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

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                       RESEARCH REPORTING SERIES
Research reports of the Office of,Research and  Development, U.S.
Environmental Protection Agency,  have been grouped  into 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

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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

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                            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

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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

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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

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       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

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       •  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

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                       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

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                               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

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                        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

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                         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

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                              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

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                          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

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                          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

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                                                   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

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                             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

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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

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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

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                             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

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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

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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

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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

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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

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                                                                    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

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                   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

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                    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

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                        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

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                            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

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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

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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

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       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

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       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

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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

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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

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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

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     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

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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

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               3-106

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                            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

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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

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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

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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

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       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

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                4-8

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                            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

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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

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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

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                5-4

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                            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

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APPENDIX A.  BOILER DESCRIPTION
              A-1

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                            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 
-------
                            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

-------
      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

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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

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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

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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

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                                               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

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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

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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

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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

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                         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

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                    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

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                                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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