
2.57
0.09
33
108.9
10300
17.34
28.85
44.13
9.68
59.03
3.95
7.62
1.28
1.01
2.49
0.09
35
110.1
10312
15.73
30.64
43.12
10,51
E8.99
4.04
8.34
1.29
1.03
2.49
0.07
Average
-
10309
16.75
29.57
43.36
10.32
58.70
4.00
8.04
1.13
1.12
2.45
0.09
-------
TABLE B-54
COAL QUALITY DATA
COMPOSITES OF 1% SULFUR TESTS
OFF-NORMAL OPERATION
(LOW SULFUR COAL)
TEST
SAMPLE
High Heating Value,
Btu/Lb
Hfl UI+- #
n*J j W U • A*
Ash, wt. %
Volatile Matter, wt. %
Fixed Carbon, wt. %
Sulfur, wt. %
Carbon, wt. %
Hydrogen, wt. %
Nitrogen, wt. %
Oxygen, wt. %
Chlorine, wt. %
Fluorine, ppm
24-35
RAW COAL
10700
15.5
10.5
27.5
46.4
0.8
61.1
4.1
1.2
6.7
0.08
115
24-35
AS FIRED COAL
11400
7.7
12.6
32.4
47.4
1.0
64.3
4.6
1.4
8.5
0.07
— CD
(1)
Insufficient Sample
B-55
-------
tn
CTl
TABLE B-55
PULVERIZER PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
TEST NO.
LOAD, GROSS (HW)
MOISTURE (RAW COAL), %
MOISTURE (AS FIRED COAL), %
SCREEN SIZE (AS FIRED COAL),
PERCENT THRU 200 MESH
»1 MILL TEHP, "F
12 MILL TEMP, 3F
B MILL TEMP, °F
14 MILL TEMP, °F
1*1 PRIMARY FAN, AMPS
n PRIMARY FAN, AMPS
#3 PRIMARY FAN, AMPS
#4 PRIMARY FAN, AMPS
*1 MILL, AMPS
R MILL, AMPS
#3 HILL, AMPS
#4 MILL, AMPS
NO OF MILLS IN SERVICE
COAL FEED RATE, MLB/HR(2)
26
44.1
15.52
6.96
66.6
150
145
141
87
17
19
--(1)
-.(1)
26
23
-(1)
-JD
2
46.9
27
44.5
14.74
6.86
63.9
150
144
102
78
17
19
--(1)
-.(1)
26
23
..(1)
..(1)
2
47.4
28
89.8
18.74
8.24
59.8
137
133
127
82
18
19
18
--(1)
26
26
28
_{!>
3
90.2
29
88.7
16.57
8.77
65.0
143
143
136
91
17
IB
17
24
24
23
26
26
4
88.5
30
87.5
17.46
6.98
62.5
145
139
134
144
14
17
21
21
23
21
27
27
4
85.5
31
88. 2
21.24
8.31
64.2
145
153
129
131
17
.-
-------
TABLE B-56
AIR HEATER PERFORMANCE
OFF NORMAL OPERATING CONDITIONS
(LOW SULFUR COAL)
tn
--J
TEST NO.
LOAD, GROSS (MM)
AIR INLET TEMP. °F
AIR OUTLET TEMP, °F
GAS INLET TEMP, °F
GAS OUTLET TEMP, °F
GAS OUTLET, TEMP-ADJUSTED, °F
INLEAKAGE, %
INLET 02, VOL 1
OUTLET 02, VOL *
EXCESS AIR INLET, %
EXCESS AIR OUTLET, %
AIR A, °F
GAS a, °F
FLUE GAS INLET, (WET) MLB/HRUJ
FLUE GAS OUTLET, (WET) MLB/HR
TOTAL HEAT INPUT, MMBTU/HR
TOTAL HEAT LOSS, MMBTU/HR
STOICHIOMETRIC 02, LB/LB COAL
AIR/COAL RATIO, W/W
HEAT RECOVERY ACROSS AIR
HEATER, MMBTU/HR
HEAT RECOVERY, % OF TOTAL
HEAT INPUT
HEAT LOSS DUE TO EXCESS AIR,
% OF TOTAL LOSS
HEAT LOSS DUE TO EXCESS AIR,
% OF TOTAL HEAT INPUT
" 'M - Thousands
26
44.1
75
561
627
328
362
10.6
5.9
7.7
37
56
486
299
557
625
498
82.1
1.83
12.4
70
14.0
19.5
3.2
27
44.5
75
573
638
340
406
17.1
4.0
7.4
23
53
498
298
493
603
488
87.4
1.78
11.9
69
14.1
19.3
3.5
28
89.8
172
559
673
293
318
16.1
4.5
7.3
26
51
387
380
938
1108
890
138.4
1.73
11.4
98
11.0
16.2
2.5
29
88.7
148
566
656
298
366
31.6
5.8
10.5
36
94
418
358
1032
1437
923
176.9
1.81
15.3
140
15.2
28.1
5.4
30
87.5
148
575
660
303
321
6.8
5.4
7.0
33
48
427
357
966
1062
873
125.8
1.78
11.5
104
12.0
15.5
2.2
31
88.2
153
568
657
305
316
7.3
6.4
8.7
44
53
415
352
966
1076
848
128.8
1.70
11.3
102
12.0
16.0
2.4
32
82.5
192
553
660
303
327
17.2
5.3
8.0
33
59
361
357
931
1105
858
135.8
1.80
12.6
92
10.8
17.6
2.8
34
90.4
152
557
660
290
316
13.8
4.1
6.8
23
46
405
370
942
1099
924
139.2
1.79
11.4
102
11.0
14.5
2.2
24
111.2
155
557
672
293
325
15.8
3.0
6.4
16
43
402
379
1125
1361
1164
170.9
1.86
11.6
125
10.8
14.9
2.2
25
111.6
155
560
674
295
328
16.0
2.9
6.4
15
42
405'
379
1118
1353
1166
170.6
1.85
11.4
125
10.8
14.8
2.2
33
108.9
162
585
690
307
333
13.1
4.9
7.2
29
50
423
383
1191
1368
1108
171.4
1.80
11.8
133
12.0
16.9
2.6
35
110.1
178
570
674
316
334
10.4
5.2
7.0
32
48
392
358
1245
1389
1141
170.2
1.80
11.7
125
11.0
15.9
2.4
-------
FIGURE B-l
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
w
N
M
(A
s
u
Q
W
H
en
to
en
H
55
U
Particle Diameter,
Dpc in Microns
• Test No. 1
A Mass Median Diameter
B-58
-------
w
V)
1
FIGURE B-2
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, D in Microns
• Test No. 2
A Mass Median Diameter
B-59
-------
FIGURE B-3
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, D in Microns
Test No. 3
Mass Median Diameter
B-60
-------
FIGURE B-4
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
•* 01 <0 f.
-------
W
N
H
cn
1
Q
W
H
trt
IO
W
w
w
FIGURE B-5
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, D in Microns
• Test No. 10
A Mass Median Diameter
B-62
-------
w
CM
M
to
1
CJ
Q
W
H
tn
w
nJ
H
!3
U
W
04
u
FIGURE B-6
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, Dnr in Microns
• Test No. 11
A Mass Median Diameter
B-63
-------
w
CO
1
FIGURE B-7
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, D in Microns
LEGEND: • Test No. 12
O Mass Median Diameter
B-64
-------
I 1UUIM. LI—u
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
W
M
u
Particle Diameter, D in Microns
Test No. 13
Mass Median Diameter
B-65
-------
FIGURE B-9
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
w
tn
1
u
Q
W
H
in
to
w
H
a
w
W
£
M
H
Particle Diameter, D in Microns
Test No. 18
Mass Median Diameter
B-66
-------
FIGURE B-10
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
w
o
M
s
Q
b)
(ft
OT
en
u
Ed
a
u
Particle Diameter, Dnr in Microns
Ku
LEGEND: • Test No. 24
• Test No. 25
A Test No. 33
O Test No. 35
• Mass Median Diameter
B-67
-------
FIGURE B-11
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
w
N
M
OT
1
o
3
V)
en
to
w
H
S3
W
W
fri
w
Particle Diameter, D in Microns
pc
LEGEND: 0 Test No. 27
O Mass Median Diameter
B-68
-------
FIGURE B-12
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
w
N
H
V)
•z
§
o
Q
W
H
cn
H
en
w
H
a
w
w
A4
Particle Diameter, D in Microns
LEGEND: • Test No. 29
• Test No. 31
O Mass Median Diameter
B-69
-------
FIGURE B-13
PARTICLE DIAMETER vs. CUMULATIVE PERCENT
LESS THAN STATED SIZE
Particle Diameter, D in Microns
LEGEND: A Test No. 28
• Test No. 30
O Mass Median Diameter
B-70
-------
c
c
Boiler
o
1-2
O • • O
1-1 1-2 2-2 1-3
2-1 3-1 3-2 23
4-1 4-2 4-3 3-3
•7 CM r> »^ CM r> »7 CN M -7 CN M
•-Ar^
-------
c
D
Boiler
1-1 1-2 2-2 1-3
2-1 3-1 3-2 2-3
o o o
4-1 4-2 4-3 3-3
»7 {M t"> — CM rj «7 N pj
«-«i^- (NC>(r!< M«")p>
ttt tH Ht
±(_
Burners
- In Service
- Out of Service
PULVERIZERS
FIGURE B15 FUEL DISTRIBUTION TO BURNERS
Test No. 28, 32, 34
B-72
-------
c
Boiler
1-1 1-2 22 1-3
2-1 3-1 3-2 2-3
4-1 4-2 4-3 3-3
C
•7 CM w ^ ty m
Burners
- In Service
- Out of Service
Hf ^H U4 HI
PULVERIZERS
FIGURE B16 FUEL DISTRIBUTION TO BURNERS
Test No. 24, 25, 29, 30, 33, 35
B-73
-------
THIS PAGE INTENTIONALLY LEFT BLANK
B-74
-------
APPENDIX C. TEST METHODS
C-l
-------
C.I SAMPLING
C.I.I Coal and Refuse
Coal was sampled by the NIPSCO coal handler from the coal hoppers to
make composites of raw coal, using sampling probes designed by NIPSCO. Appa-
ratus and procedure of ASTM-D-2234.72 governed sampling. The composite after
test completion resided in a milk pail. Its size was reduced by riffling. A
one quart mason jar sample was submitted for ultimate and proximate analysis.
Another portion was retained. A test series composite sample was then created
for all 1% S coal tests, etc. The coal handler was told when to begin, and
since tests lasted up to 3.3 hours he continued to sample until instructed to
stop.
Pulverized coal was sampled from feed pipes to make composites of as
fired coal using the apparatus and procedure of ASME PTC-4.2.
Raw ("as received") coal scale tripper integrator readings were obtained
at the station instrument panel at 30 min. intervals. Each calibrated trip was
100 Ibs. The data was inspected for drift of fuel firing rate.
Fly ash samples were taken from the bottom of ESP ash hoppers at the mid
point of each test. Ash from 3 fields (hoppers A-2, B-2 and C-2) was composit-
ed before analysis. Access was by ladder. Hoppers were run empty at the start
of each test so that material collected represented current conditions. Sam-
ples were analyzed by CTE for loss on ignition ("percent dry ash") and sulfur
content. Also selected samples were analyzed by TRW for halogens.
TRW provided NIPSCO with detailed written instructions for coal and ref-
use sampling.
C.I.2 Flue Gas
Sampling and analysis procedures, except where otherwise specified, were
in accordance with standard methods as published in the Federal Register, Volume
36, Number 247, Part II, December 23, 1971, see Table C-l. The various test
C-2
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Parameter
Particulate - outlet
Particle size
Trace Metals
Sulfur oxides
Nitrogen oxides
Hydrocarbons
Mercury
Halogens
Hydrogen sulfide
Stationary gases
Moisture
Particulate -
inlet & outlet
TABLE C-l
FLUE GAS SAMPLING METHODS
Method* - Collection
EPA Method 5 and ASME
Brink Cascade Impactor
EPA Method 5
S02-EPA Method 6, S03~ Modified Shell Development
Method
EPA Method 7
EPA Method 3
"Sampling and Analysts of Mercury
Vapor in Industrial Streams Containing
Sulfur Dioxide" Statnick, et al.
Midget bubbler train, 0.01 N NaOH absorbing
solution
EPA Method 11 with hydrogen peroxide
pre-scrubber.
EPA Method 3
EPA Method 5
ASME
*EPA Methods are found in Reference (5)
The ASME Method is found in Reference (6)
C-3
-------
parameters evaluated by the referenced method or other stated methods were as
follows:
C.I.2.1 Particulates
Two test methods were employed in the participate testing program.
Due to the expected high particulate grain loading present at the pre-
cipitator inlet, ASME methods were utilized to conduct the efficiency testing
of the precipitator. The ASME method utilized an in-situ alundum thimble as
the filtering medium. The thimble was dried and weighed prior to the sampling
and again following the sampling to determine total mass of particulate matter
collected. The grain loading of the particulates in the inlet and outlet flue
gas was then determined from the data collected during the isokinetic sampling.
The precipitator outlet location was also tested for total particulates
using Methods 1, 2, and 5, Federal Register. December 23, 1971, and Method 5,
Federal Register, August 17, 1971. The particulate matter collected with this
method was also analyzed for trace metals which is discussed in one of the fol-
lowing descriptions.
The EPA particulate sampling train was modified as shown in Figure c-1.
The filter box was redesigned to allow for a flexible tube connection between
filter and impingers so that the impinger bath could remain stationary while
having the filter box coupled rigidly to and moving with the probe.
C.I.2.2 Particle Size
Size distribution of the particulate matter was determined at the pre-
cipitator outlet location by an in-situ Brinks cascade impactor. The cascade
impactor separated particles into six (6) different size categories, varying
from greater than seven (7) microns in diameter to less than one-tenth (.1)
micron.
C-4
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FILTER
O
cn
GREENBURG-SMITH
IMPINGERS
FIGURE C-1 MODIFIED EPA SAMPLING TRAIN
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C.I.2.3 Nitrogen Oxides
Method 7, Federal Register. December 23, 1971. A grab sample was col-
lected in an evacuated flask containing a dilute solution of sulfurfc acid and
hydrogen peroxide as an absorber. The nitrogen oxides, excepting nitrous ox-
ide, were measured colorimetrically using the phenoldisulfonic acid procedure
(PDS). The nitrogen oxides sampling was conducted at the precipitator outlet
location.
C.I.2.4 Sulfur Oxides
The precipitator outlet location was sampled for sulfur dioxide and
sulfur trioxide.
The sulfur dioxide analysis was conducted in accordance with Method 6,
Federal Register, December 23, 1971. S02 was collected in a 3 percent aqueous
hydrogen perioxide solution and measured by the barium perchlorate titration
method.
The sulfur trioxide concentrations were determined using the Modified
Shell Development Method. S03 was collected in an absorbing solution contain-
ing 80 percent isopropanol. The sulfate formed in the absorber was titrated
with a standard barium perchlorate titrant using thorin as an end point indi-
cator.
C.I.2.5 Stationary Gases
Method 3, Federal Register, December 23, 1971 was the method employed
for this analysis. In lieu of an Orsat analyzer, a portable gas chromatograph
(AID) with a thermal conductivity detector was utilized. Using the GC-TC en-
abled test personnel to complete a more precise analysis and also yields a
permanent record of the data acquired. The stationary gas analysis and sam-
pling was conducted at both the inlet and outlet precipitator test locations.
Orsat analysis equipment was used to spot check the GC-TC results.
C-6
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C.I.2.6 Moisture Determination
Method 4, Federal Register. December 23, 1971. The percent of moisture
in the stack gases was determined at both locations on a volume basis.
C.I.2.7 Hydrogen Sulfide
Method 11, Federal Register. June 11, 1973 was the procedure followed
in the H2S analysis at the precipitator outlet.
The H2S was collected in an alkaline cadmium chloride solution with a
peroxide pre-scrubber to remove S02, which interferes with the absorbing solu-
tion. The amount of cadmium sulfide precipitate was determined iodometrically.
C.I.2.8 Hydrocarbons
The outlet test location was sampled for total hydrocarbons. A bag
sample was extracted from the flue gas and was analyzed on a Flame lonization
Detector (FID), and compared against a known gas.
C.I.2.9 Halogens
Fluorides and chlorides were sampled by a continuous method using
0 01N NaOH in a midget impinger absorption train. For total fluorides, or
total chloride determination, the sample probe and inlet tubing were included
in the washings taken for analysis.
C.I.3 Flow Measurement
Gas flow determinations were made using type »S» pi tot tubes and thermo-
couple actuated potentiometers in accordance with EPA Methods 1 and 2.
C-7
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C.2 DATA COLLECTION
C.2.1 General
Mitchell Station instrument data from the station control room were
recorded at intervals of 30 minutes during each test run. Several items were
not actually located in the control room and include: barometer, precipita-
tor controls and F.D. fan air temperature and humidity.
The completed test data was examined for averages and trends before
keypunching.
C.2.2 Steam Generator Operating Data
The steam generator operating data recorded for the Baseline Test in-
cluded all major gaugeboard readings, coal scale readings, atmospheric pres-
sure and dry bulb temperature - relative humidity of the air at the inlet to
the forced-draft fan as recorded manually on the operating conditions log
sheet. These data were recorded at about hourly intervals throughout the dur-
ation of each test. Averages for each parameter were noted, as well as trends
if variations were encountered. Data were transcribed to punch cards. Fuel
consumption rates were calculated from integrator readings on each coal feeder.
Each integrator trip represented 100 Ibs. Rates on each scale were added to
yield the total. Readings were twice hourly.
C-8
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C.3 ANALYTICAL METHODS
c-3-' Coal Proximate and Ultimate
ASTM Standard Method D271 .
C.3. 2 Coal Screen Size
ASTM Standard Method D197.
C-3. 3 Fly Ash Loss on Ignition
ASTM Standard Method D271. Dry basis only, % ash is reported.
C.3. 4 Fly Ash Sulfur
ASTM Standard Method D1757.
C.3. 5 Primary Flue Gas Parameters
Analytical methods for parti culates, nitrogen oxides, sulfur oxides,
stationary gases, hydrogen sulfide, and hydrocarbons are included by
reference in Subsection C.I. 2 and Table C-1.
C.3. 6 Fluorides
Fluoride gas and mist after absorption in a sodium hydroxide solution
is determined by specific fluoride ion electrode. Fluoride dust is fused
with sodium hydroxide and determined colorimetrically in a Technicon Auto
Analyzer using H9SOA distillation and lanthanum - alizarin complexone
C.3. 7 Chlorides
Chlorine in coal is part of the "ultimate" at no extra charge and is
done by the Mohr Method (ASTM D2361) using low-chlorine Eschka digestion.
C-9
-------
CTE has agreed to report the chlorine percentage to three decimal places
(i.e. 0.041 rather than 0.04).
Chlorine analysis in flue gas 1s accomplished by chloride specific
ion electrode in accordance with the Instruction Manual for Chloride Analy-
sis, Orion Research, Inc., Cambridge, Mass. As little as .02 ppm aqueous
Cl" can be detected by this method.
C.3.8 Trace Metals
Trace element distributions have not yet been determined for more
than a few coals. Consequently there are no commonly accepted or traqe
element analysis procedures established that can be used in this program.
The situation is much the same in the case of trace element analyses of
flue gas particulate from coal combustion sources. There is at present a
great deal of effort being directed at establishing standard procedures on
the part of ASTM and EPA, but their recommendations will not be available
for some time. The trace element analysis methods recommended therefore for
use in this work are those used or developed by TRW under Contract 68-02-0647
(Survey of Meyer's Process Potential for Chemical Desulfurization of United
States Coals). The adequacy of these procedures in providing both accurate
and precise trace element levels at least for coal samples, was demonstrated
under this contract by analyzing standard coal samples supplied by the
Illinois Geological Survey and the National Bureau of Standards.
The proposed analytical procedures for determining trace element
levels in NIPSCO coal, fly ash and flue gas samples are described below.
Be. Ca. Cd, Cr, Cu. Li. Mg, Mn, Ni, Pb. Sn. Sb, V, Zn
Analyses of these elements in coal and flue gas will be performed by
atomic absorption methods using one coal ash or flue gas sample. In the
analysis of the coal sample, the sample will be ashed using a low temperature
oxygen plasma asher (International Plasma Corporation, Model 1001B). Upon
complete ashing of the coal sample, the ash will be taken into solution by a
C-10
-------
HN03-HF acid mlsture, diluted to a convenient volume and stored in poly-
ethylene containers until used. Teflon or Nalgene labware will be used for
HN03-HF ash dissolution to prevent possible contamination or loss of sample
trace elements. For flue gas particulate samples collected on glass fiber
impactors, a small representative portion of the pads will be treated with
a HN03-HF acid mixture to solubilize the sample. The resulting solution
will be diluted and handled in an identical fashion to the HN03-HF acid
solubilized coal ash samples.
Solutions prepared in the above fashion will be analyzed directly for
12 elements using a Fisher Scientific Co. Model 810 atomic absorption spec-
trophotometer employing operating conditions listed in Table C-2. Since the
Model 810 is a dual channel instrument automatic background correction can
be incorporated into the measurement to enhance the accuracy of the deter-
mination. The wavelengths used for background correction for each of the
elements as well as the analytical wavelength are also listed in Table C-2.
Selenium
Analyses of Se in coal samples may have to be performed using a flame-
less atomic absorption procedure if the flame atomization method described
above is too insensitive for this study. In this event, Se analyses will be
performed using a portion of the solution from the coal ash sample and a
Fisher Scientific Company Model micro thermal analyzer attachment for the AA
spectrophotometer. For all of the analyses using the micro thermal analyzer
background corrections will be applied and standard additions of the element
will be used for quantitation purposes.
Mercury
The analysis procedure for Hg in coal is one currently in use by the
U. S. Bureau of Mines. In this procedure the coal sample is combusted in a
Leco Instrument Co. tube furnace equipped with an 02 flow. The combustion
gases are swept through an unheated quartz tube packed with gold foil for
amalgamating the Hg vapor. After initial combustion is complete, the gold
C-11
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TABLE C-2
ATOMIC ABSORPTION ANALYTICAL PARAMETERS
A) Flame Methods
Element
Mn
Cu
Cr
Ni
Sn
Ag
Sb
V
Pb
Cd
In
Li
Be
Analytical (A)
2795
3247
3579
2320
2246
3281
2176
4408
2833
2288
2139
6708
2349
Slit (A)
4
10
4
2
4
10
4
2
10
4
10
10
10
Background (A)
2882
3171
3563
2316
2186
3257
2241
2850
2297
2197
6698
2312
Slit (A)
4
10
4
2
4
10
4
—
10
4
10
10
10
Flame Conditions
Air-Acetylene
Ai r-Acety 1 ene
N20-Acetylene
Hydrogen-Ai r
Ai r-Acety1ene-Lean
Ai r-Acety1ene-Lean
N20 Acetylene-
Emission Mode
Ai r-Acety1ene-Lean
Ai r-Acety1ene-Lean
Ai r-Acety1ene-Lean
Ai r-Acety1ene-Lean
NgO-Acetylene
-------
TABLE C-2 (CONTINUED)
ATOMIC ABSORPTION ANALYTICAL PARAMETERS
B) Flameless AA Methods
Element
Hg
Sb
Analytical (A)
2537
Slit (A)
10
Background (A)
Slit (A)
2176
10
2241
10
o
Se
1960
10
1879
10
Sn
2863
2840
Flame Conditions
Ar Flow, 2 SCFH, use
IOcm Cell Heated
To 200°C
Dry at Instrument
Setting of 50 for
2 Min. Atomize at
Setting of 80 for
1 Sec. at Ar Flow
of 14 SCFH
Same Settings as for
Sb, Except for
Addition of H2 whose
Flow is Regulated at
10 psig
Same Setting as for Sb
-------
foil trap is fitted with an Ar purge and heated. The Hg vapor released from
the foil is swept into a quartz flow cell positioned in the AA and Hg is
determined using conditions in Table C-2. Calibration 1s accomplished using
known volumes of Hg saturated air in the analysis procedure.
Hg in flue gas is determined as follows: The solutions will be
placed in a closed reaction vessel and a reducing agent added to liberate
Hg vapor. The Hg vapor will then be flushed from the reaction vessel into
an M cell (f Tameless method).
Arsenic
The analytical procedure to be used for As in coal is a modified
U. S. Bureau of Mines colorimetric method. In this procedure a coal sample
is fused and the residue dissolved in a mineral acid solution. From this
solution arsine is evolved through oxidation of metal zinc and the zinc
concentration produced measured as the colored dithiocarbonate complex us-
ing the DK2A spectrophotometer. A similar procedure without MgO fusion
will be used for the analysis of As in the flue gas samples.
The analysis procedures outlined above are expected to be used for
the Baseline Test Program. However, as standard or more accurate and cost
effective procedure become available, it is expected that they will be
substituted as appropriate.
C-14
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APPENDIX D. FIELD TEST LOGS
D-1
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FIELD TEST LOG
8 May 1974 - 29 May 1974
8 May : Equipment truck and lab trailer departed McLean.
9 May : Equipment truck and lab trailer arrived Mitchell station. Began
deployment of equipment. Intermittent heavy rain.
10 May : Continued deployment of equipment. Mitchell No. 11 forced down
11 May : by fire in Mill 2, due to loss of coal flow due to set coal and/
or tramp iron. Scheduled down in p.m. for air heater cleaning.
12 May : Hangers on cold reheat line snapped while unit was coming on.
Down to repair.
13 May : Test crew assembled. Completed deployment of equipment.
14 May : Unit on at about 50MW with Mill 2 and Mill 3 down, Mill 3 with
broken retainer rings. Ran velocity traverses at outlet with
Unit No. 6 at 120MW. No negative flows.
15 May : Both mills still down. Began 46-3-WO test at 1130.
16 May : No. 2 mill back. 92MW available. One test aborted, rain. Second
test cancelled, rain.
17 May : Completed 92-3-WO and 92-3-WI tests with three mills, light rain.
18 May : No tests, rain.
19 May : Completed 92-3-WO and 92-3-WI tests with three mills.
20 May : Completed 92-3-WO and 92-3-WI tests with three mills. All 92MW
tests completed.
21 May : Mill 3 not available to start 115MW tests in morning. Afternoon,
rain.
22 May : 115MW not available until 1040, FD fan damper. Delayed start un-
til 1400 due to rain. Completed two (115-3-WO) tests.
23 May : Completed 115-3-WO and 115-3-ASH tests.
24 May : Completed two (115-3-ASH) tests.
D-2
-------
25 May : Completed two (110-3-XSA) tests. Bearing and vibration problem on
west I.D. fan. Limited control of F.D. fan dampers, resulting in
air limitation. Performed tests at 110MW to obtain additional ex-
cess air.
26 May : Completed two (46-3-WO) tests with three mills.
27 May : Completed 110-3-XSA test. Opened access door on each air heater
by one 2x4 width. Completed 115-3-VOL test.
28 May : Completed two (115-3-VOL) tests with access doors full open.
29 May : West I.D. fan shutdown at 0500, bearing high temperatures. Unable
to complete three (115-3-MISC) tests. Further testing cancelled
until next scheduled field tests.
D-3
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FIELD TEST LOG
13 April 1975-2 May 1975
13 April : Equipment truck and lab trailer departed Vienna.
14 April : Equipment truck and lab trailer arrived Gary. NIPSCO began cali-
bration of coal scales.
15 April : Began deployment of equipment. Calibration of coal scales com-
pleted.
16 April : Deployment of equipment completed.
17 April : Completed one 115-3-WO Misc test. Boiler was load limited to
about 112 MW due to feed water limitation.
18 April : Completed one 115-3-WO Misc test. Delays due to gentle rain
throughout day prevented completion of more than one test. Dur-
ing the night, NIPSCO lost all coal feed to station due to a coal
slide into the reclaiming hopper. The third 115-3-WO Misc test
was cancelled. Low sulfur coal for testing did not start to
No. 11 bunker until late on 23 April.
24 April : Filling No. 11 bunker with test low sulfur coal.
25 April : Completed two 115-1-WO tests.
26 April : Completed two 46-1-WO tests. Coal mills 3 and 4 were down.. Boil-
er feed pump 11W was down. FD fan 11W was down. Gas recircula-
ting damper was about 20% open to control temperatures.
27 April : Tests postponed, rain.
28 April : Completed one 92-1-WO and one 92-1-WI test. No. 4 mill was down
during 92-1-WO test. Short outages of mills occurred due to feed
hopper pluggage due to wet coal.
29 April : Completed one 92-1-WO and one 92-1-WI test. Continued to have
feed hopper pluggages, resulting in a load limitation to 80MW for
35 minutes during 92-1-WO test.
30 April : Completed one 92-1-WO test. No test during afternoon hours, rain.
1 May : Completed one 115-1-WO test and one 92-1-WI test. No. 4 mill down
during 92-1-WI test.
D-4
-------
2 May : Completed one 115-1-WO test to backup first test of this test
set during which the boiler may not have been stabilized on low
sulfur test coal. Equipment disassembled and packed for return
to Vienna.
D-5
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THIS PAGE INTENTIONALLY LEFT BLANK
D-6
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APPENDIX E. GLOSSARY OF TERMS
E-l
-------
GLOSSARY OF TERMS
ACF Actual cubic feet
acfm Actual cubic feet per minute
AF As fired
AH Air heater
APH Air preheater (same as air heater)
ASME American Society of Mechanical Engineers
BFP Boiler feed pump
BTU British thermal unit
CE Concentration effect
cfm Cubic feet per minute
circ Circulation
demo Demonstration
eff Efficiency
EPA Environmental Protection Agency
ESP Electrostatic precipitator
FD Forced draft
FGV Flue gas volume
FID Flame ionization detector
GC Gas chromatograph
gl Gross load
gr Grain
HC Hydrocarbon
HHV High heating value
HLE Heat loss efficiency
HVC High volatile coal
ID Induced draft
I/O Input-output efficiency
E-2
-------
GLOSSARY OF TERMS (Continued)
KWH
M
ma
macfm
MMBTU
MMLB/HR
MSA
MW
NDIR
NIPSCO
NOx
Kilowatt hours
Thousands
Milliamps
One thousand actual cubic feet per minute
Million Btu's
Million pounds per hour
Mine Safety Appliance Company
Megawatts
Non-dispersive infrared
Northern Indiana Public Service Company
Nitrogen oxides
ppm
ppmv
ppmw
psig
PT
PVT
Parts per million
Parts per million by volume
Parts per million by weight
Pounds per square inch, gauge
Pressure, temperature
Pressure, volume, temperature
SB
scf
scfm
SOx
Sootblowing
Standard cubic foot
Standard cubic foot per minute
Sulfur oxides
T&E
Test Series One
Test Series Two
Test Series Three
Test Series Four
Test Series Five
Test and Evaluation
Test series, boiler operating normally
Test Series, boiler operating off-normal
Tests 22 & 23, boiler operating normally
Test series, high sulfur coal
Test series, low sulfur coal
WL
Wellman Lord
XSA
Excess air
E-3
-------
TECHNICAL REPORT DATA .
Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-014
2.
3. RECIPIENT'S ACCESSION NO,
4. TITLE AND SUBTITLE
Demonstration of Wellman-Lord/Allied Chemical FGD
Technology: Boiler Operating Characteristics
5. REPORT DATE
February 1977
6. PERFORMING ORGANIZATION CODE
AUTHOR(S)
R.C. Adams, T.E. Eggleston, J.L. Haslbeck,
R.C. Jordan, and Ellen Pulaski
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
800 Follin Lane, SE
Vienna, Virginia 22180
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-0235 and
68-02-1877
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final: 5/74-1/76
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL_RTP prOject officer for this report is W.H. Ponder, Mail
Drop 61, 919/549-8411 Ext 2915.
16. ABSTRACT
repOrt gives results of an intensive examination and characterization
of a coal-fired boiler prior to retrofit of a full scale flue gas desulfurization (FGD)
unit employing the Wellman-Lord/Allied process. The test established a baseline
profile of the boiler for later comparison both with design and operating conditions
of other boilers for which the Wellman-Lord/Allied process is potentially applicable ,
and with operating performance after retrofit of the FGD unit. It also established a
baseline profile during operation of the boiler at conditions other than normal which
have the potential for affecting the performance of the Wellman-Lord/Allied FGD unit.
Boiler operating performance was examined for its economic performance , overall
energy balance, and the performance of auxiliaries. Detailed profiles of the flue
gas at the proposed boiler /FGD unit interface were determined at varying boiler
control settings including operation at below normal sulfur , higher than normal flue
gas volumes , and higher than normal grain loadings . The tests were performed on
Boiler No. 11 of Northern Indiana Public Service Company's Mitchell Power Station.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Boilers
Efficiency
Coal
Combustion
Air Pollution Control
Stationary Sources
Operating Characteris-
tics
Wellman-Lord/Allied
Process
13B
2 IB
07A,07D
13A
21D
I3. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
20. SECURITY CLASS (This page)
Unclassified
21. NO. OF PAGES
274
22. PRICE
EPA Form 2220-1 (9-73)
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