EPA-650/2-73-005-0
June 1975 Environmental Protection Technology Series
ROGRAM FOR REDUCTION
OF NOX FROM TANGENTIAL
COAL-FIRED BOILERS
PHASE II
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D. C. 20460
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EPA-650/2-73-005-0
PROGRAM FOR REDUCTION
OF NOX FROM TANGENTIAL
COAL-FIRED BOILERS
PHASE II
by
Ambrose P. Selker
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Contract No. 68-02-1367
ROAP No. 21ADG-080
Program Element No. 1AB014
EPA Project Officer: David G. Lachapelle
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D. C. 20460
June 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Crntcr - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOC1OECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-73-005-a
11
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ABSTRACT
This report presents the findings of the Phase II "Program For Reduc-
tion of NO From Tangentially Coal Fired Boilers" performed under the
n
sponsorship of the Office of Research and Development of the Environ-
mental Protection Agency (Contract 68-02-1367). Phase I of the program
consisted of selecting the Alabama Power Company, Barry Station #2 steam
generator which was modified for the studies performed under Phase II.
The Phase I results were presented in final report EPA-650/2-73-005,
dated August, 1973.
The work accomplished under Phase II included the design, fabrication,
and delivery of an overfire air system for the test unit, the installa-
tion of test equipment, planning, and the conducting of baseline, biased
firing and overfire air studies for NO emission control while burning
a Kentucky bituminous coal type.
These test programs included an evaluation of the effect of variations
in excess air, unit slagging, load and overfire air on unit performance
and emission levels. Additionally, the effect of biasing combustion air
through various out of service fuel nozzle elevations was also evaluat-
ed. The effect of biased firing and overfire air operation on waterwall
corrosion potential was evaluated during three thirty (30) day base-
line, biased firing and overfire air corrosion coupon tests.
Unit loading and waterwall slag conditions exhibited minimal effects on
NO emission levels while reductions in excess air levels and overfire
air operation were found to be effective in reducing NO emission lev-
J\
els.
m
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DISCLAIMER
"This report was prepared by Combustion Engineering, Inc. as an account
of work sponsored by the Office of Research and Development* U.S. Envi-
ronmental Protection Agency (EPA). Combustion Engineering, Inc. nor any
person acting on behalf of Combustion Engineering, Inc.:
"a. Makes any warranty or representation, expressed or implied in-
cluding the warranties of fitness for a particular purpose or
merchantability, with respect to the accuracy, completeness,
or usefulness of the information contained in this report, or
that the use of any information, apparatus, method, or process
disclosed in this report may not infringe privately owned
rights; or
b. Assumes any liabilities with respect to the use of, or for
damages resulting from the use of, any information, apparatus,
method or process disclosed in this report."
iv
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CONTENTS
Page No.
Abstract iii
Disclaimer iv
List of Figures vii
List of Data Sheets ix
Acknowledgements xi
Conclusions 1
Recommendati ons 3
Introduction 4
Purpose and Scope 4
Objectives
Task I 7
Task II 7
Task III 7
Task IV 8
Task V 8
Task VI 8
Task VII 8
Task VIII 10
Task IX 10
Discussion
Task I - Prepare the Design, Detail Fabrication
and Erection Drawings 11
Task II - Purchase and Fabricate Equipment 11
Task III - Test Instrument Installation 13
Tasks IV & V - Baseline and Biased Firing Test Programs 15
Test Data Acquisition and Analysis 15
Load and Excess Air Variation 17
Furnace Wall Deposit Variation 21
Biased Firing - Fuel Elevations Out of Service
Variation 26
Task VIII - Unit Optimization Study 34
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CONTENTS (Cont'd)
Page No.
Load and Excess Air Variation 34
Furnace Wall Deposit Variation 40
OFA Location & Rate Variation 44
OFA Tilt Variation 49
Load Variation at Optimum Conditions 51
Furnace Performance 55
Waterwall Corrosion Coupon Evaluation 57
Overfire Air Evaluation - Alternate Coals -
Barry 4 Tests 70
Task IX - Prepare Application Guidelines 81
References 122
Appendix I 123
Compflow:Windbox - Compartment Air Flow Distribution
Computer Program
vi
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FIGURES
No. Page No.
1 Unit Side Elevation 6
1A Schematic - Overfire Air System 9
2 Program Schedule 12
3 Emission Test System 14
4 Corrosion Probe 18
5 Corrosion Probe Locations 19
6 Corrosion Probe Temperatures 20
7 N02 Vs. Theoretical Air to Fuel Firing Zone -
Baseline Study 22
8 CO Vs. Theoretical Air to Fuel Firing Zone -
Baseline Study 23
9 Percent Carbon Loss Vs. Theoretical Air to
Fuel Firing Zone - Baseline Study 24
10 Unit Efficiency Vs. Unit Excess Air - Before Modification 25
11 Furnace Slag Pattern - Clean Furnace 27
12 Furnace Slag Pattern - Moderate Slag Furnace 28
13 Furnace Slag Pattern - Heavy Slag Furnace 29
14 NOp Vs. Theoretical Air to Fuel Firing Zone -
Biased Firing Study 31
15 CO Vs. Theoretical Air to Fuel Firing Zone -
Biased Firing Study 32
16 Percent Carbon Loss Vs. Theoretical Air to Fuel
Firing Zone - Biased Firing Study 33
17 N02 Vs. Theoretical Air to Fuel Firing Zone -
Overfire Air Study 36
18 CO Vs. Theoretical Air to Fuel Firing Zone -
Overfire Air - Baseline Study 37
19 Percent Carbon Loss Vs. Theoretical Air to Fuel
Firing Zone - Overfire Air & Baseline Study 38
20 Unit Efficiency Vs. Unit Excess Air - All Tests 39
21 Furnace Slag Pattern - Clean Furnace 41
vii
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FIGURES (Cont'd)
No. Page No.
22 Furnace Slag Pattern - Moderate Slag Furnace 42
23 Furnace Slag Pattern - Heavy Slag Furnace 43
24 N02 Vs. Theoretical Air to Fuel Firing Zone -
Overfire Air Study 45
25 CO Vs. Theoretical Air to Fuel Firing Zone -
Overfire Air Study 47
26 Percent Carbon Loss Vs. Theoretical Air to Fuel
Firing Zone - Overfire Air Study 48
27 N02 Vs. OFA Tilt & Fuel Nozzle Tilt 50
28 Percent Carbon Loss Vs. OFA Tilt & Fuel Nozzle Tilt 52
29 CO Vs. OFA Tilt & Fuel Nozzle Tilt 53
30 NOp Vs. Main Steam Flow: Normal & Optimum Operation 54
31 Chordal Thermocouple Locations 56
32 Waterwall Absorption - Baseline Operation 58
33 Waterwall Absorption - OFA Operation 59
34 Waterwall Absorption - OFA Operation 60
35 Waterwall Absorption - Baseline & OFA Operation 61
36 Gross MW Loading Vs. Time - Baseline Corrosion
Probe Study 63
37 Gross MM Loading Vs. Time - Biased Firing
Corrosion Probe Study 64
38 Gross MW Loading Vs. Time - Overfire Air
Corrosion Probe Study 65
39 Ash Analysis - Corrosion Probe Studies 69
40 N02 Vs. Theoretical Air to the Firing Zone - Barry 4 74
41 N02 Vs. Excess Air - Barry 4 75
42 CO Vs. Excess Air - Barry 4 76
43 N02 Vs. Primary/Secondary Damper Positions - Barry 4 78
44 Waterwall Corrosion Probe Locations - Barry 4 80
vm
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DATA SHEETS
Sheet Page No.
1 NOX Test Data Summary - Baseline
Study 82
2 NOX Test Data Summary - Biased
Firing Study 83
3 NO Test Data Summary - Baseline Study
After Modification 84
4A NO Test Data Summary - Overfire Air
Location, Rate & Velocity Variation 85
4B NOX Test Data Summary - OFA Tilt
Variation 86
4C NO Test Data Sumnary - Load Variation
A
at Optimum Conditions 86
5A, 5B Test Data - Baseline Study 87, 88
6A, 6B Test Data - Biased Firing Study 89, 90
7A, 7B Test Data - Baseline Study After
Modification 91, 92
8A, 8B Test Data - Overfire Air Location, Rate
& Velocity Variation 93, 94
8C, 8D Test Data - Ovefire Air Tilt Variation
and Load Variation at Optimum
Conditions 95, 96
9A, 9B, 9C Board Data - Baseline Study 97, 98, 99
10A, 10B, IOC Board Data - Biased Firing Study 100, 101, 102
11A, 11B, 11C Board Data - Baseline Study After
Modification 103. 104, 105
12A, 12B Board Data - Overfire Air Location,
Rate & Velocity Variation 106, 107
12C, 12D, 12E Board Data - Overfire Air Tilt Variation
and Load Variation at Optimum
Conditions 108, 109, 110
IX
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DATA SHEETS (Cont'd)
Sheet Page No.
"~~"~~~ 2
13A Waterwall Absorption Rates - kg-cal/hr-cm -
Right Wall Centerline Tube Rates 111
13B Waterwall Absorption Rates - kg-cal/hr-cm -
Front Wall Centerline Tube Rates 112
2
13C Waterwall Absorption Rates - kg-cal/hr-cm -
Right Wall, Rear Wall, Left Wall,
Front Wall 113
14A, 14B, 14C Waterwall Corrosion Coupon Data
Summary 114, 115, 116
15A, 15B Test Data Summary, Barry No. 4 117, 118
16 Accelerated Corrosion Rate Data -
Barry No. 4 119
17A, 17B Typical Coal Analysis 120, 121
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ACKNOWLEDGMENTS
The author wishes to acknowledge the constructive participation of Mr.
D. G. Lachapelle, EPA Project Officer, in providing the program direc-
tion necessary for its successful completion.
The cooperation and active participation of Alabama Power Company and,
in particular, the personnel of the Barry Steam Plant were essential to
successfully modifying the test unit and conducting the various test
program phases.
The results presented in this report represent the effort of many Com-
bustion Engineering, Inc. personnel whose participation was required
for its successful completion and in particular the technical contribu-
tions made by Messrs. W. A. Stevens, R. F. Swope, M. S. Hargrove, R. VI.
Robinson, R. W. Borio, R. M. Kantorak and E. R. LePage.
xi
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CONCLUSIONS
Normal Operation
1. Under normal unit operation without overfire air, excess air varia-
tion was found to have the greatest single effect on NO emission
A
levels, increasing NOV with increasing excess air. An average in-
6
crease of 0.014 g N0«/10 cal for each 1% change in excess air was
observed over the normal operating range.
2. Unit loading and variation in furnace slag conditions were found to
have the least effect on NO and CO emission levels and the percent
A
carbon in the flyash.
3. Under normal unit operation, the percent carbon loss in the fly ash
and CO emission levels increased with decreasing excess air with the
increases becoming greater below a level of approximately 20 to 25
percent excess air. CO levels in excess of 0.1 g/106cal were con-
sidered unacceptable for the purposes of this program.
Overfire Air Operation
1. NO reductions of 20 to 30% were obtained with 15 to 20 percent
n
overfire air when operating at a total unit excess air of approxi-
mately 15 percent as measured at the economizer outlet. This con-
dition would provide an average fuel firing zone stoichiometry of
95 to 100 percent of theoretical air. Stoichiometries below this
level did not result in large enough decreases in NO levels to jus-
A
tify their use. Biased firing, while potentially as effective,
necessitates a reduction in unit loading and is therefore less de-
sirable as a method of NO control.
A
2. When using overfire air as a means of decreasing the theoretical
air (TA)* to the fuel firing zone the percent carbon in the fly ash
and CO emission levels were less affected than when operating with
See Appendix I.
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low excess air. This is due to the ability to maintain acceptable
total excess air levels during overfire air operation.
3. Furnace performance as indicated by waterwall slag accumulations,
visual observations and absorption rates were not significantly af-
fected by overfire air operation.
4. On the test unit, where the overfire air port could not be installed
as a windbox extension, test results indicated that the centerline
of the overfire air port should be kept within 3 meters of the
centerline of the top fuel elevation. Distances greater than 3
meters did not result in decreased NO levels. Changes in distance
A
less than 3 meters did affect NO levels to a limited extent with
A
the NO level increasing with decreasing distance.
A
5. Optimum overfire air operation was obtained with the test unit when
the overfire air nozzles were tilted with the fuel nozzles. From a
standpoint of NO control, emission levels increased when the noz-
A
zles were directed toward each other, and flame stability decreased
when they were directed away from each other by more than 20-25°.
With the overfire air tilts fixed in a horizontal position, accept-
able unit operation was obtained, however, NO levels varied with
A
fuel nozzle position.
6. The results of the 30 day baseline, biased firing and overfire air
corrosion coupon runs indicate that the overfire air operation for
low NOX optimization did not result in significant increases in
corrosion coupon degradation. Additional studies will be required
to verify these observations over long-term operation.
7. Variables normally used to control normal boiler operation should
not be considered as NO controls with coal firing. These variables
A
include unit load, nozzle tilt, pulverizer fineness, windbox dampers
and total excess air.
8. Overall unit efficiency was not significantly affected by overfire
air operation.
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RECOMMENDATIONS
This program Investigated the effects of employing biased firing and
overflre air, as Incorporated on a specially modified unit, as methods
for controlling NO emission levels In existing steam generating units.
n
These control methods were studied using an Eastern United States bi-
tuminous coal type. Due to the location of the test site it was not,
however, within the scope of this program to Investigate coal types lo-
cated In the western areas of the United States.
1. As these western coal types are becoming a more predominate source
of fuel for electric generating stations, It was recommended In the
Task V Interim report that studies be undertaken to Include their
evaluation. EPA Contract 68-02-1486 was subsequently awarded to
Combustion Engineering, Inc. to study western coal fuels. In this
program new units being designed with overfire air systems as an
extension to the windbox will be utilized eliminating the need for
unit modifications while expanding the experimental studies to In-
clude test data for larger current design steam generating units.
2. Additionally, the results of the corrosion probe evaluations indi-
cate that the coupon weight losses encountered during a 30 day eval-
uation are small and consideration should be given to studies of up
to one year duration to verify short term test results. These
studies should include evaluation of actual fireside waterwall tube
wastage rates as well as corrosion probe wastage rates.
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INTRODUCTION
Purpose and Scope
This program encompassed the work to be performed under the second phase
of a two phase program to identify, develop and recommend the most prom-
ising combustion modification techniques for the reduction of NOX emis-
sions from tangentially coal-fired utility boilers with a minimum impact
on unit performance.
Phase I (performed under EPA Contract 68-02-0264) consisted of select-
ing a suitable utility field boiler to be modified for experimental
studies to evaluate NO emission control. Phase I also included the
A
preparation of preliminary drawings, a detailed preliminary test pro-
gram, a cost estimate and detailed schedule of the program phases and a
preliminary application economic study indicating the cost range of a
variety of combustion modification techniques applicable to existing and
new boilers. ^ '
Phase II consisted of modifying and testing the utility boiler selected
in Phase I to evaluate overfire air and biased firing as methods for NO
A
control. This phase also included the completion of detailed fabrica-
tion and erection drawings, installation of analytical test equipment,
updating of the preliminary test program, analysis and reporting of test
results and the development of control technology application guidelines
for existing and new tangentially coal-fired utility boilers.
This program was conducted at the Barry Steam Station, Unit No. 2 of
the Alabama Power Company. This unit is a natural circulation, bal-
anced draft design, firing coal through four elevations of tilting tan-
gential fuel nozzles. Unit capacity at maximum continuous rating (NCR)
is 408,000 kg/hr main steam flow with a superheat outlet temperature and
p
pressure of 538°C and 131.8 kg/cm . Superheat and reheat temperatures
are controlled by fuel nozzle tilt and spray desuperheating. A side
4
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elevation of the unit prior to modification is shown on Figure 1.
Throughout this report NO emission levels are expressed as g/10 cal NCL.
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Figure 1. Unit Side Elevation, Alabama Power Company, Barry No. 2
6
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OBJECTIVES
The objective of program Phase II was to complete the design of the
overfire air system, modify the Barry 2 unit accordingly, perform base-
line, biased firing and optimization tests and based on the results of
this program, prepare an application guideline for the NOX control
technology generated.
Specifically these objectives are defined as follows:
Task I - Prepare the design, detailed fabrication and erection draw-
ings necessary for modification of Barry No. 2 to incorpo-
rate an overfire air system. The system design provides for:
a. Introducing a maximum of 20% of the total combustion air
above the fuel admission nozzles.
b. Overfire air introduction through the top two existing
windbox compartments (thereby prohibiting the use of one
elevation of fuel nozzles).
c. Introduction of hot overfire air only with consideration
for air preheat control.
An updated schedule for Tasks II and IV were also prepared
under Task I.
Task II - Complete the purchasing and fabrication of all equipment
necessary for modification of the Barry No. 2 unit.
Task III - Install all necessary instrumentation required to measure
flue gas constituents and characterize the effects of com-
bustion modifications on unit performance. Specifically the
following determinations were made:
a. Flue gas constituents: NOX, SOX, CO, HC, 02
b. Unit Performance Effects:
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Fireside corrosion
Furnace heat absorption
Sensible heat leaving furnace
Superheater, reheater and air heater performance
Task IV - Conduct a baseline test program to establish the effect of
unit load, wall slagging and excess air variation on base-
line emission levels, thermal performance and operating
ranges. A baseline corrosion coupon test of 30 day duration
was also conducted.
Task V - Conduct a biased firing baseline test program to establish
the effect on unit emission levels while operating with
various fuel elevations out of service. These tests were
performed specifically to evaluate the maximum emission con-
trol at full load and throughout the normal load range. In
addition, the degree of control required to meet and maintain
emission standards throughout the normal control range was
also evaluated. A biased firing corrosion coupon test of 30
days duration was also conducted.
Task VI - Install all equipment required for modification of the test
unit and functionally check equipment to determine that prop-
er operation is obtained. (See Figure 1A)
Task VII - Complete final preparations for conducting the overfire air
test program to be conducted in Task VIII including the
f ol 1 owi ng:
a. Finish installation of the furnace waterwall thermo-
couples.
b. Check out all necessary test instrumentation for proper
installation and operation.
c. Review test program with EPA project officer and util-
8
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F-FUEL AND AIR
A- AIR
0-OVERFIRE AIR
Figure 1A: Schematic Overfire Air System, Barry No. 2
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ity company.*
d. Perform a final inspection of the test unit to assure
proper operation.
Task VIII- Conduct the overfire air test program, analyze the data gen-
erated and compare this data with that obtained during Task
V. The program investigated the effect of overfire air lo-
cation and rate at various unit loadings and evaluated op-
erating conditions considered as optimum from the standpoint
of NO control and unit operation. The final report was
also generated under this Task.
Task IX - Prepare a program outlining the application of the technology
developed under this study to existing and new design tan-
gentially coal-fired utility boilers. These application
guidelines will be submitted as a separate final report.
* The test program for this study was originated during the Phase I
study, Contract 68-02-0264 and was included as part of the Phase I
report.
10
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DISCUSSION
Task I - Prepare the Design. Detailed Fabrication and Erection Drawings
Engineering Drawings
The drawings necessary for the design and installation of the overfire
air system were completed by the end of the eighth program month and
were submitted to the EPA for review and approval as they were com-
pleted. The design provides for the introduction of 20% of the total
combustion air as overfire air above the existing fuel admission zone.
These compartments are located approximately 2.4 meters above the ex-
isting windbox. In addition overfire air can be introduced through the
top two compartments of the existing windbox. The current design pro-
vides for the introduction of hot overfire air only.
Updated Time Schedule
The Phase II program schedule was reviewed and updated relative to the
coordination of Tasks II, IV and V with the test unit outage.
The scheduling of the unit outage was coordinated with Alabama Power
Company and reviewed periodically to assure that the unit modification
would occur as scheduled. The final program schedule presenting the
actual periods of performance for Phase II is shown on Figure 2.
Task II - Purchase and Fabricate Equipment
The equipment for modification of the Barry No, 2 unit to incorporate
overfire air as an N0y control was assembled and ready to be shipped to
the test site by the end of the eighth program month. Completion of
equipment fabrication by this date permitted necessary time for delivery
of the equipment to the job site and performing any possible pre-outage
erection which would be accomplished prior to the unit outage.
In addition, instrumentation required for the baseline and optimization
test phases of the program was calibrated, fabricated and prepared for
shipment to the job site. This effort included fabrication of corrosion
11
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TASK
TASK DESCRIPTION
1 Prepare Design Drawings for
Fabrication & Erection of NO
Control Systems
II Purchase Equipment & Fabricate
Equipment
III Install Test Instrumentation
IV Perform Baseline Tests
V Perform Bias Firing Tests
VI Deliver Equipment S Modify Unit
VII Final Test Preparation
VIII Conduct Tests
Evaluate Results & Prepare
Final Results
IX Prepare Application Guidelines
for Minimizing NO
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probes, probe control systems, and gas sampling probes, and calibration
of thermocouples, analyzers and transducers. The emissions monitoring
system is shown in Figure 3.
Task III - Test Instrumentation Installation
The analytical test instrumentation necessary for the measurement of
flue gas constituents and unit performance were installed by the fifth
program month with the exception of the waterwall absorption thermo-
couples which were installed during the unit outage for installation of
the overfire air modification.
The instrumentation and analytical methods used were as follows:
Measurement
Flue Gas Constituents
NOX
so2
CO & Hydrocarbons
Carbon Loss
Oxygen
Fuel Analysis
Ash Analysis
Flow Rates
Steam & Water
Feedwater Flow
Reheat and Superheat
Desuperheat Spray
Reheat Flow
Instrument/Analytical Procedure
Chemiluminescence Analyzer
Wet Chemistry
Infrared Analy. and Flame
lonization Analyzer
Dust Collector
Paramagnetic Analyzer
ASTM Procedures
ASTM Procedures
Flow Orifice
Heat Balance (°F & PSIG)
Around Desuperheater
Heat Balance Around Superheat
Extractions and Estimated
Turbine Gland Seal Losses
13
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Figure 3. Gaseous Emissions Test System
14
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Measurement
Air & Gas
Total Air & Gas Weight
Overflre Air*
Air Heater Leakage
Temperatures
Steam & Water °F
Unit Absorption Rates
Waterwall Absorption*
Air & Gas °F
Pressures
Steam and Hater PSIG
Unit Absorption Rates
Unit Draft Loss
Temperature and Pressure
Logging, °F & PSI
Instrument/Analytical Procedure
Calculated
Pitot Traverse
Paramagnetic 02 Analyzer
Calibrated Stainless Steel
Sheathed CR-C Well & Button
TC's
Calibrated Stainless Steel
Sheathed Cr-C Chorda! WW TC's
Cr-C TC's
Water Cooled Probes
Pt/Pt-10% Rh TC's
Pressure Gauges and/or
Transducers
Water Manometers
C-E Data Logger
Capacity: 400 temperatures,
50 pressures
Tasks IV & V Baseline & Biased Firing Test Programs
Test Data Acquisition and Analysis
The flue gas samples for determination of NOX> 02> CO, S02 and HC emis-
sion levels were obtained at each of the two economizer outlet ducts.
* Installed during Task VI
15
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The flue gas samples were drawn from a twenty-four (24) point grid ar-
ranged on centroids of equal area in each duct with the exception of the
S02 sample which was drawn from a single average point using a heated
sample line. Fly ash samples for carbon loss analysis and dust loading
were obtained at a single point in each duct.
The percent 02 leaving the air preheaters was also determined using a
twenty-four (24) point grid arranged in centroids of equal area for the
determination of air preheater leakage and unit efficiency.
The following instrumentation was used in determining the emission con-
centrations:
1. NO : Chemiluminescence Analyzer
2. 02: Paramagnetic Analyzer
3. CO: Nondispersive Infrared Analyzer
4. HC: Flame lonization Analyzer
5. S02: Wet Chemistry
6. Carbon Loss & Dust Loading: ASME Particulate Sampling Train
A summary of the NO emission test data is tabulated on Data Sheets 1,
A
2, 3 and 4.
Unit steam and gas side performance was monitored using calibrated
thermocouples, pressure gauges, transducers and manometers as required.
Coal samples were obtained during each test for later analysis. The
samples were obtained from each feeder and blended to form a composite
sample. Fuel analyses, unit steam flow rates, absorption rates, gas and
air weights and efficiencies were calculated for each test run. Unit
efficiency was determined using the heat losses method (based on ASME
power test code 4.1-1964). The measured and calculated unit performance
test data is presented on Data Sheets 5, 6, 7 and 8. A complete set of
16
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unit board data was obtained for each test run and is presented on Data
Sheets 9, 10, 11 and 12. While Data Sheets 1 through 8 are reported in
metric units, the board data (Sheets 9 through 12) are reported in the
engineering units as taken. The 30 day waterwall corrosion coupon eval-
uation was conducted using a specially designed probe consisting of four
individual coupons shown in Figure 4. Individual probes were exposed at
five locations on the front furnace wall as shown on Figure 5. A typi-
cal trace of the control temperature range for each of the twenty cou-
pons is shown on Figure 6. The control temperature ranges were the same
for the baseline, biased firing and overfire air studies.
Task IV Baseline Test Study
Load and Excess Air Variation
Tests 1 through 7 were conducted to determine the effect of varying ex-
cess air at three unit loads on unit emission levels and performance.
These tests were conducted with clean furnace conditions.
As shown in the following table, NO emission levels increased with
/\
increased excess air but did not change significantly with changes in
unit loading. An average increase of 0.014 g N02/10 cal was noted for
each 1% change in excess air over the normal unit operating range.
Load & Excess Air Variation
Test
No.
1
2
3
4
5
6
7
Main
Steam
-Flow
10J kg/hr
219
224
214
316
404
407
405
N02
g/106cal
1.337
1.030
1.519
0.90
1.041
0.761
1.403
CO
g/106cal
0.032
0.182
0.010
0.050
0.040
0.198
0.042
Theo. Air to Unit
EA Firing Zone Eff.
% % %
35.5
17.5
58.9
12.6
22.7
11.7
30.8
130.6
117.1
151.3
109.2
117.9
107.2
125.3
88.3
88.2
87.6
89.3
89.0
89.1
89.5
WW
Slag
Clean
Clean
Clean
Clean
Clean
Clean
Clean
17
-------
AIR
OUTLET
OXYGEN SAMPLING
INSERT ~~7
/ rr
AIR
INLET
Figure 4: Corrosion Probe Assembly Drawing
18
-------
(70'4") 21.44
r V '
PI _^-^
£OFA ELEV ^"^
A
D
D
\
/
r
J U
£ FUEL ELEV. A
2 3
04 FUEL ELEV. B (1
LJ
/
X
D
0
^ FUEL ELEV. C
4 5
11 & FUEL ELEV. D fl
U U
V
/\
V
FRONT MALL
~~~
*
I
Each
/\
D
D
\
/
-
y
\
D
D
-
-
s/
Probe Nos. Above
(69'-6") 21.18
(61'-9") 18.82
(57'-5") 17.50
(49'-H") 15.22
(45'-7") 13.89
Figure 5. Water-wall Corrosion Probe Locations, Alabama Power Company
Barry No. 2
19
-------
TYPICAL COUPON
TEMP. RANGE
ALL 5 PROBES
TEMPERATURE - °F
10(
CONTROL TEMP. - 750 F -
TOP COUPON OF EACH PROBE
Figure 6: Typical Corrosion ProBe Temperature Range
20
-------
A maximum excess air limit of 30.8 and 58.9 percent was obtained at
full and half load conditions respectively due to ID fan capacities.
Minimum excess air limits of 20 to 25 percent were determined as those
at which acceptable CO emission levels could be maintained. Reduction
of N00 emission levels using excess air reduction was therefore limited
C. g
to approximately 1.04 g/10 cal as obtained during Test 5.
The changes in N02, CO, percent carbon loss in the fly ash and unit
efficiency versus theoretical air to the fuel firing zone are shown on
Figures 7, 8, 9 and 10, respectively. The theoretical air (TA) to the
firing zone is used in this case as it accounts for variations in posi-
tion and leakage in the compartment dampers above the top active fuel
compartment and thereby presents a more accurate determination of the
actual air available for combustion in the fuel firing zone than does
the total excess air. As seen on Figure 7 for clean furnace conditions
the NOo correlates well with TA with little variation due to unit load.
As shown on Figures 8 and 9 carbon loss in the fly ash and CO emission
levels increased with decreased TA levels. Unit load does not appear
to have a discernable effect. Figure 10 is a plot of Unit Efficiency
versus Unit Excess Air measured at the economizer outlet.
During this portion of the test program total hydrocarbon levels (HC)
were monitored and were found to be present in only trace quantities as
shown on Data Sheets 1 and 2. The S02 levels measured are also shown on
Data Sheets 1 and 2.
Furnace Mall Deposit Variation
Tests 8 through 14 were conducted to determine the effect on unit per-
formance and emission levels of varying furnace water-wall deposits from
a clean condition to the maximum possible slagging condition obtainable.
The maximum slagging condition was obtained after operation in excess
of twenty-four hours without operating any wall blowers. During this
21
-------
no
ro
u
o
o
en
CVJ
o
w
1.5
1.4
1.3
NSPS
1 2
i i
1 0
0 9
0 8
0 7
0.6
h
/
'
P^
f^
CJ
t.
^X
f^
>x^
x
^
x^
^
^^
^
*
_
O
^
LEGEND
Unit Load Furnace Slag
§MCR Q Light
3/4 NCR $ Moderage
1/2 MCR Heavy
100
110
120
130
140
150
160
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 7: N02 Vs. Theoretical Air to Fuel Firing Zone, Baseline Study, Tests 1-14
-------
0.6
0.5
0.4
to
u
\o
o
ro
t*l
0.3
0.2
0.1
100
O
LEGEND
Unit Load
O MCR
83/4 MCR
1/2 MCR
Furnace Slag
Light
Moderate
Heavy
160
110 120 130- 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 8: CO Vs. Theoretical Air to Fuel Firing Zone, Baseline Study, Tests 1-14
-------
INJ _
** S
(/>
1.0
0.9
0.8
0.7
0.6
3 0.4
I °'3
LU
°- 0.2
0.1
0
100
110
120
130
140
150
160
LEGEND
Unit Load
B
MCR
3/4 MCR
1/2 MCR
Furnace Slag
Q Light
$ Moderate
0 Heavy
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 9: Percent Carbon Loss Vs. Theoretical Air to Fuel Firing Zone, Baseline Study, Tests 1-14
-------
90
89
o
cc.
K | 88
HH
O
87
86
85
<3>
&
10
20
30
40
50
60
UNIT EXCESS AIR - ECONOMIZER OUTLET, PERCENT
Figure 10: Unit Efficiency Vs. Unit Excess Air
LEGEND
BASELINE TESTS
Unit Load
QMCR
D3/4 MCR
<>l/2 MCR
Furnace Slag
O Light
(J Moderate
Heavy
BIASED FIRING TESTS
Unit Load
d Max Poss.
A 3/4 MCR
Ql/2 MCR
Fuel Elev. Out
of Service
& Top
& Top Ctr.
£Bot. Ctr.
tt Bot.
-------
time period slag deposits of up to 4 Inches In thickness could be ob-
tained In and above the fuel firing zone.
Furnace Hall Deposit Variation
Test
No.
8
9
10
11
12
13
14
Main
Steam
.jFlow
10Jkg/hr
411
403
405
211
206
412
406
N02
g/106cal
0
0
1
1
1
1
1
.894
.748
.198
.118
.370
.037
.225
CO
g/106cal
0
0
0
0
0
0
0
.059
.545
.007
.378
.280
.052
.043
Theo. Air to Unit
EA Firing Zone Eff.
21.5
13.0
26.0
32.7
51.2
20.7
24.3
116
108
120
128
144
115
119
.9
.5
.8
.0
.1
.7
.2
89.6
89.6
89.6
88.3
87.9
89.2
89.3
WW Slag
1/2
1/2
1/2
Max Dep
Max Dep
Max Dep
Max Dep
Max Dep
Max Dep
Max Dep
As can be seen from Figure 7 furnace slagging did not exhibit a dis-
cernable effect on NO emission levels. As shown in Figures 8 and 9
n
this condition was also found to be true for carbon loss in the fly ash
and CO emission levels with the exception of the half load Tests 11 and
12 where CO levels higher than those obtained with clean furnace condi-
tions were observed. The high CO levels may have been due to slag build
up at or near the fuel and air nozzles which could have contributed to
poor combustion. The higher CO levels were not observed under full load
with heavy slag operation. Figure 10 indicates that furnace cleanliness
did not exhibit any discernable effect on unit efficiency.
Slag patterns taken during clean, moderate and heavy slagging conditions
at full load operation are shown on Figures 11, 12 and 13.
Task V - Biased Firing Study - Fuel Elevations Out of Service Variation
Tests 15 through 24 were conducted to determine the effect on NO emis-
sion levels of taking various fuel elevations out of service (biased
firing) at various unit loadings. As shown on the following table the
26
-------
EGQ
00
"R28
"
§ s
i 2 2
/\
Figure 11: Furnace Slag Pattern, Clean Furnace
27
-------
0EE
5
S
£
w .=
3 * £
Figure 12: Furnace Slag Pattern, Moderate Slag Furnace
28
-------
SI
o
-
CM
«
7 I 1
w x
CM « JC '
00
§
LJ<«2
h-3t-5
X
TV
cog
Figure 13: Furnace Slag Pattern, Heavy Slag Furnace
29
-------
maximum NO emissions control was obtained with the top elevation of
rt
fuel nozzles out of service at maximum and 75 percent maximum loading
(Tests 20 and 21). At 50 percent maximum loading (Test 23) the high
excess air levels required to maintain unit steam temperatures appeared
to negate any NO reductions obtained by biasing the top fuel nozzle
A
elevation, however, the emissions level obtained was below the current
EPA limit for coal fired units of 1,26 g/106cal.
Biased Firing - Fuel Elevations Variation
Test
No.
15
16
17
18
19
20
21
22
23
24
Main
Steam
-Flow
10Jkg/hr
199
297
315
321
321
314
308
208
211
202
N02
c
g/10°cal
1.206
1.142
0.840
0.792
0.795
0.599
0.696
1.124
1.043
1.282
p.
g/10°cal
0.041
0.037
0.059
0.050
0.044
0.034
0.040
0.038
0.029
0.035
Theo. Air to Unit
EA Firing Zone Eff
%
50.1
26.7
21.1
22.2
21.8
24.2
29.0
48.0
47.0
47.0
%
105.8
121.7
116.5
117.5
117.2
94.7
97.3
112.5
141.4
141.3
%
87.9
89.3
89.1
89.3
88.9
88.8
89.6
87.8
87.9
87.7
Fuel Nozzle
Elevation
Out Of
Service
Bottom
Bottom
Bottom
Bot. Ctr.
Top Ctr.
Top
Top
Top
Top Ctr.
Bot. Ctr.
As can be seen from Figure 14 biasing the center two and bottom fuel
elevations did not have a discernable effect on NO emission levels al-
though the emission level tended to be higher at reduced unit loadings
for given TA levels.
Figures 15 and 16 indicate that with biased firing, low TA levels to
the fuel firing zone were obtained without increasing either CO emis-
sion levels or the carbon loss in the fly ash. Figure 10 shows that
biased firing operation did not significantly affect unit efficiency.
This condition is due to the ability to maintain acceptable total unit
excess air levels during biased firing operation.
30
-------
1.4
1.3
NSPS
1.2
1.1
(O
V0° 1.0
O
O>
CM 0.9
O
0.8
0.7
0.6
0.5
90
O
100 110 120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
150
LEGEND
Unit Load
O Max Poss.
O 3/4 MCR
ft 1/2 MCR
Fuel Nozzles
Out of Serv.
^Top Ctr.
rjBot. Ctr.
rj Bottom
Figure 14: N02 Vs. Theoretical Air to Fuel Firing Zone, Biased Firing Study, Tests 15-24
-------
0.4
0.3
ro
U
ro
0.1
90
100
110
120
130
140
150
LEGEND
Unit Load
QMax. Poss.
33/4 MCR
£1/2 MCR
Fuel Nozzles
Out of Serv.
ClTop
^Top Ctr.
QBot. Ctr.
QBottom
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 15: CO vs. Theoretical Air to Fuel Firing Zone, Biased Firing Study, Tests 15-24
-------
CO
0 6
^ 0 5
OA
i i
o n T
^^
OQ
iii n l
C£
UJ
Q.
n
C
-
O
o
Q
3
A
90
100
110
120
130
140
150
LEGEND
Unit Load
J
Max . Poss .
3/4 MCR
1/2 MCR
Fuel Nozzles
Out of Serv.
B
Ctr.
Bot. Ctr.
Bottom
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 16: Percent Carbon Loss Vs. Theoretical Air to Fuel Firing Zone, Biased Firing Study
Tests 15-24
-------
Task VIII - Unit Optimization
Load and Excess
Air
Variation
Study
(After Modification)
Load & Excess Air Variation
Test
No.
1
2
3
4
5
6
7
Main
Steam
-Flow
10Jkg/hr
219
213
217
315
450
441
423
S/106cal
0
0
1
0
0
0
1
.929
.701
.339
.684
.846
.692
.000
CO
g/106cal
0
0
0
0
0
0
0
.035
.479
.044
.140
.037
.162
.028
EA
33
16
64
15
21
12
25
%
.5
.0
.7
.5
.0
.4
.4
Theo.
Air
Firing
Zone
127
113
155
111
115
107
119
.1
.4
.4
.0
.3
.1
.5
Unit
Eff.
88.4
88.8
87.4
89.8
89.4
89.2
89.5
WW
Slag
Clean
Clean
Clean
Clean
Clean
Clean
Clean
Tests 1 through 7 were performed with unit conditions closely approxi-
mating those of Baseline Tests 1 - 7 under Program Task IV. A clean
furnace was maintained as the excess air was varied at three unit loads.
The effect of these operating conditions on emission levels and per-
formance can be seen in the Table above.
As witnessed in the previous baseline tests, NO emissions levels in-
A
creased with increased excess air.*
In general, N02 values were slightly lower after modification for
the same test conditions. This resulted from an updated firing system
installed between the sets of tests along with an average percent ni-
trogen in fuel decrease of 0.15 percent (1.21 to 1.06 percent). Also,
fuel higher heating values and furnace outlet temperatures tended to
be lower for Tests 1 - 7 after modification.
34
-------
ID fan capacities limited excess air to a maximum of 64.7 and 33.5 per-
cent at half and full load conditions respectively. Acceptable minimum
excess air limits were established at 20-25 percent to control CO emis-
sion levels. Thus, NOU emission levels could only be reduced to approx-
6
imately 0.90 g/10 cal through excess air reduction. The effect of
theoretical air to the firing zone on NO , CO, and percent carbon loss
n
in the fly ash (% CL) can be seen in Figures 17, 18 and 19. In agree-
ment with the original baseline tests, theoretical air to the firing
zone (TA) was used for comparison in place of total excess air (EA).
TA is determined by location and means of admission as well as quantity,
and consequently better defines that air actually available for initial
combustion.
Figure 17 indicates a definite increase in NO emission levels with in-
n
creasing TA for clean furnace conditions. CO emission levels and per-
cent carbon loss in the fly ash can be seen to increase with decreased
TA without overfire air. Reasonable control of CO and % CL can only be
maintained at TA levels above 120%. No definite relationship can be
observed between unit load and CO emission levels. Percent CL can be
seen to be greater at higher unit loads for given TA levels.
Changes in unit efficiency versus excess air at the economizer outlet
are presented in Figure 20. Overall, unit efficiency decreases as the
excess air increases.
Hydrocarbon emission levels appeared only in trace quantities for this
portion of the test program. HC and S02 levels are presented on Data
Sheets 3 and 4.
35
-------
1.4
u>
LEGEND
Unit Load Furnace Slag
0 MCR
D 3/4 MCR
O 1/2 MCR
O Light
3 Moderate
Heavy
110
120 130 140 150
THEORETICAL AIR TO FIRING ZONE, PERCENT
160
Figure 17:
N02 Vs. Theoretical Air to Firing Zone, Overfire Air Study,
Load and Excess Air Variation, Tests 1-14
-------
CO
U.3
0-4
0-3
to
u
IO
o
">.
01
SO. 2
0 1
0
v
K
«\
o
O
\
X
0 <
^
* <«
»~^
-^-
~
«««^.^_
<
^
LEGEND
Unit Load Furnace Slag
O MCR O Light
D 3/4 MCR O Moderate
Ol /? MPR A HPAVV
100
110 120 130 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
160
Figure 18: CO Vs. Theoretical Air to Firing Zone, Overfire Air Study,
Load and Excess Air Variation, Tests 1-14
-------
100
110 120 130 140 150
THEORETICAL AIR TO FIRING ZONE, PERCENT
160
LEGEND
Unit Load Furnace Slag
O MCR
D 3/4 MCR
O 1/2 MCR
O Light
O Moderate
9 Heavy
Figure 19: Percent Carbon Loss Vs. Theoretical Air to Firing Zone, Overfire Air Studv
Load and Excess Air Variation, Tests 1-14
-------
91
90
CJ
U) LL>
tr-, II
89
88
87
86
0
i>
0
-&-
0
0
0
©
©
0
0
0
©-
10
O
-©
Ci
70
20 30 40 50 60
UNIT EXCESS AIR - ECONOMIZER OUTLET, PERCENT
Figure 20: Unit Efficiency Vs. Excess Air - Economizer Outlet, All Tests (Before & After Modification)
-------
Furnace Wall Deposit Variation (After Modification)
Theo.
Main Air
Steam NO, rn Firing Unit
Test ,.Flow i uu. Zone Eff. WW
No. KTkg/hr g/10 cal g/10°ca! EA % % % Slag
8 440 0.985 0.0310 17.8 112.3 89.0 1/2 Max
9
10
11
12
13
14
446
428
246
218
432
425
0
0
0
1
0
0
.699
.902
.782
.310
.819
.902
0.
0.
0.
0.
0.
0.
1239
0300
0335
0304
0298
0292
12.1
26.6
30.9
63.1
22.0
25.9
106
120
124
154
116
119
.9
.5
.6
.0
.2
.9
88.9
89.5
89.3
88.0
89.0
89.4
1/2
1/2
Max
Max
Max
Max
Max
Max
The effect of furnace waterwall deposits on unit performance and emis-
sion levels was studied in Tests 8 through 14 (Clean Condition - Max-
imum Slagging Conditions). Dirty conditions were established after a
minimum of 24 hours of no operation of wall blowers. Deposits of up to
four inches in thickness could subsequently be found in and above the
fuel firing zone.
Figures 17, 18 and 19 reveal no observable effect of furnace cleanli-
ness on NOX or CO emission levels along with percent carbon loss in the
fly ash.*
Slag patterns taken during full load operation for clean, moderate and
heavy slagging furnace conditions can be viewed in Figures 21, 22 and 23.
Again, NOX values were generally slightly lower after modification.
Nitrogen in fuel decreased an average of 0.19 percent from 1.23 per-
cent. Furnace outlet temperatures were somewhat lower for Tests 8
through 14 after modification although fuel higher heating values
showed no definite change.
40
-------
ID
KEY
Tl
3
Oi
o
n>
01
(Q
T3
B*
r*
f+
n>
-s
V
o
n>
Oi
3
Tl
i
Dl
o
fl>
RICHT
1
1
3
2
1
\/
PBfWT
i
11 2
2
1 >
1
1
1
^
r
\
3 3
3
2
1
\/
REAR
1
2
3
2
J "
1
1
NO ASH
FUZZY 4"
RUNNING
TEST 15
DATE 6/19/74
TIME 2:00 PM
MU LOAD130 MU
1
3
4
ED
6
-------
ro
(£3
O>
ro
ro
-s
Ol
n>
Bl
TO
Ol
n>
-s
a
to
ID
CO
Qi
(0
01
o
JtlfiHT
? "
1 3 2
3 33
2
V '/
\/
FRONT
1 2 1
1243
3 3 3
2
J L
i i
l
LEFT
' 'N
1 3 4
333
2
1 1
\ '/
\/
REAR
3 33
13 31
333
2
1
1
KEY
NO ASH
FUZZY 4"
RUNNING
TEST 18 & 19
DATE 6/20/74
TIKE 1Q30AM
KU LOAD " 30
-------
co
n>
ro
co
-t
n
m
co
Dl
IQ
-o
Ol
to
-t
(D
to
CO
o>
<£»
O»
n
n>
RIGHT
2 1
/ "
1 3 4
2 22
4
1 1 1
\/
FRONT
11 30
1131
13 32
22 33
« f*
4
J L
i 1 l
i i i
LEFT
1 2
' ^
1 3 2
2333
_ p-
4
1 1 2
\/
REAR
12 31
21 33
4
1 1 1
1 1 1
KEY
NO ASH
FUZZY 4"
RUNNING
Q
TEST *13
DATE 6/28/74
TIME 11:45 AM
KU LOAD 126
-------
This set of tests also confirms the results found in Tests 1 through 7.
NO emission levels increase with increased excess air. NO cannot be
A A
decreased through excess air reductions below 20 percent excess air
while maintaining an acceptable CO emission level without overfire air.
OFA Location, Rate, and Velocity Variation
Adm. Adm.
Pts.* Rate
0-1 0
0-1 Max
0-2 Max
0-1,0-2 Max
0-1,0-2 1/2 Max
0-3 Max
0-1 0
0-1,0-2 Max
0-1,0-2 1/2 Max
Tests 15 through 23 were performed to establish the effect of overfire
air admission on N0₯ emission levels. The unit load and excess air re-
A
mained constant for moderately dirty furnace conditions. Location of
air admission to the furnace was varied.
As shown in Figure 24, this set of tests shows a tendency of NO emis-
sion levels to decrease with decreased theoretical air to the firing
Test
No.
15
16
17
18
19
20
21
22
23
Main
Steam
-Flow
10Jkg/hr
336
340
338
344
338
344
342
341
346
N09
c.
c
q/10°cal
0.723
0.533
0.533
0.479
0.486
0.677
1.012
0.689
0.704
rr\
l»U
f.
g/10°cal
0.0358
0.0382
0.0413
0.0613
0.0500
0.0367
0.0321
0.0329
0.0322
Theo.
Air
Firing
Zone
%
114.5
96.7
95.8
84.8
89.3
100.5
117.4
90.4
96.9
Unit
Eff.
%
90.0
89.8
89.7
89.6
89.3
90.2
90.1
89.0
89.1
Mills
In
Serv.
BCD
BCD
BCD
BCD
BCD
BCD
ABC
ABC
ABC
OFA Admission Points:
0-1: Top overfire air compartment.
0-2: Bottom overfire air compartment.
0-3: Top fuel elevation out of service.
44
-------
1.4
1.3
NSPS
1.2
1.1
u
10
o
i
un
tf.9
10.8
0.7
0.6
0.5
0.4
0.3
80
LOWER LIMIT OF ACCEPTABLE TA LEVELS
85
90 95 100 105 110
THEORETICAL AIR TO FIRING ZONE, PERCENT
115
Figure 24: N02 Vs. Theoretical Air to Firing Zone, Overfire Air Location,
Rate & Velocity Variation, Tests 15-23
120
LEGEND
Adm. Pts.
A 0-1
k 0-2
b 0-1, 0-2
Q 0-3
Rate
A No OFA
A 1/2 Max. OFA
A Max. OFA
Mills In Serv.
ABC
BCD
-------
zone. NO levels are generally higher with ABC mills (top 3 elevations)
in service than with BCD mills (bottom 3 elevations). Both operating
conditions support the premise of reducing NO emission levels by re-
/\
ducing the air input to the fuel firing zone and admitting downstream
of that point. The fire is thereby spread out over more of the furnace
reducing its intensity. The above factors are limited by flame sta-
bility which became very lazy in Test 18. By using the bottom 3 ele-
vations in place of the top 3 elevations, the distance between the over-
fire air and the firing zone was increased. (The mean firing elevation
is also slightly decreased.) Comparison of Tests 18 and 19 with Tests
22 and 23 reveals lower NO levels obtained with increased distance be-
A
tween the overfire air and the firing zone. Operation at TA levels be-
low 95X did not result in significant reductions in NO emission levels.
n
CO emission levels remained acceptable for the entire set of tests
where the total excess air was approximately 27 percent as shown on
Figure 25.
OFA admission location or rate variation exhibited no significant
change in percent carbon loss in the fly ash as shown on Figure 26.
Unit efficiencies were not significantly affected by fuel elevations in
service, or by overfire air location and rate variation. This is ex-
plained by the fact that essentially constant total excess air levels
were maintained during this study.
46
-------
0.4
0.3
0.2
u
UD
O
o 0.1
O
80
t
LOWER LIMIT OF ACCEPTABLE TA LEVELS
85
90 95 100 105 T10
THEORETICAL AIR TO FIRING ZONE, PERCENT
115
Figure 25: CO Vs. Theoretical Air to Firing Zone, Overfire Air Location
Rate & Velocity Variation, Tests 15-23
120
LEGEND
Adm. Pts.
A 0-1
fck 0-2
b 0-1, 0-2
Q 0-3
Rate
A No OFA
A 1/2 Max. OFA
A Max. OFA
Mills In Serv..
ABC
BCD
-------
0.9
0.8
0.7
I 0.6
-0.5
0.4
I/O
00
o
on
-P" et
00 CJ> Q3
Q2
0.1
80
LOWER LIMIT OF ACCEPTABLE TA LEVELS
85
90 95 100 105 110
THEORETICAL AIR TO FIRING ZONE, PERCENT
115
Figure 26: Percent Carbon Loss Vs. Theoretical Air to Firing Zone, Overfire Air Location
Rate & Velocity Variation, Tests 15-23
120
LEGEND
Mills In Serv.
ABC
BCD
Rate
A No OFA
A 1/2 Max. OFA
A Max. OFA
Adm. Pts.
A 0-1
k 0-2
Q 0-1, 0-2
Q 0-3
-------
OFA Tilt Variation
Main
Steam
-Flow
ICTkg/hr
407
418
412
407
414
418
416
409
N09
£
c
q/10bcal
0.710
0.609
0.770
0.721
0.846
0.596
0.710
0.697
rn
l«U
c
g/10bcal
0..0324
0.0346
0.0406
0.0282
0.0360
0.0630
0.0333
0.0316
EA X
25.9
23.7
25.1
22.3
20.2
23.7
21.6
27.4
Theo.
Air
Firing
Zone
%
94.2
92.4
93.2
91.5
89.6
92.6
90.7
94.6
Unit
Eff.
%
89.6
89.3
88.9
89.3
88.6
89.4
89.0
89.0
Fuel
Nozz
Tilt
0
-5
-23
+19
-5
+22
-21
-4
-22
OFA
Tilts
o
0
0
0
-30
-30
+30
0
-22
Test
No.
24
25
26
27
28
29
30
33
Tests 24 through 30, and 33, were conducted at full unit load with ex-
cess air and theoretical air levels to the firing zone of approximately
24 percent and 92 percent, respectively. With moderate slagging con-
ditions on the waterwalls the fuel nozzle tilts and OFA tilts were
varied. This essentially moves the firing zone both in -the furnace and
in its relative position to the overfire air. Fuel nozzle tilts that
are maximum minus combined with OFA tilts of maximum plus increase the
distance between the overfire air and the firing zone. As with previous
methods of increasing this distance, the NO emission levels are de-
/\
creased. Figure 27 shows that as the tilts are moved toward one an-
other (fuel nozzle tilts up; OFA tilts down), the OFA - firing zone
separation is decreased and the NO levels are increased.
rt
When the OFA tilts are maximum minus and the fuel nozzle tilts maximum
plus, the term overfire air becomes ambiguous. The actual overfire air
is less than the reported value, because the air is being forced .down
into the raised firing zone. At this point where the combined fuel
nozzle and OFA tilt differential is 52 degrees toward each other, the
NO emission level reaches a maximum of 0.846 g/10 cal.
A
49
-------
01
o
0.9
0.8
u
VO
o
CM
O
0.7
0.6
0.5
70 60
50 40 30 20 10 0 10 20 30 40 50
TOWARD EACH OTHER AWAY FROM EACH OTHER
OFA TILT AND FUEL NOZZLE TILT A , DEGREES
Figure 27: NC2 Vs. OFA Tilt and Fuel Nozzle Tilt Differential, OFA Tilt Variation
Tests 24-33
60 70
-------
Percent carbon loss in the flyash exhibits a definite increase as the
fuel nozzle tilts and OFA tilts move away from each other. This can be
witnessed in Figure 28.
CO emission levels also show an increase as the tilt differential in-
creases, yet there is enough total excess air to maintain an acceptable
emission level as shown in Figure 29.
Flame stability arises as a limiting factor in variation of the tilts.
As the tilts move substantially away from each other, the fire becomes
unstable and pulsing may result. Test 29 was performed with a fuel noz-
zle and OFA tilt differential of 51 degrees away from each other. NOV
6
emission levels decreased to 0.596 g/10 cal, yet the CO emission levels
began to increase and the fire appeared less stable. Maintaining the
fuel nozzle tilts and OFA tilts at approximately equal tilt angles re-
sulted in acceptable flame stability as well as reduced NO emission
n
levels.
For all OFA tilt variation tests the NO emissions level obtained was
below the EPA limit of 1.26 g/106cal.
Load Variation at Optimum Conditions
Tests 30 through 35 were conducted to evaluate unit performance and
emission levels at optimum operating conditions as determined during
Tests 15 through 29. Tests were conducted over the unit load range at
varying furnace waterwall slagging conditions. The NO emission level
A
results of this series of tests versus unit loading, expressed as main
steam flow, are shown on Figure 30.
51
-------
ro
0.7
0.6
GO
-------
0.07
0.06
r- 0.05
10
0
10
o
SO-04
en
CO
a 03
a 02
70 60
Figure 29: C0_ Vs
50 40 30 20 10 0 10 20 30 40 50
TOWARD EACH OTHER AWAY FROM EACH OTHER
OFA TILT AND FUEL NOZZLE TILT A, DEGREES
tilt and Fuel Nozzle Tilt Differential, OFA Tilt Variation
60 70
-------
. n
-^
1 .4
1.3
NSPS
1.2
1.1
1 .0
O
D
O
C\J
O
.7
.4
LEGEND
O Baseline Tests
A Optimization Tests
200
250
300
350
400
450
50
MAIN STEAM FLOW - 10 KG/HR
75
100
PERCENT OF FULL LOAD RATING
Figure 30: N0? Vs. Main Steam Flow, Ranges for Normal & Optimum Operation
-------
Load Variation at Optimum Conditions
Test
No.
30
31
32
33
34
35
Main
Steam
,Flow
10Jkg/hr
416
314
204
409
310
204
N02
,.
g/10°cal
0.710
0.708
0.828
0.697
0.608
0.655
rn
l»U
c
g/10°cal
0.033
0.033
0.031
0.032
0.034
0.032
EA %
21.6
25.2
46.9
27.4
27.4
45.9
Theo.
Air
Firing
Zone
%
90.7
89.4
88.5
94.6
90.6
88.5
Unit
Eff.
%
89.0
89.1
89.2
89.0
88.2
89.0
WW
Slag
Clean
Clean
Clean
Max.
Max.
Max.
This figure illustrates the range of N02 levels obtained both during
baseline (after modification) and optimum unit operations. Not all the
baseline tests are included as in some cases unit operation was felt to
depart excessively from normal operations. Low excess air operation
can be cited as an example.
The wide range of N0» levels obtained, particularly during the base-
line tests are due to variations in unit operating parameters such as
excess air level. During the optimization tests total excess air at
the unit economizer outlet was maintained between 20 and 28% at full
and 3/4 load and 45 to 47% at 1/2 load and fuel nozzle tilts raised or
lowered as required to maintain acceptable reheat and superheat outlet
temperatures. Also minimum excess air levels were established on the
basis of maintaining acceptable CO emission levels and flame stability.
Tests 30, 31 and 32 were conducted as a series and no problems were en-
countered while changing load with optimum operation.
Furnace Performance
During the test program furnace performance was monitored by use of
chordal thermocouples installed in the furnace waterwalls. A schematic
of the thermocouple locations is shown in Figure 31 and a tabulation of
55
-------
en
IO
I
CO
o
s.
PI
n>
o
o
o
-a
a>
o
a>
o
n>
n>
01
Til
i I i I ' !
iii!!i!!i
23 24 25 26 27 28 29
O S-O S-O S'O S-OS10 S-O
30 31 32 33 34
OS'OS-OS'OS'O
0 2
ir
0 4
ir
o 6
ir
35 36 37 38 39 40 41 [<
O O O O O O O
fc
MAQ en c i e.y c » CA
H9 3U 9 1 3t 9 J 9*r -d
ooooooo*
(
0 61
0 63
0 1
^^^ |V
0 3
ir
0 5
ir
0 7
ht4-t
l|7 14 1* 2
00 0 C
>| 42 43 514 4
0 O 0 C
j| *''m"n
L 55 55 4-Sjr-
J 6 o eT c
4--S"
>| 0 60
10-
0 62
\ I0
X ° M
\z
^
*s'*i
D 2J
5 4(
1 0
58 5f
?B6
X
-j
V,
I
/
r
l23'-4"
lOJ'-J-
941-9"
91--4"
I4--4"
-74-.*..
M-.9"
S91-7» '
J7'-S"
49MI1'
45 -7-
JJ--7"
REAR (7)
LEFT SIDE (5)
FRONT (37)
RIGHT SIDE (25) (64 TOTAL)
-------
the absorption rates obtained Is presented on Sheets 13A, 13B and 13C.
The temperatures and corresponding absorption rates were found to vary
significantly with wall slag conditions making data interpretation
difficult. The method finally arrived at as representing an accurate
indication of furnace performance is as follows:
The front and right side wall centertube profiles were plotted as shown
in Figure 32 and the average of these profiles determined. It should be
noted that the maximum and minimum profiles shown do not represent in-
dividual walls in every case, i.e., at given furnace elevations the max-
imum rate shown may switch from wall to wall.
For comparison of optimum and normal unit operation with respect to fur-
nace performance, three full load tests with similar furnace slagging
conditions, etc., were selected for comparison. The average centerline
profiles for these tests (14, 24, 33) were determined, as shown on Fig-
ures 32, 33 and 34, and then plotted together as shown on Figure 35. As
shown, furnace performance remained essentially unchanged when furnace
slagging effects are taken into account.
It should be noted here that obtaining desired slag conditions proved to
be difficult and somewhat unpredictable during overfire air operation.
This situation was most pronounced in the firing zone where slag accu-
mulations would normally shed themselves before appreciable accumula-
tions could be built up.
Uaterwall Corrosion Coupon Evaluation
Following completion of the steady state phases of the baseline, biased
firing and overfire air test programs, thirty (30) day waterwall corro-
sion coupon evaluations were performed. The purpose of these evalua-
tions was to determine whether any measurable changes in coupon weight
losses could be obtained for the various firing modes studied.
The corrosion probes used in the evaluations were previously shown on
57
-------
24.38
~ (80)
Date: 6/28/74
riLoad: 125 MW
Furn. Absorp.: 153.17 106KG-CAL/Hfi
Total Absorp.: 276.4 1Q6KG-CAL/HR
'.t-TA to Fuel Firing Zone: 119.9 X
'-Total Excess Air: 25.9 X
" O - Front WW Center Tube Profile
O - Right WW Center Tube Profile
" - Avg. Center Tube Profile - Both Walls
FUEL ELEV. A -\| -
FUEL ELEV. C ' H
0 24 6 8 10 12 14 16 18 20 22 24
TUBE CROWN ABSORPTION RATE, KG-CAL/HR-ChT
Figure 32: Average Centerline Absorption Profile, Test 14
58
-------
36.58
(120)
33.53
(110)
30.48
(100)
27.43
(90)
24.38
(80)
21.34
(70)
18.29
(60)
15.24
(50)
12.19
(40)
9.14
(30)
6.10
ft
:.
:\
: i . i i i"
TEST 124
Date: 7/29/74
Load: 124 MW
Furn. Absorp.: 145.13 106KG-CAL/HR
Total Absorp.: 276.9 106KG-CAL/HR
TA to Fuel Firing Zone: 94.2 J
Total Excess Air: 25.9 S
O - Front WW Center Tube Profile
_ - Right WW Center Tube Profile
A - Avg. Center Tube Profile - Both Walls
0 * "6 8 10 12 14 16 18 20 22 24 26 28
TUBE CROWN ABSORPTION RATE, KG-CAL/HR-CM2
Figure 33: Average Centerline Absorption Profile, Test 24
59
-------
36.58
(120)
33.53
(110)
8 10 12 14 16 18 20 22 24 26 28
6.10
(20)
TUBE CROWN ABSORPTION RATE. KG-CAL/HR-CM
Figure 34: Average Center!ine Absorption Profile, Test 33
60
-------
36.58
(120)
33.53
(110)
02 4 6 8 10 12 14 16 18 20 22 24 26 28
TUBE CROWN ABSORPTION RATE, KG-CAL/HR-CM2
Figure 35: Average Center!ine Absorption Profile, All Tests
61
-------
Figure 4. The Individual probes were exposed at five locations on the
furnace front wall as shown on Figure 5, The coupon temperatures were
maintained at the same levels for each 30 day run and a typical trace
of the control temperature range for each of the twenty coupons Is shown
on Figure 6.
The individual coupon weights were determined before and after each
thirty day test and the individual coupon and average probe weight
losses are shown on Sheets 14A, 14B, and 14C. The weight losses are
2
calculated as mg/cm of coupon surface area. Of the sixty coupons ex-
posed, three were damaged during disassembly and were therefore not
included in the weight loss determinations. The affected coupons were
as follows: Coupon K-l, baseline study, and coupons 2-1 and 2-4 over-
fire air study. In addition, five coupons from probes T and N of the
overfire air study resisted disassembly and were therefore weighed as
single units and average weight losses were determined.
Figures 36, 37 and 38 show the unit load schedules for each of the
30 day test periods.
The biased firing study was conducted with the top fuel firing eleva-
tion out of service as this operating condition was shown during steady
state biased firing tests to produce the lowest NO emission level of
/\
the biasing modes studied. The overfire air study was conducted using
an "optimized" operating mode as determined during the overfire air
steady state tests.
Throughout each study the following damper positions were maintained
over the load ranges indicated.
At unit loadings below 204,000 kg/hr steam flow, with two elevations of
mills in service, damper positions were maintained as follows:
62
-------
150
125
100
75
50
25
"-\j~
2/6/74
rv
v^
2/7/74 I 2/8/74 2/9/74 I 2/10/74
' ' I I "t I « .' |
2/11/74
AVG. GROSS MW/HR
30 DAY PERIOD
87.7 MW/HR
3/11/74" "| _3/12/74"_
CORROSION PROBE EXPOSURE TIME - DAYS
Figure 36: Gross MW Loading Vs. Time
Study
- Baseline Corrosion Probe
63
-------
AVG. GROSS NU/
HR - 30 DAY
PERIOD
64.0 MW/HR
3-21-74 I 3-22-74 3-23-74
3-27-74" "J" 3-28-74 '3-29-74 | 3-30-74
25 I
4-14-74 4-15-74
4-16-74 4-17-74 I 4-18-74
CORROSION PROBE EXPOSURE TIME - DAYS
4-19-74 I 4-20-74
Figure 37: Gross MW Loading Vs. Time
Study
64
- Biased Firing Corrosion Probe
-------
AVG. GROSS MW/HR
30 DAY PERIOD
77.0 MU/HR
9-11
9-1Z | 9-13 9-14 9-15 $-16 9-19
CORROSION PROBE EXPOSURE TIME - DAYS
1« Ml-t I .-,1.1
.9-20
Figure 38: Gross MW Loading Vs. Time
Study
- Overfire Air Corrosion Probe
65
-------
Biased Firing Operation Overfire Air Operation
Coal Auxiliary
0
0
0
0
30
50
30
1001 Combustion
pj Air Only
OFA Dampers
Coal
100
30
0
0
100
100
Auxiliary
100
50
50
0
0
0
From 204,000 to 272,000 kg/hr steam flow, with three elevations of mills
in service, the damper positions were as follows:
Biased Firing Operation Overfire Air Operation
Coal Auxi1i ary
1001 Combustion
100 J Air Only
50
20
50
50
20
50
20
50
OFA Dampers
Coal
100
30
30
0
100
100
Auxiliary
100
50
50
50
50
0
66
-------
At unit loadings above 272,000 kg/hr to the maximum steam flow with the
maximum elevations of mills in service, the following damper positions
were maintained.*
Biased Firing Operation Overfire Air Operation
OFA Dampers 100
100
Coal Auxiliary Coal Auxiliary
1001 Combustion 100
100 J Air Only 100
50 50
30 30
50
50
30
50
30
50
The percent oxygen was monitored daily during each thirty day study at
each probe location and was found to be essentially the same for the
various test conditions ranging between 16 and 19 percent Op.
The weight losses calculated for the biased and overfire air portion of
the test program were found to be greater than those for the baseline
tests. The average weight losses for all five probes were as follows:
30
30
50
50
50
50
At no time during the biased firing study was the top elevation coal
pulverizer placed in service. Maximum unit loading was therefore
limited to the maximum with the lower three mills in service.
67
-------
Baseline Biased Firing Overfire Air
2.6381 mg/cm2 4.6429 mg/cm2 4.4419 mg/cm2
These values are within the range of losses which would be expected for
oxidation of carbon steel for a 30 day period. To verify this premise
control studies were conducted in C-E's Kreisinger Development Labora-
tory using probes exposed during the biased firing study. These probes
were cleaned and prepared in an identical manner to those used for fur-
nace exposure and placed in a muffle furnace for 30 and 60 day exposures
at 750 F with a fresh air exchange. The test results were as follows:
2
Probe Wt. Loss mq/cm - 30 Days
M (30 day) 4.7999
Q (30 day) 4.7741
R (60 day) 5.1571/2 = 2.5785
B (60 day) 8.3493/2 =4.1746
These results indicate that the test coupons oxidized more rapidly
during the first 30 days exposure with average weight losses decreas-
ing in the second thirty days. Based on these results, it appears
that the differences in weight losses observed during the test pro-
gram are within the ranges to be expected from oxidation alone.
Chemical analysis of deposits taken during the test program does not,
in itself, show that molten phase attack has occurred. The composition
of the deposits does show some differences, primarily in the iron con-
tent as noted on Figure 39. The deposit collected during the biased
firing and overfire air tests show 50 and 35 percent iron, respectively,
versus 30 percent in the baseline test. Higher iron is normally in-
dicative of lower melting temperatures. However a certain quantity of
CaO is necessary to flux the iron if it is to result in a low melting
mixture. The CaO content is considerably less in the biased firing and
overfire air tests as compared to that of the baseline test. According-
68
-------
Water-wall Waterwall
Ash Fusibility
IT
ST
HT
FT
Ash Composition
Si02
A1203
Fe203
CaO
MgO
Na20
K20
Ti02
P2°5
S03
Waterwall
Slag
Samp! e
Baseline
Test
1930
2090
2200
2500
46.2
18.4
29.9
3.9
0.8
0.32
0.61
N.R.
N.R.
0.34
100.4
Coal Ash
(As -Fired)
2150
2410
2500
2620
45.8
30.7
13.9
1.8
1.3
0.4
1.4
0.8
0.5
1.2
97.8
Slag
Sample
Biased
Fi ri ng
Test
2060
2170
+2700
+2700
38.4
10.3
50.0
1.0
0.3
0.1
0.7
N.R.
N.R.
0.8
101.5
Slag
Sample
Overfire
Air
Test
1930
2090
2250
38.5
18.1
35.4
1.8
0.9
0.4
1.9
1.0
N.R.
0.4
98.4
Figure 39. Ash Analysis
69
-------
ly the fusibility temperatures are higher for the biased firing test
and slightly higher for the overfire air tests. This agrees with ob-
servations made during the tests, i.e., deposits during biased firing
were more friable and easily removed than in the baseline tests with
the overfire air tests falling closer to baseline operation.
For comparison fusibilities and compositions have been given in Figure
39 for the coal ash as fired. This points out the selective deposition
of certain constituents in the coal ash, like iron, and also shows that
resultant fusibility temperatures of deposits can be significantly diff-
erent than the coal ash as fired.
Overfire Air Evaluation - Alternate Coal Types
The evaluation of alternate coal types with respect to their effect on
unit performance and NO emissions optimization was originally proposed
A
as part of this study. However, due to coal supply problems encountered
after the start of work, these evaluations proved to be not feasible and
were therefore not performed. Tests of a similar nature evaluating Ala-
bama and Midwestern coals were performed during 1973 by Esso Research
and Engineering Co. under EPA Contract 68-02-0227 at the Alabama Power
Co., Barry No. 4 unit. A discussion of those test results has therefore
been included in this report/ '
Unit Description
Barry No. 4 is a controlled circulation, radiant, reheat, single cell
pressurized design firing coal through five elevations of tilting tan-
gential fuel nozzles. Maximum continuous rating is 1,164,969 kg/hr
superheat steam flow at 538°C/176 kg/cm2 and 1,024,566 kg/hr reheat
steam flow at 538°C/44 kg/cm. Control load rating is 582,485 kg/hr
main steam flow.
Alabama and Midwest coals plus petroleum coke were fuels being burned
at the time of the test program. The petroleum coke was fired exclu-
70
-------
sively through the center fuel nozzle (Elevation C) and normally repre-
sented one-quarter to one-fifth of the heat input.
Test Objectives
The objectives of the Esso test program were as follows:
1. A series of short (thirty minutes) tests for optimizing NO reduc-
n
tion by varying the following:
A. Excess Air
B. Nozzle Tilt
C. Overfire Air
D. Primary/Auxiliary Air Damper Settings
E. Unit Load
F. Pulverizer Coal Fineness
G. Firing Alabama Coal, Alabama + Coke and Midwest + Coke
2. A two or three day sustained operation at optimum NO reduction op-
erating conditions for checking possible short term unit operating
problems.
3. A three hundred hour operating period at optimum NO reduction con-
A
ditions for determining possible long term operating problems.
Discussion
Test Data Acquisition
Esso Research measured all gas emission levels with instrumentation lo-
cated in a specially designed mobile van. The van was located at ground
level and had the following instrumentation:
NO Thermo Electric Chemiluminescence
N02 Beckman Ultraviolet, Thermo Electric Chemiluminescence
71
-------
co2
so2
CO
Beckman Infrared
02 Beckman Paramagnetic
Esso also employed a remote recorder readout of CO, N02 and 02 in the
control room for convenience in observing emission levels during testing.
There were no conveniently located test inserts available for gas sam-
pling at the gas duct entering the air heater. Esso, therefore, had to
set up a twelve point sampling grid after the air heater. The flue gas
sampling rate from each point was proportioned to a gas flow previously
determined by velocity traverse. All gas sample lines were heated until
the particulate filters, then all condensables are removed by a 32°F ice
bath. The gas sample is then blended to one sample per probe location
and pumped under 5 pounds pressure to the sample analytical van.
C-E instrumented Corners #1 and 2 windbox compartments to determine the
amount of overfire air and the air flow to each compartment. A static
pressure tap was installed in each compartment and the pressure differ-
ential to the furnace measured.
Petroleum coke, Alabama coal and Midwest coal are normally available at
this plant. Normally the coals are fired as mixed in the coal pile. For
the test series Alabama and Midwest coals were supplied directly to the
bunker. The petroleum coke is burned in a separate Nozzle "C" with coal
firing in surrounding Coal Nozzle B and D to insure stable ignition.
Normal coal fineness as taken before the tests was 72 percent thru the
200 mesh screen. Coal fineness was changed to approximately 60 percent
thru the 200 mesh screen on several tests to investigate the possible
effect on NO emission levels.
«
72
-------
Esso Research obtained pulverizer coal and coke samples from the feeder
belts of each mill on every test. Typical analysis for the coals and
coke is presented on Sheet 17.
Unit Performance
Boiler operation as reported on Sheet 15 and ISA was based on board in-
strumentation. The NO , CO, C02 and S02 PPM values represent data as
averaged from Esso data sheets using the appropriate instrument calibra-
tion tables.
Test Emission Data
Overfire Air
The greatest effect on NO emission levels was obtained by use of over-
A
fire air which decreases the amount of air to the firing zone. Figure
40 presents the NO emission levels versus percent excess air to the
, A
firing zone for all tests. Emission levels are reduced from 525 PPM to
approximately 327 PPM in reducing theoretical air from 134 to approxi-
mately 95 percent at 0° tilt.
Excess Air
Unit operating excess air as determined at the air heater inlet had no
significant effect on NO emission levels (corrected to 0 percent excess
A
air when maintaining a constant theoretical air to the firing zone.
Figure 41 shows that with this type of operation the unit operating ex-
cess air level could be varied from 6 percent to 26 percent with essen-
tially constant NO emission; unit excess air was important, however, in
A
keeping CO emissions at low values (Figure 42).
CO Emissions
Figure 42 indicates that CO emissions are a function of percent excess
air at the air heater inlet and also the amount of overfire operation.
The test data indicates that at 15 percent excess air unit operation
and no overfire air the CO emission was 33 PPM which increased to 93 PPM
73
-------
Alabama Power Company
Barry #4
3
CM
O
1 3
NSPS
1 2
i i
1 0
0 9
0 8
0 7
0 6
Oc
.3
£
50
L
A
/*-*
c
Y
A y
'
10
/
"%
r
1C
-30
^
/
A,
/
!)
10
Degret
V n
7 u
G
>G
^B
D
n
Tilt
r
.
x^»
0
/
12
0 Dec
/
0
ree r
1
It
LEGEND
Degrees Tilt Symbol
-20 to -30 A
0 0
+15 to +20 n
SYMBOL COAL
Open Alabama + C
Solid Midwest + C
30 1/2 Solid Alabama
THEORETICAL AIR TO THE FIRING ZONE, PERCENT
Figure 40: N0« Vs. Percent Theoretical Air to Firing Zone,
All Tests at Unit Loads of 290 to 360 MW
-------
Alabama Power Company
Barry #4
1.4
01
ro
O
C\J
O
1.3
NSPS
1 2
1 l
i n
0 R
0 7
0 6
n R
-O
r
o
d
) ©
h ,-,
-
-------
Alabama Power Company
Barry #4
150
CT>
CVJ
O
3
St.
Q.
Q_
CD
O
100
50
0
,
*<
5
Symbol
A
O
§
\
Vs!
/
u
'hfjr*-
Ty
i
\
\
/ G
V^
^
D
\0
1
ks
^
Ds^
*\$
-------
with overfire air (90 to 100 percent theoretical air to burner zone).
In coal firing 15 percent excess air would seem to be the lowest prac-
ticable limit of operation.
Nozzle Tilt
Operating at -30° fuel nozzle tilt increased the NO emission approxi-
A
mately 87 PPM over that obtained at 0° tilt. The limited testing with
plus tilts o-
sion levels.
plus tilts of +15° and +20° produced no effect on the measured NO emis-
A
Effects of Other Operating Variables
The variation of primary/secondary air dampers (Figure 43) unit load and
the pulverized coal fineness had minor effects on NO emission levels.
This substantiates previous test results and indicates that these opera-
ting variables should continue to be used to control normal boiler op-
eration and should not be considered as NOX controls with coal firing.
Type of Coal
During the test series the following combinations of fuel were fired:
Fuel No. of Tests
1. Alabama Coal 4
2 Alabama Coal + Coke 15
3. Midwest Coal + Coke 5
Figure 40 plots all tests and identifies the firing combinations and in-
dicates no change in emission levels with fuel change.
Unit Operation
Superheat-reheat outlet temperature of 538/538°C could be maintained at
90 percent MCR horizontal tilt and 95 percent theoretical air to the
burner zone which was the optimum NO reduction conditions. The overfire
/\
77
-------
Alabama Power Company
Barry #4
1.4
1.3
NSPS
1.2
1 i
1 0
IS
u
to
° 0 9
i
°° ~ 0.8
o u<
0 7
0 6
n R
AUX./PRIM. DAMP. - % (
TEST NO.
LOAD - MW
T?LT - DEG.
% THEORETICAL AIR TO
FIRING ZONE
3PEN
V
100/2C
3/
34{
2.L
C
109.1
k
*\
)
t
3
[
)
^^
1
100/5C
/
34!
'(
109.^
P
)
>
j
I
)
I
'
-C
50/1 0(
3!
36(
2.t
'(
109.!
p
)
)
I
)
Figure 43: Auxiliary/Primary Damper Positions Vs. N02
-------
operation maintains the gas weight thru the unit which results in un-
changed superheat-reheat performance.
No adverse furnace slagging was noted during the short term tests with
low theoretical air to the firing zone. The three hundred hour, long
term test with approximately 95 percent theoretical air to the firing
zone and 15 percent excess air at air heater inlet was also completed
without excessive furnace slag buildup.
300 Hour Corrosion Probe Test Results
Corrosion probes were installed in the furnace of the test boiler by
inserting them through available viewpoints in the furnace firing zone
as shown on Figure 44. Prior to installing the probes in the test fur-
nace, the probes were prepared by mild acid pickling, preweighing the
coupons, and screwing them onto the probes along with the necessary
thermocouples. Each probe was then exposed to the furnace atmosphere
prevailing for the particular type of operation desired for approxi-
mately 300 hours at coupon temperatures of about 468°C in order to accel-
erate corrosion. After exposure, furnace slag was cleaned off and saved
for future analyses, and the coupons were carefully removed from the
probes. In the laboratory the coupons were cleaned ultrasonically with
fine glass beads to the base metal, and reweighed to determine the
weight loss.
Total weight loss data was converted to corrosion rates on a mils per
year basis, using the combined inner and outer coupon rates, coupon
material density, and exposure time.
Corrosion rates have been determined for 8 coupons installed on 4 probes
(2 coupons/probe), in four different locations on the furnace wall. The
corrosion data obtained is tabulated on Sheet 16.
Although there is some scatter in the data obtained, Esso concluded "that
79
-------
PROBE
NOS.
ABOVE
EACH
LOCATION
-3
0-
^H
^1
/
I
E
C
C
[
\
k
]
:
:
:
:
/
<{. FUEL
t FUEL
Q. FUEL
-------
no major differences In corrosion rates have been observed for coupons
exposed to 'low NO ' conditions compared to those subjected to normal
operation."
Esso further concluded that "since corrosion rates were deliberately
accelerated in this study in order to develop 'measurable1 corrosion
rates in a short time period, measured rates, as expected, are much
higher than the normal wastage of actual furnace wall tubes."
Task IX - Application Guidelines
The program outlining the application of the technology developed under
this study to existing and new tangentially coal fired utility boilers
will be presented in the Task IX report and is therefore not discussed
as part of this report.
81
-------
ALABAMA POWER COMPANY
RARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE STUDY
NOX TEST DATA SUMMARY
TEST No.
PURPOSE OF TEST
DATE
LOAD
MAIN STEAM FLOW
EXCESS AIR ECON. OUTLET
THEO. AIR To FUEL FIRING ZONE
FUEL ELEV. IN SERV.
FUEL NOZZLE TILT
./*.. Aux.
. ' p3 FUEL
| in 1 1 AUX.
gg |M FUEL
LJO: z/S Aux. /Aux.
siSicMrucL
Si°L_ *"*
2 0>*nj"] FUEL
V' AUX.
SHO TEMPERATURE
RHO TEMPERATURE
UNIT EFFICIENCY
GAS WEIGHT ENT. A.H.
NO"
SO
so
CO
CO
HC
o
0
CIRBON Loss IN FLYASH
DUST LOADING
TEST No.
PURPOSE OF TEST
1
2
3
EXCESS AIR VAR
NW-
10JKo/HR
-------
ALABAMA POWER COMPANY
BARRY J3
C-E POWER SYSTEMS
FIELD TESTINB AND
PERFORMANCE RESULTS
BIASED FIRING STUDY
NOX TEST DATA SUMMARY
Test No.
15
Biased Firing
Purpose of Test
Date
Load
Main Steam Flow
Excess Air Econ. Outlet
Theo. Air to Fuel Firing Zone
Fuel Elev. In Serv.
Fuel Nozzle T1lt
w Aux.
pn Fuel
6,' I I Aux .
8 p {53 Fuel
° ^^ Aux /Aux
j 65 5 EEI Fuel
K 2 o I 1 Aux .
§ 5^t P'D"! Fuel
>^ Aux.
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Weight Ent. A.H.
NO.
NO!
SO*
so.
CO
CO
HC
0,
4
Carbon Loss 1n Flyash
MW-
10JKg/HR
X
X
Deg.
°C
°C
* 3
103Kg/HR
PPM -,X 0,
GR/IO^CAL*
PPM -,l 0,
GR/106CAL<:
PPM -,J 0,
GR/IO^CAL*
PPM - X 0,
X A.H. In'
X A.H. Out
X
1/2 Load
1-19-74
66
199
50.1
105.8
ABC
-9
50
20
50
20
50/50
20
50
100
100
546
496
87.9
341
594
1.206
1721
4.861
33.38
.0412
0.0
7.10
8.54
.32
16
1L
li
li
1 Fuel Elev. Out of Service - Air Dampers
3/4 Load
1-18-74
96
297
26.7
121.7
ABC
0
50
20
50
20
50/50
20
50
100
100
539
506
89.3
430
543
1.142
1682
4.922
29.10
.0372
0.0
4.55
7.19
.34
f
12-3-73
100
315
21.1
116.5
ABC
-15
50
30
50
30
50/50
30
50
100
100
529
501
89.1
439
397
.840
2422
7.137
45.63
.0588
0.0
3.72
6.08
.46
-Max Load -
12-4-73
103
321
22.2
117.5
ABD
-15
50
30
50
30
50/100
100
50
30
50
543
520
89.3
455
373
.792
2553
7.536
38.51
.0497
.012
3.885
5.80
.37
*l
12-5-73
99
321
21.8
117.2
ACD
-10
50
30
100
100
50/50
30
50
30
50
523
486
88.9
428
387
.795
2292
6.543
35.48
.0443
.012
3.825
6.30
.42
Test No.
Purpose of Test
Date
Load
Main Steam Flow
Excess Air Econ. Outlet
Theo. Air to Fuel Firing Zone
Fuel Elev. in Service.
Fuel Nozzle Tilt
Aux.
|Fuel
Fuel
Aux./Aux.
Fuel
Aux
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Weight Ent. A.H.
NO
NO,
S0|
sof
coz
CO
HC
0-
Carbon Loss in Flyash
Dust Loading
20
21
23
Biased Firing -
Max Load
MW,
103Kg/HR
X
X
Deg.
°C
°C
X ,
10JKg/HR
PPM -,X 0,
GR/106CAL*
PPM -.X 0,
GR/106CAL*
PPM -,X 0,
GR/10°CAL<:
PPM - X 0,
X A.H. In'
X A.H. Out
X
GR/SCM
12-6-73
102
314
24.2
94.7
BCD
-5
100
100
50
30
50/50
30
50
30
50
544
515
88.8
451
285
.599
2277
6.661
26.61
.0341
0.0
4.165
7.31
.25
8.65
1 Fuel Elev. Out of Service - Air Dampers Open
3/4 Load p 1/2 Load H
1-18-74
94
308
29.0
97.3
BCD
+10
100
100
50
20
50/50
20
50
20
50
512
469
89.6
435
331
.696
1566
4.578
31.28
.0400
0.0
4.76
8.37
.30
1-19-74
64
208
48.0
112.5
BCD
0
100
100
50
20
50/50
20
50
20
50
501
448
87.8
360
520
1.124
1861
5.593
29.10
.0382
0.0
6.93
8.40
.20
1-19-74
64
211
47.0
141.4
ACD
0
50
20
100
100
50/50
20
50
20
50
507
454
87.9
361
485
1.043
2245
6.710
22.41
.0293
0.0
6.85
8.58
.11
1-19-74
66
202
47.0
141.3
ABD
-15
50
20
50
20
50/100
100
50
20
50
544
513
87.7
356
609
1.282
1807
5.288
27.54
.0353
0.0
6.79
6.87
.21
83
SHEET 2
-------
ALABAMA POWER COMPANY
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
NOX TEST DATA SUMMARY
BASELINE STUDY AFTER MODIFICATION
TEST HO
Purpose of Test
Date
Load HU
Main Steam Flow lO^KG/HR
Excess Air Econ Outlet X
Theo. Air to Fuel Firing Zone X
Fuel Elev. In Serv.
OFA Nozzle Tilt DEG
Fuel Nozzle Tilt OEG.
OFA
OFA
Aux
Fuel
Aux
Fuel
Aux /Aux.
Fuel
Aux.
Fuel
Aux.
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Weight Ent. A.H
NOX
N02
S02
S02 GR/1
CO PPM -
CO GR/1
HC PPM - OX 02
02 X A.H. In
02 X A.H Out
Carbon Loss In Flyash X
C
C
KpKG/HR
PPM - OX 02
GR/106CAL
PPH - olcft
92
1
fc
F
6/25/74
62
219
33.5
127 1
ABC
0
3
0
0
20
30
20
30
20/20
30
20
0
0
492
435
88.4
335
444
.929
3678
10.718
27.54
.0351
0
5.36
7.35
.29
2
6/25/74
62
213
16 0
113.4
ABC
0
6
0
0
0
30
0
30
10/10
30
10
0
0
4GB
402
88.8
270
335
.701
3621
10.551
375 77
4790
0
2.95
5.52
.23
3_
Excess Air
6/25/74
64
217
64 7
155.4
ABC
0
-14
0
0
50
30
50
30
50/50
30
50
0
0
536
499
87.4
413
640
1 339
2611
7 606
34.66
.0442
0
8.36
9.70
1 06
4
Var. - Clean
6/27/74
92
315
15 5
111.0
ABC
0
2
0
0
30
20
60
20
80/80
20
50
0
0
504
466
89.8
398
327
.684
2634
7.674
109.70
1398
0
2.87
5 5
.11
5
Furnace Cond.
6/19/74
131
450
21.0
115.3
ALL
0
-13
0
0
80
30
100
30
100/100
30
100
30
100
528
488
88.4
593
404
.846
2251
6.559
26.37
0336
0
3.71
7.36
.75
6
MBxInium Lofld
6/27/74
127
441
12.4
107 1
ALL
0
-3
0
0
100
30
100
30
100/100
30
100
30
100
524
487
89.2
546
330
.692
2677
7.800
127 2
.1622
0
2 36
5 75
.51
7.
6/27/74
125
423
25.4
119.5
ALL
0
-22
0
0
100
35
100
35
100/100
35
100
35
100
518
480
89.5
559
477
1.000
2707
7.889
21.74
.0277
0
4.34
7.02
.74
TEST HO.
Purpose of Test
Date
Load MM
Main Steam Flow ICpKG/HR
Excess Air Econ Outlet X
Theo Air to Fuel Firing Zone X
Fuel Elev. In Serv
OFA Nozzle Tilt DEG
Fuel Nozzle Tilt DEG
(Fuel
Aux.
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Weight Ent. A.H
TOX
S02
S02
CO
CO
HC
°2
02
Carbon Loss in Flyash
"C
"C
lO^KG/HR
PPM - OX 02
PPM -
PPM - OX 02
GR/106CAL
PPM - OX 02
X A.H. In.
X A H. Out.
X
8 9 10
E.A. Var. - Mod. Dirty Furnace
K Maximum Load »)
11
13
14
E A Var. - Dirty Furnace
1/2 Load Maximum Load
6/20/74
130
440
17.8
112.3
ALL
0
-21
0
0
80
30
100
30
100/100
30
100
30
100
526
486
89 0
565
470
.985
1941
5 655
24 31
.0310
0
3 24
G.8
22
6/20/74
129
446
12 1
106 9
ALL
0
-17
0
0
80
30
100
30
100/100
30
100
30
100
528
483
88.9
542
334
.699
2482
7.232
97.16
.1239
0
2.31
6 19
42
6/28/74
125
428
26.6
120 5
ALL
0
-6
0
0
100
30
100
30
100/100
30
100
30
100
524
480
89 5
584
431
902
2500
7.283
23 55
0300
0
4 5
7 48
61
6/26/74
65
246
30.9
124.6
ABC
0
-16
0
0
20
30
20
30
20/20
30
20
0
0
507
457
89.3
363
373
782
2558
7 453
26.28
.0335
0
5 04
7 55
17
6/26/74
68
218
63.1
154 0
ABC
0
-16
0
0
50
30
50
30
50/50
30
50
0
0
531
498
88 0
419
626
1.310
2461
7.171
23.85
0304
0
B 23
10.75
05
6/28/74
126
432
22.0
116 2
ALL
0
-6
0
0
100
30
100
30
100/100
30
100
30
100
524
496
89.0
575
391
819
2564
7.470
23 4
0298
0
3.86
7.3
.36
6/28/74
125
425
25.9
119 9
ALL
0
-6
0
0
100
30
100
30
100/100
30
100
30
100
529
499
89.4
583
431
.902
2629
7.661
22.92
.0292
0
4.4
7.15
.25
84
SHEET a
-------
ALABAMA POWER COMPANY
BAP-T ff
C-E Povtr SvsT'MS
Fl^LD T'5TIMC ANP
PE»roi>MAiicc RESULTS
NOX TEST DATA SUMMARY
OVERFIRE AIR LOCATION, RATE & VELOCITY VARIATION
TEST NO.
Purpose of Test
Date
Load , MM
Mam Steam Flow ID^KG/HR
Excess Air Econ. Outlet X
Theo. Air to Fuel Firing Zone X
Fuel Elev. In Serv.
OFA Nozzle Tilt DEG.
Fuel Nozzle Tilt DEG.
I OFA
Aux.
Fuel
Aux.
' Aux./Aux.
Fuel
Aux.
jFuel
Aux.
SHO Temperature °C
RHO Temperature °C
Unit Efficiency , X
Gas Height Ent. A.H. KPKG/HR
NOX PPM -
W>2 GR/IC
S02 PPM - OX 02
SO? GR/106CAL
CO PPM - OX 02
CO GR/10»CAL
HC PPM - OX 07.
02 X A.H. In.
02 X A.H. Out.
Carbon Loss In Flyash X
16.
17
ISA
OFA Damper Position Variation
19
7/10/74
97
336
28.5
114.5
BCD
0
-5
0
0
0
0
50
30
SO/SO
30
50
30
50
518
457
90.0
458
345
.723
1892
5 512
28.10
.0358
0-.
4.74
6.51
.51
7/10/74
98
340
27.1
96.7
BCD
0
-5
100
0
0
0
50
30
SO/ 50
30
50
30
50
510
452
89.8
447
254
.533
1973
5.750
29.96
.0382
0
4.55
6.49
.59
7/10/74
100
338
25.6
95.8
BCD
0
-5
0
100
0
0
50
30
50/50
30
50
30
50
514
457
89.7
442
254
.533
2092
6.097
32.4
.0413
0
4.36
6.08
.63
7/12/74
100
344
26.6
84.8
BCD
0
-4
100
100
0
0
50
30
50/50
30
50
30
50
524
476
89.6
466
229
.479
2397
6.984
48.08
.0613
0'.
4.5
6.32
.54
7/11/74
100
338
24.8
89.3
BCD
0
-4
50
SO
0
0
50
30
SO/SO
30
50
30
50
521
486
89.3
468
232
.486
2684
7.821
39.20
0500
0
4.25
6.05
.32
TEST NO.
Purpose of Test
Date
Load MU
Main Steam Flow lO'KG/HR
Excess Air Econ. Outlet X
Theo. Air to Fuel Firing Zone X
Fuel Elev. In Serv.
OFA Nozzle Tilt DEG.
Fuel Nozzle Tilt DEG
FTOFA
LJOFA
. Zv Aux.
20 21 22
OFA Damper Position Variation
21
LJ K zgg Fue1
rigtfX Aux. /Aux.
g|5pJFuel
kftFuei
V Aux.
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Height Ent. A.H.
NOX
N02
S02
S02
CO
CO
HC
02
°Z
Carbon Loss in Flyash
c
c
103|(G/HR
PPM - OX 02
GR/106CAL
PPM - OX Oz
GR/106CAC
PPM - OX 02
GR/10*CAL
PPM - OX 02
X A.H. In.
X A.H. Out.
X
7/11/74
100
344
25.4
100 5
BCD
0
-4
0
0
100
0
50
30
50/50
30
50
30
50
524
479
90 2
468
323
.677
1821
5.308
28.79
.0367
0
4 33
6.14
.49
7/12/74
102
342
25 4
117.4
ABC
0
-4
0
0
100
100
50
30
50/50
30
50
0
0
532
498
90.1
476
483
1.012
1814
5.284
25.16
.0321
0
4.33
6.05
.46
7/12/74
102
341
27.9
90 4
ABC
0
-4
100
100
100
100
50
30
50/50
30
50
0
0
524
491
89.0
494
329
.689
2259
6.583
25.79
.0329
0
4.67
6.46
.54
7/12/74
102
346
28.1
96.9
ABC
0
-4
50
SO
50
50
50
30
50/50
30
50
0
0
521
485
89.1
492
336
.704
2417
7.042
25.28
.0322
0
4.69
6.72
.60
WFT 4A
-------
ALABAMA Powcn COMPANY
BARRV IS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
NOX TEST DATA SUMMARY
OFA TILT VARIATION
TEST NO.
Purpose of Test
Date
Load , HW
Main Steam Flow KHKG/HR
Excess Air Econ. Outlet X
Theo. Air to Fuel Firing Zone X
Fuel Elev. In Serv.
OFA Nozzle Tilt
Fuel
DEG
Lie Tilt DEG.
OFA
OFA
Aux.
Fuel
Aux.
Fuel
Aux./Aux.
Fuel
Aux.
Fuel
Aux.
SHO Temperature °C
RHO Temperature °C
Unit Efficiency , X
Gas Weight Ent. A.H. l^KG/HR
NOX PPM - OX 0?
NO? GR/lOOCAt
SO? PPM - OX 02
502 GR/106CAL
CO PPM - OX 02
CO GR/10»CA[
HC PPH - OX 02
0? X A.H. In.
02 X A.H. Out.
Carbon Loss In Flyash X
24
25
26
21
28
29
OFA & Fuel Nozzle Tilt Variation
7/29/74
124
407
25.9
94.2
ALL
0
-5
100
100
100
100
so
30
50/50
30
50
30
50
538
532
89.6
548
339
.710
2450
7.140
25.4
.0324
0
4.4
5.9
.37
7/29/74
124
418
23.7
92.4
ALL
0
-23
100
100
100
100
50
30
50/50
30
50
30
50
521
508
89.3
566
290
.609
2920
8.511
27.1
.0346
0
4.1
6.0
.37
Full
7/29/74
124
412
25.1
93.2
ALL
0
+19
100
100
100
100
50
30
50/50
30
50
30
50
524
527
88.9
585
368
.770
3310
9.647
31.8
.0406
0
4.3
6.2
.40
Loud
7/29/74
125
407
22.3
91.5
ALL
-30
-5
100
100
100
100
50
30
50/50
30
50
30
50
527
533
89.3
557
344
.721
3160
9.208
22.1
.0282
0
3.9
6.0
.29
7/29/74
125
414
20.2
89.6
ALL
-30
+22
100
100
100
100
50
30
50/50
30
50
30
50
524
535
88.6
586
404
.846
3370
9.820
28.2
.0360
0
3.6
5.8
.29
7/29/74
124
418
23.7
92.6
ALL
+30
-21
100
100
100
100
50
30
50/50
30
50
30
50
521
505
89.4
544
285
.596
3240
9.443
49.4
.0630
0
4.1
6.4
.49
LOAD VARIATION AT OPTIMUM CONDITIONS
TEST MO.
Purpose of Test
30
Max. Load
31
32
33
Load Variation at Optimum Conditions
34
3/4 Load
1/2 Load
35
1/2 Load
Date
Load
MW
Main Steam Flow lO^KG/HR
Excess Air Econ. Outlet X
Theo. Air
Fuel Elev
to Fuel Firing Zone X
In Serv.
OFA Nozzle Tilt
Fuel Nozzle Tilt
rn
r
' n?
la? U
3^y iS
N s o re
z SXM
K
V
OFA
OFA
Aux.
Fuel
Aux.
Fuel
Aux. /Aux.
Fuel
Aux.
Fuel
Aux.
SHO Temperature
RHO Temperature
Unit Efficiency
Gas Weight Ent. A.H.
NOX
ml
S02
soi
CO
CO
HC
02
02
Carbon Loss In Flyash
Dust Loading
DEG
DEG.
C
"C
, x
WKG/HR
PPH - OX Of
GR/10BCAL
PPH - OX 0»
GR/10»CAL
PPH - OX 02
GR/106CAL
PPH - OX 09
X A.H. In.
X A.H. Out.
X
GR/SCH
7/30/74
125
416
21.6
90.7
ALL
0
-4
100
100
100
100
50
30
50/50
30
50
30
SO
538
536
89.0
574
339
.710
1680
4.896
26.1
.0333
0
3.8
5.3
.61
8.64
7/31/74
97
314
25.2
89.4
ABC
-12
-16
100
100
100
100
50
30
50/50
30
50
0
0
525
514
89.1
456
338
.708
1730
5.043
26.1
.0333
0
4.3
5.7
.39
7/31/74
65
204
46.9
88.5
AB
0
-5
100
100
100
100
50
30
50/0
0
0
0
0
535
514
89.2
341
396
.828
1740
5.070
24.4
.0311
0
6.8
8.2
.32
7/31/74
122
409
27.4
94 6
ALL
-22
-22
100
100
100
100
50
30
50/50
30
50
30
50
521
521
89 0
584
333
.697
2430
7.083
24.8
0316
0
4.6
6.3
.24
7/31/74
95
310
27.4
90.6
ABC
-22
-22
100
100
100
100
50
30
50/50
30
50
0
0
506
493
88.2
472
291
.608
2490
7.256
26.4
.0337
0
4.6
6.8
.33
8/1/74
64
204
45.9
88.5
AB
-10
-IS
100
100
100
100
50
30
50/0
0
0
0
0
512
493
89.0
329
313
.655
2420
6.960
25.0
.0319
0
6.7
8.4
1?
86
SHEET 4B
-------
ALABAMA PowtR COMPANY
BARRY IS
C-E POWER SYSTEMS
FIELD TESTING AND
PeRPORMANCc RESULTS
BASELINE STUDY
TEST DATA
TEST No.
DATE
TIME
UNIT LOAD - Mrf
10
12
13
FLOWS -
FEEDWATER
SH SPRAY (HEAT BALANCE)
MAIN STEAM
TURBIHE LEAKAGE
RH EXTRACTION
RH SPRAY (HEAT BALANCE)
RH FLOW (CALC.)
AIR t GAS FLOUS - IQTtG/HR
GAS EHT. A.H.
GAS Lvc A.H.
AIR CUT A.H.
AIR LVG. A.H.
A.H. LEAKAGE
UNIT ABSORPTIOH - 106Kc-CAL/H»
ECON.
FURN.
DRUM - DCSUP.
DESUP. - S.H. OUT.
RH
TOTAL
PRESSURES
STEAM & WATER - KG/CM
ECON. IN
DRUM
SH - DESUP. IN
SH OUT
RH IN
RH OUT
AIR & GAS - CM We
F.D. FAN OUT
"B" A.H. AIR OUT
"B" A H. GAS OUT
"D" ELEV. LETT REAR FUEL AIR COMP.
"A" ELEV. LEFT REAR FUEL AIR COMP.
LEFT MILL DUCT AT WINOBOX
MILL AIR DUCT AT "B" ELEV. MILL
UPPER FURNACE
TEMPERATURES - *C
STEAM t WATER
SH OUT
SH OESUP IN
SH DESUP. OUT
RH OUT
RH DesuP IN
RH DESUP OUT
ECON IN
ECON OUT
1 1 -30-73
01 55
66
217
2.11
819
9.98
13.79
18
195
352
392
389
328
40 18
B.32
85 53
24
16 9
19.8
154.6
134.1
132.8
130.9
129.8
15.04
14.27
3.56
1.524
-12.193
-3 81
-2 54
1.016
-.762
-1 524
529
426
418
488
895
294
198
233
11-30-73
00 00
65
222
1.67
224
10.2
14.56
.09
199
300
343
320
278
42 6
7.03
89.06
18 5
18.62
18 85
152
134 3
133.0
131 1
129.8
15 25
14.41
3.048
1.016
-15.24
-3 175
-3.175
1.016
-.762
-1.778
498
393
389
446
267
267
198
227
11-30-73
02-45
67
206
8.3
214
9.52
12 70
18
192
412
451
427
389
38.74
9 65
79 05
29.2
16 08
20.6
154.6
134
132.6
131.1
130.0
15 11
14.34
4.064
2.032
-16.256
-3.175
-3 175
.508
-1.016
-1.524
548
470
435
517
311
310
198
242
1-18-74
16 00
93
309
2.5
316
14
23
0.0
279
386
445
414
355
59
8.8
110
31.2
22
24.8
207
140.5
139
133.6
130.8
22.43
21.09
5.08
1.016
-15.24
-3.048
-1.524
.508
-1.27
-2 032
500
409
404
449
286
286
217
242
11-14-73
15-10
124
400
4.13
404
17.83
31.62
.907
355
554
631
590
512
77.88
12.20
145
54
24.5
33 67
270
142 2
140.5
134.3
130.7
29.38
27.98
10.67
3.81
-26.416
1.905
.635
2.032
-.508
-1 .524
539
458
449 *
514
342 .
339
230
257
11-2B-73
13-21
123
401
5.90
407
17.92
31.62
.907
358
518
587
546
478
67.90
10 99
148
52
27.32
35.56
274
136.7
134.9
132.2
130.7
29.46
28 05
7.112
1.016
-28.86
-.381
-.508
-3.81
-1.905
-1.778
539
452
440
524
343.
340
230
254
11-28-73
10:37
123
393
11.8
405
17.6
31.0
1.32
357
592
663
623
552
71
12.8
143
57.6
24.1
35.9
273
136.8
135
132.3
130.7
29.46
28
15.24
5.588
-27.686
5.08
3 81
3.81
2.032
-.635
538
475
447
524
342
339
230
259
11-15-73
11-10
126
399
11.5
411
17.83
31.39
1.13
363
567
618
375
524
49.89
12.19
142.5
59.0
29.18
36.29
279
149.6
147.8
137.4
131.2
30.09
28.68
10.16
3.048
-25 908
1.905
.254
1.778
.635
-15.24
548
468
444
533
351
348
231
258
11-19-73
13. 04
122
391
12.11
403
17.55
31.07
.907
355
502
561
520
461
58.88
11.16
143.6
52.7
28 22
33 94
279
139.9
138.1
133.3
130.5
29.24
27.84
7.62
1.905
-24.384
.635
0
.508
-1.016
-2.032
533
456
431
510
337
335
229
254
11-19-73
10:00
124
384
20.14
405
17.24
29.89
.907
358
565
645
603
523
80.0
12.7
138.9
59.4
28.68
36.16
275.8
141.0
139.3
134.1
131.0
29.53
28.12
13.335
6.35
-27.94
5.08
3.81
4.445
3.175
-1.016
544
484
440
531
347
344
229
259
12-5-73
01-40
66
210
1.09
211
9.66
13.52
.09
188
323
350
351
301
36.51
7 66
83.6
20.2
16.78
18.9
147.1
131.3
130.0
129.5
129.1
14.69
13.92
3.048
1.27
-10.668
-3.556
-3 048
.508
-.508
-1.778
518
409
405
476
339
283
197
231
12-4-73
23-30
74
204
1.81
206
9.39
12.79
.18
184
369
408
385
346
39.42
8.85
79.53
25.49
14.97
19.05
147.8
131.5
130 2
129.7
129.4
14.76
13.99
3.302
.508
-14.224
-3.302
-1.524
-.254
-1.524
-1 524
548
446
438
508
310
309
199
239
11-16-73
14:20
125
"390
21.86
412
17.46
30.84
.73
364
556
635
592
513
79.11
12.87
138
61.4
31.25
35.73
275.7
150.6
148.9
137.7
131.1
29.74
28.33
10.668
4.318
-27.432
2.54
2.54
22.86
.508
-1.27
539
481
4%
522
343
340
230
259
11-16-73
9:50
125
385
20.77
406
17.24
30.3
.907
359
567
646
604
524
79 38
12.7
137.5
60.9
28.53
36.04
141 5
146.5
144.8
136. 1
131.0
29.81
28.40
12.70
5.08
27.94
4.445
4.445
3.81
2.54
-1.016
543
486
440
529
347
344
230
259
-------
ALABAMA POWER COMPANY
BARRY f2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE
TEST
STUDY
DATA
TEST No.
#5 HP HEATER l«
K HP HEATER OUT
K HP HEATER EXT IN
#5 HP HEATER DRAIN
SPRAT WATER
AIR 4 G>9
A.H GAS IN
A.M. GAS OUT
A H AIR IN
A.H AID OUT
FURNACE OUTLET (Avc.)
AIR HEATER LEAKAGE - %
A.H. GAS Sloe EFFICIENCY - %
UNIT EFFICIENCY - g
PRODUCTS or COMBUSTION . GR/10 CAL.
AH INLET
10
12
13
EXCESS AIR - %
A.H. IN
A.H OUT
FUEL ANALYSIS - $
CARBON
HrOROGEN
NITROGEN
OXYOCN
SULFUR
MOISTURE
ASH
HHY - CAL/C
167
199
286
19S
134
282
145
29.4
263
1096
11 41
49 5
88 3
1852
1877
1911
2012
2079
2106
2138
2241
35.5
52.1
65.1
4.4
1.2
5 6
2.1
8 8
12.8
64SS
166
198
260
195
134
273
150
30.6
261
1127
14.19
44 5
88.2
1589
1611
1649
1744
1834
1858
1894
1991
17.5
35.6
65.2
4 4
1.2
5.6
S 2
8 7
12 7
6499
168
199
300
196
134
295
142
24.4
269
1045
9 41
53 0
87.6
2173
2200
2232
2333
2389
2419
2448
2552
58.9
74.8
65 6
4.4
1.2
5.6
1.8
7 6
13.8
6499
183
217
282
214
148
298
150
43 3
269
1202
15.33
52.3
89.3
1343
1512
1532
1575
1667
1766
1787
1827
12 6
31 4
64 9
4 1
1.2
5 5
2 3
9 8
12.2
6449
194
231
336
226
157
325
154
41.0
280
1226
14 07
55 1
89.0
1665
1944
1190
1825
1919
1944
1982
2081
22 7
41.4
65.1
4.3
1 3
6.9
3.1
8 8
10.5
6460
193
230
337
225
156
321
153
33.3
282
1295
13.08
53.8
89 1
1554
1775
1595
1687
1751
1775
1811
1906
11.8
27.6
66
4.4
1.2
5.6
1.4
7 0
14.4
6466
193
230
337
225
157
298
150
43.3
269
1206
12.03
S3.S
89.5
1784
1807
1843
1939
2014
2039
2074
2171
30.8
47.6
66.3
4.4
1.2
5.6
1.7
7.4
13.4
6560
195
232
346
227
157
325
153
39
281
1314
8 87
57.0
89.6
1663
1685
1728
1822
1822
1845
1886
1984
21.5
33.2
66.8
4.3
1.3
6.9
2.3
9 1
9.3
6538
193
231
331
226
156
320
156
37 8
283
1274
11.72
53.6
89.6
1514
1534
1577
1669
1706
1728
1771
1865
13.0
27.5
65 4
4.3
1.3
7.4
2.3
8.8
10.1
6555
194
231
341
226
156
328
153
41.0
276
1278
14.16
57.9
89.6
1678
1699
1741
1838
1933
1958
1998
2097
26 0
45.3
64.0
4.3
1.3
7.4
3.0
9.9
10.1
6494
167
199
275
195
134
277
153
33.3
262
1122
11.29
48.3
88.3
1782
1805
1845
1942
2000
2025
2061
2160
32.7
48.8
63 5
4.2
1.1
5.9
2.9
9.5
12.9
6382
168
199
300
195
134
288
152
30 0
268
1096
10.69
51.1
87 9
2030
2057
2092
2192
2061
2291
2324
2426
51.2
68.4
64.2
4.2
1.1
5.9
2.5
9.6
12.5
6449
194
232
337
227
157
329
153
36 7
282
1323
14.22
55 4
89.2
1615
1636
1678
1775
1863
1888
1926
2027
2O.7
39.3
64.6
4.3
1.3
7.4
2.7
10.7
9.6
6494
194
231
341
226
157
330
149
35 6
278
1302
14 00
56.7
89.3
1678
1699
1739
1836
1931
1957
1926
2092
24.3
43.1
64.7
4.4
1 2
6 9
2 3
8.3
12.2
6477
-------
ALABAMA POWER COMPANY
BARRY fS
C-E POWER SYSTEMS
FIELD TESTING AND
PERfORMANCE RESULTS
BIASED FIRING STUDY
TEST DATA
TEST NO.
Date
Time
Unit Load
FLOWS - 1Q3KG/HR
Feedwater
SH Spray (Heat Balance)
Main Steam
Turbine Leakage
RH Extraction
RH Spray (Heat Balance)
RH Flow (Calc.)
AIR & GAS FLOWS -
15
16
17
18
19
20
21
22
23
24
MM
Gas Ent.
Gas Lvg.
Air Ent.
Air Lvg.
AH
AH
AH
AH
AH Leakage
UNIT ABSORPTION - IQ^KG-CAL/HR
Economizer
Furnace
Drum - DESK
UESH - SH Out.
RH
Total
PRESSURES
STEAM 8 HATER - KG/CH2
Economizer In.
Drum
SH - DESK In.
SH Out.
RH In.
RH Out.
AIR & GAS - CM. WG
FD Fan Out.
"B" AH Air Out.
"B" AH Gas Out.
"D" Elev. Left Rear Fuel Air Comp.
"A" Elev. Left Rear Fuel Air Comp.
Left Mill Duct at Uindbox
Mill Air Duct at "B" Elev. Mill
Upper Furnace
TEMPERATURES - °C
STEAM & WATER
SH Out.
SH DESK In.
SH DESH Out.
'19/74
09:10
66
199
0
199
9.06
12.1
.091
178
341
377
356
350
35.5
8.88
76.4
27.2
11.5
17.5
141.5
138.5
137.2
132.8
130.3
14.84
14.0
2.03
-.508
14.73
-.762
-1.27
-.762
-2.29
-2.03
546
459
452
1/18/74
18:24
96
296
1.77
297
13.4
20.9
.272
264
430
505
475
398
76.8
10.05
110
36.6
21.0
26.2
204
139.9
138.4
133.1
130.2
22.26
21.0
7.87
2.03
-18.8
1.27
-.762
1.016
-.762
-1.78
539
456
435
12/3/73
11:07
100
304
10.85
315
13.7
22.0
.408
280
439
502
467
405
62.8
10.01
115
39.8
22.4
28.1
216
132.2
130.7
129.4
128.6
22.89
21.7
7.37
2.03
-18.8
1.27
1.02
1.27
-.508
-2.03
529
454
425
12/4/73
01:30
103
310
11.15
321
13.9
22.2
.272
284
455
499
465
421
43.1
10.045
116
43.1
22.9
29.4
222
132.9
131.3
130
129.4
23.24
22.05
7.11
2.03
-19.81
-1.52
-1.02
1.016
-1.016
-2.03
543
466
436
12/5/73
23:50
99
314
5.54
321
14.2
23.1
.091
282
428
479
446
396
50.6
9.4
120.5
35.4
23.9
26.9
216
133.6
132
130.3
129.4
21.98
21.49
4.06
.762
-17.78
-1.52
-1.78
-.508
-1.27
-2.03
523
429
416
12/6/73
02:30
102
307
7.08
314
13.7
22.2
.408
278
451
511
477
418
59.8
9.8
116.5
39.2
24.0
28.1
218
133.9
132.4
130.8
129.7
22.75
21.56
6.1
1.27
-18.8
-1.78
.254
.508
-2.03
-2.03
544
449
431
1/18/74
20:30
94
307
1.50
308
13.8
22.2
.045
272
435
507
476
405
72.8
9.55
105.8
34.8
19.4
25.2
205
139.5
138
132.8
129.9
22.4
21.14
7.87
2.29
-18.8
-.508
.76
1.27
-.254
-1.78
512
427
423
1/19/74
15:45
64
203
2.18
208
9.5
13.3
0.0
185
360
400
376
337
39.6
8.45
80.0
23.3
12.1
17.6
141.5
138.7
137.3
133.1
130.2
14.98
14.14
2.29
-.254
-14.22
-2.03
-.76
-.762
-2.29
-1.78
501
427
420
1/19/74
13:30
64
209
1.77
211
9.6
13.6
0.0
188
361
403
380
338
42.5
8.65
80.8
24.2
12.7
17.8
144
138.4
137
132.5
130.1
14.84
14
2.03
-.254
-14.22
-2.03
-2.03
-1.016
-1.52
-2.03
507
431
424
1/19/74
11:30
66
194
7.62
202
9.1
11.9
.091
181
356
404
382
334
42.8
9.13
73.9
28.2
14.5
19.4
145
138.4
137
133.1
130.2
14.77
13.93
2.29
-.508
-14.73
-2.03
-2.03
-1 016
-2.29
-1.78
544
472
438
89
SHEET 6A
-------
ALABAMA POWER COMPANY
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING STUDY
TEST DATA
TEST NO.
TEMPERATURES - "C
15
16
17
18
19
20
21
22
23
24
STEAM & MATER (Cont.)
RH Out.
RH DESK In.
RH DESH Out.
Economizer In.
Economizer Out.
#5 HP Heater In.
#5 HP Heater Out.
#5 HP Heater Ext. In.
US HP Heater Drain
Spray Hater
AIR & GAS
AH Gas In.
AH Gas Out.
AH Air In.
AH Air Out.
Furnace Outlet (Avg.)
Air Heater Leakage X
AH Gas Side Efficiency %
Unit Efficiency *
PRODUCTS OF COMBUSTION - GR/106CAL.
AH INLET
Dry Air
Wet Air
Dry Prod.
Met Prod.
AH OUTLET
Dry A1r
Net Air
Dry Prod.
Net Prod.
EXCESS AIR - *
AH In.
AH Out.
FUEL ANALYSIS - %
Carbon
Hydrogen
N1 trogen
Oxygen
Sulfur
Moisture
Ash
HHV - CAL/G
496
307
307
200
241
169
200
297
197
135
298
154
28.3
273
1036
10.4
51.1
87.9
1962
2000
2010
2120
2100
2210
2240
2340
50.1
66.7
63.5
4.1
1.1
6.4
2.3
9.7
12.9
6510
506
320
319
218
450
185
219
313
214
149
311
147
44.4
271
1197
17.89
55.4
89.3
1720
1740
1780
1875
2050
2080
2115
2210
26.7
51.1
64.8
4.1
1.2
5.5
2.2
10.4
11.8
6416
501
315
313
218
248
184
219
303
215
149
307
145
38.4
271
1246
14.32
55.3
89.1
1650
1670
1715
1815
1910
1935
1970
2080
21.1
39.9
64.3
4.2
1.1
5.9
2.9
11.6
10.0
6360
520
327
326
219
450
185
220
321
216
150
311
147
37.8
274
1253
9.46
56.8
89.3
1670
1690
1732
1830
1841
1865
1905
2010
22.2
34.7
64.7
4.2
1.1
5.9
2.8
11.4
9.9
6383
486
308
308
217
244
182
218
302
213
147
301
140
23.3
268
1171
11.8
53.4
89.0
1610
1632
1670
1765
1816
1840
1880
1970
21.8
37.3
62.5
4.2
1.1
5.9
2.7
10.0
13.6
6399
515
327
326
217
247
183
218
321
213
147
305
136
17.2
269
1195
13.24
53.8
88.8
1685
1705
1745
1840
1925
1950
1990
2085
24.2
42.0
64.8
4.2
1.1
5.9
2.5
9.4
12.1
6438
469
297
297
217
245
183
217
291
214
148
312
143
44.0
265
1129
16.73
56.3
89.6
1745
1770
1810
1900
2060
2090
2125
2190
29.0
52.2
65.2
4.2
1.2
5.5
2.1
9.0
12.9
6455
448
268
268
199
237
169
200
261
197
136
293
147
37.2
268
999
11.02
52.7
87.8
2060
2084
2130
2230
2300
2330
2370
2480
48.0
65.4
63.1
4.1
1.1
6.4
2.4
11.9
11.0
6088
454
274
274
199
237
169
201
266
197
136
293
146
32.2
268
873
11.77
51.8
87.9
2036
2060
2100
2205
2295
2320
2355
2460
47.0
65,5
65.5
4.1
1.1
6.4
2.6
12.2
10.1
6332
513
307
307
200
243
169
201
297
196
136
298
150
30.0
268
827
13.46
49.9
87.8
1990
2016
2060
2150
2280
2310
2345
2445
47.0
68.1
65.4
4.1
1.1
6.4
2.2
9.2
11.6
6444
90
SHEET 68
-------
ALABAMA POWER COMPANY
BARRY J2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST DATA
BASELINE STUDY AFTER MODIFICATION
TEST HO.
DATE
TIME
UNIT LOAD - MW
FLOWS - 1Q3KG/HR
FEEDWATER
SH SPRAY [HEAT BALANCE)
MAIN STEAM
TUROINC LEAKAGE
RH EXTRACT
RH SPRAY (HEAT BALANCE)
RH FLOW (CALC.)
RH FLOW (TEST)
AIR & GAS FLOWS - I03(C/HR
GAS ENT. AH
GAS Lvc. AH
AIR ENT. AH
AIR Lvc. AH
AH LEAKAGE
UNIT ABSORPTION -
ECONOMIZER
FURNACE
- DRUM . DESH
DESH - SH OUT.
RH
TOTAL
PRESSURES
STEAM & WATER - KG/CM3
ECONOMIZER IN.
DRUM
SH - DESH IN.
SH OUT.
RH IN.
RH OUT.
AIR & GAS - CM. WB
FD FAN OUT.
"B" AH AIR OUT.
"B" AH GAS OUT.
"D" ELEV LEFT REAR FUEL AIR COMP
"A" ELEV. LEFT REAR FUEL AIR COMP.
LEFT MILL DUCT AT WINDBOX
MILL AIR DUCT AT "B" ELEV. MILL
JPPER FURNACE
TEMPERATURES - "C
S STEAM t WATER
n
^ SH OUT.
£ SH DESH IN
1
6/25/74
S 30
62
219
1.05
219
10 1
13.64
818
196
187
335
379
355
311
44.6
7.79
87 8
17.16
15.8
19.20
147.8
130.6
128.9
127 7
127
14.27
13.50
6.10
1.78
-10.67
1.27
1.91
508
.254
-1.27
482
390
2
6/25/74
4-25
62
212
.818
213
9.32
13.77
091
189
198
270
311
289
248
40.5
6.78
86.18
12.37
16.51
17.26
139.1
129.6
129.5
128.4
127.7
14.76
13.99
2.79
1.52
-11.68
1 27
.254
.254
-.254
-1.27
461
369
3
6/25/74
6:38
64
216
1.0
217
10.0
13.0
091
194
189
413
459
436
390
45.8
9.98
84.22
25.86
13.63
19.78
153.5
139.5
132.6
131.4
130.8
14.97
14.20
7.37
2.03
-16.26
1.27
.38
.508
0
-1.27
530
441
4
6/27/74
9-30
92
315
0
315
14 18
23.27
.318
278
279
398
459
427
366
60.9
8.59
122.19
26.69
23.49
26.13
207.1
132.1
132.9
131.1
130.1
22.29
21.02
4.83
1.02
-15.24
-1.27
1.52
0
-.762
-1.52
502
397
5
6/19/74
13:24
131
450
0
450
20.09
37.55
.182
393
393
593
737
691
547
144.0
18.60
160.95
SI. 66
25.45
36.19
292.9
137
134 9
132.0
130.1
32.13
30.58
13.21
5.08
-28.19
1.27
2.54
2.54
.762
-.508
516
433
6
6/27/74
11-18
127
441
.546
441
19.82
36.05
.591
38S
385
546
655
611
502
109.3
11.49
162.91
47.43
30.79
35.38
288.0
135.5
135.5
132.7
131.0
31.42
29.95
5.33
1.52
-24.64
.254
.508
0
-.762
-1.52
523
423
7
6/27/74
3-05
125
412
10.64
423
19.0
35.27
.364
369
371
559
657
616
518
97.6
12.57
150.89
50.85
26.79
34.90
276.0
135.9
136 1
133.9
132.1
30.23
28.82
13.46
4.57
-25.4
1.27
2.54
2.54
2.03
-.508
515
444
8
6/20/74
9-41
130
435
4.95
440
19.68
37.09
1.409
385
394
565
694
650
522
128.5
18.24
155.53
51.84
24.70
36.31
286.6
136.5
135.8
133
131.3
32.20
30.72
11.68
4.32
-28.45
1.27
2.03
2.03
.762
-1.27
510
438
9
6/20/74
12:25
129
446
.227
446
19.95
36.91
.591
390
389
542
670
624
497
127.7
14.94
158.18
51.23
27.67
35.00
287.0
136.2
135.5
132.5
130.8
31.78
30.23
8.89
2.54
-24.13
.508
1.016
.762
-.762
-1.27
523
433
JO
6/28/74
14:45
125
421
6.14
428
19.18
33.23
1.227
376
377
584
702
661
543
117.8
13.71
153.17
51.21
25.12
33.24
276.4
134.3
133.7
131.1
129.6
30. 72
29.24
12.70
5.08
-26.16
1.27
2.54
3.05
2.03
-.762
516
442
J2
6/26/74
1:23
65
244
1.91
246
12.27
18.55
2.364
218
194
363
425
399
337
61.9
5.09
98.36
22.5
19.38
23.13
168.5
129.6
135.5
134.2
133.4
15.54
14.55
3.05
1.52
-11.43
-1.27
-3.05
.508
0
-1.27
508
405
\Z
6/26/74
4:05
68
200
18.14
216
10.0
15.55
1.227
193
189
419
515
491
395
96.3
10.16
74.01
29.08
18.27
22.38
153.9
127.7
129.6
128.5
127.9
15.40
14.62
6.86
2.54
-16.51
.254
1.27
0
1.016
-1 52
524
479
11
6/28/74
11:25
126
423
8.46
432
19.27
33.09
.818
380
378
575
706
665
533
131.6
12.73
153.42
51.03
27.49
33.97
278.6
134.4
135.5
132.8
131.2
30.72
29.24
9.40
2.03
-26.16
.762
1.016
1.016
0
-1.52
518
441
12
6/28/74
9-20
125
421
4.0
425
19.0
33.55
.818
373
375
583
688
645
539
105.4
12.63
153.17
51.71
24.97
33.89
276.4
135
135.4
133.1
131.7
30.72
29.24
12.7
4.32
-26.16
1.27
2.54
3.05
1.78
-.762
522
444
-------
ALABAMA POWER Co-PAtjr
BARRY ire
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST DATA
BASELINE STUDY AFTER MODIFICATION
TEST NO.
TEMPERATURES - *C
STEAM t WATER
SH DESH OUT
RH OUT.
RH DESK IN
RH DESH OUT.
ECONOMIZER IN
ECONOMIZER OUT
#5 HP HEATER IN
IS HP HEATER OUT
15 HP HEATER EXT IN
#5 HP HEATER DRAIN
SPRAY WATER
AIR t GAS
AH GAS IN
AH GAS OUT
AH AIR IN
AH AIR OUT
FURNACE OUTLET (Ave )
AIR HEATER LEAKAGE - %
AH GAS SIDE EFFICIENCY - %
UNIT EFFICIENCY - £
PRODUCTS OF COMBUSTION - GR/lcfiCAL.
AH WT SIDE
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AH COLD SIDE
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
EXCESS AIR - f
AH IN.
AH OUT
FUEL ANALYSIS - %
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
MOISTURE
ASH
10
12
13
387
436
255
250
195
229
164
194
246
193
128
269
136
31.7
248
1010
13.34
50 7
88 4
1834
1858
1897
2OO2
2098
2125
2161
2269
33.5
52.7
60.7
4.3
.9
7 5
3.2
1O.1
13.3
368
401
232
232
194
224
163
194
227
193
130
262
142
29 4
248
1010
14.97
45 0
88 8
1563
1583
1625
1725
1818
1842
1880
1983
16.0
34.9
60 0
4.3
1.0
7.4
4.2
9.8
13.3
437
487
292
291
196
239
165
195
282
193
129
287
132
32.8
252
988
11 07
56 9
87 4
2191
2219
2250
2354
2448
2480
2507
261 5
64.7
84.1
61 3
4 4
1.0
7 5
3.2
7 7
14.9
399
455
283
282
214
240
180
214
277
211
143
290
144
42 2
261
1149
15 31
53 3
89.8
1566
1586
1625
1724
1826
1850
1886
1988
15.5
34.7
64 2
4.6
1.3
7.1
3.0
9.4
10.4
433
496
332
328
229
265
190
229
331
221
163
320
143
36.1
268
1238
24.30
54.0
88.4
1630
1652
1691
1789
2059
2086
2120
2223
21.0
52 8
63.5
4.2
1.1
5.7
2.4
10.9
12.2
422
495
330
328
231
254
193
231
324
226
158
314
149
44.4
268
1232
20.01
54 3
89 2
1533
1553
1593
1691
1867
1892
1927
2030
12.4
36.8
64.0
4.6
1.1
7.0
3.1
9.1
11.1
424
493
321
321
230
257
193
229
316
225
157
320
145
53 3
263
1182
17.45
60.1
89 5
1659
1680
1716
1814
1979
1997
2028
2131
25.4
49.1
62.9
4.5
1.0
6.9
3.0
9.3
12.4
430
493
329
322
228
265
189
228
323
226
163
322
144
34 4
270
- 1266
22.73
54.0
89.0
1598
1619
1659
1755
1992
2018
2O52
2154
17.8
46.8
63.3
4.3
1.1
6 2
1.9
9.1
14.1
432
495
333
331
238
268
194
232
329
227
165
320
151
42.2
273
1271
23.55
52 4
88.9
1519
1539
1580
1679
1909
1934
1970
2075
12.1
40 9
63 6
4 4
1.1
6.8
2.8
11.0
10.3
431
486
329
325
232
261
196
232
321
228
159
320
148
53.3
266
1199
20.17
57.8
89 5
1734
1757
1794
1890
2111
2138
2171
2271
26.6
54.1
68.4
4.9
1.1
7.9
2.9
5.2
9.6
400
466
278
265
205
224
163
200
268
194
126
273
138
40.5
253
1043
17 06
51.7
89.3
1763
1786
1822
1923
2087
2114
2146
2252
30.9
54.9
64.3
4.6
1.0
7.4
3.0
9.6
10 1
404
514
299
292
210
257
164
203
289
201
128
294
135
41.1
258
1049
22 97
55.2
88 0
2228
2256
2288
2395
2771
2807
2831
2946
63 1
102.9
64.7
4.6
.9
7.4
3.0
9.2
10 2
425
485
324
322
235
261
195
232
318
229
157
320
153
47.2
272
1238
22 91
53.0
89.0
1680
1702
1741
1839
2095
2122
2156
2255
22.0
52.1
64.9
4.4
1.1
6.4
1 5
6.5
15.2
436
494
331
328
233
259
194
231
323
228
156
322
147
51 1
265
1199
IB 09
58.7
89 4
1722
1744
1783
1885
2059
2085
2120
2226
25.9
50 5
63.3
4.5
1.0
7.3
3 1
9.9
10.9
HHV - CAL/G
6011
6106
6250
6478
6350
6406
6478
6311
6367
6783
6517
6467
6350
6311
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
TEST DATA
OVERFIRE AIR LOCATION, RATE & VELOCITY VARIATION
TEST NO.
Date
Time
Unit Load - NU
FLOWS - 103KG/HR
Feedwater
SH Spray (Heat Balance)
Main Steam
Turbine Leakage
RH Extract
RH Spray (Heat Balance)
RH Flow (Calc.)
RH Flow (Test)
AIR & GAS FLOHS - 103KG/HR
Gas Ent. AH
Gas Lvg. AH
Air Ent AH
Air Lvg. AH
AH Leakage
UNIT ABSORPTION - 106KG-CAL/HR
Economizer
Furnace
Drum - DESK
DESK - SH Out.
RH
Total
PRESSURES
STEAH & WATER - KG/CM2
Economizer In.
Drum
SH - DESK In.
SH Out.
RH In.
RH Out.
AIR i GAS - CM. KG
FD Fan Out.
"B" AH Air Out.
"B" AH Gas Out
11D" Elev. Left Rear Fuel Air Comp.
"A" Elev. Left Rear Fuel A1r Comp.
Left Mill Duct at Windbox
Mill Air Duct at "B" Elev. Mill
Upper Furnace
TEMPERATURES - "C
STEAM & WATER
SH Out.
SH OESH In.
15
16
17
18
19
20
21
22
23
7/10/74
0:00
97
336
.046
336
15.18
27.18
.682
295
299
458
509
477
426
51.2
9.88
127.89
34.62
20.92
25.93
219.2
133.5
132.6
130.7
129.6
23.76
22.50
7.11
4.57
-18.80
1.016
-3.05
3.81
2.29
-1.52
509
418
7/10/74
2:15
98
340
.682
340
15.31
27.41
2.409
300
300
447
501
470
415
54.7
7.23
131.64
34.37
21.24
27.44
221.9
133.3
133.3
131.3
130.2
23.83
22.57
6.35
2.03
-18.80
0
-3.05
1.52
.254
-1.52
502
416
7/10/74
4:00
100
338
.409
338
15.22
27.55
3.273
299
303
442
489
457
410
46.5
6.15
131.9
34.78
21.39
26.91
221.1
133.1
132.7
130.7
129.6
24.04
22.78
6.86
1.52
-18.29
-.254
-2.54
1.27
.254
-1.52
507
418
7/12/74
7:25
100
343
.909
344
15.5
28.09
.682
301
300
466
519
486
433
52.8
10.31
129.78
36.87
22.81
28.80
228.6
133.3
133.6
131.5
130.4
24.32
23.06
6.60
1.78
-19.30
-.762
-3.30
.508
-1.27
-1.52
518
424
7/11/74
4:35
100
325
13
338
15.23
26.14
1.14
298
295
468
S19
484
433
52.8
10.16
122.93
38.86
24.97
30.64
227.6
133.1
133.6
131.7
130.7
23.97
22.71
5.33
1.78
-19.81
-.762
-2.29
.762
-1.016
-1.52
514
440
7/11/74
23:10
100
337
6.95
344
15.5
25.18
.136
304
298
468
521
488
436
52.2
10.33
122.99
37.27
24.95
30.79
226.3
133.1
133.4
131.4
130.3
24.25
22.99
8.13
3.05
-19.56
-.254
1.78
2.03
.254
-1.52
518
429
7/12/74
1:24
102
330
11.5
342
15.4
24.86
0
301
297
476
526
493
443
50.1
10.53
124.49
39.56
26.06
32.05
232.7
133.2
133.1
131.3
130.1
24.46
23.20
9.40
3.56
-19.56
-3.56
.254
2.79
1.52
-1.52
523
440
7/12/74
3:30
102
326
15.55
341
15.4
24.36
0
302
299
494
550
515
460
55.7
10.61
122.75
40.24
25.60
31.55
230.7
133.1
133
131.2
130.1
24.46
23.20
6.60
2.03
-19.81
-3.05
1.27
.762
-1.52
-1.52
516
445
7/12/74
4:45
102
330
15.45
346
15.59
25.59
0
305
299
492
556
521
457
64.0
10.74
124.41
40.17
25.58
31.75
232.6
133.1
133.2
131.4
130.3
24.32
23.06
6.86
2.03
-19.81
-.762
3.56
2.03
-1.16
-1.52
512
443
93
SHEET 8A
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
TEST DATA
OVERFIRE AIR LOCATION, RATE & VELOCITY VARIATION
TEST NO.
TEMPERATURES - °C
STEAM 8 MATER
SH DESH Out.
RH Out.
RH OESH In.
RH DESH Out.
Economizer In.
Economizer Out.
05 HP Heater In.
#5 HP Heater Out.
#5 HP Heater Ext. In.
#5 HP Heater Drain
Spray Water
AIR & GAS
AH Gas In.
AH Gas Out.
AH Air In.
AH Air Out.
Furnace Outlet (Avg.)
Air Heater Leakage - %
AH Gas Side Efficiency - I
Unit Efficiency - %
15
16
17
18
19
20
21
22
23
PRODUCTS OF COMBUSTION
AH HOT SIDE
Dry Air
Wet Air
Dry Products
Met Products
AH COLD SIDE
Dry Air
Wet Air
Dry Products
Wet Products
EXCESS AIR - %
AH In.
AH Out.
FUEL ANALYSIS - %
Carbon
Hydrogen
Nitrogen
Oxygen
Sulfur
Moisture
Ash
HHV - CAL/G
- GR/106
'CAL.
420
458
298
295
220
247
180
218
293
215
143
300
141
47.2
260
1121
11.19
59.1
90.0
1725
1748
1787
1880
1933
1958
1994
2091
28.5
44.0
65.9
4.4
1.1
6.7
2.3
7.4
12.2
414
455
295
287
220
240
181
219
290
213
140
299
140
36.7
262
1099
12.24
56.3
89.8
1657
1679
1717
1806
1876
1900
1936
2028
27.1
43.8
66.6
4.4
1.1
6.8
2.1
6.7
12.3
418
457
302
292
220
237
181
220
295
213
140
301
139
35.0
262
1105
10.53
57.2
89.7
1644
1665
1704
1794
1830
1854
1891
1893
25.6
39.9
65.4
4.3
1.1
6.7
2.4
7.3
12.8
422
481
305
303
220
244
181
220
298
217
146
301
141
38.4
261
1132
11.32
57.0
89.6
1675
1697
1733
1828
1879
1904
1938
2034
26.6
42.1
65.2
4.5
1.4
6.1
3.0
8.0
11.8
6606
6844
6706
6711
410
492
304
302
219
244
182
220
298
215
145
302
139
31.7
263
1188
10.96
56.5
89.3
1677
1699
1739
1837
1876
1900
1938
2038
24.8
39.6
64.3
4.4
1.1
7.1
3.0
9.6
10.5
6483
414
492
304
304
220
249
183
219
298
216
148
301
142
43.9
261
1154
11.15
58.1
90.2
1679
1700
1737
1826
1880
1904
1938
2030
25.4
40.4
69.3
4.6
.9
5.6
2.1
5.8
11.7
6994
414
510
311
311
220
249
184
219
305
217
148
303
143
44.4
263
1221
10.53
58.3
90.1
1694
1716
1752
1843
1885
1910
1943
2037
25.4
39.5
67.5
4.6
1.1
5.9
2.1
5.4
13.4
6772
409
501
305
306
220
250
185
220
299
216
149
302
142
37.2
259
1216
11.25
56.6
89.0
1751
1774
1810
1908
1963
1989
2022
2123
27.9
43.4
65.4
4.6
1.4
6.1
2.5
7.8
12.2
6511
408
494
301
301
220
250
184
220
295
217
149
304
143
39.5
263
1199
13.01
56.3
89.1
1729
1751
1787
1884
1971
1996
2029
2129
28.1
46.0
66.0
4.6
1.4
6.2
2.6
7.9
11.3
6650
94
SHEET 8B
-------
ALABAMA POVEII COMPANY
SAURY K
TEST NO.
DATE
TIME
UNIT LOAD - HU
FLOWS .
FEEDVATER
SH SPRAY (HEAT BALANCE )
MAIN STREAM
TURBINE LEAKAGE
RH EXTRACT
RH SPRAY (HEAT BALANCE)
RH CLOW (CALC.)
HH FLOW (TEST)
AIB t GAS FLOWS - 10-Wm
GAS ENT. AH
GAS Lvo. AH
AIR ENT. AH
AIR Lvs. AH
AH LEAKAGE
UNIT ABSORPTION - 10SKG-CAL/HR
ECONOMIZER
FURNACE
DRUM - DESK
DESH - SH OUT.
RH
TOTAL
PRESSURES
STEAM I WATER - KG/CM2
ECONOMIZER IN.
DRUM
SH - DESH IN.
SH OUT.
RH IN.
RH OUT.
AIR t 6A3 - CM. WG
FD FAN OUT.
"B" AH Am OUT
"B" AH CAS OUT
"0" ELEV. LEFT REAR FUEL AIR COMP
"A" ELEV. LEFT REAR FUEL AIR COMP.
LEFT MILL DUCT AT WINDBOX
MILL AIR DUCT AT "B" ELEV. MILL
UPPER FURNACE
TLMPCRATURts - "C
STEAM 4 WATER
SH OUT
SH DCSH Id.
OVERFIRE AIR
24
25
26
7/2S/74
9-40
124
398
9.05
407
18.23
31.07
.909
358
355
548
597
559
509
49.7
12.93
145.13
55.72
87.64
35.51
276.9
133.6
133.9
131.3
130.2
29.67
28 26
10.67
3.56
-96.42
0
-2.54
2.03
1.27
-1.52
547
464
7/29/74
11-05
184
415
2 68
418
18.73
33.14
.364
367
363
5S6
631
589
534
65.2
12.82
152.59
52.09
25.20
34.27
276.4
134.5
133.9
131.8
130.5
30.23
29.82
10.67
3.05
-25.91
O
2.29
1.78
1.016
-I.S2
532
448
7/29/74
13:30
124
39?
21.09
412
18.5
30.73
.727
364
363
S85
653
610
548
68.4
12.98
142.53
55.44
29.69
37.58
278. a
133.4
133.7
131.2
129.7
29.88
28.47
10.92
4.32
-26.48
0
2.29
2.29
1.016
-1.016
535
474
TEST DATA
TILT VARIATION
C-E POWER SYSTEHS
FIELD TESTING AND
PERFORMANCE RESULTS
LOAD VARIATION AT OPTIMUM CONDITIONS
28
29
30
31
38
33
34
7/29/74
15-00
125
394
13.5
407
18.23
2.05
359
557
628
586
515
70.9
12.02
144.47
55.59
38.20
37.62
277.9
133.4
133.2
131.0
129.7
29.88
28.47
11.43
3.81
-26.48
0
2.03
2.03
2.03
-1.52
545
471
7/29/74
16:30
125
384
30.32
414
IB. 55
31.59
3.41
367
357
586
663
618
541
77.0
9.78
148.08
58.14
33.24
41.23
284.5
133.5
133
131.0
129.9
30.02
28.61
10.92
4.32
-26.67
O
8.03
2.03
1.79
-1.52
538
486
7/29/74
18-07
124
416
1.82
418
18.68
36.04
3.27
366
359
544
622
582
504
78.2
10.33
154.17
53 42
24.39
36.09
278.4
135.3
134.6
138.1
130.7
29. S8
28.47
11.68
4.0G
-26.48
.854
3.30
4.06
3.05
-1.27
536
451
7/30/74
21:05
125
399
17.77
416
18 64
31.5
0
366
353
574
624
532
532
49.9
8.62
150.04
57.86
32.10
41.83
290.4
134.2
134.6
132.7
131.7
29.95
28.54
8.89
2.03
-26.92
.508
.762
1.016
.508
-1.52
554
476
7/31/74
12-28
97
301
12.32
314
14.18
20.91
2.59
881
273
456
494
461
423
38.1
9.35
1)5.87
39.46
24.72
31.68
221.1
132.5
138.4
131.5
131.0
22.92
21.65
4.83
.768
-19.06
1.52
-.254
-.254
2.03
-1.52
539
457
7/31/74
2:35
65
200
4.05
204
10 45
10. '5
1.64
185
185
341
376
355
320
34.6
8.87
78.80
26.21
14.97
21.19
149.4
131.2
132.4
131.2
130.5
J5.04
14.27
4.32
1.016
-i4.ee
1.52
.254
.254
.762
-1.016
549
456
7/31/74
81-50
122
400
8.59
409
18.27
39.5
9.5
360
355
584
645
£02
541
61.6
4.21
151.80
55.72
26.51
39.99
278.2
134.7
134.6
132.8
130.8
29.24
27.84
10.92
4.32
-26.67
0
1.78
1.78
1.52
-1.52
548
467
7/31/74
23:35
95
305
5.05
310
14.0
23.82
3.41
276
275
472
538
504
437
66.7
3.70
120.61
37.78
80.80
28.68
211.0
132.7
132.7
131.3
130.4
22.64
21.37
4.32
.762
-18.54
3.81
O
.254
1.27
-1.27
589
446
B/1/74
1:38
64
802
1 27
8O4
9.41
13.23
1.86
183
187
329
370
349
308
41.1
5.44
81.14
83.79
13.81
19.81
144.0
131.7
132.2
131.2
T30.5
14.97
14.2
3.56
.508
-13.48
3.81
.254
.254
1.27
-1.27
533
438
-------
ALAOAMA POWER COMPANV
BARHY $3
C-E POWER SrsTCMS a
FIELD TESTING AND
PERFORMANCE RESULTS
TEST DATA
OVERFIRE AIR TILT VARIATION
LOAD VARIATION AT OPTIMUM CONDITIONS
TEST NO.
TEMPERATURES - "C
STEAM t WATER
SH DESK OUT.
RH Oui.
ftH DESH IN.
RH DESH OUT.
ECONOMIZER IN
ECONOMIZER OUT
15 HP HEATCR lit
K HP HEATER OUT.
15 HP HEATER EXT IN
#5 HP HEATER DRAIN
SPRAY WATER
AIR t CAS
AH GAS IH.
AH GAS OUT.
AH AIR In.
AH AIR OUT.
FURNACE OUTLET (Avo.)
AIR HEATER LEAKAGE - %
AH GAS SIDE EFFICIENCY - %
UNIT EFFICIENCY - %
PRODUCTS OF COH3USTION - CR/106CAL.
AH HOT SIDE
DRY AIR
WET AIR
Day PRODUCTS
WET PRODUCTS
AH COLO SIDE
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
excess AIR - %
AH IN.
AH OUT.
FUEL ANALYSIS - f
CARBON
HYDROGEN
NiTROOEN
OXYGEN
SUIFUR
MOISTURE
ASH
27
28
29
30
31
33
35
444
532
350
348
231
260
193
230
343
227
155
442
509
338
337
231
257
193
230
332
227
156
429
529
340
338
231
261
193
230
333
228
155
332
149
36.1
274
1238
9.07
57.4
89.6
320
147
37.8
272
1221
11.54
57.4
89.3
323
148
37.8
274
1293
11.70
57.3
88.9
§ HHV - CAL/G
1626
1647
1682
1774
1785
1808
1841
1934
S5.9
38 2
64 4
4.5
1 0
6.2
3.1
7.5
13.3
6811
1670
1692
1710
1827
1878
1902
1938
2038
23.7
39 1
63 5
4 4
1.2
6.1
3.4
8.7
12 7
6428
1708
1730
1768
1867
1924
1949
1984
2086
25.1
40 9
63.1
4 4
1 0
6.1
3.2
9.0
13.2
6317
441
543
356
349
230
258
193
230
347
227
151
421
548
350
340
232
255
193
832
341
226
148
448
516
343
334
232
254
191
231
333
227
151
438
554
381
346
230
249
194
232
353
225
144
423
529
327
317
214
243
182
216
320
210
136
438
528
317
307
197
235
169
196
305
192
123
448
526
349
322
237
245
IBS
234
331
227
147
432
497
315
302
222
233
T80
217
299
211
144
432
498
301
290
203
228
165
198
290
194
122
323
150
36.7
275
1232
12 75
55.8
89 3
326
151
30.6
276
1310
13.15
54.6
88.6
321
143
30.0
269
1188
14.37
55.9
89.4
322
146
25.0
274
1288
8.70
56.2
89.0
302
140
22.8
265
1233
8.38
54.9
89.1
287
129
25.0
257
116
10.14
56.5
89.2
323
149
33.9
273
1232
1O.56
56.4
89.0
302
144
33.3
267
1177
14.14
53.4
88.2
284
135
29.4
257
1054
12.49
54.0
89.0
1634
1656
1695
1789
1860
18B4
1920
2017
22 3
39.1
1664
1686
1728
1825
1901
1926
1965
2065
20.2
37.3
1599
1620
1659
1748
1847
1871
1907
1999
23.7
42.9
1610
1631
1669
1760
1761
1784
1820
1913
21 6
33.0
423
529
327
317
214
243
182
216
320
210
136
302
140
22. a
265
1233
8.38
54.9
89.1
1684
1705
1744
1837
1835
1859
1895
1991
25.2
3E.4
65.8
4.4
1 1
S.4
1.9
7.5
12.9
438
528
317
307
197
235
169
196
305
192
123
287
129
25.0
257
116
10.14
56.5
89.2
1885
1909
1943
2037
2089
2116
2147
2243
46.9
62.8
64 3
4.4
1.0
6.9
3.0
7.1
13 3
1708
1730
1769
1867
1903
1927
1964
2064
27.4
41.9
1804
1827
1868
1972
2079
2106
2143
2251
27.4
46.9
1880
1905
1939
2036
2131
2159
2191
2290
45 9
65.3
63.8
4 3
1.1
5.9
3.3
8.4
13.2
62.9
4.2
1.2
5.7
3.5
8.7
13 8
64.5
4.2
1 0
5.8
3.3
8.1
13 1
65.2
4.4
1.0
E.3
2.3
7.1
13.7
65.8
4.4
1 1
S.4
1.9
7.5
12.9
64 3
4.4
1.0
6.9
3.0
7.1
13 3
64.3
4 4
9
6.9
3.2
9.6
10.7
64.0
4.4
1.1
S.9
2.9
9.7
11 0
65 0
4.4
1.0
6.9
2.9
9.6
10.2
6500
6189
6750
6644
6589
6794
6517
6133
£833
-------
ALABAMA POWER COMPANY
BARRY |2
BASELINE STUDY
BOARD DATA
C-E POWER SYSTEMS
FIELD TESTING AMD
PERFORMANCE RESULTS
TEST No.
DATE
TIME
LOAD . W
FLOWS - lO^BS/HR
BFP 2A
BFP SB
BFP 2C
REHEAT STEAM
CONOENSATE
SUPERHEAT SPRAY
REHEAT SPRAY
FEEDWATER
PRIMARY STEAM FLOW
AIR FLOW - RELATIVE
PRESSURES
STEAM & WATER - P5IG
IST STAGE EXTRACTION
STH
I2TH
1BTH
19TH (-IN. He + PSIG)
21ST (IN. He)
FEEDWATER PECULATOR INLET
FEEOWATER
DRUM
TURBINE THROTTLE
REHEAT INLET
REHEAT BOWL
EXHAUST (IN. He)
MAIN STEAM
REHEAT OUTLET
LIGHT OIL UPPER BURNERS
LIGHT OIL LOWER BURNERS
AIR t GAS - IN. We
2A FD FAN DISCHARGE
2B FD FAN DISCHARGE
2A PRCHEATER OUTLET AIR
SB PRCHCATCR OUTLET AIR
FURNACE PRESSURE
SUPERHEATER CAVITY
ECON INLET
ECONOMIZER OUTLET R.H.
ECONOMIZER OUTLET L.H.
No. 2A PRCHEATER Dirr. GAS
No. 28 PREHEATED Dirr GAS
No. 2A I D. FAN SUCTION
No. 28 1.0. FAN SUCTION
PULVERIZER 2A INLET AIR
EXHAUSTER 2A DISCHARGE
PULVERIZER 26 INLET AIR
EXHAUSTER 2B DISCHARGE
PULVERIZER 2C INLET AIR
EXHAUSTER 2C DISCHARGE
PULVERIZER 20 IHLET AIR
EXHAUSTER 20 DISCHARGE
10
13
11-30-73
01:55
66
0
260
260
630
300
0
0
370
450
470
680
212
78
23
-9
-20
1950
1890
1890
1825
200
194
-29 0
1850
200
0
0
1.8
1.2
.7
.8
-.5
1.0
-2.7
-3.7
-3.5
1.9
1.6
-6.4
-6.2
-1.5
13.2
-1.6
12.7
-2.0
12.5
-1.1
0
11-30-73
00-00
65
0
280
2SO
632
305
0
0
40O
460
400
700
218
BO
24
-9
-20
I960
190O
1900
1825
205
195
-29.0
1850
209
0
0
1.5
1.0
.7
.8
-.5
-.9
-2.2
-3.2
-3.0
1.6
1 2
-5.6
-5.0
-1.5
13.4
-1.7
12.9
-2 0
12.5
-1 2
0
1 1 -30-73
02 45
67
0
284
278
640
300
12.5
0
350
450
580
680
214
79
24
-9
-20
1950
1900
1900
1825
200
195
-29.0
1850
200
0
0
1.9
1.5
.5
.5
-5
-1.0
-3.4
-4 5
-4.4
2.4
2.0
-8.1
-8.2
-1.5
13.3
-1.7
12.8
-2.0
12.5
-1 1
0
1-18-74
16-00
93
0
350
400
775
470
3 0
0
660
680
690
1000
318
123
39
0
-15 2
1990
1910
1900
1830
308
286
-28.4
1850
297
0
O
2.1
2.0
.8
.8
-.45
-1.0
-2.4
-4.4
-4.2
2 6
1.9
-8.2
-8.O
-1.3
12.0
-1.3
13 2
-1.5
12 5
-1.2
0
11-14-73
15:10
184
0
475
480
865
600
6.0
0
880
900
830
1320
418
166
54
6.0
-13.3
2020
1950
1940
1825
410
380
-28.5
1850
385
0
0
4.5
4.0
1.5
1.5
-0.5
-1.4
-5.5
-6.75
-6.80
4.0
3.5
-13 8
-13.8
-1.3
14.3
-1.4
13.0
-1.8
12.0
-2.4
10.5
11-28-73
13:21
123
0
475
485
865
600
4.0
0
BOO
900
750
1310
415
165
54
6.0
-13.0
2010
1950
1920
182O
410
377
-27. B
1850
390
0
O
3.0
2.8
.5
.B
-.48
-1.5
-4.8
-6.2
-6.2
3.5
3.1
-12.0
-12.2
-1.4
12.8
-1.7
12.2
-1.5
12.O
-2.4
12.0
11-28-73
10:37
123
0
480
480
860
600
21.5
0
730
900
950
1310
415
165
54
6.0
-13.0
2005
1950
1940
1820
408
375
-28.0
1840
388
0
0
6.8
6.0
2.5
2.5
-0.5
-1.4
-5.4
-7.2
-7.4
4.2
3.9
-15.0
-14.8
-1.1
13.5
-1.5
13.0
-1.0
12.0
-1.8
10.2
11-15-73
irio
126
0
460
480
880
600
17.8
0
780
905
823
1340
422
170
56
6.4
-13.0
2020
1950
1940
1825
418
386
-28.4
1850
398
0
0
4.2
4.0
1.5
1.5
-.45
-1.4
-5.6
-6.8
-7.0
3.9
3.5
-13.6
-13.8
-1.2
11.5
-1.4
11.5
-1.8
12.1
-2.3
11.8
11-19-73
13-04
122
0
480
470
870
599
17.5
0
780
885
750
1310
410
165
54
6.0
-13.0
2005
1950
1940
1820
405
375
-28.0
1850
385
0
0
4.1
4.0
0.9
1.0
-5
-1.5
-5.4
-6.7
-6.7
3.6
3.2
-12.5
-13.0
-1.4
12 5
-1.6
12 2
-I 8
12.5
-2.4
12.0
11-19-73
10:00
124
0
480
480
880
600
31
0
780
900
925
1310
415
165
54
6.0
-13.0
2005
1950
1940
1820
409
376
-28.1
1850
388
0
0
6.0
5.2
2.5
2.5
-.OS
-1.4
-6.1
-7.4
-7.0
4.3
3.7
-15.0
-14.5
-1.2
13.5
-1.4
13.0
-1.5
12.5
-2.0
13.0
12-5-73
01:40
66
0
460
0
635
300
2.2
0
370
447
450
665
210
77
21.5
-8.5
-20.0
1930
1890
1900
1825
197
198
-SB. 4
1850
200
26
26
1.5
1.1
.7
.8
5
-1.0
-2.6
-3.5
-3.3
1.9
1.3
-6.0
-5.8
-1.2
12.3
-1.6
12.8
-2.4
12.0
-1 2
0
12-4-73
23-30
74
0
460
0
635
300
2.3
0
330
445
550
775
211
77
23
-8.5
-20.0
1940
1900
1900
1825
200
190
-28.4
1850
200
26
26
1.5
1.2
.4
.5
-.5
-1.1
-3.2
-4.1
-4.0
2.3
1.8
-7.6
-7.2
-1.4
12.4
-1.8
12.7
-2 3
12.1
-1.2
0
11-16-73
14:20
125
0
460
480
880
600
35
0
780
901
850
1330
420
169
56
6.6
-13.0
2020
1950
1940
1820
415
382
-28.1
1850
397
0
0
4.9
4.2
1.5
1.5
-.50
-1.7
-6.0
-7.5
-7.7
4.1
3.6
14.5
14.5
-1.3
13.5
-1.4
12 8
-1.8
12.2
-2.4
12.0
11-16-73
9:50
125
0
4G8
490
870
600
36
0
760
901
895
1330
420
169
56
6.4
-13.0
2015
1950
1940
1820
415
382
-28.1
1850
395
0
0
5.8
5.2
2.2
2.2
-.35
-1.5
-5.9
-7.5
-7.6
4.2
3.8
15.0
14.8
-1.2
13.7
-1.4
13.2
-1 7
12.2
-2.O
12.2
-------
ALABAMA POWER COMPANY
BARRY J2
BASELINE STUDY
BOARD DATA
C-E POWER SVSTCMS
FIELD TEST me ANO
PERFORMANCE RESULTS
TESI No.
TEMPERATURES
AIR 4 GAS - °F
BOILER OUTLET GAS L.H.
BOILER OUTLET GAS R.H
ECONOMIZER OUT GAS L H
ECONOMIZER OUT GAS R.H
PREHEATCR 2A OUTLET GAS
PREHCATCR SB OUTLET GAS
PRCHEATCR 2A INLET AIR
PREHEATER 2B INLET AIR
PREHEATCR 2A OUTLET AIR
PREHEATCR 26 OUTLET AIR
PULVERIZER 2A IHIET AIR
PULVERIZER 2A INTERNAL
PULVERIZER SB INLET AIR
PULVERIZER SB INTERNAL
PULVERIZER 2C INLET AIR
PULVERIZER 2C INTERNAL
PULVERIZER SO INLET AIR
PULVERIZER SO INTERNAL
TEMPERATURES
13
STEAM & WATER - °F
FCCDWATCR
ECONOMIZER WATER OUTLET - L H
ECONOMIZER WATER OUTLET - R H
RH DCSUPH IN L H
RH DESUPH OUT L H
RH DCSUPH. IN R.H.
'H DCSUPH OUT R H.
SUPERHEAT OUT L H
SUPERHEAT OUT.R.H.
THROTTLE STEAM L H.
THROTTLE STEAM R.H
REHEAT OUTLET L.H
REHEAT OUTLET R.H.
SUPERHEATER OUTLET
RCHEATER OUTLET
UPPCR VALVC CHEST
LOWER VALVE CHEST
H P. EXHAUST
REHEAT BOWL
IK
CONDCNSATC TEMP.
S.H DESUPH. IN L H
S H DCSUPH OUT L H
S H DCSUPH IN R.H
S.H. DCSUPH OUT R.H
MISCELLANEOUS
I DFAN 2A RPM
I D FAN SB RPM
F D FAN 2A RPM
F 0. FAN SB RPM
FAN DAMPER POSITION - (0-12)
ID FAN 2A
ID FAN SB
ro FAN 2A
FD FAN 2B
527
638
546
547
30O
299
80
90
5O2
5O5
46O
I4O
462
ISO
455
165
80
80
619
631
532
529
323
294
75
90
500
495
460
140
460
159
441
159
70
70
541
552
569
570
292
289
71
79
511
511
463
143
462
159
458
158
80
80
S32
643
575
570
320
991
108
102
517
505
470
155
475
140
460
140
110
110
660
671
620
62?
318
311
102
108
538
530
479
150
482
150
470
160
480
159
661
670
619
618
311
310
92
90
540
540
48O
142
480
160
483
140
490
135
678
681
640
632
298
300
120
128
525
528
460
160
465
160
470
ISO
480
158
662
672
622
622
311
311
100
99
539
535
472
145
480
160
479
160
485
155
656
662
613
6!1
320
318
94
98
540
537
480
142
483
150
480
141
490
14O
669
678
632
625
302
305
102
109
529
529
460
159
462
160
475
160
485
150
621
632
540
531
313
291
92
90
502
499
460
158
465
150
440
ISO
90
90
631
645
558
555
310
289
87
81
511
508
480
141
495
150
445
142
90
90
667
678
632
628
315
315
100
100
54O
539
480
142
495
155
4B5
150
495
138
669
679
635
630
308
308
100
1OO
532
532
465
159
472
159
422
16O
490
159
412
452
455
565
565
565
565
980
979
975
975
9O2
679
967
900
958
89
551
901
429
95
BOO
782
795
789
420
420
360
340
B 0
8 4
3.2
3 2
412
445
446
502
502
502
502
917
920
920
920
821
809
911
829
900
85
501
835
376
95
740
730
738
734
400
400
340
340
4 8
5 .1
2 5
Z 6
412
470
470
580
580
580
580
1020
1003
1008
10O7
951
930
998
948
978
90
578
938
458
95
878
811
879
826
480
480
365
380
6.0
S 4
3.8
3 8
447
468
4G8
535
332
535
535
950
938
940
938
862
848
899
831
899
101
531
845
370
107
771
762
770
762
460
480
440
450
5.6
5 6
4 0
4.0
470
492
495
632
632
631
631
992
991
986
986
932
946
975
940
917
101
632
941
452
110
846
838
856
839
660
660
510
547
12.0
12.0
11.6
11.6
465
491
492
639
639
639
639
999
999
992
990
970
930
972
959
970
95
639
949
461
115
849
833
840
815
6OO
600
44O
450
7.4
7.4
5.6
6.0
465
500
500
637
637
637
637
989
999
989
989
972
922
975
964
969
99
638
950
461
115
891
852
B77
812
680
6 BO
660
650
11.4
11.2
10.9
10.9
4.70
497
499
660
660
659
659
1021
1000
1005
1005
980
979
1003
985
990
100
659
980
483
110
870
821
878
839
660
660
505
540
12.0
12. 0
11.6
11.6
469
490
490
628
628
628
628
981
979
980
980
948
898
965
938
962
100
628
931
445
112
865
823
831
791
620
640
450
460
12.0
12 0
5.8
6 0
470
500
500
649
646
646
646
997
1008
998
998
982
941
989
976
988
98
649
970
475
110
911
836
8S9
801
683
680
600
600
12.0
12.0
11.6
11.6
412
450
449
532
532
533
532
960
951
951
951
888
832
935
874
940
99
535
879
409
96
775
765
765
755
430
420
330
320
5.6
5.7
3.2
3.2
414
461
4SO
578
578
578
578
1013
1006
1003
1005
939
905
990
932
984
100
580
927
450
9E
834
819
829
820
480
4BO
370
380
6 5
6 3
3 4
3.4
470
500
500
640
64O
64O
64O
995
999
990
990
959
965
9BO
960
971
100
640
960
470
115
900
822
895
808
680
680
540
540
12. 0
13.0
11.6
11.6
470
500
50?
650
650
648
648
1002
1004
999
999
978
926
989
975
9BO
98
649
972
480
110
900
832
904
820
670
680
590
582
12. 0
12.0
11.6
11.6
DRUM LEVEL Irj. - KOHM
LEVEL
-2.0
-0.8
-1 0
-1.0
-O.B
-0.5
-2.5
-1.0
-0.25
-0 25
-------
ALABAMA POWER COMPANY
BARRY #2
BASELINE STUDY
BOARD DATA
C-E POWER SYSTEMS
FIELD TESTING AMD
PERFORMANCE RESULTS
TEST No.
13
EXHAUSTER DAMPER POSITION - % OPEH
0-18 SCALE
MILL 2A
MILL SB
MILL 2C
MILL 2D
PULVERIZER FEEDER CAP - jt OPEH
0 - 12 SCALE
MILL 2A
MILL SB
MILL 2C
MILL 80
SPRAT VALVE POSITIONS - % OPEN
SH SPRAT L
SH SPRAY R
RH SPRAY L
RH SPRAY R
BURNER TILT POSITION - DEGREES
TJ5
RR
LF
RF
FEEDWATER VALVE - % OPEN (0-12 SCALE)
AIR HTR. 2A RECIRC. DAMPER - % OPEN
AIR HTR. 2B RECIRC. DAMPER - £ OPEN
40
38
32
0
11 4
11.0
11.5
O
40
39
33
O
11 2
11.6
11.5
O
44
42
42
43
6.0
6.O
4.4
5 9
38
40
42
41
6.0
5.6
B.2
5.8
40
42
39
42
8.0
8.1
5.8
5.8
39
44
40
42
8 0
8.0
5.8
5.8
4.3
3.8
3.0
0
16
16
0
0
42
46
46
46
8.1
37
50
4.4
3.7
3.0
0
0
0
0
0
42
413
413
413
8.1
38
51
4.4
3.7
3.0
0
39
39
0
0
42
46
46
46
8.1
39
50
5.7
5.7
5.6
0
0
0
0
0
0
+8
410
410
8.0
39
52
5.5
5.4
5.4
4.5
29
0
0
0
43.5
+2.0
45.0
43.0
12.0
31
38
4.4
3.9
4.1
5.0
30
O
O
O
44
44
44
44
11.4
44
43
4.6
4.0
4.4
5.1
48
32
0
0
44
+4
44
44
11.4
40
42
5.3
5.1
5.5
5.6
40
40
0
0
410
45
410
47
12.0
34
36
5.1
4.5
5.8
6.0
44
36
0
0
-22
-X
-22
-22
12
32
36
5.2
4.6
5.8
6.0
68
52
0
0
-22
-22
-22
-22
12
32
27
4.7
4.3
2 6
0
0
0
0
0
-9
-9
-9
-10
12
35
36
4.5
3.7
3.4
0
16
16
0
O
42
44
44
44
12
35
36
5.2
5.2
5.8
6.0
66
54
0
0
-22
-22
-22
-22
9.8
34
36
5.3
5.2
5.6
6.0
72
56
0
0
-22
-22
-22
-22
9.8
34
36
-------
ALABAMA POWER COMPANY
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING STUDY
BOARD DATA
Test No.
Date
Time
Load - MW
Flows - 103LBS/HR
BFP ZA
BFP 2B
BFP 2C
Reheat Steam
Condensate
Superheat Spray
Reheat Spray
Feedwater
Primary Steam Flow
Air Flow - Relative
PRESSURES
Steam t Hater - P5IG
1st Stage Extraction
8th
12th
16th
19th (-In. Hg- + PSIG)
21st (In. Hg)
Feedwater Regulator Inlet
Feedwater
Drum
Turbine Throttle
Reheat Inlet
Reheat Bowl
Exhaust (In. Hg)
Main Steam
Reheat Outlet
Light Oil Upper Burners
Light Oil Lower Burners
PRESSURES
Air S Gas - In Mg
ZA FD Fan Discharge
2B FD Fan discharge
2A Preheater Outlet A1r
2B Preheater Outlet Air
Furnace Pressure
Superheater Cavity
Econ. Inlet
Economizer Outlet R.H.
Economizer Outlet L.H.
Ho. 2A Preheater Oiff. Gas
No. 2B Preheater Dlff. Gas
No. 2A I.D. Fan Suction
No. 2B I.D Fan Suction
15
16
17
18
19
20
21
23
24
1-19-74
09:10
66
0
220
230
635
330
3.1
0
390
450
580
1680
210
75
21
-11.5
-21.0
2045
1890
1890
1845
199
188
-29.4
1850
200
26
26
1.2
0.8
- 5
- 2
-.45
-1.0
-3.0
-4.0
-4.0
2 2
2.0
-7.2
-7.2
1-18-74
18:24
96
0
324
382
770
460
10.0
0
660
675
750
1000
315
122
39
0.0
-15.2
2000
1920
1915
1830
308
286
-28.5
1850
297
0
0
3.0
3 0
1.0
1.0
-.5
-1.3
-4.2
-5.4
-5.3
3.2
2.4
-10.5
-10.0
12-3-73
11:07
100
0
360
384
770
470
17.5
0
600
690
700
1020
322
125
40
0.0
-16.0
1960
1910
1900
1810
317
294
-28.1
1840
305
0
0
3.2
2.9
1.0
1.0
-.47
-1.3
-4.1
-5.3
-5.3
2.9
2.6
-10.0
-10.0
12-4-73
01:30
103
0
360
385
790
470
17.5
0
600
700
705
1040
328
128
40
0.0
-16.0
1980
1920
1920
1825
321
300
-28. 2
1850
310
0
0
3 1
2.8
1.0
1 0
-.5
-1.4
-4.3
-5.5
-5.4
3.0
2.7
-10.2
-10 5
12-5-73
23:50
99
0
360
403
770
470
4.9
0
690
660
1020
320
125
38.5
0.0
-16.0
1975
1910
1910
1825
316
291
-28.4
1850
301
26
26
2.0
1.8
4
4
-.48
-1.3
-4.0
-5.0
-5.0
2.8
2.3
-9.1
-9.5
12-6-73
02:30
102
0
360
403
770
460
8.3
0
690
705
1030
320
125
39.5
0.0
-16.2
2000
1925
1925
1830
317
293
-28.4
1850
302
26
26
2.5
2.5
.6
.7
-.5
-1.3
-4.2
-5.3
-5.3
2.9
2.4
-9.8
-10 0
1-18-74
20:30
94
0
350
400
760
460
3.0
0
660
675
750
1000
315
120
37.0
0.0
-15.2
1980
1910
1910
1830
308
286
-28.5
1850
297
0
0
3.2
3.0
1.2
1.2
- 4
-1.2
-4.0
-5.2
-5.2
3.2
2.4
-10.1
-9.8
1-19-74
15:45
64
0
240
210
650
340
2.9
0
440
450
580
680
213
76
20.0
-11.0
-20.5
2050
1890
1900
1840
200
193
-29.0
1850
200
26
26
1.2
0.8
- 5
- 2
-.45
-1.0
-3 0
-4.0
3.8
2 3
1 9
-7.1
-7.2
1-19-74
13 30
64
0
250
200
640
341
2.5
0
440
450
590
670
212
77
20.5
-10.5
-20.2
2035
1895
1900
1845
201
190
-29 0
1850
200
26
26
1.2
0.8
-.5
- 2
-.5
-1.0
-3.0
-4.0
-3.9
2.3
1.9
-7.1
-7 1
1-19-74
11:30
166
0
240
210
640
325
10.0
0
400
442
575
670
210
76
20.5
-11.0
-21.0
2025
1890
1900
1835
199
190
-29.2
1850
200
26
26
1.2
0.8
-.5
-.2
-.4
-1.0
-3.1
-4.0
-4.0
2.3
1 9
-7.1
-7.1
100
SHEET 10A
-------
ALABAMA POWER COMPANY
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING STUDY
Test No.
PRESSURES (Confd)
Air & Gas - In. Hg
Pulverizer 2A Inlet Air
Exhauster 2A Discharge
Pulverizer 2B Inlet Air
Exhauster 2B Discharge
Pulverizer 2C Inlet Air
Exhauster 2C Discharge
Pulverizer 2D Inlet Air
Exhauster 20 Discharge
TEMPERATURES
BOARD DATA
15 16 17 18 19
20
21
22
23
24
Air g Gas - °F
Boiler Outlet Gas L.H.
Boiler Outlet Gas R.H.
Economizer Out Gas L.H.
Economizer Out Gas R.H.
Preheater 2A Outlet Gas
Preheater 2B Outlet Gas
Preheater 2A Inlet Air
Preheater 2B Inlet A1r
Preheater 2A Outlet Air
Preheater 2B Outlet Air
Pulverizer 2A Inlet Air
Pulverizer 2A Internal
Pulverizer 2B Inlet Air
Pulverizer 2B Internal
Pulverizer 2C Inlet Air
Pulverizer 2C Internal
Pulverizer 20 Inlet Air
Pulverizer 2D Internal
TEMPERATURES
Steam 8 Vfater - °F
Feedwater
Economizer Mater Outlet - L.H.
Economizer Water Outlet - R.H.
RH Oesuph. In L.H.
RH Desuph. Out L.H.
RH Desuph. In R.H.
RH Oesuph. Out R.H.
Superheat Out L.H.
Superheat Out R.H.
Throttle Steam L.H.
Throttle Steam R.H.
Reheat Outlet L.H.
Reheat Outlet R.H.
Superheater Outlet
Reheater Outlet
Upper Valve Chest
Lower Valve Chest
H.P. Exhaust
Reheat Bowl
Intermediate Exhaust
Condensate Temp.
-1.5
11.5
-1.4
11.2
-2.0
10.9
-1.2
0
640
651
569
573
301
301
81
79
511
519
465
145
465
140
445
175
89
89
388
462
466
574
574
574
574
1000
1008
998
998
886
941
990
913
975
100
568
918
440
95
-1.2
12.0
-1.0
13.2
-1.0
12.0
-1.2
0
649
660
598
591
312
285
109
102
520
503
478
160
480
160
462
162
95
95
445
480
480
596
596
596
596
986
998
985
985
901
961
979
930
965
101
595
937
451
105
-1.0
12.0
-1.5
13.0
-1.2
12.5
-1.2
0
642
659
591
590
297
297
99
98
517
520
480
138
480
145
480
122
105
105
445
478
480
585
585
585
585
978
970
970
970
920
885
955
920
952
100
589
918
435
107
-.8
13.0
-1.4
12.8
-.9
0
-1.6
12.0
649
661
595
594
300
300
99
93
520
522
484
142
483
144
100
100
490
152
449
480
481
609
609
609
609
1006
992
995
995
955
909
980
950
971
101
609
937
455
106
-1.4
13.0
-.75
0
-1.5
12.9
-2.5
12.8
639
650
579
578
290
290
71
69
512
518
480
137
100
100
475
130
479
125
442
471
473
577
577
577
577
967
969
965
962
900
861
951
895
939
94
578
885
418
104
-.7
0
-1.4
12.9
-1.2
12.1
-1.8
11.9
645
658
589
585
288
278
62
62
519
515
480
80
482
162
479
145
480
143
445
479
479
611
611
611
611
996
1009
1000
1000
955
904
990
950
1019
90
632
975
470
103
-.7
0
-1.3
13.2
-1.0
12.3
-2.0
10.5
646
650
590
580
310
278
108
102
515
495
110
110
478
155
460
160
460
142
425
472
472
551
551
551
551
941
937
938
938
849
867
981
866
921
101
555
870
401
106
-.7
0
-2.0
12.0
-1.5
12.0
-2.3
10.0
637
640
561
561
298
302
85
85
502
510
110
110
460
150
460
160
470
180
412
457
456
505
505
505
505
928
921
927
920
819
828
910
879
900
101
500
830
378
97
-1.5
10.5
-.7
0
-1.5
11.5
-2.0
10.0
637
642
561
561
298
300
86
85
505
510
460
145
no
110
480
155
470
140
413
458
451
515
515
515
515
939
930
930
930
829
841
923
840
908
100
509
840
385
97
-1.4
11.5
-1.5
11.5
-0.8
0
-2.8
8.8
646
651
571
572
302
302
82
81
515
519
478
140
465
140
95
95
460
165
413
468
468
575
575
575
575
1000
998
998
998
922
946
987
942
976
100
568
932
458
95
101
SHEET 10B
-------
ALAPAMA POWCR COMPANY
HARRT IP
C-E POWER SYSTEMS
FIELD TESTING AND
RESULTS
BIASED FIRING STUDY
Test No
S II Desuph in L H.
S II nosuph Out L.H
S N Ocsuph in R.ll
S II Ocsuph Out R H
MSCCLLANEOUS
'
1 D r,in 28 RPM
r P Fan 2A RPM
r D Fan 20 RPM
Fan Damper Position - (0-12)
-"
ID Tan 20
FD Fan 2K
TO fun 2B
Drum Level In - Nonn. H.O Level
A Mi 1 1 AMPS
D Mill AMPS
C Mi 1 1 AMPS
D 111 1 1 AMPS
ft
Exhauster Oam|
T2EFull Sea
Mill 2A
Mill 2B
Mill 2C
Mill 20
Pulverizer Feeder Cap -
T2Q1' Full Scale
Mill 2A
Mill 2B
Mill 2C
Mill 20
r Position - 7, Open
Spray Valve Positions - ", Open
SH Spray L
SH Spray R
RH Spray L
RH Spray R
Burner Tilt Positions - Degrees
CR
RR
LF
RF
Feedt/ater Valve - ' Open (0-12 Scale)
Air Mtr 2A Reel re. Damper - ". Open
Air Htr 2B Reel re. Damper - '. Open
15
BOARD DATA
16
17
18
19
20
21
22
23
24
845
828
864
851
420
470
360
340
5.4
5 8
3.7
3.8
-0 5
35
36
26
0
52
54
32
0
52
52
20
0
0
0
0
0
-10
-13
-11
-10
7.3
39
32
811
800
855
820
540
540
530
535
6 2
6.0
5.0
4.8
-0.5
36
35
38
0
56
80
57
0
56
56
55
0
40
40
0
0
0
+1
0
-1
12 0
39
41
848
797
840
792
550
560
430
440
7.7
7.8
6.8
6 8
-2.5
46
39
46
0
56
78
80
0
57
47
56
0
47
41
0
0
-18
-18
-18
-18
12 0
32
34
870
816
858
809
560
560
430
440
7 6
7.8
6.8
6.8
-1.0
46
42
0
43
80
82
0
63
64
58
0
64
47
41
0
0
-9
-10
-10
-10
12 0
32
31
809
796
799
770
520
520
380
380
7 8
7.8
4.3
4.1
-2 0
42
0
42
44
82
0
80
83
54
0
52
54
37
17
0
0
-9
-9
-9
-10
12.0
44
42
850
830
331
788
540
540
410
420
7 9
7.9
4.5
4.4
-1.0
0
42
42
44
0
79
56
54
0
50
54
55
40
20
0
0
-2
-2
-2
-2
8.4
20
20
800
789
974
786
520
530
530
535
6.0
5.8
4.8
4.6
-0.6
0
36
38
39
0
78
53
49
0
54
53
50
0
0
0
0
0
+8
tlO
+10
12.0
37
40
805
790
795
790
430
490
370
340
5.2
5.2
3.8
3.5
-0.5
0
31
35
36
0
60
50
49
0
35
49
50
0
0
0
0
0
0
0
0
7.8
37
32
805
790
800
791
420
470
370
350
5.2
5.8
3 9
3.7
-0.6
32
0
35
37
58
0
41
42
38
0
50
52
0
0
0
0
0
0
0
0
7 9
38
32
876
809
872
821
420
470
360
340
5.4
5 8
3 7
3 7
-0 8
36
37
0
26
50
52
0
28
50
50
0
20
34
35
0
0
-18
-19
-17
-16
a.o
39
32
lop
SHFCT IOC
-------
ALABAMA POWER COMPANY
BARRY £2
BOARD DATA
BASELINE STUDY AFTER MODIFICATION
C-C POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO
DATE
TIME
LOAD - KM
FLOWS - lO^BS/HR
BFP 2A
BFP 2B
BFP 2C
REHEAT STEAM
CONOENSATE
SUPERHEAT SPRAY
REHEAT SPRAY
FEEOWATER
PRIMARY STEAM FLOW
AIR FLOW - RELATIVE
PRESSURES
STEAM i WATER - PS 1C
IST STAGE EXTRACTION
BTH
12TH
16TH
19TH (-IN. He + PS1G)
21ST (IN. He)
FEEOWATER REGULATOR INLET
FEEDWATER
DRUM
TURBINE THROTTLE
REHEAT INLET
REHEAT BOWL
EXHAUST (in. He)
MAIN STEAM
REHEAT OUTLET
LIGHT OIL UPPER BURNERS
LIGHT OIL LOVER BURNERS
JO
J2
JJ
IS
PRESSURES
AIR t GAS -
M. We
2A FTJ FAN DISCHARGE
SB FD TAN DISCHARGE
2A PREHEATER OUTLET AIR
SB PREHEATER OUTLET AIR
FURNACE PRESSURE
SUPERHEATER CAVITY
ECON. INLET
ECONOMIZER OUTLET R.H.
ECONOMIZER OUTLET L.H.
No. 2A PREHEATCR Dirr. Gis
No. SB PREHEATCR Dirr
No 2A I.D. FAN SUCTION
No SB I.D. FAN SUCTION
PULVERIZER 2A INLET AIR
EXHAUSTER 2A DISCHARGE
PULVERIZER SB INLET AIR
CXHUASTCR 28 DISCHARGE
PULVERIZER 2C INLET AIR
EXHAUSTER 2C DISCHARGE
PULVERIZER 20 INLET AIR
EXHAUSTER 20 DISCHARGE
GAS
6/25/74
2-30
62
0
600 TO 520
0
642
320
29.0
0.0
440
440
460
650
210
75
20
-12
-20 0
1950
1870
1870
1825
200
197
-27.6
1840
195
24.0
25.2
2.0
1 5
1.0
1 0
-.45
- 8
-2.5
-3.4
-3.3
2.0
1.2
6 2
5.2
-1.2
10 7
-1.2
10 2
-3 5
10 5
-1.2
0
6/25/74
4-25
62
0
600 TO 520
0
650
400
29.0
0.0
440
450
390
660
210
76
20
-12
-20.0
1920
1850
I860
1850
200
192
-28.2
1825
200
24 0
25.2
1 5
1 0
.8
.8
-.45
-.75
-2.O
-3.0
-2 8
1 6
1 1
5.1
4 5
-1.2
11.0
-1.2
9.5
-3 4
10 5
-1.2
0
6/25/74
6-38
64
0
600 TO 520
0
650
380
29.0
0 0
440
440
622
660
210
75
20
-12
-20 0
1950
1900
1890
1835
197
187
-28.2
1850
197
24.0
25 2
2.7
2.2
1 1
1.2
-.45
-1.0
-3 4
-4.5
-4.6
2.5
2.0
8.5
8.5
-1.2
10.8
-1.0
10.7
-3.4
10.5
-1.2
0
6/27/74
9:30
92
0
335
275
705
610
30.0
0
640
665
600
990
311
120
36
-3
-16.1
1990
1940
1910
1840
307
284
-28.1
1860
295
0
0
2.0
1.6
.5
.6
-.45
-1.0
-3.4
-4.4
-4.4
a. s
1.8
8 2
8.0
-1.4
12.0
-1.4
10 7
-3 0
11.5
-1 2
0
6/19/74
13:24
131
0
574
524
900+
770
30.0
0
930
965
980
1440
452
183
59
6.9
-11.0
2020
1960
1950
1825
448
412
-27
1860
425
23.7
24 8
5.6
5.2
2.2
2.2
-.1
-1.0
-5.6
-7.0
-7.1
4.2
3.4
14.5
14 0
-1.0
12 0
-.25
14.5
-1.25
12.5
-1.75
11.5
6/27/74
11 18
127
0
550
480
900+
740
30.0
O
910
945
820
1420
442
176
57
5.9
-12. 0
2060
1975
1950
1825
438
402
-27. B
1865
415
0
0
3.5
3.5
1.0
1.0
-.45
-1.5
-5.5
-6.8
-7.0
3.7
3.1
13.2
13.0
-1.4
12.0
-1.2
11.2
-3.0
12.0
-1 9
12 0
6/27/74
3:05
125
0
525
410
900+
700
34.0
0
860
910
930
1350
427
171
55
5.0
-12.0
2050
1970
1940
1840
421
388
-27.8
1875
402
0
0
6.0
5.5
2.2
2.2
-.04
-1.1
-5.7
-7.2
-7.4
4.1
3.3
14.7
14.0
-1.0
12.7
.1.0
11 5
-1.8
12 0
-1.5
12.3
6/20/74
9-41
130
0
568
520
900+
741
32.5
0
900
950
960
1440
451
183
59
6.9
-11 0
2050
1960
1950
1825
448
412
-27
1865
425
0
0
5.0
4.9
2.0
2.0
-.27
-1.25
-5.5
-7.2
-7.4
4.0
3.5
14.5
14.0
-1.0
12.0
-.75
14.2
-1 75
12.0
-1.9
11.5
6/20/74
12'25
129
0
564
520
900+
742
30.0
0
920
960
870
1440
448
180
59
6.9
-11.0
2050
1950
1950
1825
441
409
-27
1865
42O
0
0
4.0
3.8
1.1
1.1
-.45
-1.4
-5.4
-6.7
-6.9
3.8
3.2
13.5
13.4
-1.1
12.2
-1.0
14.0
-2.0
12.0
-2.0
11.0
6/28/74
14-45
125
0
530
425
900+
720
33.0
0
880
920
900
1370
430
174
56
5.0
-12.1
2040
1960
1940
1825
424
390
-28.0
1850
404
0
0
5.5
5.0
2.0
2.0
-.08
-1.2
-5 7
-7.1
-7.4
4.1
3.4
14.6
14.1
-1.2
12.5
-1.2
10.5
-2 8
11.5
-1 75
12.0
6/26/74
1-23
65
0
0
460
680
400
29.0
O
440
460
480
700
220
79
22
-11
-19.5
1950
1900
1880
1825
210
197
-27.9
1840
205
23.7
24 9
1.9
1.2
.9
.9
- 475
-1.0
-2.5
-3.5
-3.4
1.95
1.4
6.2
5.9
-1.3
11.6
-1.2
10.0
-3.6
10.2
-1.2
0
6/26/74
4-05
68
0
0
490
680
400
34.0
0
400
460
660
700
220
80
22
-11
-20.0
1950
1900
1880
1825
215
198
-28.1
1850
210
23.7
24.9
3.1
2.7
1.2
1.2
-.475
.1.0
-3.75
-4.8
-4.8
2.7
2.0
9.1
9.0
-1.3
11.2
-1.2
9.9
-3.25
10.4
-1.2
0
6/28/74
11:25
126
0
530
425
900+
720
33.0
0
880
925
820
1380
436
175
56
5.2
-12.1
2050
1970
1940
1830
428
392
-28.0
1855
402
0
0
4. a
4.0
1.2
1.2
-.44
-1.5
-5.7
-7.4
-7.5
4.0
3.2
14.5
14.1
-1.5
13.2
-1.4
10.7
-3.2
11.5
-2.0
12 0
6/28/74
9:20
125
0
530
425
9OO+
720
30.0
0
890
930
930
1380
431
175
56
5.0
-12.2
2050
1970
1940
1835
428
392
-27.2
1855
406
0
0
5.5
5.0
2.0
2.0
-.05
-1.2
-5.7
-7.3
-7.4
4.1
3.4
14.8
14.2
-1.2
13.4
-1.2
11.5
-2.8
12.0
-1 6
12.3
-------
ALABAMA POWER COMPANY
BARRY 12
BOARD DATA
C-E POWER SYSTEMS
FIELD TESTiNO mo
PERFORMANCE RESULTS
TEST NO.
TEMPERATURES
AIR t GAS - T
BOILER OUTLET CAS L H.
BOILER OUTLET GAS R.H.
ECONOMIZER OUT GAS L.H
ECONOMIZER OUT GAS R H.
PRCHCATER 2A OUTLCT GAS
PREHEATER 28 OUTLET GAS
PREHEATER 2A INLET AIR
PRCHCATER 23 INLET AIR
PREHEATER 2A OUTLET AIR
PREHEATER 2B OUTLET AIR
PULVERIZER 2A
PULVERIZER 2A
PULVERIZER 28
PULVERIZER 2C
PULVERIZER 2C
PULVERIZER 3D
PULVERIZER 20
TEMPERATURES
STEAM & WATER
NLET
NTCRN
NLCT
NLET
NTERN
NLET
NTERN
. «F
FECDWATER
ECONOMIZER WATER OUTLET - L H
ECONOMIZER WATER OUTLET - R H
RH DESUPH. IN L H
RH DESUPH. OUT L H
RH DESUPH. IN R H
RH DESUPH. OUT R.H.
SUPERHEAT OUT L H.
SUPERHEAT OUT. R H
THROTTLE STEAM L H
THROTTLE STEAM R H
REHEAT OUTLET L H
REHEAT OUTLET R.H.
SUPERHEATER OUTLET
REHEATER OUTLET
UPPER VALVE CHEST
LOVER VALVE CHEST
H P. EXHAUST
REHEAT BOWL
INTERMEDIATE EXHAUST
CONDENSATE TEMP.
S H DESUPH. IN L.H
S H. DESUPH. OUT L H.
S.H DESUPH. IN. R H.
S H. DESUPH. OUT R H
MISCELLANEOUS
T~E FAN 2A RPM
ID FAN 26 RPM
F D. FAN 2A RPM
F D FAN 2B RPM
FAN DAMPER POSITION - (0-12)
ID FAN 2A
ID FAN 28
FD FAN 2A
FO FAN 28
614
625
520
515
385
279
89
89
475
477
418
145
435
150
410
166
80
80
4oe
440
439
495
495
495
495
907
915
916
918
821
811
917
815
860
95
470
801
350
110
749
738
749
740
420
420
350
340
6 1
6 1
5 9
6 0
BASELINE
3
607
618
504
504
290
289
82
88
471
425
420
142
423
160
420
160
80
80
408
430
429
461
461
461
461
872
872
870
962
780
760
875
755
820
95
439
750
312
107
701
696
709
701
380
380
320
380
5 8
5 8
4 4
4 4
3
631
642
548
552
272
879
89
90
479
485
420
160
435
155
420
165
80
80
408
460
459
562
562
562
562
992
998
998
994
912
910
997
900
929
90
532
881
411
107
842
827
842
829
500
500
450
440
8 0
8 0
6 2
6 0
STUDY AFTER MODIFICATION
4
628
638
552
558
292
289
98
98
496
491
430
150
440
140
425
139
80
80
440
460
460
547
547
547
547
935
941
941
941
858
850
940
850
870
97
820
...
107
770
760
765
757
500
500
430
430
7 2
7 1
4 3
4 4
5
660
669
612
615
290
290
100
101
509
510
460
140
480
145
475
180
475
175
472
492
492
638
638
638
638
982
980
978
980
932
925
983
924
909
105
600
890
419
127
835
820
821
810
685
675
630
625
12
12
12
12
6
647
657
594
600
295
305
105
109
508
512
430
140
450
140
442
135
455
155
470
486
485
529
629
629
629
979
978
977
975
926
907
976
917
908
99
882
119
818
804
810
801
650
650
530
530
9 8
10 0
B 4
8 6
7
652
662
609
611
300
298
120
122
499
500
420
155
44O
145
450
160
455
175
470
490
490
610
610
610
61O
962
961
960
961
920
900
964
912
897
101
880
119
850
808
842
800
685
680
680
680
12 0
12 0
12 0
12 0
8
662
669
614
617
290
292
99
99
516
518
455
145
465
160
470
200
465
175
472
494
492
630
630
630
630
972
971
970
970
941
928
978
925
90S
102
595
897
420
127
850
802
839
800
685
675
600
600
12
12
12
12
9
658
661
606
610
299
299
101
101
520
5SO
460
140
470
140
475
240
475
175
472
490
490
630
630
630
630
970
970
970
969
930
917
982
916
901
108
595
886
412
127
821
805
815
800
660
660
520
540
12
12
12
12
U)
652
662
60S
612
305
302
120
122
504
509
410
160
440
160
435
160
455
180
457
489
489
621
621
621
621
968
968
965
972
932
908
975
922
896
101
875
115
851
811
850
820
690
660
580
585
12.0
12.0
12 0
12 0
J_l
619
628
527
527
282
290
98
101
480
485
420
145
425
145
410
170
80
80
411
447
441
520
520
520
520
935
941
941
941
858
850
945
855
885
99
491
832
375
107
771
759
762
752
420
420
350
340
7.2
7 0
6 2
6 3
J2
640
650
561
569
272
285
92
101
488
496
410
155
425
155
420
180
80
80
411
471
470
562
562
562
562
980
985
983
985
940
930
987
935
929
98
530
912
431
107
908
785
899
782
530
520
460
460
8.2
8.0
8 9
8.9
12
651
662
604
610
311
306
110
108
518
517
440
160
455
150
440
150
460
175
460
489
489
621
621
621
621
972
968
968
970
938
911
975
924
891
100
875
120
845
808
845
811
680
660
580
585
12
12
12
12
12
652
663
609
612
300
298
113
115
501
506
430
155
440
155
435
155
460
175
460
490
490
630
630
630
630
982
982
980
982
942
919
985
930
902
100
879
119
842
819
847
826
690
665
660
645
12
12
12
12
DRUM LEVEL IN. - NORM
I LEVEL
-S 5
-4 0
-4 0
-4.0
-3 0
-3 0
-3 0
-2.2
-4.0
-4.0
-4.0
-4.3
-------
ALABAMA POWER COMPANY
BARRY 82
BOARD DATA
BASELINE STUDY AFTER MODIFICATION
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO.
2A MILL AMPS
SB MILL AMPS
2C MILL AMPS
2D MILL AMPS
EXHAUSTER DAMPER POSITION - f OPEN
O - IP SrALF
MILL 2A
MILL 28
MILL 2C
MILL SO
PULVERIZER FEEDER CAP - % OPEN
0.13 scTTT
MILL 2A
MILL SB
MILL 2C
MILL 20
SPRAY VALVE POSITIONS - g OPEN
SH SPRAY L
SH SPRAV R
RH SPRAV L
RH SPRAY R
BURNER TILT POSITION - DECREES
IR
RR
LF
RF
FEEDVATER VALVE - % OPEN (0-12 SCALE)
AIR HTR. 2A RECIRC. DAMPER - f OPEN
AIR HTR SB RECIRC. DAMPER - % OPEN
13
35
35
32
0
4.2
5.5
4.2
0
4.2
4.2
3 0
0
0
0
0
0
8.8
32
32
36
35
32
0
4.3
5 5
4 2
O
4.3
4.3
3 2
0
10
9
12
10
8.8
32
32
34
37
31
0
4 0
5 5
4 2
0
4 0
4.0
2 9
0
0
0
0
0
-13
-13
-10
-12
8.7
38
39
36
36
38
0
5 4
5.6
5.4
0
5 4
5.4
5 8
0
0
0
0
0
+4
44
+7
+6
11.5
52
52
40
39
40
36
s a
7.75
5 2
5.2
5 S
7.75
5.2
5.2
0
0
0
0
-8
-6
-5
-7
12+
26
25
37
36
37
38
5.4
5 6
5.4
5 4
5.4
5.4
5.8
5.6
0
O
0
0
-2
-2
+2
0
11.4
48
49
36
36
36
38
5.4
5 6
5 4
5.4
5.4
5.4
6.0
5.6
44
40
0
0
-22
-26
-22
-24
11.4
48
44
48
40
40
34
5.4
8 1
5.5
5 6
5.4
8 1
5 5
5.6
40
40
0
0
-22
-25
-21
-23
12+
26
26
42
39
41
35
5.3
8.0
5.4
5.4
5 3
8.0
5.4
5.4
18
18
0
0
-9
-11
-9
-10
12+
26
26
38
34
37
36
5.4
5 6
5 4
5.5
5.5
5.5
6.0
5.6
37
39
0
0
-3
-3
0
-1
12+
46
42
35
34
26
0
4.7
4.8
3.2
0
4 8
4.8
2.6
0
0
0
0
0
-10
-12
-9
-10
12+
41
41
32
33
30
0
4.4
4.5
3.8
0
4.4
4.4
3.7
0
65
64
0
0
-10
-10
-8
-9
8.5
41
41
36
36
38
36
6 8
5.9
5.7
5.8
5.7
5.7
6.2
5.8
40
38
0
0
-3
-3
0
-1
12+
46
43
36
35
36
36
6.8
5.8
5.6
5.8
5.6
5.6
6.1
5.8
30
30
0
0
-3
-3
0
-1
12+
46
43
-------
AL«B«M> Powen COMPANY
BARRY IS
C-E POWER SYSTEMS
FIELD TESTING >HD
PcRroRMtNCE RESULTS
BOARD DATA
OVERFIRE AIR LOCATION, RATE & VELOCITY VARIATION
TEST HO.
Date
Time
Load - MM
FLOWS - 1Q3LBS/HR
BFP ZA
BFP 2B
BFP 2C
Reheat Steam
Condensate
Superheat Spray
Reheat Spray
Feedwater
Primary Steam Flow
Air Flow - Relative
PRESSURES
STEAM i HATER - P5IG
1st Stage Extraction
8th
12th
16th
19th (-In Hg. +P5IG)
21st (In. Hg)
Feedwater Regulator Inlet
Feedwater
Drum
Turbine Throttle
Reheat Inlet
Reheat Bowl
Exhaust (In. Hg)
Main Steam
Reheat Outlet
Light Oil Upper Burners
Light Oil Lower Burners
PRESSURES
AIR & GAS - IN. HG
2A FD Fan Discharge
2B FD Fan Discharge
2A Preheater Outlet Air
2B Preheater Outlet Air
Furnace Pressure
Superheater Cavity
Economizer Inlet
Economizer Outlet RH
Economizer Outlet LH
No 2A Preheater Diff. Gas
No. 2B Preheater Diff Gas
No 2A ID Fan Suction
No 2B ID Fan Suction
Pulverizer 2A Inlet Air
Exhaust 2A Discharge
Pulverizer 2B Inlet Air
Exhauster 2B Discharge
Pulverizer 2C Inlet Air
Exhauster 2C Discharge
Pulverizer 20 Inlet Air
Exhauster 2D Discharge
TEMPERATURES
AIR S GAS - °F
Boiler Outlet Gas LH
Boiler Outlet Gas RH
Economizer Outlet Gas LH
Economizer Outlet Gas RH
Preheater 2A Outlet Gas
Preheater 2B Outlet Gas
Preheater 2A Inlet Air
Preheater 2B Inlet Air
Preheater 2A Outlet Air
Preheater 2B Outlet Air
Pulverizer 2A Inlet A1r
Pulverizer 2A Internal
Pulverizer 2B Inlet Air
Pulverizer 2B Internal
Pulverizer 2C Inlet Air
Pulverizer 2C Internal
Pulverizer 2D Inlet Air
Pulverizer 20 Internal
16
17
1BA
19
20
21
22
23
7/10/74
0 00
97
0
415
360
810
525
30.5
0
690
725
700
1060
334
131
40
0
-15.2
2000
1950
1930
1850
329
304
-27 3
1870
315
0
0
4 2
4.0
2.0
2.0
- 48
-1.2
-4.0
-5.3
-5 3
2 9
2.4
10 0
10.0
-.7
1 0
- 9
10.0
-3.2
11 0
-1.8
11 0
639
646
571
572
292
292
122
132
489
492
100
100
435
140
420
145
440
142
7/10/74
2-15
98
0
415
360
810
530
30.5
0
690
715
660
1060
338
130
40
0
-15.2
2010
1950
1930
1850
330
305
-27.6
1870
315
0
0
3 1
2.7
1.0
1.0
-.48
-1.2
-4.0
-5.2
-5.2
2.9
2.3
10.0
10.0
- 7
1 0
-1.2
10.0
-3.3
11.0
-2.0
11 0
638
648
571
574
292
292
98
98
495
501
90
90
440
140
420
140
440
140
7/10/74
4-00
100
0
420
360
820
535
30.0
0
690
720
660
1060
340
133
40
0
-15.1
2010
1950
1935
1850
330
306
-27.6
1870
320
0
0
3 1
2.9
1.0
1 1
-.48
-1.2
-4.0
-5.2
-5.2
2 9
2.35
10.0
10.0
-.7
9
-1.2
10.0
-3.3
11 0
-2 0
11 2
639
649
572
578
292
291
92
95
498
501
80
80
440
140
420
140
445
140
7/12/74
7:25
100
0
425
365
835
535
29.8
0
700
725
675
1080
340
135
41
0
-15 2
2000
1950
1930
1845
332
309
-27 3
1865
321
23
25
3.0
2.5
.8
.8
-.45
-1.2
-4.2
-5.5
-5.5
3 0
2.4
10.5
10 5
-1 7
0
-1 0
11.5
-2 5
11.0
-1.4
11 2
640
649
572
579
289
290
95
99
492
500
80
80
440
150
440
160
450
180
7/11/74
4 35
100
0
410
355
805
525
36.0
0
650
715
680
1060
340
132
41
0
-15.6
2000
1940
1920
1835
330
305
-27.4
1850
319
23
25
3.0
2 7
1.0
1.0
-.48
-1 2
-4.2
-5.5
-5.5
2.9
2.4
10 4
10 5
-.7
.8
-1 0
10.2
-2.1
11.5
-1 1
12 0
641
650
577
582
291
287
91
91
500
502
80
80
440
130
440
155
460
155
7/11/74
23.10
100
0
420
360
820
540
31.9
0
685
725
720
1070
340
135
41
0
-15 2
2000
1940
1915
1835
330
308
-27.4
1850
320
23
25
3.9
3.3
1.5
1.5
- 45
-1 2
-4 1
-5.5
-5 5
3 0
2.4
10.3
10 3
-.7
1 0
- 95
11.5
-2 6
11 2
-1 75
11.3
640
648
573
579
289
297
105
110
489
500
100
100
440
160
440
160
455
160
7/12/74
1-24
102
0
420
360
830
535
33.0
0
670
725
720
1080
342
136
42
0
-15.2
2000
1940
1920
1835
335
310
-27 3
1850
322
23
25
4 0
3 8
1.8
1 8
- 45
-1 2
-4.3
-5 6
-5 6
3.0
2 4
10.5
10.7
-1 1
11 5
- 8
11.5
-2.4
11.5
-1 2
0
645
652
578
583
290
299
103
111
492
505
410
160
440
160
440
170
100
100
7/12/74
3:30
102
0
420
365
830
540
34.0
0
670
725
680
1080
348
136
42
0
-15.2
2010
1950
1925
1840
340
314
-27.3
1855
325
23
25
3.0
2.7
1 8
1 8
- 45
-1 2
-4 4
-5.8
-5 8
3 1
2 6
11.0
11 0
-1 4
12 0
-.9
11.5
-2 4
11 5
-1 2
0
645
652
580
589
290
298
92
98
498
509
420
140
445
140
450
160
100
100
7/12/74
4:45
102
0
425
365
830
540
34.0
0
670
725
700
1080
347
136
42
0
-15.2
2000
1940
1925
1835
339
313
-27.3
1860
325
23
25
3.4
3.0
1 0
1 1
- 45
-1.3
-4 4
-5.7
-5 7
3 1
2 6
11 0
11 0
-1 25
12 0
- 75
12 0
-2 4
12 0
-1 2
0
645
652
579
586
290
298
98
101
495
507
425
140
445
150
455
155
80
80
106
SHEET 12A
-------
ALABAMA POWER COMPANY
BARRY JZ
C-E POUCH SYSTEMS
FIELD TESTING AMD
PERFORMANCE RESULTS
BOARD DATA
OVERFIRE AIR LOCATION, RATE & VELOCITY VARIATION
TEST NO Ji
TEMPERATURES
STEAM 8 WATER - "F
Feedwater
Economizer Water Outlet - LH
Economizer Water Outlet - RH
RH DESH Inlet LH
RH DESH Outlet LH
RH DESH Inlet RH
RH DESH Outlet RH
Superheat Outlet LH
Superheat Outlet RH
Throttle Steam LH
Throttle Steam RH
Reheat Outlet LH
Reheat Outlet RH
Superheater Outlet
Reheater Outlet
Upper Valve Chest
Lower Valve Chest
HP Exhaust
Reheat Bowl
Intermediate Exhaust
Condensate Temperature
SH DESH Inlet LH
SH DESH Outlet LH
SH DESH Inlet RH
SH DESH Outlet RH
MISCELLANEOUS
ID Fan 2A RPM 560 550
ID Fan 2B RPM 560 540
FD Fan 2A RPM 540 450
FD Fan 28 RPM 540 460
FAN DAMPER POSITIONS (0-12)
ID Fan 2A 12+ 12+
ID Fan 2B 12+ 12+
FD Fan 2A 9.8 8.2
FD Fan 28 9.6 8.2
Drum Level In. + Norm. H20 Level -4.5 -4.5
2A Mill Amps 0 0
2B Mill Amps 37 36
2C Mill Amps 36 36
2D Mill Amps 41 41
EXHAUSTER DAMPER POSITION - « OPEN
0-12 SCALE
Mill 2A 00
Mill 2B 4.6 4.5
Hill 2C 4.4 4.4
Mill 2D 4.4 4 4
PULVERIZER FEEDER CAP. - « OPEN
Mill 2A 00
Mill 28 4.4 4.4
Mill 2C 4.9 4.8
Mill 2D 4.5 4.6
SPRAY VALVE POSITION - % OPEN
SH Spray L 00
SH Spray R 00
RH Spray L 00
RH Spray R 00
BJRNER TILT POSITION - DEGREES
LR -2 -2
RR 00
LF 00
RF -1 -1
Feedwater Valve - I Open (0-12 Scale) 12+ 12+
Air Htr. 2A Red re. Damper - X Open 40 29
Air Htr. 28 Red re Damper - I Open 40 29
17
ISA
19
20
22
445
469
469
572
572
572
572
960
959
955
950
890
860
965
855
899
101
549
840
384
119
809
795
799
788
445
469
469
567
567
567
567
945
942
940
938
872
848
950
845
890
101
539
837
375
119
800
789
790
780
445
470
470
574
574
574
574
952
952
950
948
889
859
957
854
898
100
545
845
380
119
808
792
796
785
450
471
470
585
585
585
585
961
965
966
968
897
889
975
889
920
101
560
872
410
120
812
800
805
795
447
472
472
582
582
582
582
959
962
959
968
917
907
970
907
911
102
554
892
419
120
840
781
832
779
450
472
472
585
585
585
585
961
969
965
975
905
891
975
895
905
105
555
870
405
121
815
784
813
787
450
478
477
600
600
600
600
981
988
985
990
940
929
990
928
929
105
575
909
430
121
841
788
839
789
450
478
478
589
589
589
589
968
968
965
969
930
912
975
915
920
102
565
903
422
120
843
772
842
778
450
477
477
582
582
582
582
960
962
961
960
921
905
970
905
910
101
557
890
417
120
841
774
837
775
540
540
450
460
12+
12+
8.2
8.2
-4 5
0
36
36
42
0
4.8
4.6
4.6
0
4 6
5.2
4.8
560
560
450
460
12+
12+
12+
12+
-4 5
0
36
36
38
0
8 6
5.2
4.6
0
5.2
5.8
4.8
560
560
460
470
12+
12+
6.2
5.9
-4.5
0
37
36
41
0
8.4
4.4
4.4
0
5.2
5.7
5.4
52
52
0
0
570
560
500
500
12+
12+
12
12
-4.5
0
37
36
40
0
8.4
4.8
4.4
0
4.3
4.8
4.4
36
36
0
0
575
570
520
520
12+
12+
12
12
-4.5
36
38
38
0
4.8
8 4
4.8
0
4.8
4.8
5.3
0
50
50
0
0
580
580
450
460
12+
12+
12
12
-4.5
36
37
38
0
5.0
8 4
5.0
0
5.0
5.0
5.5
0
60
60
0
0
580
580
480
480
12+
12+
12+
12+
-4.5
36
37
38
0
5.3
8 4
5.4
0
5.4
5.4
5 9
0
60
60
0
0
-2
0
0
-1
12+
29
26
0
0
0
0
12+
32
35
0
+1
0
-1
12+
0
0
0
+2
+2
0
12+
32
32
0
+2
+2
0
12+
32
34
0
+2
+2
0
12+
32
34
0
+2
+1
0
12+
32
34
107
SHEET 128
-------
ALABAMA POWER COMPANY
BARRY 82
BOARD DATA
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO
DATE
TIME
LOAD - MW
FLOWS - IQ-^-BS/HR
BFP 2A
BFP 2B
BFP 2C
REHEAT STEAM
CONDENSATC
SUPERHEAT SPRAY
REHEAT SPRAY
FEEDWATCR
PRIMARY STEAM FLOW
AIR FLOW - RELATIVE
PRESSURES
STEAM &"WATEH - PSIG
IST STAGE EXTRACTION
BTH
12TH
16TH
19 (-IN Ho- + PSIG)
21sT (in He)
FEEDWATCR REGULATOR INLET
FECOWATER
DRUM
TURBINE THROTTLE
REHEAT INLET
REHEAT BOWL
EXHAUST (in He)
MAIN STEAM
REHEAT OUTLET
LIGHT OIL UPPER BURNERS
LIGHT OIL LOWIR BURNERS
PRESSURES
2A FD FAN DISCHARGE
2B FD FAN DISCHARGE
2A PREHCATER OUTLET AIR
26 PREHEATER OUTLET AIR
FURNACE PRESSURE
SUPERHEATER CAVITY
ECON. INLET
ECONOMIZER OUTLET R.H
ECONOMIZER OUTLET L.H
No 2A PREHEATCR Dirr. GAS
No 2B PREHEATER OIFF. GAS
No. 2A I.D. FAN SUCTION
No. 2B I D. FAN SUCTION
PULVERIZER 2A INLET AIR
EXHAUSTER 2A DISCHARGE
PULVERIZER 28 INLET AIR
EXHAUSTER 2B DISCHARGE
PULVERIZER 2C INLET AIR
EXHAUSTER 2C DISCHARGE
PULVERIVER 2D INLET AIR
EXHAUSTER 20 DISCHARGE
OVERFIRE AIR
TILT VARIATION
24
7/29/74
9 40
124
0
500
410
900+
620
33 0
0
820
900
800
1320
420
168
55
5 9
-12 5
2030
1950
1930
1825
411
380
-27.2
1850
390
0
0
4 9
4.5
1 5
1.5
- 20
-1 3
-5 6
-7 1
-7 4
3 9
3 5
14.4
14 0
-1 3
12 0
-1 0
10.0
-2.6
12.0
-2.0
10 5
25
7/29/74
11-05
124
0
510
415
900+
630
31.0
0
870
915
797
1350
425
170
56
6.0
-12.2
2050
1950
1930
1825
420
386
-27.1
1850
398
0
0
4 9
4 8
1 7
1 7
- 21
-1 2
-5 6
-7.1
-7.4
4.0
3.5
14 4
14 0
-1 1
12.5
-1 0
10 0
-2 5
12 5
-1 9
10 5
26
7/29/74
13 30
124
0
500
410
900+
625
40.0
0
800
885
800
1300
420
170
55
6.0
-12.5
2020
1950
1930
1825
411
380
-27 1
1B50
393
0
0
4 9
4 5
1 9
1.9
- 175
-1.2
-5 7
-7.2
-7.4
4.0
3 4
14.5
14 0
-1.2
12.5
-1 0
9.5
-2 5
12.0
-1 9
10.5
27
7/29/74
15 00
125
0
500
41O
900+
620
35.0
0
81O
902
799
1320
420
170
56
6.0
-12.5
2020
1950
1925
1820
417
384
-27 1
1850
398
0
0
4.9
4.4
1 9
1.9
-.15
-1.2
-5 7
-7.1
-7.4
4.0
3.5
14.5
14.0
-1.2
12.0
-1.0
9.0
-2 5
12.0
-2 0
11.0
28
7/29/74
16-30
125
0
500
410
900+
625
48.5
0
800
900
785
1319
422
172
56
6.2
-12.4
2010
1940
1915
1820
418
385
-27 0
1850
398
0
0
4.5
4.2
1.5
1.5
- 18
-1.2
-5.7
-7.2
-7.4
3.9
3 4
14.5
14.0
-1.2
12.0
-1.0
9.5
-2.7
12.0
-1.75
11 5
29
7/29/74
18:07
124
0
510
415
900+
630
31.5
0
860
900
810
1340
421
171
55.5
6.0
-12 2
2040
1950
1940
1825
415
381
-27 0
1850
395
0
0
5.1
5.0
2 0
2.0
- 05
-1.2
-5.5
-7 1
-7.4
4.0
3 4
14.5
14.0
-1 0
12.7
-1.0
9.4
-2.6
12.5
-1.6
11.5
30
7/30/74
21 05
125
0
500
410
900+
625
35 0
0
820
900
780
1335
422
172
56.0
6.0
-12.5
2040
1960
1940
1835
418
384
-27 0
1860
398
0
0
4 0
3.9
1.0
1.0
-.45
-1.7
-5.6
-7.5
-7 8
3.9
3 5
14.5
14 5
-1.4
12 0
-1.0
9 2
-3.4
11.5
-2.0
10.0
LOAD VARIATION
OPTIMUM
H
7/31/74
12-22
97
0
390
330
810
480
33 5
0
620
680
635
1019
324
129
39
-1.0
-16.0
2000
1925
1910
1835
315
292
-27 5
1865
305
0
0
2.5
2.0
5
.5
- 425
-1.2
-3.8
-5 4
-5.4
2.8
2.4
10.O
10 1
-1.4
12.0
-1.0
9.5
-3.5
11 5
-1 2
0
32
7/31/74
2-35
65
0
270
225
665
350
31.0
0
4OO
455
540
690
219
79
22
-12
-2O.O
1935
1925
1900
1850
204
195
-27.8
1865
200
24
25
1 9
1.7
5
5
-.425
-1.0
-2.9
-4 1
-4.0
2.1
1.7
7.5
7.2
-1.25
12.5
-1.0
10.0
-1.2
0
-1 2
0
AT
CONDITIONS
33
7/31/74
21-50
122
0
500
4OO
900+
625
33.5
0
840
895
800
1320
419
170
55
6 0
-12 5
2O60
1960
1950
1835
411
380
-27.0
1865
391
23.5
25 0
4.9
4.5
1.5
1.5
- 35
-1.5
-5 4
-7 2
-7.5
4.0
3.6
14.7
14.2
-1.25
12.2
-1.0
9.2
-3.0
12.0
-1.5
11.0
34
7/31/74
23.35
95
0
375
325
798
480
32.2
0
620
675
620
1018
321
127
38
0.0
-16.0
2010
1950
1920
1BSO
311
290
-27.4
1865
300
23.5
25 0
2.5
2 0
.5
.5
-.5
-1.1
-3 7
-5.1
-5.1
2 8
2.3
1O.O
10.0
-1.4
12.5
-1.1
10.0
-3.5
12.0
-1.2
0
35
8/1/74
1 38
64
0
275
SK
660
350
31.0
0
300
445
51O
680
215
78
21 5
-12
-20.0
1960
1910
1900
1850
200
191
-27 7
1865
200
23.5
25 0
1 5
1 0
.2
.2
- 45
-1.0
-8.7
-3.9
-3.8
2.0
1.6
7.1
6.8
-1.4
12.9
-1.0
10.2
-1.0
0
-1.2
0
-------
ALABAMA POWER COMPANY
BARRY |2
BOARD
OVERFIRE AIR
TUT VARIATION
DATA
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
IOAD VARIATION AT
OPTIMUM CONDITIONS
X
m
(
S
TEST NO
TEMPERATLRCS
AIR t GAS - *F
BOILER OUTLET GAS L H.
BOILER OUTLET GAS R.H.
ECONOMIZER OUT GAS L H
ECONOMIZER OUT GAS R H.
PREHEATER 2A OUTLET GAS
PREHEATER 26 OUTLET GAS
PREHEATER 2A INLET AIR
PREHEATER 26 INLET AIR
PREHEATER 2A OUTLET AIR
PREHEATER 26 OUTLET AIR
24
25
26
27
29
30
31
32
33
34
35
PULVERIZER 2A
PULVERIZER 2A
PULVERIZER 25
PULVERIZER SB
PULVERIZER 2C
PULVERIZER 2C
PULVERIZER 20
PULVERIZER 20
TEMPERATURES
STEAM & WATER
NLET AlR
NTERNAL
NLET AlR
NTERNAL
NLET AlR
NTERNAL
NLET AlR
NTERNAL
F
FECDWATER
ECONOMIZER WATER OUTLET - L H.
ECONOMIZER WATER OUTLET - R.H.
RH OESUP . IN L.H.
RH OESUP . OUT L.H.
RH OESUP IN R.H.
RH Desup . OUT R H.
SUPERHEA OUT L.H.
SUPERHEA OUT R.H.
THROTTLE STEAM L.H.
THROTTLE STEAM R.H.
REHEAT OUTLET L.H.
REHEAT OUTLET R.H.
SUPERHEATER OUTLET
REHEATER OUTLET
UPPER VALVE CHEST
LOWER VALVE CHEST
H.P EXHAUST
REHEAT BOWL
INTERMEDIATE EXHAUST
CONOENSATE TEMP.
S H. DESUPH. IN L.H
S.H. DESUPH OUT L.H.
S.H. DESUPH. IN R.H.
S.H. DESUPH. OUT R.H.
Ml SCELLANEOUS
I.0. FAN 2A RPM
ID FAN SB RPM
F D. FAN 2A RPM
F.D. TAN SB RPM
FAN DAMPER POSITION - (0-12)
ID TAN 2A
ID TAN 26
FD FAN 2A
FD FAN 26
DRUM LEVEL IN - NORM. HO LEVEL
460
170
480
135
499
170
495
175
467
668
668
668
668
995
992
995
990
958
972
1000
990
978
110
649
970
475
124
891
839
880
841
690
680
560
570
12+
12+
124
12+
651
661
600
605
298
295
79
80
502
511
460
150
480
160
495
175
480
160
467
482
482
649
649
649
649
965
977
968
968
911
930
970
946
959
110
633
939
447
125
855
838
845
834
690
670
570
570
12+
12+
12+
1Z+
660
669
609
612
300
300
95
95
508
519
460
160
480
155
495
175
470
175
467
490
490
65O
650
650
650
975
988
972
972
951
970
975
981
959
111
630
969
471
125
905
815
90O
818
690
675
590
590
12+
12+
12+
12+
661
670
610
615
303
302
95
98
512
521
460
160
480
160
500
165
470
175
470
491
490
668
668
668
668
999
10O1
995
992
978
980
990
992
985
112
650
995
489
125
906
845
685
830
690
680
565
570
12+
12+
12+
12+
661
670
611
305
302
92
95
516
522
460
16O
465
160
500
17O
500
175
47O
491
492
656
656
656
656
982
992
978
972
971
982
975
995
970
115
64O
995
49O
126
921
809
911
8O3
690
680
570
580
12+
12+
12+
12+
652
661
602
609
293
298
92
95
500
514
450
165
465
160
495
175
400
180
470
486
485
649
649
649
649
970
982
977
972
915
938
970
940
961
111
631
945
450
127
858
841
851
840
690
680
600
600
12+
12+
12+
12+
655
670
606
611
302
298
85
80
510
519
465
160
485
155
490
140
480
170
470
490
491
695
695
695
695
1009
1010
1002
1002
975
990
1000
997
988
105
655
990
490
125
919
851
920
860
690
679
540
540
12+
12+
12+
12+
639
651
570
578
292
287
82
78
499
505
450
155
480
150
475
140
100
100
449
470
470
638
638
640
640
981
977
985
981
931
943
977
958
960
109
592
949
460
120
696
829
892
835
560
560
440
440
7.0
7 0
4.3
5 2
630
641
542
550
290
261
88
80
488
480
455
155
460
140
100
100
100
100
415
457
456
621
621
621
621
997
1000
1000
995
928
950
995
957
967
105
570
935
457
113
895
849
900
860
48O
480
400
400
5.8
5.8
3.8
3.8
660
670
610
615
302
298
89
89
511
519
465
170
480
150
495
160
380
165
465
489
489
680
680
680
680
975
981
979
972
932
951
970
970
949
111
619
940
455
127
940
885
926
884
690
670
570
570
12+
12+
11.8
11.8
635
649
569
572
291
288
80
86
499
505
465
155
480
140
480
140
100
100
447
462
462
616
616
619
619
940
950
940
941
876
905
942
920
922
111
550
902
410
125
885
845
881
850
540
540
410
420
7.4
7.3
6.0
5.8
628
638
540
539
300
256
80
90
490
475
460
145
460
140
100
100
100
100
412
450
449
590
590
590
590
958
959
960
965
888
889
953
920
927
110
530
890
422
114
880
860
869
851
460
460
370
370
6.0
6 0
3.6
3 6
-5.0
-5.0
-4.9
-5 0
-4.9
-5.0
-4.5
-5.0
-5.0
-5.0
-5.2
-5.0
-------
ALABAMA POWER COKPAHT
SARRY 02
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO
2A MILL AMPS
28 MILL AMPS
2C MILL AKPS
2D MILL AMPS
EXHAUSTER DAMPER POSITION - g OPEN
O - lg STALE
MILL 2A
MILL 2B
MILL 2C
MILL 2D
PULVERIZER FEEDER CAP - g OPEN
O - 13 SEAL?
MILL 2A
MILL 26
MILL 2C
MILL 20
SPBAY VALVE POSITIONS - t OPEN
SH SPRAY L
SH SPRAY R
RH SPRAY L
RH SPRAY R
BURNER TILT POSITIONS - DECREES
TJR
RR
LF
RF
FEEOWATER VALVE - % OPEN {0-72 SCALE)
AIR HTR 2A RCCIRC DAMPER - f OPEN
AIR HTR 26 RCCIRC DAMPER - t OPEN
BOARD
OVERFIRE AIR
DATA
TILT VARIATION
24
38
37
38
39
6 0
6 2
6 0
4 1
6.0
6.0
6 6
4 2
39
40
0
0
0
0
0
0
12+
24
20
25
40
37
38
39
6 0
6 2
6 0
4 0
6 0
6.0
6.6
4 2
0
0
0
0
-30
-30
-30
-30
12+
24
20
26
40
37
3B
40
6 0
6.1
6 0
4 0
6.0
6.0
6.5
4.2
70
70
0
0
+30
+30
+30
+30
18+
24
20
27
40
37
39
39
6 1
6.4
6.2
4.2
6 2
6.2
6 7
4 3
49
48
0
0
0
0
0
0
12+
24
20
28
40
37
38
40
5.9
6 1
5 9
4.B
6.0
6.0
6.4
4.9
90
88
0
0
+30
+30
+30
+30
10.4
24
20
29
39
36
38
40
5.8
6 0
5 8
4 7
5 8
5.8
6.3
4.8
0
0
0
0
-30
-30
-30
-30
12+
24
20
30
36
35
38
40
5.5
5.6
5-5
4 0
5 5
5.5
6.0
4.0
52
50
0
0
0
0
0
0
12+
38
34
LOAD VARIATION
AT
OPTIMUM CONDITIONS
3_1
36
36
38
0
5 4
5 6
5.4
0
5.5
5.5
6.0
0
48
48
0
0
-12
-12
-12
-12
9.4
37
33
32
38
36
0
0
5.6
5 7
0
0
5.6
5.6
0
0
36
36
0
0
0
0
0
0
9.4
37
33
33
36
36
38
41
5 4
5.6
5 4
5 1
5 4
5.4
5.9
3.1
37
37
0
0
-22
-22
-22
-22
9 3
26
25
34
37
36
38
0
5 4
3 6
5.6
0
5.5
5 5
6.0
0
34
33
0
0
-22
-22
-22
-22
9.4
26
25
35.
37
37
0
0
6.0
6 2
0
0
6.0
6.0
0
0
20
20
0
0
-10
-10
-10
-to
9.4
26
25
-------
ALABAMA POWER Co.
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
WATERWALL ABSORPTION RATES, KG'CAL/HR
RIGHT WALL CENTERLINE TUBE RATES
-CM2
TC t
ELEVATION
TEST 1
2
3
4
5
6
7
8
g
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
1
11 8' -6"
2.02
2.36
1.33
3.01
3.78
4.41
3.73
4.59
6.26
5.14
4.16
4.15
4.95
4.44
4.12
5.25
6.47
3.61
4.39
3.14
4.00
3.49
2.67
4.76
3.00
4.61
4.22
7.16
5.42
7.55
7.07
5.21
7.27
7.52
6.60
3
107 '-6"
3.56
3.64
2.85
5.36
7.19
7.30
5.04
8.28
9.96
5.66
4.95
5.46
6.53
4.96
5.17
5.77
7.26
4.91
5.44
5.23
5.31
5.32
5.00
5.28
5.08
6.71
6.32
8.22
7.80
9.14
7.60
6.00
7.53
7.52
5.81
5
96 '-6"
7.49
8.63
5.18
12.23
10.90
13.66
10.06
11.45
14.99
12.27
6.26
6.51
13.14
11.30
9.66
8.15
9.90
9.92
10.19
10.24
12.45
11.40
11.87
12.68
10.63
14.66
8.43
11.93
8.32
9.93
8.65
7.05
7.80
8.84
6.60
7
85 '-6"
8.81
12.07
7.02
1.25
10.90
1.83
1.19
8.54
15.52
7.51
6.79
6.51
9.96
9.97
.37
2.38
3.33
.16
2.32
.64
.49
1.46
.91
9.24
6.66
13.07
10.02
14.04
9.91
8.08
6.80
6.00
7.80
8.05
6.33
9
74' -6"
10.93
13.13
8.08
2.76
22.55
3.37
2.18
21.78
23.46
6.45
6.53
5.98
13.94
17.66
3.34
7.62
6.99
13.37
4.65
4.18
2.71
2.46
2.67
7.92
6.13
19.69
15.85
17.22
11.24
3.87
7.07
5.47
7.27
8.05
6.33
19
69 '-6"
9.07
9.95
7.55
14.88
7.46
16.04
7.67
5.11
15.52
10.15
4.43
5.72
17.38
14.74
7.80
10.26
10.96
13.37
9.40
2.63
2.20
1.96
1.90
3.98
2.48
2.80
10.81
11.66
9.91
6.23
11.56
8.90
11.24
9.37
8.18
22 44 47
64' -7" 59' -7" 54' -9"
1.28
.86
.83
5.10
6.93
7.83
8.73 12.18
4.06
6.26
9.36
6.00
5.72
15.00
15.01
13.36
12.38
13.61
10.45
5.17
12.1
12.98
11.93
11.87
8.18
11.95
12.80
11.34
12.72
12. 03
9.14
7.07
4.42
14.15
11.22
7.92
57
49' -11"
8.54
6.51
9.66
13.29
18.85
20.81
27.78
10.13
8.63
24.18
11.56
11.53
25.05
24.00
3.34
3.42
3.84
18.67
14.43
20.58
15.10
15.11
15.32
23.80
32.55
15.45
18.76
13.25
27.63
4.65
18.98
14.73
24.47
15.47
10.56
60
45 '-7"
4.08
5.99
9.93
7.73
20.96
14.45
11.38
13.04
12.34
6.98
6.53
7.56
10.76
15.28
10.71
8.68
10.70
17.34
9.92
18.20
10.33
9.81
10.02
12.68
20.43
10.15
15.05
11.93
17.33
7.02
16.07
12.87
14.95
13.35
17.45
62
351 -7"
3.30
3.12
4.13
4.31
12.49
10.21
14.56
15.70
15.26
12.80
6.53
7.83
12.61
12.62
10.98
9.47
12.55
8.07
10.45
9.72
4.53
3.24
3.70
7.92
13.01
4.35
12.40
7.43
17.86
8.34
9.98
7.05
16.54
14.14
7.92
64
-------
ALABAMA POWER Co.
BARRY #2
C-E POWER SvSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
WATERWALL ABSORPTION RATES, KG-CAL/HR-CM2
FRONT WALL CENTERLINE TUBE RATES
ro
TC #
ELEVATION
TEST
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
2
107 '-6"
6.44
6.78
5.18
10.11
11.16
12.33
9.26
10.92
13.67
11.48
5.21
5.46
12.88
10.77
8.07
7.62
8.05
8.07
9.13
8.66
10.33
10.34
10.02
10.56
10.10
12.27
9.22
9.54
9.91
9.66
7.86
6.00
8.85
8.31
7.12
4
96 '-6"
7.49
8.89
4.92
11.96
9.57
12.60
8.47
7.48
9.96
4.61
4.95
5.72
6.26
4.96
5.17
5.77
6.99
5.17
4.91
9.98
11.39
10.07
7.64
8.18
8.24
10.68
7.64
9.81
8.06
9.66
8.12
5.21
7.00
6.99
5.81
6
85 '-6"
11.99
14.72
7.55
7.46
10.37
18.69
12.44
10.66
10.48
15.98
6.79
6.77
7.84
8.39
14.16
10.79
12.29
14.16
12.84
11.30
17.22
18.29
16.91
9.51
6.66
19.96
14.26
12.99
11.24
13.38
11.56
8.10
7.00
6.99
5.54
8
74' -6"
18.08
16.31
8.08
24.67
24.92
27.14
10.85
22.31
25.83
14.92
6.53
6.25
11.56
11.56
11.77
15.83
14.41
11.25
6.22
22.69
21.98
15.90
19.02
15.07
15.66
19.96
8.16
12.19
10.18
25.81
8.12
6.26
18.66
10.96
7.39
13
69' -6"
10.93
11.01
8.61
9.84
10.10
12.86
6.35
16.76
14.20
7.24
4.95
5.46
6.79
5.48
2.57
4.46
5.68
7.28
8.86
9.98
8.48
4.80
13.46
6.34
10.10
7.51
7.11
9.54
10.44
13.90
7.60
5.21
6.48
5.58
3.20
38
59' -7"
«. _ _
... _
...
_ __
___
_-
--_
...
...
...
. __
_ _ _
_ _
_
...
_ ._
-__
...
- __
. ..
._-
...
. _
-__
...
-__
...
...
...
51
)'-11"
10.13
8.89
13.11
14.62
19.11
20.28
23.56
7.22
7.05
5.40
7.85
8.88
7.58
12.36
2.32
2.92
4.63
10.19
9.66
9.19
3.23
2.21
2.40
16.40
19.64
12.80
8.69
6.11
18.92
8.61
7.33
5.21
21.57
22.08
7.92
61
35 '-7"
3.04
2.88
4.66
4.05
12.75
13.39
18.55
15.70
17.38
15.72
6.26
8.09
14.47
14.74
18.13
15.83
16.26
9.92
10.98
16.07
5.58
4.80
5.00
12.95
20.43
5.40
14.26
8.75
20.77
8.87
11.56
7.84
19.98
14.94
8.18
63
25 '-7"
2.52
2.36
1.33
3.01
7.46
4.67
9.53
9.60
7.84
5.66
6.26
7.56
5.21
5.22
6.22
7.62
9.37
6.49
5.44
4.97
3.48
2.45
2.67
5.02
9.57
4.35
3.44
6.90
9.38
7.55
8.12
5.73
12.56
10.43
7.65
-------
ALABAMA POWER Co.
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
WATERWALl ABSORPTION RATES, KG-CAL/HR-CM2
RIGHT WALL
HORIZONTAL AVERAGE
TUBE RATES
GJ
n
TC f
ELEVATION
TEST 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
17-21
69' -8"
8.65
9.53
7.97
13.51
5.67
14.40
7.84
3.66
7.38
8.20
4.84
5.62
10.18
8.34
9.70
11.70
13.77
7.31
6.96
2.89
2.76
2.52
3.19
12.22
9.63
10.54
10.81
12.94
11.34
9.52
7.71
6.32
10.08
8.21
7.65
42-46
59' -7"
9.54
9.16
9.27
11.84
9.98
15.11
11.96
7.63
10.05
16.31
5.09
5.46
14.34
15.34
11.38
10.93
10.44
12.77
4.61
9.52
10.14
9.36
10.16
12.22
14.00
12.21
12.40
14.44
16.07
10.66
10.38
7.98
17.06
14.67
10.76
55-59
49' -11"
8.28
5.82
9.58
7.90
10.64
16.75
18.26
7.10
6.53
15.28
9.18
9.16
15.70
17.92
9.41
12.13
11.95
16.73
8.72
13.62
13.51
13.43
13.64
8.55
22.35
10.25
14.70
12.81
20.06
4.48
17.84
14.02
18.21
13.35
10.12
REAR WALL
HORIZONTAL AVERAGE
TUBE RATES
23-29
59'-7"
5.78
4.97
4.79
6.01
12.22
8.07
8.21
9.22
14.01
12.13
9.10
8.74
13.94
14.06
10.62
10.46
10.44
6.07
7.52
6.42
5.51
6.28
6.04
9.74
9.61
7.53
8.14
9.21
12.18
12.01
10.85
8.53
10.44
9.11
9.05
LEFT WALL
HORIZONTAL AVERAGE
TUBE RATES
30-34
59'-7"
11.67
12.23
10.72
10.20
17.10
14.53
9.04
14.12
14.83
19.48
4.79
6.19
16.06
16.81
18.29
18.37
16.47
14.48
7.50
7.77
13.72
14.85
15.54
15.86
14.18
14.45
13.52
17.60
12.72
11.47
8.85
9.02
10.66
9.27
9.50
FRONT WALL
HORIZONTAL AVERAGE
TUBE RATES
10-16
69 '-6"
11.94
12.34
8.56
13.20
16.33
17.01
10.90
13.80
16.45
14.92
6.35
5.72
12.93
13.91
10.77
12.74
13.17
10.81
9.70
10.92
15.85
13.48
19.17
11.89
12.04
14.22
9.88
13.52
12.30
14.00
7.33
5.21
8.33
8.10
7.75
35-41
59 '-7"
10.31
11.11
8.85
15.68
17.34
17.41
16.12
20.10
18.43
18.98
7.59
6.38
17.64
18.09
15.70
16.45
16.88
17.16
- 14.43
16.25
18.76
17.66
17.12
16.08
16.76
13.95
10.03
14.80
16.76
16.51
16.78
14.51
16.05
13.79
9.20
48-54
49' -11"
8.24
6.92
11.87
9.39
18.73
12.26
17.13
20.73
17.94
13.86
7.76
8.75
13.27
13.66
8.54
9.09
10.35
16.12
9.54
9.16
8.42
7.74
12.28
9.18
13.81
10.17
8.88
7.26
17.63
10.51
9.14
8.11
16.05
16.57
9.42
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
Probe
No.
I
Coupon
No.
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
BASELINE TEST
Initial Wt.
GR.
199.2937
201.3871
198.3883
195.8045
199.1977
199.6807
202.8649
202.3445
199.0122
202.2508
201.9826
199.6584
202.5778
200.8579
202.7075
197.7676
199.5913
197.4684
194.9513
202.0694
Final Wt.
GR.
199.1341
201.2135
198.2384
195.6946
199.0534
199.5009
202.7226
202.2442
198.8632
202.1171
201.8976
199.5954
202.5080
200.7484
202.5924
197.6750
197.2730
194.7783
201.9251
Wt. Loss
GR.
.1596
.1736
.1499
.1099
.1443
.1798
.1423
.1003
.1490
.1337
.0850
.0630
.0698
.1095
.1151
.0926
.1954
.1730
.1443
Wt. Loss/ Avg. Wt. Loss/
Coupon
MG/CIT
3.1643
3.4418
2.9719
2.1789
2.8609
3.5647
2.8213
1.9885
Probe
MG/Cir
9541
6507
6852
249
3838
1769
282
1.8359
3.874
3.4299
2.8609
2.9392
2.8088
2.13475
1.91965
3.38826
Avg. Wt. Loss/Test 2.6381 MG/CM2
114
SHEET 14A
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
Probe Probe Coupon
Loc. No. No.
1 B 1
2
3
4
2 Q 1
2
3
4
3 R 1
2
3
4
4 M 1
2
3
4
5 D 1
2
3
4
Avg. Wt. Loss/Test 4.6429
BIASED FIRING TEST
Initial Wt.
GR.
197.9531
202.1660
198.3393
200.5603
199.3158
196.2751
202.8709
200.2327
198.8940
199.8790
196.0683
199.3342
199.5078
198.7039
198.3125
200.8838
197.9655
202.9412
199.1306
198.2205
Final Wt.
GR.
197.6484
201.8659
198.0383
200.2799
199.1437
196.0480
202.5541
200.0655
198.7626
199.6842
195.8721
199.1690
199.3628
198.4853
198.1121
200.6771
197.7001
202.5809
198.7976
198.0234
Wt. LOSS
GR.
.3047
.3001
.3010
.2804
.1721
.2271
.3168
.1672
.1314
.1948
.1962
.1652
.1450
.2186
.2004
.2067
.2654
.3603
.3330
.1971
Wt. Loss/
Coupon
MG/CIT
0411
9499
9678
5593
3.4121
4.5026
6.2810
3.3150
2.6051
3.8622
3.8899
3.2753
,8748
3341
.9732
,0981
,2619
,1435
,6022
Avg. Wt. Loss/
Probe
MG/CMZ
5.8795
4.3777
3.4081
3.8201
5.7289
3.9078
115
SHEET 14B
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
Probe Coupon
No. No.
S 1
2
3
4
T 1
2
3
4
F 1
2
3
4
N 1
2
3
4
2 1
2
3
4
Avg. Wt. Loss/Test 4.4419 MG/CM^
OVERFIRE AIR TEST
Initial Wt.
GR.
200.7678
196.0684
199.6433
197.8187
200.7026
593.7075
199.1897
199.4476
199.3119
199.0463
202.8354
201.2249
397.4898
191.8528
192.7875
Final Wt.
GR.
200.5465
195.8121
199.3849
197.6419
199.1437
593.2000
198.9156
199.1351
198.9858
198.7404
202.6125
200.9784
397.2000
191.6484
192.5909
Wt. Loss
GR.
.2213
.2563
.2584
.1768
.2802
.5075
.2741
.3125
.3261
.3059
.2234
.2465
.2898
.2044
.1966
Wt. Loss/
Coupon
HG/or
4.3876
5.0815
5.1235
3.5053
5.5554
3.3540
3.3540
3.3540
4344
1958
4654
0649
4292
8872
8729
2.8729
4.0525
3.8979
Avg. Wt. Loss/
Probe
MG/CIT
4.5244
3.9044
6.0401
3.7656
3.9752
1.16
SHEET 14C
-------
ALABAMA POWER COMPANY
BARRY |4
C-E POWER SYSTEMS
FIELD TESTING «ND
PERFORMANCE RESULTS
TEST DATA SUMMARY
BARRY NO. 4
TEST NO
10
12
13
D*TE (1973)
TIME
TEST CONDITIONS
LOAD
MAIN STEAM FLOW
SH DESH SPRAY
MAIN STEAM OUTLET
HOT RH OUTLET
OXYGEN AH INLET
Excess AIR AH INLET
HILL CLASSIFIER SETTINGS
BURNER TILT
MILLS IN SERVICE
* 4 TYPE or FUEL
GROSS KM
X10XKG/HR
X10T
-------
ALABAMA POWER
BARRY It
COMPANY
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST DATA SUMMARY
BARRY NO. 4
TEST NO.
DATE (1973)
TIME
1/22
1340
18
19
29
30
31
1/22 1/22 1/22 1/19 1/19 1/19
0657 0905 1203 1145 1245 1400
ffi
1/22
1103
33
1/24
0945
34
1/24
1000
1/24
1055
37
1/24
1145
TEST CONDITIONS
LOAD
MAIN STEAM FLOW
SH DESH SPRAY
MAIN STEAM OUTLET
HOT RH OUTLET
OXYGEN AH INLET
EXCESS AIR AH INLET
MILL CLASSIFIER SETTINGS
BURNER TILT
MILLS IN SERVICE
* t TYPE or FUEL
GROSS MW
X10T
-------
ACCELERATED CORROSION RATE DATA
ALABAMA POWER, BARRY NO. 4
Firing Condition
Baseline
Baseline
Baseline
Baseline
Low NOY
A
Low NOV
A
Low NOV
/\
Low NO..
Corrosion Rate*,
Mils/Yr
34
24
17
18
11
13
16
16
32
26
41
52
77
87
13
18
* Paired corrosion rate values obtained on two coupons exposed
on the same probe.
119
SHEET 16
-------
Alabama Power Company
Barry #4
C-E Power Systems
Field Testing and
Performance Results
TYPICAL COAL ANALYSIS
ALABAMA COAL
Obtained From
Peabody Coal Company
Analysis by Pittsburg Testing Laboratory
Proximate Analysis As Received
SAMPLE IDENTIFICATION
Date
Moisture - %
Ash - %
Volatile Matter - %
Fixed Carbon - %
Sulfur - %
HHV - BTU/LB
Date
Moisture - %
Carbon - %
Hydrogen - %
Oxygen - %
Nitrogen - %
Sulfur - %
Ash - %
HHV - BTU/LB
ABC
9/30/72
8.40
13.00
25.92
52.68
2.02
11,897
Ultimate As Fired
MIDWEST BITUMINOUS
PEABODY
WARRIOR
9/14/72
10.1
11.36
19.75
58.79
2.67
12,131
1/07/72
9.09
70.01
3.83
3.83
1.28
2.21
9.75
12,290
PEABODY
TIGER
9/30/72
9.2
9.4
28.8
52.6
2.55
12,269
Analysis By Alabama Power Co.
Proximate Analysis As Received
SAMPLE IDENTIFICATION
Date
Moisture - %
Ash - %
Volatile Matter - %
Fixed Carbon - %
Sulfur - %
HHV - BTU/LB
EAGLE 1
11/72
8.63
9.75
2.75
13,072
EAGLE 2
11/72
10.36
8.86
3.15
13,023
120
SHEET 17A
-------
Alabama Power Company C-E Power Systems
Barry #4 Field Testing and
Performance Results
PETROLEUM COKE
Analysis by Gulf Oil Company, Port Arthur, Texas
Proximate Analysis As Received
SAMPLE IDENTIFICATION A2602
Date 2/17/70
Moisture - % 7.7
Ash - % .10'
Volatile Matter - % 10.80
Fixed Carbon - % 81.40
Sulfur - % 3.53
HHV - BTU/LB 15,700
121 SHEET 17B
-------
REFERENCES
1. Blakeslee, C. E. and Selker, A. P.,"Program For Reduction of NO
/\
From Tangential Coal Fired Boilers - Phase I"
2. Crawford, A. P., Manny, E. H. and Bartok, W., "Field Testing:
Application of Combustion Modifications to Control NO Emissions
A
From Utility Boilers"
122
-------
APPENDIX I
COMPFLOW - WINDBOX
COMPARTMENT AIR FLOW DISTRIBUTION COMPUTER PROGRAM
INTRODUCTION
A description of COMPAIR, a computer program which calculates the wind-
box assembly air flow distribution, was presented in Reference 1. The
program has been subsequently found to be deficient; the approach taken
in the calculation of the compartment loss coefficient resulted in op-
erational difficulties in certain cases. The program was revised to
eliminate this problem.
The revised program, COMPFLOW, is described herein. The basic assump-
tions and limitations of the calculation method are outlined and dis-
cussed. Program runs for two tests conducted at Barry #2 are included.
ANALYSIS
Consideration will be initially focused on those cases where the air
flow to each compartment is supplied solely by the windbox.
Assumptions:
1. Constant total pressure at compart-
ment inlet plane, i.e., PT = const.
2. Constant density, i.e., R(I) = R =
const.
3. Constant static pressure at nozzle
exit plane, i.e., P = const.
y
4. Fully turbulent flow, i.e., Head
1 »(Velocity) .
Utilizing these assumptions, it follows that
2 * [ TX
= K(I) * gWf] = const.
0)
Where K(I) = loss coef. for Compartment "I"
Q(I) = volume rate of flow for Compartment "I"
A(I) = nozzle exit area of Compartment "I"
123
-------
Equation (1) yields
Q(D A
JT = M
1=1 1=1
By definition
V" - \
(2)
Using Equations (1) and (3), we have
PT PT
2 * [ 'X " Ty
T
] = 2 *[ TX "
y] - [SUf] = [K(I) - 1]
«>
In order to arrive at a relation for K(I), the windbox compartment total
pressure loss will be set equal to the sum of its component losses, i.e.,
PT PT (I)
* [ TX Ty ] = [K(I) +
Kgo(I) T Kf(I)] *
Where B(I) = inlet flow area of Compartment "I"
Assumption (5): The values listed below, which allow for no interaction,
adequately represent the compartment total pressure loss.
VALUE
LOSS
Miter bend, Kg (I) 0.3
90° bend, K9Q(I) 1.2
Friction, Kf(I) 0.1
Nozzle, KN(I)
Damper, Kp(I)
COMMENT
Typical s/£ = 45
f«0.02, {j-<5; Kf = fjj
- 1; Assume C = 1
KN =
0
Figure 1 Assumed to include inlet loss
Using the above values, Equations (4) and (5) yield
r+ [1.6 +
REFERENCE
2
2
2
3
4
<5>
124
-------
For coal fired units the mill air must be taken into account. Using
Equation (2) for the secondary air flow, it follows that
B
LI= 1
* Wl + X(I) * W2
(7)
Wl + W2 Wl + W2
where W(I) = mass rate of flow to Compartment "I"
Wl = total windbox air to corner
W2 = total mill air to corner
X(I) = fraction of mill air to Compartment "I"
Figure 1 and Equations (6) and (7) constitute the basis of COMPFLOW.
Note that if some other source of air were available to the windbox as-
sembly, Equation (7) would yield the flow distribution with adjustments
in the definitions of W2 and X(I).
Note also that if there is no corner to corner biasing of compartment
dampers, Equation (7) may, to a very good approximation, be regarded
on a furnace/elevation basis.
PROGRAM DESCRIPTION
A description of the program input is as follows:
Input
Fuel and Air Compartment Geometry
Number of Compartments
Width of Compartments
Height of Individual Compartments
Number of Dampers per Compartment
Nozzle Exit Area per Compartment
Test Data
Percent Excess Air
Total Air Flow
Compartment Damper Positions
Fuel Elevations in Service
Typical program outputs for Alabama Power Co., Barry #2, tests 5 and 20,
are shown on Figure 2. These runs represent both normal and overfire
air operation. A definition of the output is shown on Figure 3.
DISCUSSION
A. Development of the Method
The method presented herein, of calculating the windbox assembly flow
125
-------
distribution, is the result of what is obviously a greatly simplified
treatment; numerous assumptions were made in the development of the
method. The validity of each of these assumptions will now be examined.
Assumption (1): Constant total pressure at the compartment inlet plane.
Air issuing from a duct branches to each of the wind-
box assemblies; the fluid is moving at a low velocity
relative to that at the nozzle exit. It would be
reasonable to assume that the total pressure loss be-
tween the supply duct exit and the compartment inlet
plane is a negligible fraction of the velocity head
at the nozzle exit. It is all the more realistic to
assume, as is the case herein, that the total pressure
distribution in the supply duct and the consequent
losses along individual streamlines, are such that the
total pressure is uniform at the compartment inlet
plane.
Assumption (2): Constant density fluid within the windbox assembly.
The reasoning for this assumption is analagous to that
set forth in (1); note that while isothermal flow is
not implied between the supply duct and the compartment
inlet, it is assumed within the windbox assembly.
Assumption (3): Constant static pressure at the nozzle exit plane.
The static pressure of the jets issuing from the wind-
box nozzles is equal to the local furnace pressure.
The variation in furnace pressure throughout this re-
gion should be negligibly small.
Assumption (4): Fully turbulent flow.
This is a valid assumption for the vast majority of
cases; unit Reynolds numbers(based on nozzle exit
velocity) greater than 10 per foot are typical even
for small opening of compartment dampers.
Assumption (5)
The compartment loss coefficient for existing configura-
tions are adequately represented by the formulations
presented herein (i.e. Figure 1 and Equation (6)).
Curves of K versus damper position, as calculated from
Figure 1 and Equation (6), are shown in Figure 4 for
compartment outlet/inlet area ratios (i.e. A(I)/B(I) of
0.534, 0.322 and 0.136; these values cover the range of
our existing compartments. Results obtained from the
cold-flow model tests of Reference 5, at area ratios
of 0.322 and 0.136, are also shown in this figure; the
126
-------
test results are seen to be In excellent agreement
with the predicted values. These test results indicate
that nozzle tilt, flow rate, firing angle, the presence
of turning vanes and probably compartment inlet inter-
action, are secondary influences on compartment pressure
loss and consequently on compartment flow rate. These
results justify the omission of these factors in the
development of the method presented herein.
B. Previous Calculations
In the previous method of calculating the windbox assembly flow distri-
bution (Reference 1), the compartment loss coefficient was determined from
the equation
2
= KO+KD(I)
where KD(!) was specified as herein KO evaluated from test
values of the total secondary air flow and windbox/furnace AP.
Highly closed damper positions result in a very large value of
KD, as is seen in Figure 1, and a small error in this parameter
will result in a large variation in KO. Program runs with all
compartment dampers at or near the full open position yielded
values of KO consistent with the value presented herein, i.e.,
@ 100% open, Kn»0.1, K = K/10035
.2
from Equation (6), K/100%^ 1 + 1.7 * [£]
. 2
for existing geometries, 0<[g-] < 0.29
therefore, with KO^K/IOOX, 1 < KO <1.5
Program runs with one or more compartment dampers highly closed would
sometimes yield values of KO outside this range; in rare cases this
would result in operational difficulties.
REFERENCES
1. N. D. Brown, "COMPAIR, Burner-Compartment Air-Flow Distribution Com-
puter Program," Project No. 121029, September, 1971.
2. "Flow of Fluids Through Valves, Fittings, and Pipe,"
Crane Co., Technical Paper No. 409, May, 1942.
3. R. V. Giles, "Fluid Mechanics and Hydraulics," Schaum Publishing Co.,
1962.
4. P. S. Dickey & H. L. Coplan, "A Study of Damper Characteristics,"
Trans, of the ASME, February, 1942.
127
-------
5. N. D. Brown, "Windbox Compartment Flow Tests," Test Report 72-6,
Project No. 412003, March 2, 1972.
128
-------
DAMPER LOSS COEFFICIENT
VS.
POSITION
_ 2(PT - p
D 'l T2
% Open = (6/BO) x 100
(Q/A)
T1 = Total Pressure @ "1"
PT2 = Total Pressure @ "2"
R = Fluid Density
Q = Volume Rate of Flow
A = Flow Area
'xVx-x x x-x
/// / //
1 Blade
2 Blades
3 Blades
20
40 60
DAMPER POSITION - % OPEN
129
80
100
-------
AIR FLOW DISTRIBUTION TO WINDBOX COMPARTMENTS
ALABAMA POWER AND LIGHT CO., BARRY #2
EPA '73 - '74 TESTS
FLOW DISTRIBUTION FOR TEST NO. 5
PER CENT EXCESS AIR 22.7
COMPART-
MENT
(NO.)
1
2
3
4
5
6
7
8
9
10
FIRING
Yes
Yes
Yes
Yes
AREA WT. FLOW
(% OF TOTAL)
9.44
6.55
18.03
6.55
9.44
9.44
6.55
18.03
6.55
9.44
Firing Fuel Compartment Total Air Flow (%)
Air Flow Above Burner Zone (%) = 3.9
Air Flow to Burner Zone (% of Theor. Air) :
DAMPERS
(% OPEN)
60
20
100
20
100
100
20
100
20
100
= 33.55
117.91
ACTUAL FLOW
(% OF TOTAL)
7.8
8.39
16.37
8.39
8.64
8.64
8.39
16.37
8.39
8.64
FLOW DISTRIBUTION FOR TEST NO. 20
PERCENT EXCESS AIR 24.2
COMPART-
MENT
(NO.)
1
2
3
4
5
6
7
8
9
10
FIRING
Yes
Yes
Yes
AREA WT. FLOW
(% OF TOTAL)
9.
6.
.44
.55
18.03
6.55
.44
.44
.55
18.03
6.55
9.44
9.
9.
6.
DAMPERS
(% OPEN)
100
100
50
30
50
50
30
50
30
50
Firing Fuel Compartment Total Air Flow (%) = 30.82
Air Flow Above-Burner Zone (%) = 23.73
Air Flow to Burner Zone (% of Theor. Air) = 94.72
ACTUAL FLOW
(% OF TOTAL)
9.42
6.85
14.93
10.27
7.68
7.68
10.27
14.93
10.27
7.68
130
-------
COMPFLOM
Definition of Output
1. The "AREA WT. FLOW" is the ratio of the compartment free area to
the total free area of the corner; as such it is a realistic
approximation of the actual compartment (secondary) flow only when
all compartment dampers are full open.
2. The comparment "ACTUAL FLOW" is the ratio of the compartment mass
flow rate (including mill air if applicable) to the total mass flow
to the corner (see ANALYSIS, equation (7)).
3. The "FIRING FUEL COMPARTMENT TOTAL AIR FLOW" is the ratio of the
total mass flow rate to firing fuel compartments (including mill air
if applicable) to the total mass flow to the corner.
4. The "AIR FLOW ABOVE BURNER ZONE" is defined as the percentage of the
total mass flow rate supplied above the uppermost firing fuel com-
partment, less 50% of the flow to the compartment immediately above
it.
5. % Theoretical Air = (1- % Air Above Burner Zone)(1QO + % Exce$s A1r)
to Burner Zone.
131
-------
COMPARTMENT LOSS COEFFICIENT
VS.
DAMPER POSITION
K - 2(PT P
x" sy
(Q/Ar
PTx = Total Pressure @ "x"
Ps = Static Pressure (? "y"
R = Fluid Density
Q = Volume Rate of Flow
A = Nozzle Exit Area
A. _ n
B u-
25
20
15
10
_ Nozzle Exit Area
- compart. Inlet Area
K= 1 + (1.6 + K) x
40
60
LEGEND
SYMBOL
o
D
A/B
0.322
0.136
80
100
DAMPER POSITION - % OPEN
132
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-650/2-73-005-a
2.
3. RECIPIENT'S ACCESSION*NO.
4. TITLE AND SUBTITLE
Program for Reduction of NOx from Tangential
Coal-Fired Boilers, Phase n
5. REPORT DATE
June 1975
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Ambrose P. Selker
8. PERFORMING ORGANIZATION REPORT NO,
9. PERFORMING OR6ANIZATION NAME AND ADDRESS
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
10. PROGRAM ELEMENT NO.
1AB014; ROAP 21ADG-080
11. CONTRACT/GRANT NO.
68-02-1367
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Phase n Final: 7/73 - 3/75
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
is. ABSTRACT The reporf gives results of Phase II of a program to reduce the emission
of NOx from tangential coal-fired boilers. Results of Phase I, during which a suit-
able utility steam generator was selected to be modified for the Phase II studies,
were presented in final report EPA-650/2-73-005, dated August 1973. The Phase II
work included: the design, fabrication, and delivery of an overfire air system for the
test unit; the installation of test equipment; planning; and baseline, biased firing and
overfire air studies for NOx emission control while burning a Kentucky bituminous
coal type. These test programs included an evaluation of the effect of variations in
excess air, unit slagging, load, and overfire air on unit performance and emission
levels. The effect of biasing combustion air through various out-of-service fuel
nozzle elevations was also evaluated. The effect of biased firing and overfire air
operation on waterwall corrosion potential was evaluated during three 30-day baseline
biased firing, and overfire air corrosion coupon tests. Unit loading and waterwall
slag conditions had minimal effects on NOx emission levels. Reductions in excess
air levels and overfire air operation were found to be effective in reducing NOx
emission levels.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Nitrogen Oxides
Combustion Control
Coal
Boilers
Air Pollution Control
Stationary Sources
NOx Reduction
Tangential Firing
Combustion Modification
13B
07 B
21B
21D
13A
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
144
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
133
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