U.S. Environmental Protection Agency Industrial Environmental Research EPA-600/7-77-'117
Office* of Research and Development Laboratory
Research Triangle Park. North Carolina 27711 October 11 977
OVERFIRE AIR TECHNOLOGY
FOR TANGENTIALLY FIRED
UTILITY BOILERS BURNING
WESTERN U.S. COAL
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S.
Environmental Protection Agency, have been grouped into seven series.
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1. Environmental Health Effects Research
2. Environmental Protection Technology
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6. Scientific and Technical Assessment Reports (STAR)
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This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from
the effort funded under the 17-agency Federal Energy/Environment
Research and Development Program. These studies relate to EPA's
mission to protect the public health and welfare from adverse effects
of pollutants associated with energy systems. The goal of the Program
is to assure the rapid development of domestic energy supplies in an
environmentally—compatible manner by providing the necessary
environmental data and control technology. Investigations include
analyses of the transport of energy-related pollutants and their health
and ecological effects; assessments of, and development of, control
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This document is available to the public through the National Technical
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EPA-600/7-77-117
October 1977
OVERFIRE AIR TECHNOLOGY
FOR TANGENTIALLY FIRED UTILITY
BOILERS BURNING WESTERN U.S. COAL
by
Richard L. Burrington, John D. Cavers,
and Ambrose P. Selker
C-E Power Systems
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Contract No. 68-02-1486
Program Element No. EHE624A
EPA Project Officer David G. Lachapelle
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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FIELD TEST PROGRAM TO STUDY STAGED
COMBUSTION TECHNOLOGY FOR TANGENTIALLY
FIRED UTILITY BOILERS BURNING WESTERN U.S. COAL TYPES
BY
RICHARD L. BURRINGTON
JOHN D. CAVERS
AMBROSE P. SELKER
C-E POWER SYSTEMS
COMBUSTION ENGINEERING, INC.
WINDSOR, CONNECTICUT 06095
CONTRACT NO. 68-02-1486
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
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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. Environmental
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 Including
the warranties of fitness for a particular purpose or merchantabili-
ty, with respect to the accuracy, completeness, or usefulness of the
information contained 1n this report, or that the use of any infor-
mation, apparatus, method, or process disclosed 1n 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."
11
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ABSTRACT
This report presents the findings of a program designed to Investigate and
evaluate the effectiveness of employing overflre air as a method of reducing
NOX emission levels from tangentlally fired boilers burning Western U.S. coal
types. This work was performed under the sponsorship of the Office of Re-
search and Development of the Environmental Protection Agency (Contract 68-
02-1486). The results of this program are compared with the results obtained
under Phase II "Program for Reduction of NOx from Tangentlally Coal Fired
Boilers" (Contract 68-02-1367).
These test programs Investigated the effect that variations In excess air,
unit slagging, load and overflre air had on unit performance and emission lev-
els. Additionally, the effect of biasing combustion air through various out-
of-service fuel nozzle elevations was also Investigated. The effect of over-
fire air operation on waterwall corrosion potential was evaluated during thir-
ty (30) day baseline and overflre air corrosion coupon tests. The results of
the corrosion coupon tests Indicate that overflre air operation for low NOx
optimization will not result 1n significant Increases 1n corrosion coupon de-
gradation.
Overflre air operation and reductions 1n excess air levels were found to be
effective 1n reducing NOX emission levels. NOX reductions of 20 to 30 percent
were obtained when operating with 15 to 20 percent overflre air. These reduc-
tions occurred with the boilers operating at a total unit excess air of ap-
proximately 15 to 25 percent as measured at the economizer outlet. Unit load-
Ing exhibited a minimal effect on NOX emission levels. Waterwall slag condi-
tions were found to have wide and Inconsistent effects on NOx emission levels.
111
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CONTENTS
PAGE NO.
Disclaimer 11
Abstract 111
List of Figures vll
List of Data Sheets x1
Conversion Table xi11
List of Abbreviations and Symbols xlv
Acknowledgment xv
Section I
Introduction 1
Conclusions
Normal Operation 3
Biased Firing Operation 3
Overflre Air Operation 3
Recommendations 5
Summary
Baseline Operation Study 6
Biased Firing Operation Study 11
Overflre A1r Operation Study 11
Boiler Performance 22
Waterwall Corrosion Coupon Evaluation 22
Section II - EPA Contract 68-02-1486
Objectives
Task I - Unit Selection 26
Task II - Test Planning & Fabrication of Test Equipment .... 26
Task III - Installation of Instrumentation 27
Task IV - Baseline Operation 27
Task V - Biased Firing Operation 28
Task VI - Overflre A1r Operation 30
Task VII - Preparation of Test Report and Analysis of Data ... 32
Discussion
Task I - Unit Selection 33
Task II - Test Planning & Fabrication of Test Equipment .... 37
Task III - Installation of Instrumentation 37
Columbia Energy Center, Unit II
Tasks IV, V & VI - Test Data Acquisition and Analysis 41
Task IV - Baseline Operation Study 45
Load and Excess A1r Variation - Clean Furnace 45
Load and Excess A1r Variation - Moderately Dirty Furnace . . 46
Load and Excess A1r Variation - Dirty Furnace 47
Analysis of Results 47
Task V - Biased Firing Study 48
Fuel Elevations Out of Service Variation 48
iv
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CONTENTS (Cont.)
PAGE NO.
Analysis of Results 53
Task VI - Overfire A1r Operation Study 56
Excess Air and Overfire Air Rate Variation 56
Overfire A1r Register Tilt Variation 58
Load and Furnace Uaterwall Deposit Variation at Optimum
Conditions 59
Analysis of Results 60
Furnace Performance 65
Waterwall Corrosion Coupon Evaluation 71
Huntington Station, Unit #2
Tasks IV, V & VI - Test Data Acquisition and Analysis 79
Task IV - Baseline Operation Study 83
Load and Excess A1r Variation - Clean Furnace 83
Load and Excess A1r Variation - Moderately Dirty Furnace . . 83
Load and Excess A1r Variation - Dirty Furnace 84
Analysis of Results 85
Task V - Biased Firing Operation Study 89
Fuel Elevations Out-of-Service Variation 89
Analysis of Results 91
Task VI - Overfire A1r Operation Study 95
Excess Air and Overfire Air Rate Variation 95
Overfire Air T1lt Variation 98
Load and Furnace Waterwall Deposit Variation at Optimum
Conditions 99
Analysis of Results 100
Waterwall Corrosion Coupon Evaluation 105
Section III - EPA Contract 68-02-1367
Alabama Power Company, Barry Station, Unit #2
Introduction 115
Conclusions
Normal Operation 117
Overfire Air Operation 117
Objectives
Task I 119
Task II 119
Task III 119
Task IV 120
Task V 120
Task VI 120
Task VII 120
Task VIII 120
Task IX 120
Discussion
Task IV & V - Baseline and Biased Firing Test Programs .... 122
Test Data Acquisition and Analysis 122
Task IV - Baseline Test Study 124
Load and Excess A1r Variation . . 124
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CONTENTS (Cont.)
PAGE NO.
Furnace Wall Deposit Variation 131
Task V - Biased Firing Study 131
Fuel Elevations Out-of-Service Variation 131
Task VIII - Unit Optimization Study 135
Load and Excess Air Variation 135
Furnace Wall Deposit Variation 139
OFA Location, Rate, and Velocity Variation 144
OFA Tilt Variation 148
Load Variation at Optimum Conditions 153
Furnace Performance 157
Waterwall Corrosion Coupon Evaluation 157
Section IV - Application Guidelines
Introduction 170
Conclusions 171
Recommendations
Existing Steam Generating Units 172
New Steam Generating Units 172
Discussion
Design and Description of OFA Systems 174
Field Test Program 174
Exploratory Field Test Program - Existing Units 175
Effect on Unit Performance 176
Economic Evaluation 177
Applicability
Existing Steam Generating Units 181
New Steam Generating Units 181
References 182
Appendices
Appendix A - Wisconsin Power & Light Company
Test Data & Results 183
Appendix B - Utah Power & Light Company
Test Data & Results 242
Appendix C - Alabama Power Company
Test Data & Results 289
Appendix D - Compflow
Program Description 301
vi
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FIGURES
FIGURE PAGE NO.
(Section I)
1 N09 vs. Theoretical Air, Baseline Study, Maximum Load . . 8
2 N0« vs. Theoretical A1r, Baseline Study, 1/2 Load .... 9
3 N0« vs. Main Steam Flow, Baseline Study 10
4 CO vs. Theoretical A1r, Baseline Study, Maximum Load . . 12
5 Carbon Heat Loss vs. Theoretical A1r, Baseline Study
Maximum Load 13
6 Fuel Elevation Out-of-Service vs. N09, Biased Firing
Study f 14
7 N09 vs. Theoretical Air, Biased Firing Study, Maximum
^Study 15
8 N09 vs. OFA Damper Opening, Overflre A1r Study 17
9 NO, vs. Theoretical A1r, Overflre A1r Study,
^Test Series 1 18
10 N02 vs. T1lt Differential, Overflre A1r Study 19
11 NO, vs. Theoretical A1r, Overflre A1r Study,
*Test Series 2 20
12 NO, vs. Theoretical A1r, Overflre A1r Study,
^Test Series 3 21
13 Unit Efficiency vs. Excess A1r, Maximum Load 23
14 ' Corrosion Probe Assembly Drawing 24
(Section II)
15 Typical Windbox of Tangential Firing System 34
16 Unit Side Elevation - Columbia Energy Center,
No. 1 35
17 Unit Side Elevation - Huntington Station,
No. 2 36
Section II: Columbia Energy Center1, Unit #1
18 Furnace Waterwall Deposit Pattern, Clean Furnace .... 43
19 Furnace Waterwall Deposit Pattern, Moderate Slag
Furnace 44
20 Furnace Waterwall Deposit Pattern, Heavy Slag
Furnace 45
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FIGURES (Cont.)
FIGURE PAGE NO.
21 NCL vs. Theoretical Air, Baseline Study 48
22 CCTvs. Theoretical A1r, Baseline Study 49
23 Carbon Heat Loss vs. Theoretical Air, Baseline Study . . 50
24 Unit Efficiency vs. Excess A1r, Baseline Study 52
25 N02 vs. Theoretical A1r, Biased Firing Study 54
26 Fuel Elevation Out-of-Service vs. NO,, Biased Firing
Study f 55
27 Unit Efficiency vs. Excess Air, Biased Firing Study ... 57
28 N02 vs. Theoretical A1r, Overfire A1r Study 61
29 CO vs. Theoretical A1r, Overfire A1r Study 62
30 Carbon Heat Loss vs. Theoretical A1r, Overfire A1r
Study 63
31 N02 vs. Difference in T1lt, Overfire A1r Study 64
32 Unit Efficiency vs. Excess Air, Overfire A1r Study ... 66
33 Chordal Thermocouple Locations 67
34 Elevation vs. Furnace Heat Absorption - Baseline
Study 68
35 Elevation vs. Furnace Heat Absorption - Biased
Firing Study 69
36 Elevation vs. Furnace Heat Absorption - Overfire
A1r Study 70
37 Water-wall Corrosion Probe Locations, Columbia #1 .... 72
38 Typical Corrosion Probe Temperature Range 73
39 Gross MW Loading vs. Time - Baseline Corrosion Probe
Study 74
40 Gross MW Loading vs. Time - Overfire Air Corrosion
Probe Study 75
41 As-Fired Ash and Coupon Deposit Analysis, Baseline
Study 77
42 As-Fired Ash and Coupon Deposit Analysis, Overfire
Air Study 78
Section II: Huntington Station, Unit #2
43 Furnace Waterwall Deposit Pattern - Clean Furnace .... 80
44 Furnace Waterwall Deposit Pattern - Moderate Slag
Furnace 81
45 Furnace Waterwall Deposit Pattern - Heavy Slag
Furnace 82
46 N02 vs. Theoretical Air, Baseline Study 86
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FIGURES (Cont.)
FIGURE PAGE NO.
47 CO vs. Theoretical A1r, Baseline Study 87
48 Carbon Heat Loss vs. Theoretical Air, Baseline Study . . 88
49 Unit Efficiency vs. Excess Air, Baseline Study 90
50 N02 vs. Theoretical A1r, Biased Firing Study 92
51 Fuel Elevation Out-of-Serv1ce vs. N09, Biased Firing
Study f 93
52 CO vs. Theoretical Air, Biased Firing Study 94
53 Carbon Heat Loss vs. Theoretical Air, Biased Firing
Study 96
54 Unit Efficiency vs. Excess A1r, Biased Firing Study ... 97
55 N02 vs. Theoretical A1r, Overfire A1r Study 101
56 CO vs. Theoretical A1r, Overfire A1r Study 102
57 Carbon Heat Loss vs. Theoretical A1r, Overfire A1r
Study 103
58 N02 vs. Tilt Differential, Overfire A1r Study 104
59 Unit Efficiency vs. Excess A1r, Overfire A1r Study ... 106
60 Waterwall Corrosion Probe Locations, Huntlngton Station,
No. 2 107
61 Typical Corrosion Probe Temperature Ranges, Huntlngton
Station, No. 2 108
62 Gross MW Loading vs. Time - Baseline Corrosion Probe
Study 109
63 Gross MW Loading vs. Time - Overfire A1r Corrosion
Probe Study 110
64 As-Fired Ash and Coupon Deposit Analysis, Baseline
Study 113
65 As-Fired Ash and Coupon Deposit Analysis, Overfire Air
Study 114
Section III: Barry Station, Unit #3
66 Unit Side Elevation, Barry Station, No. 2 116
67 Schematic Overfire Air System, Barry Station, No. 2 ... 121
68 Gaseous Emissions Test System 123
69 Waterwall Corrosion Probe Locations, Barry Station,
No. 2 125
70 Typical Corrosion Probe Temperature Range, Barry
Station, No. 2 126
71 NOg vs. Theoretical Air, Baseline Study 127
72 CO vs. Theoretical A1r, Baseline Study 128
73 Percent Carbon Loss vs. Theoretical Air, Baseline
Study 129
74 Unit Efficiency vs. Unit Excess A1r 130
75 Furnace Slag Pattern - Clean Furnace 132
76 Furnace Slag Pattern - Moderate Slag Furnace 133
1x
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FIGURES (Cont.)
FIGURE PAGE NO.
77 Furnace Slag Pattern - Heavy Slag Furnace 134
78 N02 vs. Theoretical Air, Biased Firing Study 136
79 CO vs. Theoretical Air, Biased Firing Study 137
80 Percent Carbon Loss vs. Theoretical Air, Biased
Firing Study 138
81 N02 vs. Theoretical Air, Overfire A1r Study 140
82 CO vs. Theoretical Air, Overfire Air Study 141
83 Percent Carbon Loss vs. Theoretical Air, Overfire
Air Study 142
84 Unit Efficiency vs. Excess Air 143
85 Furnace Slag Pattern - Clean Furnace 145
86 Furnace Slag Pattern - Moderate Slag Furnace 146
87 Furnace Slag Pattern - Heavy Slag Furnace 147
88 N02 vs. Theoretical Air, Overfire Air Study 149
89 CO vs. Theoretical Air, Overfire Air Study 150
90 Percent Carbon Loss vs. Theoretical Air, Overfire
Air Study 151
91 N02 vs. Tilt Differential, Overfire Air Study 152
92 Percent Carbon Loss vs. Tilt Differential, Overfire
Air Study 154
93 CO vs. Tilt Differential, Overfire A1r Study 155
94 N02 vs. Main Steam Flow 156
95 Chordal Thermocouple Locations on Furnace Water-walls . . 158
96 Average Centerline Absorption Profile - Test 14 .... 159
97 Average Centerline Absorption Profile - Test 24 .... 160
98 Average Centerline Absorption Profile - Test 33 .... 161
99 Average Centerline Absorption Profile - All Tests ... 162
100 Gross MW Loading vs. Time - Baseline Corrosion Probe
Study 164
101 Gross MW Loading vs. Time - Biased Firing Corrosion
Probe Study 165
102 Gross MW Loading vs. Time - Overfire A1r Corrosion
Probe Study 166
103 Ash Analysis 169
Section IV: Application Guidelines
104 Overfire A1r System Costs 178
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DATA SHEETS
SHEET PAGE NO.
Al, A2 Baseline Operation Study - Emissions Test Data,
Columbia #1 184, 185
A3, A4 Biased Firing Operation Study - Emissions Test Data,
Columbia #1 186, 187
AS, A6 Overfire A1r Operation Study - Emissions Test Data,
Columbia #1 188, 189
A7, A8 Baseline Operation Study - Test Data,
Columbia #1 190, 191
A9, A10 Biased Firing Operation Study - Test Data,
Columbia #1 192, 193
All - A13 Overfire A1r Operation Study - Test Data,
Columbia #1 194-196
A14, A15 Baseline Operation Study - Test Results,
Columbia #1 197, 198
A16, A17 Biased Firing Operation Study - Test Results,
Columbia #1 199, 200
A18 - A21 Overfire A1r Operation Study - Test Results,
Columbia #1 201-204
A22 - A25 Baseline Operation Study - Waterwall Absorption
Rates, KW/m2, Columbia #1 205-208
A26 - A29 . Biased Firing Operation Study - Waterwall Absorption
Rates, KW/m2, Columbia #1 209-212
A30 - A35 Overfire A1r Operation Study - Waterwall Absorption
Rates, KW/mz, Columbia #1 213-218
A36 - A41 Baseline Operation Study - Board & Computer Data,
Columbia #1 219-224
A42 - A47 Biased Firing Operation Study - Board & Computer Data,
Columbia #1 225-230
A48 - A56 Overfire Air Operation Study - Board & Computer Data,
Columbia #1 231-239
A57 Waterwall Corrosion Coupon Data Summary -
Baseline Test, Columbia #1 240
A58 Waterwall Corrosion Coupon Data Summary -
Overfire A1r Test, Columbia #1 241
Bl, B2 Baseline Operation Study - Emissions Test Data,
Huntlngton #2 243, 244
B3, B4 Biased Firing Operation Study - Emissions Test Data,
Huntlngton #2 245, 246
B5, B6 Overfire A1r Operation Study - Emissions Test Data,
Huntlngton #2 247, 248
B7, B8 Baseline Operation Study - Test Data,
Huntlngton #2 249, 250
B9, BIO Biased Firing Operation Study - Test Data,
Huntlngton #2 251, 252
xl
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DATA SHEETS (Cont.)
SHEET PAGE NO.
Bll - B13 Overflre A1r Operation Study - Test Data,
Huntlngton #2 253-255
B14 - B17 Baseline Operation Study - Test Results,
Huntlngton #2 256-259
B18, B19 Biased Firing Operation Study - Test Results,
Huntlngton #2 260, 261
B20 - B23 Overflre A1r Operation Study - Test Results,
Huntlngton #2 262-265
B24 - B29 Baseline Operation Study - Board & Computer Data,
Huntlngton #2 266-271
B30 - B35 Biased Firing Operation Study - Board & Computer Data,
Huntlngton #2 272-277
B36 - B44 Overflre Air Operation Study - Board & Computer Data,
Huntlngton #2 278-286
B45 Waterwall Corrosion Coupon Data Summary -
Baseline Test, Huntlngton #2 287
B46 Waterwall Corrosion Coupon Data Summary -
Overflre A1r Test, Huntlngton #2 288
Cl NOx Test Data Summary - Baseline Study Before
Modification, Barry #2 290
C2 NOx Test Data Summary - Biased Firing Study
Barry #2 291
C3 NOx Test Data Summary - Baseline Study After
Modification, Barry #2 292
C4 NOX Test Data Summary - OFA Location, Rate and
Velocity Variation, Barry #2 293
C5 NOx Test Data Summary - OFA T1lt and Load Variation,
Barry #2 294
C6 Waterwall Absorption Rates, kg-cal/hr-cm2 -
Right Wall Center-line Tube Rates, Barry #2 295
C7 Waterwall Absorption Rates, kg-cal/hr-cm2 -
Front Wall Center!1ne Tube Rates, Barry #2 296
C8 Waterwall Absorption Rates, kg-cal/hr-cm2 -
Right Wall, Rear Wall, Left Wall, Front Wall,
Barry #2 297
C9 Waterwall Corrosion Coupon Data Summary -
Baseline Test, Barry #2 298
CIO Waterwall Corrosion Coupon Data Summary -
Biased Firing Test, Barry #2 299
C11 Waterwall Corrosion Coupon Data Summary -
Overflre Air Test, Barry #2 300
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CONVERSION FACTORS
SI METRIC UNITS TO ENGLISH UNITS
To Convert From
kg/s
ng/J
MJ/s
ug/J
kJ/kg
MPa
KW/m2
To
103LB/HR
LB/106BTU
106BTU/HR
LB/106BTU
BTU/LB
PSIA
I6BTU/HR-FT2
Multiply By
7.936640
2.326E-3
3.412141
2.326
4.299226E-1
1 .450377E+2
3.16998E-1
ENGLISH UNITS TO SI METRIC UNITS
To Convert From
103LB/HR
PSIA
LB/106BTU
LB/106BTU
106BTU/HR
BTU/LB
106BTU/HR-FT2
To
kg/s
MPa
ng/0
ug/J
MJ/s
kJ/kc
KW/m2
Multiply By
1.259979E-01
6.894757E-3
4.29922E+2
4.29922E-1
2.930711E-1
2.326
3.154594
°F = 1.8(°C)+32C
X111
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ABBREVIATIONS AND SYMBOLS
Abbreviations
Definitions
N0x
THC
NA
X-S
ww
MCR
TA
EA
FFZ
NSPS
Oxides of Nitrogen
Total Hydrocarbons
Not Available
Excess
Waterwal1
Maximum Continuous Rating
Theoretical Air to Fuel Firing Zone
Excess Air
Fuel Firing Zone
New Source Performance Standard
Symbol s
N02
CO
°2
S02
CO,
Nitrogen Dioxide
Carbon Monoxide
Oxygen
Sulfur Dioxide
Carbon Dioxide
x1v
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ACKNOWLEDGMENTS
The authors wtsh to acknowledge the constructive participation of Mr. D. G.
Lachapelle, EPA Project Officer, In providing the program direction necessary
for Its successful completion.
The cooperation and active participation of the following companies and, in
particular, the personnel at the respective plants were essential to success-
fully conducting the various test program phases.
1. Alabama Power Company
Barry Station, Unit #2
2. Utah Power and Light Company
Huntlngton Station, Unit #2
3. Wisconsin Power and Light Company
Columbia Station, Unit #1
The results presented 1n this report represent the effort of many Combustion
Engineering, Inc. personnel whose participation was required for Its success-
ful completion. In particular the technical contributions made by R. F. Swope,
R. W. Robinson, E. R. LePage, L. A. Ratte, M. S. Hargrove and K. M. Cerrato
are gratefully acknowledged.
xv
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SECTION I
INTRODUCTION
The emphasis on Improved quality of the environment has led to the design of
coal fired steam generators with the capability of using overflre air to re-
duce and control NOX emission levels. For tangentially fired steam genera-
tors, the overfire air 1s admitted through registers 1n an extended wlndbox.
Previous work with coal fired steam generators has demonstrated that overfire
air simulation with tangential firing 1s effective in reducing NOX emission
levels by as much as 50 percent of uncontrolled values.
Some of this previous work was performed by Combustion Engineering, Inc. under
an EPA-sponsored two-phase program to Identify, develop and recommend the most
promising combustion modification techniques for the reduction of NOx emis-
sions from tangentially coal fired utility boilers with a minimum Impact on
unit performance.
This two-phase program is briefly described as follows:
Phase I (performed under EPA Contract 68-02-0264) consisted of selecting
a suitable utility boiler to be modified for experimental studies to
evaluate NOX emission control. Phase I also included the preparation of
preliminary drawings, a detailed preliminary test program, a cost esti-
mate and detailed schedule of the program phases and a preliminary appli-
cation economic study Indicating the cost range of a variety of combus-
tion modification techniques applicable to existing and new boilers [1]*.
Phase II (performed under EPA Contract 68-02-1367) consisted of modifying
and testing the utility boiler selected in Phase I to evaluate overfire
air and biased firing as methods for NOX control. This phase also In-
cluded:
1. The completion of detailed fabrication and erection drawings,
2. Installation of analytical test equipment,
3. Updating of the preliminary test program,
4. A baseline operation study,
5. Analysis and reporting of test results and,
Numbers in brackets refer to references at end of report.
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6. 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 #2 of the
Alabama Power Company [2].
The majority of this previous work has been conducted on units firing Eastern
or Midwestern bituminous coals.
In recent years, the utilization of Western U.S. coals as an energy source has
Increased significantly. The Incentives for their use are the low sulfur con-
tent conducive to low SOX emission levels and the large available reserves
that may be used In Heu of oil and natural gas which are 1n short supply.
Based on Phase II recommendations to Investigate Western coal types which were
becoming a predominate source of fuel for electric generating stations, this
study, EPA Contract 68-02-1486, was contracted by Combustion Engineering,
Inc.'s, Field Testing and Performance Results Department.
The objective of this program was to Investigate the effectiveness of employ-
Ing overflre air as a method of reducing NOX emission levels from tangentially
fired boilers burning Western U.S. coals. The effect of reducing NOX emission
levels was evaluated with respect to unit performance, unit efficiency, water-
wall corrosion rates and related gaseous emission levels.
Specifically, the factors considered in realizing this objective were as fol-
lows:
1. The program was conducted on two units designed with overfire air
registers, the first unit firing a Western U.S. subbituminous coal
and the second unit firing a Western U.S. bituminous coal.
2. The test program evaluated baseline, biased firing and overfire air
operation and consisted of approximately 60 steady state tests per
unit and two months of waterwall corrosion rate studies per unit.
3. The effect of NOX control methods on all gaseous constituents was
evaluated during all tests. The following constituents were mea-
sured: NOX* SOX, CO, THC, 02 and particulate samples for unburned
combustible analysis.
4. The effects of NOX control methods on steam generator performance
were evaluated during all tests by obtaining necessary temperatures,
pressures, flows, etc., with calibrated equipment.
5. Based on the results of this program, conclusions and recommendations
were made pertaining to the acceptable application of staged firing
with respect to NOX emission levels, corrosion rates and unit opera-
tion for each type of coal tested.
6. The results of this program were compared with the results obtained
under Contract 68-02-1367 for a unit equipped with an overfire air
system not Included in the original design.
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CONCLUSIONS
NORMAL OPERATION
1. Under normal unit operation without overfire air, excess air variation was
found to have the greatest single effect on NOX emission levels, increas-
ing NOx with increasing excess air. An average increase of 6.4 ng/J for
each one percent change in excess air (EA) was observed over a normal op-
erating range of 15 to 25 percent EA for the three units.
2. Unit loading was found to have a limited effect on NOX and CO emission
levels and carbon heat loss.
3. Variations in furnace waterwall deposits had wide and inconsistent effects
on NOx ^nd CO emission levels and carbon heat loss.
4. 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 24 ng/J were considered unacceptable for the
purposes of this program.
BIASED FIRING OPERATION
Biased firing was found to be most effective when the top fuel firing eleva-
tion was removed from service. This mode of operation simulates overfire air
operation. However, while biased firing is a potentially effective method of
NOX control, it may necessitate a reduction in unit loading. Therefore, biased
firing is not considered to be the most desirable method of NOX control.
OVERFIRE AIR OPERATION
1. NOX reductions of 20 to 30 percent were obtained with 15 to 20 percent
overfire air when operating at a total unit excess air of approximately 15
to 25 percent as measured at the economizer outlet.
This condition would provide an average fuel firing zone stoic hi ometry of
95 to 105 percent of theoretical air. Stoichiometries below this range did
not result in large enough decreases in NOX levels to justify their use.
2. When using overfire air as a means of decreasing the theoretical air to the
fuel firing zone, the combustible loss and CO emission levels were less af-
fected than when operating with low excess air since during overfire air
operation, acceptable overall excess air levels are maintained. Reduction
in operating excess air levels for NOX control is often precluded because
of the ash properties of the coal being fired. Further, as coal is an ex-
tremely complex fuel characterized by wide variations in properties, even
-------
between different seams In the same mine area, excess air Is the only
means available to the operator to compensate for departures from the de-
sign coal. For the above reasons, the application of overflre air rather
than low excess air firing is recommended on coal fired steam generators.
3. Furnace performance as indicated by waterwall slag accumulations, visual
observations and absorption rates were not affected by overflre air opera-
tion.
4. At Alabama Power Company's Barry Station Unit #2 where the overfire air
port could not be installed as a windbox extension, test results indicated
that the center!ine of the overfire air port should be kept within 3 me-
ters of the centerline of the top fuel elevation. Distances greater than
3 meters did not result in significantly decreased NOX levels. On new de-
signs, and whenever possible on field modified units, it is preferable to
introduce the overfire air through a vertical extension of the windbox
rather than through isolated ports displaced above the windbox. The ef-
fectiveness of introducing overfire air through an extended windbox is dem-
onstrated via the tests conducted on Wisconsin Power & Light, Columbia #1
and Utah Power & Light, Huntingdon Canyon #2. The overfire air compart-
ments on an extended windbox tilt independently of the remainder of the
windbox to permit adjustments in the "point" of overfire air introduction.
5. Optimum overflre air operation was obtained when the overfire air registers
were tilted away from the fuel nozzles. NOx control was nearly as effec-
tive when the overfire air registers were tilted with the fuel nozzles.
NOX emission levels Increased when the overflre air registers and fuel noz-
zles were directed toward each other. At Alabama Power Company's Barry
Station Unit #2, flame stability decreased when the overflre air registers
and fuel nozzles were directed away from each other by more than 20 to 25
degrees. This phenomena was not observed at either Wisconsin Power and
Light Company's Columbia Energy Center Unit #1 or at Utah Power and Light
Company's Huntingdon Station Unit #2. With the overflre air tilts fixed in
a horizontal position, acceptable unit operation was obtained, however, NO
levels varied with fuel nozzle position.
6. The results of the thirty day baseline and overflre air corrosion coupon
runs indicate that the overflre air operation for low NOx optimization did
not result in significant increases in corrosion coupon degradation. Addi-
tional long-term operation studies will be required to verify these observa-
tions.
7. The average NOX levels experienced during the thirty day overfire air stud-
ies were as follows: Barry #2-172 ng/J, Huntington Canyon #2-231 ng/J and
Columbia #1-294 ng/J. The emission levels for Columbia #1 reflect operat-
ing conditions beyond the control of the test program.
8. Variables normally used to control normal boiler operation should not be con-
sidered as NOX controls with coal firing. These variables include unit load,
nozzle tilt, pulverizer fineness, windbox dampers and total excess air-
9. Overall unit efficiency was not affected by overflre air operation.
-------
RECOMMENDATIONS
This program was designed to Investigate the effects of the following process
variables and combustion modifications on NOX emission levels 1n existing steam
generating units:
Process Variables
Excess A1r Level
Unit Load
Furnace Waterwall Deposits
Combustion Modifications
Biased Firing
Overflre A1r Firing
The effects of furnace waterwall deposits could not be adequately documented.
Several Investigations have indicated that furnace waterwall deposits can ef-
fect NOx emission levels. Therefore, this process variable should be Investi-
gated further.
The effect of fuel nitrogen on NOX formation was not Investigated per se in this
program. However, as the effect of fuel nitrogen 1s becoming of increasing
concern, its contribution to NOX emission levels in coal fired boilers should
be quantified.
Additionally, the results of the corrosion probe evaluations Indicate that the
coupon weight losses encountered during a thirty day evaluation 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.
-------
SUMMARY
Percent excess air, bulk flame temperature and residence time of the combustion
gases all directly affect the formation of oxides of nitrogen (NOX). The two
oxides of nitrogen which are of significance are nitric oxide (NO) and nitrogen
dioxide (NOg). NO Is the more predominant form and accounts for 90 to 95 per-
cent of the total NOX generated 1n a utility boiler. Once it enters the at-
mosphere NO is converted to N02, which is more hazardous to human health. Most
references In this report to NO? are actually refering to total nitrogen oxides.
This method of expressing NOx as N02 Is 1n agreement with EPA practice.
While It is not the subject of this report, it should be noted that NOX gener-
ated by the combustion of coal can occur by two mechanisms. One mechanism Is
by the oxidation of atmospheric nitrogen (thermal NOx) while the other mecha-
nism Involves the conversion of fuel bound nitrogen (fuel NOx). The formation
of thermal NOX 1s known to be dependent on flame temperature, oxygen concen-
tration in the combustion zone and residence time at temperature.
Several Investigators have observed that the formation of fuel NOx is responsi-
ble for a significant portion of the total NOX emitted from the combustion pro-
cess [3,4,5,6]. The reaction can take place at a much lower flame temperature
and has also been shown to be dependent on the oxygen concentration in the com-
bustion zone. The coals being fired at Alabama Power Company's Barry #2 and
Utah Power and Light Company's Huntington Canyon #2 had nitrogen analysis rang-
ing from 1.1 to 1.3 percent nitrogen by weight. Wisconsin Power and Light Com-
pany's Columbia #1 had an analysis ranging from 0.6 to 0.8 percent nitrogen by
weight. Preliminary plots of N0£ versus the coal nitrogen content did not show
any correlation between N02 and coal nitrogen content. Any correlation would
probably have been masked by the limited range of the nitrogen content of the
coals being fired and by the variation in excess air levels.
BASELINE OPERATION STUDY
It has been well documented that the formation of NOX is dependent upon excess
air and the oxygen concentration 1n the combustion zone. The oxygen concentra-
tion in the combustion zone is directly related to excess air and also to the
theoretical air to the fuel firing zone (TA). TA Is a computational tool used
by Combustion Engineering, Inc. which accounts for variations 1n position and
leakage in all windbox compartment dampers.* This method allows for the ac-
counting of leakage 1n the compartments above the top active fuel compartment
and, therefore, 1s a better approximation of the actual air (I.e., oxygen)
available for combustion 1n the fuel firing zone than total excess air (EA).
Therefore, all parameters are plotted versus theoretical air to the fuel firing
* See Appendix D.
-------
zone rather than the total excess air. For the baseline operation study the
TA Is essentially the same as the total air since no air was diverted through
the overflre air registers.
Figure 1 ts a plot of N02* versus TA for the full load baseline tests at Ala-
bama Power Company's Barry Station Unit #2, Utah Power and Light Company's
Huntlngton Canyon Station Unit #2 and Wisconsin Power and Light Company's Co-
lumbia Energy Center Unit #1. As shown by this figure, NO? Is proportional
to TA and, therefore, to oxygen concentration in the fuel firing zone and ex-
cess air.
Figure 2 is a plot of N02 versus TA for the half (1/2) load tests for all
three units. As with the full load tests, the half (1/2) load tests also show
increasing N0£ emission levels with Increasing TA. Comparison of the full and
half (1/2) load tests show that at similar theoretical air levels, the N02
emission levels for the half (1/2) load tests are lower than or equal to the
NOg levels for the full load tests. The effect of load is better shown in
Figure 3, where emission levels are plotted versus theoretical air level for
full, three quarter and one half load baseline tests. This plot shows that in
some, but not all cases, N02 levels tend to increase with unit loading. It can
be shown that occasionally the opposite trend was observed.
While NOp levels correlated well with TA, attempts to find what effect fuel
nozzle tilt and furnace condition had on NOX formation were not as successful.
Changes in fuel nozzle tilt were found to produce wide and inconsistent varia-
tions in N02 emission levels.
Other investigators have found that increased slagging of the furnace walls
tends to increase NOX by increasing the furnace outlet temperature and, there-
fore, the bulk flame temperature £3,5]. Bulk flame temperature Increases due
to the reduced heat transfer from the hot combustion gases to the water-cooled
furnace wall's. The amount of reduction in heat transfer may depend greatly up-
on the type of slag on the furnace walls. The furnace conditions for the full
and half (1/2) load tests are indicated on Figures 1 and 2. Furnace condition
was found to have wide and inconsistent effects on N02 emission levels for the
tests run on the subject boilers. The results obtained showed that for some
tests an increase in furnace slag resulted in an increase in N02 emission lev-
els while no effect was observed for other tests. Furnace condition was'mea-
sured by visual observation of the furnace waterwalls. Since waterwall absorp-
tion is closely related to furnace condition, an attempt was made to correlate
N02 emission levels with furnace waterwall absorption and therefore with furnace
condition. This attempt produced no meaningful results. The lack of correla-
tion between N02 emission levels and furnace condition might be partially at-
tributed to the fact that the visual observation of furnace waterwall deposits
is very subjective. Also, the contribution of fuel nitrogen may be dominant in
the formation of N0¥.
A
In this report, oxides of nitrogen (NOX) are expressed as nitrogen dioxide
(N02) to be consistent with the requirements of the New Source Performance
Standards, Federal Register Vol. 35, No. 247, Part II, Dated December 31, 1971
-------
00
_..J .4 -.+_
110 115 120 125 130 135
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 1: N09 vs. theoretical air, baseline study, maximum load
140
LEGEND
OAlabama Power Co.
Barry #2
Avil scons In Power &
Light Co.
Columbia #1
Qutah Power & Light Co.
Huntington #2
Furnace Condition
LJClean
[•Moderately Dirty
•Dirty
-------
CM
O
115
125 130 135 140 145 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
LEGEND
OAlabama Power Co., Barry #2 & Clean
QWisconsin Power & Light Co., Columbia #1 ^Moderately Dirty
£utah Power & Light Co., Huntington #2 ADirty
Figure 2: N02 vs. theoretical air, baseline study, 1/2 load
155
-------
100 110 120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 3: N02 vs. unit loading, baseline study
LEGEND
© Alabama Power Co.
Barry #2
^ Wisconsin Power &
Light Co.
Columbia #1
(3 Utah Power & Light Co,
Huntington Canyon #2
Unit Loading
OFull
QThree Quarter
A One Half
-------
The effect of reducing TA on CO emission levels and carbon heat loss 1s shown
on Figures 4 and 5 for the full load tests. Both CO emission levels and car-
bon heat loss Increase with decreasing TA. This trend 1s a result of the re-
duced oxygen available for complete combustion. CO emission levels show no
effect due to furnace condition. However, carbon heat loss appears to de-
crease with Increasing furnace waterwall deposits. This may be related to the
higher bulk flame temperatures encountered In a heavily slagged furnace.
BIASED FIRING OPERATION STUDY
Biased firing Involves the removal of a full firing elevation from service with
the dampers being opened so as to admit air through the idle fuel nozzle eleva-
tions. The effect on NOp emission levels when taking various fuel elevations
out of service is shown in Figure 6. The lowest M>2 levels for each unit were
obtained when the top fuel firing elevations were removed from service and the
respective compartment air dampers were 100 percent open. Overflre air opera-
tion is simulated by this method of unit operation. The trend is for increas-
ing N02 levels as the elevation being removed 1s lower in the windbox. The in-
crease In N0£ levels can be attributed to the increased oxygen available in the
fuel firing zone.
Examination of the units on an individual basis showed a slight reduction in
N02 levels when the bottom fuel firing elevation was removed from service.
This reduction in N0£ might be caused by a cooling of the hot combustion gases
by the cooler combustion air, which is being admitted through the bottom fuel
firing elevation.
N02 is plotted versus TA for the full load biased firing tests in Figure 7.
The correlation found for the baseline tests is also evident for the biased
firing tests, N02 being directly proportional to TA.
CO emission level and carbon heat loss plots for the biased firing tests have
not been included. Preliminary plots of these variables against TA revealed
wide and Inconsistent variations. This Inconsistency is most probably due to
firing with different fuel elevations out of service.
OVERFIRE AIR OPERATION STUDY
The overfire air operation studies were divided Into three separate test series,
each designed to determine an optimum operating condition. The three test se-
ries were:
1. Excess Air and Overflre Air Rate Variation,
2. Overflre Air Register Tilt Variation, and
3. Load and Furnace Waterwall Deposit Variation at Optimum Conditions
The first of these test series Involved the variation of the overfire air rate
at various excess air levels. Variation of the overfire air rate is accom-
plished by changing the overfire air register damper opening. The maximum over-
fire air rate corresponds to the overfire air register dampers being 100 percent
open. With the exception of Alabama Power Co., Barry #2, the overfire air
11
-------
ro
o
o
110 115 120 125 130 135
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 4: CO vs. theoretical air, baseline study, maximum load
140
LEGEND
0Alabama Power Co.
Barry #2
Awi scons in Power &
Light Co.
Columbia 11
Qutah Power & Light Co.
Huntington #2
Furnace Condition
QClean
(•Moderately Dirty
•Dirty
-------
1.0
0.9
0.8
i-
S 07
<_> «• '
Of.
UJ
°- 0 6
u.u
to
^
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ii
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li
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/
k"ir
Mr
C
^^
r)
M
--
LEGEND
OAlabama Power Co.
Barry #2
^Wisconsin Power &
Light Co.
Columbia #1
Qutah Power & Light Co
Huntington #2
Furnace Condition
Ddean
QiModerately Dirty
• Dirty
105 110 115 120 125 130 135
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
140
Figure 5: Carbon heat loss vs. theoretical air, baseline study, maximum load
-------
to
u_
o
o
B
CM
CM
1*5
?c
o
4J
O>_
(O
CO
LEGEND
©Alabama Power Company
Barry #2
Awi scons in Power &
Light Co.
Columbia #1
EJUtah Power & Light Co.
Huntington #2
120 140 160 180 200 220 240 260 280 300 320
NOg, ng/J
Figure 6: Fuel elevation out of service vs. N02, biased firing study
-------
CM
O
320
NSPS
280
240
200
180
160
140
120
~\
L.
A
E
90 95 100 105 110 115 120
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
125
130
LEGEND
O Alabama Power Co.
B=rry #2
isconsin Power &
Light Co.
Columbia #1
Qutah Power & Light Co.
Huntington #2
Figure 7: N02 vs. theoretical air, biased firing study, maximum load
-------
systems were designed to introduce up to 15 percent of the total combustion
air above the top level of fuel nozzles at MCR. Barry #2 was designed to in-
troduce 20 percent of the total air as overfire air. During normal boiler
operation the overfire air dampers are opened just enough to cool the over-
fire air registers.
As the overfire air dampers are opened the N0£ emission levels are found to
drop for a constant excess air level. This trend is shown in Figure 8. Six
excess air levels have been shown, with the trend being similar for all excess
air levels.
Theoretical air to the fuel firing zone and overfire air damper opening are
closely related, with TA decreasing as the damper opening increases. Figure
9 is a plot of N02 versus TA for the damper variation tests for all three
units. For these tests, as in the baseline and biased firing studies, the
N02 emission levels are found to increase with increasing TA. The evidence
shown in Figures 8 and 9 indicates that NOX is more dependent upon TA rather
than EA.
Once the optimum excess air level and overfire air rate had been determined
for each unit, the second test series were run. This test series involved a
variation in tilt of the overfire air registers and fuel nozzles. The varia-
tion in tilt refers to how many degrees toward or away from each other the
fuel nozzles and overfire air registers are moved. This variation is calcu-
lated by taking the difference in degrees that the overfire air registers are
angled toward or away from the fuel nozzles, i.e., overfire air register tilt
minus fuel nozzle tilt.
Tilt variation of the fuel nozzles and overfire air registers is designed to
move the fuel firing zone both in the furnace and in its position relative to
the overfire air registers. Movement of the fuel nozzles and overfire air
registers away from each other accentuates the effect of staged combustion.
Movement of the fuel nozzles and overfire air registers toward each other min-
imizes the effect of staged combustion because the air is being forced down
into the firing zone.
Figure 10 is a plot of N02 versus the difference in tilt of the fuel nozzles
and overfire air registers. NOg emission levels are found to be highest when
the overfire air registers and fuel nozzles are angled toward each other and
lowest when they are angled away from each other. From the standpoint of NOX
reduction, the optimum tilt variation would be with the overfire air registers
and fuel nozzles angled away from each other. However for ease of boiler oper-
ation, parallel operation of the overfire air registers and fuel nozzles would
be best.
Figure 11 shows N02 plotted versus TA for the second series of tests in the
overfire air study. Again, N02 emission levels are found to be directly pro-
portional to TA.
In the final series of tests for each unit, the effects of load and furnace
waterwall deposits on NOX formation are examined. Boiler operation was at the
optimum conditions determined in the previous test series for each unit. Half,
three-quarter and full load tests were conducted on each unit at clean and
dirty furnace conditions. Figure 12 is a plot of the N02 emission levels
16
-------
350
300
^ 260
c
CVJ
o
200
150
100
R5PS
•H-
1O
0 20 40 60 80 100
OVERFIRE AIR REGISTER DAMPER OPENING, * OPEN
LEGEND
OAlabama Power Co.
Barry #2
^Wisconsin Power & Light Co.
Columbia #1
Qutah Power & Light Co.
Huntington #2
EA-Excess Air at Economizer Outlet
Figure 8: NOp vs. OFA damper opening, overfire study
-------
00
350
NSPS
CM
O
300
250
200
150
100
~4
^Ef-
-E?
LEGEND
©Alabama Power Co.
Barry #2
3/4 Load
^Wisconsin Power & Light Co.
Columbia #1
Full Load
Qutah Power & Light Co.
Huntington #2
Full Load
80 90 100 110 120 -
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 9: NOg vs. theoretical air, overfire air study,
Test series 1
130
-------
NSPS-
onri
300
280
260
240
r>
C 200
CM
o
180
160
140
6
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0
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4
X.
N
0
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LEGEND
©Alabama Porier Co.
Barry n
^Wisconsin Povev &
Light Co.
Columbia #1
Qutah Power & Light Co
Huntington *2
1
TOWARD AWAY
OFA REGISTER AND FUEL NOZZLE TILT DIFFERENTIAL, DEGREES
Figure 10: N02 Vs. tilt differential, overfire air study
-------
ro
o
NSPS—
300
280
260
240
-a 220
Dt
^ 200
o
180
160
140
120
-"«*
x'
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13
s
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A
<^
^
^
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A
-
85 90 95 100 105
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
110
LEGEND
©Alabama Power Co.
Barry *2
^Wisconsin Power &
Light Co.
Columbia #1
CD Utah Power & Light Co.
Huntington #2
Figure 11: NOp vs. theoretical air, overfire air study.
Test series 2
-------
LEGEND
ro
o>
c
A
CM
?40
230
220
91 n
£ 1 U
190
1 OA
loU
i en
\ OU
nn
<5>
LJ
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,
4
A
£
k
7
ft
f
©
IS
E
rid
Alabama Power Co.
Barry #2
© Ful 1 Load
Q3/4 Load
^1/2 Load
Utah Power & Light Co.
Huntington #2
A Full Load
k3/4 Load
&1/2 Load
Wisconsin Power & Light Co
Columbia #1
(DFull Load
®3/4 Load
/Ni /? load
Furnace Condition
(~*\\ •;»,»!*•
85 90 95 100 105 110
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
CModerately Dirty
•Dirty
Figure 12: NOp vs. theoretical air, overfire air study,
Test series 3
-------
versus TA for each test in this series. This figure attempts to minimize the
effect of TA and show the effect of load and furnace condition on NO? emission
levels. Both Huntington #2 and Columbia #1 show an increase in NO?, levels as
unit load rises from half (1/2) load to full load. The effect of furnace con-
dition on these units shows inconsistent variation in the results. Except for
one half (1/2) load test, Barry #2 results also indicate an increase in N02
levels with increasing unit load.
For the overfire air studies, plots of CO emission levels and carbon heat loss
versus TA produced the same trend that was established in the baseline opera-
tion studies. The CO levels and carbon heat losses were found to increase with
decreasing theoretical air levels.
BOILER PERFORMANCE
Figure 13 is a plot of unit efficiency versus excess air for the full load
tests performed on the subject units. As can be seen in Figure 13, biased
firing and overfire air boiler operation did not affect unit efficiency. In
a previous section it was shown that N02 emission levels can be reduced through
the use of overfire air. Therefore, these results indicate that it may be pos-
sible to reduce N0£ emission levels without adversely affecting boiler perfor-
mance or operation.
In general, unit efficiency is found to decrease with increasing excess air.
The decrease in unit efficiency with increasing excess air levels can be at-
tributed to the increasing economizer outlet gas flows and temperatures and
therefore to increased dry gas losses.
The 2 to 3 percent difference in unit efficiency between Columbia Energy Cen-
ter, Unit #1 and Barry Station, Unit #2 or Huntington Station, Unit #2 can be
attributed to higher dry gas losses and moisture in the fuel losses for the
Columbia Energy Center's Unit #1. These higher losses are due to the type of
coal being fired at Columbia Energy Center, Unit #1.
WATERWALL CORROSION COUPON EVALUATION
Thirty (30) day waterwall corrosion coupon evaluations were performed at the
baseline and optimum overfire air conditions for each unit. The purpose of
these evaluations was to determine what effect low excess air or staged com-
bustion would have on waterwall tube wastage.
The method used to evaluate corrosive potential, waterwall tube wastage, in a
boiler is by exposing samples of tube material to furnace conditions for fi-
nite periods of time and then measuring the weight losses. This is accom-
plished by inserting test probes consisting of five (5) coupons each into the
furnace fuel firing zone and maintaining them at typical waterwall metal tem-
peratures. Figure 14 depicts the type of probe and coupons used to obtain
such information. This particular probe utilized air to keep the coupon at
the desired temperature.
Typical instrumentation to automatically maintain the desired temperature con-
sists of an electronic controller, and a pneumatic controller. The pneumatic
controller operates as a switching device, using solenoid valves, to regulate
the amount of cooling air going to the probe. The amount of air is based on a
22
-------
90
CJ
Q£
O
UJ
H*
O
89
88
10 20 30 40
a. Alabama Power Cc., Barry #2
90
89
83
10 20 30 40
b. Utah Power & Light Co., Huntington
87
86
10 20 30 40
c. Wisconsin Prwer & Light Co., Columbia *1
EXCESS MR AT ECONOMIZER OUTLET, PERCENT
Figure 13: Unit efficiency vs. excess air
LEGEND
^Baseline
u Study
3 Biased Firing
Stud
Overfire Air
23
-------
AIR
OUTLET
OXYGEN SAMPLING
HISCRT ~~7 -L\L
/ n
AIR
IKLET
Figure 14: Corrosion Probe Assembly Drawing
24
-------
signal from the electronic controller which 1s tied Into the sensing thermo-
couple at the probe coupon.
At the end of the exposure period the coupons are evaluated for weight loss
and visual evidence of attack. The average weight losses for the baseline and
overflre air modes of boiler operation are shown In the following tables. The
results Indicate that waterwall tube wastage Is unaffected by mode of boiler
operation.
AVERAGE CORROSION COUPON WEIGHT LOSSES
Baseline Overflre Air
Unit Operation Operation
Alabama Power Company 9 ,
Barry Station, Unit #2 2.6381 mg/cnf 4.4419 mg/cnT
Wisconsin Power & Light Co. „ ?
Columbia Energy Center, Unit #1 8.0770 mg/cm 8.0933 mg/cm
Utah Power & Light Co. 9 9
Huntington Station, Unit #2 3.4266 mg/cnT 2.6357 mg/cnT
The weight losses for the Barry Station Unit #2 and the Huntington Station
Unit #2 are within the range of losses which would be expected for the oxida-
tion of carbon steel for a thirty (30) day period. This premise was verified
by control studies conducted in C-E's Kreisinger Development Laboratory.
The weight losses measured at the Columbia Energy Center Unit #1 are slightly
higher than expected. One possible reason for the higher losses is that some
of the probes overheated during the thirty (30) day tests. Another possible
reason for the higher weight losses is that the coal being burned at Columbia
Energy Center's Unit #1 Is a subbltumlnous type coal while Barry Station Unit
#2 and Huntington Station Unit #2 both burn bituminous type coals. However,
the results for the Columbia Energy Center tests show the weight losses are
equivalent regardless of the mode of boiler operation.
25
-------
SECTION II - EPA CONTRACT 68-02-1486
OBJECTIVES
The objective of this program was to investigate the effectiveness of employ-
ing staged combustion as a method of reducing NOv emission levels from tan-
gentially fired boilers burning Western U.S. coals. Specifically this objec-
tive is broken down by task as follows:
TASK I - UNIT SELECTION
The basis for selection of suitable test units follows:
1. One unit (Unit "A") firing a Western U.S. subbituminous coal and a
second unit (Unit "B") firing a Western U.S. bituminous coal.
2. Both units were representative of current Combustion Engineering,
Inc. design employing overfire air registers in an extended windbox
as a means of NOv emission control. Neither unit required modifica-
tions with regard to those features necessary to permit evaluation of
biased firing and staged combustion.
3. The size of the boilers allowed a diverse experimental program and
permitted scale-up correlation of performance and emissions data to
that developed under EPA Contract No. 68-02-1367 £2].
4. Two utilities willing to participate in the program which included
absorbing generating losses incurred during the test program.
5. A utility which agreed to an outage of approximately one month for
the installation of waterwall thermocouples on the unit that would
be firing the Western U.S. subbituminous coal.
TASK II - TEST PLANNING & FABRICATION OF TEST EQUIPMENT
This task included the preparation of a detailed test program for each unit
designed to investigate the effects of the following process variables and
combustion modifications on NOX, SOX, THC, CO and unburned combustibles.
PROCESS VARIABLES
Excess Air Level
Load
Furnace Wall Deposits
26
-------
COMBUSTION MODIFICATIONS
Biased Firing
Overtire Air Firing
The test program provided for documentation of the effects of the test vari-
ables on the thermal and operational performance of the boilers. It also
provided for the evaluation of long term and transient operation, thermal -
efficiency, slagging, fireside corrosion, flame stability and other process
responses considered essential to the commercially acceptable operation of
the boilers.
The following were considered in the test program planning:
1. Analytical measurements and sampling techniques.
2. Emission measurements which included NO , SO , CO, THC and 02. CO?
was determined by calculation.
3. Necessary analysis of fuel properties relevant to furnace operation
and emissions.
4. Measurement of process variables.
The test program utilized statistical test design methods and prior experience
where possible to maximize the information output from each test.
TASK III - INSTALLATION OF INSTRUMENTATION
Task III involved the installation, on each unit, of the analytical instrumen-
tation required for calculation of C02 and for measurement of flue gas con-
stituents (NOX, SOX, CO, THC, 02 and unburned carbon). Also installed was the
necessary instrumentation required to characterize the effects that combustion
modifications have on unit performance; i.e., fireside corrosion and heat ab-
sorption. Instrumentation to determine waterwall absorption rates was in-
stalled only on Unit A. Instrumentation to determine unit absorption rates
and thermal performance of the reheater, superheater, economizer and air heat-
er sections were installed on both Units A and B.
TASK IV - BASELINE OPERATION - UNITS A & B
Similar but separate test programs were conducted on Units A & B to determine
the effect of unit load, furnace wall deposits and excess air variation on
baseline gaseous emission levels and unit performance. During this portion of
the test program only a minimum amount of air necessary for cooling was admit-
ted through the overfire air registers.
There were nineteen (19) tests performed for the combination of conditions in-
dicated in Test Matrix 1.
27
-------
TEST MATRIX 1
D-l
D-2
D-3
L-l
L-2
L-3
L-l
L-2
L-3
L-l
L-2
L-3
E-l
1
5
8
11
13
17
E-2
2
4
6
9
14
16
18
E-3
3
7
10
12
15
19
TEST CONDITIONS
Percent Excess A1r
Minimum
Normal
Maximum
E-l
E-2
E-3
Furnace Wall Deposits
Clean D-l
Moderate D-2
Heavy D-3
Unit Load
Maximum L-l
3/4 Maximum 1-2
1/2 Maximum L-3
A baseline operation waterwall corrosion rate test of a four (4) week duration
was conducted after the completion of the baseline emissions test program.
This study was performed at normal operating conditions with maximum load be-
ing carried whenever possible. The baseline operation corrosion rate test was
conducted on both Units A & B.
TASK V - BIASED FIRING OPERATION - UNITS A & B
A program was conducted to establish the effect of operating with various fuel
elevations out of service and of varying the excess air levels on gaseous emis-
sion levels and unit performance. Specifically, this portion of the program
established maximum emissions control at full load and throughout the normal
load range without utilizing the overflre registers; however, air was admitted
through the dampers of the Idle fuel nozzle elevations.
28
-------
C0nducted on Un1t A at the conditions specified 1n
TEST MATRIX 2
i
B-1
B-2
B-1
B-2
B-3
B-4
B-3
B-4
B-5
B-6
B-5
B-6
E-l
L-l
1
2
3
4
•
L-2
5
6
7
L-3
8
9
10
E-2
L-l
11
12
13
L-2
14
15
16
L-3
17
18
TEST CONDITIONS
Firing Elev. Out of Serv.
Top B-1
Top Middle B-2
Top Center B-3
Bottom Center B-4
Bottom Middle B-5
Bottom B-6
Unit Load
Maximum L-l
3/4 Maximum L-2
1/2 Maximum L-3
Percent Excess Air
Minimum E-l
Normal E-2
29
-------
For Unit B, there were sixteen (16) tests conducted at the conditions speci-
fied in Test Matrix 3.
TEST MATRIX 3
B-l
B-2
B-l
B-2
B-3
B-2
B-3
B-4
B-3
B-4
B-5
B-4
B-5
E-l
L-l
1
2
3
L-2
4
5
6
L-3
7
8
E-2
L-l
9
10
11
L-2
12
13
14
L-3
15
16
TEST CONDITIONS
Firing Elev. Out of Serv.
Top B-l
Top Center B-2
Center B-3
Bottom Center B-4
Bottom B-5
Unit Load
Maximum L-l
3/4 Maximum L-2
1/2 Maximum L-3
Percent Excess Air
Minimum E-l
Normal E-2
TASK VI - OVERFIRE AIR OPERATION - UNITS A & B
The overfire air operation test program was the same for both Units A & B.
The test program, utilizing the overfire air system, investigated the effect
of overfire air admission rates on gaseous emission levels at various unit
loads and operating conditions. Those conditions which were found to be op-
timum from the standpoint of both effectiveness in reducing NOX emission lev-
els and maintaining safe unit operation were evaluated to determine their ac-
ceptability for long term operation.
The first series of tests in this portion of the program were to determine the
effect on the NOX emission levels and unit performance, when varying the over-
fire air rate with respect to excess air.
30
-------
There were eleven (11) tests conducted at maximum load under the conditions
identified 1n Test Matrix 4.
TEST MATRIX 4
A-1
A-2
A-3
A-4
A-5
E-l
6
7
8
E-2
1
2
3
4
5
E-3
9
10
11
TEST CONDITIONS
Overflre Air Rate
None A-1
1/4 Maximum A-2
1/2 Maximum A-3
3/4 Maximum A-4
Maximum A-5
Percent Excess Air
Minimum
Normal
Maximum
E-l
E-2
E-3
Having established the optimum overfire air rate and excess air level, this
condition was used in conducting a series of fuel nozzle and overfire air reg-
ister tilt variation tests.
The objective of this evaluation was to determine the effect of overfire air
register tilt on the NOX emission levels, steam temperatures and furnace wall
deposits.
There were seven (7) tests performed at maximum unit load under the conditions
listed in Test Matrix 5.
TEST MATRIX-5
R-l
R-2
R-3
F-l
12
14
F-2
13
15
17
F-3
16
18
TEST CONDITIONS
Fuel Nozzle Tilt
Maximum Minus
Horizontal
Maximum Plus
F-l
F-2
F-3
Overfire Air Register Tilt
Maximum Minus
Horizontal
Maximum Plus
R-l
R-2
R-3
The objective of the final series of tests for this test program was to deter-
mine the effect on NOv emission levels and unit performance when operating at
the previously established optimum conditions, while varying unit load and
furnace wall deposits.
31
-------
There were six (6) tests conducted at the conditions Identified In Test Matrix
6.
TEST MATRIX 6
L-l
L-2
L-3
OC-1
D-1
19
21
23
D-3
20
22
24
TEST CONDITIONS
Unit Load
Maximum
3/4 Maximum
1/2 Maximum
Furnace Wall Deposits
Clean
Heavy
L-l
L-2
L-3
D-1
D-3
Unit Operating Conditions
Optimum Conditions OC-1
To determine the effect of long term and transient overfire air operation on
the furnace waterwall wastage rate, a waterwall corrosion study was conducted
for a four (4) week period. This study was conducted at optimum conditions
for NOX reduction, as determined In the previously outlined test program, with
maximum load being maintained whenever possible.
TASK VII - PREPARATION OF TEST REPORT AND ANALYSIS OF DATA
The test report includes all data obtained during the test program and the
analysis of that data.
Specific areas of analysis and reporting are:
1. The reporting of emissions data with respect to modes of operation
and coal type.
2. The analysis of emission data with respect to Contract 68-02-1367,
for a unit that is equipped with a modified overfire air system.
3. The reporting of emission data with respect to unit performance.
4. The reporting of the corrosion probe study with respect to overfire
air operation and coal type.
5. The analysis, of corrosion probe wastage data with respect to Contract
68-02-1367.
6. The scale-up considerations for design of new overfire air systems
resulting from this study and Contract 68-02-1367-
7. The possible changes to cost estimates for overfire air systems In
new and existing boilers if this study indicates previously developed
cost estimates based on Contract 68-02-1367 should be revised.
32
-------
DISCUSSION
TASK I - UNIT SELECTION
The two units selected for participation 1n this test program were:
UNIT A - Wisconsin Power & Light Co.
Columbia Energy Center, Unit #1
UNIT B - Utah Power & Light Co.
Himtlngton Canyon, Unit #2
These units are representative of current Combustion Engineering, Inc. boiler
design. Both units Incorporate overfire air registers In an extended windbox
as a means of NOX emission control. A typical windbox arrangement for one
corner of a unit Is shown In Figure 15. The primary air, which conveys the
coal, 1s Introduced through the center portion of the tilting coal nozzles.
Secondary air is Introduced selectively through openings at the periphery of
the coal nozzles and/or through the air nozzles. Windbox air dampers located
in the fuel and air compartments regulate the distribution of the secondary
air. The quantity of air flow is controlled by the induced draft and forced
draft fan system [7].
Unit A, Columbia Energy Center, Unit II, 1s a controlled circulation, balanced
draft, radiant, reheat boiler firing pulverized coal through six elevations of
tilting tangential fuel nozzles. Unit capacity at maximum continuous rating
(NCR) is 479 kg/s (3,800,000 LBS/HR) main steam flow at a superheat outlet
temperature and pressure of 541°C (1005°F) and 18.1 MPa (2620 PSIG), respec-
tively. The Columbia Energy Center, Unit #1 fires a Montana Rosebud seam sub-
bituminous 'C' coal. A side elevation of Columbia Energy Center, Unit #1 is
shown in Figure 16.
Unit B, Huntington Canyon, Unit #2, is also a controlled circulation, balanced
draft, radiant, reheat boiler firing pulverized coal through five elevations
of tilting tangential fuel nozzles. The unit capacity at the maximum continu-
ous rating (MCR) 1s 382 kg/s (3,036,000 LBS/HR) main steam flow with a super-
heat outlet temperature and pressure of 541°C (1005°F) and 18.2 MPa (2645
PSIG), respectively. This unit fires a high Volatile 'B1 bituminous coal sup-
plied from the nearby Peabody Coal Company's Deer Creek Mine. A side eleva-
tion of Huntington Canyon, Unit #2 is shown in Figure 17.
In both units, superheat outlet temperatures are controlled by spray desuper-
heating. Reheat outlet temperatures are controlled by fuel nozzle tilt and
spray desuperheatlng.
33
-------
TANGENTIAL FIRING
SYSTEM
INCORPORATING
OVERFIRE AIR
FOR NOx CONTROL
COAL FIRING
WINDBOX
SECONDARY AIR DAMPERS
SECONDARY AIR
DAMPER DRIVE UNIT
OVERFIRE AIR
NOZZLES
SIDE IGNITOR
NOZZLE
SECONDARY
AIR NOZZLES
NOZZLES
OIL GUN
Figure 15: Typical windbox of tangential firing system
34
-------
Figure 16. Unit side elevation, Wisconsin Power and Light Company,
Columbia Energy Center No. 1
35
-------
Figure 17. Unit side elevation, Utah Power and Light Company
Huntington Station No. 2
36
-------
TASK II - TEST PLANNING & FABRICATION OF TEST EQUIPMENT
The test program was designed to Investigate the effect of excess air level,
unit load, furnace wall deposits, biased firing, and overflre air operation
with respect to NOx and related gaseous emission levels, furnace waterwall
corrosion and unit performance. The Instrumentation required to achieve the
above mentioned goals Included such Items as fabrication of corrosion probes,
probe control systems, gas temperature and sampling probes, calibration of
thermocouples, analyzers and pressure gauges and the packaging of equipment
for shipping to the test sites.
At the test sites, flue gas samples for the determination of NOv, SOX, THC
and CO were obtained from the boiler economizer outlet ducts. The percent
oxygen In the flue gas entering and leaving the air preheaters was also ob-
tained for the determination of air preheater leakage and unit efficiency.
The type of Instrumentation used in determining the emission concentrations
and the general locations of these instruments are described in the discussion
of Task III - Installation of Instrumentation. Unit steam and gas-side per-
formance was monitored using calibrated thermocouples, pressure gauges and
manometers as required. The general locations of these instruments are also
described in the discussion of Task III - Installation of Instrumentation.
Type E chordal thermocouples were Installed In the furnace waterwalls at Wis-
consin Power and Light Co.'s, Columbia Energy Center, Unit #1.
Coal samples were obtained during each test for later analysis. Fuel analysis,
unit emission levels, steam flow rates, absorption rates, gas and air weights
and efficiencies were calculated for each test. The calculating methods and
procedures used are listed in the discussion of Task III - Installation of
Instrumentation.
The test program documented and discussed in detail all tools and techniques
regarding analytical measurements and sampling techniques and calculating pro-
cedures used.
TASK III - INSTALLATION OF INSTRUMENTATION
Instrumentation necessary to conduct the baseline, biased firing and overfire
air test programs on the selected units was Installed and calibrated. This in-
strumentation consisted of the following:
LOCATION OF MEASUREMENT
MEASUREMENT INSTRUMENT OR METHOD OR CALCULATION PROCEDURE
Flue Gas Constituents
Nitrogen Oxides - NO Chemlluminescence Economizer Gas Outlet
Analyzer
Carbon Monoxide - CO Infrared Analyzer Economizer Gas Outlet
Total Hydrocarbons - Flame lonization
THC Analyzer Economizer Gas Outlet
37
-------
MEASUREMENT
Flue Gas Constituents
(Cont.)
Oxygen - Og
Sulfur Dioxide - S02
Carbon Dioxide - COy
Unburned Combustibles
Steam and Water Flows
Feedwater
SH Desuperheat Spray
RH Desuperheat Spray
Reheat
Superheat
Air and Gas Flows
Total Flue Gas
Total Air
Overfire Air
Air Heater Leakage
Miscellaneous Flows
Coal
Pressures
Steam and Mater
INSTRUMENT OR METHOD
Paramagnetic Analyzer
Wet Chemistry
Calculated
Cyclone Dust Collee-
tor
ASME Dust Collector
Mercury Manometer
Calculated
Calculated
Calculated
Calculated
Calculated
Calculated
Calculated
Calculated
Coal Scales
Calibrated Gauges
LOCATION OF MEASUREMENT
OR CALCULATION PROCEDURE
Economizer Gas Outlet
and Air Heater Gas In-
let and Outlet
Economizer Gas Outlet
Combustion Calculations
Economizer Gas Outlet -
Unit A
Air Heater Gas Outlet -
Unit B
Feedwater Orifice
Heat and Mass Balance
Heat and Mass Balance
Heat and Mass Balance
Heat and Mass Balance
Heat and Combustion
Calculations
Heat and Combustion
Calculations
Mass Balance
Mass Balance
Coal Feeders - Plant
Instrumentation
Economizer Inlet
Drum
Superheat Outlet
Reheat Inlet
38
-------
MEASUREMENT
Pressures (Cont.)
INSTRUMENT OR METHOD
Air and Gas
Plant Instrumenta-
tion
Temperatures
Steam and Water
Calibrated Stainless
Steel Type E Hell and
Type E Button Thermo-
couples
Air and Gas
Miscellaneous
Coal Samples
Mall Deposit Patterns
Waterwall Corrosion
Calibrated Stainless
Steel Sheathed Type E
Chordal Thermocouples
Type E Thermocouples
ASTM Procedures
Visual Observation
Corrosion Probes
LOCATION OF MEASUREMENT
OR CALCULATION PROCEDURE
Reheat Outlet
Superheat Spray Water
Reheat Spray Water
High Pressure Heater
Shell Side
FD Fan Outlet
AH Air Inlet
AH Air Outlet
Windbox
Furnace
Economizer Outlet
AH Gas Inlet
AH Gas Outlet
ID Fan Inlet
Economizer Inlet
Economtzer Outlet
SH Desuperheat Inlet
SH Desuperheat Outlet
Superheat Outlet
RH Desuperheat Inlet
RH Desuperheat Outlet
Reheat Outlet
SH DESH Spray Hater
RH DESH. Spray Water
HP Heater Inlet Steam
HP Heater Drain
HP Heater PW Inlet
HP Heater FW Outlet
Furnace Haterwall Tubes
Atr Heater Gas Inlet
Atr Heater Gas Outlet
Air Heater Air Inlet
Air Heater Air Outlet
Coal Feeders
Furnace Water-walls
Front Furnace Waterwall
39
-------
The same Instrumentation and measurements as required In support of the base-
line, biased firing and overflre air test programs on Unit A were utilized on
Unit B, with the exception of the chordal thermocouples installed in the fur-
nace waterwall tubes.
All test measurements were supplemented by monitoring and recording the nor-
mally available plant operating instrumentation.
40
-------
COLUMBIA ENERGY CENTER, UNIT #1
TASKS IV, V & VI - TEST DATA ACQUISITION AND ANALYSIS
Wisconsin Power and Light Company's, Columbia Energy Center, Unit No. 1 has two
"hot precipitators", i.e. the electrostatic precipitators are located between
the boiler economizer outlets and the air preheater gas inlets. The use of the
hot precipitators necessitated the sampling of the flue gas at three locations;
economizer outlet, air preheater gas inlet, and air preheater gas outlet.
Flue gas samples for determination of NOg, CO, 0? and THC emission levels were
obtained from each of the two economizer outlet ducts. The flue gas samples
were drawn using a twelve (12) point grid in each duct. The S02 sample was
drawn from a single point in the left economizer outlet duct using a heated
sample line. The fly ash sample for carbon loss analysis was also obtained
from a single point in the left economizer outlet duct.
The percent oxygen in the flue gas entering and leaving the two air preheaters
was drawn from an eighteen (18) point grid in each air preheater gas inlet and
outlet duct. The grids were arranged so as to allow sampling on centroids of
equal area. The percent oxygen in the flue gas entering and leaving the air
preheaters is required for the determination of the air preheater leakage. The
percent oxygen at these two points plus the percent oxygen in the flue gas leav-
ing the economizer is used in the calculation of unit efficiency.
Visual observations of the furnace waterwalls were recorded for each test. How-
ever, visual observations of the furnace waterwalls were hampered due to the in-
sufficient number and location of the observation doors. Typical wall deposit
patterns taken during clean, moderate and heavy furnace slagging conditions at
full load operation are shown on Figures 18, 19 and 20. These slag patterns
are typical for all modes of boiler operation.
Chorda! thermocouples were installed in the furnace waterwalls of Columbia
Energy Center, Unit No. 1. The chordal thermocouples are utilized to determine
the waterwall absorption rates and are therefore useful in monitoring furnace
performance. The use of the chordal thermocouples is further explained in a
separate subsection, Furnace Performance.
The Coal Feeders at Columbia #1 are pressurized. As a result, coal samples
were Initially obtained from the conveyor belts feeding the coal bunkers, with
one sample being obtained for each test for later analysis. The samples could
only be obtained when the bunkers were being filled, which was two to three
times per day. This sampling method was not considered desirable, as it was
Impossible to know If the coal being fed to the coal bunkers was representative
of the coal being burned during any one test. Gate valves were installed in
the pipes feeding the coal from the bunkers to the feeders. With the installa-
tion of the gate valves, samples were obtained from each coal feeder during
41
-------
FURNACE WATEPHALL DEPOSIT PATTERN
1 1 2
1 1 2
1 1 2
1 1 1
1 1 1
1 1 1
000
004
505
FRONT
1 1
' «<;
222
3 1 1
1 1 1
M f>
1 1 1
1 3 3
1 3 4
V
RIGHT
SIDE
000
1
1 3 1
2 3 3
1 3 1
1 3 1
1 1 1
1 1 1
J
1 1 1
500
REAR
000
> ' '
2 1 1
1 1 t
1 1 1
1 1 1
1 1 1
J
1 1 1
V
LEFT
SIDE
NO A
FUZZ'
UGH'
UGH'
HED.
HEAV
RUNN
NOTE
KEY
:13 MM
LIGHT 13 MM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
•100 MM
50 MM
100 MM
NOTE: 25.4 MM • 1 INCH
0
1
2
' 3
5
6
Figure 18: Furnace waterwall deposit pattern, clean furnace
-------
FURNACE WIEFHALL DEPOSIT PATTERN
•
333
3 33
3 3 3
3 3 3
3 3 3
333
443
J 4 4 3
233
FMNT
3 3 3
3 3<;
332
332
332
M
3 3 2
3 3 2
442
V
MIGHT
SIDE
332
222
3 3 3
333
H
3 3 2
442
4-42
332
REAR
333
> 3 3
332
332
333.
333
432
442
V
LEFT
SIDE
NO A1
FUZZ1
LIGH1
LIGH1
MED.
HEAV1
RUNN
NOTE
KEY
:13 MM
LIGHT 13 NM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
•100 MM
50 MM
100 MM
NOTE: 25.4 MM - 1 INCH
0
1
2
3
4
5
6
Figure 19: Furnace waterwall deposit pattern, moderate slag furnace
-------
FURNACE WATERMLL DEPOSIT PATTERN
222
222
3 3 3
3 3 3
T 3 3 3
666
666
666
222
• •<
441*
I* k 2
n 6 6 6r
666
666
•J •
V
000
0
222
555
3 3 3
1 3 3 3 T
666
666
J fc
FRONT RIGHT REAR
SIDE
222
) 2 2
222
622
1333
2 3 3
6 1 1
>f
V
LEFT
SIDE
NO A
FUZZ
UGH'
UGH
MED.
HEAV
RUNN
NOTE
KEY
= 13 MM
LIGHT 13 MM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
•100 MM
50 MM
100 MM
NOTE: 25.4 MM • 1 INCH
0
1
2
3
4
5
6
Figure 20: Furnace waterwall deposit pattern, heavy slag furnace
-------
each test and were blended to form a composite sample for each test.
The test data and results for the tests conducted at Wisconsin Power and Light
Company's, Columbia #1 are tabulated In Appendix A. Summaries of the emissions
test data for the baseline, biased firing and overflre air operation studies
are tabulated on Sheets A-l through A-6. During some of the testing 1n March
and May of 1976, CO emission levels were not monitored due to malfunctioning of
the CO analyzer. These tests are reported as not available, (NA), on the emis-
sions test data summary sheets. Unit Performance test data for the three
studies are tabulated on Sheets A-7 through A-13. The calculated unit perfor-
mance test results are tabulated on Sheets A-14 through A-21. Unit efficiency
1s determined using the Heat Losses Method (ASME Power Test Code, PTC 4.1-1964,
reaffirmed 1973). Sheets A-22 through A-35 are a tabulation of the average
waterwall absorption rates, as measured at each chordal thermocouple for each
test. A set of unit board and computer data was obtained for each test and 1s
tabulated on Sheets A-36 through A-56.
All test data and results are reported In SI Metric units, with the exception
of the board and computer data. The board and computer data 1s reported in the
engineering units provided by plant Instrumentation.
The thirty (30) day waterwall corrosion coupon evaluations were conducted using
a specially designed probe consisting of four individual coupons. The water-
wall corrosion coupon evaluations are described and discussed under a separate
subsection 1n this report.
TASK IV - BASELINE OPERATION STUDY
Load and Excess Air Variation - Clean Furnace
Tests 1 through 7 were performed to determine the effect of varying excess air
on unit emission levels and performance. These tests were conducted at three
unit loads with clean furnace conditions. The slag observed on the furnace
waterwalls ranges from 0 to 25.4 mm (1 in.) 1n thickness.
Initially, maximum and minimum excess oxygen levels of six (6) percent and
three and one-half (3.5) percent at the economizer outlet were set by Wiscon-
sin Power and Light Co. as acceptable modes of unit operation at full load.
Wisconsin Power and Light later requested that the minimum excess oxygen limit
be raised to four (4) percent. At reduced loads these limits were slightly
higher. On a few occasions, excess oxygen values as low as two and one-half
(2.5) percent were experienced, when measured using test Instrumentation. The
limits set by Wisconsin Power and Light were exceeded on those occasions due
to a discrepancy between plant and test Instrumentation. The Plant oxygen ala-
lyzer was being used to monitor and control unit operations. At times the Plant
analyzer was reading approximately one percent (1%) higher than test Instrumen-
tation.
During Initial testing of Columbia, Unit No. 1, mechanical stops on the Induced
draft fans prevented the unit from reaching full load during high excess air
operation tests. The mechanical stops were changed during a unit outage 1n
June, 1976 enabling the unit to achieve full load during subsequent high excess
air operation tests.
45
-------
Comparison of NOg emission levels with unit load shows N02 levels were gener-
ally higher at half load than at full load. This might be attributed to the
fact that the excess air levels are higher at half load than at full load.
CO emission levels are found to be higher at full load unit operation than at
half load operation. This can be attributed to the fact that at lower loads
the unit operates at higher excess air levels.
The effect of excess air level and unit loading on unit efficiency, carbon heat
loss, unburned hydrocarbons and sulfur dioxide emission levels is discussed in
conjunction with the other baseline tests.
1
2
3
4
5
6
7
NO?
ng/J
322.9
260,
303.
246.
291,
335.
333.8
CO
ng/J
4.8
4.8
5.4
NA
1.5
1.7
2.2
X-S Air
20.7
21.8
34.7
35.6
Theo. Air
To Firing
Zone - %
27.
37.
117.8
118.9
131
132.
126.
136.
.4
.5
.7
.2
43.5
141.4
Unit
Effic.
86.95
87.49
86.28
87.35
87.94
87.05
87.23
Furnace
Condition
Clean
Clean
Clean
Clean
Clean
Clean
Clean
Load and Excess Air Variation - Moderately Dirty Furnace
Tests 8 through 12 were conducted with a moderately dirty furnace. The slag
observed on the furnace waterwalls ranged from 25.4 mm (1 in.) to 76.2 mm (3
in.) 1n thickness and was in a plastic state in the thicker areas. The excess
air levels and unit loads were allowed to vary per the test program.
The N02 emission levels for tests 8 through 12 are shown 1n the following table.
Examination of this table shows only small changes in emission levels for the
full load tests. This could be due to small changes in excess air levels. For
the half load tests there is a distinct change in N02 level with a change in ex-
cess air level. At similar excess air levels, the full load tests have higher
N02 levels than the half load tests.
At similar unit loads, CO emission levels do not show any appreciable change
with changes in excess air levels. Comparison of full and half load tests show
CO emission levels to be higher at full load. As with tests 1 through 7, this
difference can be partially attributed to the fact that the boiler operates at
higher excess air levels at half load.
N02
ng/J
295.
290.
310.
270.
368.3
CO
ng/J
5.1
4.9
5.1
1.5
1.9
X-S Air
Theo. A1r
To Firing
Zone - %
19,
23.
30.
20.
116.
120.
127.
117,
52.5
145.0
Unit
Effic.
87.04
86.85
86.93
87.26
86.41
Furnace
Condition
Moderate
Moderate
Moderate
Moderate
Moderate
46
-------
Load and Excess A1r Variation - Dirty Furnace
Tests 13 through 19 were conducted with heavy furnace wall deposits. Furnace
wall deposits ranged from 50.8 mm (2 in.) to 101.6 mm (4 1n.) thick. The slag
was usually 1n a plastic state and at times built up to 305 mm (12 1n.) to 610
mn (24 1n.) thick on the lower furnace walls. This buildup was caused by the
slag slowly flowing down the furnace walls. The excess air levels and unit
loads were varied per the test program.
As shown in the following table, there 1s a correlation between N02 emission
levels and excess air level at half load. At full load this correlation is
not evident, as the N02 at the low excess air level 1s higher than expected.
As with the earlier baseline tests, the CO levels for the half load tests are
lower than for the full load tests.
Main
Steam Theo. A1r Unit
Test Flow N02 CO X-S A1r To Firing Efflc. Furnace
NUO
ng/J
No. kg/s ng/J ng/J % Zone - % % Condition
13 432 315.7 NA 17.1 114.3 86.57 Heavy
14 426 309.5 4.9 22.6 119.7 76.75 Heavy
15 397 334.3 5.6 32.2 129.0 76.20 Heavy
16 329 252.9 NA 35.7 132.5 85.56 Heavy
17 264 294.6 1.2 26.1 122.8 87.65 Heavy
18 267 347.7 1.3 39.5 134.3 87.15 Heavy
19 263 369.2 1.4 54.8 144.6 86.23 Heavy
Analysis of Results
The changes in NOg. CO and carbon heat loss versus theoretical air to the fuel
firing zone are shown on Figures 21, 22 and 23. These parameters are plotted
versus theoretical air to the fuel firing zone rather than the total excess air.
For the baseline operation study the TA Is essentially the same as the total
air.
Figure 21 shows that N02 correlates reasonably well with TA. Increasing TA re-
sults 1n Increasing N02 emission levels. This correlation is in agreement with
other research, which has shown that N02 emission levels are proportional to the
concentration of oxygen available for combustion. Comparison of full load and
half (1/2) load test at similar TA shows that the half (1/2) load tests have
lower N02 levels. The two three-quarter (3/4) load tests shown on Figure 21 do
not correlate with the full or half (1/2) load tests with respect to TA or unit
load.
With the exception of one supposedly clean test, furnace waterwall deposits ap-
pear to have some effect on NCfc emission levels. As Figure 21 indicates, those
tests performed with heavier furnace waterwall deposits generally have higher
N02 levels.
While the data plotted 1s not sufficient proof to the above statement, it does
support the argument that NCfe emission levels are affected by furnace waterwall
deposit conditions.
47
-------
Wisconsin Power & Light Co.
Columbia Energy Center
Unit #1
00
360
340
320
300
280
260
240
ISPS
110
-a
^
o
I
O
150
Figure 21
120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
N02 vs. theoretical air to fuel firing zone, baseline study
LEGEND
Unit Load
8 Max
3/<
^ 1/2 Max
Furnace Slag
8
Clean
Moderate
Dirty "
-------
Wisconsin Pcwe>" & Light Co.
Columbii Energy Cente.-
Unit #1
ID
01
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^
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Unit Load
O Max
^> 1/2 Max
Pi iY*r\Af*t* ^1 ^ n
O Clean
(J Moderately Dirty
0 Dirty
no
120
130
140
150
Figure 22:
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
CO vs. theoretical air to fuel firing zone, baseline study
-------
in
o
110
Wisconsin Power & Light Co.
Columbia Energy Center
Unit #1
0.12
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LEGEND
Unit Load
OMax
Do /^ ua v
o/i piax
<>l/2 Max
Furnace Slag
00,
Clean
3 Moderately Dirty
A Dirty
^ u i rty
120
130
140
150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 23: Carbon heat loss vs. theoretical air, baseline study
-------
Figure 22 does not show any variation in CO emission levels with changes 1n
TA. However, it does show that unit loading has a significant effect on CO
emission levels. The CO levels at full load are approximately five (5) times
the CO levels at half (1/2) load. It should be noted that the half (1/2) load
tests were performed in May, 1976, while the full load tests were performed in
March, 1976. Besides changes in tilt, the only other significant change other
than load was that the fuel and auxiliary nozzle compartment damper settings
were changed. The fuel nozzle compartment dampers were opened from an average
50% open to 100% open, while the auxiliary nozzle compartment dampers were
closed from approximately 100% open to approximately 50% open. Whether this
would have any effect on CO emission levels 1s unknown.
The percent carbon heat loss in the fly ash versus theoretical air to the fuel
firing zone is shown in Figure 23. The carbon heat loss values for tests 13
and 15 have not been plotted on Figure 23, as they were too high to be shown
on this figure. With the exception of these two tests and the one high test
shown, carbon heat loss appears to be unaffected by variations 1n TA, unit
load and furnace waterwall deposits.
Figure 24 is a plot of unit efficiency versus excess air at the economizer out-
let. This figure Indicates that unit efficiency is Inversely proportional to
excess air at the economizer outlet. By examining the full load and half (1/2)
load test separately, the decrease in unit efficiency with Increasing excess air
at the economizer outlet is more apparent.
The S02 emission levels were monitored for each test and are reported on Sheets
Al and A2. No correlation was evident between SOg emission levels and excess
air, unit loading or furnace waterwall deposits. It was not possible to con-
trol the S02 emission levels as they are more a function of the sulfur content
of the fuel r.ather than the mode of boiler operation.
Unburned hydrocarbon emission levels were monitored and were found to be at
such low levels as to be unmeasurable.
A thirty (30) day baseline waterwall corrosion coupon test was conducted in
April and May of 1975. Boiler operation was normal with full load being main-
tained as much as possible. The waterwall corrosion coupon test is discussed
in the section, Waterwall Corrosion Coupon Evaluation.
TASK V - BIASED FIRING STUDY
Fuel Elevations Out of Service Variation
Eighteen (18) tests were conducted at Columbia Energy Centers', Unit #1 to de-
termine the effect on NO? emission levels when taking various fuel elevations
out of service (biased firing). These tests were performed at three unit load-
Ings and two excess air levels.
As shown by the data In the following table, the NOg emission levels are lowest
with the top and/or top middle elevation of fuel nozzles out of service (Tests
1, 2, 5, 8, 14 and 17). When comparing tests with similar operating conditions
(Tests 5 vs. 14 or 8 vs. 17), it can be seen that increasing excess air level
results in increasing N02 emission levels.
51
-------
Wisconsin Power & Light Co.
Columbia Energy Center
Unit 11
88.00
87.00
86.00
85.00
c>
10
Figure 24 =
20
30
40
LEGEND
O Max Load
Q 3/4 Max Load
<>l/2 Max Load
50
60
EXCESS AIR, PERCENT
Unit efficiency vs. excess air, baseline study
52
-------
CO emission levels appear to be affected only by unit load with the levels be-
ing higher for full and three-quarter load than for half load. The CO analy-
zer was Inoperative during much of the biased firing testing due to problems
with the analyzer source assembly and excessive electrical noise.
No thirty (30} day waterwall corrosion coupon evaluation was performed follow-
ing the biased firing operation study.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Main
Steam
Flow
kg/s
426
428
433
431
352
352
344
263
258
268
417
417
438
353
325
350
261
264
N02
ng/J
CO
ng/J
X-S A1r
Theo.
A1r to
Firing
Zone-%
Unit
Effic.
203.9
209.1
249.2
250.3
215.9
260.2
227.3
162.2
245.1
266.8
231.2
297.2
280.4
222.5
231.7
246.4
228.7
316.9
NA
NA
NA
NA
8.0
4.2
44.8
1.4
1.2
1.6
NA
5.4
NA
22.6
NA
NA
1.2
2.1
20,
18.
15.
19.0
26.1
21
30.
19.
34.
29.
23.
24.
18,
34.1
35.8
41.3
35.9
36.6
.4
,4
,2
.7
.7
,7
.2
.2
,1
.6
,4
108.2
116.6
112.6
116.9
110.0
117.5
125.6
94.4
133.5
128.4
122.7
123.4
115.8
117.9
132.9
135.8
105.8
135.8
86.19
86.54
85.56
86.52
86.76
87.71
86.30
87.17
87.93
87.37
85.73
86.49
86.69
86.92
86.37
86.11
86.62
86.67
Fuel Nozzle
Elevation
Out of
Service
Top
Top Middle
Bottom Center
Bottom
Top
Top Center
Bottom
Top & Top Middle
Top Cen. & Bottom Cen.
Bottom & Bottom Mid.
Top Middle
Top Center
Bottom Center
Top
Bottom Center
Bottom
Top & Top Middle
Bottom & Bottom Mid.
Analysis of Results
emission levels versus theoretical air to the fuel firing zone are plotted
on Figure 25. This figure Indicates a trend similar to the baseline study tests,
with Increasing N02 levels for Increasing TA. No effect due to a variation In
unit load Is evident 1n Figure 25. The furnace waterwalls were moderately dirty
for most of the biased firing tests and therefore no effect on N0£ levels due to
furnace waterwall deposits was observed.
Figure 26 1s a plot of fuel firing elevation out of service versus N02 emissions
level. The lowest N02 emissions levels were obtained with the upper fuel firing
elevations removed from service and with the respective compartment dampers 100%
open. Overflre air operation 1s simulated with this method of unit operation.
The highest N02 levels were obtained when the center fuel firing elevations were
removed from service. Removal of the bottom fuel firing elevation from service
gives a slight reduction from the higher N02 levels obtained with the center lev-
els removed from service.
CO emission level or carbon heat loss versus TA are not plotted. Preliminary
plots gave no Indication that TA, unit load or furnace wall deposits had any ef-
fect on CO emission levels or carbon heat losses.
53
-------
o>
306
294
282
270
258
246
g1 234
222
210
198
186
174
162
Wisconsin Power & Light Co.
Columbia Energy Center
Unit II
318 ,—
NSPS
90
o
O
95 100 105 110 115 120 125 130 135 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
LEGEND
Fuel Elevation Not In Service Unit Load
O-A A-D OMax
O - B O - E 3 3/4 Max
O - C 0 - F-(Top) 0 1/2 Max
A&B - Both Elevations Out During Same Test
Figure 25: N02 vs. TA, biased firing study
54
-------
Wisconsin Power & Light Co.
Columbia Energy Center
Unit #1
TOP
160
180
200 220
280 300
240 260
. ng/J
Figure 26: Fuel elevation out of service vs. N02, biased firing study
LEGEND
Unit Load
O Max
Q 3/4 Max
1/2 Max
Excess A1r
O 15* TO 25%
(fc 25.IX TO 35X
A 35.IX TO 45X
-------
Figure 27 shows steam generator efficiency versus percent excess air at the
economizer outlet. Although there Is more scatter than In the baseline tests,
the trend of decreasing unit efficiency with Increasing excess air 1s still
evident. The variation In the fuel elevations firing may have contributed to
the scatter In the data.
S02 emission levels were monitored for each test and are reported on data
sheets A-3 and A-4.
Unburned hydrocarbon emission levels were monitored and were at such low levels
as to be immeasurable.
TASK VI - OVERFIRE AIR OPERATION STUDY
Excess Air and Overfire Air Rate Variation
Tests 1 through 11 were conducted to determine the effect on the N0£ emission
levels and unit performance when varying the overflre air rate with respect to
excess air level. For tests 1 through 11, the overfire air registers were held
at horizontal tilt while the fuel nozzle tilts were allowed to vary from a -8
degrees to a +8 degrees. The fuel nozzles were allowed to vary to maintain ac-
ceptable superheat and reheat temperatures.
The following table shows that N0£ emission levels increase with increasing
theoretical air to the fuel firing zone. Except for tests 1 and 2, N02 emis-
sion levels are found to correlate well with excess air level. The N02 levels
for tests 1 and 2 are much higher than expected. No obvious reason for the
high N02 levels can be found. However one possible explanation is that the
furnace wall deposits were considerably different for test 1 and 2. Examina-
tion of the waterwall slag patterns for tests 1 and 2 shows that during these
tests the slag was 50.8 mm (2 in.) to 101.6 mm (4 in.) thick, glassy and run-
ning down the furnace walls. For the remaining tests the slag was about 25.4
mm (1 in.) to 101.6 mm (4 In.) thick and mostly plastic; however, it was not
glassy or running down the walls as fast. The problem with the glassy slag 1s
that it reradlates back to the fire Increasing the bulk flame temperatures.
Due to the problems encountered with the CO analyzer the CO levels were only
monitored for tests 1 and 2. Based on the results of test 1 through 11, the
optimum excess air operating level was found to be the minimum, approximately
15 percent at the economizer outlet. The optimum overfire air rate 1s with the
overfire air dampers 100 percent open. This mode of operation will allow 15 to
20 percent of the total combustion air to be Introduced above the top level of
fuel nozzles depending upon unit load.
Main
Steam Theo. Air Unit OFA
Test Flow N02 CO X-S A1r To Firing Effic. Dampers
No. kg/s ng/J ng/J % Zone - % % % Open
1 425 356.1 4.9 23.9 120.9 86.19 0
2 426 354.9 4.9 23.2 115.7 86.54 25
3 439 222.8 NA 21.8 109.7 85.56 50
4 445 203.4 NA 19.7 105.2 86.52 70
5 444 215.4 NA 20.4 104.6 86.76 95
56
-------
Wisconsin Power & Light Co.
Columbia Energy Center
Unit #1
88.10
87 90
87 70
87 50
87 30
•_ 87 10
z;
UJ
£ 86 90
*
>-
S 86 70.
i— i
o
H*
Li-
ft 86 50
(—
H-l
•ZL
=> og 3Q
86.10
r "
-
a_
<8i
i
>
. R
LU
C^
b
<5
Q
j
r
1
O
(-I
p
i
1
1
LEGEND
Unit Load
O Max
/;\ i ! LJ j/4 Max
V ; O 1/2 Max
i
;
I I
O J . 7U
at; ?n .
85 50
10
i
=
; 0
* i
20
.
3
• t • i
i i
i • i
L . 1 ...
0 40 5
EXCESS AIR, PERCENT
Figure 27: Unit efficiency vs. excess air, biased firing study
57
-------
Main
Steam Theo. Air Unit OFA
Flow NO? CO X-S Air To Firing Effic. Dampers
NU9
ng/J
kg/s ng/J ng/J % Zone - %_ % % Open
446 182.7 NA 13.3 110.7 86.71 0
441 177.9 NA 13.9 101.8 86.30 50
439 171.4 NA 15.1 99.0 87.17 100
398 299.2 NA 36.8 128.2 87.97 25
390 274.7 NA 35.8 118.8 87.37 80
389 246.5 NA 30.0 111.5 85.73 100
Overfire Air Register Tilt Variation
Seven (7) tests were conducted to determine the effect of fuel nozzle and over-
fire air register tilt variation on N0£ emission levels and unit performance.
These tests, 12 through 18, were conducted at the optimum overfire air rate
(dampers 100 percent open) established in tests 1 through 11. Although tests
1 through 11 indicated an excess air level of approximately 15 percent to be
optimum for low NOx formation, an average excess air level of 24 percent was
maintained for tests 12 through 18. The higher excess air level was easier to
maintain from the standpoint of boiler operation and did not result in signifi-
cantly higher NOg levels.
The overfire air registers were varied from a -5 degrees to a +30 degrees,
while the fuel nozzles were varied from a -5 degrees to a +26 degrees. During
a unit outage in early June, 1976 the fuel nozzle tilt mechanism was modified.
The bottom two fuel firing elevations were prevented from going below a hori-
zontal tilt, but could travel upward to a maximum +26 degrees. The upper four
fuel firing elevations were allowed to travel from a -10 degrees to a +26 de-
grees. When the bottom two fuel firing elevations were at horizontal, the upper
four elevations were at a -10 degrees. As the tilts moved upward, the upper four
fuel firing elevations rose farther and faster, so that at the maximum upward
tilt all the fuel firing elevations were at a +26 degrees.
For these tests the furnace waterwall slagging conditions ranged from light to
moderate waterwall deposits. The slag was in a plastic state in those areas of
the waterwalls where the slag was 25.4 mm (1 in.) or thicker and could be seen
slowly flowing down the lower waterwalls.
The following table shows that N02 emission levels were reduced by movement of
the fuel nozzles and overfire air registers away from each other. While tests
16 through 18 have higher NOg levels than test 12 through 15 the trends are
similar. The differences in the N02 levels can be attributed to small varia-
tions in boiler operation on a daily basis and to the location of the fuel
firing zone in the furnace. For tests 16, 17 and 18 the fuel firing zone was
higher in the furnace than tests 12 through 15. With the fuel firing zone
higher in the furnace, the waterwall surface area available for cooling of the
flame is greatly reduced. The loss of cooling of the flame can result in an in-
crease in flame temperature, which can result in an increase in thermal N0£ for-
mation.
Parallel operation of the fuel nozzles and overfire air registers is as effec-
tive as when they are moved away from each other. Therefore, for ease of testing
58
-------
and botler operation, parallel tilt conditions were chosen for the mode of
boiler operation In tests 19 through 24.
CO emission levels are not found to be greatly affected by tilt variation.
The one test with high CO levels could be the result of the maximum upward
fuel nozzle and overflre air register tilts. At these high tilts, the resi-
dence time of the hot combustion gases 1n the furnace would be reduced. This
reduction In residence time could affect the oxidation of CO to C02.
Main Fuel OFA
Steam Theo. A1r Unit Nozzle Register
Test Flow N02 CO X-S A1r To Firing Efflc. Tilt Tilt
No. kg/s ng/J ng/J % Zone - % % Degrees Degrees
12 446 195.5 4.9 23.9 102.8 87.20 -5 -5
13 444 205.4 1.5 26.9 105.7 86.90 0 -5
14 443 188.5 3.0 26.9 106.0 87.28 -5 0
15 425 198.9 NA 18.3 101.5 86.43 +1 0
16 438 273.7 2.2 24.6 103.9 87.45 +26 0
17 440 224.6 4.5 26.2 104.7 86.88 +2 -1-30
18 441 223.4 17.0 23.2 103.1 87.13 +26 +30
Load and Furnace Uaterwall Deposit Variation at Optimum Conditions
Tests 19 through 24 were conducted at the optimum excess air level, overfire
air rate and fuel nozzle and overflre air register tilts determined in tests
1 through 18. These tests were performed to determine the effect on NOX emis-
sion levels and unit performance at the optimized conditions, while varying
unit load and furnace wall deposits. The excess air level ranged from a low
of 19 percent at full load to a high of 34 percent at half load. The overfire
air register dampers were 100 percent open. The fuel nozzles and overflre air
registers were essentially parallel for tests 19 through 24. The tilts ranged
from horizontal tilt to a +10 degree tilt for the overflre air registers and a
+1 to +12 degree tilt for the fuel nozzles.
The following table shows that NO? formation is affected by furnace waterwall
condition for the three-quarter (5/4) and full toad tests. Except for tests
23 and 24, NOg emission levels increase with increasing furnace waterwall de-
posits. N02 emission levels are also affected by unit load, with higher N02
levels at higher loads.
Except for test 19, CO emission levels are unaffected by unit load or furnace
waterwall deposits. The CO levels for test 19 are considerably higher than
tests 20 through 24. The higher CO level may be due to the lower excess air
level.
Main
Steam Theo. A1r
Test Flow NOg CO X-S Air To Firing Efflc. Furnace
No.
Flow N02 MJ A-a Air ID firing tine. i-urnace
kg/s ng/J ng/J % Zone - % % Condition
19 441 182.8 22.1 19.1 99.7 87.66 Moderate
20 438 234.8 1.1 25.4 99.3 86.63 Heavy
21 350 171.8 1.2 30.0 98.6 87.53 Clean
59
-------
Main
Steam Theo. A1r Unit
Test Flow N02 CO X-S Air To Firing Effic. Furnace
No. kg/s ng/J ng/J % Zone - % % Condition
22 342 220.6 T.I 28.5 103.4 87.39 Moderate
23 263 161.9 1.2 32.5 106.1 88.47 Clean
24 259 161.0 1.6 34.2 107.0 87.78 Moderate
Analysis of Results
N02, CO and carbon heat loss values versus theoretical air to the fuel firing
zone are shown on Figures 28, 29 and 30, respectively. Although only tests 1
through 11 were conducted to determine the effect of TA variation all 24 tests
are shown on Figures 28, 29 and 30.
Figure 28 shows that N0£ emission levels increase with increasing theoretical
air to the fuel firing zone. Furnace waterwall deposits and unit load are also
indicated on Figure 28. On this boiler, comparison of tests with similar TA's,
but different waterwall deposits give no indication that furnace waterwall
slagging has any effect on NOg emission levels. Two half (1/2) load and two
three-quarter (3/4) load tests were performed for the overfire air operation
study. The two half (1/2) load tests have the lowest NO? emission levels,
while the N0£ emission levels for the three-quarter (3/4) load tests are of
the same magnitude as the full load tests.
CO versus theoretical air to the fuel firing zone is plotted in Figure 29.
This figure indicates a possible increase in CO levels at theoretical air lev-
els of approximately 100% to 105%. While this Is the expected trend, the data
plotted in Figure 29 is insufficient to support such a trend. However, carbon
heat loss follows a similar trend when plotted versus TA. Figure 30 is a plot
of carbon heat loss for the overfire air study. For theoretical air levels In
the range from 100% to 110% carbon heat losses are found to rise rapidly. This
is also an expected trend and is what previous studies have shown to be true
for both carbon heat loss and CO.
The second task in the overfire air study involved the effect of overfire air
register tilt variation on N02, CO and carbon heat loss. The N02 emission lev-
els for these tests are plotted versus the tilt differential between the fuel
nozzles and overfire air registers as shown on Figure 31. Preliminary plots of
CO and carbon heat loss versus the difference in tilts yeilded no useful Infor-
mation and therefore no plots have been included. The difference 1n tilts re-
fers to how many degrees toward or away from each other the fuel nozzles and
overfire air registers are moved. This difference is calculated by taking the
difference in degrees that the overfire air registers are angled toward or away
from the fuel nozzles.
Figure 31 Indicates that the maximum NO? levels are obtained when the fuel noz-
zles and overfire air registers are angled toward each other. With the excep-
tion of one test (#17), minimum NO? levels are obtained when the fuel nozzles
and overfire air registers are angled away from each other. Most of these tests
were performed with clean furnace waterwalls, while test 17 had moderately dirty
waterwalls. The N02 levels for test 17 were higher than expected. This might
be attributed to the heavier waterwall deposits observed for this test.
60
-------
o>
CM
o
95
WISCONSIN POWER & LIGHT CO.
COLUMBIA ENERGY CENTER
UNIT #1
OCft
JOU
340
320
onn
JUU
280
260
240
220
200
ion
1 Ou
ifin
NSPS-
"N
O
r
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y
^
/*
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Cfe
-------
WISCONSIN POUER & LIGHT CO,
COLUMBIA ENERGY CENTER
UNIT *1
ot
IS)
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25
20
15
10
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LEGEND
Unit Load
0 Max
D 3/4 Max
/S 1/2 Max
^^
Furnace Slag
Light
O Moderate
0 Heavy
95
100
105
no
115
120
125
130
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 29: CO vs. theoretical air to fuel firing zone, overfire air study
-------
WISCONSIN POWER & LIGHT CO.
COLUMBIA ENERGY CENTER
UNIT #1
O»
b>>
0.06
0.05
s
0.04
a
0.03
0.02
0.01
95
-&
•
*
100
125
105 110 115 120
THEORETICAL AIR TO FUEL FIRING ZONE. PERCENT
Figure 30: Carbon heat loss vs. theoretical air, overfire air study
130
LEGEND
Unit Load
O Max
83/4 Max
1/2 Max
Furnace Slag
Q
$
Light
Moderate
Heavy
-------
WISCONSIN POWER & LIGHT CO.
COLUMBIA ENERGY CENTER
UNIT #1
CM
320
300
Z80
260
240
220
200
180
160
NSPS-
Q
C)
o
O
UNIT LOAD
O Max
All Tests
30 25 20 15
10
10 15 20 25
30
TOWARD DEGREES AWAY
DIFFERENCE IN TILT OF OVERFIRE AIR REGISTERS AND FUEL NOZZLES
Figure 31: N02 vs. difference in tilt, overfire air study
-------
Figure 32 shows unit efficiency versus excess air at the economizer outlet.
Examination of only the full load tests shows that a decrease 1n unit effi-
ciency Is evident with Increasing excess air at the economizer outlet. Such
a trend Is in agreement with the baseline tests and with previous studies at
Alabama Power Company's, Barry Station, Unit #2 [2].
SO? emission levels were monitored for each test and are reported on Sheets
A-5 and A-6. No correlation between S02 emission levels and excess air level,
unit load, or furnace waterwall deposits was apparent.
Unburned hydrocarbons were monitored for all overflre air tests and were at
such low levels as to be immeasurable.
A thirty (30) day waterwall corrosion coupon evaluation was conducted in Janu-
ary and February of 1977. The. overflre air register dampers were allowed to
modulate between 5% open at half load and 75% to 100% open at full load. Unit
loading was varied per Wisconsin Power and Light Company's System demands with
full load being maintained as much as possible. The waterwall corrosion study
1s discussed 1n the section, "Waterwall Corrosion Coupon Evaluation."
FURNACE PERFORMANCE
Furnace performance at Columbia Energy Center, Unit #1 was monitored by the use
of Type "E", chorda1 thermocouples Installed 1n the furnace waterwalls. A sche-
matic of the thermocouple locations 1s shown 1n Figure 33. Furnace performance
1s measured by furnace waterwall absorption rates. Tabulations of the average
waterwall absorption rates, as measured at each chordal thermocouple, are pre-
sented 1n Appendix A on Sheets A22 through A35.
Waterwall temperatures and corresponding absorption rates were found to vary
significantly with furnace waterwall deposit conditions. For comparison of the
waterwall absorption rates, the full load (MCR) tests for the three different
modes of boiler operation are shown on Figures 34, 35 and 36. The average hor-
izontal strip absorption rate profiles of the front and right side walls for
these tests are plotted versus the distance above or below the firing zone cen-
ter.
The baseline test profiles show very little heat absorption variation from the
hopper slopes to the furnace outlet. The baseline profiles indicate uniform
heavy slagging In the combustion zone which results in slightly depressed rates
1n that area. The biased firing test profiles also show very little variation
over the entire furnace height. The absorption rate profiles for the overfire
air tests show little variation from the firing zone center down to the hopper
slopes. There Is a peaking effect just above the firing zone center and a dis-
tinct split in the absorption rate profiles between the upper fuel nozzles and
the furnace outlet. This split can be traced to a change 1n the fuel and aux-
iliary air damper openings. Those tests conducted In March, 1976 had fuel air
damper openings of approximately 30 to 50 percent open and auxiliary air damper
openings of approximately 100 percent open. The fuel and auxiliary air damper
openings were changed following the testing 1n March, 1976. Those tests per-
formed 1n May and June of 1976 had fuel air damper openings of approximately
100 percent open and auxiliary air damper openings ranging from 30 to 50 per-
cent open.
65
-------
WISCONSIN POWER & LIGHT CO.
COLUMBIA ENERGY CENTER
UNIT #1
88.47
88.27
88.07
87.87
87.67
87.47
87.27
87.07
86.87
86.67
86.47
86 27
86 07
85 87
85.67
XX
LEGEND
Unit Load
O Max
D 3/4 Max
O 1/2 Max
O-
0
)
0
0
0C
0
O
r
u
f
)
&
**2r
0
}
C
Q
^
^
C
\y
]
j
O
e
12 15 18 21 24 27 30 33 36 39
EXCESS AIR, PERCENT
Figure 32: Unit efficiency vs. excess air, overflre air study
66
-------
Powrn < .. ir.-T i'c.
CCLUMPK
C-E Ponta SY- ![••;
r I f L7> Tf ST I **r. AND
(•tUFOBMll'.'-.E RESULTS
307.8
NOTE:AU.ELD«TDMt
AND 01
4N METCRS.
FRONT WALL RIGHT WALL REAR WALL LEFT
FURNACE WALL THERMOCOUPLE LOCATION
FIGURE 33: CHORDAL THERMOCOUPLE LOCATIONS
-------
FURNflCE HEflT RBSORPTION RRTE PROFILES
HORIZONTflL STRIP RflTES
WISCONSIN POWER & LIGHT CO.
COLUMBIA «1
Baseline Tests - MCR
cr
LJ
K
LJ
cr
LJ
LJ
o
in
o
CO
z
I—I
on
HH
u_
LJ
CD
OL
O
LJ
>
O
CO
CE
LJ
O
CE
f-
co
•-H
Q
CROWN - KW/M2
Figure 34: Elevation vs. furnace heat absorption
68
-------
FURNRCE HERT RBSORPTION RRTE PROFILES
HORIZONTflL STRIP RflTES
WISCONSIN POWER & LIGHT CO.
COLUMBIA «1
Bias Firing Testa - MCR
i/i
QC
UJ
r
QL
UJ
UJ
O
UJ
O
N
CD
UJ
CD
UJ
O
CO
CE
Ltl
O
2
0=
I-
co
I— I
0
-25
CROWN - KW/M2
Figure 35: Elevation vs. furnace heat absorption
69
-------
FURNflCE HEflT flBSORPTION RflTE PROFILES
HORIZONTflL STRIP RflTES
WISCONSIN POWER fc LIGHT CO.
COLUMBIfl »1
Overfire Air Tests - MCR
5
CL
LJ
LJ
CJ
LJ
•z.
o
N
CD
ce.
i—i
u_
2
O
_l
LU
m
a:
o
tu
>
o
CD
a:
LJ
u
-25
CROWN - KW/M2
Figure 36: Elevation vs. furnace heat absorption
70
-------
As mentioned previously, furnace waterwall deposits had a significant effect
on waterwall temperatures and corresponding absorption rates. Obtaining the
desired slagging conditions proved very difficult and somewhat unpredictable
during the testing at Columbia Energy Center, Unit #1. One of the biggest dif-
ficulties was in observing the furnace waterwalls to obtain an accurate visual
determination of the furnace waterwall deposits.
WATERWALL CORROSION COUPON EVALUATION
Following completion of the steady state phases of the baseline and overflre
air test programs, thirty (30) day waterwall corrosion coupon evaluations were
performed. The purpose of these evaluations was to determine whether any mea-
surable changes In coupon weight losses could be obtained for the two modes of
firing under study.
The Individual probes were exposed at five locations on the furnace front wall
as shown on Figure 37. The coupon temperatures were maintained at the same
levels for each 30 day run and a typical tract of the control temperature range
for each of the twenty coupons 1s shown on Figure 38.
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 A57 and A58. The weight losses are calculated as mg/cm' of coupon sur-
face area.
Figures 39 and 40 show the unit load schedules for each of the 30 day test pe-
riods.
The overflre a1r_portion of the study was conducted as close as possible to the
"optimum" operating conditions determined during the overfire air steady state
tests.
Throughout the overflre air study the overflre air dampers were maintained at
the full open configuration over the range of unit loading shown on Figure 40
with the following exceptions. From January 22 through January 24, January 27
through January 29 and February 8 through February 17 the OFA dampers were
opened 75%. Also during a unit start-up on February 25 the dampers were opened
from 0 to 20% and then maintained at 40% open during February 26 and February
27.
The percent oxygen was monitored daily during each thirty day study at each
probe location and was found to range between 3 and 19 percent 02 during both
the baseline and overflre air studies.
The weight losses calculated for the baseline and overfire air runs were found
to be the same with the average weight losses for all five probes as follows:
Baseline Overflre Air
8.0770 mg/cm2 8.0933 mg/cm2
These values are greater than the range of losses experienced at Barry #2,
Huntlngton Canyon #2 and during a control study conducted at C-E's Kre1singer
Laboratory by a factor of approximately 2 to 1.
71
-------
r
L
i
J
r
v
-------
Wisconsin Power & Light Co.
Columbia Energy Center
Unit No. 1
TYPICAL COUPON
TEMP. RANGE
ALL 5 PROBES
TEMPERATURE - °F
CONTROL TEMP. - 750 F
(399 C). TOP COUPON
OF EACH PROBE.
Figure 38. Typical corrosion probe temperature range
73
-------
WISCONSIN POWER & LIGHT CO.
COLI*ei» ENERGY CEN1FR
UNIT |1
8
8
m MM \\\m n«ii!inn!i!i!
I ! "I '• :I If " '!
I.' litiilim !! W I itilliiiiiti It itlHmli
CORROSION PROBE CXPOSIFE TIME - DAYS
FIGURE 39: Gooss MW LO*OIHO vs. TIME . BASCIINC CORROSION PROBC STUDY
AVG. GROSS
X) DAY PER I CO
421.3 WHR
-------
WISCONSIN POWER & LIGHT CO.
COLUWIA ENERGY CENTER
UNIT 11
550
t!;;:! tru tj: ::::i:::: :::: :it: :_t ;:::
j iWU::: jittti ;|:!!;}::::|:::;j:::;rtn *!
1/26/77 1/27/77
450
400
350
300
850 m
200 '
550
8/05/77
g/06/77 g/07/77 2/08/77 g/09/77~ g/10/77 g/11/77 g/lg/77
8/13/77
8/14/77
2/15/77
CORROSION PROBE EXPOSURE TlfC - DAYS
Fiounc 40: Gnoss W LO«OINO vs. Tint . ovdtrmc «i« CO«»O»ION PROBI STUDY
AVG. GROSS MW/H?
30 DAY PERIOD
448.8 W/W
-------
The results Indicate that while there was no change In weight loss between the
baseline and overfire air runs something resulted In the losses being consis-
tently higher than expected based on previously obtained data.
Review of test logs reveals a possible explanation. During both runs periodic
overheating (up to approximately 540°C) of Individual probes occurred due to
partial slagging of the probe coupons. This occasionally created a situation
where the coupon containing the control thermocouple would be covered with slag
while the other coupons of a given probe were still clean. The control thermo-
couple would then reduce air flow to the entire probe causing the clean coupons
to overheat. This situation was corrected when encountered by switching the
temperature control to a hotter coupon. The frequency of occurrance was approx-
imately the same for both runs.
Chemical analysis of the coupon deposits also tends to support this observation
as the fusibility temperatures of the inner deposits on some of the affected
probes were very high. This coupled with the fused state of the initial depos-
its indicates possible overheating. Coal ash and deposit analysis are shown on
Figures 41 and 42.
76
-------
Wisconsin Power & Light Company
Columbia #1
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON DATA SUMMARY
AS FIRED ASH AND COUPON DEPOSIT ANALYSIS
Sample Location
Ash Fus1b1l1ty-°F
Initial Deformation Temp.
Softening Temp.
Fluid Temp.
Ash Composition-%by Weight
S102
2f
MgO
Na20
K20
TlOo
P205
BASELINE STUDY
Pulverized Coal
ip. 2130
2170
2290
38.6
17.5
6.7
13.5
3.7
0.4
0.5
0.9
15.2
— _
Probe A
Outer
2000
2080
2270
33.9
14.4
34.8
11.6
3.1
0.1
0.3
0.7
1.0
—
Probe B1
Initial
I.S.2
9.4
4.3
74.8
3.0
0.7
0.1
^0.1
0'.3
4.3
0.4
Probe C
Outer
2010
2080
2270
37.7
14.7
29.4
12.4
3.4
0.2
0.3
0.8
0.9
Probe D
Outer '
2010
2080
2310
41.4
16.4
21.5
14.4
3.4
0.4
0.3
0.9
1.1
—
Probe E
Outer
1960
2010
2140
28.8
10.0
45.3
9.2
2.1
0.3
0.4
0.5
1.7
0.1
Total
97.0
99.9
97.4
99.8
99.8
98.4
1. Outer Sample Not Available
2. I.S. - Insufficient Sample
Figure 41: As-fired ash and coupon deposit analysis, baseline study
-------
Wisconsin Power & Light Company
Columbia #1
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON DATA SUMMARY
AS FIRED ASH AND COUPON DEPOSIT ANALYSIS
Sample Location
Ash Fus1bil1ty-°F
Initial Deformation Temp.
Softening Temp.
Fluid Temp.
Ash Composition-Boy Weight
S109
A1203
CaO 3
MgO
NazO
T102
OVERFIRE
Pulverized Coal
ip. 2110
2170
2260
41.3
17.2
7.6
13.4
4.0
0.6
0.5
0.8
14.0
AIR STUDY
Probe G1
Initial
I.S.2
6.9
3.6
76.4
3.5
1.0
0.5
0.5
0.3
6.5
Probe H
Outer
1920
1940
2060
20.7
8.3
56.8
6.9
2.0
0.5
0.5
0.5
3.4
Probe I
Outer
1930
1940
2060
20.5
8.1
55.8
6.8
1.8
0.5
0.5
0.5
3.7
Probe J
Outer
I.S.2
12.8
5.3
69.9
4.9
1.3
0.4
0.3
0.3
2.5
Probe K
Outer
1930
1950
2060
21.5
7.9
57.7
6.8
1.8
0.4
0.4
0.4
2.8
Total
99.4
99.2
99.6
98.2
97.7
99.7
1.
2.
Outer Sample Not Available
I.S. - Insufficient Sample
"Figure 42: As-fired ash and coupon deposit analysis, overfire air study
-------
HUNTINGTON STATION, UNIT #2
TASKS IV, V & VI - TEST DATA ACQUISITION AND ANALYSIS
Flue gas samples for determination of N02, CO, 02 and THC emission levels were
obtained at each of the two economizer outlet ducts. The flue gas samples were
drawn from twelve (12) point grids arranged on centrolds of equal area 1n each
duct. The SOg sample was drawn from a single point 1n the left economizer out-
let duct using a heated sample line. The fly ash sample for carbon loss analy-
sis was obtained from a single point 1n the left air preheater flue gas outlet
duct.
Coal samples were obtained from each feeder and blended to form a composite sam-
ple. Each sample was analyzed by the fuels lab at Combustion Engineering Inc.'s
Krelslnger Development Laboratory. During some of the testing the Deer Creek
Mine Coal was mixed with coal from Peabody Coal Company's Wllberg Mine and from
Amerdan Coal Company's Church Mine. The Wllberg and Deer Creek Mines were min-
ing the same coal seam but from opposite sides of the mountain. The Church coal
was trucked In from a mine 10 to 15 miles south of the plant. Analysis of the
Church, Wllberg and Deer Creek coals showed that the coals had very similar
characteristics. Although analysis showed the coals to be very similar, visual
observations of the furnace waterwalls showed a definite-Increase In furnace
waterwall deposits when firing a blended coal. A blended coal may display prop-
erties more unsatisfactory to unit performance than any of the component coals
fired separately [8]. Typical slag patterns taken during clean, moderate and
heavy slagging conditions at full load operation are shown on Figures 43, 44
and 45. These slag patterns are typical for all modes of boiler operation.
These coals were not blended for those tests conducted In April, May or July of
1975. For those tests conducted 1n September, October or December of 1975, the
coals were usually blended. However, 1t was Impossible to tell on any one day
what percent of each coal was being used. The Wllberg and Church Mine coals
were always blended with the Deer Creek Mine coal and were never used exclusive-
ly.
Summaries of the emissions test data for the baseline, biased firing and over-
fire air operation studies are tabulated 1n Appendix B on Sheets B-l through
B-6. Unit performance test data for the three studies are tabulated on Sheets
B-7 through B-13. The calculated unit performance test results are tabulated
on Sheets B-14 through B-23. Unit efficiency 1s determined using the Heat
Losses Method (ASME Power Test Code, PTC 4.1-1964, Reaffirmed 1973). A set of
unit board and computer data was obtained for each test and 1s tabulated on
Sheets B-24 through B-44.
All test data and results are reported In SI Metric Units with the exception of
the board and computer data, which are reported In the engineering units pro-
vided by plant Instrumentation.
79
-------
FURNACE WA1ERWALL DEPOSIT PATTERN
CO
222
220
220
220
020
000
020
000
000
poo
200
0 1 1
000
i r
000
000
J I
000
V
222
0
220
2 1 1
1 1 1
3 1 1
•
1 1 1
1 2 1
J !•
1 1 1
000
FRONT RIGHT REAR
SIDE
000
y k k
1 2 0
330
1 0 0
^
1 0 0
020
J
030
V
LEFT
SIDE
NO A
FUZZ1
LIGH'
UGH'
MED.
HEAV
RUNN
NOTE
KEY
= 13 HH
LIGHT 13 MM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
-100 HM
50 MM
100 MM
NOTE: 25.k MM - 1 INCH
0
1
2
3
A
5
6
Figure 43: Furnace water-wall deposit pattern, clean furnace
-------
FURNACE WATERWALJL DEPOSIT PATTERN
00
•
k k *»
k I* 2
A i» 2
A It 1
,1 1 1
3 1 1
1 1 1
220
000
4 A 1»
A A CT
1* A 2
1 1 1
-.1 1 1 p
000
020
j L
220
V
322
2
333
*» 3 3
3 3 3
,2 2 2 r
2 1 1
0 1 1
J k
220
000
FRONT RIGHT REAR
SIDE
000
>• •
k 7. 2
k 2 2
-t k 1 1
1 1 0
1 1 0
220
V
LEFT
SIDE
NO AS
FUZZY
LIGHT
LIGHT
MED.
HEAVY
RUNNI
NOTE :
KEY
:13 MM
LIGHT 13 MM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
•100 MM
50 MM
100 MM
NOTE: 25.A MM = 1 INCH
0
1
2
3
1»
5
6
Figure 44: Furnace waterwall deposit pattern, moderate slag furnace
-------
FURNACE WATERWALL DEPOSIT PATTERN
00
ISi
3 k k
366
2 6 6
266
T 2 6 6 |
266
J 6 6 1 L
000
1* 1* I*
6 6 *C
6 6 1
6 6 1
1 6 1 if
6 1 1
J 2 1 1 L
V
i i i
i
222
3 3 3
2 3 3
| 2 3 3 f
233
J i 1 o L
000
FRONT RIGHT REAR
SIDE
222
J 6 6
6 6 1
6 6 1
1 6 6 1
666
J k k 1
V
LEFT
SIDE
NO A
FUZZ
LIGH
LIGH
MED.
HEAV
RUNN
NOTE
KEY
= 13 MM
LIGHT 13 MM - 25 MM
LIGHT TO MED. 25 MM
MED. TO HEAVY 50 MM
-100 MM
50 MM
100 MM
NOTE: 25.*» MM » 1 INCH
0
1
2
3
If
5
6
Figure 45: Furnace waterwall deposit pattern, heavy slag furnace
-------
The thirty (30) day waterwall corrosion coupon evaluations were conducted us-
ing a specially designed probe consisting of four Individual coupons. The wa-
terwall corrosion coupon evaluations are described and discussed under a sep-
arate subsection In this report.
TASK IV - BASELINE OPERATION STUDY
Load and Excess Air Variation - Clean Furnace
Tests 1 through 7 were conducted to determine the effect of varying excess air
on unit emission levels and performance. These tests were conducted at three
unit loads with clean furnace conditions.' Maximum and minimum excess air lev-
els of 40 percent and 15 percent respectively were considered by Utah Power and
Light Co. as acceptable modes of unit operation at full load. These limits were
exceeded on a few occasions.
As shown 1n the following table, N02 emission levels Increased with Increased
excess air. At equivalent levels of theoretical air to the fuel firing zone
(TA), NOz emission levels were higher at full load than at half load.
CO emission levels did not change appreciably with changes in excess air level
or unit loading. The effect of excess air level and unit loading on unit ef-
ficiency, carbon heat loss and unburned hydrocarbon and sulfur dioxide emission
levels Is discussed In conjunction with the other baseline tests.
Main
Steam
Flow
kg/s
376
380
377
380
298
204
203
202
N02
ng/J
248.0
262.8
332.4
357.0
328.0
249.
284.
.2
.3
360.3
CO
ng/J
NA*
6.9
7.7
8.2
NA
4.8
4.8
5.0
X-S Air
18.
27.
32.
40.
28.
23.
32.
Theo. Air
To Firing
Zone - %
116.4
124.8
1
130
137.8
126.9
122
131
.9
.1
50.0
150.0
Unit
Effic.
98.92
90.37
90.16
89.56
90.05
91.05
91.05
90.51
Furnace
Condition
Clean
Clean
Clean
Clean
Clean
Clean
Clean
Clean
Load and Excess A1r Variation - Moderately Dirty Furnace
Tests 8 through 12 were to have been conducted with a moderately slagged fur-
nace. However, when operating with the Deer Creek Mine Coal, 1t was difficult
to obtain any appreciable amounts of slag on the furnace waterwalls. As a re-
sult of this, tests 8 through 12 were actually conducted with clean furnace wa-
terwalls. Excess air levels and unit load were allowed to vary per the test
program.
The NO? levels for Tests 8 through 12, as shown In the following table, are also
found to be proportional to the excess air levels. Although tests 8 through 12
were conducted with excess air levels, unit loads and furnace wall deposits sim-
ilar to tests 1 through 7, the NOz emission levels are generally lower. One
* NA - CO values not available due to operational difficulties with CO analyzer.
83
-------
possible explanation for this difference in NO? emission levels for similar
tests Is the effect of fuel nozzle tilt. The fuel nozzles had a higher upward
tnt for tests 1 through 7. While the higher tilts reduce the residence time
of the hot gases in the furnace, they also decrease the furnace water-wall sur-
face available for cooling. The decrease in surface cooling area results in a
higher flame temperature, which can cause higher N(>2 emission levels. The only
exception to this is Test #8 which correlates well with Test #1. As in Tests 1
through 7, at similar theoretical air levels to the fuel firing zone, NOz emis-
sion levels are again higher for full load tests than half load tests.
CO emission levels again did not show any appreciable change with changes in
excess air level or unit loading. The only exception to this is Test #9 which
when compared to a similar test (#2 or 2A) has an unusually high CO level for
the excess air level at which the unit was operating.
Main
Steam
Flow
kg/s
378
377
375
203
208
N02
ng/J
267.1
258.6
295.3
232.6
318.8
CO
ng/J
6.9
37.5
NA
4.6
5.0
X-S Air
19.5
29.0
40.9
27.4
48.8
Theo. Air
To Firing
Zone - %
117.5
126.3
137.8
126.4
147.6
Unit
Effic.
89.93
90.10
89.64
91.07
90.75
Furnace
Condition
Clean
Clean
Clean
Clean
Clean
Load and Excess Air Variation - Dirty Furnace
The test program called for Tests 13 through 19 to be conducted with heavy fur-
nace wall deposits. As in Tests 8 through 12 it was difficult to obtain any ap-
preciable amount of slag on the furnace wa ten/alls. However, moderately thick
furnace wall deposits of 12.7 mm (1/2") to 50.8 mm (2") were obtained. Excess
air and unit load were again varied per the test program.
As shown In the following table Increasing N0£ emission levels are again found
with increasing excess air levels. Again, for similar TA's, N02 emission levels
for full load are higher than N0£ levels at half load. There is no other obvi-
ous correlation between N02 emission level and unit loading.
Excess air variation and unit load again showed no obvious effect on CO emission
levels.
Main
Steam
Flow
kg/s
377
375
375
298
204
206
205
N02
ng/J
213.8
253.7
319.1
CO
ng/J
.2
,7
285.
215.
233.0
333.1
10.4
7.2
8.3
4.1
4.5
NA
5.0
X-S Air
15.0
Theo. Air
To Firing
Zone - %
20,
35.
23.0
25.
28,
47.8
113.1
118.1
132
121
124
127.9
146.6
Unit
Effic.
90.38
90.34
90.30
90.78
90.74
90.43
90.34
Furnace
Condition
Moderate
Moderate
Moderate
Moderate
Moderate
Moderate
Moderate
84
-------
Analysis of Results
The changes in NO?, CO and carbon heat loss versus TA are shown on Figures 46,
47 and 48, respectively. For the baseline operation study the TA is essen-
tially the same as the total air.
Figure 46 shows that N02 emission levels correlate reasonably well with theo-
retical air to the fuel firing zone. Increasing TA results In increased NOg
emission levels. This correlation is In agreement with previous studies which
have shown that N02 emission levels are proportional to the concentration of
oxygen available for combustion.
Based on the data as plotted in Figure 46, it can be concluded that there is
some variation of N02 emission levels with unit load. As discussed previously
for similar theoretical air levels to the fuel firing zone, NOg emission lev-
els for full load unit operation are higher than NO? levels at half load unit
operation. N02 emission levels for three-quarter (3/4) load operation are of
the same order of magnitude as full load N02 levels.
There 1s no distinct variation of N02 emission levels with furnace waterwall
deposits. The results of those tests performed with moderately dirty furnace
wall deposits have too much scatter to show any correlation between N02 levels
and furnace wall deposits. This lack of correlation may be partially attrib-
uted to the fact that visual observations of furnace waterwall deposits is
very subjective. While furnace wall deposits for Tests 13 through 19 were con-
sidered to be moderately dirty, they may have in fact been very similar to fur-
nace waterwall conditions for Tests 1 through 12.
With the exception of Test #9, Figure 47 shows that CO emission levels did not
show any appreciable variation with changes in TA. As mentioned previously
Test #9 had an. unusually high CO level when considering the furnace slag con-
ditions and the excess air level at which the unit was operating. Below 120
percent TA, Figure 47 shows a slight rise In CO emission levels. This rise in
CO levels below 120 percent TA is in agreement with baseline studies at Alabama
Power Company's, Barry Station, Unit #2. However, the data as presented in
Figure 47 is insufficient to be considered a trend for this study.
Unit loading had no significant effect on CO emission levels. CO emission lev-
els for the half load and three-quarter load tests are lower than the CO levels
for full load tests. However, as the CO levels for all the unit loads are of
the same order of magnitude, 1t is difficult to distinguish what effects changes
In unit loading have on CO levels. Any distinction is further hampered by the
fact that the half load tests are performed at higher excess air levels than
full or three-quarter load tests. The higher excess air level operation at
lower loads would promote more complete combustion resulting in lower CO levels.
Boilers are operated at higher excess air levels at half load for temperature
control purposes, I.e., to maintain superheat and reheat outlet temperatures
and therefore the maximum and minimum excess air limits were shifted upward for
half load operation. Furnace waterwall slag conditions are found to have no ef-
fect on CO emission levels.
Figure 48 shows percent carbon loss 1n the fly ash versus percent theoretical
air to the fuel firing zone. The carbon heat loss results are very similar to
the CO results. There 1s a general trend of Increasing carbon heat loss with
85
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT n
330
310
BPS
oo
Ot
290
270
2SO
230
110
v
s>
0
o
O
7^
120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
150
LEGEND
Unit Load
OHax
O 3/4 Max
O1/2 Max
Furnace Slag
O clean
• Moderately Dirty
Figure 46:
N02 vs. theoretical air to fuel firing zone, baseline study
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT n
CO
•vj
44
40
36
32
28
24
20
16
12
110 120 130 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 47: CO vs. theoretical air to fuel firing zone, baseline study
LEGEND
Unit Load
OMax
D 3/4 Max
O1/2 Max
Furnace Slag
O Clean
w Moderately Dirty
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT 12
.60
-------
decreasing TA. No distinct variation of carbon heat loss with unit loading is
evident with the exception that carbon heat losses for the half load tests are
lower than the carbon heat losses for full load tests. As with the CO results,
this variation may be related to the fact that the half load tests were run
with higher excess air levels than full load tests. The higher excess air lev-
els would promote better carbon burnout. Based on the data as plotted in Fig-
ure 48, carbon heat losses appear to be unaffected by variations in furnace wa-
terwall deposits.
Figure 49 shows unit efficiency versus percent excess air at the economizer
outlet. When viewed without regard to unit load, the scatter in the data as
plotted in Figure 49 overshadows any obvious trend. However, when full load
and half load tests are examined separately a decrease in unit efficiency is
found with increasing excess air at the economizer outlet.
No effect on unit efficiency was obvious for changes in furnace waterwall de-
posits for the baseline operation tests.
SO? emission levels were monitored for each test and are reported on Sheets
B-T and B-2. No correlation was evident between SOg emission levels and ex-
cess air, unit loading or furnace waterwall deposits. It was not possible to
control the SOg emission level as it Is more a function of the sulfur content
of the fuel rather than the mode of boiler operation.
Unburned hydrocarbon emission levels were monitored and were found to be at
such low levels as to be unmeasurable.
A thirty (30) day waterwall corrosion coupon test was conducted in April and
May of 1975. The boiler was operated normally with full load being maintained
as much as possible. The waterwall corrosion coupon test is discussed in the
section "Waterwall Corrosion Coupon Evaluation."
TASK V - BIASED FIRING OPERATION STUDY
Fuel Elevations Out of Service Variation
Tests 1 through 16 were conducted to determine the effect on N0£ emission lev-
els, when taking various fuel elevations out of service (biased firing) at
three different unit loadings and two excess air levels. The test program
called for half load tests being performed with two adjacent fuel firing ele-
vations out of service. However, Utah Power and Light Co. would not permit
this mode of operation. As a result, the half load tests were performed with
only the top fuel firing elevation of the two adjacent elevations out of ser-
vice.
As can be seen in the following table, maximum N0£ emissions control was ob-
tained with the top elevation of fuel nozzles out of service (Tests 1, 4, 7,
9 and 12).
No thirty (30) day waterwall corrosion coupon evaluation was performed follow
ing the biased firing operation study.
89
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
o
H4
u.
u_
LU
91.0
90.8
90.6
90.4
90.2
90.0
89.8
89.6
0
4
0
r&
0
-4
LEGEND
Unit Load
8
Max
3/4 Max
1/2 Max
14 18
22
42 46
50
26 30 34 38
EXCESS AIR, PERCENT
Figure 49: Unit efficiency vs. excess air, baseline study
90
-------
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Main
Steam
Flow
kg/s
375
371
368
297
295
299
218
214
375
370
369
295
299
299
203
210
NO
NU9
ng/J
168,
223,
243,
191,
203.
263,
178,
263,
208.
227.
255.
214.
283.8
248,
187.
224.3
CO
ng/J
16.7
4.8
9.2
6.3
4.4
4.8
4.8
4.1
5.0
5.0
5.2
5.2
5.7
6.4
4.5
4.6
Theo. Fuel Nozzle
Air to Unit Elevation
X-S A1r Firing Efflc. Out of
% Zone-% % Servi ce
19.8 107.1 89.91 Top
118.9 90.40 Center
117.8 89.97 Bottom
98.5 90.14 Top
119.3 90.23 Top Center
119.8 90.97 Bottom Center
106.5 90.99 Top
122.8 90.84 Center
107.6 89.80 Top
125.3 89.97 Top Center
126.8 90.13 Bottom Center
109.1 90.21 Top
127.0 89.97 Center
131.0 90.04 Bottom
124.4 90.77 Top Center
24.7 124.0 90.58 Bottom Center
21.5
20.9
16.8
19.9
20.8
22
24
26
27
29
29
28
31
25
.6
.4
.3
.4
.3
.3
.0
.7
.1
Analysis of Results
Figure 50 1s a plot of N02 emission levels versus theoretical air to the fuel
firing zone. As with the baseline study tests, this figure shows that increas-
ing TA results 1n Increasing N02 emission levels. As evidenced by the scatter
in the data, unit loading does not appear to have any distinct effect on N02
emission levels.
Most of the biased firing tests were performed during the time period when the
coal being fired was a blend of two or three coals. Furnace water-wall slagging
conditions for the biased firing tests ranged from light to moderately dirty
furnace waterwalls. As a result of the small variation In furnace waterwall
deposits, no effect on N02 emission levels was evident. Therefore, furnace
slagging conditions have not been indicated on the biased firing graphs.
Figure 51 is a plot of fuel firing elevation out of service versus N0£ emis-
sions level. As this figure shows, the lowest N02 levels were obtained when
the top fuel firing elevation was removed from service. This method of unit
operation most closely simulates overfire air operation. The highest N02 emis-
sion levels were obtained when the center fuel firing elevation was removed
from service. Removal of the bottom fuel firing elevation from service showed
a reduction In N02 levels from the highest levels obtained when the center fuel
elevation was removed from service. These lower N02 levels may possibly be at-
tributed to the flow of air under the fuel firing zone causing a lowering 1n
bulk flame temperature.
CO emission levels versus theoretical air to the fuel firing zone are plotted
1n Figure 52. No variation 1n CO emission levels with unit loading or furnace
waterwall deposits is evident. The variation In CO emission levels with TA is
not as expected. Test #1 has an unusually high CO emission level. This can be
partially attributed to the fact that the dampers for the top fuel firing ele-
vatton were only 10 percent open as opposed to the 100 percent open desired.
91
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
. UNIT K
ro
W
•
CXI
200
180
160
ir
I
G
100
105 110 115 120 125
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
130
LEGEND
Unit Load
§
Max
3/4 Max
1/2 Max
Fuel Elevation
Not 1n Service
Figure 50: N02 vs. theoretical air to fuel firing zone, biased firing study
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
TOP A
vo
CO
UJ
«/>
o
I
Ul
BOTTOM E
-9
•B-
»
•e-
160
180
200
280
220 240
N02 - ng/0
Figure 51: Fuel elevation out of service vs. N02, biased firing study
LEGEND
Unit Load
OMax
D 3/4 Max
O 1/2 Max
Excess Air
8
Minimum
Normal
-------
UTAH POWER & LIGHT CO-
HONTINGTON STATION
UNIT 12
14
12
10
10
8
100 105 110 115 120 125
THEORETICAL AIR TO FUEL FIRING ZONE. PERCENT
Figure 52: CO vs. theoretical air, biased firing study
130
LEGEND
Unit Load
I Max
13/4 Max
11/2 Max
Fuel Elevation
Not 1n Service
-------
This fact coupled with the low excess air operation may have contributed to the
high CO level. While there is a rise in CO level for TA's below 120 percent,
the variation is not pronounced. Also, Tests #13 and #14 have slightly higher
CO emission levels while operating at the highest TA.
Figure 53 shows that some of those tests (Nos. 3, 4 and 14) with high CO emis-
sion levels also have some of the highest carbon heat loss values regardless of
unit load or TA. Figure 53 indicates that increasing carbon heat loss 1s pos-
sible with decreasing TA. This trend is not completely supported by the data
as plotted. Tests 3, 13 and 14 have higher carbon heat loss values than ex-
pected for the excess air levels at which the unit was operating. It should be
noted that these tests were run with the center and bottom fuel elevations out
of service. Plotting of the fuel elevation out of service versus the CO emis-
sion levels did not provide any useful information; therefore, it is not in-
cluded 1n this report.
Figure 54 shows unit efficiency versus percent excess air at the economizer
outlet. This plot reveals no useful information regarding the effect of excess
air level on unit efficiency.
S02 emission levels were again monitored for each test and are reported on Data
Sheets B-3 and B-4.
Unturned hydrocarbon emission levels monitored were at such low levels as to be
immeasurable.
TASK VI - OVERFIRE AIR OPERATION STUDY
Excess Air and Overfire Air Rate Variation
Tests 1 through 11 were conducted to determine the effect of varying the over-
fire air rate and excess air level on the N02 emission levels and Unit Perfor-
mance. For these tests the overfire air registers were held at horizontal
while the fuel nozzle tilts were allowed to vary from a -14 degrees to a +17
degrees. For each group of tests in this series, the variation in tilt was
held to the minimum allowed while maintaining acceptable superheat and reheat
outlet temperatures. Furnace waterwall deposits were not controlled for these
tests and ranged from light to heavy slagging conditions on the waterwalls.
The overfire air tests were performed during that time period when the coal be-
ing fired was a blend of two to three coals. There was also some problems at
this time with soot blowers being out of operation.
As shown by the following table, N02 emission levels are found to Increase with
Increasing theoretical air to the fuel firing zone. This correlation is evi-
dent regardless of the total excess air level the unit is operating at. Al-
though Tests 1 through 5 were conducted at normal excess air levels, averaging
26.5 percent at the economizer outlet, the N02 emission levels were lower than
for Tests 6 through 8 at minimum excess air levels, averaging 19 percent at the
economizer outlet. This variation was not as expected.
One possible explanation to this unexpected variation 1s that the tilts for
tests 6 through 8 were at a plus ten (+10) degrees while those tilts for tests
1 through 5 ranged from a plus six (+6) to a minus fourteen (-14) degrees.
While the plus tilts 1n tests 6 through 8 reduced the residence time of the hot
95
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
0.60
0.50
to
0.40
0.30
0.20
0.10
iSfS
e-
100
125
130
105 110 115 120
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 53: Carbon heat loss vs. theoretical air, biased firing study
LEGEND
Unit Load
'Max
13/4 Max
i1/2 Max
Fuel Elevation
Not in Service
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
91.1
90.9
90.7
90.5
^ 90.3'
90.1
89.9
89.7
o
o
16
20 24 28
PERCENT EXCESS AIR
32
LEGEND
Unit Load
'Max
'3/4 Max
Max
Figure 54: Unit efficiency vs. excess atr, biased firing study
97
-------
gases in the furnace they also exposed the fire to less furnace water-wall sur-
face. The decrease in furnace waterwall surface cooling area seen by the fire
can result in increased flame temperatures with a corresponding increase in
thermal NOX formation. Previous experience has shown minimum total excess air
gives the minimum N0£ emission levels for any given coal. One possible expla-
nation to this difference in N02 emission levels is that the coal being burned
at this time was a blend of American-Church Mine, Peabody-Wi 1 berg Mine and Pea-
body-Deer Creek Mine coals. The percentages of each coal burned on a daily
basis was an unknown factor. The Church Mine or Wilberg Mine coals were never
used exclusively. Although these coals are of similar individual analysis, in-
creased slagging conditions were experienced when firing a blend of these coals.
The testing at this time was further aggravated by the necessity from that
which had been required when burning design coal. Wall deposits were greater
at this time, with running slag being experienced where previously only dry
slag had existed.
Although those tests conducted at the normal excess air operating level re-
sulted in the lowest NOX values* normal excess air operation was not considered
optimum for NOX control. Based on the above facts, the optimum excess air op-
erating level was considered to be the minimum, approximately 20 percent at the
economizer outlet. The optimum overfire air rate based on the NOJ> emission lev-
el results for Tests 1 through 11 is with the overfire air dampers 100 percent
open. This allows approximately 15 to 20 percent of the total combustion air
to be introduced above the top level of fuel nozzles.
With the exception of Tests 7 and 8, CO emission levels are not found to vary
significantly with changes in TA. Tests 7 and 8 have the lowest TA of Tests 1
through 11. This could contribute to the high CO levels monitored.
Theo. Air Unit OFA
Test Flow N02 CO X-S Air To Firing Effic. Dampers
No. kg/s ng/J ng/J % Zone - % % % Open
1 369 273.7 4.7 27.0 125.2 89.51 0
2 372 251.1 4.6 28.2 120.2 90.13 25
3 372 229.4 4.6 26.2 111.6 89.92 50
4 370 213.0 4.6 25.5 107.1 89.99 75
5 370 205.3 4.5 25.2 105.4 90.05 100
6 372 300.1 4.7 18.5 116.7 90.09 0
7 372 247.3 36.3 19.2 102.9 89.70 50
8 370 221.6 49.0 19.2 96.6 90.46 100
9 369 353.2 4.8 32.1 123.2 89.44 25
10 368 334.0 4.4 33.8 113.8 89.18 75
11 370 332.3 4.8 33.8 112.5 89.48 100
Overfire Air T1lt Variation
Tests 12 through 18 were conducted to determine the effect of fuel nozzle and
overfire air register tilt on NOg emission levels and unit performance. These
tests were conducted at the optimum overfire air rate (dampers 100 percent open)
and excess air level (approximately 20 percent excess air at the economizer out-
let) established In Tests 1 through 11. The fuel nozzles were varied from a -20
degrees to a +25 degrees, while the overfire air registers were varied from a
98
-------
-30 to a +30 degrees. This variation of the fuel nozzle and overflre air reg-
ister tilt angles moves the fuel firing zone both 1n the furnace and 1n Its
effective position relative to the overflre air registers. Movement of the
fuel nozzles and overflre air registers away from each other accentuates the
effect of staged combustion. Movement of the fuel nozzles and overflre air
registers toward each other minimizes the effect of staged combustion because
the air is being forced down Into the firing zone. For these tests the fur-
nace slagging conditions were allowed to vary, and ranged from light to moder-
ate waterwall deposits.
As shown 1n the following table, minimum N0£ levels were obtained when the fuel
nozzles and overflre air registers were separated by 20 to 30 degrees (Tests 14
and 17). Parallel operation of the fuel nozzles and overflre air registers was
nearly as effective, when both the fuel nozzle and overfire air registers were
1n a horizontal position (Test 15) or when both were tilted downward to their
respective limits (Test 12). N02 emission levels were highest when the nozzles
were moved toward each other. Therefore, the optimum condition was at a tilt
differential of 20 to 30 degrees away from each other (Tests 14 and 17). For
ease of boiler operation the tilt conditions for Test 17 were utilized 1n Tests
19 through 24.
With the exception of Tests 12 and 18, CO emission levels appear to be relative-
ly unaffected by variations in fuel nozzle and overflre air register tilts. It
should be noted that for Tests 12 and 18 the TA was less than 100 percent and
that the fuel nozzles and overflre air registers were essentially operating in
parallel. Test 12 was conducted with the fuel and overflre air nozzles at maxi-
mum minus tilt, while test 18 was conducted with the fuel and overflre air noz-
zles at maximum plus tilt. Operation of the boiler with the tilts at the maxi-
mum plus will reduce the residence time of the gases 1n the furnace and may re-
sult in higher CO levels due to Insufficient burnout of the CO.
Theo. Air Unit Fuel OFA
To Firing Effic. Nozzle Register
Zone - % _% Tilt-0 Tilt-0
12 370 223.3 10.4 23.1 99.6 90.11 -20 -30
13 364 263.4 4.5 25.1 101.1 89.83 0 -30
14 370 179.8 4.8 22.0 99.2 90.32 -20 0
15 370 212.1 4.6 25.1 101.1 89.82 0 0
16 372 283.5 4.4 21.3 98.4 89.90 +25 0
17 377 186.1 4.9 23.5 99.8 90.01 0 +30
18 367 252.1 15.8 21.7 98.6 89.51 +25 +30
Load and Furnace Waterwall Deposit Variation at Optimum Conditions
Tests 19 through 24 were conducted at the optimized conditions of excess air
level, overftre air rate and fuel nozzle and overflre air register tilt as de-
termined in Tests 1 through 18. These tests were run to determine the effect
on NOX emission levels and unit performance at optimum conditions, while vary-
ing unit load and furnace wall deposits. These tests were conducted at an aver-
age excess air level of 21 percent, overflre air register dampers 75 to 100 per-
cent open and with the overflre air registers tilted to +30 degrees while the
fuel nozzles were held at horizontal.
99
-------
As shown 1n the following table, NO? emission levels are affected by unit load,
with higher N02 levels for higher loads. Furnace waterwall deposits have a
greater effect on NO? levels at lower loads. A distinct effect on N02 emis-
sion level Is evident at half (1/2} load (Test Nos. 23 and 24), while this d1s.
tlnctlon 1s considerably less for three-quarter (3/4) load (Tests 21 and 22)
and is reversed for full load (Tests 19 and 20). This suggests a possible re-
lationshlp between furnace waterwall deposits, unit load and N0£ levels.
Except for Test 23, CO emission levels are unaffected by unit load or furnace
waterwall deposits. The CO level and the carbon heat loss for Test 23 are
high when considering the conditions at which the boiler was operating.
N02
ng/J
196
190
161
167.8
132.0
155.3
X-S Air
18
19
19
21
22.8
23.9
Theo. Air
To Firing
Zone - %
95.8
97,
98.
95.0
97.3
99.7
Unit
Efflc.
89.79
89.85
90.41
90.65
90.79
90.76
Furnace
Condition
Clean
Moderate
Clean
Moderate
Clean
Moderate
Analysis of Results
The changes in NOg, CO and carbon heat loss versus changes In theoretical air
to the fuel firing zone are shown in Figures 55, 56 and 57, respectively.
Figure 55 shows that there is a definite trend in N02 emission levels with
changes in TA. Increasing TA results in increasing N02 emission levels. Fur-
nace waterwall deposits and unit load are also indicated on Figure 55. No cor-
relation between furnace waterwall deposit variation and N02 emission level is
evident from the data as plotted. The effect of unit load on NOg levels shows
lower N02 levels for lower loads. As these low load tests (Tests 21, 22, 23
and 24) also have some of the lowest TA's, these should be compared with full
load tests at similar TA's to find the effect of unit load. A comparison of
Tests 21 and 24 with Tests 14 and 17 or of Tests 22 and 23 with Tests 19 and
20 shows that lower loads resulted in lower N02 levels.
CO emission level versus theoretical air to the fuel firing zone is plotted in
Figure 56. Figure 56 indicates rise in CO emission levels below TA levels of
104 percent. Previous studies at Alabama Power Company's, Barry #2 [2] have
shown that CO levels tend to rise rapidly in those TA regions where N02 levels
are falling rapidly.
As is evident In Figure 57, decreasing theoretical air to the fuel firing zone
results 1n Increasing carbon heat loss levels. This trend, while being similar,
is much more apparent than with the CO emission levels, with carbon heat losses
rising rapidly below 104 percent TA. This trend was also observed at Alabama
Power Company, Barry Station, Unit #2 [2].
Figure 58 shows the effect that variation of fuel nozzle and overfire air reg-
ister tilts has on N02 emission levels.
100
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT 12
100 105 110 115 120 125
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 55: N02 vs. theoretical air to fuel firing zone, overflre air study
LEGEND
Furnace Slag
8
Light
Moderate
Heavy
Unit Load
OMax
U 3/4 Max
<>V2 Max
-------
UTAH POWER & LIGHT CO.
HUNTINCTON STATION
UNIT 12
o
ro
o>
8
48
44
40
36
32
28
95
100
125
105 110 115 120
THEORETICAL AIR TO FUEL FIRING ZONE. PERCENT
Figure 56: CO vs. theoretical air to fuel firing zone, overflre air study
LEGEND
Furnace Slag
O Light
(P Medium
• Heavy
Unit Load
Otfax
D 3/4 Max
OV2 Max
-------
UTAH POWER & LIGHT CO.
HUNTINCTON STATION
UNIT #2
0.65
u>
§
I
o
&
«t
o
0.55
0.45
0.35
0.25
0.15
95 100 105 110 115 120 125
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 57: Carbon heat loss vs. theoretical air, overfire air study
LEGEND
Furnace Slag
I
Light
Moderate
Heavy
Unit Load
8 Max
^ 3/4 Max
Ol/2 Ma
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
340
320
300
280
260
240
220
200
180
160
NSPS-
r
1
^
<
)
)
^
\
c
^"""-x,
)
\
c
1
^-^
)
fr
"\
^x.
f\ 1
"Xw
^*N
(
\
r o
^^.
)
ft 1
\<
C 1
)
n 9
35 30
25 20 15 10 5 0
TOWARD DEGREES AWAY
OFA REGISTER & FUEL NOZZLE TILT DIFFERENTIAL, DEGREES
Figure 58: N02 vs. tilt differential, overflre air study
-------
Figure 58 shows that as the fuel nozzles and overffre air registers are angled
toward each other, NO? emission levels rise. Conversely as the nozzles are
moved away from each other, the effect of staged combustion becomes more pro-
nounced, until at 30 degrees away from each other the NOg emission level 1s
186 ng/J for full load unit operation.
Prior experience at Alabama Power Company's, Barry Station, Unit #2 has shown
that flame stability can be a limiting factor as the fuel nozzles and overfire
air registers move substantially away from each other. Tests, similar to Tests
12 through 18, at the Barry Station, Unit #2 Indicated a probable maximum dif-
ferential of 50 degrees between the fuel nozzles and overfire air registers [2],
Flame instability was not apparent during tilt variation tests at Utah Power
and Light Company's Huntlngton Canyon Station, Unit #2. The maximum differen-
tial of the fuel nozzles and overfire air registers away from each other for
these tests was only 30 degrees compared to 50 degrees for the Barry tests.
Figure 59 shows unit efficiency versus excess air at the economizer outlet. A
decrease in unit efficiency is evident with increasing excess air at the econ-
omizer outlet. This trend is in agreement with the baseline and biased firing
tests at Huntington Canyon Station, Unit #2 and previous tests at Barry Station,
Unit #2.
S0£ emission levels were monitored and are reported on Sheets B-5 and B-6. As
with the other tests there is no apparent correlation between S02 emission lev-
els and excess air, unit load or furnace waterwall deposits.
Unburned hydrocarbons were monitored for all overfire air tests and were at
such low levels as to be unmeasurable.
A thirty (30) day waterwall corrosion coupon test was conducted in November,
1975. The boiler operated with the overfire dampers 100% open and with full
load being maintained as much as possible. The overfire air corrosion coupon
test is discussed in the following section, Waterwall Corrosion Coupon Evalua-
tion.
WATERWALL CORROSION COUPON EVALUATION
Following completion of the steady state phases of the baseline and overfire
air test programs, thirty (30) day waterwall corrosion coupon evaluations were
performed. The purpose of these evaluations was to determine whether any mea-
surable changes in coupon weight losses could be obtained for the modes of
firing under study.
The Individual probes were exposed at five locations on the furnace front wall
as shown on Figure 60. The coupon temperatures were maintained at the same
levels for each 30 day run and a typical tract of the control temperature range
for each of the twenty coupons is shown on Figure 61.
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 B45 and B46. The weight losses are calculated as mg/cm2 of coupon sur-
face area.
Figures 62 and 63 show the unit load schedules for each of the 30 day test
105
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
C_5
UJ
Q.
LiJ
91 8
91 fi
Ql 4
Ql 2
91 0
on o
90 6
90 4
90 2
on n
3U. U
on o
oy .0
QQ C
0:7.0
QQ A
O3 .f
PQ ")
oy . £
89.0 -
4
£•
^
AA
A
A
A
^
A
A
"
i
/
A
'
si
C
1
^
A
2^
^
A
^
&
LEGEND
Unit Load
A Max
A 3/4 Mai
A 1/2 Ma.
16 18 20 22 24 26 28 30 32 34
EXCESS AIR, PERCENT
Figure 59: Unit efficiency vs. excess air, overflre air study
106
-------
A
c
n
n
a
a
D
a
^^•M
V
1
n
u
t OVERFIRE AIR \T
COMPARTMENT |L
2
54 Rd M 79 ' TM
rl TT fTTIMIMX
• 52.71 (172 11 )
51.41 ri68'8")
bU.8^ (Ib6'9")
FRONT WALL
Figure 60. Waterwall corrosion probe locations, Huntington Station No. 2
107
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT #2
TYPICAL COUPON
TEMP. RANGE
ALL 5 PROBES
CONTROL TEMP. 399 C (750F)
TOP COUPON OF EACH PROBE
Figure 61. Typical corrosion probe temperature ranges, Huntington Station No. 2
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT |g
2
§
AUG. GROSS MW/HR
30 BAY PERIOD
273 Mrf/HR
6/03/75
6/04/75
6/06/75
6/07/75
6/08/75
6/09/75
6/10/75
CORROSION PROBE EXPOSURE TIME - DAYS
FIGURE 62: GROSS MM LOADING vs. TIME - BASELINE CORROSION PROBE STUDY
-------
UTAH POWER & LIGHT CO.
HUNTINGTON STATION
UNIT |g
450
noo
350
300
250
200
10/23/75 10/24/7510/25/75 10/26/75 10/P7/75 10/28/75
10/29/75
10/30/7"5
AV6. GROSS MW/H? -
30 DAY PERIOD
347 Mrf/HR
III|IU, rr:: ;::: un; :::- ::j: :.i: :u: ;i;^.; ,ii^-i.uH/« Ht»
I75 11/17/75 11/18/75 11/19/75
11/21/75
11/22/75
11/23/75
CORROSION PROBE EXPOSURE TIME - DAYS
FIGURE 63: GROSS MM LOADING vs. TIME - OVERFIRE AIR CORROSION PROBE STUDY
-------
periods.
The overfire air portion of the study was conducted using the "optimum" oper-
ating conditions determined during the overfire air steady state tests.
Throughout the overfire air study the overfire air dampers were maintained at
the full open configuration over the range of unit loading shown on Figure 63
with the following exceptions. On November 2, 1975 the overfire air were
closed during unit start-up. Between November 5 and November 7, 1975 one com-
partment was closed when required to maintain proper windbox pressure. Novem-
ber 15 to November 16, 1975 one compartment was closed at reduced unit loading
and on November 22 and November 23, 1975 one or both dampers were closed during
low load operation.
The percent oxygen was monitored daily during each thirty day study at each
probe location and was found to range between 7 and 19 percent Q£ during both
the baseline and overfire air studies.
The weight losses calculated for the baseline portion of the test program were
found to be greater than those for the overfire air tests. The average weight
losses for all five probes were as follows:
Baseline Overfire Air
3.4266 mg/cm2 2.6357 mg/cm2
These values are within the range of losses which would be expected for oxida-
tion of carbon steel for a 30 day period. This premise is verified by control
studies conducted in C-E's Kreisinger Development Laboratory using probes ex-
posed during the biased firing study conducted at Alabama Power Co., Barry #2.
These probes'were cleaned and prepared in an Identical manner to those used for
furnace exposure and placed in a muffle furnace for 30 and 60 day exposures at
399°C with a fresh air exchange. The test results were as follows:
Probe Wt. Loss mg/cm2 - 30 Days
M (30 day) 4.7999
Q (r
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 decreasing in the second
thirty days. Based on these results, it appears that the differences in weight
losses observed during the test program are within the ranges to be expected
from oxidation alone.
Chemical analysis of coupon deposits taken during the test program indicate an
enrichment in iron as compared with the "as fired" coal ash analysis with the
greater enrichment occurring during the baseline study. Also the degree of
Iron enrichment during the overfire air study was not as consistent as was
noted 1n the baseline study. There is some question as to whether the ash de-
posits accurately represent Inner and outer layers of deposit In some probes.
Despite the uncertainty there was nothing about the compositions or fusibility
111
-------
temperatures which would indicate a change In slagging condition between the
baseline and overfire air studies. The as-fired ash and coupon deposit analy-
ses are given on Figures 64 and 65.
112
-------
Utah Power & Light Company
Huntington Canyon, #2
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSIO-N COUPON DATA SUMMARY
AS FIRED ASH AND COUPON DEPOSIT ANALYSIS
Sample Location
Ash Fus1bil1ty-°F
Initial Deformation Temp.
Softening Temp.
Fluid Temp.
Ash Composition-%by Weight
S102
A1203
CaO
MgO
Na20
K20
S03
Total
BASELINE STUDY
Mill Exhauster
2050
2160
2440
49.0
15.5
7.2
9.0
2.0
4.8
1.0
1.0
7.6
Probe #1
1980
2040
2210
21.0
4.5
54.6
9.0
2.1
2.0
0.5
0.3
6.0
Probe #2
I.S.
18.4
6.0
47.9
6.5
1.1
3.2
0.9
0.6
15.4
Probe #3
1980
2160
2270
21.0
4.8
54.8
8.0
1.7
1.9
0.6
0.4
6.8
Probe #4 Probe #5
I.S. 1910
I.S.
2050
18.5 I.S.
7.9
45.6
8.3
1.3
3.3
0.6
0.3
14.1
97.1
100.0
100.0
100.0
99.9
I.S. - Insufficient Sample
Figure 64: As-fired ash & coupon deposit analysis, baseline study
-------
Utah Power & Light Company
Huntington Canyon, #2
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON DATA SUMMARY
AS FIRED ASH AND COUPON DEPOSIT ANALYSIS
OVERFIRE AIR STUDY
Sample Location
Ash Fusibil1ty-°F
Initial Deformation Temp.
Softening Temp.
Fluid Temp.
Ash Compos it1on-Bby Weight
Si02
A12&3
Fe?03
CaO
MgO
Na0
K2
Mill Exhauster Probe #1 Probe #2 Probe #3 Probe #4 Probe #5
SO
2130
2200
2450
51.5
17.0
4.7
8.9
1.1
5.2
0.6
1.0
6.6
2200
2250
2530
1890
1920
2020
56.9
19.2
4.4
9.6
1.1
4.6
0.6
0.6
<0.1
28.7
11.3
32.8
13.9
2.6
2.5
0.4
0.4
4.7
2120
2210
2440
1940
1970
2140
I.S.
55.6
18.3
5.4
9.1
1.0
4.4
0.6
0.6
0.3
29.3
26.8
25.5
9.3
1.6
2.2
0.3
0.9
3.8
23.9
9.2
39.9
11.9
2.3
2.0
0.3
0.5
5.5
Total
96.6
97.0
97.1
95.3
99.9
95.5
I.S. - Insufficient Sample
Figure 65: As-fired ash & coupon deposit analysis, overfire air study
-------
SECTION III - EPA CONTRACT 68-02-1367
ALABAMA POWER COMPANY, BARRY STATION, UNIT #2
INTRODUCTION
This program encompassed the work to be performed under the second phase of a
two phase program to identify, develop and recommend the most promising com-
bustion modification techniques for the reduction of NOX emissions from tan-
gentially coal fired utility boilers with a minimum impact on unit performance.
Phase I (performed under EPA Contract 68-02-0264) consisted of selecting a
suitable utility field boiler to be modified for experimental studies to eval-
uate NOX emission control. Phase I also included the preparation of prelimi-
nary drawings, a detailed preliminary test program, a cost estimate and de-
tailed schedule of the program phases and a preliminary application economic
study indicating the cost range of a variety of combustion modification tech-
niques applicable to existing and new boilers [1].
Phase II consisted of modifying and testing the utility boiler selected in
Phase I to evaluate overfire air and biased firing as methods for NOX control.
This phase also included the completion of detailed fabrication and erection
drawings, installation of analytical test equipment, updating of the prelimi-
nary test prdgram, 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 Ala-
bama Power Company. This unit is a natural circulation, balanced draft design,
firing coal through four elevations of tilting tangential fuel nozzles. Unit
capacity at maximum continuous rating (MCR) is 113 kg/s main steam flow with a
superheat outlet temperature and pressure of 538°C and 12.9 MPa. Superheat and
reheat temperatures are controlled by fuel nozzle tilt and spray desuperheatfng
A side elevation of the unit prior to modification is shown on Figure 66.
Throughout this report NOX emission levels are expressed as ng/J N02.
115
-------
Figure 66. Unit side elevation, Alabama Power Company, Barry Station No. 2
116
-------
CONCLUSIONS
NORMAL OPERATION
1. Under normal unit operation, without overfire air, excess air variation was
found to have the greatest single effect on NOX emission levels, increasing
NOX with increasing excess air. An average increase of 3.34 ng/J 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 NOX and CO emission levels and the percent carbon in
the fly ash.
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 be-
coming greater below a level of approximately 20 to 25 percent excess air.
CO levels in excess of 23.9 ng/J were considered unacceptable for the pur-
poses of this program.
OVERFIRE AIR OPERATION
1. NO reductions of 20 to 30% were obtained with 15 to 20 percent overfire
air when operating at a total unit excess air of approximately 15 percent
as measured at the economizer outlet. This condition 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 de-
creases in NOX levels to justify their use. Biased firing, while poten-
tially as effective, necessitates a reduction in unit loading and is there-
fore less desirable as a method of NOX control.
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 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 ob-
servations and absorption rates were not significantly affected 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 over-
fire 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
NOX levels. Changes in distance less than 3 meters did affect NOX levels to
* See Appendix D.
117
-------
a limited extent with the NOX level increasing with decreasing distance.
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 NOX control, emission levels increased when the nozzles were directed
toward each other, and flame stability decreased when they were directed
away from each other by more than 20-250. With the overfire air tilts
fixed in a horizontal position, acceptable unit operation was obtained,
however, NOX levels varied with fuel nozzle position.
6. The results of the 30 day baseline, biased firing and overfire air corro-
sion coupon runs indicate that the overfire air operation for low NOX op-
timization did not result in significant increases in corrosion coupon
degradation. Additional studies will be required to verify these observa-
tions over long-term operation.
7. Variables normally used to control normal boiler operation should not be
considered as NOX controls with coal firing. These variables include unit
load, nozzle tilt, pulverizer fineness, windbox dampers and total excess
air.
8. Overall unit efficiency was not significantly affected by overfire air op-
eration.
118
-------
OBJECTIVES
The objective of program Phase II was to complete the design of the overfire
air system, modify the Barry #2 unit accordingly, perform baseline, biased
firing and optimization tests and based on the results of this program, pre-
pare 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 drawings necessary for
modification of Barry No. 2 to incorporate 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 com-
partments (thereby prohibiting the use of one elevation of fuel noz-
zles).
c. Introduction of hot overfire air only with consideration for air pre-
heat 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 modifi-
cation of the Barry No. 2 unit.
TASK III
Install all necessary instrumentation required to measure flue gas constituents
and characterize the effects of combustion modifications on unit performance.
Specifically the following determinations were made:
a. Flue gas constituents: NOX, SOX, CO, HC, 02
b. Unit Performance Effects:
Fireside Corrosion
Furnace Heat Absorption
Sensible Heat Leaving Furnace
Superheater, Reheater and Air Heater Performance
119
-------
TASK IV
Conduct a baseline test program to establish the effect of unit load, wall
slagging and excess air variation on baseline emission levels, thermal perfor-
mance and operating ranges. A baseline corrosion coupon test of 30 day dura-
tion 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 de-
gree 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 function-
ally check equipment to determine that proper operation is obtained. (See Fig-
ure 67).
TASK VII
Complete final preparations for conducting the overfire air test program to be
conducted in Task VIII including the following:
a. Finish installation of the furnace waterwall thermocouples.
b. Check out all necessary test instrumentation for proper installation
and operation.
c. Review test program with EPA project officer and utility 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 generated and compare
this data with that obtained during Task V. The program investigated the ef-
fect of overfire air location and rate at various unit loadings and evaluated
operating 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 tangentially 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.
120
-------
F-FUEL AND AIR
A-AIR
0-OVERFIRE AIR
Figure 67. Schematic overflre air system, Barry Station No. 2
121
-------
DISCUSSION
Tasks 1, 2 and 3 were completed essentially as stated in the program Phase II
Objectives.
TASK IV & V - BASELINE AND BIASED FIRING TEST PROGRAMS
Test Data Acquisition and Analysis
The flue gas samples for determination of NOX, Og, CO, SOg and HC emission lev-
els were obtained at each of the two economizer outlet ducts. The emissions
monitoring system is shown in Figure 68.
The flue gas samples were drawn from a twenty-four (24) point grid arranged 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 sam-
ples for carbon loss analysis and dust loading were obtained at a single point
in each duct.
The percent QZ 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 concentra-
tions:
1. NO: Chemiluminescence Analyzer
J\
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 NOX emission test data is tabulated on Data Sheets Cl, C2, C3,
C4 and C5.
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
122
-------
Figure 68. Gaseous emissions test system
123
-------
efficiencies were calculated for each test run. Unit efficiency was deter-
mined using the heat losses method (based on ASME Power Test Code 4.1-1964).
The 30 day waterwall corrosion coupon evaluation was conducted using a spe-
cially designed probe consisting of four individual coupons. Individual
probes were exposed at five locations on the front furnace wall as shown on
Figure 69. A typical trace of the control temperature range for each of the
twenty coupons is shown on Figure 70. 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 excess 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, NOx emission levels increased with increased
excess air but did not change significantly with changes in unit loading. An
average increase of 3.34 ng/J was noted for each 1% change in excess air over
the normal unit operating range.
Main
Steam Theo. Air Unit
Flow NOg CO X-S Air To Firing Eff. WW
kg/s ng/J ng/J % Zone - % _J» Slag
1 61 319.3 7.5 35.5 130.6 88.3 Clean
2 62 246.0 43.5 17.5 117.1 88.2 Clean
3 59 362.8 2.5 58.9 151.3 87.6 Clean
4 88 215.0 11.9 12.6 109.2 89.3 Clean
5 112 248.6 9.5 22.7 117.9 89.0 Clean
6 113 181.8 47.3 11.7 107.2 89.1 Clean
7 112 335.1 10.1 30.8 125.3 89.5 Clean
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 N02 emission
levels using excess air reduction was therefore limited to approximately 248.6
ng/J as obtained during Test 5.
The changes in NO?, CO, percent carbon loss in the fly ash and unit efficiency
versus theoretical air to the fuel firing zone are shown on Figures 71, 72, 73
and 74, respectively. The theoretical air (TA) to the firing zone is used in
this case as It accounts for variations in position and leakage in the compart-
ment 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 71 for clean
furnace conditions the N0£ correlates well with TA with little variation due
to unit load. As shown on Figures 72 and 73 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 74 1s a plot of unit efficiency versus
124
-------
(70'4") 21.44
m
-
V "'- -
"1 20FAELEV.1 -~~^~"
r
D
£ FUEL ELEV. A
2 3
Qi FUEL ELEV. B fl
U
\y
P
D
£ FUEL ELEV. C
4 5
_n £ FUEL ELEV. D R
U U
—- -^
— '
»
" Each
p
D
-
-
\/
m
i
/\
D
D
-
-
V V
/\
V
FRONT WALL
. Probe Nos. Above
(69'-6") 21.18m
(6V-9") 18.82m
(57'-5") 17.50m
(49'-H") 15.22m
(45'-7") 13.89m
Figure 69. Waterwall corrosion probe locations, Alabama Power Company
Barry Station No. 2
125
-------
TYPICAL COUPON
TEMP. RANGE
ALL 5 PROBES
TEMPERATURE - °F
0«
CONTROL TEMP. - 750 F(399C],
TOP COUPON OF EACH PROBE
Figure 70: Typical corrosion probe temperature, range, Barry Station No. 2
126
-------
ro
380
360
160' u-.
100
160
110 120 130 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 71: N02 vs. theoretical air to fuel firing zone, baseline study, Tests 1-14
LEGEND
Unit Load
OMCR
D 3/4 MCR
1/2 MCR
Furnace Slag
O Light
Moder
Heavy
-------
ro
Co
131
121
111
101
91
81
71
61
51
41
31
21
11
1
100
*
\
160
LEGEND
Unit Load
OHCR
D 3/4 MCR
MCR
Furnace Slag
Ought
9 Moderate
• Heavy
110 120 130- 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 72: CO vs. theoretical air to fuel firing zone, baseline study, Tests 1-74
-------
1.0
0.9
0.8
^ 0.6
/H •-
8 0.5
iv eg 0.4
o
o
QC
0.3
0.2
0.1
0
100
110
120
130
140
150
160
LEGEND
Unit Load
MCR
3/4 MCR
1/2 MCR
Furnace Slag
I
Light
Moderate
Heavy
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 73: Percent carbon loss vs. theoretical air to fuel firing zone, baseline study, Tests 1-14
-------
o [Z
90
89
8
QC
UJ
Q.
•
O Op
Z UU
Lkl
»—t
O
M*
u.
&
H-
NM
Z P7
3 O/
OC
ot>
OK
•V
S.O
d^
0
^
O
O
1^ ^
*<2>
O A
£
^^
a
^
^ •
^
>^
^^
*^
»<
LEGEND
BASELINE TESTS
Unit Load Furnace Slag
QMCR O Light
Q3/4 MCR 3 Moderate
<>l/2 MCR * Heavy
BIASED FIRING TESTS
Unit Load Fuel Elev. Out
of Service
-
(^ Max Poss . ^ Top
A 3/4 MCR tf) Top Ctr.
Q 1/2 MCR £Bot. Ctr.
flBot.
10
20
30
40
50
60
UNIT EXCESS AIR - ECONOMIZER OUTLET, PERCENT
Figure 74: Unit efficiency vs. unit excess air
-------
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 Cl and C2. The S02 levels measured are also shown on Data Sheets
Cl and C2.
Furnace Wall Deposit Variation
Tests 8 through 14 were conducted to determine the effect on unit performance
and emission levels of varying furnace water-wall deposits from a clean condi-
tion to the maximum possible slagging condition obtainable. The maximum slag-
ging condition was obtained after operation in excess of twenty-four hours
without operating any wall blowers. During this time period slag deposits of
up to 102 mm in thickness could be obtained in and above the fuel firing zone.
Main
Steam Theo. Air Unit
Test Flow N02 CO X-S Air To Firing Eff.
No. kg/s ng/J ng/J % Zone - % % WW Slag
8 114 213.5 14.1 21.5 116.9 89.6 1/2 Max Dep
9 112 178.7 130.2 13.0 108.5 89.6 1/2 Max Dep
10 112 286.1 1.6 26.0 120.8 89.6 1/2 Max Dep
11 59 267.0 90.3 32.7 128.0 88.3 Max Dep
12 57 327.2 66.9 51.2 144.1 87.9 Max Dep
13 114 247.7 12.4 20.7 115.7 89.2 Max Dep
14 113 292.6 10.3 24.3 119.2 89.3 Max Dep
As can be seen from Figure 71, furnace slagging did not exhibit a discernable
effect on NOX emission levels. As shown in Figures 72 and 73, this condition
was also found to be true for carbon loss in the fly ash and CO emission lev-
els with the exception of the half load Tests 11 and 12 where CO levels higher
than those obtained with clean furnace conditions were observed. The high CO
levels may have been due to slag buildup 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 74 indicates
that furnace cleanliness did not exhibit any discernable effect on unit effi-
ciency.
Slag patterns taken during clean, moderate and heavy slagging conditions at
full load operation are shown on Figures 75, 76 and 77.
TASK V - BIASED FIRING STUDY
Fuel Elevations Out of Service Variation
Tests 15 through 24 were conducted to determine the effect on NOX emission lev-
els of taking various fuel elevations out of service (biased firing) at various
unit loadings. As shown on the following table the maximum NOX emissions con-
trol was obtained with the top elevation of fuel nozzles out of service at max-
imum 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 NOX reductions obtained by biasing the top
131
-------
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FUZZY 4"
RUNNING
TEST
DATE 11/14/
TIME IS:
HU LOAD 1
SB
2
3
4
5
S
73
10
24
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LIGHT 1/2" - 1"
LIGHT TO MEDIUM
1" - 2"
MEDIUM TO HEAVY
2" - 4"
HEAVY >4"
RUNNING
TEST f 8
DATE 11/15/73
TINE 11:10
MM LOAD 126
-------
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MEDIUM TO HEAVY
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HEAVY >4"
RUNNING
TEST
DATE 11/16
TINE 14
HHLOAD
H
1 2 |
3
4
•
31
13
m
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125
-------
fuel nozzle elevation, however, the emissions level obtained was below the cur-
rent EPA limit for coal fired units of 301 ng/J.
Main
Steam
Flow
kg/s
55
82
87
89
89
87
86
58
59
56
NO?
ng/J
288.0
272.8
200.6
189.2
189.9
143.1
.2
.5
166.
268.
249.1
306.2
CO
ng/J
9.8
8.9
14.0
11.9
10.6
8.1
9.5
9.1
7.0
8.4
X-S Air
50.1
Theo. Air
To Firing
Zone - %
105.8
Unit
Eff.
.7
.1
.2
26.
21
22.
21.8
24.2
29.0
48.0
47.0
47.0
121.
116.
117.
117.
94.
97.
112.
141.
87.
89.
89.1
3
.9
141.3
89.
88.
88.8
89.6
87.8
87.9
87.7
Fuel Nozzle
Elevation
Out of
Service
Bottom
Bottom
Bottom
Bottom Center
Top Center •
Top
Top
Top
Top Center
Bottom Center
As can be seen from Figure 78, biasing the center two and bottom fuel elevations
did not have a discernable effect on NOX emission levels although the emission
level tended to be higher at reduced unit loadings for given TA levels.
Figures 79 and 80 indicate that with biased firing, low TA levels to the fuel
firing zone were obtained without increasing either CO emission levels or the
carbon loss in the fly ash. Figure 74 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 oper-
ation.
TASK VIII - UN-IT OPTIMIZATION STUDY
Load and Excess Air Variation (After Modification)
Tests 1 through 7 were performed with unit conditions closely approximating
those of Baseline Tests 1-7 under Program Task IV. A clean furnace was main-
tained as the excess air was varied at three unit loads.
The effect of these operating conditions emission levels and performance can
be seen in the Table below.
1
2
3
4
5
6
7
Main
Steam
Flow
kg/s
61
59
NO?
ng/J
221.9
167.4
CO
ng/J
X-S Air
60
87
125
122
117
319.8
162,
202.
165.
238.8
8.4
114.4
10.
33.
8.0
38.8
6.6
.6
.4
33.
16.
64.
15.
21.
12.
25.4
Theo. Air
To Firing
Zone - %
127.1
113.4
155.4
111.0
115.3
107.1
119.5
Unit
Effic.
88.4
88.8
87.4
89.8
89.
89,
89.5
WW Slag
Clean
Clean
Clean
Clean
Clean
Clean
Clean
135
-------
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_, o
JIU
POO
&7U
970,
t/U
9cn
tOU
oon
tou
91 n
fclU
Inn
90
170
50
130
NSPS-
/f
"*
/
/
I
/
/
•
s
/
A
X
/>
o
471
3/4 MCR Olop Ctr.
^1/2 MCR QBot. Ctr
Q Bottom
90
100 110 120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
150
Figure 78: N02 vs. theoretical air to fuel firing zone, biased firing study, Tests 15-24
-------
40
O>
O
O
30
20
10
90
O
LEGEND
Unit Load
OMax Poss.
$3/4 NCR
a 1/2 MCR
Fuel Nozzles
Out of Serv.
I Top
>Top Ctr.
Bot. Ctr.
Bottom
150
100 110 120 130 140
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 79: CO vs. theoretical air to fuel firing zone, biased firing study, Tests 15-24
-------
» • *
0 6
!§0 5
i— i
— • i/i
U> CO
no o n ^
*** y u. j
O
S^
u
i
o 0 . 1
a:
Ul
a.
n
(2
i
,
O
o
a
•
«
»
LEGEND
Fuel Nozzles
Unit Load Out of Serv.
QMax. Poss. £ Top
J3/4 MCR OT°P ctr-
1/2 MCR Q Bot. Ctr
O Bottom
90
100
110
120
130
140
150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
Figure 80: Percent carbon loss vs. theoretical air to fuel firing zone, biased firing study,
Tests 15-24
-------
As witnessed in the previous baseline tests, NOX emission levels increased with
increased excess air.*
ID fan capacities limited excess air to a maximum of 64.7 and 33.5 percent at
half and full load conditions respectively. Acceptable minimum excess air lim-
its were established at 20-25 percent to control CO emission levels. Thus, NOX
emission levels could only be reduced to approximately 215 ng/J through excess
air reduction. The effect of theoretical air to the firing zone on NOX, CO,
and percent carbon loss in the fly ash (% CL) can be seen in Figures 81, 82 and
83. Consistent with the original baseline tests, theoretical air to the firing
zone (TAJ was used for comparison in place of total excess air (EA). TA is de-
termined by location and means of admission as well as quantity, and consequent-
ly better defines that air actually available for initial combustion.
Figure 81 indicates a definite increase in NOX emission levels with increasing
TA for clean furnace conditions. CO emission levels and percent 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 emis-
sion levels. Percent CL can be seen to be greater at higher unit loads for
given TA levels.
Changes in steam generator efficiency versus excess air at the economizer out-
let are presented in Figure 84. Overall, unit efficiency decreases as the ex-
cess 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 Sheet C3.
Furnace Wall Deposit Variation (After Modification)
The effect of furnace waterwall deposits on unit performance and emission lev-
els was studied in Tests 8 through 14 (Clean Condition - Maximum Slagging Con-
ditions). The results are shown in the table below. Dirty conditions were es-
tablished after a minimum of 24 hours of not operating the wall blowers. De-
posits of up to 102 millimeters in thickness could subsequently be found in
and above the fuel firing zone.
Main
Steam Theo. Air Unit
Flow NOg CO X-S Air To Firing Effic.
kg/s ng/J ng/J % Zone - % % HW Slag
122 235.3 7.4 17.8 112.3 89.0 1/2 Max
124 166.9 9.6 12.1 106.9 88.9 1/2 Max
119 215.4 9.2 26.6 120.5 89.5 1/2 Max
* In general, N02 values were slightly lower after modification for the same
test conditions. This resulted from an upgraded firing system installed be-
tween the sets of tests along with an average percent nitrogen in fuel de-
crease 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.
139
-------
i1
CM
100
no
120 130 140 150
THEORETICAL AIR TO FIRING ZONE, PERCENT
Figure 81: N02 vs. theoretical air to firing zone, overfire air study,
load and excess air variation, Tests 1-14
160
LEGEND
Unit Load Furnace Slag
Light
Moderate
Heavy
83/4 MCR
1/2 MCR
-------
115
105
95
85
75
65
8 55
45
35
25
15
100
LEGEND
Unit Load Furnace Slag
8
NCR
3/4 MCR
MCR
O Light
(J Moderate
Heavy
110 120 130 140 150
THEORETICAL AIR TO FUEL FIRING ZONE, PERCENT
160
Figure 82: CO vs. theoretical air to firing zone, overflre air study,
load and excess air variation, Tests 1-14
-------
ro
LEGEND
Unit Load Furnace Slag
O MCR
D 3/4 MCR
OV2 MCR
O Light
$ Moderate
0 Heavy
THEORETICAL AIR TO FIRING ZONE, PERCENT
Figure 83: Percent carbon loss vs. theoretical air to firing zone, overfire air study
load and excess air variation, Tests 1-14
-------
CO
91
90
u 89
88
87
86
9
©
•J
©
0
0
D
©
&•
(O
10
20
30
40
50
0
60
70
UNIT EXCESS AIR - ECONOMIZER OUTLET, PERCENT
Figure 84: Unit efficiency vs. excess air - economizer outlet, all tests (before & after modification)
-------
Main
Steam Theo. Air Unit
Flow N02 CO X-S Air To Firing Effic.
kg/s
NU? i>u A-b Mir 10 riring ETTIC.
ng/J ng/J % Zone - % % W Slag
68 186.8 8.0 30.9 124.6 89.3 Max
61 312.9 7.3 63.1 154.0 88.0 Max
120 195.6 7.1 22.0 116.2 89.0 Max
118 215.4 7.0 25.9 119.9 89.4 Max
Figures 81, 82 and 83 reveal no observable effect of furnace cleanliness on NOX
or CO emission levels along with percent carbon loss in the fly ash. Again,
NOX values were generally slightly lower after modification. Nitrogen in fuel
decreased an average of 0.19 percent from 1.23 percent. Furnace outlet temper-
atures were somewhat lower for Tests 8 through 14 after modification although
fuel higher heating values showed no definite change.
Slag patterns taken during full load operation for clean, moderate and heavy
slagging furnace conditions are shown in Figures 85, 86 and 87.
This set of tests also confirms the results found in Tests 1 through 7, i.e.,
NOX emission levels increase with increased excess air. NOX cannot be de-
creased through excess air reductions below 20 percent excess air while main-
taining an acceptable CO emission level without overfire air.
OFA Location, Rate and Velocity Variation
Tests 15 through 23 were performed to establish the effect of overfire air ad-
mission on NOX emission levels. The unit load and excess air remained constant
for moderately dirty furnace conditions. Location of air admission to the fur-
nace was varied.
Main
Steam Theo. Air Unit Mills
Test Flow NOz CO To Firing Eff. In Adm. Adm.
No. kg/s ng/J ng/J Zone - % _% Serv. Pts.* Rate
15 93 178.7 8.6 114.5 90.0 BCD 0-1 0
16 94 127.3 9.1 96.7 89.8 BCD 0-1 Max
17 94 127.3 9.9 95.8 89.7 BCD 0-2 Max
18 96 114.4 14.6 84.8 89.6 BCD 0-1,0-2 Max
19 94 116.1 11.9 89.3 89.3 BCD 0-1,0-2 1/2 Max
20 96 161.7 8.8 100.5 90.2 BCD 0-3 Max
21 95 241.7 7.7 117.4 90.1 ABC 0-1 0
22 95 164.6 7.8 90.4 89.0 ABC 0-1,0-2 Max
23 96 168.1 7.7 96.9 89.1 ABC 0-1,0-2 1/2 Max
* OFA Admission Points:
0-1: Top overfire air compartment
0-2: Bottom overfire air compartment.
0-3: Top fuel elevation out of service.
144
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1
1 3 3
3
_ f
2
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1
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1
2
3
2
1
1
KEY
NO ASH
FUZZY 4*
RUNNING
TEST fS
DATE 6/19/74
TINE 2:00 PN
NULOAD130MU
-------
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1 3 4
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13 31
333
2
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FUZZY 4"
RUNNING
TEST 18 I 19
DATE 6/20/74
-------
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11 30
11 31
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21 33
4
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RUNNING
TEST »13
DATE 6/28/74
TIHE ":45AN
m LOAD 126
-------
As shown in Figure 88, this set of tests shows a tendency of NOX emission lev-
els to decrease with decreased theoretical air to the firing zone. NOX 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 NOX emission levels by reducing the air input to the fuel firing
zone and admitting the balance of combustion air 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 stability which became very lazy in Test
18. By using the bottom 3 elevations in place of the top 3 elevations, the dis-
tance between the overfire 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 NOX levels obtained with increased distance
between the overfire air and the firing zone. Operation at TA levels below
95% did not result in significant reductions in NOX emission levels.
CO emission levels remained acceptable for the entire set of tests where the
total excess air was approximately 27 percent as shown on Figure 89.
OFA admission location or rate variation exhibited no significant change in
percent carbon loss in the fly ash as shown on Figure 90.
Unit efficiencies were not significantly affected by fuel elevations in service,
or by overfire air location and rate variation. This is explained by the fact
that essentially constant total excess air levels were maintained during this
study.
OFA Tilt Variation
Tests 24 through 30, and 33, were conducted at full unit load with excess air
and theoretical air levels to the firing zone of approximately 24 percent and
92 percent, respectively. With moderate slagging conditions 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 maxi-
mum plus increase the distance between the overfire air and the firing zone.
As with previous methods of increasing this distance, the NOX emission levels
are decreased. Figure 91 shows that as the tilts are moved toward one another
(fuel nozzle tilts up; OFA tilts down), the OFA-firing zone separation is de-
creased and the NOX levels are increased.
Test
No.
Main
Steam
Flow
kg/s
N02
ng/J
CO X-S Air
ng/J %
Theo. Air
To Firing
Zone - %
Unit
Effic.
%
Fuel
Nozzle
Tilt-0
OFA
Tilts-0
24 113 169.6 7.7 25.9 94.2 89.6 -5 0
25 116 145.4 8.3 23.7 92.4 89.3 -23 0
26 114 183.9 9.7 25.1 93.2 88.9 +19 0
27 113 172.2 6.7 22.3 91.5 89.3 -5 -30
28 115 202.1 8.6 20.2 89.6 88.6 +22 -30
29 116 142.3 15.0 23.7 92.6 89.4 -21 +30
30 116 169.6 7.9 21.6 90.7 89.0 -4 0
33 114 166.5 7.5 27.4 94.6 89.0 -22 -22
148
-------
10
ZOU
240
220
200
-a 160
c
CM (go
100
80
. — —
J^
— -~
~^~*
k)^
-^
H*|
^
-
^
^~~
^
a
^^
-^
---
-^^
/-
-^
^'
^
rr
^
^"
^
y
LEGEND
Adm. Pts.
So-2
QO-3*
Rate
ANo OFA
Al/2 Max. OFA
A Max. OFA
Mills In Serv.
ABC @
BCD [D]
SO 85 90 95 100 105 110 115 120
THEORETICAL AIR TO FIRING ZONE, PERCENT
Figure 88: N02 vs. theoretical air to firing zone, overflre air location,
rate & velocity variation, Tests 15-23
-------
40
30
S 20
Ol
o
10
80
85
Figure 89:
90
95
100
105
110
115
THEORETICAL AIR TO FIRING ZONE, PERCENT
CO vs. theoretical air to firing zone, overfire air location,
rate & velocity variation, Tests 15-23
120
LEGEND
Adm. Pts.
&0-1
NO-Z
QO-1, 0-2
QO-3
Rate
A No OFA
A1/2 Max. OFA
A Max. OFA
Mills In Serv.
- ABC (§)
BCD ID!
-------
Ol
0.9
0.8
0.7
3 0.6
Gf
5 0.5
to
I/)
I
UJ
£Q2.
0.
ai
o
80
LOWER LIMIT OF ACCEPTABLE TA LEVELS
85
90
95
100
105
110
115
120
A No OFA
A 1/2 Max. OFA
A Max. OFA
Adm. Pts.
A 0-1
bk 0-2
& 0-1, 0-2
O 0-3
THEORETICAL AIR TO FIRING ZONE, PERCENT
Figure 90: Percent carbon loss vs. theoretical air to firing zone, overflre air location
rate & velocity variation, Tests 15-23
-------
en
ro
220
210
200
5. 190
*
o" 180
170
160
150
140
"70 60
o
60 70
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 f DEGREES
Figure 91: N02 vs. OFA tilt and fuel nozzle tilt differential, OFA tilt variation
Tests 24-33
-------
When the OFA tilts are maximum minus and the fuel nozzle tilts maximum plus,
the term overfire air becomes ambiguous. The actual overflre air is less than
the reported value, because the air is being forced down into the raised fir-
ing zone. A~t this point where the combined fuel nozzle and OFA tilt differen-
tial is 52 degrees toward each other, the NOX emission level reaches a maximum
of 202.1 ng/J.
Percent carbon loss in the fly ash exhibits a definite increase as the fuel
nozzle tilts and OFA tilts move away from each other. This can be seen in Fig-
ure 92.
CO emission levels also show an increase as the tilt differential increases,
yet there is enough total excess air to maintain an acceptable emission level
as shown 1n Figure 93.
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 nozzle and OFA tilt dif-
ferential of 51 degrees away from each other. NOX emission levels decreased
to 142.3 ng/J, yet the CO emission levels began to increase and the fire ap-
peared less stable. Maintaining the fuel nozzle tilts and OFA tilts at approx-
imately equal tilt angles resulted in acceptable flame stability as well as re-
duced NOX emission levels.
For all OFA tilt variation tests the NOX emissions level obtained was below
the EPA limit of 301 ng/J.
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 water-
wall slagging conditions. The NOX emission level results of this series of
tests versus unit loading, expressed as main steam flow, are shown on Figure
94.
Main
Steam
Flow
kg/s
116
87
57
114
86
57
N02
ng/J
169.6
169.1
197.8
166.5
145.2
CO
ng/J
7.
7.
7.
7.
156.4
8.0
7.6
X-S Air
21.6
25.2
46.9
27.4
27.4
45.9
Theo. Air
To Firing
Zone - %
Unit
Effic.
90
89
88
94
90
.7
.4
.5
.6
.6
.5
89,
89.
89,
89.
88.
89.0
UW 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 1n 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 N02 levels obtained, particularly during the baseline tests
153
-------
in
16
15
14
13
12
o
u
10
9
8
7
70 60
O
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 92: CO vs. OFA t1H and fuel nozzle tilt differential, OFA variation
Tests 24-33
60 70
-------
Ul
Ul
0.7
0.6
I
^0.5
£0.4
5
0.3
0.2
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 93: Percent carbon loss vs. OFA tilt and fuel nozzle tilt differential,
OFA tilt variation, Tests 24-33
60 70
-------
en
330
310
290
270
250
230
210
.190
170
150
130
50
50
60
70
(20
80
90
100
110
120
STEAM FLOW - 10JKG/HR
75
PERCENT OF FULL LOAD RATING
100
LEGEND
O Baseline Tests
^Optimization Tests
Figure 94:
NO- vs. main steam flow, ranges for normal & optimum operation
-------
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 encountered
while changing load with optimum operation.
FURNACE PERFORMANCE
During the test program, furnace performance was monitored by use of chrodal
thermocouples installed in the furnace waterwalls. A schematic of the thermo-
couple locations is shown in Figure 95 and a tabulation of the absorption rates
obtained is presented on Sheets C6, C7 and C8. The temperatures and correspond-
ing absorption rates were found to vary significantly with wall slag conditions
making data interpretation difficult. The method finally arrived at as repre-
senting an accurate indication of furnace performance is as follows:
The front and right side wall centertube profiles were plotted as shown in Fig-
ure 96 and the average of these profiles determined. It should be noted that
the maximum and minimum profiles shown do not represent individual walls in
every case, i.e., at given furnace elevations the maximum rate shown may switch
from wall to wall.
For comparison of optimum and normal unit operation with respect to furnace
performance, three full load tests with similar furnace slagging conditions,
etc., were selected for comparison. The average center!ine profiles for these
tests (14, 24, 33) were determined, as shown on Figures 96, 97 and 98, and then
plotted together as shown on Figure 99. 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 sit-
uation was most pronounced in the firing zone where slag accumulations would
normally shed themselves before appreciable accumulations could be built up.
WATERWALL CORROSION COUPON EVALUATION
Following completion of the steady state phases of the baseline, biased firing
and overfire air test programs, thirty (30) day waterwall corrosion coupon
evaluations were performed. The purpose of these evaluations was to determine
whether any measurable changes in coupon weight losses could be obtained for
the various firing modes studied.
The individual probes were exposed at five locations on the furnace front wall
as shown on Figure 69. 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 70.
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
157
-------
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23 24 25 26 27 28 29
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-------
36.58
(120
33.53
(110)
30.48
(100)
27.43
24
0 24 6 8 10 12 14 16 18 20 22 24 26 28
TUBE CROWN ABSORPTION RATE. KG-CAL/HR-CM2
Figure 96: Average centerllne absorption profile, Test 14
159
-------
36.58
(120)
33.53
(110)
30.48
(100)
27.
m
\<
i:
I TEST 124
t Date: 7/29/74
! Load: 124 NU ,
_: Furn. Absorp.: 145.13 10°KG-CAL/HR
-• Total Absorp.: 276.9 lO^KG-CAL/HR
: TA to Fuel Firing Zone: 94.2 I
_: Toul Excess Air: 25.9 X
O - Front WW Center Tube Profile
O - Right WW Center Tube Profile
- A - Avg. Center Tube Profile - Both Walls
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28
TUBE CROWN ABSORPTION RATE. KG-CAL/HR-CM2
Figure 97: Average center!1ne absorption profile, Test 24
160
-------
36.58
(110)
33.53
(110)
24 6 8 10 12 14 16 18 20 22 24 26 28
TUBE CROWN ABSORPTION RATE. KG-CAL/HR-CM2
Figure 98: Average centerllne absorption profile, Test 33
161
-------
36.58
(120)
33.53
(UO)
&
V
« 6 8 10 12 14 16 18 20 22
TUBE CROUN ABSORPTION RATE. KG-CAL/HR-CM2
Figure 99: Average centerline absorption profile, All Tests
162
-------
Sheets C9, CIO and Cll. The weight losses are calculated as mg/cm2 of coupon
surface area. Of the sixty coupons exposed, three were damaged during disas-
sembly 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, overfire air study. In addition, five coupons from probes T and N of
the overfire air study resisted disassembly and were therefore weighed as sin-
gle units and average weight losses were determined.
Figures 100, 101 and 102 show the unit load schedules for each of the 30 day
test periods.
The biased firing study was conducted with the top fuel firing elevation out
of service as this operating condition was shown during steady state biased
firing tests to produce the lowest NOX 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 56.7 kg/s steam flow, with two elevations of mills in
service, damper positions were maintained as follows:
Biased Firing Operation Overfire Air Operation
OFA Dampers 100
100
Coal Auxiliary Coal Auxiliary
100
100
50
30
100 Combustion 50
100 " Air Only 0
30 0
50 0
30 0
0
From 56.7 to 75.5 kg/s steam flow, with three elevations of mills in service,
the damper positions were as follows:
Biased Firing Operation Overfire Air Operation
OFA Dampers 100
100
Coal Auxiliary Coal Auxiliary
Combustion 100
100 " Air Only 100
50
163
-------
AVG. GROSS W/HR .
30 OAT PERIOD
87.7 MW/HR
2/7/74 2/8/74 2/9/74
•- I • • l I j
2/14/74 I 2/15/74 'AflJ 2/20/74
I " I I i »- *_^
— -i- .J •• i .. .»; . ii • -I- -: Irr
3/8/74 j 3/9/74 | 3/10/74
3/12/74
CORROSION PROBE EXPOSURE TINE - DAYS
Figure TOO: Gross MW loading vs. time - baseline corrosion probe
study
164
-------
AV6. GROSS mi
HR - 30 MY
_ PERIOD
M.OtH/HR
4-16-74 I 4-17-74 I 4-18-74
CORROSION PROBE EXPOSURE TIME - DAYS
Figure 101: Gross MW loading vs. time - biased firing corrosion probe
study
165
-------
AVG. GROSS NU/HR •
30 DAY PERIOD
77.0 NH/HR
9-11
^•tiTtliiTiTi';.-|tf trt*«|- "i .1 i' -|- •• • i
| 9-12 I 9-13 I 9-14 ] 9-15
CORROSION PROBE EXPOSURE TIME - DAYS
16 9-19 9-20
Figure 102: Gross MW loading vs. time - overfire air corrosion probe
study
166
-------
Biased Firing Operation Overfire Air Operation
(Cont.)CCont.)
Coal Auxiliary Coal Auxiliary
20 30
50 50
50 50
20 30
50 50
20 0
50 0
At unit loadings above 75.5 kg/s to the maximum steam flow with the maximum
elevations of mills 1n service, the following damper positions were maintained.*
Biased Firing Operation Overfire Air Operation
Coal
Auxiliary
100 Combustion
100
30
30
.
30
Air
50
50
50
50
50
Only
OFA Dampers
Coal
100
30
30
30
100
100
Auxiliary
100
50
50
50
50
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 03.
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:
Baseline Biased Firing Overfire Air
2.6381 mg/cm2 4.6429 mg/cm2 4.4419 mg/cm
These values are within the range of losses which would be expected for oxida-
tion of carbon steel for a 30 day period. To verify this premise control
* At no time during the biased firing study was the top elevation coal pulveri-
zer placed in service. Maximum unit loading was therefore limited to the max-
imum with the lower three mills in service.
167
-------
studies were conducted in C-E's Kreisinger Development Laboratory using probes
exposed during the biased firing study. These probes were cleaned and pre-
pared in an identical manner to those used for furnace exposure and placed in
a muffle furnace for 30 and 60 day exposures at 399°C with a fresh air ex-
change. The test results were as follows:
M
Q
R
B
Probe Ht. Loss mg/cm2 - 30 Days
(30 day) 4.7999
30 day) 4.7741
60 day) 5.1571/2 = 2.5785
'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 decreasing in the second
thirty days. Based on these results, it appears that the differences in
weight losses observed during the test program are within the ranges to be ex-
pected from oxidation alone.
Chemical analysis of deposits taken during the test program does not, in it-
self, show that molten phase attack has occurred. The composition of the de-
posits does show some differences, primarily in the iron content as noted on
Figure 103. The deposit collected during the biased firing and overfire air
tests show 50 and 35 percent iron, respectively, versus 30 percent in the base-
line test. Higher iron is normally indicative of lower melting temperatures.
However a certain quantity of CaO is necessary to flux the iron if it is to re-
sult 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.
Accordingly the fusibility temperatures are higher for the biased firing test
and slightly higher for the overfire air tests. This agrees with observations
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 fall-
ing 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 fusibil-
ity temperatures of deposits can be significantly different than the coal ash
as fired.
168
-------
Water-wall Waterwall
Waterwal 1
Slag
Sample
Baseline
Ash Fusibility
IT
ST
HT
FT
Ash Composition
S102
A12°3
Fe2°3
CaO
MgO
Na'20
K20
Ti02
P2°5
so3
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-F1red)
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
Firing
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 103: Ash Analysis
169
-------
SECTION IV - APPLICATION GUIDELINES
INTRODUCTION
This section presents the results of Task IX of the Phase II - "Program for Re-
duction of NOX from Tangential Coal Fired Boilers" performed under the sponsor-
ship of the Office of Research and Development of the Environmental Protection
Agency (Contract 68-02-1367). These results were subsequently updated under
Task VII d of Contract 68-02-1486, "Staged Combustion Technology for Tangen-
tially Fired Utility Boilers Burning Western U.S. Coal Types." The results
presented are based on field performance tests performed at Alabama Power Com-
pany, Barry #2; Utah Power & Light Company, Huntington Canyon #2; Wisconsin
Power & Light Company, Columbia #1 and current contractor experience.
The utilization of overfire air as an NOX control technique is discussed rela-
tive to the following areas of interest:
1. Necessary equipment modifications and costs (as of January, 1977) associ-
ated with applying this technology to existing steam generators.
2. Specific limitations to the general applications of the technology devel-
oped.
3. Emission control and cost effectiveness of applying the developed technol-
ogy to new steam generator designs.
170
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CONCLUSIONS
1. Prior to Incorporating overfire air as an NOX control system on existing
unit designs, an exploratory test program must be performed to determine
the acceptability of the unit for modification.
2. The costs of installing an overfire air system on an existing unit could
range between 2 to 4 times the cost as included on a new unit design.
Based on January, 1977 estimates, existing unit modification costs could
range from 0.24 to 1.8 $/kw, depending on unit size.
3. Approximately 40% of the existing coal fired units in the United States are
of tangential design and could conceivably be modified to incorporate over-
fire air systems.
4. Unit size, heat rate and expected life must be considered in deciding
whether modifications are justified.
5. Incorporation of an overfire air system will not significantly affect unit
performance.
6. A large percentage of the existing tangentially coal fired units in the
United States can meet current EPA standards for NOx emission levels. The
necessity of applying the overfire air technique for NOx control should
therefore.be established prior to committing a unit for modification.
171
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RECOMMENDATIONS
EXISTING STEAM GENERATING UNITS
The applicability of the technology developed in the course of this project
should be qualified by the following conditions:
1. Any unit under consideration should be subjected to an exploratory test
program to determine the necessity of modification with respect to appli-
cable NOX compliance limits. The minimum test requirements recommended
for such a study would consist of studying the effect of available process
variables such as excess air level. The minimum test data would consist
of NOX, CO for combustion efficiency and sufficient board or test data to
identify changes in unit operating characteristics.
2. A review should be made of the unit and turbine useful life expectancy,
unit size versus modification costs, and unit heat rate.
NEW STEAM GENERATING UNITS
All tangentially coal fired units since approximately 1970 have included Over-
fire Air (OFA) systems in the original unit design. The OFA system is there-
fore not considered by Combustion Engineering, Inc. as an additional NOX con-
trol device.
172
-------
DISCUSSION
The effectiveness of overfire air operation in reducing NOX emissions from ex-
isting utility steam generators was evaluated by selecting, modifying, testing
one unit and selecting and testing two additional units designed with OFA sys-
tems. The effects of OFA system operation on unit performance and emission con-
trol was studied in each of these units. The modified test unit, Alabama Power
Company's Barry #2, is a natural circulation, balanced draft design, firing coal
through four elevations of tilting tangential fuel nozzles. Unit capacity at
maximum continuous rating (MCR) is 113 kg/s main steam flow with a superheat
outlet temperature and pressure of 538QC and 12.9 MPa.
The units designed with overfire air systems and burning Western coal types are
described as follows:
Utah Power & Light Company, Huntington Canyon #2 is a controlled circulation,
balanced draft design firing a Western bituminous coal type through five ele-
vations of tilting tangential fuel nozzles. Unit capacity at maximum continu-
ous rating (MCR) is 382 kg/s main steam flow with a superheat outlet tempera-
ture and pressure of 541°C and 18.2 MPa.
Wisconsin Power & Light Company, Columbia #1 is a controlled circulation, bal-
anced draft design firing a Western subbituminous coal type through six eleva-
tions of tilting tangential fuel nozzles. Unit capacity at maximum continuous
rating (MCR) is 478 kg/s main steam flow with a superheat outlet temperature
and pressure of 541°C and 18.1 MPa.
Superheat and reheat temperatures for the three units are controlled by fuel
nozzle tilt and spray desuperheating.
In order to evaluate unit performance during these studies, necessary steam, wa-
ter, air and gas temperature and pressure measurements were performed as well as
NOX, CO, 02, THC, S02 and carbon loss determinations to assess emission perfor-
mance. The test program for the modified unit was conducted in three phases
consisting of baseline and biased firing portions conducted prior to modifica-
tion and baseline and overfire air portions conducted after unit modification.
The effect of the modification on unit performance was found to be insignifi-
cant and the test data summaries for each phase are shown in Appendices A, B
and C. Similar three phase programs were conducted on the two test units burn-
ing Western coal types evaluating baseline, biased firing and overfire air op-
eration. Short term comparative corrosion tests were conducted on each unit
over thirty day periods using corrosion coupons, which are made of the same ma-
terial as the waterwalls. During this evaluation, both normal and OFA operation
was evaluated. The unit load schedules for the baseline and biased firing and
overfire air evaluations are shown on Figures 39, 40, 62, 63, 100, 101 and 102.
The respective data summaries are shown on Sheets Al through A6; Bl through B6
and Cl through C5. Corrosion coupon locations are shown on Figures 37, 60 and
69.
173
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DESIGN AND DESCRIPTION OF OFA SYSTEMS
The overfire air system as incorporated in tangential coal fired furnaces con-
sists of air compartments and registers, ductwork, flow control dampers and
nozzle tilting mechanisms. A typical arrangement of this system is shown on
Figure 15. The overfire air compartments and registers are designed as verti-
cal extensions of the corner windboxes unless, as in the case of some existing
units, modification at that location is not possible due to structural consid-
erations.
In the latter case, as was the situation with the modified test unit, the sep-
arate compartments and registers were installed within three meters of the top
of the existing windbox. As shown on Figure 67, this arrangement requires ad-
ditional ductwork for supplying air to the OFA system.
Control dampers for regulating the OFA flow rate should be coordinated with the
windbox fuel and auxiliary air compartment dampers to correctly proportion air
flow as required for various operating modes.
An independent OFA register tilt mechanism should also be provided on retrofits
of existing units to permit coordinating these registers with the fuel and air
nozzle tilts.
The overfire air registers and ducts should be sized for 15% of the full load
secondary* air flow using the same register and duct velocities as the windbox.
Each overfire air port consists of two registers above each windbox, usually as
an extension of the windbox.
FIELD TEST PROGRAM
The field performance tests conducted at Barry No. 2 firing Eastern bituminous
coal and at Huntington Canyon No. 2 and Columbia No. 1 firing Western bitumi-
nous coals respectively showed that an overfire air system on a tangential coal
fired furnace can reduce NOx emissions with no detriment to unit operation or
maintenance. NOX emission reductions of 20 to 30% were obtained with 15 to 20
percent overfire air when operating at a total unit excess air of approximately
15 to 25 percent as measured at the economizer outlet. This condition provided
an average fuel firing zone stoichiometry of 95 to 105 percent of theoretical
air"The firing zone stoichiometries attainable at given overall excess air
levels did vary somewhat from unit to unit. Stoichiometries below the 95 per-
cent level did not result in large enough decreases in NOX levels to justify
their use. Biased firing (removing the top burner elevation from service),
while potentially as effective, necessitated a reduction in unit loading and is
therefore less desirable a method of NOx control. In essence, this method uses
the uppermost fuel and air compartment as a windbox extension.
When using overfire air as a means of decreasing the theoretical air to the fuel
firing zone the percent carbon in the fly ash and CO emission levels were less
* Secondary air does not include coal pulverizer transport air.
174
-------
affected than when operating with low excess air.* This is due to the ability
to maintain acceptable total excess air levels, as measured at the economizer
outlet, during overfire air operation while the theoretical air to the fuel fir-
Ing zone 1s reduced.
Furnace performance as indicated by waterwall slag accumulations, visual ob-
servations and absorption rates, was not significantly affected by overfire
air operation.
On existing units where, for structural reasons, an overfire air port might
not be installed as a windbox extension, test results indicate that the center-
line of the overfire air port be kept within three meters of the centerline of
the top fuel elevation. Distances greater than three meters did not result in
decreased NOX levels. Changes within the three meters limit did affect NOX
levels slightly with the NOX levels increasing as the distance decreased.
The overfire air nozzles should tilt in unison with the fuel nozzles where pos-
sible. Tilting the overfire air and fuel nozzles towards each other directs
the overfire air into the fuel admission zone thereby negating the original in-
tent, while tilting the nozzles away from each other may result in decreased
flame stability. If the overfire air nozzle tilt is fixed in a horizontal po-
sition NOX levels would probably then vary to a limited extent with fuel noz-
zle position. In other words, the NOX levels may increase or decrease as the
total Included angle between the fuel and OFA nozzles is decreased or increased
respectively.
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. The
results of this study are shown on Sheets A57 and A58, B45 and B46 and C9
through Cll. Potential long term corrosion effects were not evaluated as part
of this program.
EXPLORATORY FIELD TEST PROGRAM - EXISTING UNITS
To determine both the necessity and acceptability of applying the OFA technique
for NOX emissions control on existing tangentially fired units, an evaluation
should be performed prior to committing the unit to modification.
This evaluation should include the study of existing process variables, such
as excess air, as an NOX control method. If these techniques should prove un-
satisfactory, the program should then be expanded to evaluate the effect of
biased firing on NOX emissions. This technique consists of removing the top
fuel elevations from service and using the upper air and fuel compartments for
the Introduction of overfire air. This evaluation should be conducted at the
maximum possible unit loading with one pulverizer out of service and otherwise
normal operation.
During biased firing operation, changes in total excess air required to main-
tain acceptable CO levels, the amount of carryover from the furnace outlet, and
* A minimum of 20 to 25 percent excess air was generally established for the
test units.
175
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furnace slagging tendencies should be observed. Carryover could be visually
observed, while Increased slagging might be evaluated both visually and in
terms pf bottom ash handling system performance. Outlet steam temperatures
and air heater exit gas temperatures should also be observed for comparison
of normal operation.
The minimum Instrumentation necessary for a comprehensive evaluation is as
follows:
Unit Performance
Superheat (S.H.) Outlet Temp.
Reheat (R.H.) Outlet Temp.
R.H. & S.H. Spray Flows
Gas Temp. Lvg. Air Heater (A.H.)
Excess Air Lvg. A.H.
Furnace Carryover
Furnace Slagging
Unit Gas Side Pressure Drop
Emissions Performance
NOX, CO & 02
EFFECT ON UNIT PERFORMANCE
Calibrated Board Data*
Calibrated Board Data*
Calibrated Board Data*
Thermocouple Grid in A.H. Outlet Duct
Gas Sampling Grid In A.H. Outlet Duct
Visual Observation
Visual Observation & Ash System Perfor-
mance, Nozzle Tilt Changes & Desuper-
heating Sprays
Calibrated Board Readings*
Gas Sampling Grid in A.H. Inlet Duct
The application of OFA as an NOX control device spreads out the furnace fire,
which reduces flame intensity and temperature and the initial oxygen concentra-
tion. These effects combine to limit the formation of oxides of nitrogen com-
pounds with the reduced oxygen apparently affecting the formation of NO by the
fuel bound nitrogen.
In the case of coal firing, the NOX emissions originate from two sources, fuel
bound and atmospheric nitrogen, and thus (NO) Total - (N0)e , N + (NO)..
'2 in air.
Test results from all three units Indicated that as long as the total excess
oxygen (fuel compartment 02 + OFA 03), as measured at the economizer, remains
changed from the baseline condition, unit performance would remain unaffected.
In some cases, however, a slightly Increased total oxygen may be required to
prevent an Increase 1n CO and unburned carbon emission levels. This situation
* If not available, test Instrumentation should be considered.
176
-------
could be simulated with a biased firing test (top fuel elevation out of ser-
vice) conducted during the exploratory program to determine the necessity of
unit modification. While.this approach will necessitate a reduction in unit
loading, testing should be conducted at the highest possible loading obtain-
able for comparison to normal unit operation.
Otherwise, overall steam generator performance, including fan power, final
steam temperatures, furnace wall tube temperatures and corrosion, and unit ef-
ficiency remain essentially unchanged.
The effect on furnace slagging has been found to vary somewhat with coal types
and in particular with blends of various coals. Therefore, since coal types
vary widely, the effect of changing firing zone stoichiometries on slagging
tendencies should be evaluated during the exploratory program, again by using
the biased firing technique. Where evaluating units with spare coal pulveri-
zer capacity, this check should, if at all possible, be made at, or close, to
full unit rating, particularly from the standpoint of evaluating unit slagging
tendencies. A minimum evaluation period of one week is recommended for study-
ing slagging tendencies.
On some units, the spreading out of the furnace fire might result in some com-
bustible carryover from the unit furnace to the superheat sections. The ten-
dency toward this condition can also be evaluated during the exploratory pro-
gram by visual observation and watching for changes in unit performance.
ECONOMIC EVALUATION
The cost of incorporating overfire air systems on existing and new unit designs
was evaluated for steam generating units from 125 to 1000 MW capacity. The re-
sults of this study are shown on Figure 104.
The cost estimates for the revision of existing units are based on studies per-
formed on units within this size range including the actual costs for modifica-
tion of the Barry 2 unit. The cost estimates presented for including the over-
fire air system in new unit designs are based on current experience with these
systems.
The accuracy of the January, 1977 cost estimates is plus or minus ten percent.
Because the overfire air system is included as an integral part of new unit de-
sign, it is not therefore, considered as an optional or additional emissions
control device. The costs of existing units could be from 0.24 to 1.8 $/kw,
due to variations in existing unit design and construction which might make
modifications more complicated. These costs may also vary and escalate with
the prevailing economic climate.
The largest four-windbox (single cell) furnaces manufactured to date have been
in the 625 MW size range at which point eight-windbox furnaces (generally di-
vided into two cells) have been selected. Since an eight windbox tangentially
fired furnace has double the firing corners of a four-windbox furnace, the costs
of windboxes and ducts increase significantly.
The resulting increase in the cost of electricity generated is approximately
177
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1.80
1.50
* 1.20
H- 0.90
o
0.60
0.30
0.00
EXISTING UNITS MODIFICATION COSTS
4 WINDBOX FURNACES-7 8 WINDBOX FURNACES
200
400 600 800
UNIT SIZE, mw
1000
1.20
0.90
NEW UNITS INSTALLATION COSTS
0.60
o
o
4 WINDBOX FURNACES-7 8 WINDBOX FURNACES
0.30
0.00
200
400 600 800
UNIT SIZE, mw
1000
Figure 104: Overfire Air System Costs - Tangential coal fired steam
generators - January, 1977 equipment costs
178
-------
0.02| for a typical new 500 MW plant* costing 600 $/kw using coal costing 1.00
$/105BTU, as illustrated in Table 1. The overfire air system increases capi-
tal costs by 0.2 $/kw, and all other costs are unchanged. The mills/kwhr in-
crease is 0.006.
An existing 500 MW plant has overfire air system costs up to 0.8 $/kw. Genera-
tion costs for a 600 $/kw plant increase by up to 0.10% or 0.026 mills/kwhr. An
existing 500 MW plant which was installed for 300 $/kw and receives coal cost-
ing 0.50 $/106BTU has much lower operating costs than the previous example.
The cost increase percentage is 0.14%, but the increase in mills/kwhr remains
unchanged at 0.026, as shown in the last column of Table 1.
$/KW
Coal Handling, Storage, Pulverizing, Ash Handling 53
S0;2 Scrubber System 90
Boiler, Air Heaters, Fans, Stack 74
Steam Turbine-Generator, Piping, Heaters, Water Treatment,
Condenser, Cooling Towers 110
Structures, Sitework Foundations, Offices, Land, Workshops,
Controls, Switchgear, Transformers 76
Subtotal 403
Engineering, Construction 53
Contingency 44
Interest During Construction 100
Total 600
The increases in generating costs (mills/kwhr) for typical 100 MW plants are
approximately double the increases for 500 MW plants. The increases for 600
MW plants with divided furnaces are 2535 to 35% higher; and the increases for
1000 MW plants are the same as for 500 MW plants.
Transmission and distribution costs are not included in these comparisons.
These examples are only typical; a specific plant has to be evaluated on its
particular economic criteria.
* January, 1977 equipment costs for 500 MW Coal Fired Power Plant with Lime-
stone S02 Scrubbing System.
179
-------
TABLE 1. COST OF ELECTRICITY GENERATED - 500 MW PLANTS
Capital Costs. $/kw
Annual Cap. Cost* $
Annual Fuel Cost, $
Labor & Maint. (e), $
Total Annual Cost (f), $
Electricity Cost (g),
M1lls/kwhr
Increase, %
Increase* Mills/kwhr
Net Heat Rate 9500 Btu/Kwhr
January, 1977 Equipment Costs
New
Plant
Without
Overfire Air
600.00
54,000,000 (a)
26,000,000 (c)
10,800,000
90,800,000
33.630
—
•»•«
New
Plant
With
Overfire Air
600.20
54,018,000
26,000,000
10,800,000
90,818,000
33.636
0.018
0.006
Recent
Existing
With Added
Overfire Air
600.80
54,072,000
26,000,000
10,800,000
90,872,000
33.656
0.077
0.026
Older
Existing
Without
Overfire Air
300.00
27,000,000 (b)
13,000,000 (d)
10,800,000
50,800,000
18.815
—
__ _
Older
Existing
With Added
Overfire A1r
300.80
27,072,000
13,000,000
10,800,000
50,872,000
18.841
0.140
0.026
Based on:
Annual Fixed Charge Rate of 18% X 600 $/kw X 500,000 kw.
18% X 300,$/kw X 500,000 kw.
1.00 $/10j BTU coal cost X 5400 hr/yr X 500,000 kw X 9500 BTU/kwhr.
0.50 $/10° BTU coal cost X 5400 hr/yr X 500,000 kw X 9500 BTU/kwhr.
Labor and maintenance cost of 4.0 mills/kwhr.
5400 hr/yr at 500 MW = 2700 gwhr/yr.
Cost at plant bus bar; transmission and distribution not included.
-------
APPLICABILITY
EXISTING STEAM GENERATING UNITS
In a specific existing plant, the exploratory field test program will provide
the data to determine whether an overfire air system is needed to meet NOX lim-
its. If so, the biased firing tests will show operating effects such as com-
bustible loss, corrosion, or furnace slagging. Favorable results from the
field tests should be followed by an evaluation,.as shown in Table 1, to deter-
mine whether modification costs are economically justified.
Economic considerations include plant age and efficiency. Will the plant con-
tinue to operate long enough to pay off the investment? The annual capital
cost is inversely proportional to the number of years. Steam generator size
also has an effect on the relative economics of overfire air system modifica-
tions. For example, the minimum modification cost is about $120,000, which is
4.8 $/kw for a 25 MW unit. With complications, 12 $/kw is possible for a 25
MM unit.
Approximately 40% of the existing coal fired units in the United States are of
tangential design and could conceivably be modified to incorporate overfire air
systems, if the field test and economic evaluation results are favorable. Since
1949, approximately 320 tangential units have been put into service without
overfire air systems.
NEW STEAM GENERATING UNITS
At the current levels of NOX limits, an overfire air system should be included
as a standard design feature of a new unit. The technology is proven, and the
cost is minimal when included in the original design.
181
-------
REFERENCES
1. Blakeslee, C. E., and A. P- Selker. Program For Reduction of NOX from Tan-
gential Coal Fired Boilers - Phase I. EPA-650/2-73-005. U.S. Environmen-
tal Protection Agency, Research Triangle Park, North Carolina, 1973. 190
pp.
2. Selker, A. P. Program For Reduction of NOX From Tangential Coal Fired
Boilers - Phase II. EPA-650/2-73-005-a. U.S. Environmental Protection
Agency, Research Triangle Park, North Carolina, 1977. 133 pp.
3. Winship, R. D., and P. W. Brodeur. Controlling NOX Emissions in Pulverized
Coal Fired Units. Engineering Digest, September, 1973. pp. 31-34.
4. Haynes, B. S., and N. Y. Kirov. Nitric Oxide Formation During the Combus-
tion of Coal, Combustion and Flame, Volume 23, 1974. pp. 277-278.
5. Vatsky, J., and R. P. Weiden. NOX A Progress Report, Heat Engineering,
vaiaKjr, u., auu n. r. neiuen. nux
July/September, 1976. pp. 125-129.
6. Graham, J. Combustion Optimization Electrical World, June 15, 1976. pp.
43-58.
7. Thimot, G. W., and E. L. Kochey, Sr. Coal Firing is Different. Presented
at Instrument Society of America Power Division Symposium, Houston, Texas,
May 19-21, 1975.
8. Bogot, A., and R. P. Hensel. Considerations in Blending Coals to Meet S02
Emission Requirements. Presented at National Coal Association/Bituminous
Coal Research, Louisville, Kentucky, October 19-21, 1976.
182
-------
APPENDIX A
TEST DATA & RESULTS
FOR
WISCONSIN POWER & LIGHT COMPANY
COLUMBIA ENERGY CENTER
UNIT #1
-------
WISCONSIN POWER & I IGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
EMISSJONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
FURNACE CONDITION
EXCESS AIR CONDITION
DATE
UNIT LOAD
NOZZLE COMPARTMENT ? S ? ? ^ f
DAMPER POSITION - % OPEN p » p o o -
•r -i -i
STEA
EMPE
EMPE
ELEV
OZZL
Nozz
1-F
1-t
1-D
1-C
1-B
1-A
* FLOW
RATURE
RATURC
ATIONS
E TILT
LE TILT
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
IN SERVICE
1976
MM
KO/S
"c
°C
DEC
DEC
% OPEN
% OPEN
i OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
£ OPEN
% OPEN
% OPEN
H OPEN
$ OPEN
< OPEN
H OPEN
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NOX (ADJ. TO 0< Og)
NOX AS N02
302 (Aoj. TO Ot 05}
SOg
CO (ADJ. TO OjS OB)
CO
HC (ADJ. TO o# 02 ^
OS AT ECONOMIZER OUTLET
Og AT A.M. INLET
02 AT A.M. OUTLET
COg AT ECONOMIZER OUTLET
COg AT A.H. INLET
COg AT A.H. OUTLCT
CARBON Loss IN FUY ASM
PPM
NC/J
PPM
NG/J
PPM
NG/J
PPM
±
^
MAX
CLEAN
MlN
3/10
524
441
536
541
ABDEF
0
-4
0
0
100
50
TX>
50
100
50
100
0
100
50
100
50
100
20.7
117.8
650
322.9
1156
799.7
16
4.B
0
3.6
4.3
4.5
15.6
15. n
14.8
0.02
2
MAX
CLEAN
NORM
3/8
524
442
540
542
ABDEF
0
+1
0
0
100
50
100
50
100
50
100
0
100
50
100
50
100
21.8
MB. 9
520
260.2
1138
792.6
16
4.8
0
3.8
4.4
5.1
1^.6
11!. 1
M . 3
^.Ol
3
MAX
CLEAN
MAX
3/15
485
400
543
541
ABDEF
0
-2
0
0
100
50
100
50
100
50
100
0
100
50
100
50
100
34.7
131.4
599
303.7
1003
708.4
18
5.4
0
5.5
5.7
6.8
14.1
n.9
12.9
o.op
456
3/4 MAX 1/2 MAX 1/2 MAX
CLEAN
NORM
3/13
399
334
542
539
ABDEF
0
+17
0
0
55
40
50
45
50
40
50
0
50
40
50
40
50
35.6
n?.5
498
246.3
1119
770.4
NA
NA
0
5.6
5.7
7.6
14.0
13.9
12.2
o . 04
CLEAN
MlN
5/23
324
267
546
522
CDEF
0
+10
0
0
0
85
0
90
0
85
5
90
0
0
0
0
0
27.7
126.7
593
291.2
1362
931.8
5
1.5
0
4.6
4.9
7.2
14.9
14.6
19.5
i.<->.i
CLEAN
NORM
5/S3
323
269
543
521
CDEF
0
-HO
0
0
5
75
5
85
5
80
10
70
10
0
0
0
0
37.5
136.2
653
335.2
1379
985.0
6
1.7
0
5.8
6.0
7.6
13.5
13.3
11.9
1. OP
7
1/2 MAX
CLEAN
MAX
5/23
322
268
548
522
CDEF
0
+9
0
0
10
BO
15
80
10
85
20
85
15
0
0
0
0
43.5
141.4
662
333.8
1230
864.0
7
2.2
0
6.4
6.5
8.1
13.1
13.0
11.6
o./v»
8
MAX
9
MAX
22
— >
MAX
MODERATELY DIRTY
MlN
3/10
514
427
540
541
ABDEF
0
-4
0
0
55
40
60
40
55
35
50
0
50
35
50
35
55
19.4
116.5
596
295.7
1184
817.9
17
5.1
0
3.5
4.0
4.2
15.9
15.4
15.2
o. rt?>
NORM
3/9
515
432
540
541
ABDEF
0
+3
0
0
100
50
100
50
100
50
100
0
100
50
100
50
100
23.7
120.7
578
290.2
1230
859.4
16
4.9
0
4.1
4.5
5.6
15.2
14.8
I.1?. 8
o.oe
MAX
3/10
482
394
540
544
ABDEF
0
-4
0
0
100
50
100
50
100
50
100
0
100
50
100
50
100
30.6
127.5
626
310.6
1171
809.1
17
5.1
0
5.0
5.2
5.6
14.5
14. S
13.9
a. it
-------
Wi SCONS i
COLUMBIA
r1tXO TtaT\Mtt UN 11
PERFORMANCE Rtiu
BASELINE OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
FURNACE CONDITION
EXCESS AIR CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
•-&
11
12
13
14
15
16
17
18
19
I-F
l-t
1-0
I-C
1-B
I-A
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NOX (ADJ. TO at 05}
NOX AS NOg
S02 (ADJ. TO Og Og^
soe
co (ADJ. TO nf, ogl
CO
HC (ADJ. TO at 02)
Og AT ECONOMIZER OUTLET
0_ AT A.M. INLET
of AT A.M. OUTLET
COg AT ECONOMIZER OUTLET
C0p AT A.M. INLET
COg AT A.M. OUTLET
CARBON Loss IN FLY ASH
1976
Mrf
KO/S
°C
°c
DEC
DEO
13. 5
0.19
329
542
540
ABDEF
0
+18
0
55
40
50
45
50
40
50
50
40
50
40
50
35.7
132.5
478
252.9
975
718.5
NA
NA
5.6
6.0
7.4
14.0
13.6
12.3
O.04
1/2 MAX
DIRTY
MIN
5/25
322
264
545
529
ABCD
+7
0
o
0
0
0
0
0
80
0
85
0
75
0
BO
100
26.1
122.8
586
294.6
1250
875.4
4
1 .2
o
4 A
1 *1
4.8
6e
• o
15.1
14. "»
n.o
0.02
1/2 MAX
DIRTY
NORM
5/25
325
267
545
534
ABCD
+6
0
0
0
0
0
0
10
80
15
80
15
80
15
80
100
39.5
134.3
690
347.7
1460
1024.4
4
1 T
0
6.0
6.3
7.7
13.6
13.3
12.0
O.02
1/2 MAX
DIRTY
MAX
5/25
322
263
546
536
ABCD
o
+7
0
0
0
0
0
0
55
70
45
90
50
70
40
85
100
54.8
144.6
733
369.2
1140
8OO. 1
5
1 .4
0
7.5
7.7
9.6
12.2
12.0
10.3
0.02
-------
WISCONSIN POWER 4 LIGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
EXCESS AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
1-F
!§
o —
CO
3£
1-E
M3
TIC"
I^B
TTA"
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
1976
MW
KS/S
°C
"c
DEC
DEC
t OPEN
% OPEN
f OPEN
1, OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
< OPEN
% OPEN
% OPEN
% OPEN
Excess AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NOX (ADJ. TO Ojf
NOX AS NO
SO (ADJ. TO
5
n
-\
B
02)
CO (ADJ. TO Of 02)
CO
HC (ADJ. TO at o2)
Og AT ECONOMIZER OUTLET
02 AT A.M. INLET
0- AT A.H. OUTLET
COg AT ECONOMIZER OUTLET
C02 AT A.H. INLET
COg AT A.H. OUTLET
CARBON Loss in FLY ASH
PPM
NG/J
PPM
NG/J
PPM
NG/J
PPM
1
MAXIMUM
MINIMUM
>
^ 5/19
505
426
546
550
ABCDE
0
+4
n
0
0
100
45
100
45
100
45
100
45
100
45
100
50
20.4
10B.2
408
2O3.9
115?
802.4
NA
NA
0
3.6
4.0
6.3
15.8
15.4
13.3
o. 02
2
MAXIMUM
MINIMUM
5/19
506
428
546
547
ABCDF
0
-4
O
0
30
100
35
100
30
100
30
100
25
100
35
100
45
18. 4
116.6
413
209.1
1101
776.6
NA
NA
0
3.3
4.0
6.2
16.1
15.4
13.4
'XO?
3 .4 5 6 7
MAXIMUM MAXIMUM 3/4 MAX 3/4 MAX 3/4 MAX
MINIMUM
V14
525
433
543
542
ABDEF
0
-4
0
0
90
50
90
50
90
50
90
95
90
40
80
50
95
15.2
112.6
492
249.2
117O
826.1
NA
NA
0
2.8
3.3
4.7
16.5
16. n
14.7
n.35
MINIMUM
_ MonpRATELY
5/19
506
411
545
548
BCDEF
0
-8
0
0
35
100
35
100
30
100
30
100
30
100
30
100
0
19. n
116.9
504
250.3
NA
NA
NA
NA
0
3.4
4.0
6.1
16.0
15.4
13.5
o.nj?
MINIMUM
5/12
422
^52
545
544
ABCE
0
-2
0
0
0
100
20
100
20
0
15
100
15
100
10
100
100
26.1
110.0
417
215.9
1088
783.6
25
8.0
0
4.4
4.7
6.8
14.9
14.6
12.7
•XO3
MINIMUM
5/12
422
352
543
545
ABCE
0
0
0
0
0
0
20
100
10
100
15
100
15
100
15
100
100
21.7
117.5
507
260.2
1088
778.1
13
4.2
0
•<.8
4.2
5.9
15.3
14.9
13.4
n.o?
MINIMUM
5/16
421
344
546
547
BCDE
0
+13
0
0
0
0
25
100
20
100
15
100
15
90
10
100
100
30.7
125.6
442
227.3
1088
778.6
143
44.8
0
5.0
5.2
6.6
14.3
14.1
12.8
O.O2
_8
1/2 MAX
MINI MUM
5/21
320
263
545
545
A8CD
0
+10
0
0
0
100
0
100
0
85
0
90
0
90
0
90
100
19.7
94.4
326
162.2
1252
865.9
5
1.4
0
3.5
3.7
6.0
15.9
15.7
13.6
O.O7
9
^
1/2 MA"X
MINIMUM
CLEAN
6/27
314
258
544
504
ABEF
0
0
0
0
0
90
0
90
0
100
0
100
0
80
0
BO
80
34.2
133.5
513
245.1
995
662.2
4
1.2
0
5.4
5.6
7.6
14.3
14.1
12.2
O. OS
-------
COL UMBiA 17
F vcuo TKBT«NO juto
BIASED FIRING OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
Excess AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
NOZZLE COMPARTMENT ? R ? 1 52 ?
DAMPER POSITION - OPEN n » p o o -
Z -1 -H
JTEAM FLOW
MPERATURE
MPERATURE
ELEVATIONS
JZZLE TILT
JOZZLE TILT
OFA
I-F
I-E
I-D
I-C
I-B
1-A
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
IN SERVICE
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NOX (ADJ. TO Og 02 ^
NOX AS NOg
sos (ADJ. TO og 051
SOp
CO (ADJ. TO Og 021
CO
HC (ADJ. TO Og Ogl
Og AT ECONOMIZER OUTLET
Op AT A.H. INLET
0| AT A.H. OUTLET
COp AT ECONOMIZER OUTLET
AT A.H. INLET
CO!
CO* AT A.H.
CARBON Loss
OUTLET
IN FLY ASM
1976
MM
KG/S
°c
°c
DEC
DEC
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g OPEN
g
: g
PPM
NG/J
PPM
NG/J
PPM
NG/J
PPM
g
g
g
g
g
g
%
JO
1?2 MAX
MINIMUM
/•»
L-L.EAN
5/23
324
268
547
529
CDEF
0
+5
0
O
0
55
0
65
0
55
0
60
0
90
0
100
0
29.2
128.4
525
266.8
1313
929.3
5
1.6
0
4.8
5.2
6.9
14.5
14.2
12.6
0.04
11
J2
_13
J4
J5
!§
r?
15
i/AoiiTinti nc i-iic-i i-i n» Tinkle i n tM-nm/T ^.
MAXIMUM
NORMAL
^
" 5/19
491
417
546
550
ABCDF
0
+5
0
0
0
100
50
100
45
100
40
100
45
100
50
100
50
23.1
122.7
454
231.2
1174
831.0
NA
NA
0
4.0
4.1
6.7
15. 3
15.2
12.8
o.oa
MAXIMUM MAXIMUM 3/4 MAX 3/4 MAX 3/4 MAX
NORMAL
5/10
497
417
547
546
ABCEF
0
-2
0
0
15
100
35
100
30
100
35
100
30
95
30
100
100
24.6
123.4
590
297.2
870
610.3
18
5.4
0
4.2
4.8
6.2
15.2
14.7
13.4
O.O3
NORMAL
htlnt-i
NORMAL
f. _.,..
3/16 5/12
523
438
542
542
ABDEF
0
-4
0
0
95
50
95
50
90
50
95
50
95
100
85
50
95
18.4
115.8
556
260.4
1029
721.9
NA
NA
0
3.3
4.3
5.6
16.1
15.2
13.9
0.03
423
353
545
544
ABCE
0
0
0
0
0
100
30
100
35
0
30
100
25
100
20
100
100
34.1
117.9
443
222.5
1139
796.9
74
22.6
0
5.4
5.7
7.1
14.1
13.8
12.5
0.02
NORMAL
3/13
400
325
543
540
ABDEF
0
0
0
0
55
40
50
45
50
35
50
100
50
40
50
40
50
35.8
132.9
462
231.7
859
599.6
NA
NA
0
5.6
5.7
7.4
13.8
13.8
12.1
0.02
NORMAL
5/16
422
350
546
547
BCDE
0
+10
0
0
0
0
35
100
35
100
40
100
35
100
50
100
100
41.3
135.8
494
246.4
1166
810.7
NA
NA
n
6.2
6.4
8.4
13.4
13.2
11.4
0.02
1/2 MAX
NORMAL
%
5/21
320
261
545
543
ABCD
0
+12
0
0
0
100
0
100
0
90
0
90
0
90
0
70
100
35.9
105.8
462
228.7
1256
865.4
4
1.2
0
5.6
5.8
7.6
13.9
13.7
12.1
0.02
1/2 MAX
NORMAL
CLEAN
5/23
323
264
545
530
CDEF
0
+9
0
0
0
85
0
90
0
80
0
90
0
100
0
100
0
36.6
135.8
629
316.9
1278
897.1
7
2.1
0
5.7
5.9
7.8
13.6
13.4
11.7
0.04
-------
WISCONSIN POVCR '. LIGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TCSTIIIG AMD
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
Excess AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NOX (ADJ. TO 0* Og)
NOX AS NOg
SO,, (ADJ. TO Of 02)
SOg
CO (ADJ. TO <*t Op)
CO
HC (AOJ. TO o< o 1
Os AT ECONOMIZER OUTLET
0. AT A.M. INLET
o| AT A.M. OUTLET
COg AT ECONOMIZER OUTLET
CO AT A.H. INLET
Col AT A.H. OUTLET
CARBON Loss IN TLV ASH
1
2
3
4
5
6
7
B
9
10
1976
MW
KO/S
°C
•C
DEC
DEO
% OPEN
< OPEN
< OPEN
% OPEN
# OPEN
* OPEN
^ OPEN
f OPEN
£ OPEN
< OPEN
£ OPEN
< OPEN
% OPEN
* OPEN
t OPEN
*
'E if
PPM
NC/J
PPM
NQ/J
PPM
NG/J
PPM
«
*
<
g
1!
*
MAXIMUM
NORMAL
jf
3/17
517
425
542
542
ACDEF
0
-4
0
0
100
V
100
50
100
50
100
50
10O
0
100
50
100
23.9
120.9
718
V56. 1
1190
821.9
16
4.9
0
4.1
4.3
5.3
15.3
15.1
14.2
MAXIMUM MAXIMUM
NORMAL
3/17
512
426
541
541
ACDEF
0
-4
25
25
95
SO
100
50
95
50
100
50
95
0
95
50
95
23.2
115.7
710
354.9
1207
B39.8
16
4.9
0
4.0
5.0
5.4
15.4
14. S
14.2
0.09
NORMAL
3/20
524
439
533
534
ACDEF
0
-8
50
50
85
so
85
50
85
50
80
50
85
0
80
50
85
21.8
109.7
442
222.8
1266
88B.B
NA
NA
0
3.8
4.0
5.3
15.5
15.3
14. 1
1.02
MAXIMUM
NORMAL
^.
3/20
525
445
534
533
ACDEF
0
41
70
70
75
go
75
50
75
50
70
50
70
0
70
50
70
19.7
105.2
409
203.4
1404
171.9
NA
NA
0
3.5
3.9
5.1
15.8
15.4
14.4
n.ni
MAXIMUM MAXIMUM MAXIMUM
NORMAL
3/22
526
444
534
538
ACDEF
0
+1
95
95
65
•50
65
50
70
50
60
50
70
0
65
50
70
20.4
104.6
434
215.4
1320
911.8
NA
NA
0
3.6
4.1
5.0
15.7
15.2
14.4
1.12
MINIMUM MINIMUM
3/20 3/20
521
446
543
547
ACDEF
0
+6
0
0
65
50
65
50
65
50
60
50
65
0
60
50
75
13.3
110.7
364
182.7
1203
840.2
NA
NA
0
2,5
3.3
4.5
16.7
16.0
14.9
o.O?
522
441
532
534
ACDEF
0
+8
50
50
55
50
50
50
55
50
50
50
55
0
50
50
70
13.9
101.8
356
177.9
1245
666.5
NA
NA
0
2.6
3.4
5.0
16.6
15.9
14.4
O.O4
MAXIMUM
MINIMUM
3/20
522
439
532
532
ACOEF
0
41
100
100
50
go
50
50
50
50
50
50
50
0
50
50
50
15.1
99.0
344
171.4
1240
861.0
NA
NA
0
2.8
3.5
4.5
16.4
15.8
14.9
o. 03
MAXIMUM
MAXIMUM
3/24
476
398
538
540
ABCEF
0
+2
25
25
100
50
90
50
90
0
95
50
95
50
90
50
100
36.8
128.2
594
299.2
1267
868.3
NA
NA
0
5.7
5.8
7.0
13.9
13.8
IS. 7
(1.0T
MAXIMUM
MAXIMUM
3/24
473
390
539
540
ABCEF
0
41
80
80
80
50
75
50
80
0
80
50
75
50
80
50
90
35.8
118.8
551
274.7
1342
931.8
NA
NA
0
5.6
5.8
7.0
13.8
13.7
12.6
a. os
11
12 .
~~ TILT TORT
MAX IMUM
MAX IMUM
3/24
472
389
534
539
ABCEF
0
+3
100
100
55
50
50
50
50
0
50
45
50
50
50
50
85
30.0
111.5
485
246.5
1329
940.3
NA
NA
0
4.9
5.0
6.1
13.5
14.5
13.5
O.OI
wi in ur H
MAXIMUM
MINI MUM
6/24
524
446
540
547
ABOEF
-5
-5
100
100
25
100
20
100
20
100
20
0
15
100
20
100
100
23-9
102.8
395
195.5
1023
704.7
16
4.9
0
4.1
4.4
5.6
13.9
15.0
13.9
o.os
-------
WISCONSIN POWER £ LIGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTINO »HD
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
EXCESS AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
13
14
15
16
17
18
19
20
21
22
23
24
z
LJ
$*
r
1s
h
uo
Kj°-
se
zl
o
—
1-F1
I-L
t-b
rr
l-B
EE
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
(ADJ. TO Of 02)
NO
NOX AS NOg
soe (ADJ. TO
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA f1
BASELINE OPERATION STUDY
C-E POWER- SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO.
DATE
UNIT LOAD
PRESSURES (GAUGE!
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE: IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
RH SPRAY WATER
HP HTR's G14G2 STH
TEMPERATURES
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PENO Div INLET LINK
SH PEND Div INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH PEND SPCO FRONT IN LINK
SH PENO SPCD FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESH INLET COMB. LINE
RH RADIANT WALL FRONT IN HOR
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PCND SPCD FRONT IN LINKS
RH PEND SPCO FRONT IN LINKS
RH PEMO SPCO FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAT WATER
RH SPRAY WATER
COLO RH EXT STM TO G1iG2 HTR
FW IN TO HP HTR G1
FV, IN TO HP HTR G2
FW OUT or HP HTR Gl
FW OUT or HP HTR G2
STM DRAIN FROM HP HTR Gl
STH DRAIN TROM HP HTR G2
AIR t GAS
PRi AIR AH AIR
PR I AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
PRi AIR AH AIR
PRi AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
ECONOMIZER GAS
ECONOMIZER GAS
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
INLET
INLET
INLET
INLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
TEST DATA
1976
Mrf
KG/S
MPA
•c
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
J^
3/10
584
411.51
18.664
18.271
16.892
11.2.12
3.654
3.447
18.457
10.052
3.606
247
344
343
NA
350
384
390
414
404
496
482
539
533
319
275
267
309
308
312
303
531
552
173
163
328
207
206
247
247
212
208
9
5
16
15
369
374
361
362
418
431
398
409
122
119
2
3/08
524
430.91
18.781
18.326
16.878
11.321
3.634
3.413
19.809
10.122
3. SOS
247
337
333
NA
345
378
386
421
421
498
490
538
•543
321
292
283
323
320
317
308
531
553
173
182
328
206
205
247
246
211
208
4
3
22
23
354
361
346
349
402
413
383
392
111
119
3
3/15
485
380.51
18.409
18.078
16.872
10.163
3.330
•>.151
19.009
9.908
3.323
243
344
342
NA
348
388
392
417
415
497
490
542
544
316
268
272
306
307
312
301
536
547
171
179
323
203
202
242
242
SOB
205
4
4
20
21
364
369
354
353
409
422
395
401
118
118
4
3/13
399
324.19
17.878
17.582
16.706
8.246
2.641
2.489
18.850
9.542
2.627
230
333
328
NA
332
: 383
383
418
417
507
499
543
542
298
298
297
331
329
NA
319
545
532
159
151
305
192
191
228
229
195
193
2
n
14
33
329
328
323
T20
371
379
355
357
110
106
5
5/23
324
262.45
17.492
17.278
16.699
6.433
2.068
1.896
18.84?
9.329
2.068
219
317
312
317
318
381
382
435
431
518
507
547
546
283
283
282
318
317
318
307
523
522
156
96
288
184
184
219
218
187
187
27
23
37
36
T11
303
303
298
339
141
322
324
117
101
6
5/23
323
264.72
17.499
17.251
16.685
6.440
2.068
1.896
18.871
9.336
2.068
219
321
317
320
326
382
383
434
428
513
501
545
541
280
280
280
312
312
313
304
517
526
154
91
287
184
184
218
219
187
186
27
23
38
?7
302
305
302
301
346
349
••27
331
118
101
7
5/23
322
262.45
17.492
17.264
16.706
6.440
2.068
1.889
18.809
9.329
2.062
219
323
317
321
327
382
383
437
432
521
509
550
547
283
283
285
314
316
316
310
516
529
155
87
291
184
184
218
218
187
186
26
23
36
16
306
309
302
302
346
351
328
333
118
101
8
3/10
514
397.02
18.574
18.202
16.865
10.901
3.571
3.372
18.395
9.991
3.558
247
344
343
NA
352
387
393
414
408
496
482
543
538
321
261
263
304
303
308
300
531
552
173
193
329
206
206
247
246
212
208
10
7
16
14
371
378
353
366
416
432
398
411
123
121
9
3/09
515
405.84
18.630
18.230
16.885
10.956
3.57B
3.385
19.684
10.011
3.572
246
344
341
NA
350
384
391
413
412
497
484
542
538
322
269
267
108
304
309
299
531
551
172
182
327
205
204
246
246
211
?08
7
•S
17
18
166
371
357
159
411
4£7
396
403
117
119
JO
3/10
482
371.19
18.333
18.003
16.80?
10.080
3.302
3.11T
18.31?
9.85?
3.303
243
147
343
NA
351
389
395
413
413
496
484
543
538
3U
279
268
313
312
309
301
541
547
168
179
322
203
202
242
242
207
204
9
7
17
16
369
374
35?
363
413
427
396
406
122
119
190
SHEET A7
-------
WISCONSIN POWER & LIOHT Co.
COLUMBIA |1
BASELINE OPERATION STUDY
C-E POWER SYSTEMS
FIELD TESTING, AND
PERFORMANCE RESULTS
TEST NO.
DATE
UNIT LOAD
PRESSURES (GAUGE)
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLCT
RH OUTLET
SH SPRAY WATER
RH SPRAY WATER
HP HTR's G1&G2 STM IN
TEMPERATURES
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET.
SH PEND Div INLET LINK
SH PCNO Div INLET LINK
SH DESH OUTLET LINK
SH DESK OUTLET LINK
SH PEND SPCD FRONT IN LINK
SH PEND SPCD FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESK INLET COMB. LINE
RH RADIANT WALL FRONT IN HCR
RH RADIANT WALL FRONT IN HCR
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAY WATER
RH SPRAY WATER
COLD RH EXT STM TO GUG2 HTR
FW IN TO HP HTR G1
FW IN TO HP HTR G2
FW OUT OF HP HTR G1
FW OUT OF HP HTR G2
STM DRAIN FROM HP HTR G1
STM DRAIN FROM HP HTR G2
AIR IL GAS
PR i AIR AH AIR
PRi AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
PR i AIR AH AIR
PR i AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
ECONOMIZER GAS
ECONOMIZER GAS
AH GAS INLCT
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
INLET
INLET
INLET
INLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
TEST DATA
1976
KM
KG/S
WA
«C
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
J2
5/21
321
238.75
17.347
17.154
16.685
6.295
2.075
1.903
18.354
9.198
2.082
220
331
328
332
332
391
392
413
410
509
494
551
541
283
257
244
306
301
299
285
546
536
156
162
291
186
185
219
219
188
187
22
21
33
33
315
320
313
315
351
357
337
340
120
121
\Z
5/25
321
248.84
17.423
17.196
16.678
6.336
2.068
1.B89
18.312
9.341
2.075
219
338
331
334
344
392
396
427
423
508
499
545
547
282
274
266
309
304
301
293
527
545
155
162
289
184
184
218
218
186
186
28
24
35
34
323
330
317
321
363
370
347
355
119
114
13
3/12
524
402.94
18.623
18.230
16.878
11.114
3.661
3.461
19.595
10.011
3.654
248
348
346
NA
349
391
393
415
413
496
489
544
542
327
256
268
301
304
316
308
544
542
176
184
333
207
206
248
248
213
209
11
9
14
13
377
383
369
372
422
417
406
413
126
119
12
3/09
513
408.74
18.643
18.244
16.899
10.928
3.564
3.365
19.354
10.025
3.551
246
344
344
NA
349
386
393
419
417
494
482
539
539
321
269
266
308
304
307
300
533
548
173
182
327
205
204
245
246
209
207
8
6
14
13
376
382
367
371
425
437
405
416
120
123
.15
3/10
484
371.19
18.312
17.968
16.816
10.087
3.309
a. 137
19.264
9.846
3.310
243
346
342
NA
352
389
393
411
408
499
487
542
537
315
273
261
311
308
304
295
541
547
169
179
322
202
202
242
242
207
204
6
4
17
17
366
373
357
361
412
427
393
405
120
119
1§
3/13
401
322.43
17.906
17,623
16.741
8.267
2.654
2.51?
19.030
9.561
2.641
231
331
327
NA
330
361
382
421
418
507
501
543
542
297
296
297
330
328
327
319
545
536
158
129
306
192
191
329
229
196
193
6
2
29
30
332
331
326
323
372
425
357
359
109
107
V7
5/25
322
246.45
17.430
17.223
16.727
6.274
2.075
1.901
18.278
9.218
2.075
220
327
322
326
330
387
389
4S7
423
512
496
548
542
283
265
249
305
302
295
283
528
531
156
163
290
185
184
218
219
188
187
29
27
34
34
313
322
311
316
350
357
336
343
118
116
!§
5/25
325
245.45
17.423
17.237
16.720
6.343
2.096
1.931
18.085
9.239
2.103
221
337
337
336
341
392
395
425
421
508
494
548
543
283
266
249
304
298
292
281
530
538
156
163
290
186
185
219
220
188
187
29
27
34
33
321
327
317
319
361
368
344
352
119
114
12
5/25
322
244.05
17.409
17.196
16.692
6.157
2.032
1.910
18.182
9.308
2.089
219
343
343
339
348
393
398
427
423
507
496
547
546
283
270
256
306
302
296
287
528
543
156
163
289
186
184
218
219
188
187
29
26
36
35
324
331
318
323
368
376
349
358
121
111
191
SHEET A8
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA 11
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST DATA
TEST NO.
DATE
UNIT LOAD
nows
FEEDWATER
PRESSURES (GAUGE)
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINC 1ST STAGE
RH INLET
RH OUTLET
SH SPRAT WATER
RH SPRAY WATCR
HP HTR's G1&G3 STM IN
TEMPERATURES
WATER tuo STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PENO Div INLET LINK
SH PENO Div INLET LINK
SH DESK OUTLET LINK
SH DESK OUTLET LINK
SH PEND SPCD FRONT IN LINK
SH PEND SPCD FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESK INLET COMB. LINE
RH RADIANT WALL FRONT IN HOP
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAV WATER
RH SPRAY WATER
COLD RH EKT STM TO G1&G2 HTR
FW INTO HP HTR G1
FW INTO HP HTR G2
FW OUT or HP HTR Gl
FW OUT or HP HTO G2
STM DRAIN FROM HP HTR G1
STM DRAIN FROM HP HTR G2
AIR t GAS
PRI AIR AH AIR INLET
PR I A i R AH A i R 1 NL CT
SEC AIR AH AIR INLET
SEC AIR AH AIR INLET
PRI AIR AH AIR OUTLET
PRI AIR AH AIR OUTLET
SEC AIR AH AIR OUTLET
SEC AIR AH AIR OUTLET
ECONOMIZER GAS OUTLET
ECONOMIZER GAS OUTLET
AH GAS INLET
AH GAS INLCT
AH GAS OUTLET
AH GAS OUTLET
1976
MW
KO/S
WA
•c
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
L
R
J_
5/19
505
405.84
18.636
18.S37
16.968
10.948
3.516
3.254
19.891
10.115
3.48S
247
345
340
347
353
384
392
423
420
504
499
543
549
326
292
284
327
324
323
315
534
566
178
184
329
208
207
247
248
213
210
32
32
34
34
369
383
361
371
418
433
396
412
143
147
2
5/19
506
411.51
18.643
18.223
16.913
10.908
3.537
3.268
20.016
10.108
3.509
247
349
339
347
346
386
388
424
422
504
492
549
543
327
277
277
310
312
318
310
543
552
178
185
331
208
207
247
247
213
210
31
31
33
33
369
373
363
363
418
422
397
403
145
142
3
3/14
525
404.33
18.636
18.244
16.865
11.101
3.661
3.454
19.650
10.018
3.647
248
348
347
NA
351
390
397
418
414
492
489
542
544
326
257
268
298
302
316
310
542
542
174
183
333
207
206
248
248
213
210
11
10
15
14
382
?91
375
379
436
446
411
421
137
134
4
5/19
506
404.33
18.588
18.175
16.920
10.894
3.509
3.261
19.774
10.073
3.482
248
351
340
347
349
386
389
418
416
496
502
539
552
326
292
287
318
319
322
316
544
553
179
185
330
BOB
207
247
247
213
211
27
26
30
29
368
368
T61
359
417
421
395
398
142
138
5
5/12
422
348.51
18.043
17.713
16.761
8.791
2.806
2.579
19.429
9.722
2.779
235
332
329
335
336
382
386
432
426
507
499
546
545
305
305
304
334
332
332
325
540
548
171
118
308
197
197
P34
234
202
199
24
23
33
33
340
346
333
336
389
391
367
372
122
123
6
5/12
422
345.11
18.023
17.713
16.789
8.756
2.792
2.692
19.292 .
9.715
2.786
234
331
324
329
333
381
383
427
423
510
501
544
543
302
303
304
335
333
332
326
542
548
169
120
308
197
197
234
235
201
199
21
20
33
34
334
340
329
331
381
383
360
364
120
121
7_
5/16
421
341.71
18.037
17.71?
16.782
8.818
2.799
2.586
19.250
9.742
2.792
234
331
324
333
340
382
389
432
427
506
508
539
553
304
305
305
340
333
333
329
528
566
167
99
309
198
197
234
235
202
199
24
22
31
30
334
342
327
332
379
387
359
368
119
121
a
s/ai
320
236.75
17.306
17.134
16.665
6.295
2.068
1.903
18.306
9.191
2.07"!
220
?30
326
331
332
389
392
410
408
509
497
548
543
284
266
253
309
304
299
287
547
543
156
163
290
184
185
219
219
187
187
24
22
31
29
318
123
316
117
354
354
338
342
123
123
9
6/27
314
255.78
17.471
17.306
16.720
6.460
3. 027
1.855
18.974
9.329
NA
216
338
308
312
312
378
380
436
434
519
514
546
542
278
277
278
306
306
309
299
500
50B
40
82
284
64
179
88
216
47
183
36
31
36
34
i 293
•wo
232
292
284
328
314
320
111
112
192
SHEET A9
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA fl
C-E POWER SVSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST DATA
TEST NO.
DATE
UNIT LOAD
PRESSURES [GAUGE)
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
RH SPRAY WATER
HP HTR's G11G2 STH IN
TEMPERATURES
1976
MW
KO/S
MPA
10
5/23
324
260.31
17.458
17.223
16,678
6.433
2.068
1.896
18.761
9.308
2.068
V,
5/19
491
391 . 10
18.506
18.154
16.947
10.480
3.413
3.165
18.816
10.025
3.385
«
5/10
497
383.66
18.464
18.244
16.872
10.597
3.475
3.199
19.347
9,991
3,440
JJ
3/16
523
407.22
18.671
18.857
16.899
11-233
3.661
3.468
19.629
10.039
3.647
If
5/12
423
348.51
18.078
17.768
16.858
8.805
2.813
2.606
19.422
9.763
2.799
_15
3/13
400
320.54
17.892
17.616
16.741
8.225
2.634
2.489
19.036
9.556
2.627
li
5/16
422
345.11
18.064
17.733
16.789
8.811
2.806
2.599
19.236
9.756
2.799
,7
5/21
320
234.23
17.361
17.161
16.692
6.316
2.061
1.896
18.361
9.218
2.068
IS
5/23
323
253.51
17.478
16.858
16.672
6.419
2.068
1.896
18.657
9.301
2.068
WATER ANO STEAM
ECONOMIZER INLET •
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PEND Oiv INLET LINK
SH PEND Oiv INLET LINK
SH DESH OUTLET LINK
SH DESK OUTLET LINK
SH PCND SPCD FRONT IN LINK
SH PCND SPCD FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESH INLET COMB. LINE
RH RADIANT WALL FRONT IN HDR
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PENO SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PENO SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAT WATER
RH SPRAY WATER
COLD RH EXT STH TO G14G2 HTR
FW INTO HP HTR Gl
FW INTO HP HTR G2
FW OUT or HP HTR Gl
FW OUT OF HP HTR G2
STM DRAIN FROM HP HTR Gl
STH DRAIN FROM HP HTR G2
Am t GAS
PRi AIR AH AIR
PR I AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
PRi AIR AH AIR
PR I AIR AH Am
Sec AIR AH AIR
SEC AIR AH AIR
ECONOMIZER GAS
ECONOMIZER GAS
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
INLET
INLET
INLET
INLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
•c
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
220
318
313
316
323
381
385
435
427
517
507
548
547
283
284
284
320
318
316
308
521
537
157
101
290
185
184
219
219
187
186
245
348
342
348
357
387
393
420
416
500
501
538
554
324
287
278
324
320
319
309
533
567
176
182
387
207
206
245
245
211
208
247
352
346
349
357
392
397
413
409
505
491
548
546
328
265
269
308
308
316
307
531
561
179
183
332
208
207
246
247
212
S10
248
346
343
NA
351
386
393
413
411
494
493
537
548
326
264
272
307
308
319
308
529
556
174
184
331
208
207
248
248
212
209
234
337
334
338
341
385
389
432
424
504
497
546
545
304
303
304
331
328
328
321
542
547
169
173
309
198
197
235
235
SOS
200
229
328
324
NA
331
379
384
423
419
504
504
540
547
295
298
298
329
325
326
324
535
544
160
119
306
192
191
229
229
195
193
235
336
332
340
349
183
394
433
425
502
504
536
556
303
304
304
339
332
333
328
524
571
168
93
310
198
197
234
235
201
200
219
334
331
336
341
391
395
409
407
508
501
544
546
283
271
262
315
306
300
289
542
544
155
163
289
185
184
218
218
187
187
220
323
318
322
327
383
387
431
427
510
507
543
548
283
£83
283
318
317
314
307
524
536
155
107
289
184
184
218
219
187
186
L
R
L
R
L
R
L
R
L
R
L
R
L
R
26
22
38
37
300
305
298
299
342
344
321
326
116
118
31
32
34
33
371
381
362
369
419
431
398
410
144
142
27
28
29
29
376
389
167
376
426
437
404
418
137
134
3
.1
18
IB
370
377
361
364
427
434
399
409
129
112
27
26
29
30
347
353
339
342
397
399
376
381
122
123
5
4
29
29
331
334
325
325
378
380
357
361
118
114
24
22
30
29
340
351
332
339
389
403
367
381
124
123
25
24
30
29
327
334
322
327
361
362
347
354
126
127
22
19
41
41
295
296
291
289
348
349
319
322
112
109
193
SHEET AID
-------
WISCONSIN POWER 1 LIGHT Co.
COLUMBIA tl
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE !ST STAGE
RH INLET
RH OUTLET
SH SPRAT WATER
RH SPRAY WATER
HP HTR's G1&G2 STM IN
TEMPERATURES
AIR & GAS
PRi AIR AH AIR
PRl AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
PRi AIR AH AIR
PRi AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
ECONOMIZER GAS
ECONOMIZER GAS
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
INLET
INLET
INLET
INLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
TEST DATA
1976
hW
KG/S
MPA
1
3/17
517
398.53
18.581
18.216
16.920
10.908
3.585
3.392
19.588
9.963
3.523
a
3/17
512
4O0.04
18.588
18.188
16.892
10.845
3.572
3.378
19.671
9.950
3.509
3
3/20
524
432.30
18.802
18.354
16.920
11.356
3.640
3.426
20.022
10.163
3.572
4
3/20
525
432.30
18.788
18.319
16.913
11.300
3.654
3.440
19.760
10.129
3.592
5
3/22
586
419.95
18.733
18.299
16.927
11.356
3.675
3.461
18.823
10.136
3.606
6
3/20
5S1
444.27
18.892
18.409
16.913
11.355
3.627
• 3.385
20.319
10.239
3.530
7
a/20
522
437.72
18.850
18.409
16.940
11.300
3.634
3.413
20.105
10.177
3.558
8
3/20
522
434.94
18.830
18.161
16.920
9.915
3.640
3.420
20.016
10.163
3.572
WATER t STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PEND Oiv INLET LINK
SH PEND Div INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH PEND SPCD FRONT IN LINK
SH PEND SPCO FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DCSH INLET COMB. LINE
RH RADIANT WALL FRONT IN HDR
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PENO SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAY WATER
RH SPRAY WATER
COLO RH En STM TO G1&G2 HTR
FW INTO HP HTR G1
FW INTO HP HTR G2
FW OUT or HP HTR G1
FW OUT or HP HTR G2
STM DRAIN FROM HP HTR G1
STM DRAIN FROM HP HTR G2
•c
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
247
349
345
351
352
387
392
410
408
494
491
538
546
324
254
264
299
301
310
300
532
553
173
183
329
207
2O6
247
247
211
208
247
349
346
351
352
388
393
414
412
494
486
541
542
323
307
261
296
298
308
299
531
552
173
182
329
206
206
246
246
211
208
241
313
309
316
319
356
363
402
397
484
475
532
534
295
258
249
295
294
291
285
524
544
144
174
326
197
197
239
238
202
19B
241
316
313
321
322
358
366
400
399
485
472
534
534
298
454
248
287
287
287
283
521
545
142
173
327
197
196
238
238
202
197
242
314
313
315
324
358
366
393
388
483
477
530
537
294
247
246
288
289
286
279
523
552
142
177
328
198
197
240
239
202
196
246
331
326
332
339
377
382
433
422
510
497
544
543
323
312
304
339
337
132
326
532
562
172
181
327
206
205
246
246
212
209
239
306
304
308
314
352
359
404
4O1
488
481
528
536
294
264
252
299
296
291
288
518
550
139
173
327
195
194
217
238
202
197
241
308
306
309
318
353
361
4O2
397
484
478
528
536
293
259
247
296
291
289
281
519
545
141
172
328
195
194
238
237
201
196
L
R
L
R
L
R
L
R
L
R
L
R
L
R
3
1
18
17
376
383
367
371
431
438
406
415
122
119
8
2
15
14
381
389
372
377
437
444
406
421
122
120
9
17
13
16
368
378
359
367
421
433
396
410
118
112
16
17
11
16
373
388
365
377
426
443
402
419
119
116
11
14
11
15
366
377
357
367
422
433
397
409
113
113
23
23
26
26
346
357
369
346
399
408
373
387
123
118
14
17
15
17
354
363
347
353
408
418
382
394
115
109
16
18
18
21
359
369
352
359
412
423
387
401
118
112
194
SHEET All
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA |1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
RH SPRAY WATER
HP HTR's G1&G2 STM IN
TEMPERATURES
WATER t STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PEND Div INLET LINK
SH PEND Div INLET LINK
SH DESK OUTLET LINK
SH DESK OUTLET LINK
SH PEND SPCD FRONT IN LINK
SH PEND SPCD FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESH INLET COMB. LINE
RH RADIANT WALL FRONT IN HDR
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PENO SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAT WATER
RH SPRAY WATER
COLO RH EXT STH TO G14G2 HTR
FW INTO HP HTR G1
FW INTO HP HTR G2
FW OUT OF HP HTR G1
FW OUT OF HP HTR G2
STM DRAIN FROM HP HTR Gl
STM DRAIN FROM HP HTR G2
TEST DATA
2
1976 3/24
MW 476
KG/S
380.51
MPA
18.354
18.030
16.864
9.977
3.282
3.103
18.864
9.825
3.820
12
3/24
473
372.83
18.264
17.933
16.816
9.777
3.227
3.048
18.699
9.832
3.165
11
3/24
472
366.53
18.237
17.892
16.795
9.728
3.234
3.048
18.374
9.805
3.172
J2
6/24
524
426.88
18.788
18.347
16.892
11.383
3.661
3.427
20.133
10.336
3.716
n
6/24
525
421.34
18.747
18.374
16.947
1 1 . 362
3.661
3.440
19.960
10.329
3.716
If
6/24
523
424. 1 1
18.712
18.381
16.947
11.369
3.627
3.406
20.091
10.349
3.709
_15
3/24
511
401.43
18.547
18.161
15.877
10.825
3.558
3.372
19.616
10.018
3.496
-16_
6/30
526
415.79
18.726
18.333
16.891
11.411
3.661
3.440
19.754
10.315
NA
AIR t GAS
PRi AIR AH AIR
PRI AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
PRI AIR AH AIR
PRI AIR AH AIR
SEC AIR AH AIR
SEC AIR AH AIR
ECONOMIZER GAS
ECONOMIZER GAS
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
INLET
INLET
INLET
INLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
OUTLET
°C
L
LC
RC
R
L
R
L
R
L
R
L
R
L
L
L
LC
RC
R
L
R
236
327
324
327
332
368
376
397
398
489
479
539
537
292
246
242
283
287
232
275
535
544
142
171
318
193
193
233
233
198
194
237
326
324
328
331
368
377
399
399
488
478
539
539
287
240
237
284
284
281
269
536
544
142
171
317
193
193
234
233
197
193
235
323
319
327
326
369
373
402
392
483
471
535
532
285
226
224
272
271
278
262
526
551
139
169
316
192
192
S33
233
197
192
243
340
342
346
352
385
391
429
420
507
490
542
539
325
281
290
331
327
326
319
532
562
71
186
328
57
205
95
244
98
209
244
345
345
349
354
388
394
435
427
514
498
548
548
334
287
282
IBS.
321
324
316
529
563
69
186
336
57
204
95
244
98
209
244
341
342
343
351
387
389
429
419
507
499
544
545
329
301
291
331
326
326
323
538
554
74
185
331
59
204
95
243
97
208
239
315
315
319
323
363
368
394
391
482
475
531
534
292
229
233
273
277
283
274
520
551
143
172
327
196
195
238
237
201
195
244
342
346
346
345
388
389
422
419
510
498
552
545
333
298
237
326
329
331
320
543
547
79
186
335
39
205
85
244
43
210
L
R
L
R
L
R
L
R
L
R
L
R
L
R
12
14
16
14
367
375
358
364
423
431
399
408
120
112
10
14
11
14
371
378
362
367
427
432
403
411
121
114
10
15
10
14
371
382
364
371
426
435
402
412
121
115
29
26
31
30
357
369
339
341
398
421
386
397
133
131
31
29
32
32
362
376
322
332
403
428
390
4O4
137
137
27
26
29
28
341
364
346
341
402
399
384
393
131
132
15
14
11
16
367
380
361
369
424
435
399
411
120
120
28
25
29
28
353
362
314
349
397
407
387
393
128
125
195
SHEET A12
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TC5T NO.
DATE
UNIT LOAD
FLOWS
FEEOVATER
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE 1si STAGE
RH INLET
RH OUTLET
SH SPRAT WATER
RH SPRAY WATER
HP HTR's G11G2 STM IN
TEWERATURES
TEST DATA
V7
1976 6/25
MW 524
KG/S
41O.12
18.678
19.333
16.940
11.328
3.627
3.420
19.112
10.315
3.716
U!
6/30
526
418.56
18.740
18.388
16.906
11.473
3.661
3.399
19.822
10.370
NA
J9
6/29
524
418.56
18.726
18.340
16.906
11.411
3.661
3.427
19.884
10.343
NA
20
6/E5
521
412.90
18.795
18.374
16.954
11.287
3.627
3.413
19.767
10.308
NA
£1
6/26
419
341.71
18.037
17.809
16.816
8.825
2.792
2.614
19.671
9.881
NA
22
6/25
422
322.43
17.982
17.706
16.802
8.749
3.565
2.646
18.864
9.791
NA
23
6/27
316
262.45
17.526
17.306
16.685
6.578
2.055
1.917
19.133
9.343
NA
24
6/29
322
244.06
17.437
17.258
16.678
6.502
2.075
1.938
18.561
9.377
NA
•c
WATER i STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH PEND Div INLET LINK
SH PENO Div INLET LINK
SH DESK OUTLET LINK
SH DESH OUTLET LINK
SH PENO SPCD FRONT IN LINK
SH PENO SPCO FRONT IN LINK
SH OUTLET LEADS
SH OUTLET LEADS
RH DESH INLET COMB. LINE
RH RADIANT WALL FRONT IN HDR
RH RADIANT WALL FRONT IN HDR
RH PEND SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH PENO SPCD FRONT IN LINKS
RH PEND SPCD FRONT IN LINKS
RH OUTLET LEADS
RH OUTLET LEADS
SH SPRAY WATER
RH SPRAY WATER
COLD RH EXT STM TO G1&G2 HTR
FW INTO HP HTR G1
FW INTO HP HTR G2
FW OUT or HP HTR Gl
FW OUT or HP HTR G2
STM DRAIN FROM HP HTR Gl
STH DRAIN FROM HP HTR G2
AIR i GAS
PHI AIR AH AIR INLET
PRI AIR AH AIR INLET
SEC AIR AH AIR INLET
Sec AIR AH AIR INLCT
PRI AIR AH AIR OUTLET
PRI AIR AH AIR OUTLET
Sec AIR AH AIR OUTLET
SEC AIR AH AIR OUTLET
ECONOMIZER GAS OUTLET
ECONOMIZER GAS OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
L
LC
RC
R
L
R
L
R
L
R
L
R
L
R
L
LC
RC
R
L
R
L
R
L
R
L
R
I
R
L
R
L
R
L
R
243
346
345
347
354
388
393
422
415
502
503
542
553
330
291
283
322
322
326
315
531
563
72
185
333
43
204
94
244
92
209
33
28
33
31
351
372
319
304
398
424
393
402
133
133
244
343
347
348
343
338
389
422
418
509
498
551
545
331
304
300
329
333
334
322
546
538
80
186
334
39
205
86
244
43
209
27
24
28
27
348
353
308
340
401
406
376
385
126
124
245
343
343
343
348
388
391
424
421
506
497
548
545
331
294
294
323
324
330
321
538
557
79
136
334
46
205
86
244
51
209
26
23
28
27
358
368
318
354
398
411
389
398
128
128
243
345
344
349
351
391
394
425
422
504
494
551
546
331
283
274
314
314
319
309
532
552
63
184
333
42
204
94
243
96
208
35
32
36
34
368
379
316
361
418
430
395
407
136
142
231
326
327
329
332
333
386
431
428
508
506
545
548
304
304
305
329
328
332
325
530
554
55
132
309
43
192
94
230
47
197
36
35
37
36
322
334
271
323
376
373
351
358
118
123
232
337
338
342
346
391
394
426
422
506
496
550
546
308
289
276
329
316
313
306
538
553
51
174
312
42
194
94
232
96
197
36
34
37
36
323
356
261
346
393
387
368
379
127
137
216
306
306
303
308
380
379
427
443
509
511
537
538
274
289
272
301
296
292
294
503
496
32
78
278
64
180
88
216
44
183
36
32
36
36
287
292
221
230
337
324
309
313
100
106
218
323
320
323
326
384
387
423
418
512
508
546
547
284
282
284
312
309
313
304
526
541
43
159
289
48
182
66
217
72
184
31
28
33
32
296
312
247
304
354
341
327
332
103
114
196
SHEET A13
-------
WISCONSIN POWER 4. LIGHT Co.
COLUMBIA /i
C-E POUCH SvftTKMa
FltLD TtSTlHO fcNO
PERFORMMiCE RtSUUt
BASaiNE OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLWS
FEEOVATER (MEASURED)
SH SPRAY (PLANT FLOW NOZZLE)
MAIN STEAM (CALCULATED)
TURB. LEAK. (Tuna. HT. BAL.)
HP HTR. EXT. (HEAT BAL.!
RH SPRAY (PLANT FLOW NOZZLE)
RH STEAM (CALCULATED)
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM - SH DESH
SH DESH - SH OUTLET
REHEATED
TOTAL
UNIT EFFICIENCY
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE in AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
ELECTROSTATIC PRECIP. Loss
TOTAL LOSSES
ErnciENCY
HEAT INPUT
HCAT INPUT FROM FUEL
EXCESS AIR
ELECTROSTATIC PRECIP.
AIR HEATER INLET
AIR HEATER OUTLET
TEST RESULTS
1976
MM
KO/S
:ZLE)
>AL.)
I
:ZLE)
MJ/3
%
333
MJ/S
.LET*
1
3/10
524
412
30
441
7
36
17
416
224
362
261
164
274
13O4
4.55
7.55
0.11
0.17
0.37
0.04
0.01
0.02
0.23
13.05
66.95
1500
20.7
25.1
26.7
2
3/08
524
431
11
442
7
38
12
410
212
401
253
165
253
1284
4.29
7.21
0.10
0.1B
0.36
0.03
0.01
0.03
0.30
12.51
87.49
1468
21.8
25.8
33.1
3
3/15
465
381
19
400
6
32
14
375
212
341
230
164
244
1191
4.99
7.42
0.1S
0.19
0.36
0.03
0.01
0.02
0.58
13.72
86.28
1380
34.7
36.5
47.0
4
3/13
399
324
9
334
5
25
1
304
170
327
189
122
167
975
4.16
7.03
0.10
O.S3
0.37
0.03
0.01
0.04
0.69
12.65
67.35
1116
35.6
36.8
55.8
5
5/23
324
262
4
267
4
18
0
244
125
293
146
96
132
793
3.72
7.13
0.09
0.28
0.32
0.02
0.01
0.03
0.45
12.06
87.94
902
27.7
30.0
51.6
6
5/83
383
265
4
269
4
18
0
246
135
286
145
97
134
797
3.93
7.57
0.09 .
0.26
0.32
0.02
0.01
0.02
0.69
12.95
87.05
916
37.5
39.3
55.8
7
5/23
322
262
6
266
4
18
0
246
135
282
147
101
131
797
4.10
7.15
0.10
0.28
0.31
O.OS
0.01
0.02
0.78
12.77
87.23
914
43.2
44.2
61.9
8
3/10
514
397
30
427
6
35
19
404
219
349
254
181
277
1279
4.48
7.48
0.10
O.18
0.36
0.03
0.01
0.02
O.27
12.96
87.04
1469
19.4
23.5
24.9
9
3/09
515
406
SB
432
6
36
17
407
221
359
252
181
271
1284
4.69
7.41
0.11
0.18
0.36
0.03
0.01
0.02
0.35
13.15
86.85
1478
23.7
26.9
35.9
12
3/10
482
371
23
394
6
31
12
369
215
325
238
154
239
1171
4.75
7.49
0.11
0.19
0.37
0.03
0.01
0.11
0.54
13.61
86.93
1347
30.6
32.7
35.7
_n
5/21
321
237
26
263
4
17
6
248
134
243
162
117
164
820
4.16
7.24
0.10
0.27
0.39
0.02
0.01
0.01
0.54
12.74
87.26
940
20.4
21.0
37.6
!i
5/25
321
249
16
265
4
17
2
246
153
244
159
104
147
806
5.07
7.28
0.12
0.28
0.39
O.OS
O.O1
0.02
0.39
13.59
86.41
933
52.5
55.9
81.5
JI3
3/12
524
403
29
432
7
35
21
411
224
348
260
183
285
1301
4.80
7.55
0.11
0.17
0.37
0.03
0.01
0.30
0.08
13.43
86.57
1503
17.1
10.5
30.2
14
3/09
513
409
18
426
6
35
17
401
225
360
249
165
266
1266
4.97
7.29
0.12
0.18
0.35
0.03
0.01
0.01
0.19
13.15
86.85
USB
22.6
27.5
3?. 4
J5
3/10
484
371
26
397
6
31
14
374
813
327
235
164
249
1169
4.84
7.49
0.11
0.19
0.37
0.03
0.01
0.19
0.56
13.80
86.20
1379
32.8
35.0
40.1
J6
3/13
401
322
7
329
5
25
1
300
164
326
192
111
167
962
4.55
7.57
0.11
0.23
0.37
0.03
0.01
0.04
1.55
14.44
85.56
11?.)
35.7
39.1
M.n
V7
5/25
322
246
17
264
4
17
5
247
133
259
159
106
153
809
4.09
7.19
0.10
0.28
0.39
0.02
0.01
O.OS
0.26
12.35
87.65
923
26.1
29.2
45.3
!§
5/25
325
846
20
267
4
17
4
250
148
243
163
109
157
820
4.42
7.16
0.10
0.27
0.40
0.02
0.01
0.02
0.45
12.85
87.15
941
39.5
42.3
52.7
19
5/25
322
244
19
263
4
17
3
245
157
232
160
107
151
807
5.00
7.23
0.12
0.28
0.39
0.02
O.O1
0.02
0.71
13.77
86.23
936
54.8
57.1
83.2
-------
WISCONSIN POWER S LIGHT Co.
COLUMBIA II
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST RESULTS
TEST NO.
DATE 1976
UNIT LOAD MW
PRODUCTS OF COMBUSTION >Ma/J
1
3/10
524
ELECTROSTATIC PRECIPITATOR INLET
DRY PRODUCTS
WET PRODUCTS
AIR HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS KG/S
GAS ENTERING PRECIPITATOR
GAS ENTERING AIR HEATER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE %
GAS SIDE EFFICIENCY
-------
WISCONSIN POWER £ LIGHT Co.
COLUMBIA /I
C-E POVER SYSTEMS
FIELD TESTING AMD
PCRFORMAHCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEOWATER (MEASURED^
SH SPRAV (PLANT FLOW NOZZLE)
MAIN STEAH (CALCULATED)
TURB. LEAK. (Time. HEAT BAL.)
HP HTR. EXT. (HEAT BALANCED
RH SPRAY (PLANT FLOW NOZZLE)
RH STEAM (CALCULATED)
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM - SH DESH
SH OESH . SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASM Loss
PYRITE REJECTION Loss
CARBON Loss
ELECTROSTATIC PRECIP. Loss
TOTAL Losses
EFFICIENCY
HEAT INPUT
HEAT INPUT FROM FUEL
EXCESS AIR
ELECTROSTATIC PRECIP.
AIR HEATER IMLCT
AIR HEATER OUTLET
TEST RESULTS
1976
MM
KQ/3
ZLE)
BAL.)
CE>
ZLE)
MJ/s
*
ISS
MJ/s
IUCT
1
5/19 .
505
406
81
426
6
35
13
398
222
356
244
182
248
1252
5.33
7.24
0.13
0.18
0.37
0.03
0.01
0.02
0.50
13.81
86.19
1453
80.4
83.2
42.3
2
5/19
506
412
17
428
6
35
16
404
224
363
248
180
263
1272
5.31
7.29
0.12
0.18
0.35
0.03
0.01
0.03
0.15
13.46
86.54
1470
18.4
23.2
41.3
3
3/14
525
404
29
433
7
35
21
412
228
347
264
181
284
1304
5.31
7.55
0.12
0.17
0.36
0.04
0.01
0.35
0.53
14.44
85.56
1524
15.2
18.4
28.4
4
5/19
506
404
26
431
7
34
12
408
282
354
245
192
24B
1862
5.20
7.25
O.12
0.18
0.34
0.03
0.01
0.02
0.34
13.48
86.52
1459
19.0
23.2
40.4
5
5/12
422
349
4
352
5
2B
2
381
178
345
187
134
176
1081
4.63
7.86
0.11
0.82
0.37
0.08
0.01
0.03
0.60
13.24
86.76
1177
26.1
28.4
47.1
6 .
5/12
422
345
7
352
5
27
1
321
168
351
193
133
177
1082
4.85
7.88
0.10
0.88
0.37
0.02
0.01
0.02
0.48
13.29
86.71
1179
21.7
24.5
38.4
7
5/16
481
342
3
344
5
27
1
314
174
340
196
117
173
1001
4.54
7.72
0.11
0.23
0.36
0.02
0.01
0.02
0.70
13.70
86.30
1160
30.7
32.3
45.1
B
s/ai
380
237
87
863
4
16
4
247
132
245
160
180
160
817
4.38
7.23
0.10
0.27
0.39
0.02
0.01
0.01
0.42
12.83
87.17
937
19.7
21.1
39.5
9
6/27
314
256
3
258
4
18
0
236
119
292
142
90
180
763
3.84
7.11
0.09
0.29
0.35
0.02
0.01
0.02
0.30
12.03
B7.97
867
34.2
35.9
56.1
JO
5/23
324
260
7
268
4
18
0
245
127
287
148
102
135
799
4.16
7.17
0.10
0.88
0.33
0.03
0.01
0.04
0.52
12.63
87.37
915
29.2
38.4
48.2
JJ
5/19
491
391
26
417
6
32
13
392
227
335
242
185
250
1239
5.45
7.30
0.13
0.17
0.35
0.03
0.01
0.02
0.82
14.27
85.73
1445
23.1
S3. 9
46.2
J2
5/10
497
384
33
417
6
30
18
399
887
319
850
190
869
1856
5.82
7.36
0.12
0.18
0.35-
0.03
0.01
0.03
0.21
13.51
B6.49
1452
24.6
29.2
41.3
13
3/16
523
407
31
438
7
35
18
415
223
366
249
191
279
1308
4.86
7.63
0.11
0.17
0.36
0.03
0.01
0.03
0.10
13.31
86.69
1509
IB. 4
25.4
35. 8
11
5/12
423
349
5
353
5
27
2
323
190
333
195
131
179
1027
4.73
7.01
0.11
0.22
0.3B
0.02
0.01
0.02
0.57
13.08
86.92
1182
34.1
36.7
50.4
js
3/13
400
321
4
325
5
85
1
296
161
329
183
112
163
949
4.76
7.29
0.11
0.24
0.36
0.03
0.01
0.08
0.81
T3.63
86.37
1099
35.8
36.7
54. B
J6
5/16
428
345
5
350
5
86
1
380
190
328
201
122
178
1020
5.23
7.13
0.12
0.22
0.35
0.02
0.01
0.02
0.78
13.89
86.11
1185
41.3
43.2
65.8
J7
5/21
380
234
27
261
4
16
3
844
148
832
157
128
158
806
5.03
7.16
0.12
0.28
0.40
0.03
0.01
0.08
0.38
13. 3B
86.68
929
35.9
37.6
56.0
11
5/23
323
854
11
264
4
18
0
242
130
273
147
104
134
788
3.89
7.33
0.09
O.ffl
0.33
0.08
0.01
0.04
1.14
13.33
86.67
909
36.6
38.4
58.8
-------
WisconsiN POWER t LIOMT Co.
COLUMBIA ill
C-F! POWCR SYSTEMS
F I ELD Ten I JJG AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST RESULTS
TEST MO.
10
11
12
13
14
15
16
17
18
DATE 1976
UNIT LOAD tV
PRODUCTS OF COMBUSTION WJ
ELECTROSTATIC PRECIPITATOR INLET
DRY PRODUCTS
WET PRODUCTS
AIR HCATCR INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS KG/S
GAS ENTERING PRECIPITATOR
GAS ENTERING Am HEATER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE ""•
GAS SIDE EFFICIENCY ^
GAS DROP C
AIR RISE C
TEMPERATURE HEAD C
FUEL ANALYSIS
CARBON
HYDROGEN
NITROGEN *•
OXYGEN
SULFUR ~:'
MOISTURE
Hs« '
HHV ' ' ' " <-•
5/1 'I
505
405
437
443
453
414
446
?86
191
475
509
635
64B
740
658
568
92
13.9
66.0
227
319
352
51.4
3.4
_7
12.5
.5
24.7
7.7
i/in
5^6
404
436
444
450
419
458
38?
390
478
512
641
664
753
662
573
80
13.2
66.3
236
314
749
51.0
3.4
.7
12.2
.6
25.0
7.1
3/14
525
393
425
407
412
403
436
374
379
436
469
648
664
715
628
578
51
7.6
67.6
254
347
384
41.8
3.4
.7
12.3
.7
24.< 1
P. 7
5/19
506
398
431
435
440
411
444
380
385
466
500
629
648
730
642
562
82
12.5
66.4
226
315
350
51.2
3.4
.8
12.5
.7
P4.7
7.7
5/12
422
437
471
4B2
489
445
478
420
425
508
542
554
563
638
576
500
75
13.2
69.9
219
287
321
52.4
3.7
.8
11.6
.6
23.9
7.0
5/12
422
420
455
449
455
429
465
403
409
475
511
536
548
602
536
482
54
10.0
70.6
216
282
313
50.3
3.8
.7
11.7
.6
25.9
7.O
1 Q'1^7
5/16
421
451
485
475
481
455
491
431
439
497
533
563
570
618
558
509
48
8.7
70.6
218
284
317
50.1
3.7
.7
11.8
.5
25.3
7.1
5/21
320
400
433
441
446
404
437
382
387
463
497
406
409
466
418
363
57
13.6
65.9
187
271
293
50.4
3.4
.7
12.5
.6
25.4
7.0
6/27
314
429
462
473
479
435
468
411
416
497
531
401
406
460
415
361
54
13.4
69.4
178
239
265
48.5
3.3
.6
13.6
.5
25.9
7.6
5/23
324
440
473
474
480
451
484
422
428
502
536
433
443
490
439
392
47
10.8
68.6
180
247
271
50.1
3.5
.7
11. 6
1.0
23.9
<3.S
5/19
491
421
454
476
482
423
456
403
408
496
530
656
659
766
697
590
107
16.2
66.2
227
317
353
51.*
3.6
.7
11. C
.£
24.2
7.^
5/10
497
422
455
442
448
436
470
403
408
476
509
661
682
739
650
592
57
8.5
69.4
249
329
367
50.5
3.4
.7
12.2
.6
25.1
7.5
3/16
523
402
435
420
425
424
458
383
388
461
495
656
691
747
641
585
56
8.1
71.0
259
333
372
48.8
3.3
.7
12.2
.7
25.6
8.7
5/12
423
451
484
477
483
460
492
433
439
504
537
572
582
635
571
519
53
9. 1
70.9
230
296
331
51.2
3.5
.7
12.1
.9
23.5
8. 1
3/13
400
455
489
496
503
458
492
438
443
516
551
537
541
606
553
487
65
12.0
69.4
214
284
317
50.2
3.5
.8
11.8
.7
24.7
8.3
5/16
422
471
504
526
533
477
510
453
459
550
584
597
604
692
632
544
88
14.4
68.9
220
292
328
51.0
3.5
.7
12.1
.6
24.4
7.7
5/21
320
450
483
490
497
455
488
432
438
514
548
449
453
509
462
407
56
12.1
66.2
195
279
303
49.7
3.4
.8
11.8
.8
24.6
8.9
5/23
323
461
496
508
515
467
502
444
450
534
567
451
456
515
468
409
59
13.0
71.0
183
236
265
48.9
3.6
.6
11.5
1.0
25.8
B. 6
-------
WISCONSIN POWER £ LIGHT Co.
COLUMBIA l\
C-E POVCH SYSTCMS
FIELD TCSTIHO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUNT
TEST NO.
DATE
UNIT LOAD
1976
MW
KQ/S
FLOW
FEEDWATEB (MEASURED)
SH SPRAY (PLANT FLOW NOZZLE)
MAIN STEAM (CALCULATED)
TURBINE LEAKAGE (TURBINE HEAT BALANCE)
HP HTR. EXTRACTION (HEAT BALANCE)
RH SPRAY (PLANT FLOW NOZZLE)
RH STEAM (CALCULATED)
UNIT ABSORPTION MJ/3
ECONOMIZER
FURNACE
DRUM . SH DESH
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY %
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN Fur ASH Loss
PVRITE REJECTION Loss
CARBON Loss
ELECTROSTATIC PRECIPITATOR Loss
TOTAL LOSSES
Err ICIENCV
HEAT INPUT MJ/s
HEAT INPUT FROM FUEL
EXCESS AIR H
ELECTROSTATIC PRECIPITATOR INLET
AIR HEATER INLET
AIR HEATER OUTLET
TEST RESULTS
J^
3/17
517
399
26
425
6
34
20
404
227
341
246
185
281
1280
4.69
7.94
0.11
0.18
0.36
0.03
0.01
0.01
0.79
14.12
85.88
1490
23.9
25.4
33.3
2
3/17
512
400
26
426
6
34
20
405
230
340
247
183
285
1286
4.86
7.61
0.11
0.18
0.36
0.03
0.01
0.02
0.07
13.25
86.75
1482
23.2
30.8
34.2
3
3/20
524
432
7
439
7
38
14
409
160
467
246
156
287
1315
4.54
7.46
0.11
0.17
0.36
0.03
0.01
0.02
0.80
13.50
86.50
1520
21.8
23.2
33.3
4_
3/20
525
432
12
445
7
37
15
416
167
459
255
163
294
1338
4.55
7.36
0.11
0.17
0.36
0.03
0.01
0.01
0.60
13.20
86.80
1541
19.7
22. 5
31.6
5
3/22
526
420
24
444
7
36
15
416
159
449
257
180
298
1342
4.36
T.SB
0.10
0.17
0.36
0.03
0.01
0.02
0.51
12.84
87.16
1540
20.4
23.9
30.8
6
3/20
521
444
2
446
7
38
3
404
2OO
432
236
175
227
1269
4.05
7.39
0.09
0.18
0.35
0.02
0.01
0.03
0.25
12.37
87.63
1448
13.3
18.4
26.9
7
3/20
522
438
3
441
7
39
12
407
151
485
245
150
278
1310
4.20
7.34
0.10
0.17
0.36
0.03
0.01
0.04
0.32
12.57
87.43
1498
13.9
19.0
30.8
a
3/20
522
435
4
439
7
38
13
407
151
479
241
153
284
1309
4.08
7.32
0.10
0.17
0.36
0.03
0.01
0.03
0.33
12.43
87.57
1495
15.1
19.7
26.9
9
3/24
476
381
17
398
6
31
13
374
178
387
225
159
272
1221
5.09
7.37
0.12
0.19
0.35
0.03
0.01
0.01
0.96
14.13
85.87
1422
36.8
37.7
49.4
_10
3/24
473
373
17
390
6
31
14
367
174
380
223
155
264
1196
5.23
7.29
0.12
0.19
0.36
0.03
0.01
0.02
0.80
14.05
85.95
1392
35.8
37.6
49.3
JJ_
3/24
472
367
22
389
6
30
16
368
165
383
225
154
264
1191
5.02
7.34
0.12
0.19
0.33
0.02
0.01
0.01
0.90
13.94
86.06
1384
. 30.0
30.8
40.4
_12
6/24
524
427
19
446
6
35
11
415
237
376
258
187
261
1319
4.61
7.07
0.11
0.17
0.35
0.02
0.01
0.02
0.44
12.80
87.20
1513
23.9
26.1
35.8
-------
WISCONSIN POWER
COLUMBIA «i
LIGHT Co.
C-E POWER SYSTEMS
FIELD TESTING »NO
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE 1976
UNIT LOAD Mil
FLOWS KB/S
FEEDVATER (MEASURED!
SH SPRAY (PLANT FLOW NOZZLE!
MAIN STEAM (CALCULATED)
TURBINE LEAKAGE (TURBINE HEAT BALANCE)
HP HTR. EXTRACTION (HEAT BALANCE)
RH SPRAY (PLANT FLOW NOZZLE)
RH STEAM (CALCULATED!
UNIT ABSORPTION MJ/s
ECONOMIZER
FURNACE
DRUM - SH DESK
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY %
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
ELECTROSTATIC PRECIPITATOR Loss
TOTAL LOSSES
EFFICIENCY
HEAT INPUT MJ/s
HEAT INPUT FROM FUEL
EXCESS AIR %
ELECTROSTATIC PRECIPITATOR INLET
AIR HEATER INLET
AIR HEATER OUTLET
TEST RESULTS
12
6/24
525
421
SS
444
7
35
16
41 B
243
360
265
195
263
1326
4.80
7.05
0.11
0.17
0.35
0.03
0.01
0.02
0.56
13.10
86.90
1526
26.9
28.5
41.4
If
6/24
523
424
19
443
7
35
8
408
233
375
253
196
243
1300
4.62
7.03
0.11
0.17
0.35
0.02
0.01
0.02
0.39
12.72
87.28
1489
26.9
27.7
38.6
-15
3/25
511
401
23
425
6
34
18
402
159
428
245
171
284
1286
4.74
7.38
0.11
0.18
0.37
0.03
0.01
0.01
0,74
13.57
86.43
1488
18.3
20.4
30.8
Jj>
6/30
526
416
23
438
7
34
12
409
227
368
253
203
243
1295
4.42
7.12
0.10
0.16
0.35
0.02
0.01
0.06
O.S9
12.55
87.45
1481
24.6
26.1
36.8
17
6/25
524
410
30
440
7
34
14
413
237
353
260
213
257
1320
4.66
7.48
0.11
0.17
0.36
0.03
0.01
0.05
0.25
13.12
86.88
1519
26.2
28.5
40.5
_18
6/30
526
419
23
441
7
35
10
409
233
366
254
204
233
1289
4.26
7.18
0.10
0.18
n.35
0.02
0.01
0.05
0.72
12.87
87.13
1479
23.2
24.7
37.7
15
6/29
524
419
22
441
7
35
12
412
228
371
256
199
249
1302
4.21
7.12
0.10
0.17
0.34
0.02
0.01
0.03
0.34
12.34
87.66
1485
19.1
19.8
30.9
20
6/85
521
413
25
438
7
34
17
414
240
354
261
202
263
1320
4.75
7.27
0.11
0.17
0.35
0.02
0.01
0.03
0.66
13.37
86.63
1524
25.4
27.7
39.5
£1
6/26
419
342
9
350
5
27
0
318
173
346
194
141
173
1027
4.22
6.92
0.10
0.22
0.37
0.02
0.01
0.02
0.59
12.47
87.53
1173
30.0
32.4
48.3
IE
6/25
422
322
20
342
5
25
5
316
186
302
202
152
202
1044
4.43
6.97
0.10
0.22
0.34
0.02
0.01
0.02
0.50
12.61
87.39
1195
28.5
30.1
42.4
23
6/27
316
262
1
263
4
19
0
240
115
306
144
82
- 123
770
3.25
6.91
0.08
0.29
0.35
0.02
0.01
0.03
0.59
11.53
88.47
870
32.5
35.1
51.6
24
5/29
328
244
15
259
4
17
0
238
189
261
148
114
133
785
3.73
6.94
0.09
0.28
0.36
0.02
0.01
0.02
0.77
12.82
87.78
894
34.2
34.2
50.5
-------
WISCONSIN POWER
COLUMBIA it
* LIGHT CO.
C-E. POWER STSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERF1RE AIR OPERflTKJN STUDY
TEST RESULTS
TEST NO.
DATE i 975
UNIT LOAD t/u
PRODUCTS OF COM3USTION JUS/J
ELECTROSTATIC PRECIPITATOR INLET
DRY PRODUCTS
WET PRODUCTS
AIR HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS KG/S
GAS ENTERING PRECIPITATOR
GAS ENTERING AIR HEATER
GAS LEAVING AIR HEATER
Am ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE %
GAS SIDE EFFICIENCY %
GAS DROP c
AIR RISE C
TEMPERATURE HEAD c
FUEL ANALYSIS
CARBON %
HYDROGEN %
NITROGEN £
OXYGEN %
SULFUR %
MOISTURE %
ASH *
HHV KJ/KO
1
3/17
517
413
448
420
425
417
452
394
400
443
478
668
673
712
633
596
39
5.6
71.9
267
339
379
47.30
3.20
0.70
11.80
0.70
27.90
8.40
19050
2
3/17
512
414
447
406
411
438
472
395
400
449
483
662
700
716
609
593
16
2.3
72.4
278
346
382
48.80
3.30
0.70
IS. 10
0.60
25.80
B.70
19492
3
3/20
524
412
446
427
433
417
450
394
400
450
483
678
684
734
65B
608
50
7.4
72.3
264
333
372
50.30
3.50
0.80
12.00
0.60
24.80
8.00
20050
4
3/20
525
400
433
412
417
409
442
382
387
438
471
667
681
726
642
596
45
6.7
72.2
263
341
378
49.80
4.40
0.80
11.80
0.70
24.90
8.60
20097
5
3/22
526
401
434
406
411
412
445
384
389
434
467
668
685
719
633
599
34
5.0
73.1
268
333
373
50.00
3.50
0.80
11. BO
0.70
24.10
9.10
20306
6
3/20
521
383
416
393
398
399
432
365
370
427
460
602
626
666
576
536
40
6.4
71.7
237
313
337
50.20
3.50
0.80
12.00
0.60
25.20
7.70
20120
7
3/20
522
384
416
403
409
400
433
366
370
438
471
623
649
706
613
554
57
8.8
72.1
250
318
354
49.80
3.40
0.70
12.00
0.80
24.90
8.40
19980
8
3/20
522
387
419
398
397
401
434
369
374
424
457
626
649
683
594
559
34
5.4
73.1
256
321
357
49.70
3.40
0.60
12.00
0.90
24.90
8.50
20004
9
3/24
476
461
494
480
486
463
497
442
448
501
535
702
707
761
691
637
54
7.7
72.0
262
331
371
50. 4O
3.50
0.80
13.10
0.70
24.00
7.50
20004
JO
3/24
473
453
486
473
479
459
492
436
441
496
530
676
665
738
667
614
53
7.7
71.4
264
337
377
50.20
3.50
0.80
11.90
0.90
23.90
8.80
20283
,,
3/24
472
443
476
455
461
445
478
424
429
476
510
659
662
706
638
594
44
6.6
71.7
265
339
377
58.30
3.60
0.80
13.60
0.50
24.00
5.20
20515
!§
6/24
524
412
444
425
430
419
451
394
399
450
488
678
688
729
650
604
47
7.0
70.0
235
297
344
51.50
3.60
0.80
12.70
0.50
23.80
7.10
2O864
-------
WISCONSIN POWER X LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
TitLD TESTING «IID
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST RESULTS
TEST NO.
DATE
UNIT LOAD
PRODUCTS Or COSBUSTION
ELECTROSTATIC PRECIPITATOR
Our PRODUCTS
WET PRODUCTS
Am HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR aOWS
GAS ENTER i no PRCCIPITATOR
GAS ENTER i NO AIR HEATER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAOE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE EFFICIENCY
GAS DROP
AIR RISE
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NlTROOEN
OXYGEN
SULFUR
MOISTURE
ASH
HHV
1976
MW
WJ
INLET
KG/S
%
C
C
C
i
a
%
%
f
•t
Kj/KG
13
6/24
525
409
441
431
436
414
446
391
396
454
4B6
673
680
748
6G5
604
62
9.0
68.8
234
286
348
49.90
3.40
0.60
13.80
0.40
24.60
7.3O
20562
14
6/24
523
412
444
428
433
415
446
394
399
448
481
661
664
716
645
594
52
7.7
69.5
233
299
343
50.10
3.40
0.60
13.80
0.50
24.20
7.40
20492
15
3/S5
511
404
437
421
426
411
444
387
392
445
478
650
661
711
634
583
50
7.8
70.9
260
336
374
50.20
3.50
0.70
11.90
0.90
23.50
9.30
19911
16
6/30
526
411
443
426
432
415
448
393
398
449
482
656
663
714
640
589
51
7.6
71.0
239
291
344
50.80
3.50
0.80
12.70
0.50
24.70
7.10
2O678
17
6/25
524
413
442
432
437
420
454
394
400
458
492
671
690
747
664
608
57
8.4
70.1
239
272
348
47.80
3.30
0.70
13.70
0.50
25.70
8.60
19399
18
6/30
526
391
423
412
418
395
428
373
378
435
468
626
633
692
618
559
59
9.3
70.0
230
884
336
48.90
3.40
0.80
14.10
0.50
25.60
6.70
S0515
19
6/29
524
380
412
396
401
382
414
362
366
416
448
612
615
665
595
544
50
8.3
70.4
240
297
349
49.40
3.40
0.70
14.40
0.40
25.10
6.60
2O562
20
6/25
521
409
442
428
434
416
449
391
396
453
487
674
684
742
661
604
58
8.3
69.4
237
292
349
49.40
3.40
0.60
13.80
0.40
25.30
7.10
2OI20
11
6/26
419
440
472
473
479
448
480
422
427
499
538
554
563
684
562
501
61
10.8
70.9
208
249
301
51 .90
3.60
0.60
18.90
0.60
22.90
7.50
20585
22
6/25
422
417
449
436
442
422
454
398
403
460
498
536
542
588
528
482
46
8.5
69.3
216
266
319
50.40
3.50
0.70
14.60
0.70
23.90
6.20
S0655
23
6/87
316
481
454
454
459
429
462
403
408
479
513
395
402
446
399
355
44
11.1
73.0
183
207
858
49.30
3.40
0.60
14.30
0.40
25.10
6.90
SO515
24
5/29
322
433
466
465
471
433
466
415
480
484
517
417
417
462
481
375
45
11 .0
71.5
195
232
280
49.80
3.40
0.70
13.60
0.70
24.10
8.30
SOSB3
-------
Wfacon*In Power s Llghc Co.
Columbia t\
BASELINE OPERATION STUDY
C-t Povt«r %y
F\«^d TemtX
Performance
WTERWALL ABSORPTION RATES. kW/nT
s
m
-I
TF3T
T/C * 1
2
2
4
5
6
7
d
9
10
11
12
12
14
15
lu
IT
IS
19
20
21
22
23
24
23
2o
27
28
29
30
31
32
23
34
35
36
37
38
39
40
41
42
A ^
f 3
44
4t>
1
':.<>
U.D
0.0
IB. 73
2.10
0.0
15.17
IB. 02
16.24
110.7s
91.37
22.49
5 o.OO
95.22
15.29
8.28
61.39
44.10
73.24
50. 4b
5.71
131. 7J
lib. 94
76.05
60.53
53.24
40.53
0.0
97.72
36.69
91.33
65.78
64.87
64. 37
28.56
44.2o
87.09
b9.82
44.26
71. b7
64.35
71. -jl
I t a «_ (.
1 J O *U *?
69.23
•n.an
2
45. jj
O.U
lOo. 11
191. jo
an. jt
n.o
110.44
19. 17
z. T^
120. >J
45. j6
78. lo
»1. Id
80. J:>
47. da
8 2 . U y
30./-.
92. J,;
93. 7d
74. Uu
56. 30
113. 74
121. 7d
79., 0
I0tt.o2
26. JJ
70. jt
O.U
33.3-,
51. of
93. *J
126. Jo
111. Ji
116. oJ
86. uf
7o. *j
2b.2t
14B.31
29. t-t
91. jj
113. -f/
100. jy;
M5. J<
l"i>. ^J
J
2 1. J(j
0.0
.1.0
d. J J
j5.9B
J.J
4. J3
.31
')2. 7 a
L Jo . -t,l
j>. +0
I ) .ilj
o).06
111 .05
//.ol
MJ.U
t
3').UJ
:J .0
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Ud.4V
32. 7o
0 .U
d2.d
J £ • C }
I 72. J J
1 .J.jl
5
32.32
0.0
0.0
5i.78
29.62
0.0
3.39
75.31
65.29
75.31
63.47
56.19
50.74
0.0
87.20
34.49
157.51
126.46
110.94
109.11
64.42
0.0
161.28
257.88
141.19
Io4.93
159.45
0.0
122.76
150.16
192. 14
150.16
140. 11
130.07
101.76
185.24
15d.77
198.00
127.77
14o.90
It4.lu
M.il
i »g j i;
1 f * • £. 3
i >2. m
ZOO. 2 3
b
23.26
0.0
0.0
59.41
31.33
0.0
3.54
85.24
80.68
80.68
70.65
55.19
56.09
0.0
86.20
33.50
154.67
119.06
101.71
97.15
56.14
0.0
155.71
261.42
135.62
152.97
126.48
0.0
114.45
147.32
200.25
155.54
146.41
127.23
9B.OI
166.39
145.89
105. 14
128.55
145. d9
141.33
O.U
i c /. •a f.
1 7U • J *r
172.77
I7d.25
7
32.03
0.0
0.0
73.78
27.53
0.0
0.0
94.16
75.01
82.30
57.71
53.16
45.90
0.0
97.86
27.90
161.77
116.12
103.33
93.29
59.57
0.0
162.80
263.95
138.15
155.50
140.89
0.0
106.94
138.90
198.22
123.37
137.07
116.98
95.07
159.39
130.17
156.05
124.69
132.91
135.64
0.0
1 £7 Q2
i. *f f * v£
lt.4.35
169.S3
8
2.90
0.0
0.0
22.42
13. U7
0.0
150.68
28.01
33.06
107.40
97.90
41.70
60.67
63.29
106.24
16.14
66.80
58.06
64.62
56.60
11.90
132.05
58.29
94.05
72.15
89.67
80.91
0.0
77.96
52.45
118.14
94.03
93.30
74.31
40.10
78.47
107.69
8o.50
74.09
109.15
89.42
133.91
1 1 sl \ **
L 1 v • L?
76.79
99.43
9
120.87
0.0
52.43
166.53
6.40
0.0
140.97
62.63
8.59
100.05
90.91
69.01
58.08
53.53
33.49
96.32
41.64
85.36
89.02
48.91
8.53
124.69
146.61
100.03
106.42
116.47
75.07
0.0
100.73
64.23
97.99
50.57
73.34
62.40
30.63
44.53
58.17
68.19
81.88
85.53
99.22
70.93
fl 1 ?O
O L • £ 7
122.38
115.99
10
0.0
0.0
0.0
28.88
102.61
0.0
83.43
31.81
31.81
101.91
96.43
43.57
59*03
109'. 21
5.23
20.09
63.54
61.71
72.65
60.81
14.76
130.24
45.41
94.62
75.45
0.0
83.67
0.0
75.26
58.85
128.21
B3.47
84.38
68.87
36.16
58.28
89.28
84.72
46.46
106.63
85.63
116.68
1 H7 ft
-------
Wisconsin Power £ Light Co.
Columbia fl
BASELINE OPERATION STUDY
C-E Power Systems
Field Testing and
Performance Results
WATERWALL ABSORPTION RATES, kW/m
10
11
12
13
IS
1/C ft
47
43
49
50
51
b2
53
54
55
56
47
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
73
79
80
31
82
d3
84
85
uo
87
88
OO
Cb.24
37. 40
66.12
146.44
114.96
111.30
54.20
V0.73
103.32
0.0
0.0
1-3. 2J>
86.82
31.44
27.83
190.17
44.17
77.37
70.50
25.11
41.38
U.O
0.0
150.91
97.93
96.11
86. Oo
Z&.77
0.0
60.32
0.0
71.25
35.79
56.08
120.36
11-. 57
95.30
7t.li
70. 9d
b2.d4
99. 20
8 7. •*!>
14?*?"
oo . V O
S4.I.-
I'M. JJ
119. J^
Iu8. t i
UO. tJ
117. j-J
79. o7
27. 3j
43. J't
0.0
il. J
lid. i-J
84.42
46.0^
9. to
31. J4
101.33
140. 2 j
98. dJ
92.32
142.01
0.0
0.0
103.41
110. JU
123.24
142.4o
58. ft)
0.0
36. H 1. J\
i 7.O4
133.31
1,1.^
y<:.ul
I0o.:jl
03 tt'j
3J» 16
4 f . 3 J
J.O
.1.0
loJ.02
J4.t 3
33.46
3o.5
L J i • i J
J J. I*;
3V. 17
OJ.72
».d .32
lJ.41
Ho. 3d
23. U7
33 .4o
J3. 94
21. 1-t
0.0
U.O
70.03
33.72
3.23
0.0
17.37
60.68
36.71
131.49
102.27
113.03
0.0
0.0
102.3o
n. ->3
L3d.d4
123.37
103. 76
J .0
31.23
0.0
37.53
47.62
->1.52
o 4 . 7 1
07. d ?
133. ol
11 J. ltd
7 1 . ') t
I- 7.0*
63 .'Jf
111 . 1 J
.? I • *? J
1 j ,1 . 3 )
47.10
131.78
ii9.ua
37.05
15d.03
4'j.30
165.33
93.20
45. dU
110.55
0.0
36. H4
39.55
30.52
78.96
57. 1U
103.16
90.81
7.84
94.50
107.29
123.29
0.0
o.n
0.0
135.71
134.09
171.31
118.36
0.0
140.11
152.39
125.50
44.45
207.12
22«.49
152.38
132.29
0.0
150.95
120.82
130.34
12'J.o^
1 1 3. £i>
1 3 1 . S !•
3B.77
134.43
Ii7 .17
48.42
146.81
90.38
149.72
84.91
83.08
104. 9b
0.0
50.33
47.60
35.84
81.59
58.82
98. 02
76.12
8.61
86.20
99.88
118.15
0.0
0.0
0.0
123.74
179.44
159.36
110.05
0.0
135.45
149.15
117.19
116.27
197.00
229. 61
147.72
123.98
0.0
156.34
129.8o
144.47
LJ2.it>
1 3'.- 2f
123.26
128.74
43.99
134.91
117.56
147.70
07.44
118.47
100.21
0.0
48.31
47.40
32.03
HI. 39
55.89
92.34
63.17
7.57
86.90
89.64
105.16
0.0
0.0
0.0
113.49
169.19
145.46
98.88
0.0
130.63
142.55
107.85
106.02
173.08
166.69
144.76
121.95
0.0
148.83
121.44
150.66
120.00
1 12.31)
L 3d .Do
67.31
81.90
92.85
81.90
143.31
112.63
119.20
62.25
87.79
108.97
0.0
0.0
165.29
92.23
38.13
77.45
138.09
57.03
82.56
21.13
34.09
47.14
0.0
0.0
133.51
65.58
107.20
99.17
32.88
0.0
69.21
0.0
83.07
45.18
73.36
120.11
13^.11
107.69
82.12
104.54
104.54
10J. 19
91.39
133.04
LI > . 93
72.16
80.37
96.81
100.16
135.76
36.36
131.19
65.46
24.66
19.30
0.0
0.0
137.31
72.47
17.39
14.73
69.01
115.57
101.87
37.11
38.92
59.83
0.0
0.0
92.72
50.78
129.26
127.43
32.64
0.0
86.12
0.0
87.03
51.48
39.09
126.63
103.79
105.62
78.23
41.23
78.55
1O8.68
105. Oi
7 *,.
-------
Wfccon*In
Columbia ft
X Light Co.
BASELINE OPERATION STUDY
UATERWALL ABSORPTION RATES. kW/nt
Performance
8
TFST
T/C « 91
92
93
94
95
96
9?
93
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
1
115.39
120.3 7
148.27
144.62
0.0
202.02
82.23
104.33
72.00
81.61
1<.1.29
135.13
0.0
109.47
157.00
0.0
170.11
0.0
46.72
0.0
45.1)1
71.47
05. 45
55.17
111.15
99. do
2
11)5. J-.
103. lo
138.11
37.70
O.I)
75.24
102. jj
106.43
1:1.11
118.3;
108. dj
V.5J
^0.3 1
0.0
!•»-.. 65
0.0
•J4.16
0.0
->0.0b
lOd. It]
«t.lf
t V.04
u>l.,J9
JJ ,OU
4
115.47
114.37
120.44
13U.30
0.0
•14.92
I4f.2b
67.70
71.17
u6.07
l
-------
Wisconsin Power & Light Co.
Columbia i\
BASELINE OPERATION STUDY
C-E rower Systems
Field Testing and
Performance Results
WATERUALL ABSORPTION RATES. kW/m
TFfT
T/C *
10
17
14
1
2
3
4
5
6
7
8
9
in
11
12
13
14
15
16
17
Id
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
33
39
40
41
42
43
44
.05
47.96
20.55
159.44
155.79
52.14
47.76
4!>=oO
3
109. 2j
0.0
133.-»i
l4t>.^J
i:-n. j'
0.0
j.o
o.o
1^^. u4
, j.o>;
J.O
)3. 72
JJ.,)3
'tt. d3
J J . 3 2
OJ. 46
33.4 -j
31.23
J.O
2t.21
u3.09
40.83
114.17
10J.4G
jj.73
3o.7 1
0.0
ii4.65
190.96
103.16
121). 69
J.O
0.0
32.13
42.22
132.40
IJj.O*
104.37
4l) .40
7:>.dO
uJ.Ol
dj.24
d3.33
J7.1S(
lU.J.Jt
10J.a7
J.O
JJ .43
LCI-j .. BO
TfST
T/C *
17
1 J
46
47
4d
49
50
51
52
53
54
5s
So
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
7«
79
80
81
82
63
84
85
86
87
88
8V
•JO
31.69
54. di)
04. 3t
25.44
19.02
114.80
17.4V
bl.33
97.27
20.33
0.0
0.0
65.60
30.03
tj.66
73.52
106.37
67.69
JU.61
123.54
111.85
108.20
0.0
0.0
101.90
81.45
147.93
109,. 21
109.94
0.0
112.86
0.0
61.04
108.47
213.44
217.31
144.83
119.99
124.37
44.71
119.08
bC.il
iu.78
V8.63
131.53
L09..W
135. ^t
116.0,,
89. j)
153. 2d
121. s2
87. J3
55. ul
112.14
123. ij
0.0
UI.J2
128.o2
aa.tj
36. Ot
47. dJ
76. yl
b4.1o
152.04
26.20
67. d3
70.34
0.0
0.0
0.0
52.31
74.35
122.72
73.44
0.0
161.32
65.44
123.47
145.3V
85. ii
145. {4
120.22
3C>.4!>
o.o
111. JO
114.71
114. it
71. J-
1 35.<2»
as. rt
d.>.4l
oi.tl
10J.33
d.n
117.46
42.31
uO.92
ti .11
it. 60
40.03
0.0
120.20
UJ.25
dj.jl
*0.33
t9.41
f j.dO
30. J2
130.14
27.78
«7.65
rj.38
d.o
0.0
0.0
49.38
72.32
117.03
6^.77
0.0
132.40
jo.o9
IOL.35
10d.65
dO. 77
126.41
101. rs
n.n
0.0
yr.«o
112.20
io3. or
o-t. ?8
ll-t.03
j ». 10
o9.43
J4.94
100.4?
oi.35
117.54
40.20
71.96
46.52
79. 2S
d3.64
0.0
123.05
1J0.35
31.06
41.37
49.52
73.91
50.4J
125.20
30.44
56.14
62 .M
o.«
O.t
0.*
46.91
66.0*
101.62
55. IS
0.0
lOj.12
yo.81
41.42
39.60
79.97
124.70
100.04
67.22
0.0
45.89
108.67
102 .2«
!>7.6
66.70
96.44
11.22
0.0
58.99
109.11
0.0
112.62
0.0
34.36
0.0
76.80
127.47
78.54
111.95
105.93
92.16
17
79.3*
58.40
127.71
71.14
0.0
75.04
97. it
0.0
105.20
77. 3.1
0.0
43. to
0.0
34.10
53.46
0.0
91.05
0.0
79. 3.1
0.0
66. I)f3
0.0
10T. OB
I31.lt)
96.89
108.34
18
J2. 78
io. Jd
lit. r 7
74.13
0.0
7+.B9
100. <.a
0.0
101.35
74.49
0.0
47.08
0.0
28.36
46.44
0.0
74.62
0.0
do. 42
0.0
65.33
0.0
97.70
86.24
43.00
104.68
19
d4.72
58.32
112.10
80.17
0.0
76.82
92.37
0.0
86.86
63.53
103.67
32. UO
0.0
23.48
40.90
0.0
69.69
0.0
81.06
0.0
62. JO
».o
96.9ft
83.62
74.92
79.34
-------
Wisconsin Power t Light Co.
Columbia /I
BIASED FIRING OPERATION STUDY
WATEftWAlL ABSORPTION RATES. kW/m*
C-t pQvmr ^y%t.m»
Fln\d Tailing and
Performance Kesu\ta
8
TFfT
T/C i 1
Z
i
4
b
S
7
a
9
in
11
12
13
14
15
16
17
la
19
zo
21
22
24
2<>
25
26
27
28
29
30
31
32
33
34
35
3b
37
38
39
40
ll
42
•i J
44
45
1
74. 10
0.1
U.'j
95.10
ill. 4 7
C.O
0.0
96.20
77.94
HI. 73
75.20
45.15
82.50
49.69
107.06
104.34
ob. 10
111.05
76.04
72.39
50.90
0.0
111.70
148.24
08.80
100.74
91.61
44.23
64.03
93.23
90.41
96. SB
84.10
95.97
133.42
93.55
82. bO
127.34
59.80
B4.*2
120.03
70.7 j
<44. 7d
lit). Jl
118. bJ
i
I2t.jj
0.0
52. /I
233. .>->
121. of
O.U
125. 3i
l3l.3i
3l.v»7
138.3')
70. li
J* • to
45. d»
97. J?
91. 34
lol. il
70.u3
57. ij
41. i +
al.2a
85.2J
0.0
149. at
251.01
so. ^r
1 11 . 7V
91. UJ
IJD.Ou
UU.J-.
9u . aa
°1. fJ
J6. V3. ;?
111. id
119. •i^.
85. 72
U6.J7
74. II
56. jj
60. 1 *
55. -> j
\.jl. n
1411. j.
Itb. I L
1
7.17
).<>
).'!
ia.70
112.26
•).U
2 o. u 7
JJ. 14
•i^. It
Jd.oO
Jd.oU
VI. 43
72.^7
t-f.9a
30.39
lt.2d
du.dO
-»j.79
J1.24
j-> .J I
l'J.u2
Is7. Od
J3.B7
11V.7B
/U.f2
47.o(j
it. 67
11J.77
1U6. 73
Ml. 25
l'J2. lo
LLG.oO
ou • 64
TO. 22
ja. j i
72. JO
t)u.0i
11. 1. )2
>/ .77
1 J j.22
j7 . 17
I.I i. .11
/^.od
73 . 'J (
u ;. . i
t
,1i> . 7 J
J .0
> J.t-1
I .7.07
J6. 72
•1.0
u9. t j
12*.-)0
&Z.35
3>. 1>)
^t.27
53.^3
34.19
39.02
12.29
lil. 72
54 .0 J
jrt.4b
47.73
^1.37
63.02
).0
147.25
110.72
•0.97
1 H.03
139 ,9i
111.93
127.37
9a.j3
JV.bO
Jt.ll/
lOj.94
12b.l1l
127.
-------
Wisconsin Power S Light Co.
Co.lumbla t\
BIASED FIRING OPERATION STUDY
WATERWALL ABSORPTION RATES. kW/re
C-E Power Systems
Field Testing and
Performance Results
TEST
T/C «
to
o
u>
5
46
47
48
f9
50
51
52
53
54
55
5ii
57
3d
55
60
61
62
63
64
65
66
67
68
69
70
71
12
73
74
75
7o
71
T 9
la
79
80
Bl
82
93
64
Bj
36
87
??,
1
71.00
88.39
J3.d7
105.74
162. 04
144.o9
179.3b
57.06
65.26
105.42
0.0
169.98
194.61
94.19
SO. 72
83.41
108.07
74.29
91.63
48.71
67.83
146.36
0.0
0.0
73.36
87.04
149.15
106.22
52.40
0.0
93.23
d2.27
• Q t Q
OO • 7 7
H4.02
78.03
128.26
96.29
104.51
102.03
129.49
10J.91
104. U3
7 b. 3^
2
o2.u t
il.ji
c)9. > ^
t>6. -' J
113.26
202. i f
170.0-.
79. jj
77. jl
39. od
3.0
12H. ,1 j
143. aj
102. 1/
u4.0*
93.2*
99. Ji
53. II
95. uJ
BB.Vl
97. »J
!5b.dJ
0.0
0.0
I27.o2
94. f t
I 70. 23
120.32
34.ol
0.0
114. Vi
94. >i
72*.J-»
106.42
94.2 -t
103. tt
UV.JJ
142. y7
1 >5.2J
) I . d .1
72. Jj
3
r>.*2
111. .12
lu'.oO
J/.J 3
U3.3 y
Jo.^lp
Ut.-tO
lJj.2?
o2. J v
lid. Ob
O..J
u.o.
I »>.70
Jo .o-V
jd.uO
Jl. Jti
7 4 . i) 'J
43.15
-» d . 5 9
Ijl.ud
-3.10
jt .O4
71. 2d
0.0
111.51
Jl .30
1 J 7. 8 j
lid. d2
Ji.94
0.0
7o.oO
0.0
Jj.bu
JO. J 7
lit). 70
12 J . 1 1
12'). 75
•1*1 .iVy
/•*•:> /
1J J. id
llj. 7u
1 I » . > ')
-t
1 •» b . 4 V
7
102.56
169.23
156.45
124. 4d
153.44
29.54
43.09
19.70
135.17
IJ7. 91
0.0
53.37
53.37
34.32
86.43
59.08
92. U2
78.21
66.37
97.37
127.51
126.60
0.0
0.0
0.0
149.51
210.64
180.55
127.60
0.0
150.24
168.50
141 11
L 1 L . I 1
116.45
152.43
206. 2o
154.26
151.52
0.0
129. Ob
164.60
16B.31
141.84
d
54.93
ti-V .98
70.40
34.93
13d. 63
82.03
103.01
96.54
56.54
121.27
0.0
142.24
129.45
103.88
54.08
54.99
90.52
54.99
60. 82
40.55
84.19
67. 7B
0.0
0.0
0.0
76.11
105.30
97.09
153.70
U.O
91.45
84.16
01 45
O L . ^ t
62.29
116.51
llf.68
62.74
92.78
0.0
89.54
77.68
73.1i
74.O4
iJloo
9
111.70
130.04
137.35
103.56
108.81
112.46
123.42
86.91
53.22
93.29
0.0
89.69
96.06
63.25
35.44
37.25
0.0
131.09
111.00
51.78
102.82
0.0
0.0
0.0
0.0
45.55
69.18
93.80
69.18
0.0
164.86
58.10
RT i a
J 1 . L O
32.73
220.88
233.64
136.95
162.52
0.0
154.70
156.52
lea. 39
1 31. d7
1O2. 6b
10
53.17
150.76
145.28
45.91
153.76
49.32
162.41
88.46
36.65
107.62
0.0
35.71
42.04
29.41
63.25
45.08
75.09
55.97
10.23
76.96
83.35
98.86
0.0
0.0
0.0
134.59
180.24
178.41
119.98
0.0
158.17
160.00
43.29
226.06
257.01
153.09
125.70
0.0
159.89
129.76
141.63
127. O2
121. ±>4
11
59.74
81.62
87.71
95.01
156.19
137.93
158.62
50.33
63.68
90.44
0.0
134.57
177.16
104.12
84.23
81.79
96.40
72.06
87.87
44.69
62. 88
133.48
0.0
0.0
69.92
82.09
133.23
110.09
52.92
0.0
84.01
81.58
fLQ A?
O » *^C
45.15
84.04
130.31
101.08
104.73
101.08
118.15
103.54
109.63
75.54
6S.8.2
12
141.17
62.65
74.51
70.86
41.42
123.49
150.89
86.96
99.74
82.39
0.0
117.74
143.31
84.86
29.56
35.89
72.27
67.71
92.35
145.25
46.70
136.12
0.0
0.0
135.26
88.68
108.77
80.46
18.78
0.0
76.60
0.0
32^05
55.05
225.66
69.62
184.65
167.32
71.77
71.77
99.15
136.60
149. 38
13
0.0
76.85
88.71
128.90
113.96
113.96
113.04
79.26
78.35
124.92
0.0
0.0
129.22
63.49
66.41
61.85
111.14
57.30
95.61
128.42
14.79
72.72
0.0
0.0
154.04
45.45
128.47
119.34
42.73
0.0
60.71
0.0
on 7 7
ou • • f
58.89
70.14
166.93
134.97
166.93
90.22
133.47
158.12
126.16
113.37
122. SI
14
41.76
155.76
142.97
126.54
167.35
141.79
111.65
27.95
46.93
123.52
0.0
120.22
141.23
103.78
68.43
48.42
164.30
79.38
126.86
37.52
123.18
121.36
0.0
0.0
0.0
183.52
83.09
111.40
89.48
0.0
168.73
193.37
57^39
72.32
262.92
198.28
164.53
0.0
149.37
182.23
194.08
147.54
129.SB
15
31.71
48.60
67.09
33.52
13.63
107.88
20.71
40.49
89.62
24.28
0.0
0.0
88.08
38.94
6.32
99.30
151.35
89.26
47.36
130.34
114.81
112.99
0.0
0.0
0.0
91.16
161.55
148.70
107.60
0.0
131.16
0.0
moo
.70
93.72
230.95
206.36
154.36
127.87
0.0
47.09
115.45
51.63
Z15. 45
103.50
-------
Wlicons In power & Light Co. C.E VoMr sv»««m»
Columbia t\ F\e\a Tutlng «nd
Performance Results
BIASED FIRING OPERATION STUDY
MM-ERWM.L ABSOHrnOM HATES. kW/m2
Te«T I 2 1 4 5 6 7 B 9 10 11 12 13 14 15
T/C » 91 115.46 121.j, lav.79 12J.37 146.13 152.52 132.43 112.14 120.68 135.93 108.70 108.87 82.00 146.35 109.71
92 93.54 IDS.ji. 107.Oi UU.9* 134.26 l<<7.05 140.65 133.14 123.42 124.97 84.33 87.87 122.18 137.22 103.32
u>
S
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
Ho
99.94
78.94
0.0
129. Od
211.12
118.10
100.53
126.43
0.0
143.39
0.0
BB.BO
97.00
O.O
35.09
0.0
112.45
0.0
87.91
H4.31
103.27
63.44
59.21
08.91
114.03
87. ij
n.o
133. in
64. Jd
125.19
1)3. J 7
135. uj
141. /a
HI. jy
0.0
113. 3f
107. 71
O.i)
t)9. 3 J
:> .0
lll.Vi
0.0
90. U
77. /U
105. U
(. 1 . t'J
52. -JJ
90. ,!V
Ij2. 7 1
a i . 3 3
<> .1)
127.06
43 .19
47.31
3J.4u
UJ.t4
111.94
HJ.Oi
o.o
JJ.97
I2:>.b7
U.O
>4. 36
J .U
JO. 30
U.O
tt. ittl
7 4 .3 j
J y .28
J 1 . jl
d7.20
110.70
14u.47
122. 72
0.0
127.17
-si .1 *
121 .6d
12). 03
134.67
78.24
12d.90
o.n
102.61
143.4 1
U.O
119.31
1) .0
7S.37
0.4
jl.42
jJ.ul
ltd. 3 7
3d. «2
>2.7J
11G.3'
139.74
111.43
0.0
162.22
148.52
0.0
96.36
145.13
130.86
103.66
0.0
86.11
113.05
0.0
o!o
69.76
0.0
123.86
0.0
62.62
143.30
151. d8
97. 73
138.83
129.69
0.0
174.09
167.68
0.0
101.84
159.73
145.49
123.70
0.0
99.90
128. OB
0.0
116.81
0.0
84.35
0.0
123. d6
0.0
56.24
149.69
10B.U5
106. B6
134.26
130.61
0.0
100.12
174.99
0.0
194.96
150.60
87.04
121.19
0.0
83.60
95.51
0.0
82.35
0.0
36.13
0.0
57.25
0.0
158.46
162.47
116.26
104.12
77.47
54.72
0.0
105.12
86.92
0.0
86.89
95.51
0.0
92.28
0.0
77.86
97.29
0.0
100.42
0.0
92.93
0.0
103.83
0.0
ad. 72
67.23
51.30
53.36
127.08
103.33
0.0
128.35
71.80
0,0
61.73
178.94
143.74
0.0
0.0
65.54
0.0
0.0
0.0
0.0
55.07
84.52
60.87
0.0
0.0
157.04
126.39
92.38
145.98
103.06
0.0
78.74
101.60
0.0
153.60
178.65
151.68
36.59
0.0
21.68
35.97
0.0
34.72
0.0
23.14
0.0
104.33
0.0
59.62
179.56
124.28
120.41
91.65
74.62
0.0
114.67
140.78
118.62
101.06
118.13
121.80
98.21
0.0
82.34
92.36
0.0
82.34
0.0
88.29
0.0
115.21
89.39
96.18
64.58
56.10
63.68
149.06
79.66
0.0
143.50
66.72
76.81
72.04
108.88
133.86
91.22
0.0
114.40
124.41
0.0
123.16
0.0
84.86
0.0
107.80
106.94
170.65
101.57
56.28
106.13
155.97
101.17
0.0
133.06
103.76
170.47
75.29
88.39
95.10
126.65
0.0
99.72
147.28
0.0
170.38
0.0
61.67
0.0
36.33
78.24
38.90
146.84
127.07
107.56
133.57
124.43
0.0
137.82
124.10
0.0
96.59
107.00
104.62
81.24
0.0
59.94
86.88
0.0
83.12
0.0
93.73
0.0
116.79
0.0
67.40
128.00
120.14
104.34
124.32
145.32
0.0
169.61
132.17
0.0
67.27
55.80
47.09
10.74
0.0
51.73
74.28
0.0
71.78
0.0
44.37
0.0
49.17
0.0
66.36
106.87
as. 33
82.32
-------
Wisconsin Power & Light Co.
Columbia 11
BIASED FIRING OPERATION STUDY
C-E Power Systems
Field Testing and
Performance Results
UATERUAIL ABSORPTION RATES. kW/m*
TEST
T/C *
16
17
to
5
o>
.-»
1
2
3
4
5
6
7
U
9
10
11
12
13
14
Ib
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39.
40
41
42
43
4
11.04
0.0
0.0
55.0o
45.99
3l.U
65.11
6b.rf/
38.74
0.0
45.lt
71.30
110.73
72.40
74.^3
48. To
89.73
0.0
0.0
134.94
72. S3
98.1)7
0.0
0.0
51. 4a
•79.oo
103.34
90.61
92.43
5U.72
124.34
84. .>*
78. 2o
104.71
34. uJ
66. tl
79.17
0.0
M5.0 }
t r. ^d
1 1 '. . <: u
2j.i3
0.0
0.0
4/.JO
21.06
0.0
0 .0
J/.49
72.04
92.04
4a.60
36.o4
34.84
0.0
87.01
J9.49
124.61
V7.65
dJ.OS
JO. 31
t J.73
993.17
1>7.16
295 .56
134.29
148.90
133.77
0.0
126.32
190.96
213.34
Iul.j2
1*2.39
132.30
104.00
171.06
loO.lO
201. la
134.94
1^4.62
l-*4.9d
•J.O
lu^ . J<«
n «; . •. i
i . < . r i
TFFT
T/C *
16
17
46
47
48
49
50
51
52
53
54
55
56
57
5t)
59
60
61
62
63
64
65
66
67
63
69
70
71
72
73
74
7b
76
77
78
79
ao
81
82
83
84
85
Bo
37
8tl
B-J
129.05
1 JO. *3
in !»-o A
35. Oi
75. Y3
66. dj
47. 7 j
134. 13
69. 3.5
93.9o
51.17
54. di)
40.30
0.0
12B.ol
125.8o
88.43
49.01
52.33
91.30
59.60
55. *7
46. Ut
79.70
61.4e»
0.0
0.0
0.0
76. Id
100.81
89.83
36.22
0.0
90.61
76.93
76. 9J
58. 72
108. Jo
108. 3u
80.03
33.7.2
O.I)
82.31
08* \jy
02.^7
03. 14
a o . d I
~r 'i _ j /
:M).15
Ud.uO
123.99
31.06
lul.16
46.31
ljO.25
dtf.17
43.60
100.03
0.0
39.03
43.55
32.71
62.95
44.79
7S.70
53.86
12.55
66.64
76.67
94.00
0.0
0.0
0.0
1^1.51
16o.2S
I7o.29
U3.33
0.0
144.10
192.39
124.09
3
1 j j _ .* 1
TEST
T/C « 91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
115
116
16
11B. 43
125.74
136.70
146.44
0.0
104.70
171.04
0.0
178.85
109.51
70.63
•129.12
0.0
53.95
75.67
0.0
49.78
0.0
3F.25
0.0
53.01
0.0
131.37
141.17
82.79
, 96.51
17
109. td
116.78
43. *2
49.39
0.0
99.71
87.91
0.0
90.61
95.59
117.91
86. 0*
0.0
64.7a
86.69
0.0
87.31
0.0
89.34
0.0
113.46
0.0
87.87
68.23
54.10
55.71
18
127.42
124.u8
141.12
06.30
0.0
79.35
101.30
0.0
162.44
Id2.01
157.77
35.77
0.0
17. T8
38. «9
0.0
35.15
0.0
22.85
0.0
39.4J
0.0
59.33
157.37
125.81
113.72
-------
HI icon*In Power 5 Light Co.
Columbl. /I
C-E Povnr Vy»««w
Flald luting and
Perfonune* tasulu
OVERFIRE AIR OPERATION STUDY
Tf ST
T/C j
to
o>
1
2
i
4
5
6
7
3
•i
in
n
12
12
14
15
la
17
18
19
20
21
22
23
24
25
2a
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
45
44
45
1
72.87
0.0
114.87
141.30
62.90
0.0
115.78
94. 90
29.43
24.93
dl.26
20.46
87.65
77.ol
130.51
6.33
K^.31
43. US
89.41
69.33
28.47
148.83
19.33
138.78
50.26
0.0
59.30
0.0
19.35
55.51
108.43
111.17
91.08
142.23
101.12
oJ.12
77.71
95.05
110.58
7J.13
91.40
107.1)4
57.93
dl.bd
110.29
?
70.2.J
II. 0
129. 9J
41.19
92. U
(l.'J
115. J2
V2.Vd
29. jy
29. oy
•33.2 +
H.12
91. 7u
•*5.tl
142.24
10.22
64* J.!
32. l-i
93. J2
74. OJ
38. (47
L!>6.oO
26. JJ
146. do
56. 1)
88. tl
52.13
O.U
23.0V
59.^3
103.72
115. y.)
97. oJ
139.0+
95.20
o4. J.)
30. ol
9 6. •» +
Lit. 70
72. 11
•>3.22
Db.oi
36.33
) > . lJ
Ml. JJ
3
0.0
0.'.)
O.II
100. 11
'to. 00
()« '1
0.0
0.0
0.14
J7. 33
2.dJ
j7 .32
6d.26
3t .34
122.04
10 3 . !>Q
7V. 12
2 7.31
70. yi
7J.21
51. 73
122 .09
179 .ol
li 7.02
63. +9
0.0
O.U
0.0
2»6. H
102 .6')
I') 7. 26
134.0^
109.09
IU.22
77.U
u j . i 3
32 .Oil
1 • J . u 7
ua .0 2
12V.+J
Ha. 10
JJ. 19
1+3. Jl
1 J J . J •>
JJ.2 4
•t
7. 7t
0 .0
11.22
77.27
J3. 1<)
!).4.33
lib. Ill
120.94
Id4.fl4
191.23
7
-------
Wisconsin Power & Light Co.
Columbia II
OVERFIRE AIR OPERATION STUDY
WATERWALL ABSORPTION RATES, kW/ni
C-E Power Systems
Field Testing and
Performance Results
11
12
13
15
T/C
40
47
48
4')
50
il
52
53
54
55
56
57
515
54
60
61
62
63
64
63
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
93
84
85
86
S7
d8
B'l
qi»
•jl.o2
70.94
110.3 i
67.09
39. *y
31. 3o
90.19
38.57
61.3M
93.23
0.0
0.0
141.30
73. 7b
13.34
78.53
dl.2o
32.14
104.09
145.12
112.24
52.03
0.0
0.0
175.29
52.08
129. bo
97.68
52.13
0.0
80.13
0.0
90.17
57.33
90.4V
134.42
85.01
135.24
102.27
66.00
112.73
lll.bl
IO1.77
d U • 7 7
i i . il t
114. 22
59. -.7
0.0
O.'J
ISS.dO
50. 7i
132. 23
UI4.2J
146. Jo
n.o
81.61
0.0
<)•*.£>)
63. af
a9.13
159. 7u
«4. 2o
137.04
104. 4j
7'l. il
111.37
112.2*
I0o . j-r
3 I. a J
Jo.oZ
Jl .-ft
J'J.J i
117. >;
J2.24
n. LI
j j . j j
-i. 77
Q.'J
ij .LJ
22.06
J.I
U..)
111.')')
bl.fO
30.41
77. iii
1J2. 3d
12J.30
1 •> ,i4
1JJ.J1
122.04
133. /'t
O.U
0.0
14.1. 3d
11 J.u9
Idu.'JO
lit .69
134.53
a.o
r-».^9
0.0
fJ.d7
it*, ri
Iju.d^
iOa .00
2 J.Jb
JO. 22
3 1 . a 9
J.O
tu. r^
o3. Id
J2.24
i -» • 2 U
I L.-.Z
// .3.
1 ) » . 9 1
117. •);
•»7. ?o
122. 2*
U j « J-t
•>.O
13.0-1
20. Jj
13.25
U.I)
O.'l
I La. 'Jt
3d. 12
i->.H
7f ,4»
120. Ju
1 09 . 40
110.71
129.42
117.34
l j-t.31;
O.I)
0.0
143.40
63. 7j
1 43 . 90
133.03
83. «0
0.0
u3.i)/
0.0
uU.07
J3.3d
. f 0 . 2 1
71.12
36.30
63. >9
26. JJ
r-j.03
33.97
73. 2o
^0.3-)
li . > j
u3.u >
ot.13
112.20
l'J5.9l>
57.43
134.71
0.0
0.
-------
Wisconsin Po»v«r
Columbia /I
C-E Povrar Sy»xwm»
Field T««t\ng Mid
Performance Reiu\ti
OVERFIRE AIR OPERATION STUDY
WATERUftLL ABSORPTION RATES, kW/m
17 ST
t/C * 91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
ins
109
110
111
112
113
114
lib
1 16
1
129. 7o
12o.ll
155.33
142.53
0.0
117.79
76.62
319. dd
32.8O
98.70
91.72
153.72
0.0
106.80
134.34
0.0
141.85
0.0
59.19
0.0
54.76
62.10
o4.6,2
34.O2
62.53
111. 49
2
12'J.OJ
122. 61
145. tj
129.63
II. 0
116.12
67. il
in/«.d»
do.vtj
100. li
90. 3f
143.42
0.0
93.33
165.91
0.0
171.13
O.'J
uO. -jj
n.u
53. JJ
O2.t>o
o4« / J
5 1 . 3 f
t>4. o j
Ho.^j.
3
33.77
« I .0 I
0.')
Jo .31
<).<)
1 i 'J . 3 (J
iO. '-i'l
j-i.il
J 3.0 J
131.3.;
im. 71
3<: .09
0.0
i. U 1
33.34
•J.'i
o4 . u 2
J.O
t J.d 7
0.0
-la .3^
7 y • I 7
* y .^5
1 3 J . j 4
llJ .d5
11^. 12
<•
jO.lt,
-»j .0«d
H. 0
Jl.23
O.D
101. id
07.23
2d 7.03
J) .0 j
129.5o
116.17
37.13
0 .0
If. 14
lOV.lo
o.n
Li!J . 3 J
U.U
03. J J
0.1)
23 .Jj
y 1 . i')
6 1 .V 1
12-t.O i
L Lit .(Id
I 1 1) . 3 0
5
3.0
57.12
93.60
dl.73
0.0
112.73
46.06
n.o
63.19
149.33
109.46
76.98
0.0
60.69
105.80
0.0
113.32
0 . n
58. 70
0.0
33.37
107.21
128. ¥2
LU.03
113.69
6
144.35
133.39
43.99
178.12
0.0
149.82
153.38
70.02
113.93
158.07
127.33
139.32
0.0
119.30
138.69
n.o
144.94
0.0
58.36
0.0
103.14
106. 04
135.85
149.86
1 Ij6.bc,
116.03
7
47.62
55.81
0.0
123. 3*
0.0
127.90 -
144.25
93.14
99.32
144.38
122.77
76.08
0.0
36.63
01.71
0.0
99.89
0.0
43.34
0.0
7d.49
90.40
lU9.3u
143.47
122. 17
110.55
t)
37.19
31.77
0.0
94.57
0.0
99.10
112.71
53.00
86.97
143.91
117.74
70.75
0.0
23.85
57.59
0.0
58.22
0.0
43.31
0.0
56. 13
77.15
94.28
ltt.82
140.57
121.06
9
7.30
52.07
83.05
112.27
0.0
90.16
135.77
141.32
109.15
155.15
81.53
27.23
0.0
11.78
91.68
17.31
97.95
0.0
47.11
0.0
27.37
68.28
145.69
83.49
79. 7U
35.75
10
0.0
41.24
79.45
89.49
0.0
91.99
136.70
145.00
119.23
117.74
84.31
25.41
0.0
16174
71.04
0.0
61.64
0.0
50.74
0.0
26.50
69.22
132.01
80.31
77.01
60.31
11
51.80
50.59
94.34
97.99
0.0
101.38
133.62
151.65
142.63
106.14
86.71
0.0
0.0
0.0
44.94
0.0
29.13
0.0
54.33
0.0
33.98
59.16
124.37
67.21
75.76
55.44
12
174.77
162.36
198.12
168.20
0.0
163.05
113.65
223.36
196.36
236.20
171.09
0.0
0.0
100.10
0.0
0.0
0.0
0.0
74.12
126.52
66.18
107.30
0.0
159.64
95.84
122.18
13
160.85
145.33
175.45
169.98
0.0
146.23
122.39
222.78
194.32
253.81
179.44
0.0
0.0
159.98
0.0
0.0
0.0
0.0
68.44
121.57
72.17
103.25
0.0
147.18
92.69
122.50
14
180.73
181.64
206.26
157.00
0.0
151.51
97.53
111.28
202.33
226.32
173.77
0.0
0.0
109.20
0.0
0.0
0.0
0.0
70.07
91.23
54.66
99.40
0.0
190.79
89.76
114.99
15
27.82
14.43
0.0
66.84
0.0
51.23
113.20
538.57
66.50
76.85
83.57
19.90 i
0.0
66.12
23.00
119.37
54.85
0.0
104.86
0.0
94.02
104.13
79.27
86.90
75.36
106.08
-------
Wisconsin Power & Light Co.
Columbia II
C-E Power System*
Field Testing and
Performance Results
OVERFIRE AIR OPERATION STUDY
AlSBUfTIOM PATEI,
TEST
T/C »
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
2f>
Z-i
30
31
32
33
;-4
35
it
?7
3d
39
41!
41
42
41
44
45
16
0.0
0.0
0.0
0.0
64.11
0.0
78.70
0.0
19.89
20.79
88.92
92.57
77.05
77.05
43.27
0.0
U.O
46. 00
79.71
85.18
97.97
0.0
145.51
0.0
0.0
129. Vd
I o3.!>9
0.0
152. uQ
151.69
o.n
62.21
72.24
72.24
72.24
U2.82
172.08
10*. *9
ltf.13
V3.i5
9- .81
17'J.33
1M4.28
22^.26
1*3.37
17
0.0
0.0
ol. J7
0.0
•y7.i>
0.0
107.3d
0.0
22. Ui
42. 2u
45.40
63. 3 J
63. J 7
67.0.:
14. td
n.u
151. Jl
Iul.o2
no. iu
100. la
53.43
154. tj
142. il<
n.o
O.J
34.32
V5.iid
n.o
1511. 11
176. a
222. 2a
ti'l.^i
od. ^1
152.^3
•jtl.-i-t
47.u«l
122. Jj
1?5. 20
143. I-J
122.0,.
I'U.JJ
Ij4. ti
215.2-.
106. Jd
91. i^
' 13
0.0
0.0
0.0
0.0
03 .32
0.0
30. JO
o.o
17.49
23.75
41.82
8*. 21
30.08
7V. 17
'•9.00
0.0
0.0
•»•*. 46
>12.73
U2.o2
J0.y4
0.0
179. 3u
II. J
0.0
119.30
1)0.50
'J .0
154.27
171.13
0.0
o-i. Jl
(lZ .TV
J7.D5
dd.03
1-.-..1U
l7t . 1 7
HT. d2
l3>. <2
a-,.o»
vi. ou
172. J5
1 jy. ^s
<^21. Jfl
^Ol.dt
19
0.0
0.0
60.27
0.0
109.56
0.0
138.79
0.0
30.48
70.47
43.16
d3.24
51.34
86.90
13.40
0.0
0.0
159.88
154.40
3l.2»
71.3')
0.0
13d. 01
0.0
O.O
Ui}.~>'<
177.20
O.D
33.37
I6o.0 >
,1.0
7-,, 78
136.4 7
153.32
148. 73
163.67
54.13
146.32
t j.8b
loo .11
164.13
ls-«.5-t
175.83
lo5.Ud
1J2. 12
20
0.0
0.0
72.09
0.0
97.65
0.0
124.14
0.0
25.93
43.12
44.94
65.87
60.40
55.85
17.79
0.0
0.0
99.55
134.26
107.77
54.85
106.30
105.99
0.0
0.0
129.74
173.56
0.0
87.51
•115.82
0.0
71.08
70. 17
123.87
114.00
52.26
96.95
79. bO
125.27
120.70
106.08
135.31
144.32
132.88
i»o«23
21
0.0
0.0
0.0
0.0
41.54
0.0
58.80
0.0
98.26
71.80
11.32
38.16
75.45
0.0
3.66
0.0
0.0
39.04
90. 94
106.46
70.87
16.68
122.06
0.0
0.0
130.29
160.42
0.0
115.48
145.62
0.0
143.80
158.41
39.85
33.32
143.24
79.32
26.67
124.06
129.54
130.45
0.0
129.90
128.98
125.33
22
0.0
0.0
0.0
0.0
65.40
0.0
83.64
0.0
13.08
32.97
40.21
62.92
29.37
0.0
3.91
0.0
0.0
101.22
108.53
84.79
79.32
224.50
151.54
0.0
0.0
45.79
0.0
0.0
116.65
151.35
0.0
67.37
116.65
129.44
98.39
67.73
29.64
41.38
27.84
118.84
116.10
0.0
115.55
73.57
94.55
£3
0.0
0.0
0.0
0.0
55.97
0.0
73.27
0.0
112.82
86.35
25.55
52.65
90.00
0.0
17.58
0.0
0.0
53.60
105.55
121.08
85.47
31.09
13o.72
0.0
0.0
144.94
173.06
0.0
130.16
160.29
0.0
158.47
173.07
54.46
43.10
157.95
94.03
41.25
13d .78
14-.. 25
143.17
0.0
144.66
143.74
llJ.09
24
0.0
0.0
10.69
0.0
78.34
0.0
96.59
0.0
27.85
45.90
53.16
75.92
42.28
0.0
14.55
0.0
0.0
114.29
121.59
97.86
92.38
237.56
164.63
0.0
0.0
98.88
0.0
0.0
129.77
164 ,4o
o.n
80.47
129.77
142.55
111.50
80.87
42.68
54.47
40.87
131.99
1^.25
o.n
128.74
80.75
107. 74
216
SHEET A33
-------
Wisconsin Power S Light Co.
Columbia II
C-E Power Systems
Field Testing and
Performance Results
TFST
T/C •
OVERFIRE AIR OPERATION
STUDY
MTtmttll AISMPTIOH RATES, kU/«2
46
47
48
49
5(1
51
52
53
54
55
5o
57
58
59
60
61
62
65
t4
o5
66
67
68
69
70.
71
72
7J
74
75
76
77
7U
79
80
HI
82
rfj
8t
65
H6
117
lid
167. d3
163.49
155. tl
18
161.71
17u.51
193.64
167.19
155.89
Io6.85
Id2.36
113.88
129.41
lid. 45
0.0
7t«44
do. 30
60.76
•Jo .51
30.06
0.0
!<)•». 73
dl.90
jO.62
111.95
0.0
0.0
0.0
14il.44
U7.52
2id. 77
242.41
17* .ju
J.O
ldd.46
ft. J4
199 .40
93.34
278. d6
m. 47
131.27
22o.l2
191.30
21.-. 77
19 a .2n
110.57
1 J0.*0
loo. 14
19
141.16.
156.68
158.51
138.42
140.83
140.83
109.77
110.69
152.70
137.17
0.0
107.73
124.17
83.07
34.10
43.16
0.0
Jo.03
75.94
27.70
55. Jl
0.0
O.O
0.0
o3.14
40.7.,
SO.* 7
36. do
62.30
o.o
146.93
o2.9 J
64.75
79.34
260.23
242.04
209.27
Jo .90
130.60
103.07
191.35
207. 7»
17-J.90
l5J. Ill
155.44
20
111.87
131.06
169.40
158.45
181.84
96.92
177.27
45.88
46.78
138.03
O.O
105.87
138.75
97.65
36.77
37.68
54.94
59.49
165.39
27.65
53.03
0.0
0.0
0.0
117.87
157.13
141.61
114.21
144.35
0.0
96.64
UJ2.12
111.08
77.41
64.10
191.90
134.40
103.34
130.75
59.85
110.9o
138.56
163.01
177.ol
57.70
21
79.68
97.02
120.76
110.71
94.91
91.26
97.65
60.26
74.84
73.93
0.0
75.20
63.82
43.35
22.85
15.72
0.0
113.79
90.96
22.63
23.73
O.c
0.0
0.0
0.0
36.41
66.39
106.61
127.55
o.n
137.40
5l.6t
46.19
20.05
197.99
214.40
144.15
127.71
0.0
150.90
134.46
150.90
118.94
SB. 30
94.00
22
78. 13
95.46
1 1 1 . 90
101.86
53.27
45. 10
46.01
54. Id
95.19
44.20
0.0
73.60
B4.5'3
52. 60
20.41
30.27
108. 5t
71.12
62.01
12.32
40.20
0.0
0.0
0.0
o.o
30.35
63.91
75. 7o
66.70
0.0
144.90
44.04
47.36
77.40
130.71
54.99
145.33
7b.o7
0.0
133.82
142.95
1*6.60
102.77
77.21
71.47
„
94.43
111.78
135.52
125.48
109.72
10o.07
112.40
75.05
89.64
Ud.7;
0.0
8V. 69
83.30
J7.79
37.25
30.03
0.0
I2d.35
105.52
37.29
3d. 19
0.0
J.O
o.o
0.0
50.99
dl.03
181.45
142.20
0.0
152.UL
6t>. 28
60.82
34.5:
212.68
229.08
158.80
!<.<;.•.->
0.0
165.65
149.22
Io5.o5
13J.70
103. So
lOd.61
24
"> 1 . 3 I
103. 65
125.09
115.04
66.48
58.29
59.20
67.:-?
108.43
57.56
0.0
bo.55
97.50
65.56
33.24
43. IB
121.56
84.12
75.01
26.11
53.21
0.0
0.0
n.O
0.0
43.35
70.99
8H.85
99. BO
a.o
158.07
57.71
60.44
90.il
143.86
td.12
158. *7
vL.e2
'j.n
147. ri
156.1'.
159.79
115. 96
90.4(i
64.71'
217
SHEET A34
-------
Wisconsin Power 6 Light Co.
Columbia fl
C-E Power Systems
Field Testing and
Performance Results
OVERFIRE AIR OPERATION STUDY
UATEB»IL ABSORPTION KATES. kW/B
TFST
T/C •
16
17
ia
it
20
21
22
23
24
91
92
Oi
04
vv
>16
97
98
..>
lol.2u
nto
O.U
103. *(
o.u
O.U
n.u
n.o
64. /J
76. cJ
lOI'.lj
loO.oV
".u
186.31
I"i-.u2
116.73
1V7.J6
173.23
lVu.03
iaa.09
U.U
4v.3C
101.2/
411.46
194. o7
2U7.UO
1V4.55
U.O
U.O
Uo .40
'>.0
U.U
u.n
U.:l
4U .02
1U1. J-5
<5.3/
17-1.^9
O.U
Jll.b 5
i n, us
131. ID
136.46
I8u.4fe
191.93
171.87
O.Q
60.82
139. 7i
1 4 1 .
-------
POWER t LIGHT Co.
COLUMB
C-E POWER SYSTEMS
FIELD TESTING »NO
PERFORMANCE; RESULTS
BASELINE OPERATION STUDY
BOARD & COWVTER DATA
«C
C
C
C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
•B
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE 1976
TIME
LOAD MW
FLOWS - lO^B/HR
FEEDWATER
SUPERHEAT SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY L
REHEAT SPRAY R
BFP TURB. EXTR. STH. FLOW 1-A
BFP TUHB. EXTR. STH. FLOW 1-B
BFP Time. MN. STH. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM & WATER - PSIG
FEEDWATER TO ECON.
BOILER DRUH
TURBINE THROTTLE
TURBINE IST STAGE
HP HTR. 1-G1 & 1-G2 STCAH IN.
AIR & GAS - IN HgO
FD FAN 1-A DISCHARGE
FD FAH 1-B DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURH. LEFT WINDBOX
RT. WDBX TO FURN. DIFF. P
LEFT WDBX TO FURN. DIFF. P
FURNACE
PHI. SH GAS OUT.
REHEATER GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCH.
IDF 1-B DISCH.
PAF 1-A DISCH. HOB.
PAF 1-B DISCH. HOR.
PRI . HOT AIR DUCT
TEWERATURES
AIR & GAS - °F
1-A FD FAN DISCH.
1-B FD FAN DISCH.
1-A AH AIR IN.
1-B AH AIR IN.
1-A AH AIR OUT.
1-B AH AIR OUT.
1-A AH GAS IN.
1-B AH GAS IN.
1-A AH GAS OUT.
1-B AH GAS OUT.
1
3/10
09:45
524
3170
107
130
57
75
0
0
7.4
1626
1585
2735
2682
2399
1666
539
5.67
9.13
7.72
7.24
3.68
3.50
2.22
2.25
3.22
4.03
-.51
-.83
-.66
-2.58
-6.46
-8.62
-8.56
-15.5
-14.2
-.51
-.46
32.92
32.67
30
51
60
77
78
696
712
760
759
272
27S
2
3/OB
14:00
524
3338
24
64
39
60
0
0
7.8
1606
1560
2751
2691
2400
1682
536
5.63
8.68
7.50
6.86
3.51
3.50
2.12
2.20
3.18
3.90
-.50
-.73
-.61
-2.34
-6.34
-8.25
-8.43
-14!o
-.55
— 48
32.87
32.77
30
41
52
83
88
668
686
730
732
258
265
3
3/15
15:35
483
2996
74
80
50
59
0
0
7.0
1612
1593
2698
2654
2406
1520
492
5.87
9.61
8.21
7.61
3.93
3.93
2.49
2.47
3.65
4.13
-.60
-.64
-.56
-2.49
-6.42
-8.87
-8.65
-15.6
-14.6
-.48
-.47
32.64
32.58
30
46
57
82
87
684
702
750
751
265
267
4
3/13
10:00
399
2412
6
68
10
0
0
0
7.4
1298
1284
2620
2586
2399
1242
391
4.35
6.79
5.84
5.46
3.04
2.95
2.28
2.34
3.16
3.82
-.39
-.53
-.19
-1.79
-4.49
-6.36
-6.24
-11.2
-10.2
-1.07
-2.15
32.47
32.29
30
41
50
107
112
627
630
682
676
253
246
5
5/23
12:35
324
1974
0
35
0
0
44
34
15.0
864
919
2566
2538
2406
987
310
8.70
7.76
7.29
6.74
5.66
5.56
4.97
4.97
6.19
6.68
-.66
-51
-.78
-1.20
-2.70
-3.99
-4.13
-6.76
-6.41
-.77
-.88
31.56
32.28
30
77
f f
83
102
105
565
576
612
608
241
242
6
5/23
14:30
323
1987
0
34
0
0
44
34
15.1
950
1023
2568
2541
2405
987
310
9.35
8.23
7.73
7.08
5.67
5.51
5.04
5.07
6.21
6.79
-.54
-.50
-.77
-1.29
-3.00
-4.12
-4.25
-7.30
-6.98
-.66
-.76
31.54
32.23
30
•J-T
84
104
107
57?
584
622
516
240
7
5/23
16:20
322
1967
3
42
0
0
44
34
14.9
1017
1088
2573
2544
2403
985
309
9.77
8.59
7.98
7.32
5.85
5.71
5.04
5.04
6.20
6.72
-.57
-.53
-.84
-1.35
-3.15
-4.54
-4.63
-7.94
-7.?4
-.60
-.69
31.64
32.30
30
7fi
*o
85
103
105
576
589
624
620
243
239
8
3/10
14:00
-14
3085
1 74
K-i
69
81
0
0
7.5
1548
1506
2722
2668
2400
1618
527
5.43
8.59
7.18
6.74
3.49
3.34
2.16
2.20
3.17
3.93
-.47
-.67
-.60
-2.54
-6.04
-8.15
-8.12
-1-5.7
-13.1
-.51
-.50
32.76
32.56
30
qe
D-J
65
75
78
698
718
763
763
274
275
9
3/09
10:00
515
3134
34
110
60
77
0
0
7.3
1630
1581
2734
2679
2403
1634
529
5.82
9.41
8.01
7.43
3.74
3.83
2.41
2.38
3.40
3.98
-.48
-.72
-.55
-2.45
-6.39
-8.89
-8.37
-15.4
-14,1
-.52
-.45
32.74
32.64
30
46
58
76
80
689
703
753
753
265
274
12
3/10
16:30
482
2866
76
107
39
59 -
0
0
6.3
1555
1516
2636
2637
1446
15O1
488
5.47
8.66
7.30
6.80
3.54
3.38
2.22
2.28
?.14
3.89
-.44
-.79
-.62
-2.54
-6.00
-8.00
-8.00
-14.6
-13.3
-.54
-.49
32.89
32.55
30
SP
PC
61
77
80
693
712
757
759
270
270
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
219
SHEET A36
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA f\
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD & COMPUTER DATA
*c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
•B
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE 1976
TIME
LOAD MW
FLOWS - 10\B/HR
FEEDWATER
SUPERHEAT SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY L
REHEAT SPRAY R
BFP TURB. EXTR. STH. FLOW 1-A
BFP TURB. EXTR. STH. FLOW 1-B
BFP TURB. MN. STH. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINOBOX
PRESSURES
STEAM I WATER - PSIG
FEEDWATER TO ECON.
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STABE
HP HTR. 1-G1 & T-G2 STEAM IN.
AIR 4 GAS - IN HgO
FD FAN 1-A DISCHARGE
FD FAN 1-B DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURN. LEFT WINDBOX
RT. WDBX TO FUHN. DIFF. P
LEFT WDBX TO FURN. DIFF. P
FURNACE
PHI. SH GAS OUT.
REHEATER GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
A i R HTR . 1 -A GAS 1 N .
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCH.
IDF 1-B DISCH.
PAF 1-A DISCH. HDR.
PAF 1-B DISCH. HDR.
PR I . HOT AIR DUCT
TEMPERATURES
AIR 4 GAS - °F
1-A FD FAN DISCH.
1-B FD FAN DISCH.
1-A AH AIR IN.
1-B AH AIR IN.
1-A AH AIR OUT.
1-B AH AIR OUT.
1-A AH GAS IN.
1-B AH GAS IN.
1-A AH GAS OUT.
1-B AH GAS OUT.
11
5/21
05:00
321
1734
91
117
14
30
39
70
7.6
790
810
2547
2521
2403
966
313
6.45
5.71
5.36
4.88
4.04
3.65
3.62
3,57
4.81
5.17
-.48
-.55
-.73
-1.29
-2.48
-3.52
-3.74
-6.29
-5.90
-.94
-.91
31.66
32.72
30
72
83
96
100
590
608
641
637
247
259
12
5/25
13:00
321
1824
55
74
0
15
39
71
6.3
1190
1241
2556
2529
2405
969
311
11.58
10.01
9.08
8.25
6.43
6.31
5.40
6.12
6.54
6.96
-.61
-.58
-.94
-1.52
-3.72
-5.11
-5.20
-9.15
-8.52
-.39
-.45
31.66
32.52
30
77
82
99
102
604
627
655
657
244
241
13
3/12
06:00
525
3115
113
120
81
83
0
0
7.6
1567
1504
2726
2675
2397
1649
539
5.29
8.69
7.28
6.71
3.38
3.43
2.10
2.11
3.13
3.92
-.41
-.82
-.84
-2.43
-6.39
-8.74
-8.09
-15.0
-13.5
-.49
-.41
32.85
32.77
30
56
68
71
74
710
724
774
776
276
276
14
3/9
14:00
512
3179
61
79
58
76
0
0
7.6
1622
1575
2683
2676
2402
1623
526
5.79
9.24
7.96
7.41
3.62
3.80
2.32
2.35
3.23
3.94
-.68
-.77
-.70
-2.42
-6.49
-8.75
-8.34
-15.4
-14.3
-.43
-.69
32.64
32.44
30
50
58
70
73
705
725
771
775
270
270
15
3/10
18:50
484
2859
102
106
44
67
0
0
6.8
1602
1558
2686
2639
2397
1503
490
5.60
9.00
7.47
6.96
3.57
3.45
2.20
2.21
3.17
3.93
-.53
-.61
-.47
-2.58
-6.12
-8.24
-8.18
-14.9
-13.6
-.49
-.43
32.81
32.63
30
49
58
78
82
688
710
753
757
267
268
16
3/13
13:30
4OO
2444
0
54
10
0
0
0
7.6
1302
1283
2625
2589
2404
1245
393
4.25
6.71
5.84
5.33
2.93
2.87
2.30
2.37
3.16
3.88
-.40
-.54
-.29
-1.75
-4.39
-6.41
-6.18
-11.3
-10.3
-.94
-.93
32.69
32.29
30
46
55
102
107
631
634
685
680
253
249
V7
5/25
18:20
322
1820
56
82
10
29
44
34
14.1
896
900
2559
2532
2408
958
312
8.64
7.85
7.30
6.64
5.57
5.51
5.00
4.94
5.79
6.46
-.55
-.62
-.90
-1.23
-2.65
-3.84
-3.90
-6.74
-6.23
-.62
-.62
31.63
32.53
30
81
92
100
102
591
612
637
640
E44
252
J8
5/25
16:30
325
1818
65
96
8
27
42
52
11.2
1046
1099
2558
2531
2407
969
316
10.46
9.32
8.54
7.85
6.31
6.22
5.47
5.49
6.56
7.03
-.61
-.63
-.93
-1.36
-3.23
-4.69
-4.75
-8.13
-7.35
-.45
-.44
31.74
32.77
30
80
89
98
100
603
62O
652
653
245
245
19
5/25
14:35
322
1810
66
84
4
23
39
71
B.3
1210
1259
2558
2532
2403
968
313
11.89
10.21
9.17
8.41
6.47
6.42
5.37
5.45
6.58
7.00
-.61
-.69
-1.02
-1.54
-3.83
-5.30
-5.50
-9.50
-8.72
-.32
-.38
31.76
32.64
30
79
85
101
105
607
629
6OO
/ 661
/ 245
' 243
* C - COMPUTER DATAJ 8 - BOARD DATA; NA - NOT AVAILABLE.
220
SHEET A37
-------
VISCONSIN POWER & LIGHT Co.
COLUMBIA t\
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD £. COMPUTER DATA
TEST NO.
10
•c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
DATE
TIME
LOAD
TEMPERATURES
AIR t GAS - *F
ECON. N GAS OUT.
ECOM. S GAS OUT.
1-A PA FAN DISCH. Hon.
1-B PA FAN DISCH. HDR.
1-A AH PR 1. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM 4 WATER - *F
BOILER ECON. l«
DOWNCOHCR 1
DOWNCOMER S
DOWN CO HER 3
DOWNCOMER 4
DOWNCOHER 5
BLR. SH ATMP 1-A STH. IN.
BLR. SH ATMP 1-B STH. IN.
BLR. S SH HOR. OUT.
BLR. N SH HOR. OUT.
TURBINE THROTTLE
BLR. S RH ATM5 STH. OUT. A
BLR. N RH ATM* STH. OUT. B
BLR. S RH HDR. OUT. A
BLR. N RH HDR. OUT. B
HP HTR. 1-G1 £ 1-G2 EXTR. STM.
HP HTR. 1-F1 FW OUT.
HP HTR. 1-F2 FW OUT.
HP HTH. 1-G1 FW OUT.
HP HTR. 1-G2 FW OUT.
HP HTR. 1-G1 DRAIN
HP HTR. 1-G2 DRAIN
PULVERIZER OATA
PLV 1-A BOWL LOWER P
PLV 1-B BOWL LOWER P
PUV 1-C BOWL LOWER P
PLV 1-D BOWL LOWER P
PLV 1-E BOWL LOWER P
PLV 1-F BOWL LOWER P
PLV 1-A BOWL Dirr. P
PLV 1-B BOWL Dirr. P
PLV 1-C BOWL Dirr. P
PLV -D BOWL DIFF. P
PLV -E BOWL DIFF. P
PLV -F BOWL DIFF. P
PLV -A COAL AIR OUT. P
PLV -B COAL AIR OUT. P
PLV -C COAL AIR OUT. P
PLV -D COAL AIR OUT. P
PLV -E COAL AIR OUT. P
PLV -F COAL AIR OUT. P
PLV -A PRI. AIR IN. FLOW
PLV -B PRI. AIR IN. FLOW
PLV -C PRI. AIR IN. FLOW
PLV -D PRI. AIR IN. FLOW
PLV -E PRI. AIR IN. FLOW
PLV -F PRI. Am IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
M
IN. H-0
IN. HgO
IN. HTO
IN. H?0
IN. (CO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. HfO
IN. H?0
IN. H§0
0-iasf
0-125*
0-123$
0-125*
0-125*
0-125*
°F
3/10
09:45
524
788
802
60
95
708
689
480
677
678
679
682
680
851
856
1008
1001
1002
478
479
991
1015
618
411
410
479
479
415
382
21.36
22.68
.23
22.89
22.16
22. B1
7.61
7.80
.06
7.95
7.12
7.17
9. 84
11.36
-.13
10.80
11.58
10.26
126.1
127.8
37.2
125.2
127.8
125.2
144
3/08
14:00
524
750
758
52
95
681
669
477
675
676
677
681
679
830
829
1002
1011
1000
480
480
989
1015
620
407
407
476
476
412
377
21.52
22.37
.13
23.09
22.19
21.51
7.67
7.74
.00
8.00
7.10
7.32
10.17
11.15
-.35
10.99
11.56
10.67
125.1
128.3
0.0
125.4
127.7
125.1
139
3/15
15:35
483
780
792
55
69
697
686
471
675
677
677
676
676
838
846
1006
1011
1006
471
471
1000
1012
610
404
403
470
469
406
374
20.23
21.29
.21
22.04
21.44
19.83
7.14
7.41
.03
7.72
6.99
6.93
9.41
10.71
-.19
10.45
11.17
9.55
125.8
128.6
0.0
126.0
127.9
125.0
142
3/13
10:00
399
710
728
53
64
639
620
448
673
674
674
676
676
850
827
1014
1012
1009
589
588
1019
992
581
387
386
449
449
387
357
18.51
19.49
.19
19.64
19.84
17.78
6.66
6.79
.02
6.82
6.46
6.21
8.43
9.74
-.22
9.34
10.26
8.58
125.7
128.4
0.0
125.6
128.5
125.3
144
5/23
12:35
324
638
548
86
•NA
579
574
424
666
668
669
673
670
844
813
1008
1001
1001
550
550
966
963
543
366
366
424
424
366
335
-.27
-1.18
19.31
19.36
19.74
18.15
.45
.20
6.39
6.46
6.18
6.05
-1.11
-1.23
9.32
9.23
9.64
8.83
0.0
30.8
131.2
126.2
126.3
126.2
87
5/23
14:30
323
651
557
85
NA
586
577
424
666
668
669
673
670
837
813
1003
996
999
547
546
957
964
538
366
365
423
423
366
335
-.28
-1.17
19.16
19.34
19.39
18.06
.45
.20
6.41
6.44
6.20
6.13
-.96
-1.15
9.35
9.33
9.89
9.03
o.o
30.2
131.4
125.9
129.2
125.3
88
5/23
16:20
322
655
556
84
NA
588
579
424
666
868
669
673
670
839
822
1009
1008
1006
554
553
952
966
547
366
355
423
423
366
335
-.15
-1.10
19.21
19.38
19.58
18.52
.45
.20
6.38
6.46
6.14
6.21
-.95
-1.16
9.25
9.19
9.63
8.93
0.0
29.7
131.4
126.3
129.4
124.0
88
3/10
14:00
514
794
c •*
66
1'"'4
712
694
477
676
678
678
682
679
860
855
1009
999
1003
478
479
990
1014
620
410
410
477
477
415
381
20.90
22.38
.25
22.54
21.89
20.28
7.53
7.74
.06
7.66
7.02
7.08
9.68
11.24
-.13
10.61
11.29
9.68
125.9
128.4
45.9
124.9
127.9
124.5
142
3/09
10:00
515
775
791
56
I "5
701
686
477
674
676
676
680
678
848
848
1006
1003
1002
476
477
989
1020
619
408
407
475
475
411
376
21.39
22.51
.23
22.87
22.25
21.10
7.67
7.77
.05
7.98
7.13
7.21
10.06
11.37
-.23
10.85
11.66
10.41
125.6
128.6
46.9
125.3
127.9
124.7
141
3/10
16:30
482
782
796
62
101-
707
690
468
674
676
676
680
677
865
858
1009
1003
1004
472
471
1008
1006
607
4O4
403
469
469
406
376
20.25
21.69
.25
21.78
21.34
19.39
7.12
7.47
.07
7.58
6.88
6.83
9.32
10.89
-.14
10.78
10.03
9.44
125.3
128.4
47.3
124.8
127.9
125.4
143
* C - COMPUTER DATA; B - BOARD DATA, NA - NOT AVAILABLE.
221
SHEET A38
-------
WISCONSIN POWER & LIOHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BMUD t COMPUTER DATA
TEST NO.
II 15 25. 22.
21 21
•C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
r.
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
D»TE
TIME
LOAD
TEMPERATURES
AIR i G»s - °F
ECON. N GAS OUT.
ECON. S GAS OUT.
1-A PA FAN.DISCH. HDR,
1-B PA TAN DISCH. HDR.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM I WATCR - *F
BOILER E ON. IN.
DOWNCOME 1
DOWNCOME 2
DOWNCOME 3
DOWNCOME 4
DOWNCOMER 5
BLR. SH ATMP 1-A STM. IN.
BLR. SH ATMP 1-B STM. IN.
BLR. S SH HDR. OUT.
BLR. N SH HDR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STM. OUT. A
BLR, N RH ATMP STH. OUT. B
BLR. S RH HOR. OUT. A
BLR. N RH HDR. OUT. B
HP HTR. 1-G1 4 1-62 EXTR. STM
HP HTR. 1-F1 FW OUT.
HP HTR. 1-F2 FW OUT.
HP HTR. 1-G1 FW OUT.
HP HTH. 1-G2 FW OUT.
HP HTR. 1-G1 DRAIN
HP HTR. 1-G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER P
PLV 1-B TOWL LOWER P
PLV 1-C BOWL LOWER P
PLV 1-D BOWL LOWER P
PLV 1-E BOWL LOWER P
PLV 1-F BOWL LOWER P
PLV 1-A BOWL DIFF. P
PLV 1-B BOWL DIFF. P
PLV 1-C BOWL DIFF. P
PLV 1-D BOWL DIFF. P
PLV 1-E BOWL DIFF. P
PLV 1-F BOWL DIFF. P
PLV 1-A COAL AIR OUT. P
PLV 1-B COAL AIR OUT. P
PLV 1-C COAL AIR OUT. P
PLV 1-D COAL AIR OUT. P
PLV 1-E COAL AIR OUT. P
PLV 1-F COAL AIR OUT. P
PLV 1-A PRI. AIR IN. FLOW
PLV 1-B PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-E PRI. AIR IN. FLOW
PLV 1-F PRI. AIR IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
MW
IN. HO
IN. H*0
IN. HJTO
IN. H*0
IN. H?0
IN. HfO
IN. HtO
IN. ICO
IN. HXP
IN. HtO
IN. H,0
IN. \CO
IN. HtO
IN. HtO
IN. K;0
m. H!O
IN. HTO
IN. HgO
0-125*
0-125*
0-125*
0-125*
0-125*
0-125*
•F
5/21
05:00
321
662
648
78
•NA
605
604
425
666
667
668
667
667
917
878
1011
997
1003
427
425
1005
994
548
368
369
424
424
367
338
18.56
21.00
19.96
19.53
-.89
-1.16
6.37
6.53
6.68
6.69
.12
.06
8.21
10.04
9.66
9.14
1.13
1.37
126.8
128.8
130.8
126.0
0.0
O.O
144
5/65
13:00
321
693
479
88
NA
616
610
424
666
668
668
672
670
882
862
1005
1005
1003
454
429
970
986
544
366
366
424
424
366
337
18.42
20.41
19.60
19.45
0.0
-1.10
6.36
6.57
6.46
6.54
.01
.06
8.23
10.28
9.42
9.18
.05
-1.26
126.8
129.3
131.2
125.6
0.0
0.0
143
3/ia
06:00
525
817
817
66
104
723
710
478
676
678
678
682
680
860
862
1013
1010
1007
479
482
1019
1012
628
412
412
479
479
415
379
21.65
23.23
.24
23.44
21.88
18.87
7.75
8.12
.06
8.21
7.15
6.65
9.80
11.55
-.13
10.96
11.15
9.04
125.6
128.5
33.1
125.2
127.5
125.6
143
3/9
14:00
512
794
806
59
106
718
706
476
674
676
679
680
678
841
842
1007
10O5
1004
476
477
990
1015
619
409
408
476
477
413
380
20.97
22.35
.24
22.50
21.89
20.47
7.60
7.73
.07
7.77
7.04
7.07
9.90
11.16
-.17
10.64
11.24
10.15
125.4
128.7
59.5
125.2
128.0
124.8
141
3/10
18:50
484
780
788
58
93
702
688
469
674
676
676
680
678
864
853
1011
1002
1005
472
470
1006
1007
608
404
403
469
469
406
373
20.25
21.56
.23
21.84
21.30
19.48
7.25
7.44
.07
7.56
6.91
6.82
9.21
10.73
-.14
10.22
10.94
9.34
126.2
128.4
42.4
125.4
127.8
124.7
143
S/J3
13:30
400
707
726
58
75
645
624
448
673
674
674
679
676
842
847
1010
1012
1008
588
587
1015
994
580
387
386
449
449
387
357
18.64
19.17
.19
19.78
19.91
17.68
6.65
6.72
.25
6.82
6.42
6.12
8.45
9.56
-.23
9.42
10.28
8.54
125.8
128.5
0.0
125.6
127.8
124.7
144
5/25
18:20'
322
663
416
90
NA
602
604
424
666
668
668
673
670
892
857
1010
998
1003
427
425
974
975
546
367
366
424
424
366
337
18.21
20.33
19.18
19.44
-.01
-1.22
6.32
6.58
6.32
6.48
.02
.06
8.07
10.37
9.12
9.17
.05
-1.47
127.1
128.9
130.0
125.4
0.0
0.0
142
5/25
16:30
325
687
448
90
NA
614
610
426
666
668
668
673
669
904
865
1010
1000
1002
427
426
976
982
546
368
367
424
425
367
338
18.43
20.93
12.62
19.56
0.0
-1.24
6.34
6.79
6.56
6.55
.02
.06
7.95
10.49
9.37
9.11
.06
-1.26
127.3
129.3
131.7
125.6
0.0
3.6
142
5/25
14:35
322
702
461
90
NA
619
612
425
664
668
668
673
670
891
871
1006
1003
1003
428
427
972
984
545
367
366
424
424
366
337
18.39
20.78
19.52
19.44
0.0
-1.23
6.39
6.73
6.47
6.55
.03
.06
8.15
10.43
9.41
9.26
.05
-1.19
126.1
129.6
131.0
125.8
0.0
0.0
142
* C - COMPUTER DATA; B - BOARD DATAJ' NA - NOT AVAILABLE.
222
SHEET A39
-------
WISCONSIN POWER t LIGHT Co.
COLUMBIA #1
C-E POVCR SYSTEMS
FIELD TESTino AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD & COMPUTER DATA
•C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
•B
B
B
B
B
B
8
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
TEST NO,
DATE 1976
TIME
LOAD MM
PULVERIZER DATA
PLV 1-B COAL AIR DISCH. TEMP. V
PLV 1-C COAL AIR DISCH. TEMP. "F
PLV 1-D COAL AIR DISCH. TEMP. 'F
PLV 1-E COAL AIR DISCH. TEMP. 'F
PLV 1-F COAL AIR DISCH. TEMP « °F
PLV 1-A FEEDER COAL FLOW 'lOie/HR
PLV 1-B FEEDER COAL FLOW 10±.B/HR
PLV 1-C FEEDER COAL FLOW 103.B/HR
PLV 1-D FEEDER COAL FLOW 10iB/HR
PLV 1-E FEEDER COAL FLOW 1olB/MR
PLV 1-F FEEDER COAL FLOW 10T.B/HR
PLV 1-A MILL AMPS
PLV 1-B MILL AMPS
PLV 1-C MILL AMPS
PLV 1-D MILL AMPS
PLV 1-E MILL AMPS
PLV 1-F MILL AMPS
FAN DAMPER POSITION - % OPEN
1-A FD FAN INLET VANE
1-B FD FAN INLET VANE
1-A PA FAN INLET VANE
1-B PA FAN INLET VANE
SPRAY VALVE POSITION - % OPEN
1-A SH SPRAY VALVE
1-B SH SPRAY VALVE
1-A RH SPRAY VALVE
1-B RH SPRAY VALVE
MISCELLANEOUS
BURNER TILT + DEGREES
Aux. AIR DAMPERS ~ jf OPEN
1-A FUEL/AIR DAMPERS # OPEN
1-B FUEL/AIR DAMPERS $ OPEN
1-C FUEL/AIR DAMPERS % OPEN
1-D FUEL/AIR DAMPERS % OPEN
1-E FUEL/AIR DAMPERS % OPEN
1-F FUEL/AIR DAMPERS % OPEN
1-A PRI. AIR FAN AMPS
1-B PRI. AIR FAN AMPS
1-A ID FAN AMPS
1-B ID FAN AMPS
1-A FD FAN AMPS
1-B FD FAN AMPS
1-A ID FAN RPM
1-B ID FAN RPM
1-A BLR. CIRC. WTR. PUMP AMPS
1-B BLR. CIRC. WTR. PUMP AMPS
1-C BLR. CIRC. WTR. PUMP AMPS
1-D BLR. CIRC. WTF. PUMP AMPS
N DRUM LEVEL + NORM. HO LEVEL IN.
S DRUM LEVEL + NORM. H&D LEVEL IN.
FLUE GAS COMBUSTIBLES £
FLUE GAS OXYOEN *>
BARONHCTRIC PRESS. IN. HGA
i
3/10
09:45
524
146
55
147
141
145
116
117
0
114
116
116
73
72
0
74
75
75
72
71
30
25
100
92
47
65
-3°
100
51
52
0
51
51
51
170
180
500
430
201
198
460
490
71
76
70
72
-.72
-3.05
.062
3.8
29.76
2
3/08
14:00
524
142
79
144
138
141
116
112
0
113
115
116
74
71
0
73
76
74
70
70
29
24
25
13
43
0°
98
50
49
2
52
52
52
175
184
500
420
208
193
4BO
490
73
76
72
73
-.70
-2.87
.064
3.9
30.08
3
3/15
15:35
483
145
89
146
141
144
105
106
0
105
106
104
70
70
0
71
72
71
73
71
28
24
36
24
41
41
-3°
100
45
45
0
46
45
45
171
181
500
430
210
197
480
460
75
79
73
75
-.57
-2.01
.067
4.8
30.07
jl
3/13
1O:00
399
146
43
146
143
145
87
88
0
87
88
86
64
65
0
66
65
65
63
62
28
23
23
17
0
0
+15°
56
31
34
0
35
34
33
173
185
380
320
187
177
430
430
79
81
78
80
-.67
-1.58
.064
5.3
30.08
5
5/23
12:35
324
121
144
141
138
141
0
0
87
88
88
86
0
0
65
65
67
65
58
57
32
26
11
6
0
0
+6°
13
0
0
87
84
80
76
165
175
280
300
167
157
320
315
83
95
80
85
-.79
-2.02
.063
5.1
30.05
6
5/23
14:30
323
114
144
144
138
142
0
0
87
88
88
86
0
0
67
65
67
66
62
60
32
26
B
5
0
0
+6"
21
0
0
68
85
82
78
168
178
300
320
175
162
340
345
83
83
79
83
-.63
-2.26
.065
5.7
30.03
7
5/23
16:20
322
110
144
142
138
142
0
0
87
69
88
87
0
0
66
65
66
65
64
62
32
26
10
20
0
0
46°
25
0
0
90
83
64
80
168
178
310
320
179
166
354
354
81
64
78
83
-.35
-1.70
.063
6.0
30.02
B
3/10
14:00
514
145
57
147
141
144
114
115
0
112
114
113
73
71
0
73
75
74
70
69
30
25
100
1OO
64
61
-3°
79
50
50
0
50
50
50
171
181
480
410
198
138
480
468
74
77
72
74
-.68
-3.28
.068
3.9
29.81
9
3/09
10:00
515
143
69
146
139
142
114
111
0
112
114
115
74
70
0
75
75
75
73
71
30
25
45
32
50
70
0°
100
50
49
0
50
50
50
173
180
500
430
210
198
480
500
72
75
71
72
-.78
-2.92
.060
4.0
29.66
.1°
3/10
16:30
482
146
55
146
142
144
106
107
0
104
106
105
70
70
0
70
73
71
70
70
X
25
85
69
31
41
-3°
84
45
46
0
46
46
46
170
180
470
400
200
190
480
460
73
76
71
73
-.64
-2.95
.068
5.0
29.87
* C - COMPUTER DATA; B - BOARO DATA; NA - NOT AVAILABLE.
223
SHEET A40
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD t COMPUTER DATA
*c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
•e
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
TEST NO.
DATE
TIME
LOAD
PULVERIZER DATA
PLV 1-B COAL AIR DISCH. TEMP.
PLV 1-C COAL AIR DISCH. TEMP.
PLV 1-D COAL AIR DISCH. TEMP.
PLV 1-E COAL AIR DISCH. TEMP.
PLV 1-F COAL AIR DISCH. TEMP. _
PLV 1-A FEEDER COAL FLOW 10g
PLV 1-B FEEDER COAL FLOW lot
PLV 1-C FEEDER COAL Flow ICC
PLV 1-D FEEDER COAL FLOW ICC
PLV 1-E FEEDER COAL FLOW 10,
PLV 1-F FEEDER COAL FLOW 10J
PLV 1-A MILL
PLV 1-B MILL
PLV 1-C MILL
PLV 1-D MILL
PLV 1-E MILU
PLV 1-F MILL
FAN DAMPER POSITION - % OPEN
1-A FD FAN INLET VANE
1-B FD FAN INLET VANE
1-A PA FAN INLET VANE
1-B PA FAN INLET VANE
SPRAY VALVE POSITION - % OPEN
1-A SH SPRAY VALVE
1-B SH SPRAT VALVE
1-A RH SPRAT VALVC
1-B RH SPRAT VALVE
MISCELLANEOUS
1976
MM
•F
•F
•F
"F
•F
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
AMPS
AMPS
AMPS
AMPS
AMPS
AMPS
BURNER TILT +• DEGREES
Aux. AIR DAMPERS $
1-A FUEL/AIR DAMPERS f
1-B FUEL/AIR DAMPERS f
1-C FUEL/AIR DAMPERS %
1-D FUEL/AIR DAMPERS *
1-E FUEL/AIR DAMPERS f
1-F FUEI/AIR DAMPERS %
1-A PR i. AIR FAN
1-B PRI. AIR FAN
1-A ID FAN
1-B ID FAN
1-A FD FAN
1-B FD FAN
1-A ID FAN
1-B ID FAN
1-A BLR. CIRC. WTR. PUMP
1-B BLR. CIRC. WTR. PUMP
1-C BLR. CIRC. WTR, PUMP
1-D BLR. CIRC. WTR. PUMP
N DRUM LEVEL + NORM. HO LEVEL
S DRUM LEVEL 7 NORM. HJJO LE VEL
FLUE GAS COMBUSTIBLES
FLUE GAS OXYGEN
BARONMETRIC PRESS. IN
OPEN
OPEN
OPEN
OPEN
OPEN
OPEN
OPEN
AMPS
AMPS
AMPS
AMPS
AMPS
AMPS
RPM
RPM
AMPS
AMPS
AMPS
AMPS
IN.
IN.
%
a
. HGA
11
5/21
05:00
381
145
145
143
94
104
66
88
88
88
0
0
64
65
66
66
0
0
52
51
31
26
41
45
19
15
46'
0
79
82
87
82
0
0
170
178
270
300
158
149
300
300
80
83
79
83
-.64
-2.56
.063
4.2
30.08
12
5/25
13:00
321
151
144
142
79
134
88
90
89
90
0
0
64
65
67
66
0
0
69
67
31
25
26
25
8
5
+3°
29
83
86
92
88
0
0
165
175
340
350
189
175
393
393
79
83
77
79
-.56
-2.13
.067
7.0
29.98
13
3/12
06:00
525
145
50
147
141
144
119
120
0
117
112
112
77
74
0
76
76
71
71
70
30
25
52
30
100
100
-3°
95
54
54
0
54
50
44
170
180
480
410
199
1B7
480
480
73
76
72
74
-.64
-1.60
.065
3.5
29.01
14
3/9
14:00
512
144
68
146
140
143
112
109
0
110
112
112
75
71
0
75
75
76
72
71
30
25
30
23
49
68
0'
100
49
47
0
50
50
50
170
180
500
430
205
190
480
490
70
75
70
72
-.69
-2.54
.064
4.1
29.56
.15
3/10
18:50
484
145
53
147
141
144
107
109
0
105
107
106
69
70
0
70
73
71
70
70
29
24
53
41
36
50
-3°
90
45
46
0
46
46
46
170
180
480
410
200
190
48O
480
73
76
71
73
-.65
-3.03
.066
5.0
29.94
16
3/13
13:30
400
146
44
145
142
146
86
88
0
87
87
86
65
65
0
66
66
65
64
63
29
24
22
12
0
0
+17°
57
31
33
0
35
33
32
171
185
380
320
187
171
430
430
79
81
76
80
-.55
-1.15
.065
5.3
30.00
J7
5/25
18:20
322
151
143
142
82
110
86
88
88
89
0
0
65
65
67
66
0
0
59
58
31
26
26
28
17
12
+4°
0
81
84
89
85
0
0
165
175
290"
310
165
155
316
326
82
83
78
82
-.77
-1.40
.066
4.6
29.91
_18
5/85
16:30
325
154
144
142
80
114
88
90
90
91
0
0
65
65
67
66
0
0
65
64
31
26
32
41
18
12
+3°
18
85
87
83
87
0
0
165
175
310
320
180
165
360
360
80
83
78
80
-.67
-1.79
.068
5.9
29.92
J9
5/25
14:35
322
153
144
142
80
122
88
90
90
91
0
0
65
66
68
67
0
0
69
68
31
26
32
27
14
9
+4°
31
85
87
93
89
0
0
165
175
350
340
189
178
400
400
79
80
76
78
-.54
-2.25
.066
7.0
29.95
* C - COMPUTER DATA; B - BOARD DATA; NA - Not AVAILABLE.
224
SHEET A41
-------
WISCONSIN POWER 4 LIGHT Co.
COLUMBIA |1
C-E POUER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD L COMPUTER DATA
•c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
*e
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE 1976
TIME
LOAD KM
FLOWS 103LB/HR
FEEDWATER
SUPERHEAT SPRAY L
SUPERHEAT SPRAV R
REHEAT SPRAY L
REHEAT SPRAY R
BFP TURB. EXTR. STM. FLOW 1-A
BFP TURB. EXTR. STH. FLOW 1-8
BFP TURB. MN. STM. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM i WATER . PSIG
FEEDWATER TO E.CON.
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STAGE
HP HTR. 1-61 4 1-G2 STEAM IN.
AIR & GAS - IN H00
FD FAN 1-A DISCHARGE
FD FAN 1-B DISCHARGE
AIR HTR. 1-A Am IN.
Am HTR. 1-5 AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURN. LETT WINDBOX
RT. WD3X TO FURN. DIFF. P
LEFT WDBX TO FURN. DIFF. P
FURNACE- *
PRI. SH GAS OUT.
REHEATER GAS OUT.
ECOH. GAS IN.
ECON. GAS OUT,
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCH.
IDF 1-B DISCH.
PAF 1-A DISCH. HOH.
PAF 1-B DISCH. HDR.
PRI. HOT AIR DUCT
TEMPERATURES
AIR & GAS - °F
-A FD FAN Di SCH.
-B FD FAN DISCH.
-A AH AIR IN.
-B AH AIR IN.
-A AH AIR OUT.
-B AH AIR OUT.
-A AH GAS IN.
-B AH GAS IN.
-A AH GAS OUT.
1-B AH GAS OUT.
1
5/19
16:15
505
3176
80
83
38
62
43
68
8.47
1481
1555
2732
2674
2403
1618
519
14.07
13.15
11.14
10.26
7.02
7.02
5.33
5.46
6.50
7.01
-0.26
-0.43
-0.9B
-2.13
-5.73
-7.96
-7.73
-14.1
-12.9
-0.09
-0.02
32.26
33.43
30
84
91
98
102
688
722
744
758
291
293
2
5/19
13:50
506
3200
66
68
54
74
43
69
8.49
1382
1472
2731
2678
2403
1620
520
13.28
11.98
10.45
9.51
6.65
6.64
5.20
5.31
6.53
6.94
-0.64
-0.57
-1.13
-2.16
-5.61
-7.74
-7.54
-13.6
-12.4
-0.16
-0.12
32.44
33.44
30
81
88
97
101
588
702
744
744
290
288
3
3/12
07:15
524
3111
122
108
81
83
0
0
7.69
1516
1466
2728
2676
2396
1649
539
5.36
8.67
7.32
6.75
3.44
3.46
2.39
2.42
3.20
4.00
-0.43
-0.73
-0.69
-2.45
-6.18
-8.49
-8.10
-14.9
-13.6
-0.56
-0.47
32.91
32.68
30
58
68
73
76
720
738
784
789
280
283
f
5/19
11:00
506
3111
113
95
35
59
42
69
8.13
1384
1473
2720
2670
2402
1623
518
13.11
11.61
10.40
9.43
6.61
6.74
5.30
5.41
6.53
6.90
-0.70
-0.47
-1.05
-2.15
-5.67
-7.97
-7.44
-13.5
-12.2
-0.21
-0.19
32.31
33.23
30
75
80
89
92
681
692
737
733
282
280
5_
5/12
1J:00
422
2666
0
29
10
6
0
0
8.80
1247
1300
2649
2607
2400
1319
416
11.67
10.05
9.30
8.45
6.24
6.28
5.21
5.24
6.54
7.00
-0.49
-0.50
-0.87
-1.71
-4.19
-6.14
-5.67
-10.3
-9.3
-0.56
-0.52
31.89
32.75
30
7n
/u
79
96
67
639
651
695
688
249
256
5
5/12
09:20
422
2634
0
57
9
0
0
0
8.87
1169
1226
2643
2604
2400
1322
414
10.86
9.49
8.71
7.93
6.02
6.17
5.23
5.29
6.55
7.01
-0.42
-0.53
-0.86
-1.62
-3.84
-5.81
-5.42
-9.7
-9.0
-0.79
-0.74
31.93
32.75
30
Cfl
D*»
76
95
102
629
641
680
371
246
254
7
5/1 S
09:30
421
2624
0
22
10
0
42
72
8.70
1285
1342
2645
2605
2399
1321
415
11.98
10.04
9.33
8.56
6.35
6.22
5.17
5.21
6.54
6.99
-0.52
-0.56
-0.91
-1.82
-4.31
-5.91
-5.04
-10.5
-9.7
-0.35
-0.34
31.90
32. B7
30
7-3
1 J
80
91
95
627
648
679
682
250
251
a
5/21
03:10
320
1727
90
121
9
24
39
68
7.12
819
826
2546
2519
2400
951
312
5.00
4.39
3.82
3.26
2.35
2.27
1.95
1.93
2.02
3.52
-0.20
-0.59
-0.81
-1.32
-2.58
-3.52
-3.76
-6.3
-6.0
-0.86
-0.84
31.59
32.77
30
75
87
92
95
594
612
642
641
252
261
9
6/27
09:40
314
1979
0
20
'0
2
34
89
0.00
1006
951
2564
2531
2407
966
301
6.96
5.75
5.30
4.55
3.43
3.36
2.94
2.80
2.12
3.58
-0.54
-0.73
-0.86
-1.23
-2.68
-3.83
-3.96
-6.4
-6.3
-0.41
-0.40
31.64
32.79
30
87
93
99
101
549
566
591
599
226
238
* C - COMPUTER DATA; B - BOARD DATAJ NA - NOT AVAILABLE.
225
SHEET A42
-------
WISCONSIN POWER S LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD t COMPUTER DATA
TEST NO.
DATE
TIME
LOAD
1976
FLOWS - 103LB/H3
FEEOVATER
SUPERHEAT SPRAT L
SUPERHEAT SPRAT R
REHEAT SPRAT L
REHEAT SPRAT R
BFP TURB. EXTR. STM. FLOW 1-A
BFP TURB. EXTR. STM. FLOW 1-B
BFP TURB. MN. STM. FLOW COMBINED
HOT AIR TO BURNERS L WIHOBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM t WATER - PSIG
FEEOWATER TO ECON.
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STAGE
HP HTR. 1-G1 & 1 -G2 STEAM IN.
AIR i Gts - IN HpO
FD FAN 1-A DISCHARGE
FD FAN 1-6 DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURN. LEFT WINDBOX
RT. VJOBX TO FURN. Dirr. P
LEFT WD3X TO FURN. Dirr. P
FURNACC
PR I. SH GAS OUT.
REMEATER GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCH.
IDF 1-B DISCH.
PAF 1-A DISCH. HDR.
PAF 1-B DISCH. HDR.
PR i. HOT AIR DUCT
TEMPERATURES
AIR i GAS - *F
1-A FD FAN DISCH.
1-B FD FAN DISCH.
1-A AH AIR IN.
1-B AH AIR IN.
1-A AH AIR OUT.
1-B AH AIR OUT.
1-A AH GAS IN.
1-B AH GAS IN.
1-A AH GAS OUT.
1-B AH GAS OUT.
\0
5/23
11:05
324
1940
12
46
0
0
44
34
14.70
902
913
2565
2539
2402
984
310
7.35
6.46
5.99
5.57
4.41
4.32
3.82
3.72
4.55
5.38
-0.63
-0.48
-0.74
-1.22
-2.78
-3.97
-4.12
-6.9
-6.4
-0.85
-0.90
31.50
32.33
30
74
80
104
108
564
580
611
608
240
242
_n
5/19
18:35
491
3005
107
101
40
64
42
67
8.08
1502
1583
2711
2660
2400
1559
505
14.17
13.30
11.27
10.49
7.18
7.19
5.53
5.59
6.56
7.01
-0.23
-0.25
-0.82
-2.03
-5.68
-7.98
-7.77
-14.3
-13.0
-0.00
-0.06
32.32
33.37
30
84
91
98
102
690
718
748
753
292
291
J2
5/10
09:50
497
2972
125
140
66
80
0
0
7.65
1514
1554
2701
2652
2400
1574
513
13.78
12.75
11.12
10.86
7.13
7.20
5.64
5.70
6.54
6.97
-0.03
-0.18
-0.68
-2.10
-5.78
-8.36
-7.99
-14.5
-13.1
-0.13
-0.03
33.17
34.33
30
76
81
88
91
702
731
762
453
276
281
_13
3/16
10:OO
522
3139
135
111
70
75
0
0
7.51
1576
1552
2734
2687
2395
1672
537
5.47
8.78
7.58
7.04
3.52
3.38
2.35
2.14
3.0B
3.73
-0.44
-0.62
-0.48
-2.56
-6.22
-8.91
-8.89
-15.5
-14.0
-0.78
-0.92
32.87
32.78
30
40
47
82
85
698
715
763
767
272
270
_H
5/12
13:45
422
2660
0
39
11
8
0
0
8.93
1411
1869
2648
2608
2408
1323
261
12.75
11.24
10.11
9.11
6.47
6.50
5.22
5.27
6.54
7.01
-0.60
-0.56
-1.03
-1.88
-4.82
-6.89
-6.50
-11.6
-10.6
-0.26
-0.22
31.94
32.84
30
76
84
91
94
651
665
710
703
253
257
-!§
3/13
15:30
400
2458
0
34
10
0
0
0
7.61
1290
1287
2623
2587
2402
1238
391
4.26
6.66
5.78
5.36
2.90
2.88
2.17
2.23
3.16
3.86
-0.51
-0.64
-0.36
-1.81
-4.47
-6.49
-6.24
-11.3
-10.1
-1.01
-0.97
32.47
32.29
30
47
56
99
105
631
639
684
684
251
252
J6
5/16
11:45
422
2634
9
32
10
0
42
73
8.95
1472
1533
2647
2608
2406
1326
416
13.09
11.96
10.29
9.60
6.63
6.49
4.98
5.12
6.54
7.01
-0.57
-0.54
-0.96
-2.05
-5.13
-7.12
-7.20
-12.6
-11.6
-0.12
-0.09
31.89
32.86
30
73
80
90
93
637
663
694
702
254
254
_17
5/21
01:15
320
1720
92
122
5
22
39
70
7.53
967
979
2544
2520
2405
953
311
7.95
6.67
6.21
5.50
4.20
4.12
3.56
3.51
4.15
5.17
-0.52
-0.59
-0.84
-1.49
-3.00
-4.13
-4.37
-7.5
-6.9
-0.73
-0.69
31.76
32.73
30
77
87
91
94
606
630
656
658
253
261
_I8
5/23
09:10
323
1909
36
48
0
0
44
34
14.99
993
1027
2563
2540
2405
983
308
9.52
8.33
7.62
7.04
5.58
5.51
4.98
4.96
6.15
6.63
-0.35
-0.49
-0.74
-1.29
-2.90
-4.22
-4.37
-7.6
-7.1
-0.7B
-0.85
31.37
32.26
30
68
78
112
116
552
561
605
596
236
233
' C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
226
SHEET A4.1
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA |1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD t COMPUTER DATA
«c
c
c
c
c
c
C'
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE
TIME
LOAD
TEMPERATURES
AIR & GAS - °F
ECON. N GAS OUT.
ECON. S GAS OUT.
1-A PA FAN DISCH. HDD.
1-B PA FAN DISCH. HDR.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM & WATER - °F
BOILER ECON. IN.
DOWNCOHER 1
DOWNCOMER S
DOWNCOHER 3
DOWNCOMER 4
DOWNCOMER 5
BLR. SH ATMP 1-A STM. IN.
BLR. SH ATMP 1-B STM. IN.
BLR. S SH HDR. OUT.
BLR. N SH HDR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STM. OUT. A
BLR. N RH ATMP STM. OUT. B
BLR. S RH HDR. OUT. A
BLR. N RH HDR. OUT. 8
HP HTR. 1-G1 & 1-G2 EXTR. STM
HP HTH. 1-F1 FW OUT.
HP HTR. -F2 FW OUT.
HP HTR. -G1 FW OUT.
HP HTR. -G2 FW OUT.
HP HTR. -G1 DRAIN
HP HTR. -G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER P
PLV 1-B BOWL LOWER P
PLV -C BOWL LOWER P
PLV -D BOWL LOWER P
PLV -E BOWL LOWER P
PLV -F BOWL LOWER P
PLV -A BOWL Dirr. P
PLV -B BOWL Dirr. P
PLV -C Bowl Dirr. P
PLV -D BOWL Dirr. P
PLV -E BOWL Dirr. P
PLV -F BOWL Dirr. P
PLV -A COAL AIR OUT. P
PLV -B COAL AIR OUT. P
PLV -C COAL AIR OUT. P
PLV 1-D COAL AIR OUT. P
PLV 1-E COAL AIR OUT. P
PLV 1-F COAL AIR OUT. P
PLV 1-A PRI. AIR IN. FLOW
PLV 1-B PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-D PRI. AIR IN. FLOW
PLV 1-E PRI. AIR IN. FLOW
PLV 1-F PRI. AIR IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
MW
.
IN. HO
IN. H,0
IN. H|0
IN. HO
IN. H|0
IN. H20
IN. HaO
IN. H20
IN. HjjO
IN. H-0
IN. H|O
IN. HgO
IN. HgO
IN. HgO
IN. H~0
IN. HgO
IN. HgO
IN. HeO
0-125?!
0-125*
0-1 25*
0-125*
1-125*
0-125*
"F
J.
5/19
16:15
505
797
770
95
NA
698
70S
474
674
676
'676
680
678
836
840
998
1012
1002
476
473
982
1026
616
408
405
472
473
411
378
20.6
24.0
21.6
23.0
22.3
-1.5
6.90
7.88
7.15
7.66
6.92
0.06
9.30
11.97
10.51
10.98
10.83
-1.64
127
129
129
126
129
0
143
2
5/19
13:50
506
777
768
93
NA
700
694
474
674
676
677
680
678
832
832
1012
997
1000
475
474
1002
1011
618
408
405
472
473
412
379
20.7
23.8
21.9
23.0
-1.1
19.5
6.94
7.79
7.29
7.80
0.12
6.73
9.45
11.86
10.66
11.02
-1.25
9.31
127
128
130
125
0
124
143
3
3/12
07:15
524
836
823
68
104
732
724
478
676
678
678
682
680
856
873
1008
1014
1008
479
482
1014
1015
628
412
412
479
479
415
378
21.7
23.4
0.2
23.6
21.9
18.9
7.79
8.11
0.04
8.09
7.04
6.64
10.13
11.69
-0.13
11.15
11.32
9.08
125
128
38
126
128
125
143
4
5/19
11:00
506
770
758
85
NA
693
683
474
674
676
676
680
678
835
849
996
1016
1001
476
473
1000
1017
617
408
406
472
473
412
376
-0.4
23.6
22.3
23.0
22.2
20.1
0.44
7.68
7.18
7.73
6.94
6.93
-1.24
11.74
10.86
11. 05
10.88
9.70
0
129
129
126
130
125
88
5
5/12
11:00
422
716
685
80
NA
650
643
451
671
672
673
677
674
821
808
1005
1003
1003
574
527
997
1002
580
389
388
451
451
391
358
21.0
24.2
23.4
-0.2
22.3
-0.1
7.23
8.25
7.74
-0.00
7.17
-0.02
6.05
11.79
11.22
0.06
10.77
0.11
127
129
131
0
126
0
143
6
5/12
09:2O
422
706
674
74
NA
639
634
452
670
672
672
677
674
834
813
1005
1001
1001
586
585
1003
1004
579
389
368
450
451
391
356
21.0
23.7
23.7
-0.2
22.3
-0.1
7.22
8.00
7.85
-0.02
7.10
-0.03
6.05
11.51
11.32
0.06
10.80
0.11
127
128
130
0
126
0
143
7
5/16
09:30
421
722
596
82
NA
637
636
451
670
672
673
677
674
829
836
995
1017
1002
588
587
974
1023
580
389
388
450
451
390
358
-0.4
23.8
23.0
23.4
21.8
0.1
0.44
7.86
7.65
7.72
6.93
0.00
-1.37
11.89
11.19
11.28
10.71
0.03
0
129
129
125
126
0
87
8
5/21
03:10
320
661
655
80
NA
608
608
425
666
667
667
672
669
917
873
1006
999
1002
427
426
998
992
547
368
367
424
424
367
338
18.5
20.0
19.7
19.6
-1.0
-1.4
6.34
6.46
6.62
6.68
0.19
0.06
8.20
10.04
9.58
9.15
-1.17
-I.3B
127
128
131
126
0
0
143
9
6/27
09:40
314
610
•NA
101
NA
561
563
417
666
667
663
418
668
833
823
999
999
NA
540
539
924
932
533
NA
356
NA
416
NA
332
17.0
20.7
0.1
X.3
18.1
16.8
5.89
6.64
0.02
0.05
5.97
5.78
7.41
10.38
0.17
30.20
8.72
8.38
123
127
51
31
126
130
146
* C - COMPUTER DATA; B - BOARD DATA; NA NOT AVAILABLE.
227
SHEET A44
-------
WISCONSIN POWER & LIGHT Co.
COLUMB tA
C-E POWER SYSTEMS
FIELD TtsriNo AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD i COMH1TER DATA
•c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE
TIME
LOAD
TENPERATURES
AIR £ GAS - °F
ECON. N GAS OUT.
ECON. S GAS OUT.
1-A PA FAN DISCH. HDR.
1-B PA FAN DISCH. HDR.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM 4 WATER - *F
BOILER ECON. IN.
Do UN COMER 1
DOWNCOMER 2
DOWNCOMER' 3
DOVHCOMER 4
DOWNCOMER 5
BLR. SH ATM3 1-A STM. IN.
BLR. SH ATW 1-B STM. IN.
BLR. S SH HOR. OUT.
BLR. N SH HOR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STM. OUT. A
BLR. N RH ATM1 STM. OUT. B
BLR. S RH HDD. OUT. A
BLR. N RH HDR. OUT. 8
HP HTR. 1-GI & 1-G2 EXTR. STM
HP HTR. 1-F1 FW OUT.
HP HTR. 1-F2 FW OUT.
HP HTR. 1-GI FW OUT.
HP HTR. 1-G2 FW OUT.
HP HTR. 1-GI DRAIN
HP HTR. 1-G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER P
PLV 1-B BOWL LOWER P
PLV 1-C BOWL LOWER P
PLV 1-D BOWL LOWER P
PLV 1-E BOWL LOWER P
PLV 1-F BOWL LOWER P
PLV 1-A BOWL Dir . P
PLV 1-B BOWL DIF . P
PLV 1-C BOWL DIF . P
PLV 1-D BOWL Di . P
PLV 1-E BOWL Di . P
PLV 1-F BOWL Di . P
PLV 1-A COAL Ai OUT. P
PLV 1-8 COAL Ai OUT. P
PLV 1-C COAL Ai OUT. P
PLV 1-D COAL AIR OUT. P
PLV -E COAL AIR OUT. P
PLV -F COAL AIR OUT. P
PLV -A PRI. AIR In. FLOW
PLV -B PRI. AIR IN. FLOW
PLV -C PRI. AIR IN. FLOW
PLV -D PRI. AIR IN. FLOW
PLV -E PRI. AIR IN. FLOW
PLV -F PRI. AIR IN. FLOW
PLV -A COAL AIR DISCH. TEMP.
1976
MW
IN. Hj>0
IN. HTO
IN. H|0
IN. Hfo
IN. HO
IN. HgO
IN. HgO
IN. HgO
IN. H-0
IN. HgO
IN. HgO
IN. HO
IN. HJSO
IN. H-0
IN. HgO
IN. HgO
IN. H-0
IN. HgO
0-125*
0-125*
0-125*
0-1 25*
0-125*
1-125*
•F
JO
5/23
11:05
324
642
557
83
•NA
578
574
424
665
668
669
673
670
850
821
1006
1005
1005
552
551
963
978
546
366
366
424
424
366
335
-0.3
-1.3
19.4
19.3
19.7
18.1
0.44
0.20
6.34
6.47
6.16
6.14
-1.15
-1.28
9.46
9.34
9.75
9.07
0
31
131
126
129
124
84
11
5/19
18:35
491
791
701
94
NA
702
697
471
673
675
676
679
677
844
851
992
1018
1001
472
470
983
1027
612
405
404
469
470
409
376
20.6
24.0
21.5
22.7
22.0
-1.4
6.83
7.74
7.12
7.60
6.84
O.O6
9.36
12.00
10.50
10.91
10.93
-1.40
127
129
130
125
129
0
143
J2
5/10
09:50
497
803
788
86
NA
713
713
473
673
674
675
679
676
865
863
1011
1O05
1005
472
471
982
1021
618
407
406
472
472
410
376
21.5
25.3
23.9
-0.3
23.5
22.4
7.28
8.30
7.82
0.29
7.34
7.38
8.99
12.55
11.70
-0.70
11.51
10.90
127
129
130
49
126
126
146
_13
3/16
1O:00
522
803
810
53
61
710
699
480
678
680
680
684
681
846
868
999
1019
1004
481
482
989
1030
624
413
412
480
480
416
384
21.4
-0.0
24.4
23.6
22.7
21.2
7.54
0.01
8.43
8.06
7.25
7.30
9.86
0.43
11.27
11.43
11.80
10.60
126
42
131
125
128
126
145
14
5/12
13:45
422
737
631
86
NA
661
653
452
671
672
673
677
675
828
819
1004
1005
1000
578
500
999
1004
580
389
38S
451
451
391
360
20.7
24.0
23.2
-0.2
22.0
-0.1
7.11
8.18
7.72
0.02
7.16
-0.01
6.12
11.68
11.09
0.06
10.57
0.11
127
128
130
0
126
0
144
J5
3/13
15:30
400
715
722
58
80
641
627
447
672
674
674
678
676
827
837
1003
1021
1009
588
587
998
1012
580
386
386
448
448
387
359
18.3
18.9
0.2
19.8
19.8
17.6
6.58
6.67
0.02
6.84
6.44
6.18
8.37
9.55
-0.23
9.45
10.29
8.52
125
128
0
125
128
125
144
_16
5/16
11:45
422
748
612
82
NA
649
648
451
670
672
673
677
674
828
845
990
1022
999
588
587
969
1037
577
389
388
450
451
391
358
-0.5
24.0
23.0
23.6
21.9
0.1
0.44
7.97
7.73
7.82
6.94
0.00
-1.41
11.85
11.14
11.34
10.66
0.09
0
129
131
125
126
0
88
17
5/21
01:15
320
676
673
82
NA
619
620
424
665
667
668
672
669
915
870
1004
1006
1003
427
427
995
995
545
367
366
424
423
366
337
18.3
20.6
19.5
19.7
-1.1
-1.3
6.31
6.61
6.53
6.72
0.17
0.06
8.17
10.13
9.48
9.23
-1.35
-1.54
127
129
132
126
0
0
143
18
5/23
09:10
323
653
538
78
NA
567
556
424
665
667
668
673
670
855
827
1003
1008
1003
552
551
973
980
545
367
365
423
424
366
334
-0.3
-1.5
19.8
19.3
19.9
18.2
0.44
0.21
6.47
6.48
6.21
6.12
-1.16
-1.35
9.78
9.36
9.85
8.98
0
32
131
126
130
124
79
C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE-.
228
SHEET
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA 11
C-E POWER SYSTEMS
FIELD TESTINC AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD t COMPUTER DATA
•C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
"B
B
B
B
8
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
6
B
B
e
B
B
8
B
C
C
C
C
C
TEST NO.
DATE 1976
TIME
LOAD MW
PULVERIZER DATA
PLV 1-6 COAL AIR DISCH. TEMP. °F
PLV UC COAL AIR DISCH. TEMP. °F
PLV 1-D COAL AIR DISCH. TEMP. T
PLV 1-E COAL AIR DISCH. TEMP. V
PLV 1-F COAL AIR DISCH. TEMP. , °F
PLV 1-A FEEDER COAL FLOW 10,LB/HR
PLV 1-B FEEDER COAL FLOW 10,LB/HR
PLV -C FEEDER COAL FLOW lOILBAff
PLV -D FEEDER COAL FLOW lOILB/HR
PLV -E FEEDER COAL FLOW lois/HR
PLV -F FEEDER COAL FLOW 1CTLB/H?
PLV -A MILL AWS
PLV -B MILL AMPS
PLV -C MILL AMPS
PLV -D MILL AMPS
PLV -E MILL AMPS
PLV 1-F MILL AMPS
FAN DAMPER POSITION - % OPEN
1-A FD FAN INLET VANE
1-B FO FAN INLET VANE
1-A PA FAN INLET VANE
1-B PA FAN INLCT VANC
SPRAY VALVE POSITION - % OPEN
1-A SH SPRAT VALVE
1-B SH SPRAT VALVE
1-A RH SPRAY VALVE
1-B RH SPRAT VALVE
MISCELLANEOUS
BURNER TILT + DEGREES
Aux. AIR DAMPERS ~ f OPEN
1-A FUEL/AIR DAMPERS % OPEN
1-B FUCL/AIR DAMPERS % OPEN
1-C FUEL/AIR DAMPERS * OPEN
1-D FUEL/AIR DAMPERS i OPEN
1-E FUEL/AIR DAMPCRS % OPEN
1-F FUEL/AIR DAMPERS t OPEN
1-A PRI. AIR FAN AMPS
1-B PRI. AIR FAN AMPS
1-A ID FAN AMPS
1-B ID FAN AMPS
1-A FD FAN AWS
1-B FO FAN AWS
1-A ID FAN RPM
1-B ID FAN RPM
1-A BLR. CIRC. WTH. PUMP AMPS
1-B BLR. CIBC. WTR. PUMP AMPS
l-C BLR. CIRC. WTR. PUHP AMPS
1-D BLR. CIRC. WTR. PUMP AWS
N DRUM LEVEL + NORM. HgO LEVEL IN.
S DRUM LCVEL + NORM. HgO LEVEL IN.
FLUE GAS COMBUSTIBLES %
FLUE GAS OXYOEN *
BARONMCTRIC PRESS. IN. HGA
1
5/19
16:15
505
144
145
142
138
159
115
116
116
116
116
0
70
74
73
75
75
0
78
77
36
31
29
21
46
34
0°
39
100
100
100
100
100
100
173
183
460
410
218
198
465
495
74
78
73
74
-0.73
-3.26
0.063
3.3
29.76
2
5/19
13:50
506
144
145
143
128
142
115
116
166
116
0
116
71
74
73
75
0
76
75
74
36
31
24
13
55
50
-4*
29
100
100
100
100
100
100
173
184
460
390
205
180
480
488
75
79
73
76
-0.42
-0.27
0.067
2.6
29.83
3
3/12
07:15
524
145
49
146
142
145
120
120
0
118
112
113
76
75
0
78
76
73
71
70
30
25
55
27
100
100
-3°
66
54
55
100
55
50
44
170
180
480
400
197
183
480
480
73
76
71
74
-0.64
-2.38
0.062
3.5
28.95
4
5/19
11:00
506
143
144
142
138
142
0
116
116
116
116
116
0
72
72
75
75
75
74
72
35
30
40
24
43
32
-9°
31
100
100
100
100
100
100
175
185
460
390
205
183
477
488
75
79
75
78
-0.80
-1.40
0.066
3.4
29.97
5
5/12
11:00
422
144
146
107
139
118
116
119
117
0
117
0
72
75
71
0
78
0
70
68
30
24
11
8
2
1
-4*
21
100
100
100
0
100
100
166
173
370
330
193
180
418
423
80
81
76
80
-0.48
-1.45
0.062
3.9
30.04
6
5/12
09:20
422
143
146
106
140
117
113
115
115
0
114
0
70
74
72
0
76
0
67
65
29
23
17
12
1
0
+1"
17
100
100
37
100
1OO
0
165
173
350
300
180
161
390
397
80
32
78
81
-0.82
-2.83
0.065
3.6
30.09
7
5/16
09:30
421
144
146
142
139
78
0
117
117
117
117
0
0
74
73
75
78
0
71
70
31
25
22
0
0
0
+11*
25
100
100
100
100
100
0
165
175
390
320
195
181
435
438
80
83
78
80
-0.76
-2.43
0.062
4.1
29.54
8
5/21
03:10
320
141
145
143
100
110
65
87
87
88
0
0
63
65
66
65
0
0
53
51
32
26
40
46
13
10
+6°
0
7B
81
86
81
100
100
168
175
260
300
158
145
298
305
80
83
78
81
-0.79
-2.56
0.060
4.0
30.01
9
6/27
09:40
314
153
*NA
T17
142
145
83
85
NA
NA
64
82
64
66
NA
NA
66
66
59
62
28
28
8
12
0
0
+6°
0
77
77
100
100
75
75
160
195
300
280
169
150
330
NA
83
87
NA
84
-0.69
-2.57
0.055
5.1
30.10
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
229
SHEET A46
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
FIELD TESTING AND
RESULTS
BIASED FIRING OPERATION STUDY
BOARD t COUNTER DATA
*c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
,B
B
B
B
B
B
B
B
B
B
6
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
TEST NO.
DATE
TIME
LOAD
PULVERIZER DATA
PLV 1-B COAL AIR DISCH. TEMP.
PLV 1-C COAL AIR DISCH. TEMP.
PLV 1-D COAL AIR DISCH. TEMP.
PLV 1-E COAL AID DISCH. TEMP.
PLV 1-F COAL AIR DISCH. TEMP.
PLV 1-A FEEDER COAL FLOW 101;
PLV 1-B FEEDER COAL FLOW 10"
PLV 1-C FEEDER COAL FLOW 10^
PLV -D FEEDER COAL FLOW 10^
PLV -E FEEDER COAL FLOW 10):
PLV -F FEEDER COAL FLOW ion
PLV -A MILL
PLV -B MILL
PLV -C MILL
PLV -D MILL
PLV -E MILL
PLV -F MILL
FAN DAMPER POSITION - % OPEN
1-A FD FAN INLET VANE
1-B FD FAN INLET VANE
1-A PA FAN INLET VANE
l-B PA FAN INLET VANE
SPRAY VALVE POSITION - * OPEN
1-A SH SPRAY VALVE
1-B SH SPRAY VALVE
1-A RH SPRAY VALVE
1-B RH SPRAY VALVE
MISCELLANEOUS
BURNER TILT + DEC
Aux. AIR DAMPERS f
-A FUEL/AIR DAMPERS %
-B FUEL/AIR DAMPERS f
-C FUEL/AIR DAMPERS %
-D FUEL/AIR DAMPERS f
-E FUEL/AIR DAMPERS t
1-F FUEL/AIR DAMPERS %
1-A PRI. AIR FAN
1-B PRI. AIR FAN
1-A ID FAN
1-B ID FAN
1-A FD FAN
1-B FD FAN
1-A ID FAN
1-B ID FAN
1-A BLR. CIRC. WTR. PUMP
1-B BLR. CIRC. WTR. PUMP
1-C BLR. CIRC. WTR. PUMP
1-D BLR. CIRC. WTR. PUMP
N DRUM LEVEL + NORM. HgO LEVEL
S DRUM LEVEL 7 NORM. HO LEVEL
FLUE GAS COMBUSTIBLES
FLUE GAS OXYGEN
BARONMETRIC PRESS. IN
1976
Mrf
•F
•F
'F
•F
•F
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
LB/HR
AMPS
AMPS
AMDS
AMPS
AMPS
AMPS
SEES
OPEN
OPEN
OPEN
OPEN
OPEN
OPEN
OPEN
AMPS
AMPS
AMPS
AMPS
AMPS
AMPS
RPM
RPM
AMPS
AKPS
AMPS
AMPS
IN.
IN.
«{
<
HGA
10
5/23
11:05
324
130
144
141
138
142
•NA
NA
87
88
88
86
0
0
67
65
67
66
57
56
31
25
14
e
0
0
+5°
0
0
0
87
83
81
78
169
179
280
310
166
155
320
323
83
84
79
84
-0.51
-2.3E
0.064
4.4
30.10
11
5/19
18:35
491
143
145
143
138
141
106
108
107
108
107
0
68
72
72
74
75
0
79
77
36
31
50
33
48
34
+2"
40
100
100
100
100
100
100
173
183
500
420
225
198
488
496
73
77
73
74
-0.76
-3.22
0.064
3.5
29.73
J2
5/10
09:50
497
152
150
91
152
162
114
116
114
0
114
112
73
73
73
0
75
70
77
76
37
32
68
57
81
58
-4°
34
100
100
100
100
100
1OO
175
185
490
420
213
196
482
500
73
77
72
73
-0.75
-3.12
0.061
3.8
29.66
J3
3/16
10:00
522
83
149
147
143
146
116
0
114
116
116
115
72
0
74
75
75
75
70
70
28
24
65
28
61
62
-3°
81
51
100
51
54
52
51
171
185
500
430
204
197
480
490
75
76
71
75
-0.68
-2. 88
0.062
4.3
29.82
14
5/12
13:45
422
144
147
110
139
121
117
118
118
0
117
0
71
75
73
0
78
0
74
73
30
25
15
3
4
3
-3°
30
100
100
100
0
100
100
165
170
410
340
203
187
445
457
79
80
75
79
-0.54
-1.33
0.062
4.9
29.91
15
3/13
15:30
400
146
45
147
142
145
86
87
0
86
87
85
65
65
0
67
67
67
64
63
29
24
23
6
0
0
+1°
50
32
33
100
34
33
33
175
182
390
320
187
175
430
430
80
82
78
79
-0.61
-1.48
0.065
5.5
29.99
16
5/16
11:45
"422
144
146
143
139
78
0
117
117
118
118
0
n
75
74
75
77
0
75
74
31
26
23
4
0
0
+6°
39
100
100
100
100
100
0
166
175
443
367
210
195
463
478
79
81
75
77
-0.47
-3.26
0.062
5.1
29.55
17
5/21
01:15
320
144
145
143
111
118
85
87
86
87
0
0
63
67
66
66
0
0
60
59
32
26
39
47
15
10
+9"
0
76
81
84
80
0
0
165
175
300
310
171
158
345
340
79
82
77
80
-0.53
-2.5J
0.059
5.B
29.92
1§
5/23
09:10
323
152
143
138
138
141
0
0
88
89
89
70
0
0
66
66
66
65
61
60
31
25
15
12
0
0
+6°
0
0
0
89
84
82
79
168
178
300
310
175
165
338
345
81
84
78
83
-0.62
-2.22
0.065
6.0
30.14
C - COMPUTER DATA; B - BOARD DATA; NA - Not AVAILABLE.
230
SHEET A4
-------
WISCONSIN POWER * LIGHT Co.
COLUMBIA |1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
BOARD t COMPUTER DATA
I 2 3
DATE
TIME
»C LOAD
1976
Mrf
FLOWS - IQ^B/HR
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
. C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
*B
C
C
C
C
C
C
C
C
C
C
FEEDWATER
SUPERHEAT' SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY L
REHEAT SPRAY R
BFP TURB. EXTR. STM. FLOW 1-A
8FP TURB. EXTR. STM. FLOW 1-B
BFP TURB. MN. STM. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM & WATER - PSIG
FEEDWATER TO CCON.
BOILER DRUM
TURBINE THROTTLE
TURBINC IST STAGE
HP HTR. 1-G1 i 1-G2 STEAH IN.
AIR I GAS - IN H&>
FD FAN 1-A DISCHARGE
FD FAN 1-B DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURN. LEFT WINDBOX
RT. WDBX TO FURN. DIFF. P
LEFT.WDBX TO FURN. DIFF. P
FURNACE
PRI. SH GAS OUT.
REHEATER GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IK.
A I R HTR . 1 -A GAS OUT .
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCHARGE
IDF 1-B DISCHARGE
PAF 1-A DISCHARGE HDR.
PAF 1-B DISCHARGE HDR.
PRI. HOT AIR DUCT
TEMPERATURES
AIR & GAS - °F
1-A FD FAN DISCHARGE
-8 FD FAN DISCHARGE
-A AH AIR IN.
-B AH AIR IN.
-A AH AIR OUT.
-B AH AIR OUT.
-A AH GAS IN.
-B AH GAS IN.
-A AH GAS OUT.
-B AH GAS OUT.
3/17
09:30
517
3083
101
109
78
82
0
0
7.6
1606
1557
2723
2673
2400
1624
529
5.56
9.16
7.75
7.19
3.60
3.38
2.22
2.20
3.39
3.96
-0.53
-0.63
-0.56
-2.48
-6.45
-8.93
-8.60
-15.5
-14.1
-0.5B
-0.62
32.95
32.74
30
44
52
75
78
712
734
778
783
274
275
3/17
10:45
512
3084
102
105
78
82
0
O
7.5
1604
1556
2722
2672
2402
1616
527
5.54
9.13
7.77
7.18
3.64
3.46
2.25
2.25
3.43
4.02
-0.49
-0.70
-0.63
-2.49
-6.46
-8.92
-8.60
-15.6
-14.0
-0.58
-0.63
32.93
32.80
30
45
53
75
78
714
736
780
785
274
275
3/20
16:50
524
3367
14
43
42
66
0
0
8.2
1609
1576
2750
2689
2397
1677
537
6.04
10.20
8.41
7.82
4.00
3.92
2.42
2.52
3.16
3.92
-0.18
-0.50
-0.31
-2.04
-5.84
-7.96
-7.74
-14.6
-13.1
-0.04
-0.04
33.42
33.40
30
72
81
86
88
696
721
758
768
281
280
3/20
19:45
525
3331
56
42
48
70
0
0
8.2
15E4
1535
2750
2689
2399
1682
540
5.77
9.63
8.10
7.62
3.80
3.73
2.47
2.50
3.18
3.99
-0.27
-0.57
-0.47
-2.32
-5.94
-8.13
-7.94
-14.6
-13.3
-0.23
-0.20
33.24
33.18
30
67
76
82
84
707
739
769
785
282
286
3/22
17:00
526
3233
95
94
50
72
0
0
8.0
1582
1539
2741
2687
2398
1580
541
5.38
8.91
7.50
6.93
3.39
3.40
2.27
2.25
3.23
3.87
-0.48
-0.72
-0.64
-2.45
-6.11
-8.72
-8.19
-15.4
-13.9
-0.44
-0.39
33.00
32.87
30
59
67
79
82
691
72O
757
762
272
275
3/20
10:05
521
3480
0
12
10
15
0
0
8.5
1486
1474
2766
2699
24O1
1689
526
5.20
8.54
7.07
6.56
3.36
3.37
2.10
2.14
3.18
4.01
-0.39
-0.70
-0.42
-2.02
-5.38
-7.67
-7.08
-13.0
-11.9
-0.09
0.11
33.48
33.32
30
77
83
93
96
553
673
709
714
266
269
3/20
12:00
522
3372
0
25
35
59
0
0
8.4
1480
1472
2754
2692
2403
1680
536
5.42
8.84
7.23
6.63
3.43
3.34
2.12
2.12
3.13
3.90
-0.56
-0.65
-0.58
-2.20
-5.64
-7.68
-7.38
-13.6
-12.2
-0.10
-0.08
33.53
33.42
30
75
82
90
93
673
696
730
738
874
272
3/20
14:30
522
3388
0
'31
39
63
0
0
8.2
1486
1470
2756
2692
2399
1682
536
5.32
8.69
7.21
6.57
3.38
3.36
2.16
2.21
3.18
3.96
-0.60
-0.81
-O.61
-2.24
-5.58
-7.64
-7.42
-13.6
-12.4
-0.11
-O.07
33.44
33.44
30
77
85
93
94
681
705
738
746
279
278
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
231
SHEET A48
-------
WISCONSIN POWER I LIGHT Co.
COLUMBIA It
C-E POWER SYSTEMS
FIELD TEST mo AND
PERFORMANCE: RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
BOARD & COMPUTER DATA
9 10 11
12
13
14
15
16
DATE
TIME
•C LOAD
1976
MW
FLOWS - IQ^B/HB
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
•B
C
C
C
C
C
C
C
C
C
C
FEEDWATER
SUPERHEAT SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY L
REHEAT SPRAY R
BFP TURB. EXTR. STM. FLOW
BFP TURB. EXTR. STM. FLOW
1-A
1-6
BFP TURB. MM. STH. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM, & WATER - PSIG
FEEDWATER TO CCON.
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STAGE
HP HTR. 1-G1 & 1-G2 STEAM
AIR £ GAS - IN HpO
FD FAN 1-A DISCHARGE
FD FAN 1-B DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
A I R HTR . 1 -A A i R OUT .
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURH. LEFT WINDBOX
RT. WDBX TO FURN. DIFF. P
LEFT WDBX TO FUHN. DIFF. P
FURNACE
PHI. SH GAS OUT.
REHEATED GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCHARGE
IDF 1-B DISCHARGE
PAF 1-A DISCH. HDR.
PAF 1-B DISCH. HDR.
PRI. HOT AIR DUCT
TEMPERATURES
AIR & GAS - °F
1-A FD FAN DISCH.
1-B FD FAN DISCH.
1-A AH AIR IN.
1-B AH AIR IN.
1-A AH AIR OUT.
1-B AH AIR OUT.
1-A AH GAS IN.
1-B AH GAS IN.
1-A AH GAS OUT.
1-B AH GAS OUT.
IN.
3/24
00:45
473
2912
56
79
45
61
0
0
6.6
166B
1614
2691
2644
2405
1496
485
6.24
11.72
8.94
B.41
4.44
4.53
3.14
3.06
3.67
4.24
-0.14
-0.3B
-0.25
-1.99
-6.00
-8.30
-7.70
-14.8
-13.2
-0.16
0.05
32.92
32.92
30
66
75
60
83
693
716
758
760
272
272
3/24
02:20
473
2834
59
78
46
62
0
0
6.4
1658
1613
2684
2637
2401
1465
478
6.08
10.30
8.54
7.93
4.11
4.13
2.68
2.57
3.16
3.92
-0.23
-0.27
-0.16
-2.00
-5.90
-8.39
-7.82
-14.8
-13.4
-0.28
-0.12
33.00
32.86
30
62
71
77
80
698
720
764
767
273
270
3/24
04:00
472
2800
84
91
57
70
0
0
6.1
1543
1510
2675
S631
2400
1456
480
5.58
9.30
7.70
7.11
3.57
3.61
2.39
2.39
3.20
4.00
-0.44
-0.76
-0.59
-2.36
-5.76
-7.88
-7.26
-14.0
-12.6
-0.36
-0.21
32.86
32.77
30
60
70
76
79
701
725
764
768
273
274
6/24
12:00
524
3297
70
79
28
63
43
77
8.1
1767
1663
2746
2691
2401
1680
538
14.98
13.58
11.51
10.42
7.05
7.05
5.41
5.40
5.47
6.13
-0.53
-0.68
-1.18
-2.23
-6.52
-8.55
-8.39
-15.2
-14.2
0.29
0.36
32.61
33.95
30
78
87
91
92
665
692
720
736
265
271
6/24
13:20
525
3289
82
94
50
77
43
76
8.0
1774
1668
2745
2691
2402
1679
538
15.15
13.55
11.59
10.54
7.01
7.00
5.33
5.29
5.43
6.13
-0.61
-0.71
-1.25
-2.36
-6.64
-8.82
-8.68
-15.5
-14.7
0.21
0.28
32.60
33.88
30
80
90
92
94
670
702
725
744
270
275
6/24
09:45
523
3327
70
78
10
50
43
76
8.1
1785
1683
2744
2686
2402
1679
531
15.12
13.71
11.63
10.56
7.03
6.98
5.37
5.31
5.45
6.09
-0.43
-0.65
-1.11
-2.31
-6.51
-8.86
-8.71
-15.5
-14.6
0.26
0.32
32.50
33.75
30
75
83
87
88
658
681
714
723
260
265
3/25
10:15
510
3079
97
98
67
76
0
0
7.6
1477
1454
2720
2670
2394
1614
522
5.37
8.52
7.53
6. IS
3.59
3.58
2.39
2.43
3.14
3.94
-0.45
-0.67
-0.54
-2.27
-5.76
-7.72
-7.39
-14.0
-12.7
-0.35
-0.29
33.22
33.09
30
59
70
79
82
695
'22
758
764
272
283
6/30
09:50
526
3255
85
95
33
60
43
B9
8.0
1739
1637
2751
2698
2405
1687
535
14.75
13.35
11.45
10.34
7.13
7.01
5.38
5.38
5.46
6.13
-0.43
-0.64
-1.08
-2.23
-6.21
-8.48
-8.47
-14.6
-13.9
0.07
0.04
32.82
33.49
30
75
79
86
87
663
677
722
725
260
264
C - COMPUTER DATA; B - BOARD DATA; NA . NOT AVAILABLE.
232
SHEET
-------
WISCONSIN POWER A LIGHT Co.
COLUMBIA |1
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
BOARD 1 COMPUTER DATA
17 18 19
20
21
22
23
DATE
TIME
«C LOAD
1976
riOWS - 103LB/HR
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
«B
C
C
C
C
C
C
C
C
C
C
FEEDVATER
SUPERHEAT. SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY L
REHEAT SPRAY R
8FP TURB. EXTH. STM. FLOW 1-A
BFP TURB. EXTR. STM. FLOW 1-B
BFP TURB. MN. STM. FLOW COMBINED
HOT AIR TO BURNERS L WINDBOX
HOT AIR TO BURNERS R WINDBOX
PRESSURES
STEAM & WATER - PSIG
FEEDWATER TO ECON.
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STAGE
HP HTR. 1-G1 I 1-G2 STEAM IN.
AIR & GAS - IN HaP
FD FAN 1-A DISCHARGE
FD FAN 1-B DISCHARGE
AIR HTR. 1-A AIR IN.
AIR HTR. 1-B AIR IN.
AIR HTR. 1-A AIR OUT.
AIR HTR. 1-B AIR OUT.
FURN. RIGHT WINDBOX
FURN. LEFT WINOBOX
RT. WDBX TO FURN. DIFF. P
LEFT WDBX fo FURN. DIFF. P
FURNACE
Pni. SH GAS OUT.
REHEATER GAS OUT.
ECON. GAS IN.
ECON. GAS OUT.
AIR HTR. 1-A GAS IN.
AIR HTR. 1-B GAS IN.
AIR HTR. 1-A GAS OUT.
AIR HTR. 1-B GAS OUT.
IDF 1-A DISCHARGE
IDF 1-B DISCHARGE
PAF 1-A DISCH. HDR.
PAF 1-B DISCH. HOR.
PRI . HOT AIR DUCT
TEMPERATURES
AIR & GAS - °F
1-A FD FAN DISCH.
1-B FD FAN DISCH.
1-A AH AIR IN.
1-B AH AIR IN.
1-A AH AIR OUT.
1-B AH AIR OUT.
1-A AH GAS IN.
1-B AH GAS IN.
1-A AH GAS OUT.
1-B AH GAS OUT.
6/25
11:15
524
3262
138
103
40
68
43
76
a. 3
1793
1674
2739
2E8B
2411
1671
534
15.24
13.82
11.76
10.71
7.09
6.95
5.41
5.40
5.46
6.44
-0.52
-0.74
-1.24
-2.43
-6.68
-8.79
-8.83
-15.6
-14.6
0.18
0.11
32.63
33.78
30
81
86
93
93
667
695
724
737
270
273
6/30
08:35
526
3284
80
100
23
53
43
89
8.1
1777
1649
2751
2699
2406
1697
535
14.86
13.27
11.26
10.39
7.12
6.91
5.33
5.35
5.41
6.02
-O.47
-0.60
-1.03
-2.21
-6.18
-8.50
-8.51
-14.7
-14.2
0.11
0.06
32.79
33.77
30
74
78
84
85
651
657
711
712
255
255
6/29
08:50
523
3262
88
89
40
58
43
89
8.3
1611
1529
2751
2696
2403
1685
535
14.19
12.57
11.02
9.89
6.91
6.76
5.30
5.36
5.43
6.07
-0.54
-0.67
-1.12
-2.24
-5.83
-7.78
-7.83
-13.8
-13.2
-0.01
0.06
32.77
34.16
30
73
81
85
87
665
690
725
732
259
270
6/25
14:45
517
3203
101
100
53
78
42
74
7.8
1704
1607
2745
2694
2416
1644
499
14.69
13.36
11.30
10.09
6.90
6.82
5.36
5.29
5.45
6.17
-0.54
-0.92
-1.38
-2.33
-6.32
-8.52
-8.50
-14.8
-14.2
0.09
0.13
32.74
33.89
30
87
91
99
101
680
708
734
750
277
282
6/26
10:30
419
2651
35
34
0
2
43
81
8.6
1453
1365
2652
2607
2405
1305
411
12.78
11.02
9.78
8.71
6.34
6.42
5.41
5.39
5.44
6.15
-0.52
-0.70
-1.03
-1.70
-4.43
-6.28
-6.14
-10.6
-9.9
-0.26
n.04
31.73
32.61
30
8B
93
100
103
606
627
654
663
244
262
6/25
16:S5
422
2517
77
80
0
37
39
72
6.3
1346
1241
2638
2598
2404
1291
416
10.97
9.26
8.35
7.23
5.28
5.32
4.28
4.00
4.03
5.12
-0.53
-0.77
-1.13
-1.80
-4.44
-6.09
-6.26
-10.7
-10.2
-0.23
-0.16
32.50
33.76
30
B9
95
102
104
634
661
687
702
259
275
6/27
11:35
316
2062
0
2
0
3
34
89
0.0
1006
944
2571
2533
2408
984
306
6.36
4.99
4.66
3.95
2.86
2.76
2.33
2.26
1.35
3.00
-0.51
-0.71
-0.90
-1.26
-2.71
-3.81
-3.99
-6.29
-6.19
-0.32
-0.32
31.75
32.64
30
89
94
102
104
535
555
580
584
see
233
6/29
01:30
322
1891
56
61 '
0
3
39
89
7.1
1022
952
2559
2527
2405
975
309
6.51
5.26
4.80
4.09
2.27
2.87
2.42
2.42
1.56
3.10
-0.54
-n.64
-0.85
-1.32
-2.77
-3.87
-4.02
-6.53
-6.46
-0.50
-0.49
31.84
32.98
30
83
90
96
97
568
592
614
629
226
241
C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
233
SHEET A50
-------
WISCONSIN POWER £ LIGHT Co.
COLUMBIA #1
C-E POWER SYSTEMS
FIELD TESTiNO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
BOARD i COMPUTER DATA
1 2 3
*c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
DATE
TIME
LOAD
TEMPERATURES
AIR i GAS - "F
ECON. N G»s OUT.
ECON. S GAS OUT.
1-A PA TAN DISCM. Hon.
1-B PA TAN DISCH. Hon.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM & WATER - °F
BOILER ECON. IN.
DOWNCOMER 1
OOWNCOMER 2
DOWNCOMER 3
DOWNCOMER 4
DOWNCOMER 5
BLR. SH ATM3 1-A STH. IN.
BLR. SH ATHP 1-B STM. In.
BLR. S SH HDR. OUT.
BLR. N SH HDR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STM. OUT. A
BLR. N RH ATW STH. OUT. B
BLR. S RH HDD. OUT. A
BLR. N RH HDR. OUT. B
HP HTR. 1-G1 t 1-G2 EXTR. STM
HP HTR . 1 -F1 FV OUT.
HP HTR. 1-F2 FW OUT.
HP HTH. 1-G1 FW OUT.
HP HTR. 1-G2 FW OUT.
HP HTR. 1-G1 DRAIN
HP HTR. 1-G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER
PLV 1 -B BOWL LOWER
PLV 1-C BOWL LOWER
PLV 1-D BOWL LOWER
PLV 1-E BOWL LOWER
PLV 1-F BOWL LOWER
PLV 1-A BOWL DIFF.
PLV 1-B BOWL DIFF.
PLV 1-C BOWL DIFF.
PLV 1-D BOWL DIFF.
PLV 1-E BOWL DIFF.
PLV 1-F Bowu DIFF. P
PLV 1-A COAL AIR OUT. P
PLV 1-B COAL AIR OUT. P
PLV 1-C COAL AIR OUT. P
PLV 1-D COAL AIR OUT. P
PLV 1-E COAL AIR OUT. P
PLV 1-F COAL AIR OUT. P
PLV 1-A PRI. AIR IN. FLOW
PLV 1-B PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-D PRI. AIR IN. FLOW
PLV 1-E PRI. AIR IN. FLOW
PLV 1-F PRI. AIR IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
VU
t
IN. HgO
IN. HgO
IN. HO
IN, H50
IN. £0
IN. HgO
IN. H|O
IN. HgO
IN. HgO
IN. HgO
IN. HO
IN. HgO
IN. HgO
IN. HgO
IN. tCO
IN. fGO
IN. HoO
IN. H20
0-1E5*
0-125*
0-125*
0-125*
0-125*
0-125*
°F
3/17
09:30
517
810
813
56
72
725
717
477
676
679
679
682
680
845
847
•NA
NA
1003
478
4BO
991
1019
623
411
411
478
478
414
382
21.4
-0.03
24.4
23.3-
22.5
21.0
7.50
0.01
8.40
7.99
7.24
7.19
9.71
0.40
11.24
11.34
11.66
10.33
126
42
131
125
128
124
144
3/17
10:45
512
812
815
57
72
727
718
477
676
678
679
682
680
845
849
NA
NA
1004
478
480
992
1022
622
411
410
477
477
413
380
21.2
-0.03
24.1
23.5
22.5
20.8
7.37
0.01
8.35
3.03
7.22
7.14
9.83
0.40
10.97
11.26
11.59
10.28
126
42
130
125
127
124
144
3/20
16:50
524
800
790
84
95
707
702
478
678
680
680
684
681
811
830
NA
NA
1005
482
482
991
1017
624
412
412
480
479
416
384
21.6
0.03
23.0
23.9
22.4
21.2
7.29
0.02
7.89
8.05
6.97
6.98
10.40
0.43
10.94
11.55
11.90
10.44
126
41
131
126
128
125
145
3/20
19:45
525
817
790
79
90
717
720
480
678
680
680
684
681
819
843
NA
NA
1006
482
481
991
1020
625
412
412
480
480
416
382
21.6
0.02
23.1
23.0
22.7
21.2
7.44
0.02
8.06
8.19
7.11
7.07
10.19
0.45
11.00
11.49
12.08
10.59
126
42
130
126
128
125
145
3/22
17:OO
526
796
796
70
85
704
696
480
678
679
680
684
681
838
846
NA
NA
1005
482
482
997
1025
626
413
413
481
481
417
382
21.0
0.02
24.6
23.2
22.0
22.2
7.35
0.02
8.59
8.06
7.07
6.94
10.43
0.40
11.34
11.00
11.45
9.86
126
43
131
125
128
125
145
3/20
10:05
521
748
749
88
108
661
656
476
679
681
681
685
683
796
808
NA
NA
996
602
521
989
1026
613
410
410
477
477
414
380
21.1
0.04
22.1
23.1
21.8
20.9
7.24
0.02
7.74
7.79
6.84
6.91
9.97
0.43
10.22
11.15
11.42
10.08
125
43
131
126
129
125
145
3/20
12:00
522
774
766
88
98
682
677
478
679
680
681
684
682
810
823
NA
NA
1006
483
482
988
1022
623
412
411
479
479
416
384
21.2
0.04
22.2
23.1
22.0
20.7
7.24
0.02
7.86
7.90
6.96
6.92
10.32
0.43
10.37
11.14
11.60
10.24
126
42
131
125
128
125
145
3/20
14:30
522
777
770
90
102
690
686
478
679
680
680
683
682
809
820
1009
1018
1008
482
482
993
1023
626
411
411
479
479
416
384
21.2
0.04
22.1
23.1
21.9
20.4
7.31
0.02
7.75
7.93
6.98
6.88
10.34
0.42
10.34
11.06
11.54
10.23
125
42
131
126
128
126
145
* C - COMPUTER DATA; B - BOARO DATA: NA - NOT AVAILABLE.
234
SHEET A51
-------
WISCONSIN POWER £ LIGHT Co.
COLUMBIA /I
C-E POWER SYSTEMS
FIELD TESTiNO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD & COMPUTER DATA
•c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
TEST NO.
DATE
TIME
LOAD
TEMPERATURES
Am 4 GAS - V
ECON. N GAS OUT.
ECON. S GAS OUT.
1-A PA FAN DISCH. HDR.
1-B PA FAN DISCH. HDR.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM t WATER - *F
BOILER ECON. IN.
DOWNCOMCR 1
DOWNCOMER 2
DOWNCOMER 3
DOWNCOMER 4
DOWNCOMCR 5
BLR. SH ATMP 1-A STM. IN.
BLR. SH ATMP 1-B STM. IN.
BLR. S SH HDR. OUT.
BLR. N SH HDR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STM. OUT. A
BLR. N RH ATMP STM. OUT. B
BLR. S RH HDR. OUT. A
BLR. N RH HDR. OUT. B
HP HTR. 1-G1 4. 1-G2 EXTR. STM
HP HTR. 1-F1 FW OUT.
HP HTR. 1-F2 FW OUT.
HP HTR. 1-G1 FW OUT.
HP HTR. 1-G2 FW OUT.
HP HTR. 1-G1 DRAIN
HP HTR. -1-G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER P
PLV 1-B BOWL LOWER P
PLV 1-C BOWL LOWER P
PLV 1-D BOWL LOWER P
PLV -E BOWL LOWER P
PLV -F BOWL LOWER P
PLV -A BOWL DIFF. P
PLV -B BOWL DIFF. P
PLV -C BOWL DIFF. P
PLV -D BOWL DIFF. P
PLV -E BOWL DIFF. P
PLV 1-F BOWL DIFF. P
PLV 1-A COAL AIR OUT. P
PLV 1-B COAL AIR OUT. P
PLV 1-C COAL AIR OUT. P
PLV 1-D COAL AIR OUT. P
PLV 1-E COAL AIR OUT. P
PLV 1-F COAL AIR OUT. P
PLV 1-A PHI. AIR IN. FLOW
PLV 1-B PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-D PRI. AIR IN. FLOW
PLV 1-E PRI. AIR IN. FLOW
PLV 1-F PBI. AIR IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
MW
.
IN. HaO
IN. HaO
IN. HaO
IN. H.O
IN. HKO
IN. H|O
IN. H-0
IN. H|0
IN. HgO
IN. HO
IN. H|0
IN. HaO
IN. HaO
IN. HaO
IN. HaO
IN. HgO
IN. HaO
IN. HgO
0-125*
0-125*
0-125*
0-125*
0-125*
0-125*
9
3/24
00:45
473
788
800
77
102
705
693
470
675
677
677
681
678
838
834
1006
1010
1003
471
470
1006
1008
606
404
403
468
469
406
374
20.1
24.0
22.0
0.30
21.0
18.7
6.85
7.73
7.59
0.05
6.75
6.39
9.92
12.64
10.48
0.22
11.10
9.20
126
130
132
0
127
125
144
JO
3/24
02:20
473
787
807
72
92
712
698
467
673
675
676
680
678
841
839
1004
1007
1004
467
466
1004
1010
605
402
401
467
467
404
372
20.0
23.3
22.3
0.30
21.0
18.8
6.85
7.59
7.67
0.05
6.73
6.36
9.78
12.18
10.50
0.21
11.06
9.24
126
130
131
0
128
125
144
3/24
04:00
472
785
800
72
92
713
705
468
672
674
676
680
677
849
851
1003
1009
1004
466
467
993
1017
604
402
402
467
467
404
372
• 19.7
22.7
22.2
0.30
20.8
18.5
6.87
7.45
7.74
0.05
6.76
6.40
9.43
11.70
10.16
0.21
10.72
8.92
126
130
131
0
128
125
143
6/24
12:00
524
750
744
90
*NA
678
680
467
675
677
677
682
679
830
847
996
993
991
481
478
973
1022
615
129
400
208
466
120
374
20.7
23.9
0.09
22.3
21.3
21.4
6.93
7.84
0.0
7.33
7.16
7.13
9.40
11.93
0.05
10.97
10.7)
10.52
124
125
131
123
127
128
148
6/24
13:20
525
756
748
91
NA
684
638
467
675
677
677
681
678
849
850
1013
1010
1006
479
478
969
1021
629
132
4OO
208
467
120
376
20.7
23.8
0.09
22.2
21.9
21.4
6.91
7.77
0.02
7.34
7.10
7.14
9.46
11.86
0.04
10.81
10.62
10.36
123
124
38
123
127
128
149
6/24
09:45
523
74O
744
85
NA
671
668
465
676
677
677
681
678
824
843
1004
1003
1000
486
481
992
1014
616
1 25
399
208
466
119
373
20.6
23.6
0.09
22.1
21.9
21.3
6.84
7.72
0.01
7.23
7.10
7.09
9.50
11.82
0.06
10.74
10.58
10.41
124
124
0
123
127
127
147
3/25
10:15
510
795
743
70
95
707
705
478
674
676
678
681
683
840
846
1002
1013
1004
476
477
989
1032
621
409
408
476
476
412
376
20.6
23.1
22.9
0.20
21.5
20.1
7.17
7.90
7.97
0.05
6.96
6.87
10.12
11.67
4.90
0.21
11.20
9.80
126
130
130
0
128
125
143
J6
6/30
09:50
526
738
745
86
NA
676
665
467
676
677
677
681
679
845
836
1010
998
NA
481
479
1003
1000
623
428
400
191
467
100
407
20.4
24.6
0.09
21.7
22.8
21.2
6.79
7.91
0.0
7.16
7.43
6.93
9.36
12.49
0.0
10.51
11.10
10.47
123
128
0
123
126
128
147
* C - COMPUTER DATA,- B - BOARD DATA; NA - NOT AVAILABLE.
235
SHEET A52
-------
WISCONSIN Pouta S. LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD & COMPUTER DATA
TEST NO.
17
18
19
SO
21
22
23
24
*c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
DATE
TIME
LOAD
TEMPERATURES
AIR & GAS - T
ECON. N GAS OUT.
ECON. S GAS OUT.
1-A PA FAN DISCH. HDR.
1-B PA FAN DISCH. HDR.
1-A AH PRI. AIR OUT.
1-B AH PRI. AIR OUT.
STEAM & WATER - °F
BOILER ECON. IN.
DOWNCOMER 1
DOWHCOMER 2
DOWNCOMER 3
DOWNCOMER 4
DOWHCOMCR 5
BLR. SH ATMP 1-A STM. IN.
BLR. SH ATMP 1-B STM. IN.
BLR. S SH HDR. OUT.
BLR. N SH HDR. OUT.
TURBINE THROTTLE
BLR. S RH ATMP STH. OUT. A
BLR. N RH ATMP STM. OUT. B
BLR. S RH HDR. OUT. A
BLR. N RH HDR. OUT. B
HP HTR. 1-G1 i 1-G2 EXTH. STM
HP HTR. 1-F1 FW OUT.
HP HTR. 1-F2 FW OUT.
HP HTR. 1-G1 FW OUT.
HP HTR. 1-G2 FW OUT.
HP HTR. 1-G1 DRAIN
HP HTR. 1-G2 DRAIN
PULVERIZER DATA
PLV 1-A BOWL LOWER P
PLV 1-B BOWL LOWER P
PLV 1-C BOWL LOWER P
PLV 1-D BOWL LOWER P
PLV 1-E BOWL LOWER P
PLV 1-F BOWL LOWER P
PLV -A BOWL DIFF. P
PLV -B BOWL DIFF. P
PLV -C BOWL DIFF. P
PLV -D BOWL DIFF. P
PLV -E BOWL Dirr. P
PLV -F BOWL DIFF. P
PLV -A COAL AIR OUT. P
PLV -B COAL AIR OUT. P
PLV -C COAL AIR OUT. P
PLV -D COAL AIR OUT. P
PLV -E COAL AIR OUT. P
PLV -F COAL AIR OUT. P
PLV 1-A PRI. AIR IN. FLOW
PLV 1-B PRI. AIR IN. FLOW
PLV 1-C PRI. AIR IN. FLOW
PLV 1-D PRI. AIR IN. FLOW
PLV 1-E PRI. AIR IN. FLOW
PLV 1-F PRI. AIR IN. FLOW
PLV 1-A COAL AIR DISCH. TEMP.
1976
Mrf
.
IN. HO
IN. H?0
IN. my
IN. (CO
IN. H50
IN. HO
IN. H|0
IN. HpO
IN. HO
IN. HpO
IN. HJ3
IN. H?0
IN. H|O
IN. HpO
IN. HgO
IN. HpO
IN. H90
IN. H|0
0-125J&
0-1 2Sf
0-125j{
0-125j<
0-125jf
0-125JS
6/25
11:15
524
750
*NA
96
NA
682
678
467
675
676
676
680
678
840
866
992
1012
1000
479
478
976
10S1
620
177
400
208
466
122
374
20.3
24.1
0.09
22.0
21.4
20.7
6.83
7.84
0.02
7.30
7.04
7.03
9.23
12.06
0.03
10.72
10.34
9.89
124
126
45
123
126
127
146
6/30
08:35
526
733
743
84
NA
664
651
467
675
677
677
681
678
842
833
1011
1001
NA
482
481
1004
996
621
138
400
191
467
102
433
20.4
24.4
0.09
21.7
22.8
21.1
6.76
7.84
0.01
7.09
7.40
6.91
9.37
12.28
0.05
10.53
10.98
10.38
124
128
0
123
126
128
146
6/29
08:50
523
747
748
83
NA
678
672
468
676
678
678
683
680
840
842
1007
1006
NA
481
480
993
1013
623
NA
400
191
467
198
347
20.2
24.9
0.09
21.6
22.5
20.5
6.80
8.05
0.03
7.12
7.41
6.87
9.12
12.51
0.09
10.54
10.93
9.99
124
128
0
124
126
128
152
6/25
14:45
517
756
NA
101
NA
694
694
466
675
677
676
680
678
849
854
1005
1007
969
477
477
977
1008
609
199
395
208
460
142
370
19.8
24.9
0.10
21.5
20.7
19.4
6.75
8.13
0.02
7.28
6.90
6.63
8.85
12.33
0.07
10,15
9.82
9.11
124
128
73
123
126
128
150
6/26
10:30
419
684
NA
102
NA
617
620
444
670
672
672
676
674
825
831
999
1010
681
585
585
974
1011
579
271
379
207
443
104
355
19.7
23.9
0.11
21.6
21.3
-1.3
6.35
7.71
0.01
7.14
7.00
0.06
8.96
11.88
0.11
10.41
10.36
-1.33
124
127
74
123
126
0
140
6/25
16:25
422
704
NA
102
NA
651
660
446
671
672
672
676
673
858
859
1005
1006
913
457
455
986
1012
583
206
381
208
444
137
357
18.0
22.1
0.10
19.4
18.9
17.5
6.26
7.09
0.02
6.63
6.35
6.08
7.84
10.98
0.09
9.12
8.96
8.12
127
127
81
123
126
127
150
6/27
11:35
316
601
NA
102
NA
549
548
417
665
666
667
667
675
667
824
790
982
NA
484
527
924
894
5S7
189
356
195
417
113
332
16.8
20.8
0.11
30.3
18.5
16.6
5.80
6.68
0.03
0.05
6.27
5.65
7.49
10.39
0.16
30.17
8.99
7.99
123
127
64
31
126
127
143
6/29
01:30
322
625
631
93
NA
581
582
421
668
669
669
673
670
855
855
1005
1009
NA
549
548
969
988
543
83
359
192
420
189
299
17.5
21.6
0.09
17.9
18.8
-1.3
6.06
6.87
0.04
6.02
6.29
0.06
7.82
10.90
0.18
8.51
9.10
-1.22
124
128
36
123
126
0
152
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
236
SHEET
A53
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA II
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
BOARD t COMPUTER DATA
1 2 3
•C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
DATE 1976
TIME
LOAD w
PULVERIZER DATA
PLV 1-B COAL ATR DISCH. TEMP. °F
PLV 1-C COAL AIR DISCH. TEMP. °F
PLV 1-D COAL AIR DISCH. TEMP. °F
PLV 1-E COAL AIR DISCH. TEMP. °F
PLV 1-F COAL AIR DISCH. TEMP. CF
PLV 1-A FEEDER COAL FLOW 10T.B/HR
PLV 1-B FEEDER COAL FLOW 103LB/HR
PLV 1-C FEEDER COAL FLOW 10|LB/HR
PLV l.D FEEDER COAL FLOW 10iB/HR
PLV 1-E FEEDER COAL FLOW 10J.B/HR
PLV 1-F FEEDER COAL FLOW lO^B/HR
PLV 1-A MILL AMPS
PLV 1-B MILL AMPS
PLV 1-C MILL AMPS
PLV 1-D MILL . AMPS
PLV 1-E MILL AMPS
PLV 1-F MILL AMPS
3/17
09:30
517
82
150
148
143
146
114
0
107
115
116
116
71
0
74
73
75
74
3/17
10:45
512
87
148
148
142
146
114
0
106
116
116
116
71
0
74
73
75
75
3/20
16:50
524
93
149
148
142
146
116
0
108
117
116
116
73
0
74
76
78
76
3/20
19:45
525
93
149
149
142
146
117
0
109
118
118
117
73
0
73
75
77
77
3/22
17:00
526
88
142
147
142
146
114
0
113
115
114
115
72
0
78
75
75
76
3/20
10:05
521
91
150
145
142
146
115
0
107
116
116
115
72
0
74
76
77
77
3/20
12:00
522
92-
149
145
142
146
115
0
107
115
116
115
72
0
75
76
76
77
3/20
14:30
522
93
149
14S
142
147
114
0
107
116
116
115
72
0
74
75
75
75
FAN DAMPER POSITION - % OPEN
•8 1-A FD FAN INLET VANE
B 1-B FD FAN INLET VANE
B 1-A PA FAN INLET VANE
B 1-B PA FAN INLET VANE
SPRAY VALVE POSITION - f OPEN
B 1-A SH SPRAY VALVE
B 1-B SH SPRAY VALVE
B 1-A RH SPRAY VALVE
B 1-8 RH SPRAY VALVE
MISCELLANEOUS
71
70
28
24
45
27
80
90
71
70
28
24
37
25
84
96
75
74
33
29
22
0
49
35
74
73
32
28
21
5
56
40
72
71
30
26
62
30
60
43
73
72
34
30
72
72
34
30
17
0
28
41
73
72
34
30
12
0
33
46
B
5
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
BURNER TILT
Aux. AIR DAMPERS
-A FUEL/AIR DAMPERS
B FUEL/AIR DAMPERS
-C FUEL/AIR DAMPERS
-D FUEL/AIR DAMPERS
-E FUEL/AIR DAMPERS
-F FUEL/A |R DAMPERS
-A PHI . AIR FAN
-B PRI. AIR FAN
1-A ID FAN
1-B ID FAN
1-A FD FAN
1-B FD FAN
1-A ID FAN
1-B ID FAN
1-A BLR, CIRC. WTR. PUMP
1-B BLR. CIRC. WTR. PUMP
1-C BLR. CIRC. WTR. PUMP
1-D BLR. CIRC. WTR. PUMP
N DRUM LEVEL + NORM, HgO
S DRUM LEVEL ~ NORM, H_0
FLUE GAS COMBUSTIBLES
FLUE GAS OXYGEN
BARONMETRIC PRESS.
+ DEGREES
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
% OPEN
AMPS
AMPS
AMPS
AMPS
AMPS
AMPS
RPM
RPM
AMPS
AMPS
AMPS
AMPS
LEVEL IN,
LEVEL IN.
IN. HGA
-3°
100
50
0
47
53
51
51
172
t83
500
430
208
195
485
495
74
77
72
74
-0.69
-2.25
0.065
4.0
30.04
-3°
100
50
0
46
53
51
51
172
183
500
430
207
195
485
495
74
77
72
74
-0.62
-2.27
0,066
3.9
29.99
+r
81
51
0
47
54
52
51
170
182
500
430
203
193
490
500
76
78
74
74
-0.69
-2.22
0.061
4.0
28.80
+3'
69
53
0
48
55
53
52
170
181
500
420
200
190
490
500
76
78
72
74
-0.53
-2.75
0.061
3.9
28.89
0°
68
50
0
51
53
51
51
171
182
490
420
202
190
480
495
75
78
73
74
-0.68
-2.97
0.063
4.0
30.29
+5°
77
50
0
45
52
50
50
170
180
470
400
195
183
480
490
80
80
76
78
-0.48
-2.28
0.063
3.6
28.64
+5.
66
50
0
46
53
51
50
170
182
460
400
194
184
483
490
77
79
75
76
-0.58
-2.61
0.064
3.4
28.72
-1°
58
50
0
46
53
51
50
169
181
470
400
192
182
480
490
77
79
74
76
-0.44
-2.64
0.064
3.6
28.72
• C - COMPUTER DATAJ B - BOARD DATAJ NA - NOT AVAILABLE.
237
SHEET A54
-------
OVERFIRE AIR OPERATION STUDY
BOARD t COMPUTER DATA
»c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
•B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
c
c
TEST NO.
DATE 1 976
TIME
LOAD MM
PULVERIZER DATA
PLV -B COM. AIR DISCH. TEMP. °F
PLV -C COAL AIR DISCH. TEMP. °F
PLV -D COAL AIR DISCH. TEMP. °F
PLV -E COAL AIR DISCH. TEMP. *F
PLV -F COAL AIR DISCH. TEMP. "F
PLV -A FEEDER COAL FLOW lofLB/HR
PLV 1-B FEEDER COAL FLOW 103.8/W
PLV 1-C FEEDER COAL FLOW 10rLB/HR
PLV 1 -0 FEEDER COAL FLOW 103.8/HR
PLV 1-E FEEDER COAL FLOW lOZLB/HR
PLV 1-F FEEDER COAL FLOW ICrLB/HJ?
PLV 1-A MILL AMPS
PLV 1-B MILL AMPS
PLV 1-C MILL AMPS
PLV 1-D MILL AMPS
PLV 1-E MILL AMPS
PLV 1-F MILL AMPS
FAN DAMPER POSITION - % OPEN
1-A FD FAN INLET VANE
1-B FD FAN INLET VANE
1-A PA FAN INLET VANE
1-B PA FAN INLET VANE
SPRAY VALVE POSITION - % OPEN
1-A SH SPRAT VALVE
1-B SH SPRAY VALVE
1-A RH SPRAY VALVE
1-B RH SPRAY VALVE
MISCELLANEOUS
BURNER TILT + DEGREES
Aux. AIR DAMPERS % OPEN
1-A FUEL/AIR DAMPERS % OPEN
1-B FUEL/AIR DAMPERS % OPEN
1-C FUEL/AIR DAMPERS f OPEN
1-D FUEL/AIR DAMPERS f OPEN
1-E FUEL/AIR DAMPERS % OPEN
1-F FUEL/AIR DAMPERS % OPEN
1-A PRI. AIR FAN AMPS
1-B PRI. AIR FAN AMPS
1-A ID FAN AMPS
1-B ID FAN AMPS
1-A FD FAN AMPS
1-B FD FAN AMPS
1-A ID FAN RPM
1-B 10 FAN RPM
1-A BLR. CIRC. WTR. PUMP AMPS
1-B BLR. CIRC. WTR. PUMP AMPS
1-C BLR. CIRC. WTR. PUMP AMPS
1-D BLR. CIRC. WTR. PUMP AMPS
N DRUM LEVEL + NORM. HO LEVEL IN.
S DRUM LEVEL + NORM. HgO LEVEL IN.
FLUE GAS COMBUSTIBLES %
FLUE GAS OXYGEN %
BARONMETRIC PRESS. IN. HGA
9
3/24
00:45
473
146
149
155
142
146
102
105
102
0
104
103
66
72
72
0
71
73
76
76
30
26
44
32
39
41
0'
41
42
44
43
0
44
43
167
180
500
430
211
198
493
499
76
78
73
75
-0.72
-2.24
0.060
4.7
29.53
10
3/24
02:20
473
144
148
152
141
146
101
105
102
0
104
102
67
72
71
0
70
71
75
75
30
25
46
31
37
44
0*
90
42
43
42
0
43
43
170
130
500
430
210
195
494
498
76
78
72
74
-0.49
-1.96
0.060
5.1
29.49
11
3/24
04:00
472
143
148
149
140
144
102
105
103
0
104
102
66
72
71
0
69
71
73
73
30
25
70
39
46
54
0"
66
42
44
43
0
45
44
170
180
480
410
203
188
490
495
75
78
73
74
-0.66
-2.50
0.057
4.6
29.43
12
6/24
12:00
524
154
0
147
142
149
118
119
0
118
118
117
72
74
0
72
75
74
80
83
31
30
25
61
47
34
+r
100
100
0
100
100
100
100
165
200
510
470
226
202
»NA
NA
74
80
73
75
-0.35
-2.60
0.056
3.2
29.5S
13
6/24
13:20
525
155
0
148
143
149
118
120
0 '
118
118
118
73
74
0
72
75
75
81
83
31
30
29
62
65
47
+7°
26
100
100
0
100
100
100
165
200
520
480
228
205
NA
NA
73
80
73
74
-0.54
.2.45
0.055
3.9
29.45
14
6/24
09:45
523
153
0
146
143
148
118
119
0
118
117
116
71
74
0
72
74
74
80
83
30
30
25
62
36
25
+3'
25
100
100
0
100
100
100
165
202
520
480
229
205
NA
NA
75
81
75
76
.0.74
-1.83
0.054
3.7
29.59
15
3/25
10:15
510
142
148
86
140
144
110
114
111
0
112
112
73
73
73
0
75
76
72
70
29
25
34
26
63
74
0°
60
47
49
49
0
49
49
162
182
460
400
200
185
487
492
76
78
72
74
-O.48
-2.64
0.063
3.6
29.81
16
6/30
09:50
526
156
0
145
156
148
117
118
0
117
115
117
71
73
0
72
73
74
77
80
30
30
28
35
41
39
+3°
25
100
100
0
100
100
100
165
205
490
450
224
204
490
NA
77
82
75
78
-0.35
-0.70
0.056
4.3
29.85
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
238
SHEET ASS
-------
WISCONSIN POWER & LIGHT Co.
COLUMBIA fl
C-E POWER SYSTEMS
FIELD TESTiMO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD t COMPUTER DATA
•C
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
•B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
TEST NO.
DATE 1976
TIME
LOAD Mil
PULVERIZER DATA
. PLV 1-B COAL AIR DISCH. TEMP. °F
PLV 1-C GOAL AIR DISCH. TEMP. *F
PLV 1-D COAL AIR DISCH. TEMP. °F
PLV 1-E COAL AIR DISCH. TEMP. °F
PLV 1-F COAL AIR DISCH. TEMP. °F
PLV 1-A FEEDER COAL FLOW 1CMLB/HR
PLV 1-B FEEDER COAL FLOW 10XLB/HR
PLV 1-C FEEDER COAL FLOW 103.B/HR
PLV 1-0 FEEDER COAL FLOW lois/HR
• PLV 1-E FEEDER COAL FLOW 10fLB/HR
PLV 1-F FEEDER COAL FLOW 10T.B/HR
PLV 1-A MILL AMPS
PLV 1-B MILL AMPS
PLV 1-C MILL AMPS
PLV 1-0 MILL- AMPS
PLV 1-E MILL AMPS
PLV 1-F MILL AMPS
FAN DAMPER POSITION - f OPEN
1.A FD FAN INLET VANE
1-B FD FAN INLET VANE
1-A PA FAN INLET VANE
1-B PA FAN INLET VANE
SPRAY VALVE POSITION -
BARONHETRIC PRESS. IN. HGA
17
6/25
11:15
524
153
0
146
142
147
117
118
0
117
117
116
73
75
0
73
75
76
80
63
31
30
89
59
53
41
+8"
26
100
100
0
100
100
ion
165
SOO
520
470
165
200
•NA
NA
74
79
73
74
-0.77
-2.99
0.056
3.4
29.65
IS
6/30
08:35
526
154
0
144
154
143
118
119
0
118
115
117
71
73
0
74
71
75
78
81
30
29
28
35
36
30
+3°
25
100
100
0
too
100
100
165
203
500
450
225
205
490
NA
77
82
74
80
-0.87
-0.89
0.056
4.4
29.86
19
6/29
08:50
523
158
0
150
159
150
113
116
0
114
114
113
70
74
0
73
70
73
76
79
30
29
28
33
48
40
+6'
19
100
100
0
100
100
100
165
200
470
420
214
193
480
NA
75
80
73
75
-0.44
-2.19
0.055
3.5
29.75
20
6/25
14:45
517
156
0
150
142
150
115
116
0
115
114
114
72
76
0
72
76
75
81
83
31
31
49
50
69
50
+6°
23
100
100
0
100
100
103
165
200
510
470
222
200
500
NA
75
80
73
76
-0.72
-1.40
0.056
4.3
29.65
SI
5/?fi
10:30
419
147
o-
141
143
114
116
117
0
115
115
0
74
75
0
74
75
0
73
76
28
SB
19
15
0
0
+6°
14
100
100
0
100
100
0
155
190
390
340
200
180
450
NA
78
84
78
81
-0.52
-1.39
0.055
4.6
29.89
22
6/25
16:25
422
161
0
151
142
152
90
92
0
•91
92
90
53
69
0
68
68
69
70
73
33
33
29
33
25
17
+3°
3
94
92
o
89
89
90
165
200
380
340
185
170
450
NA
75
82
75
78
-0.53
-1.30
0.055
4.3
29.63
23
6/27
11:35
316
150
0
111
147
142
84
86
0
0
66
64
64
67
0
0
66
57
59
62
28
28
0
0
n
0
+ 11*
0
80
80
0
0
77
77
160
195
300
280
165
150
330
NA
83
87
0
85
-0.59
-2.03
0.033
5.8
30.12
24
6/29
01:30
322
156
•0
148
158
111
83
86
0
84
84
0
63
67
0
64
65
0
58
61
28
27
26
26
0
0
+8°
0
77
77
0
74
75
0
155
195
290
260
165
147
325
NA
80
85
77
84
-0.56
-1.42
0.048
4.7
29.76
* C - COMPUTER DATA; B - BOARD DATA; NA - NOT AVAILABLE.
239
SHEET A56
-------
Wisconsin Power & Light Company
Columbia #1
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
BASELINE TEST
Probe
Loc.
1
2
3
4
5
Probe Coupon
No. No.
A 11
12
13
14
B 11
12
13
14
C 11
12
13
14
D 11
12
13
14
E 11
12
13
14
Initial Wt.
9
192.4714
189.2624
187.7834
189.5986
191.8667
193.0534
192.4719
187.2771
189.6148
192.3205
194.2087
195.2487
181.0037
196.4728
192.6319
189.7795
191.8554
194.4597
191.4211
196.5282
Final Wt.
g
191.6956
188.5251
187.3753
189.1607
191.3217
192.5138
192.1794
187.0411
189.1926
191.8693
193.8685
194.9058
180.7035
196.1221
192.3687
189.5630
191.4543
193.9813
191.0273
196.2131
Ht. Loss
g
.7758
.7373
.4081
.3479
.5450
.5396
.2925
.2360
.4222
.4512
.3402
.3429
.3002
.3407
.2632
.2165
.4011
.4784
.3938
.3151
Wt. Loss/
Coupon
mg/cm2
15.3814
14.6180
8.0912
6.8976
10.8054
10.6983
5.7992
4.6790
8.3707
8.9457
6.7450
6.7985
5.9519
6.7549
5.2183
4.2924
7.9524
9.4850
7.8077
6.2473
Avg. Wt. Loss/
Probe
mg/cm2
11.2471
7.9955
7.7150
5.5544
7.8731
Avg. Wt. Loss/Test 8.0770 mg/cm
240
A57
-------
Wisconsin Power & Light Company
Columbia #1
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
OVERFIRE AIR TEST
Probe Probe Coupon
Loc. No. No.
1 G 11
12
13
14
2 H 11
12
13
14
3 i n
12
13
14
4 J 11
12
13
14
5 K 11
12
13
14
Initial Wt.
g
194.9117
190.1947
196.6078
196.0734
186.5016
190.5570
195.0431
191.5820
192.8761
197.6064
194.6839
194.3763
189.5101
191.3316
189.2178
188.7732
193.0880
187.8881
186.7728
189.5299
Final Wt.
9
194.5574
189.8822
196.2830
195.3612
186.0373
190.0113
194.5049
191.1243
192.2601
197.1149
194.3220
193.9799
189.1223
190.9150
188.8155
188.5163
192.7809
187.5455
186.5222
189.3049
Wt. Loss
g
.3543
.3125
.3248
.7121
.4643
.5457
.5382
.4577
.6160
.4915
.3619
.3964
.3878
.4166
.4023
.2569
.3071
.3426
.2506
.2250
Wt. Loss/
Coupon
mg/cm2
7.0245
6.1957
6.4396
14.1182
9.2053
10.8191
10.6704
9.0744
12.2129
9.7445
7.1751
7.8591
7.6886
8.2596
7.9760
5.0933
6.0886
6.7924
4.9684
4.4609
Avg. Wt. Loss/
Probe
mg/cm2
8.4445
9.9423
9.2479
7.2544
5.5776
Avg. Wt. Loss/Test 8.0933 mg/cm2
241
SHEET A58
-------
APPENDIX B
TEST DATA & RESULTS
FOR
UTAH POWER & LIGHT COMPANY
HUNTIN6TON CANYON STATION
UNIT #2
-------
BASELINE OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA "NOZZLE TILT
FUEL NOZZLE TILT
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
•J.
TT
jT
•T
T
I
a>
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL TIRING ZONE
NO (ADJ. TO Og Oj
NO* AS NO 2
SO* (Aoj.^TO 0* Oj
SO2 2
or (ADJ. T
CO
HC (ADJ. to Of 0 )
0 AT ECONOMIZER OUTLET
Og AT A.H. OUTLET
CD AT ECONOMIZER OUTLET
COp AT A.H. OUTLET
CARBON Loss IN FLYASH
0.)
2
1975
Mtf
KG/S
C
C
DEC
DEQ
f
$
PPM
NG/J
PPM
NG/J
PPM
NG/J
PPM
<£
<£
jg
f
$
1
MAX
CLEAN
5/7
489
376
5'»l
538
ALL 5
0
+14
0
0
45
100
50
100
45
100
50
100
50
100
100
18.9
116.4
476
fMB.O
NA
0
NA
0
0
3.4
4.5
15.4
14.4
<\52
2
MAX
CLEAN
5/5
427
380
541
547
ALL 5
0
+11
0
0
45
100
50
100
45
100
50
100
50
100
100
27.4
124.8
533
PR?, 8
388
266.3
23
6.T
0
4.6
•S.8
14.1
13.1
0.3^
2A
MAX
CLEAN
5/7
428
377
534
537
ALL 5
0
+13
0
0
45
100
45
100
45
100
50
100
50
100
100
32.9
130.1
670
^r>. 4
396
2'3.2
25
7.7
0
S.3
6.4
13.5
12.6
0.22
_3 4
~^~~~~ EXCESS AIR
MAX 3/4 MAX
CLEAN
5/7
428
380
536
537
ALL 5
0
+15
0
0
45
100
45
100
45
100
45
100
50
100
100
40.9
137.8
718
357.0
374
259,1
27
B.2
0
6.2
7.3
12. B
11.9
0.31
CLEAN
10/10
360
298
547
548
ALL 5
0
0
0
0
15
100
10
100
5
100
0
100
0
100
100
28.9
126.9
662
328.0
436
300. 1
NA
o
0
4.8
7.3
14.0
11.8
O. 1?
5
VAR 1 AT 1 ON
1/2 MAX
CLEAN
7/16
259
204
546
529
ABCD
0
+18
0
0
0
100
0
100
0
100
0
100
0
0
35
23.7
122.9
505
249.2
376
256.2
16
4.8
0
4.1
6.1
14.7
13.0
0.23
6
1/2 MAX
CLEAN
7/15
260
203
543
538
ABCD
0
+11
0
0
0
100
0
100
0
100
0
100
0
0
0
32.1
131.1
573
284.3
36 T
2?O.S
16
4.8
0
5.2
6.2
13.6
12.8
">.30
7
1/2 MAX
CLEAN
7/16
258
202
544
537
ABCD
0
+6
0
0
0
100
0
100
0
100
0
100
0
.0
0
50,0
150.0
734
360.3
326
222.8
17
5.0
0
7.1
8.6
12.1
10.8
0.12
_§
MAX
CLEAN
5/5
430
378
541
543
ALL 5
0
+8
0
0
30
100
40
100
20
100
35
100
40
100
100
19.5
117.5
535
267.1
364
£52.5
23
6.9
0
3.5
5.4
15.1
13.4
0.68
Sh
MAX
CLEAN
4/30
428
377
534
537
ALL 5
0
-3
0
0
40
100
45
100
35
100
35
100
40
100
100
89.0
126.3
522
256.6
837
163.4
124
37.5
0
4.8
6.1
14.2
13.0
0.29
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON #2
C-E POWER SYSTEMS
FICLD TESTINO AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE; TILT
J
i-
£§
^
o t~
o —
U Q
fd ""
ia
o
IT
IT
~r
—
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NO (ADJ. TO vt, o )
NO* AS NO A
SO* .(Aoj.2To Of 0.)
SO? *
CO^Aoj. TO OjTOj
Z
CO
HC
0
(ADJ. TO Og 0 )
»T ECONOMIZER OUTLET
Og AT A.M. OUTLET
C0_ »T ECONOMIZER OUTLET
C(Yf »T A.H. OUTLET
CfcROON LOS& 1H FLVA9M
1975
MM
KG/S
C
C
DEC
DEC
%
4
PPM
NG/J
PPM
NG/J
PPM
NG/J
PPM
%
*
.6
5.O
15.1
n.9
n. n't
3/4 MAX
\ca »Tn v f\i
rr
1/2 MAX
5/9 10/9 7/22
433
375
539
540
ALL 5
0
+1
0
0
45
100
50
100
35
100
50
100
50
100
100
35.5
132.6
644
319.1
155
245.2
27
8.3
0
5.6
6.6
13.4
12.5
". in
361
298
548
545
ALL 5
0
0
0
0
15
100
15
100
5
100
10
20
20
100
100
23.0
121.3
592
285.2
405
281.1
14
4.1
O
4.0
5.9
14.7
!•>. 1
n. op
258
204
541
528
ACDE
0
+12
0
0
0
100
0
0
0
100
0
100
0
100
0
25.2
124.3
438
215.7
446
106.1
15
4.5
0
4.3
6.0
14.5
1.-M
n. pi
1§
1/2 MAX
7/21
260
206
541
536
ACDE
0
+13
0
0
0
100
0
0
0
100
0
100
0
100
0
28.9
127.9
470
233.0
448
109.0
NA
r\
0
4.8
6.9
14.0
1S. 1
O.SG
J9
1/2 MAX
^
7/21
258
205
542
536
ACDE
0
+13
0
0
0
100
0
0
0
100
0
100
0
100
0
47.8
146.6
669
333.1
474
328.2
16
5.0
0
6.9
8.1
12.2
11. i
O. 1 7
-------
BIASED FIRING OPERATION STUDY
EMISSIONS TEST DATA
X
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
Excess AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
1975
MW
KG/S
C
c
DEG
DEQ
r
Is
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AID AT CCONOMIZER OUTLET
THEO. AIR TO THE FUCL FIRING Zone
NO (ADJ. TO O* 0.1
NO^ AS NO 2
SOj (ADJ.^TO 05? oj
SO? 2
or (ADJ. TO of oj
co 2
HC (ADJ. TO Of 0)
0? AT ECONOMIZER OUTLET
Og AT A.H. OUTLET
CO- AT ECONOMIZER OUTLET
COg AT A.H. OUTLET
CARBON Loss IN FLYASH
PPM
NO/J
PPM
NG/J
PPM
NG/J
PPM
%
a
*
<
CLEAN
9/17
430
375
518
516
BCOE
0
46
0
0
20
10
30
100
10
100
25
100
20
100
100
1'l.R
107.1
W
168,4
41R
P87.5
56
1fi.7
O
3.6
5.7
15. 1
11.2
0.26
2
MAXIMUM
MODERATE
9/18
426
371
525
511
ABDE
0
-6
0
0
30
100
40
100
10
0
25
100
25
100
100
B1.5
118.1
I'll
PP^.7
ir,8
P'l7. R
16
4.8
n
1.8
4. 4
14. '1
14.1
o.25
_3
4
in nc rnrt r
5
'1 fl/ATt AklC 1 hi
VMn 1 M 1 1 \jn vr r utu tut VM i i \xiij 1 11
> < 3/4 MAXIMUM
CLEAN
9/20
434
368
534
541
ABCD
0
-13
0
0
50
100
50
100
45
100
50
100
50
20
20
20.9
11 7 . B
..,qn
24M
187
267.1
10
5.2
o
T.7
5.7
15.0
1 1.2
n.55
CLEAN MODERATE
12/13
356
297
544
539
BCDE
0
+18
0
0
10
100
0
100
0
100
0
100
0
100
100
16.8
•18. 5
367
191.5
257
186.4
20
6.1
0
1.1
5.6
15.1
11. 1
0.61
10/11
351
295
536
537
ACDE
0
-10
0
0
0
100
25
100
5
100
0
100
0
100
100
19.9
11 0 . 1
404
20.1.6
175
262.9
14
4.4
n
3.6
5.8
15.2
11.2
0.20
6
CLEAN
10/12
360
299
543
546
ABCE
0
-9
0
0
5
100
0
100
0
100
0
100
0
100
100
20.8
119.8
530
263.4
ISQ
248.2
16
•1.8
0
1.7
5.5
14.9
1^.4
0.22
7
1/2
CLEAN
10/12
257
218
542
534
BCOE
0
+6
0
0
5
100
0
100
5
100
0
100
0
100
100
22.6
1 Ob . ' >
Ifll
178.4
1
-------
UTAH POWER AND LIGHT COMPANY
HUNTINOTON CANYON #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
EXCESS AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
OFA
OFA
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NO (ADJ. TO Of 0 )
NO"* AS NO
so;! (ADJ. TO og oj
so
CO^AoJ. TO 0* 0 )
CO 2
HC (ADJ. TO Of 0 )
0- AT ECONOMIZER OUTLET
Og AT A.H. OUTLET
CO AT ECONOMIZER OUTLET
CO? AT A.H. OUTLET
CA.BBON Loss IN FLYASH
1975
MW
KG/S
C
C
DEC
Pro
PPM
NG/J
PPM
NO/J
PPM
NG/J
PPM
I
EMISSIONS TEST DATA
9
<
CLEAN
9/17
429
375
516
•525
BCDE
0
+20
0
0
35
20
50
100
15
100
20
100
35
100
100
P6.3
107.6
421
208.1
408
2B0.8
17
5.0
ry
6. 1
14.4
13.0
0.28
12
- MAXIMUM
CLEAN MODERATE
9/18
428
370
536
537
ACDE
0
+8
0
0
25
100
35
25
15
100
40
100
40
100
100
27.4
125.3
462
227.3
382
261.1
17
5.0
0
4.6
6.9
14.4
12.4
0.24
9/18
429
369
533
541
ABCE
0
+2
0
0
30
100
40
100
20
100
40
5
40
100
100
?9.3
126.8
513
255.9
389
269.9
17
5.2
0
4.9
S.2
14.0
13.7
o.lB
< 3/4 MAXIMUM >
MODERATE CLEAN
10/11
351
295
537
538
BCDE
0
+7
0
0
10
100
5
100
5
100
5
100
5
100
100
29.3
109.1
421
214.2
406
286.9
17
5.2
0
4.9
6.3
14.0
12.7
n.ze
12/13
356
299
543
541
ABDE
0
+9
0
0
5
100
10
100
0
100
0
100
10
100
100
28.0
127.0
549
283.8
291
209.5
18
5.7
o
4.7
7.0
13.9
11.9
0.38
CLEAN
12/13
357
299
544
541
ABCD
0
-8
0
0
0
100
5
100
0
100
5
100
10
100
100
31.7
131.0
502
248.4
252
173.7
21
6.4
0
5.2
7.1
13.7
12.0
0.41
JJ5
!§
1/2 MAXIMUM
CLEAN
7/23
256
203
543
533
ACDE
0
+12
0
0
0
100
- 0
~100
0
100
0
100
0
100
100
25.1
124.4
382
187.2
429
292.2
15
4.5
0
4.3
6.1
14.4
12.9
0. 12
CLEAN
7/24
259
210
542
535
ABCE
0
+11
0
0
0
100
0
100
0
100
0
100
0
100
100
24.7
124.0
453
224.3
443
305.1
15
4.6
0
4.3
5.9
14.4
13.0
0.20
-------
OVERF1RE AIR OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
PURPOSE OF TEST
UNIT LOAD CONDITION
EXCESS AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOZZUE TILT
FUEL NOZZLE TILT
OFA
OFA
AUX
FUEL
AUX
FUEL
, AUX
~C~| FUEL
AUX
TT| FUEL
AUX
T] FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRING ZONE
NO (ADJ. TO Of 0.)
NO* AS NO, d
sol (ADJ."So o* oj
so; 2
COT(ADJ. TO Of 0_)
CO 2
HC (ADJ. TO on o2)
0 AT ECONOMIZER OUTLET
Oj: AT A.M. OUTLET
CO- AT ECONOMIZER OUTLET
CO? AT A.H. OUTLET
CARBON Loss IN FLYASH
10
11
12
1975
MW
KQ/S
C
C
DEC
DEC
^
<
PPM
NG/J
PPM
NG/J
PPM
NO/J
PPM
%
%
%
%
HEAVY
9/17
428
369
532
539
ALL 5
0
+6
0
0
20
100
35
100
15
100
35
100
20
100
100
27.0
125.2
543
273.7
170
259.6
15
4.7
0
4.6
6.8
14.2
12.3
0.20
HEAVY
9/26
430
372
529
539
ALL 5
0
-10
25
25
25
100
40
100
20
100
30
100
40
100
100
28.2
120.3
513
PS1.1
452
308.2
1C;
4.6
0
4.7
5. 1
14.2
13.8
O.H
HEAVY
9/26
430
372
530
538
ALL 5
0
-10
50
50
20
100
30
100
10
100
20
100
30
100
100
26.2
111.6
462
223.4
370
255.8
15
4.6
0
1.5
5.3
14.3
13.5
n.2
361
247.6
15
4.4
0
5.4
7.8
13.5
11.4
0.27
MODERATE
10/1
430
370
535
540
ALL 5
0
+13
100
100
15
100
20
100
5
100
20
100
25
100
100
33.8
112.5
673
332.3
421
Pfl9.
-------
UTAH POWER AND LIGHT COMPANY
HUNTINOTON CANYON #2
C-E POWER STSTEMS
FIELD TESTino AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
EMISSIONS TEST DATA
TEST NO.
13
14
15
16
17
IB
19
20
21
22
23
24
2
oo
PURPOSE OF TEST
UNIT LOAD CONDITION
EXCESS AIR CONDITION
FURNACE CONDITION
DATE
UNIT LOAD
MAIN STEAM FLOW
SHO TEMPERATURE
RHO TEMPERATURE
FUEL ELEVATIONS IN SERVICE
OFA NOTTLE TILT
FUEL NOZZLE TILT
OFA
OFA
AUX
FUEL
AUX
~BJ FUEL
AUX
C] FUEL
AUX
FUEL
AUX
FUEL
AUX
EXCESS AIR AT ECONOMIZER OUTLET
THEO. AIR TO THE FUEL FIRINO ZONE
N0v (ADJ. TO Of 0 )
NO* AS NO-
-
(ADJ. TO
oa)
C02(ADJ. TO Oj< 0 )
CO S
HC (ADJ. TO o#~o~)
0- AT ECONOMIZER OUTLET
OJ: AT A.M. OUTLET
Co AT ECONOMIZER OUTLET
CO? AT A.H. OUTLET
CARBON Loss IN FLYASH
^
MODERATE MODERATE
1975
MW
KO/S
C
C
DEO
DEC
$
*
PPM
NG/J
PPM
NO/J
PPM
NG/J
PPM
rf
I
I*
%
I
10/4
434
364
543
547
ALL 5
-30
0
100
100
15
100
0
100
0
100
5
100
0
100
100
85.1
101.1
533
263.4
450
309.4
15
4.5
O
4.3
5.7
11.4
13.1
O.S1
10/5
422
370
520
525
ALL 5
0
-20
100
100
0
100
0
100
0
100
0
100
0
100
100
22.0
99.2
366
179.8
397
271.1
16
4.8
0
3.9
4.9
14.9
14. 0
o.:v>
HEAVY MODERATE MODERATE MODERATE ' CLEAN MODERATE
10/4
429
370
531
543
ALL 5
0
0
100
100
20
100
0
100
5
100
5
100
0
100
100
25.1
101.1
422
212.1
404
281.9
15
4.6
0
4.3
5.2
14.5
13.8
n.28
10/3
427
372
529
533
ALL 5
0
+25
100
100
15
100
5
100
5
100
0
100
0
100
100
21.3
98.4
569
283.5
386
267.5
15
4.4
0
3.8
5.1
14.9
13.7
O.S6
10/3
424
377
519
515
ALL 5
+30
0
100
100
15
100
0
100
5
100
0
100
0
100
100
23.5
99.8
375
186.1
432
298.3
16
4.9
0
4.1
5.4
14.6
13.5
O.22
10/3
429
367
535
539
ALL 5
-1-30
+25
100
100
15
100
5
100
5
100
0
100
0
100
100
21.7
98.6
49B
S52.1
349
245.9
51
15. 8
0
3.8
5.1
14.9
13.8
0.63
10/6
417
374
522
538
ALL 5
+30
0
100
100
15
100
0
100
0
100
0
100
0
100
100
18.5
95.8
392
196,5
347
241.8
19
5.8
0
3.4
5.3
15.2
13.5
o. 40
10/B
426
377
521
527
ALL 5
+30
0
100
100
15
100
0
100
5
100
5
100
0
100
100
19.6
97.1
382
190.8
364
252.1
19
5.8
0
3.5
5.6
15.1
13.3
•">. 43
i i nun vr H urtnn i i un •
3/4 MAX 3/4 MAX
CLEAN MODERATE
10/9
356
299
531
527
ALL 5
+30
0
100
100
15
100
0
100
5
100
0
100
0
100
100
19.3
98.1
329
161.3
403
275.2
19
5.7
0
3.5
6.1
15.3
13. 0
o.so
10/9
358
299
538
537
ABCE
+30
0
100
100
15
100
0
100
5
100
0
0
0
100
100
21.5
95.0
337
167.8
358
247.8
21
6.3
0
3.8
5.8
14.8
13.1
o.ss
1/2 MAX 1/2 MAX
CLEAN MODERATE
10/12
253
218
525
510
BCDE
+30
0
80
80
10
0
0
100
5
100
0
100
0
100
100
22.8
97.3
266
132.0
403
278.4
63
19.0
0
4.0
5.5
14.7
13.3
0.47
10/5
265
217
542
526
ACOE
+30
0
75
75
10
100
0
0
0
100
0
100
0
100
100
23.9
99.7
310
155.3
447
311.1
15
4.5
0
4.1
5.7
14.6
13. a
o.ss
-------
UTAH POWER t LIGHT COMPANY
HUNTINCTON CANYON fS
C-E POWER SYSTEMS
FICLO TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST DATA
TEST NO.
DATE
UNIT LOAD
1975
MM
1
5/7
429
2
5/5
427
2A
5/7
428
3
5/7
426
4
10/10
360
5
7/16
259
6
7/15
260
7
7/16
258
8
5/5
430
9
4/30
428
FLOWS KG/SEC
FEEDWATER
IST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET'
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH OESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
WA
°C
L
LC
RC
R
R
L
L
R
L
R
SH PENO SPCO FRONT INLET LINK L
SH PENO SPCD FRONT INLET LINK C
SH PENO SPCO FRONT INLET Li
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INLET .
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FW IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AND GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLET
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
NK R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
R
L
R
L
R
L
R
L
R
375
372
19.305
18.857
17.168
12.838
3.820
3.585
18.657
19.519
3.792
247
325
328
325
326
396
395
395
394
.426
435
482
489
494
526
536
322
323
321
322
360
368
353
355
542
NA
539
321
216
209
248
125
127
127
37
42
273
268
328
332
122
118
375
372
19.160
18.802
17.058
12.810
3.799
3.564
18.5ia
19.471
3.78B
248
333
336
332
334
402
397
390
396
439
438
493
493
4B6
540
541
324
324
321
321
365
374
355
363
550
NA
548
324
216
209
248
126
125
121
39
42
274
268
336
337
126
119
377
374
19.319
18.871
17.154
12.866
3.806
3.564
18.692
19.588
3.735
246
333
337
333
335
400
402
401
398
436
441
493
494
490
533
535
324
325
324
324
359
366
349
357
547
NA
538
324
216
209
247
127
128
113
36
39
273
265
341
341
122
122
377
373
19.305
18.857
17.175
12.845
3.799
3.564
18.506
19.546
3.758
246
339
342
337
339
403
408
403
400
437
441
493
493
491
536
535
326
326
324
326
359
366
351
357
546
NA
538
326
216
209
248
128
131
112
36
39
275
268
347
347
122
123
295
282
18.285
18.037
16.961
9.735
3.034
2.889
17.940
18.623
3.061
238
329
331
328
331
408
407
403
400
440
435
502
501
499
547
546
317
318
309
312
347
360
349
345
547
550
550
317
206
202
238
144
145
147
42
41
267
271
326
332
122
125
201
186
17.216
17.023
16.458
6.426
2.041
1.972
17.547
17.478
2.041
218
301
303
301
299
394
397
391
388
438
434
514
518
502
549
541
288
293
287
293
340
350
336
339
534
525
533
291
188
186
218
144
144
103
42
41
243
245
282
289
109
107
198
186
17.099
16.913
16.361
6.419
2.048
1.972
17.444
17.395
2.04S
218
308
309
305
307
399
404
391
388
436
433
509
506
498
548
537
287
292
286
292
339
347
337
345
544
532
538
290
189
166
219
146
146
104
39
39
248
248
291
294
111
104
195
185
17.161
17.016
16.465
6.384
2.03
-------
UTAH POWER & LIGHT COMPANY
HUNTINGTON CANYON IS
C-E POWER SYSTEMS
FIELD TESTiNO AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDWATER
1ST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET'
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
SH PEND SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INLET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FW IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AND GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLGT
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
1975
W
KG/SEC
MPA
•c
L
LC
RC
R
R
L
L
R
L
R
INK L
INK C
INK R
L
R
L
R
L
R
K L
K LC
K RC
K R
L
R
COMB.
L
R
L
R
L
R
L
R
L
R
JO
5/1
428
344
370
19.181
18.768
17.044
12.776
3.778
3.551
18.478
19.498
3.771
252
342
343
342
347
403
402
399
401
449
441
501
498
490
546
544
326
327
325
326
363
376
362
370
542
NA
548
325
216
209
253
138
138
118
39
43
277
273
349
351
127
126
JJ
7/17
256
198
186
17.106
16.940
16.382
6.371
2.034
1.965
17.437
17.382
2.034
217
304
304
303
303
39B
401
391
388
438
436
508
509
503
545
541
287
292
286
292
340
352
341
346
537
535
538
291
188
186
219
145
145
108
42
41
246
248
28B
292
111
108
TEST
J2
7/18
259
198
190
14.582
14.417
13.720
6.550
2.041
1.979
14.934
14.844
2.055
218
317
319
317
316
409
412
386
382
435
433
504
505
498
544
541
303
312
302
312
346
361
353
353
534
534
536
308
188
186
219
144
144
108
46
44
248
246
298
•vs
117
106
DATA
J2
5/9
433
377
373
19.271
18.850
17.175
12.852
3.840
3.627
18.692
19.560
3.847
248
331
339
339
329
398
399
396
400
433
433
488
489
486
532
532
326
326
311
313
344
351
342
350
544
NA
539
325
217
210
249
128
125
165
37
43
263
258
331
337
128
122
J4
5/9
433
375
374
19.285
18.871
17.237
12.866
3.847
3.627
18.657
19.588
3.820
247
340
345
342
341
399
401
399
401
434
436
493
494
487
537
536
327
328
311
313
344
349
341
347
542
NA
539
327
217
210
248
125
123
163
38
44
274
271
339
341
129
122
15
5/9
433
373
374
19.298
18.878
17.175
12.866
3.826
3.606
18.712
19.616
3.854
247
348
356
351
357
408
409
408
403
439
441
494
493
491
541
538
330
331
309
314
351
354
343
348
545
NA
542
329
217
210
248
129
127
170
38
41
271
263
346
351
129
125
J6
10/9
361
297
280
18.368
18.078
16.961
9.694
3.047
2.923
17.830
18.692
3^075
238
327
329
325
32B
408
407
407
404
446
440
SOB
501
496
551
544
317
322
299
304
340
347
342
339
546
543
546
318
206
202
238
144
139
157
47
42
263
270
327
331
122
121
J7
7/22
258
204
189
17.299
17.078
16.527
6.468
2.027
1.965
17.526
17.575
2.034
217
302
304
303
299
396
399
397
398
440
438
506
508
NA
545
537
284
289
283
289
337
344
332
333
542
525
538
288
186
185
216
141
137
107
39
40
247
247
288
292
117
110
18
7/21
260
204
190
17.050
16.844
16.265
6.536
2.027
1.965
17.375
17.313
2.034
217
304
306
304
304
399
399
396
393
440
435
509
507
NA
545
536
286
291
284
291
336
343
333
339
542
528
538
269
188
185
218
143
143
102
39
38
247
•249
290
296
115
111
J9
7/21
258
198
188
17.030
16.844
16.272
6.467
2.027
1.958
17.375
17.285
2.034
217
317
319
317
316
409
412
396
393
439
434
505
503
NA
547
537
286
292
285
292
336
343
333
338
540
531
537
290
188
186
218
144
144
104
39
42
250
248
298
302
116
109
250
SHEET
-------
UTAH POWER J LIGHT COMPANY
HUNTINGTON CANYON K
C-E POWER SYSTEMS
FIELD TESTING AHO
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST DATA
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDWATER
IST STAGE STEAM
PRESSIRES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEWERATURES
J_
1975 9/17
MW 430
KG/SEC
375
359
MPA
19.154
18.712
17.044
12.438
3.771
3.613
18,512
19.554
3.806
2
9/18
426
370
'59
19.133
18.636
16.940
13.397
3.764
3.592
18.450
19.512
3.792
3
9/20
434
369
359
19.098
13.616
16.913
12.417
3.778
3.613
NA
19.305
3.820
4
12/13
356
297
288
18.381
18.071
16.961
9.935
3.047
2.882
17.975
18.630
3.040
5
10/11
351
295
280
18.381
18.085
16.940
9.611
2.985
2.903
17.975
18.643
3.034
6
10/12
360
299
288
18.278
17.975
16.961
9.956
3.068
2.937
17.893
18.636
3.116
7
10/12
257
218
180
17.588
17.451
16.892
6.743
2.137
2.068
17.561
17.926
2.144
8
10/5
270
207
200
17.588
17.430
16.844
6.922
2.227
2.151
NA
17.933
2.248
°c
WATER AHO STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
SH PENO SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH OESH'lNHET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FW IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
L
LC
RC
R
R
L
L
R
L
R
: L
: C
: R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
p
249
329
333
331
333
402
398
402
397
432
422
479
476
468
521
517
315
314
313
314
351
363
348
349
530
542
538
314
217
211
250
133
134
134
248
330
333
331
333
401
399
400
399
432
423
488
484
473
529
521
319
318
317
318
356
366
348
344
543
538
542
318
217
212
249
139
140
141
249
332
336
333
333
402
403
401
403
442
427
502
493
477
543
525
327
326
314
316
359
374
344
341
551
531
543
327
217
211
251
131
132
166
238
314
315
313
318
393
397
393
397
438
444
508
515
507
546
543
315
317
314
317
353
368
356
354
552
527
541
316
205
202
238
126
126
142
237
319
322
319
323
403
399
403
399
438
433
495
496
489
536
536
306
309
301
306
337
350
342
336
531
543
539
308
206
201
237
123
124
157
238
319
321
318
321
398
396
398
396
438
433
508
501
502
544
540
314
316
309
312
349
364
752
346
544
547
546
316
207
202
239
124
125
156
219
302
304
301
306
398
395
398
395
438
434
506
507
505
540
543
286
291
284
292
329
348
337
333
526
542
536
289
189
187
220
117
117
116
221
312
313
312
313
405
404
390
387
435
424
509
505
492
547
539
288
NA
287
294
336
350
335
3S9
546
543
548
292
192
188
222
147
147
117
AIR AND GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLET
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
1
u
R
L
p
L
R
L
R
37
37
279
278
348
351
132
124
37
39
277
275
347
349
132
122
37
41
280
277
349
349
133
116
43
43
261
268
314
322
120
120
42
rr
265
271
311
326
125
127
46
43
261
265
319
322
121
115
49
47
244
249
291
293
117
111
48
46
248
253
299
301
121
119
251
SHEET B9
-------
UTAH POWER t LIGHT COMPANY
HUNTINGTON CANTON #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEOWATER
IST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
TEST DATA
1975
MW
KG/SEC
HP*
9
9/17
429
375
357
19.174
18.657
16.989
12.397
3.771
3.59S
18.457
19.581
3.799
10
9/18
428
370
360
19.154
18.671
17.023
12.486
3.778
3.613
18.416
19.609
3.806
21
9/18
429
369
359
19.098
18.657
16.961
12.438
3.778
3.613
18.485
19.526
3.806
\Z
10/11
351
295
277
18.381
18.050
16.927
9.577
2.978
2.896
17.699
18.726
3.013
12
12/13
356
299
288
18.368
18.064
16.858
9.942
3.040
2.896
18.023
18.761
3.040
_14
12/13
356
299
285
18.416
18.037
16.906
9.908
3.040
2.875
17.975
18.685
3.040
25
7/23
256
201
186
17.264
17.058
16.534
6.467
2.006
1.944
17.588
17.520
2.013
26
7/24
259
204
190
17.299
17.113
16.575
6.640
2.048
1.986
17.637
17.602
2.041
°C
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
SH PEND SPCO FRONT INLET LINK
SH PEND SPCO FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INLET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FW IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AND GAS
AH AIR INLET
AH AIR INLCT
AH AIR OUTLET
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
L
LC
RC
R
R
L
L
R
L
R
i L
i C
: R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
R
248
331
336
334
335
403
399
403
399
431
423
477
474
466
518
513
311
311
309
311
343
357
341
339
518
532
530
311
217
211
249
134
134
152
248
334
337
334
337
405
402
404
402
437
429
494
494
488
537
535
327
NA
312
314
346
360
346
342
533
541
539
327
217
211
251
133
134
165
249
336
339
336
339
407
405
406
404
438
431
494
488
479
537
529
327
NA
310
314
348
358
343
340
542
539
542
326
217
211
250
152
152
166
236
322
326
3SS
325
404
402
404
402
438
435
494
496
491
537
536
307
309
306
309
342
354
346
340
534
541
539
308
206
201
237
127
127
145
237
318
318
316
323
397
399
396
399
436
445
503
505
511
542
544
312
314
311
314
350
359
352
355
547
534
540
313
205
201
238
131
131
147
238
319
319
320
324
398
399
397
398
442
442
512
506
505
547
542
313
316
310
314
358
364
350
352
549
532
540
314
205
201
23S
140
138
156
217
304
307
305
303
400
401
398
396
441
438
504
510
499
545
542
287
291
286
291
329
346
338
337
532
533
538
289
187
185
21 B
143
143
104
217
304
306
303
304
399
402
393
390
437
437
501
504
502
543
541
286
291
284
291
334
351
339
345
536
NA
537
289
188
185
218
143
143
104
L
R
L
R
L
R
L
R
36
37
279
278
350
353
132
125
37
39
277
276
344
351
132
124
37
38
280
278
351
355
132
124
43
41
263
268
322
328
123
119
43
42
262
271
320
326
124
121
43
42
262
269
315
329
122
121
40
39
247
249
286
292
119
113
40
40
248
248
290
294
122
112
252
SHEET BIO
-------
UTAH POWER t LIGHT COMPANY
HUNTINGTON CANYON IS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEOWATER
IST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET •
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
1975
MW
KO/SEC
MP»
_]_
9/17
428
369
358
19.126
18.657
16.975
12.452
3.765
3.606
18.471
19.478
3.799
TEST
S
9/26
430
372
364
19.167
18.685
17.009
12.569
3.771
3.613
18.388
19.809
3.799
DATA
3
9/26
430
372
364
19.195
18.726
17.023
12.569
3.785
3.613
16.388
19.733
3.806
£
9/26
430
370
362
19.188
18.692
17.009
12.528
3.792
3.627
18.388
19.588
3.827
5_
9/26
431
370
364
19.236
18.726
17.037
12.590
3.806
3.627
18.388
19.657
3.827
6
10/1
430
372
362
19.209
18.678
16.961
12.535
3.771
3.592
18.388
19.540
3.785
7
10/1
429
372
252
19.147
18.685
17.009
12.535
3.771
3.613
18.388
19.650
3.799
8
10/1
428
370
360
19.133
18.643
16.969
12.500
3.765
3.599
18.368
19.560
3.799
°C
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LFNK
SH Div PANEL OUTLET LINK
SH PEND SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH PENO SPCD FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INJ.ET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER rw IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AMO GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLET
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
L
LC
RC
R
R
L
L
R
L
R
L
C
R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
R
249
336
339
336
339
406
404
406
403
437
429
492
489
480
534
529
324
323
316
316
351
363
346
344
539
539
540
323
217
211
250
136
137
166
248
334
337
334
338
407
402
406
401
438
429
490
482
479
531
527
322
NA
314
315
350
357
347
352
533
'544
538
321
216
211
249
130
131
166
248
334
337
334
337
406
403
405
402
438
429
491
•185
476
534
526
322
NA
314
314
348
359
348
349
536
539
538
322
216
211
249
131
132
166
249
333
337
334
336
404
402
403
402
440
430
496
490
481
538
529
326
326
311
312
346
361
347
347
534
539
539
325
217
211
250
132
132
166
249
335
339
337
336
404
403
404
403
439
432
493
488
477
537
527
324
323
311
312
347
360
345
342
538
534
539
324
217
211
250
132
132
166
248
330
334
332
334
404
4OO
404
400
440
430
496
489
480
537
530
326
NA
324
324
359
368
359
357
54?
550
548
325
216
211
249
132
133
132
248
?30
334
331
333
403
401
4O3
400
436
429
491
483
475
533
523
321
NA
319
319
354
362
354
152
543
539
542
321
216
211
249
132
133
132
248
331
335
333
334
405
402
404
402
438
431
491
486
476
534
526
322
323
321
322
358
364
156
151
546
541
545
322
216
211
249
132
133
132
1
L
P
L
R
L
R
L
R
37
36
281
279
351
356
133
125
13
44
282
276
337
348
138
122
32
43
283
276
338
348
138
122
32
43
281
273
338
346
137
120
32
43
282
274
340
146
138
121
43
30
272
285
339
349
126
129
43
31
272
284
339
348
126
129
43
30
274
284
341
?47
125
131
253
SHEET B11
-------
UTAH POWER & LIGHT COMPANY
HUNTINGTON CANYON f2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDVATER
IST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET•
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
TEST DATA
1975
MW
CG/SEC
MPA
9
9/27
428
369
365
19.195
18.726
16.975
12.604
3.771
3.599
18.388
19.664
3.799
JO
10/1
429
369
362
19.147
18.685
16.989
12.535
3.751
3.627
18.388
19.595
3.758
JM
10/1
430
370
362
19.147
18.678
17.003
12.521
3.758
3.585
18.388
19.560
3.765
.12
10/5
487
370
360
19.078
18.685
16.989
12.500
3.751
3.599
18.388
19.588
3.806
11
10/4
434
364
360
19.119
18.650
16.996
12.500
3.778
3.606
18.388
19.595
3.827
If.
10/5
422
370
359
19.119
18.678
16.947
12.466
3.751
3.585
18.388
.19.595
3.792
-15
10/4
429
370
362
19.092
18.657
16.996
12.535
3.771
3.606
18.388
19.526
3.799
.16
10/3
427
372
360
19.119
18.630
16.989
12.486
3.771
3.599
18.388
19.547
3.799
°c
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LINK
SH Div PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
SH PENO SPCO FRONT INLET LINK
SH PEND SPCO FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INLET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FW IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AND GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLET
AH AIR OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
L
LC
RC
R
R
L
L
R
L
R
: L
: C
; R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
R
248
341
342
338
343
406
404
406
403
436
428
489
484
479
531
525
321
NA
319
319
351
359
347
346
539
540
539
320
216
210
249
131
132
124
248
341
344
342
342
409
407
409
407
438
436
489
492
483
537
533
326
NA
324
325
354
364
352
349
541
539
543
325
216
210
249
131
132
130
248
341
344
342
342
409
40B
409
408
441
437
489
493
482
537
533
326
NA
324
325
354
365
354
348
541
539
543
325
216
210
249
132
132
131
248
333
334
330
332
400
401
399
401
432
428
487
482
479
529
523
319
NA
317
318
355
362
349
345
548
532
540
318
216
211
249
138
138
136
249
333
337
335
338
408
402
407
402
446
436
503
500
489
546
539
333
NA
320
321
352
365
357
352
541
554
550
332
217
211
250
137
138
166
248
328
332
329
329
398
398
398
398
432
425
485
500
489
526
514
315
NA
313
314
350
362
343
337
534
516
529
314
216
209
248
143
143
147
248
331
333
331
333
401
399
401
398
438
429
494
491
480
534
527
323
NA
322
322
354
367
355
353
541
545
544
323
216
211
249
141
141
164
248
329
335
333
332
402
398
402
398
435
430
484
492
481
528
530
322
NA
314
315
348
355
348
341
528
538
538
322
216
211
249
151
147
166
L
R
L
R
L
R
L
R
34
39
280
276
342
352
135
124
41
31
277
284
351
354
128
131
41
31
278
285
350
355
129
132
39
34
277
281
343
348
131
131
39
33
277
284
343
352
130
130
41
35
274
279
341
346
129
122
40
34
275
281
342
348
131
131
35
. 34
274
281
343
346
129
128
254
SHEET B12
-------
UTAH POWER & LIGHT COMPANY
HUNTINOTON CANYON fS
C-E POWER SYSTEMS
FIELD TESTING »HD
PERrORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDWATER
IST STAGE STEAM
PRESSURES
ECONOMIZER INLET
DRUM
SH OUTLET •
TURBINE IST STAGE
RH INLET
RH OUTLET
SH SPRAY WATER
HP HTR FW INLET
HP HTR STM INLET
TEMPERATURES
17
'975 10/3
MW 424
KO/SEC
377
362
MPA
19.092
18.650
16.968
12.521
3.778
3.613
18.388
19.526
3.799
TEST DATA
JI8
10/3
429
367
362
19.099
18.643
16.996
12.500
3.778
3.599
18.388
19.547
3.820
_19
10/6
417
374
359
19.105
18.733
16.996
12.486
3.751
3.599
18.388
19.547
3.799
20
10/8
426
377
360
19.188
18.761
16.996
12.500
3.765
3.599
18.388
19.560
3.799
21
10/9
356
299
282
18.381
18.099
16.996
9.770
3.034
2.896
18.009
18.712
3.075
22
10/9
358
299
282
18.45n
18.092
16.927
9.756
3.054
2.965
18.044
18.747
3.075
23
10/12
253
218
193
17.623
17.416
16.927
6.640
2.213
2.096
17.568
17.933
2.213
24
10/5
265
216
199
17.561
17.389
16.727
6.847
2.199
S.082
17.533
17.899
2.213
°C
WATER AND STEAM
ECONOMIZER INLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
ECONOMIZER OUTLET
SH DESH INLET LINK
SH DESH INLET LINK
SH DESH OUTLET LINK
SH DESH OUTLET LiNK
SH Dlv PANEL OUTLET LINK
SH Div PANEL OUTLET LINK
SH PENO SPCD FRONT INLET LINK
SH PEND SPCD FRONT INLET LINK
SH PENO SPCO FRONT INLET LINK
SH OUTLET
SH OUTLET
RH DESH INLET
RH DESH INJ.ET
RH RADIANT WALL INLET
RH RADIANT WALL INLET
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH RADIANT WALL OUTLET LINK
RH OUTLET
RH OUTLET
RH OUTLET
HP HEATER STM INLET
HP HEATER DRAIN
HP HEATER FVI IN
HP HEATER FW OUT
SH DESH SPRAY WATER
SH DESH SPRAY WATER
RH DESH SPRAY WATER
AIR AND GAS
AH AIR INLET
AH AIR INLET
AH AIR OUTLET
AH Am OUTLET
AH GAS INLET
AH GAS INLET
AH GAS OUTLET
AH GAS OUTLET
L
LC
RC
R
R
L
L
R
L
R
L
C
R
L
R
L
R
L
R
L
LC
RC
R
L
R
COMB.
L
R
248
328
332
329
331
399
397
399
397
434
424
482
481
468
522
516
313
NA
301
302
334
346
332
331
514
516
518
312
216
210
249
137
137
164
249
332
336
333
334
403
401
403
401
438
432
493
491
486
536
534
327
NA
312
314
351
358
347
343
539
538
541
327
217
211
250
143
141
165
247
327
328
326
328
396
396
396
395
429
423
486
484
473
526
518
316
316
314
316
352
362
346
343
541
536
536
316
215
209
248
133
133
144
248
326
329
326
329
397
396
397
394
432
423
487
464
471
595
517
315
314
313
314
348
361
344
344
527
526
528
314
216
210
249
135
1?6
131
237
316
318
314
317
396
396
395
395
436
428
496
498
486
534
528
303
306
T02
305
339
359
341
336
529
526
•529
304
2"6
202
238
126
127
135
237
322
326
321
323
402
403
402
403
444
436
499
499
486
542
533
308
313
301
304
342
357
339
337
542
531
539
310
206
2O2
238
134
1?4
157
218
299
TOO
297
301
392
391
391
391
429
423
497
493
484
528
522
271
277
270
277
313
327
31?
311
511
509
511
274
189
186
219
119
121
118
220
305
307
305
306
396
397
396
392
441
426
513
515
490
549
536
286
292
284
292
T29
342
326
324
529
522
530
289
191
187
221
144
145
122
L
p
L
R
L
R
L
R
40
34
274
280
340
345
129
128
39
34
276
281
346
348
129
128
39
34
273
278
337
346
129
128
41
36
273
278
337
346
129
127
42
42
262
267
317
322
123
123
47
43
261
268
325
328
121
121
49
49
242
247
288
290
117
116
48
44
244
251
296
298
121
116
255
SHEET 813
-------
UTAH POWER & LIOHT COMPANY
HUNTINGTON CANVON *2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST NO.
DATE 1975
UNIT LOAD Mw
FLOWS KO/S
FEEDWATER (MEASURED^
AUXILIARY STEAM . SH (PLANT INSTRUMENTATION!
SH SPRAY (HEAT BALANCED
MAIN STEAM (CALCULATED^
Tuna INC LEAKAGE (TURBINE HEAT BALANCED
HP HTR. EXTRACTION (HEAT BALANCED
RH SPRAY (HEAT BALANCED
RH STEAM (CALCULATED^
UNIT ABSORPTION MJ/s
ECONOMIZER
FURNACE
DRUM - SH OESH
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY %
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASM PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
TOTAL Losses
EFFICIENCY
HEAT INPUT MJ/s
HEAT INPUT FROM FUEL
EXCESS AIR <
AIR HEATER INLET
Am HEATER OUTLET
TEST RESULTS
1
5/7
489
375
0.4
1
376
7
32
0
337
153
371
142
196
172
1035
3.55
5.35
0.11
0.19
0.34
0.02
0.01
0.52
10.08
B9.92
1152
18.9
26.7
2
5/5
427
375
0.4
5
380
7
32
1
343
171
353
149
212
182
1068
3.71
4.89
0.11
0.18
0.34
0.02
Q.01
0.37
9.63
90.37
1182
27.4
37.2
2A
5/7
428
377
0.4
0
377
7
30
0
339
177
352
153
190
170
1041
3.96
4.99
0.12
0.18
0.32
0.02
0.01
0.82
9.84
90.16
1155
32.9
42.8
3
5/7
428
377
0.4
3
380
7
31
0
342
189
340
163
190
170
1051
4.27
5.13
0.13
0.18
0.36
0.03
0.01
0.31
10.44
89.56
1173
40.9
52.1
4
10/10
360
295
0.4
4
298
6
23
2
272
141
294
126
153
149
862
4.12
4.99
0.13
0.22
0.33
0.02
0.01
0.12
9.95
90.05
958
28.9
52.1
5
7/16
S59
201
0.4
3
204
4
13
0
186
82
241
71
112
99
605
3.07
4.94
0.09
0.31
0.29
0.01
0.01
0.23
8.95
91.05
665
23.7
40.0
6
7/15
260
198
0.4
5
203
4
13
0
186
87
232
76
109
103
608
3.18
4.78
0.10
0.31
0.30
0.01
0.01
0.30
8.99
91.05
668
32.1
40.9
7
7/16
258
195
1.1
a
203
4
13
0
185
100
214
83
108
102
607
3.70
4.92
0.11
0.31
0.30
0.01
0.01
0.12
9.49
90.51
671
50.0
67.9
8
5/5
430
375
0.4
3
378
7
33
5
342
162
361
150
205
184
1063
3.70
- 5.04
0.11
0.18
0.33
0.02
0.01
0.68
10.07
89.93
1182
19.5
33.7
9
4/30
428
377
0.4
0
377
7
35
0
335
160
363
150
191
168
1038
3.90
5.06
0.12
0.19
0.32
0.02
0.01
0.29
9.90
90.10
1146
29.0
40.1
-------
UTAH POWER '. LIGHT COMPANY
HUNTIMGTON CANYON f2
t-E POVKK SYSTCW9
FIELD TEST mo AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST RESULTS
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDWATER (MEASURED^
AUXILIARY STEAM - SH (PLANT INSTRUMENTATION)
SH SPRAY (HEAT BALANCE)
MAIN STEAM (CALCULATED)
TURBINE LEAKAGE (TURBINE HEAT BALANCED
HP HTR. EXTRACTION (HEAT BALANCE)
RH SPRAY (HEAT BALANCE)
RH STEAM (CALCULATED)
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM - SH DESH
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY
DRY GAS Loss
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
TOTAL LOSSES
EFTicIENCY
HEAT INPUT
HEAT INPUT TROM FUEL
EXCESS AIR
AIR HEATER INLET
AIR HEATER OUTLET
1975
MW
MJ/s
MJ/s
.10
5/1
428
374
0.4
2
375
7
36
0
333
188
328
156
199
172
1042
4.37
5.09
0.13
0.18
0.33
0.02
0.01
0.23
10.36
89.64
1163
40.9
55.4
JJ_
7/17
256
198
0.4
5
203
4
13
0
186
84
236
74
110
102
606
3.05
4.93
0.09
0.31
0.29
0.01
0.01
0.24
8.93
91.07
666
27.4
36.4
^2
7/18
259
198
0.4
9
208
4
13
0
190
99
236
81
106
96
619
3.50
4.88
0.11
0.31
0.30
0.01
O.O1
0.13
9.25
90.75
682
48.8
61.3
_K3
5/9
433
377
0.4
0
377
7
f
32
5
343
174
351
149
191
184
1049
3.53
4.90
0.11
0.18
0.34
0.02
0.01
0.53
9.62
90.38
1161
15.0
25.9
I*
5/9
433
375
0.4
0
375
7
31
6
342
193
331
150
191
183
1049
3.63
4.87
0.11
0.18
0.34
0.02
0.01
0.50
9.66
90.34
1161
20.2
30.5
JJ5
5/9
433
374
0.4
2
375
7
31
7
345
225
297
167
184
187
1059
3.94
4.93
0.12
0.18
0.34
0.02
0.01
0.15
9.70
90.30
1172
35.5
44.8
!§
10/9
361
297
0.4
1
298
6
23
0
269
137
301
127
148
151
864
3.53
4.93
0.11
0.22
0.32
0.01
0.01
0.09
9.22
90.78
951
23.0
38.2
V7
7/22
258
204
0.4
0
204
4
14
0
186
86
243
74
102
101
606
3.35
4.95
0.10
0.31
0.31
0.01
0.01
0.21
9.26
90.74
668
25.2
39.1
J_8
7/21
260
204
0.4
206
14
0
188
87
243
76
104
104
613
3.60
4.96
0.11
0.31
0.32
0.01
0.01
0.26
9.57
90.43
678
28.9
47.8
JjJ
7/21
258
198
0.4
205
4
13
0
187
100
221
84
105
103
613
3.85
4.85
0.12
0.31
0.33
O.02
0.01
0.17
9.66
90.34
678
47.8
61.4
-------
UTAH POWER 4 LIOHT COMPANY
HUNTINGTON CANYON *8
C-E POWER SYSTEMS
FIELD TESTING »ND
PERFOBMANCE RESULTS
BASELINE OPERATION STUDY
CD
0>
TEST NO.
DATE
UNIT LOAD
PRODUCTS OF COMBUSTION
AIR HEATER INLET
DAY AIR!
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS
GAS ENTERiNQ AIR HEATER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE EFFICIENCY
GAS DROP
AIR RISC
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
MOISTURE
ASH
HHV
X(G/J
KG/S
°C
°C
°c
Kj/KG
TEST RESULTS
1
5/7
429
425
432
405
414
335
399
440
468
508
539
498
467
31
6.0
70.8
806
831
291
63.30
4.90
0.90
12.10
0.50
8.40
9.90
25144
2
5/5
437
438
445
413
419
319
406
450
477
526
564
526
486
36
7.2
70.4
208
231
296
65.50
5.10
1.20
9.30
0.70
7.30
10.90
27889
8A
5/7
428
458
466
434
439
321
427
471
498
538
575
538
501
37
6.9
70.6
214
831
303
67.30
5.30
0.80
9.50
0.50
7.70
8.90
88517
3
5/7
428
489
497
460
466
321
453
502
530
579
622
583
540
43
7.4
70.7
219
234
309
61.20
4.80
0.80
9.90
0.50
8.10
14.70
25726
4
10/10
360
487
496
420
426
381
413
500
528
434
506
475
402
72
16.7
67.1
193
228
288
65.30
5.10
1.30
9.40
0.50
8.10
10.30
27679
5
7/16
259
442
450
397
404
316
391
456
483
286
321
299
264
35
12.2
69.5
170
203
244
66.80
5.20
1.10
11.60
0.50
8.70
6.10
28424
6
7/15
260
452
460
431
437
321
424
465
491
309
328
307
288
19
6.2
71.5
181
208
253
68.30
5.30
1.30
9.70
0.50
6.70
8.20
28866
7
7/16
258
533
542
484
489
317
476
546
574
346
385
363
324
39
11.2
71.3
185
207
260
66.30
5.10
1.20
10.60
0.50
8.80
7.50
28168
B
5/5
430
430
438
391
397
322
385
443
470
500
555
517
462
55
11.0
69.0
204
233
296
66.30
5.30
0.90
10.10
0.50
7.10
9.80
27912
9
4/30
428
447
454
418
426
319
412
461
488
518
560
521
480
41
8.0
69.9
211
232
301
64.80
5.00
0.90
12.40
0.50
8.20
8.20
27075
-------
UTAH POWER A LroHT COMPANY
HUNTINGTON CANYON 0S.
C-E POWER SY&TEHS
FIELD TCSTIHQ AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST RESULTS
TEST NO.
DATE
UN IT LOAD
PRODUCTS OF COMBUSTION
AIR HEATER IHUCT
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRV AIR
WET AIR
DRV PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS
GAS ENTERING AIR HCATCR
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE frr icicricv
GAS DROP
AIR RISC
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NlTROCEN
OXYGEN
SULFUR
MOISTURE
ASH
HHV
1975
W
X6/J
KG/S
Kj/K
JO
5/1
428
499
508
460
466
321
453
512
540
573
62B
590
535
55
9.6
70.1
216
03-1
109
65.60
ri.20
^.90
10.61
0.40
8.00
9.30
27633
11
7/17
256
432
44O
411
417
317
404
446
473
295
315
293
273
19
6.6
70.9
176
206
249
66.50
5.10
1.30
10.60
0.50
9.00
7.00
28238
J2
7/18
259
516
525
464
489
320
476
529
557
352
380
358
330
28
7.9
72.2
184
202
255
67.30
S.30
1.20
9.50
0.50
7.70
8.50
28633
J3
5/9
433
401
407
372
380
318
366
414
440
470
511
473
432
41
8.7
68.8
202
221
293
64.20
4.90
1.10
10.30
0.50
7.50
11.50
27051
J4
5/9
433
415
422
389
396
318
382
429
454
489
528
490
451
39
7.9
69.7
208
231
299
64.80
4.90
1.20
10.10
0.50
7. BO
10.70
27331
J5
5/9
433
464
472
442
448
320
434
478
505
556
592
553
518
35
6.4
71.9
222
228
309
63.80
4.90
1.00
10.20
0.80
7.60
11.70
26865
16
10/9
361
446
454
404
410
323
397
459
486
415
462
431
384
48
11.4
70.3
200
ess
284
57.70
5.20
1.20
•1.40
0.50
8.40
7.60
28447
17
7/22
258
443
450
405
412
318
398
456
483
292
323
300
27O
30
10.3
67.9
170
207
250
66.80
5.10
1.30
10.80
0.50
9.00
6. 5O
28214
J8
7/21
260
473
481
420
426
320
413
486
513
306
348
326
285
42
13.6
67.3
171
209
254
67.50
5.30
1.30
9.70
0.50
8.00
7.70
28633
J9
7/21
258
520
529
484
489
322
476
533
561
350
380
359
329
30
8.6
70.1
182
209
260
67.00
5.20
1.20
9.50
0.50
7.00
9.60
28214
-------
UTAH POWER & LIGHT COMPANY
HUNTINGTON CANYON *2
C-t POWER SYSTEMS
FitLD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST RESULTS
TEST HO.
DATE
UNIT LOAD
FLCWS
TetDwATER (MEASURED^
AUXILIARY STEAM - SH (PLANT INSTRUMENTATION^
SH SPRAY (HEAT BALANCED
MAIN STEAM (CALCULATED)
TURBINE LEAKAGE (TURBINE HEAT BALANCE 1
HP HTR. EXTRACTION (HEAT BALANCE!
RH SPRAY ('HEAT BALANCE)
RH STEAM (CALCULATED)
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM - SH DESH
SH DESH . SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY
DRY GAS Loss
MOISTURE IN FUCL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
TOTAL LOSSES
EFFICIENCY
HEAT INPUT
HEAT INPUT FROM FUEL
EXCESS AIR
AIR HEATCR INLET
AIR HEATER OUTLET
1975
MW
KO/S
i)
MJ/S
*
MJ/s
*
Jl
9/17
430
375
0.4
0
375
7
32
1
336
164
360
150
173
177
1023
4.13
5.01
0.13
0.19
0.35
0.02
0.01
0.26
10.09
89.91
1138
19.8
36.4
2
9/18
426
370
0.4
1
371
7
30
0
334
163
357
149
177
175
1020
3.71
4.99
0.11
0.19
0.32
0.02
0.01
0.25
9.60
90.40
1128
21.5
26.2
3
9/20
434
T69
0.4
0
368
7
32
4
334
166
350
152
180
178
1025
3.85
5.00
0.12
0.19
0.31
0.02
0.01
0.55
10.03
89.97
1140
20.9
36.4
4
18/13
356
297
0.3
0
297
6
23
0
268
114
323
107
161
13B
843
3.63
4.90
0.11
0.23
0.36
0.02
0.01
0.61
9.86
90.14
935
16.8
35.4
5
10/11
351
295
0.4
0
295
6
23
1
268
126
310
117
144
144
841
3.97
4.91
0.12
0.23
0.32
0.01
0.01
0.20
9.77
90.23
932
19.9
37.3
6
10/12
360
299
0.4
0
299
6
23
1
271
124
318
111
157
147
857
3.26
4.89
0.10
0.22
0.32
0.01
0.01
0.22
9.03
90.97
942
20.8
34.2
7
10/12
257
218
0.4
0
218
5
15
0
199
90
2S6
79
112
109
646
2.97
4.83
0.09
0.29
0.34
0.01
0.01
0.46
9.01
90.99
710
22.6
37.3
8
10/5
270
207
0.4
B
214
4
14
0
196
93
233
83
120
112
641
3.34
4.85
0.10
0.30
0.32
0.01
0.01
0.22
9.16
90, B4
706
24.4
38.1
9
9/17
429
375
0.4
0
375
7
32
0
336
170
355
152
165
171
1014
4.28
4.96
0.13
0.19
0.34
0.02
0.01
0.28
10.20
89.80
1129
26.3
40.0
U>
9/10
428
370
0.4
0
370
7
32
5
336
172
347
155
180
178
1031
4.35
4.76
0.13
0.19
0.33
0.02
0.01
0.24
10.03
89.97
1147
27.4
47.4
jM
9/18
429
369
0.4
0
369
7
31
6
336
175
340
159
172
182
1028
3.98
5.07
0.12
0.19
0.32
0.02
0.01
0.18
9.87
90.13
1141
29.3
31.7
J2
10/11
351
295
0.4
0
295
6
23
0
266
132
305
119
141
141
839
3.79
5.06
0.12
0.23
0.34
0.01
0.01
0.22
9.79
90.21
930
29.3
41.9
12
12/13
356
299
0.3
0
299
6
24
0
270
124
319
114
157
142
855
4.06
4.89
0.13
0.22
0.32
0.01
0.01
0.38
10.03
89.97
950
28.0
48.7
14
12/13
356
299
0.3
0
299
6
24
1
270
125
316
113
158
142
854
3.89-
4.99
0.12
0.22
0.31
0.02
0.01
0.41
9.96
90.04
948
31.7
49.9
15
7/23
256
201
0.4
2
203
4
13
0
185
87
237
76
103
101
604
3.47
4.86
0.11
0.31
0.33
0.02
0.01
0.12
9.23
90.77
665
25.1
39.5
J6
7/24
259
204
0.4
6
210
4
14
0
192
88
241
77
117
106
629
3.52
4.93
0.11
0.30
0.32
0.02
0.01
0.20
9.42
90.58
694
24.7
38.1
-------
BIASED FIRING OPERATION STUDY
TEST RESULTS
TtST NO.
DATE
UNIT LOAD
PRODUCTS OF CCTBUSTION
AIR HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS
GAS ENTER INC AIR HEATER
GAS LEAVINQ AIR HEATER
AIR ENTERING AIR HEATCR
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE ErrICIENCY
GAS DROP
AIR RISE
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
MOISTURE
ASH
HHV
10
\Z
.16
1975 9/17
MW 430
436
444
396
422
383
390
449
477
KG/S
480
542
505
444
61
% 12.7
% 67.3
°C 211
°C 242
•C 313
* 66.80
% 5.20
< 1.20
* 9.70
i 0.50
< 8.OO
* 8.60
KJ/KO 28307
9/18
426
406
413
404
430
391
398
419
445
485
502
466
449
17
3.6
70.5
218
238
309
67.50
5.30
1.30
9.70
n. 40
7.40
8.40
28470
9/20
434
436
443
399
425
386
393
449
476
485
542
505
448
57
11.9
69.5
215
240
310
65.90
5.10
1.20
10.00
0.40
8.10
9.30
27786
12/13
356
457
464
406
432
394
401
468
495
404
463
434
375
60
14.7
68.2
188
222
275
70.30
5.40
1.00
5.70
0.50
6.50
10.60
2B656
10/11
351
446
454
404
429
390
396
460
487
400
454
423
369
54
13.4
65.4
182
228
279
68.00
5.20
1.40
10.80
0.50
6.90
7.20
281 45
10/12
360
431
438
401
427
388
395
444
470
402
443
413
372
41
10.2
71.0
196
218
276
67.80
5.30
1.20
9.60
0.50
7.60
B.OO
28680
10/12
257
434
442
402
427
388
395
448
475
304
337
314
280
34
11.1
70.3
172
199
244
66.50
5.10
1.30
10.60
0.50
8.30
7,70
28214
10/5
270
441
448
410
436
397
403
454
480
307
339
316
285
32
10.2
68.4
173
204
253
67.00
5.20
1.30
9.70
0.50
7.80
8.50
28470
9/17
429
446
454
416
442
403
409
460
487
499
549
512
462
50
10.1
67.9
214
243
316
66.80
5.10
1.30
10.60
0.50
8.00
7.70
28168
9/10
428
467
475
418
444
404
411
482
508
508
582
545
471
74
14.5
67.2
208
239
310
65.30
4.80
1.20
10.70
O.-IO
7.40
10.20
27447
9/18
429
425
432
430
457
418
425
438
465
522
531
494
484
9
1.7
70.9
224
242
316
67.60
5.30
1.40
9.80
0.40
8.00
7.50
28424
10/11
351
466
474
438
465
425
432
480
507
433
472
441
402
39
9.0
69.8
198
223
283
67.20
5.20
1.30
10.00
0.40
8.10
7.80
27656
12/13
356
498
506
441
467
429
436
510
538
444
511
481
414
67
15.0
67.8
190
224
281
71.80
5.50
1.30
5.80
0.50
7.10
8.00
29517
12/13
356
479
487
433
460
421
428
491
519
436
492
462
406
56
12.8
68.5
191
223
279
66.10
5.20
1.20
9.50
0.40
8.10
9.50
28075
7/23
256
442
450
409
435
397
403
455
482
290
320
299
268
31
10.7
66.5
166
208
249
66.30
5.20
1.40
9.40
0.50
7.40
9.80
28447
7/24
259
443
450
413
439
400
407
' 456
482
304
335
312
282
30
9.9
66.6
168
208
252
67.20
5.30
1.20
9.60
0.50
7.40
8.80
28517
-------
UTAH POWER i LIGHT COMPANY
HUNTINOTON CANYON 12
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDWATEK (MEASURED)
AUXILIARY STEAM - SH (PLANT INSTRUMENTATION^
SH SPRAY (HEAT BALANCED
MAIN STEAM (CALCULATED^
TURBINE LEAKAGE (TURBINE HEAT BALANCED
HP HTR. EXTRACTION (HEAT PALANCE^
RH SPRAY (HEAT BALANCED
RH STEAM (C»LCUL»TCD^
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM . SH DF.SH
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY
DRY GAS LOSS
MOISTURE IN FUEL Loss
MOISTURE IN AIR Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYRITE REJECTION Loss
CARBON Loss
TOTAL LOSSES
Err ICIENCY
HEAT INPUT
HEAT INPUT TRON FUEL
EXCESS AIR
AIR HEATER INLET
AIR HEATER OUTLET
TEST RESULTS
1975
Mrf
KO/S
MJ/S
t
MJ/S
*
J^
9/17
488
369
0.4
0
3G9
7
31
3
333
174
341
157
173
175
1020
4.52
5.07
0.14
0.19
0.34
0.03
0.01
0.20
10.49
89.51
1140
27.0
46.8
2
9/26
430
372
0.4
1
372
7
32
3
336
173
348
158
174
178
1030
3.96
5.10
0.12
0.19
0.33
0.02
0.01
0.14
9.87
90.13
1143
26.2
31.8
3
9/26
430
372
0.4
0
372
7
32
3
336
173
347
158
174
177
1029
4.07
5.11
0.12
0.19
0.33
0.02
0.01
0.24
10.08
89.92
1145
26.2
32.9
4
9/26
430
370
0.4
0
370
7
32
5
336
171
346
154
179
179
1029
4.06
4.96
0.12
0.19
0.34
0.03
0.01
0.30
10.01
89.99
1143
25.5
35.6
5
9/26
431
370
0.4
0
370
7
32
5
335
174
343
156
175
178
1026
3.97
5.03
0.12
0.19
0.33
0.02
0.01
0.28
9.95
90.05
1139
25.2
32.6
6
10/1
430
372
0.4
0
372
7
31
0
333
165
356
153
181
174
1029
3.91
5.09
0.12
0.19
0.33
0.02
0.01
0.24
9.91
90.09
1142
18.5
29.3
7
10/1
429
372
0.4
0
372
7
32
0
334
166
356
153
177
174
1025
3.94
5.11
0.12
0.19
0.32
0.02
0.01
0.59
10.30
89.70
1143
19.2
30.1
B
10/1
428
370
0.4
0
370
7
31
1
332
167
352
156
174
174
1023
3.63
5.03
0.11
0.19
0.32
0.02
0.01
0.24
9.54
90.46
1130
19.2
27.8
9
9/27
428
369
0.4
0
369
7
31
0
331
185
330
158
169
172
1014
4.58
5.08
0.14
0.19
0.32
0.02
0.01
0.22
10.56
89.44
1133
32.1
48.3
TO
10/1
429
369
0.4
0
368
7
32
0
330
168
328
163
169
166
1015
4.86
4.96
0.15
0.19
0.35
0.03
0.01
0.27
10.82
89.18
1138
33.8
57.8
r^
10/1
430
370
0.4
0
370
7
32
0
331
189
329
165
169
167
1019
4.64
5.04
0.14
0.19
0.32
0.02
0.01
0.16
10.52
89.48
1140
33.8
49.5
J2
10/5
427
370
0.4
0
370
7
31
0
332
164
354
149
177
174
1018
4.03
4.95
0.12
0.19
0.32
0.02
0.01
0.25
9.89
90.11
1130
23.1
29.2
-------
UTAH POWER & LIGHT COMPANY
HUNTINGTON CANYON fS
C-E POVICR SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
UNIT LOAD
FLOWS
FEEDVATER (MEASURED)
AUXILIARY STEAM - SH (PLANT INSTRUMENTATION)
SH SPRAY (HEAT BALANCE)
MAIN STEAM (CALCULATED)
TURBINE LEAKAGE (TURBINE HEAT BALANCE)
HP HTR. EXTRACTION (HEAT BALANCE)
RH SPRAY (HEAT BALANCE)
RH STEAM (CALCULATED)
UNIT ABSORPTION
ECONOMIZER
FURNACE
DRUM - SH DESH
SH DESH - SH OUTLET
REHEATER
TOTAL
UNIT EFFICIENCY
DRY GAS Loss
MOISTURE In FUEL Loss
MOISTURE IN A.IH Loss
RADIATION Loss
ASH PIT Loss
HEAT IN FLY ASH Loss
PYHITE REJCCTION Loss
CARBON Lose
TOTAL LOSSES
HEAT INPUT
HEAT INPUT FROM TUEL
EXCESS AIR
AIR HEATER IMLCT
AIR HEATER OUTLET
1975
MW
X.Q/S
MJ/s
*
MJ/s
U
10/4
434
364
0.4
0
364
7
30
4
331
169
339
155
182
176
1022
4.21
5.10
0.13
0.19
0.32
0.02
0.01
0.21
10.17
89.83
1137
25.1
36.7
14
10/5
422
370
0.4
0
370
7
32
1
332
158
361
145
145
166
1005
3.74
4.97
0.11
0.19
0.33
0.02
O.oi
o.?o
9.68
00.32
1113
22.0
29.9
TEST
J_5
10/4
42S
370
0.4
0
370
7
31
0
332
163
356
148
181
172
1019
4.18
5.05
0.13
0.19
0.33
0.02
0.01
0.28
10.18
B9.82
1135
25.1
31.8
RESULTS
2S
10/3
427
372
0.4
0
372
7
32
3
336
166
356
148
180
173
1023
4.13
5.05
0.13
0.19
0.32
0.02
0.01
0.26
10.10
B9.90
1138
21.3
31.4
V7
10/3
424
377
0.4
0
377
7
32
5
342
161
367
147
176
175
1026
4.06
5.05
0.12
0.19
0.32
0.02
0.01
0.22
9.99
90.01
1140
23.5
33.6
11
10/3
429
367
0.4
0
367
7
31
5
334
166
348
151
181
178
1023
4.09
5.12
0.13
0.19
0.32
0.02
0.01
0.63
10.49
89.51
1143
21.7
31.6
12
10/6
417
374
0.4
0
374
7
31
0
335
155
369
142
183
177
1025
4.09
5.05
0.13
0.19
0.32
0.02
0.01
0.40
10.21
89.79
1 1 42
18.5
32.8
20
10/8
426
377
0.4
0
377
7
32
0
338
157
370
143
184
170
1024
4.02
5.04
0.12
0.19
0.32
0.02
0.01
o.43
10.15
B 1.85
1140
19.6
35.1
HI
10/9
356
299
0.4
0
299
6
23
0
270
119
323
109
151
140
642
3.71
4.98
0.11
0.23
0.33
0.02
0.01
0.20
9.59
90.41
931
19.3
39.6
22
10/9
358
299
0.4
0
299
6
23
2
272
130
311
180
144
147
853
3.50
4.95
0.11
0.22
0.32
0.02
0.01
0.22
9.35
90.65
941
21.5
37.4
23
10/12
253
218
0.4
0
218
5
15
0
199
87
261
73
108
107
634
3.02
4.95
0.09
0.30
0.34
0.01
0.01
0.47
9.21
90.79
698
22.8
34.8
24
10/5
265
216
0.4
1
217
3
15
0
197
91
251
78
114
105
638
3.32
4.95
0.10
0.30
0.32
0.01
0.01
0.22
9.24
90.76
703
23.9
36.7
-------
UTAH POWER t LIGHT COMPANY
HUNTING-TON CANYON #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST RESULTS
TEST NO.
DATE
UNIT LOAD
PRODUCTS OF COMBUSTION
Am HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY Am
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS
GAS ENTERING AIR HEATER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
AIR HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE EFFICIENCY
GAS DROP
AIR RISE
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
MOISTURE
ASH
HHV
1975
MW
Ma/J
KO/S
%
%
"C
°c
"C
%
%
%
I
f,
t
Kj/KG
J_
9/17
428
479
487
427
454
414
481
492
519
517
592
555
480
75
14.5
67.2
212
243
316
65.40
5.10
1.10
9.40
0.50
7.40
11 .10
27214
2
9/26
430
417
424
419
446
406
412
430
457
509
522
484
471
13
2.6
69.1
210
241
304
63.70
4.90
1.30
10.20
0.50
9.40
10.00
27121
3
9/26
430
427
434
418
445
406
412
440
466
509
534
497
472
25
4.9
68.5
209
241
306
65.90
5.20
1.20
9.50
0.40
8.30
9.50
27889
4
9/26
430
433
440
415
441
401
408
447
473
504
541
504
466
37
7.4
68.3
208
239
304
63.90
4.80
1.20
9.70
0.40
8.30
11.70
26842
5
9/26
431
421
428
411
437
397
404
434
461
498
525
488
460
27
5.5
68.7
210
241
306
65.10
5.00
1.30
10.40
0.40
8.70
9.10
27586
6
10/1
430
416
423
394
420
381
387
428
455
479
520
483
442
40
8.4
68.2
210
242
309
66.20
5.20
1.20
9.50
0.50
8.30
9.10
27982
7
10/1
429
422
429
399
425
386
393
434
461
486
527
490
449
41
8.5
68.2
209
241
307
67.20
5.30
1.30
9.60
0.40
7.80
8.50
28098
8
10/1
428
411
417
396
421
383
389
423
450
476
508
472
440
32
6.7
70.5
216
242
307
67.50
5.30
1.20
9.70
0.40
8.00
7.90
28540
_9
9/27
428
477
485
437
464
424
432
490
517
526
586
549
489
60
11.4
66.9
208
241
311
66.80
5.20
1.10
9.70
0.50
8.50
8.20
281 91
12
10/1
429
503
511
439
466
426
434
516
543
530
618
582
494
88
16.7
65.8
208
245
316
63.90
4.90
1.20
9.00
0.40
7.80
12.80
27121
^1
10/1
430
478
486
440
467
427
434
490
518
532
590
553
495
58
10.9
67.2
213
246
317
67.00
5.20
1.30
9.70
0.50
8.40
7.90
28447
12
10/5
427
412
419
406
432
392
399
426
452
488
510
473
451
22
4.6
68.2
210
242
309
66.60
5.10
1.30
10.60
0.50
7.70
8.20
28098
-------
UTAH POWER t LIGHT COMPANY
HUNTINOTON CANYON |3
C-E POWER
FIELD TESTiNO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO,
PRODUCTS OF COKBUSTIOH
AIR HEATER INLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
AIR HEATER OUTLET
DRY AIR
WET AIR
DRY PRODUCTS
WET PRODUCTS
GAS AND AIR FLOWS
GAS ENTERING AIR ME:AT ER
GAS LEAVING AIR HEATER
AIR ENTERING AIR HEATER
AIR LEAVING AIR HEATER
AIR HEATER LEAKAGE
A|R HEATER PERFORMANCE
AIR HEATER LEAKAGE
GAS SIDE EFFICIENCY
GAS DROP
AIR RISC
TEMPERATURE HEAD
FUEL ANALYSIS
CARBON
HYDROGEN
NITROGEN
OXYGCM
SULFUR
Mo i sruRt:
ASH
HHV
1975
MW
/Mb/J
KQ/S
*
%
°c
°c
°c
r-
f
r
?•
>'
•'••
• !/*<-.
22
10/4
434
437
444
418
439
400
4O7
450
-177
499
T42
505
462
43
a.c
67.7
211
213
311
R7.20
0.30
1.40
'1.60
O.SO
h . GO
7.40
Pfjin
11
10/5
422
412
419
400
426
487
393
435
451
474
502
466
438
28
6.0
61. 7
213
230
306
64 . 90
S.OT
1.30
in. 10
o.r)0
8.10
'1.90
27563
TEST
15
10/4
429
427
434
419
446
406
412
441
468
506
531
493
468
25
4.9
68.0
210
241
308
5",. 90
5.10
1.10
10.50
O.50
7.50
9.40
27400
RESULTS
26
10/3
4S7
424
431
404
430
391
398
436
463
489
527
490
453
38
7.7
67.-)
209
243
•310
5fl.40
r>.40
1.20
'.80
0.40
7.50
7.30
2R84r'
J7
10/3
424
428
436
409
435
396
403
441
468
496
534
497
459
38
7.6
67. q
207
239
305
66.90
•i.P.0
1.20
0.70
0.50
8.40
8.10
28284
J_8
10/3
429
429
433
410
437
397
4O3
443
470
499
537
499
461
38
7.0
68.2
P12
242
310
67.20
5.20
1.20
10.80
O.'iO
8.00
7.10
27703
12
10/6
417
430
437
396
422
383
390
442
469
482
536
499
445
54
11.?.
66.7
204
239
305
67.40
5.30
1.20
9.70
0,50
7,50
8.40
28284
20
10/8
426
435
442
398
424
385
391
448
475
483
541
504
446
58
12.0
67.3
204
237
303
. 30
1 . 40
'.70
Vi'1
7.60
!:.30
28377
23
10/12
253
432
440
406
433
394
401
445
472
3CE
330
307
280
27
9.0
69.5
167
196
240
67.2i
5.13
1 .'>''
U.Oo
0.-10
8.30
7.91
28424
24
10/5
265
442
449
414
440
4O1
408
455
482
309
339
316
287
30
9.5
68.5
172
202
251
67.30
5.30
1.30
9.70
0.40
7.60
8.40
28284
-------
UTAH POWER »NO LIGHT COMPANY
HUNTINGTON CANYON fS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C* LOAD
FLOWS
C FEEDWATER
B* MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STH. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STEAM TO STAE
B AIR FLOW TO BOILER
PRESSURES
STEAM & WATER
C FEEDWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1ST STAGE
C RH INLET, LEFT
C RH INLET, RIGHT
C RH INLET, AVG.
C RH OUTLET
C HP HTR. 2-7 STEAM IN
AIR i GAS
B FD FAN 2-1 DISCHARGE R
B FD FAN 2-2 DISCHARGE L
B FD FAN DISCHARGE Avo.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. Avo.
B UINDBOX PRESSURE R
B WIHDBOX PRESSURE L
B WINOBOX PRESSURE AVG.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
8 AH 2-1 GAS OUT PRESS. R
B AH 2-2 GAS OUT PRESS. L
B AH GAS OUT PRESSURE Avo.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESSURE AVG.
* C = COMPUTER DATA; B = BOARD DATA
1975
KM
TO^B/HR
PSIG
"HgO
1
5/7
09:25
429
2913
3050
0
0
0
58.9
58.9
0
0
3.1
3240
2825
2737
2449
1841
572
576
574
533
550
8.4
8.6
8.5
3.5
3.6
3.6
3.2
3.3
3.3
-0.5
1.80
2.28
-12.7
-11.5
-12.1
-15.6
-13.5
-14.6
2
5/5
17:23
427
2945
3000
0
0
0
SB. 9
SB. 9
0
0
3.1
3350
2810
2719
2441
1834
568
572
570
529
548
9.6
9.6
9.6
3.7
3.9
3.8
3.5
3.6
3.6
-0.6
2.10
2.52
-13.3
-12.6
-13.0
-16.6
-15.0
-15.8
2A
5/7
16:50
428
2910
3050
0
0
0
58.9
SB. 9
0
0
3.1
3510
2B25
2740
2452
1841
570
574
572
530
550
11.6
11.6
11.6
4.1
4.2
4.2
5.5
5.5
5.5
-0.5
2.12
2.78
-15.0
-13.5
-14.2
-18.4
-16.1
-17.3
3
5/7
14:15
428
2912
3000
0
0
0
58.9
58.9
0
0
3.1
3820
2825
2737
2450
1841
570
574
572
530
548
12.9
12.9
12.9
4.6
4.8
4.7
5.7
5.7
5.7
-0.5
2.43
3.06
-15+
-15+
-15+
-20.0
-17.7
-18.9
4
10/10
03:30
360
2249
2350
14.1
12.0
7.1
58.8
58.8
1.2
1.2
3.1
2720
2689
2615
2406
1435
465
469
467
429
382
8.2
8.2
B.2
2.7
3.1
2.9
4.1
4.1
4.1
-1.0
1.6
1.98
-10.4
-11.2
-10.8
-13.1
-11.1
-12.1
5
7/16
11:30
259
1535
1525
10.2
1.4
0
13.3
13.25
0
0
3.0
1700
2532
2485
2385
939
311
314
313
278
412
4.0
3.9
4.0
1.19
1.37
1.28
2.2
2.2
2.2
NA
0.32
0.65
-5.6
-5.1
-5.4
-6.8
-5.4
-6.1
6
7/15
15:05
260
1520
1520
23.2
13.5
0
9.3
9.2
0
0
3.0
1750
2515
2473
2374
938
313
314
314
279
412
4.5
4.5
4.5
1.26
1.45
1.36
2.5
2.5
2.5
-0.6
0.46
0.67
-5.4
-5.1
-5.3
-7.1
-5.7
-6.4
7
7/16
15:45
258
1503
1502
31.5
21.9
0
18.5
1B.5
0
0
3.0
2200
2523
2481
2384
935
311
312
312
278
412
6.6
6.6
6.6
1.77
1.88
1.83
3.9
3.9
3.9
-0.4
0.64
1.05
-6.8
-6.2
-6.5
-8.0
-7.2
-7.6
8
5/5
13:40
430
2900
3040
0
0
16.5
58.9
58.9
0
0
3.1
3140
2818
2724
2445
1841
574
578
576
534
553
9.6
9.6
9.6
3.5
3.6
3.6
4.5
4.5
4.5
-0.6
1.82
2.23
-12.5
-11.4
-12.0
-15.6
-13.5
-14.6
9
4/30
15:07
428
2898
3000
0
0
0
58.9
58.9
0
0
3.0
3380
2811
2723
2435
1832
569
573
571
528
548
9.9
9.9
9.9
3.8
3.9
3.9
4.3
4.3
4.3
-0.4
1.96
2.47
-13.0
-12.0
-12.5
-16.3
-14.8
-15.6
266
SHEET!B24
-------
UTAH POWER AND LIGHT COMPANY
HUNTIHCTON CANYON #2
C-E POWCR SYSTEMS
F|<-10 TeSTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
TEST NO.
DATE
TIME
C" LOAD
FLOWS
C FEEOVATER
8* MAIN STEAH
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STH. AH'2-1
C EXT. STH. TO STM. AH 2-2
C Aux. STM. TO STH. AH 2-1
C Aux. STM. TO STH. AH 2-2
C Aux. STEAM TO STAE
B AIR FLOW TO BOILER
PRESSURES
STEAM AND WATCR
C FEEDVATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE IST STAGE
C RH INLET, LEFT
C RH INLET, RIGHT
C RH INLET, Avc.
C RH OUTLET . •
C HP HTR. 2-7 STEAM IN
AIR AND GAS
B FD FAN 2-1 DISCHARGE R
B FD FAN 2-2 DISCHARGE L
B FO FAN DISCHARGE AVG.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESSURE R
B WINOBOX PRESSURE L
B WINDBOX PRESSURE Avc.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT PRESS. R
B AH 2-2 GAS OUT PRESS. L
B AH GAS OUT PRESSURE AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESSURE AVG.
* C » COHPUTER DATA; B = BOARD DATA
BOARD AND
1975
(•W
103LB/m
PSIG
"H20
10
5/1
17:50
428
2995
3050
0
0
0
58.9
58.9
0
0
3.0
3720
2812
2725
2438
1834
568
571
570
528
546
12.0
12.0
12.0
4.4
4.6
4.5
4.8
4.8
4.8
-0.5
2.28
2.95
-15+
-15+
-15+
-18.9
-17.5
-18.2
11
7/17
11:15
256
1517
1504
20.7
13.0
0
14.2
14.3
0
0
3.0
1700
2513
2472
2374
931
310
311
311
278
409
3.8
3.7
3.8
1.21
1.38
1.30
1.8
1.8
1.B
-O.V
0.38
0.75
-5.2
-4.8
-5.0
-6.8
-5.4
-6.1
COMPUTER DATA
J2
7/18
10:00
259
1482
1503
33.0
25.6
0
19.1
19.3
0
0
3.0
2100
2143
2108
1978
952
313
314
314
280
412
6.4
6.4
6.4
1.73
1.83
1.78
3.9
3.9
3.9
-0.5
0.5
1.04
-6.5
-5.8
-6.2
-8.2
-6.5
-7.4
22
5/9
15:30
433
2930
3038
0
0
27.5
58.9
58.9
0
0
3.0
2980
2828
2738
2453
1846
579
583
581
539
556
8.2
8.2
8.2
3.1
3.3
3.2
3.6
3.6
3.6
-0.5
1.54
2.0
-12.0
-10.9
-11.5
-14.6
-12.5
-13.6
If
5/9
10:15
433
2915
3012
0
0
31.0
58.9
58.9
0
0
3.0
3120
2826
2738
2456
1845
577
581
579
538
556
9.0
9.0
9.0
3.4
3.5
3.5
3.7
3.7
3.7
-0.6
1.64
2.27
-13.1
-12.1
-12.6
-16.1
-13.6
-14.9
V5
5/9
18:15
433
2905
3012
0
0
27.3
58.9
58.9
0
0
3.0
3620
2826
2737
2454
1845
575
579
577
536
554
11.5
11.6
11.6
4.2
4.4
4.3
5.0
5.0
5.0
-0.6
2.19
2.90
-15+
-15+
-15+
-18.8
-16.0
-17.4
16
lO/'f
03:O->
-61
2258
2350
4.4
1.2
22.7
58.8
58.8
1.2
1.2
3.1
2720
2699
2623
2417
1430
466
468
467
429
385
B.8
B.5
B.5
2.6
3.0
2.8
4.6
4.6
4.6
-1.0
1.45
1.89
-10.3
-10.1
-10.2
-12.1
-11.0
-11.6
17
,/32
11:15
258
1571
1508
0
0
0
7.2
7.3
0
0
3.0
1660
2537
2492
2363
932
310
311
311
278
412
3.4
3.4
3.4
1.18
1.37
1.28
1.5
1.5
1.5
-0.4
0.39
0.59
-5.2
-4.5
-4.9
-6.4
-5.1
-5.8
IS
7/21
16:30
260
1573
1532
9.8
2.5
0
8.4
8.5
0
0
3.0
1710
2504
2458
2359
931
311
315
313
279
409
3.2
3.2
3.2
1.22
1.42
1.32
1.7
1.7
1.7
-0.6
0.38
0.84
-5.6
-5.0
-5.3
-6.9
-5.5
-6.2
19
7/21
14:00
258
1529
1505
26.3
19.2
0
12.0
12.1
0
0
3.0
2020
2501
2458
2362
926
3O9
311
310
277
412
5.6
5.2
5.4
1.60
1.75
1.68
2.8
2.8
2.8
-0.6
0.67
0.94
-6.5
-5.9
-6.2
-B.I
-6.4
-7.3
2S7
SHEET BS5
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERF-ORMANCE RESULTS
TEST NO.
DATE
TIME
LOAD
TEMPERATURES
AIR AND GAS
AH 2-1 AIR IN
AH 2-2 AIR IN
AH Avo. AIR IN
BASELINE OPERATION STUDY
BOARD AND COMPUTER DATA
1 2 2A 3 4
1975
MM
AH 2-1 AIR OUT
AH 2-2 AIR OUT
AH Avo. AIR OUT
AH 2-1 GAS IN
AH 2-2 GAS IN
AH Avo. GAS IN
AH 2-1 GAS OUT
C AH 2-2 GAS OUT (1)
C AH Avc. GAS OUT
STEAM AND WATER
C FW IN TEMP. TO ECON.
C ECON. OUT Avs.
C BOILER DOWNCOMER
C SH DESH INLET L
C SH DESH INLET R
C SH DESH INLET Avo.
C SH DESH OUTLET L
C SH DESH OUTLET R
C SH DESH OUTLET Avc.
C SH OUTLET
C THROTTLE STEAM
C RH TURBINE L
C RH TURBINE R
C RH TURBINE Avc.
C RH BOILER L
C RH BOILER R
C RH BOILER Avc.
C RH OUTLET
C HP HTR. 2-7 STEAM IN
C HP HTR. 2-7 FW IN
C HP HTR. 2-7 DRAIN
C Aux. STEAH TEMP.
FAN DAMPER POSITION
B FD FANS
B ID FANS
SPRAY VALVE POSITION
B SH SPRAY
B RH SPRAY
C = COMPUTER DATA; B = BOARD DATA
(1) TC READING OPEN
•t OPEN
OPEN
5/7
19:25
429
99
87
94
499
526
512
693
700
697
253
NA
253
484
575
678
739
739
739
744
742
743
982
971
613
614
614
611
609
610
1003
611
413
423
545
68
62
0
0
5/5
17:23
427
96
88
92
504
528
516
700
706
703
257
NA
257
484
579
678
741
751
746
747
748
748
982
976
617
617
617
610
607
609
1000
616
413
422
549
70
63
0
0
5/7
16:50
428
97
87
92
503
533
518
714
722
718
257
NA
257
484
586
679
748
748
74B
753
752
753
988
978
618
618
618
616
614
615
1002
616
413
423
558
75
65
0
0
5/7
14:15
428
94
88
91
504
534
519
718
733
726
260
NA
260
484
592
679
759
753
756
759
757
758
991
980
620
620
620
617
616
617
1002
620
413
423
562
80
72
0
0
10/10
03:30
360
106
106
106
510
520
515
680
675
678
365
268
266
465
551
672
757
763
760
753
757
755
1010
999
601
606
603
584
582
583
1021
602
400
406
550
65
58
11
0
7/16
11:30
259
104
103
104
466
470
468
589
583
586
245
NA
245
428
493
666
738
736
737
730
734
732
1008
999
552
562
557
550
558
554
981
558
368
372
567
46
38
11
0
7/15
15:05
260
106
110
108
471
478
475
599
592
596
244
NA
244
428
499
664
750
746
748
741
735
738
1003
995
550
560
555
547
556
552
992
555
369
372
556
48
40
23
0
7/16
15:45
258
102
98
100
466
480
473
614
612
613
240
NA
240
428
508
665
767
759
763
734
740
737
1006
996
551
560
556
549
556
553
992
•556
368
371
578
56
46
31
0
5/5
13:40
430
96
88
92
506
530
518
700
708
704
256
NA
256
485
576
678
743
750
747
748
748
748
991
980
623
622
623
604
594
599
1003
620
413
423
552
68
61
0
21
4/30
15:07
428
96
89
93
505
528
516
704
710
707
258
NA
258
484
581
677
743
748
746
748
751
750
986
975
616
617
617
615
612
614
1002
616
412
422
556
7?
62
n
0
268
SHEET
-------
UTAH POWCR ANO LIUHT COMPANY
HOHTINOTON CANYON fS
C-f Dowro SrsTEMS
FIELD TESTING «HD
PCBrORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
TEMPERATURES
AIR AND GAS
C AH 2-1 AIR IN
C AH 2-2 Am IN
C AH AVG. AIR IN
C AH 2-1 AIR OUT
C AH 2-2 AIR OUT
C AH AVG. AIR OUT
C AH 2-1 GAS IN
C AH 2-2 GAS IN
C AH Avc. GAS IN
C AH 2-1 GAS OUT
C AH 2-2 GAS OUT (1)
C AH AVG. GAS OUT
STEAM AND WATER
C FW IN TEMP. TO ECON.
C ECON. OUT AVG.
C BOILER DOWNCOMER
C SH DESH INLET I
C SH DESH INLET R
C SH DESH INLET AVG.
C SH DESH OUTLET L
C SH DESH OUTLET R
C SH DESH OUTLET Avtf.
C SH OUTLET
C THROTTLE STEAM
C RH TURBINE L
C RH TURBINE R
C RH TURBINE Avo.
C RH BOILER L
C RH BOILER R
C RH BOILER AVG.
C RH OUTLET
C HP HTR. 2-7 STEAM IN
C HP HTR. 2-7 FW IN
C HP HTR. 2-7 DRAIN
C Aux. STEAM TEMP.
FAN DAMPER POSITION
B FD FANS
8 ID FANS
SPRAY VALVE POSITION
B SH SPRAY
B RH SPRAY
C = COMPUTER DATA; B = BOARD DATA
(l) TC READ INC OPEN
10
1975 5/1
17:50
MM 426
"F
93
89
91
506
531
518
719
717
718
260
NA
260
•F
464
591
679
749
754
752
754
758
756
992
982
621
622
622
618
617
618
1000
618
412
422
563
% OPEN
78
69
f OPEN
0
0
11
7/17
11:15
256
104
112
108
470
473
472
596
586
591
246
NA
246
428
495
664
747
744
746
730
734
732
1006
996
551
561
556
548
556
552
1001
556
368
371
567
45
39
SS
0
J2
7/18
10:00
259
104
105
105
465
480
473
617
611
614
237
NA
237
429
503
642
763
758
761
724
729
727
1005
998
581
600
591
574
591
583
1001
585
369
369
606
56
46
35
0
12
5/9
15:30
433
96
88
92
510
532
521
699
704
702
257
NA
257
485
575
678
744
745
745
750
750
750
985
974
619
619
619
576
570
573
1O03
618
414
424
548
66
59
0
30
_U
5/9
10:15
433
97
86
92
508
533
520
703
709
706
257
NA
257
485
579
679
746
746
747
751
752
752
991
981
623
624
624
573
572
573
1002
621
414
424
556
70
63
0
35
15
5/3
18:'5
433
92
87
89
= 14
53S
526
728
722
725
£62
NA
262
485
593
679
76^
76'
762
765
76S
-757
397
987
625
628
628
•:'."> i
582
587
1004
626
414
-12-5
564
76
67
0
30
'C
i •;•':-
03:00
361
109
1:2
11^
505
'14
= 11
677
679
678
262
260
261
465
548
57?
7RC
767
762
761
767
7^4
1014
1004
605
610
618
55?
"45
= 4 u
1018
6^5
j^n
406
563
63
55
o
26
V7
7/22
11:15
256
104
112
108
470
476
473
533
537
598
S44
NA
244
426
494
665
7 " '
7 "9
742
745
747
7
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON iS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BASELINE OPERATION STUDY
BOARD AND COMPUTER DATA
c
c
c
c
c
c
c
c
c
c
c
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
C
C
C
C
C
C
B
B
B
TEST NO.
DATE
TIME
LOAD
HILL DATA
MILL 2-1
MILL 2-2
MILL 2-3
MILL 2-4
MILL 2-5
COAL AIR TEMP. MILL 2-1
COAL AIR TEMP. MILL 2-2
COAL AIR TEMP. MILL 2-3
COAL AIR TEMP. MILL 2-4
COAL AIR TEMP. MILL 2-5
MILL 2-1 EXH. DISCHARGE
MILL 2-2 EXH. DISCHARGE
MILL 2-3 EXH. DISCHARGE
MILL 2-4 EXH. DISCHARGE
MILL 2-5 EXH. DISCHARGE
MILL 2-1 SUCTION
MILL 2-2 SUCTION
MILL 2-3 SUCTION
MILL 2-4 SUCTION
MILL 2-5 SUCTION
MILL 2-1 COAL FLOW
MILL 2-2 COAL FLOW
MILL 2-3 COAL FLOW
MILL 2-4 COAL FLOW
MILL 2-5 COAL FLOW
MILL 2-1 FEEDER SPEED (l)
MILL 2-2 FEEDER SPEED
MILL 2-3 FEEDER SPEED
MILL 2-4 FEEDER SPEED
MILL 2-5 FEEDER SPEED
BURNER TILT
POSITION LF
POSITION LR
POSITION RF
POSITION RR
MISCELLANEOUS
DRUM LEVEL, IN. t NORM. H_0 LEVEL
FD FAN 2-1 *
FD FAN 2-2
ID FAN 2-1
ID FAN 2-2
FLUE GAS SO IN STACK
FLUE GAS COMBUSTIBLES L
FLUE GAS COMBUSTIBLES R
FLUE GAS 0 L
FLUE GAS
-------
UTAH POWER AND LIGHT COMPANY
HgMTiNGTON CANYON 12
C-E POWER SYSTEMS
FIELD TESTING *NO
PEBTOBMANCE RESULTS
TEST NO.
BASELINE OPERATION STUDY
BOARD AND COMPUTER DATA
10 11 IS 13
14
15
16
18
J = COMPUTER DATA; B * BOARD D»TA
(I) FEEDER SPEED IN £ OF CONTROL SIGNAL.
19
DATE
TIME
C LOAD
MILL DATA
C MILL 2-1
C MILL 2-2
C MILL 2-3
C MILL 2-4
C MILL 2-5
C COAL AIR TEMP. MILL 2-1
C COAL AIR TEMP. MILL 2-2
C COAL AIR TEMP. MILL 2-3
C COAL AIR TEMP. MILL 2-4
C COAL AIR TEMP. MILL 2-5
B MILL 2-1 EXH. DISCHARGE
B MILL 2-2 EXH. DISCHARGE
B MILL 2-3 EXH. DISCHARGE
B MILL 2-4 EXH. DISCHARGE
B MILL 2-5 EXH. DISCHARGE
B MILL 2-1 SUCTION
B MILL 2-2 SUCTION
B MILL 2-3 SUCTION
B MILL 2-4 SUCTION
B MILL 2-5 SUCTION
3 MILL 2-1 COAL FLOW
B MILL 2-2 COAL FLOW
B MILL 2-3 COAL FLOW
3 MILL 2-4 COAL FLOW
5 MILL 2-5 COAL FLOW
B MILL 2-1 FEEDER SPEED (1)
3 MILL 2-2 FEEDER SPEED
6 MILL 2-3 FEEDER SPEED
3 MILL 2-4 FEEDER SPEED
B MILL 2-5 FEEDER SPEED
BURNER TILT
B POSITION LF
B POSITION LR
B POSITION RF
B POSITION RR
MISCELLANEOUS
3 DRUM LEVEL, IN. - NORM. HpO LEVEL
C FD FAN 2-1
C FD FAN 2-2
C ID FAN 2-1
C ID FAN 2-2
C FLUE GAS S00 IN STACK
C FLUE GAS COMBUSTIBLES L
C FLUE GAS COMBUSTIBLES R
C FLUE GAS 0 L
C FLUE GAS Ot R
C FLUE GAS Or Ava.
3 AMBIENT TE&P.
8 AMBIENT REL. HUMIDITY
B BAROMETRIC PRESSURE
1975
MW
AMPS
AMPS
AMPS
AMPS
AMPS
°F
"F
•F
"F
"F
"HO
"HTO
"hPO
"H?0
"H?0
"hTO
"H?0
"kTO
"}fQ
"hfo
10\B/fe
10^LB/HR
lOiB/tfi
10 LB/HR
103LB/H?
*
f
%
%
- DEGREES
AMPS
AMPS
AMPS
AMPS
PPM
%
t
i
%
°F
"Ho
5/1
17:50
428
91
89
91
91
91
149
147
147
147
150
8.5
7.6
7.8
7.9
8.0
-1.6
-1.7
-1.6
-1.8
-1.6
64
65
63
64
65
74
78
78
78
79
NA
NA
NA
NA
0
252
230
424
417
NA
0
0
6.32
4.73
5.53
50
50
23.77
7/17
11:15
256
79
80
81
82
0
146
146
148
145
86
5.9
6.4
7.8
6.5
0
-2.2
-2.3
-2.2
-2.5
0
44
44
46
45
0
50
54
57
53
0
6
9
8
7
-1
172
171
307
306
NA
0
0
3.14
3.51
3.33
70
67
23.88
7/18
10:00
259
81
76
84
80
0
147
147
149
146
87
5.7
9.5
10.1
7
0
-2.1
-2.0
-1.7
-2.1
0
44
44
50
53
0
52
53
61
64
0
3
5
5
3
-1
189
184
328
326
NA
0
0
5.74
6.73
6.24
78
33
23.92
5/9
15:30
433
91
96
90
88
89
149
148
148
147
149
8.3
8.0
7.0
7.1
7.6
-1.9
-1.6
-2.0
-2.0
-2.0
66
62
61
62
63
75
75
74
75
75
3
5
5
3
0
216
205
374
372
501
0
0
3.80
1.8B
2.84
63
43
23.91
5/9
10:15
433
91
95
89
89
90
149
148
148
147
150
8.1
8.0
7.2
7.4
7.3
-1.8
-1.6
-1.9
-2.0
-2.0
66
62
62
62
62
76
75
74
75
74
8
10
10
8
0
224
210
385
387
255
0
0
4.88
3.17
4.03
61
44
23.91
5/3
18:15
433
92
96
89
89
90
149
147
147
147
150
8.2
8.3
7.4
7.2
7.6
-1.8
-1.5
-1.9
-1.9
-1.9
65
62
61
62
63
76
75
74
75
75
2
3
4
2
0
248
227
423
417
328
0
7.36
4.4?
5.89
60
42
23.0
10/9
X':00
361
NA
NA
',!A
riA
NA
149
148
147
78
149
7.4
6.5
6.9
0
7.0
-1.9
-1.8
-1 .7
0
-1.9
64
70
68
0
70
74
82
80
0
83
0
1
0
0
0
?">!
?17
35 E
356
NA
. 10
2.55
-2
66
23.98
7/22
11:15
258
90
0
78
80
82
147
86
148
146
149
5.8
0
7.3
6.5
6.9
-2.2
0
-2.2
-2.4
-2.3
47
0
43
49
50
54
0
53
59
60
11
12
12
12
-1
171
170
307
307
;.i
0
0
2.77
3.71
82
41
23.95
7/21
16:30
260
fO
a
81
81
83
147
85
149
146
149
5.6
0
7.4
6.9
6.8
-2.3
0
-2.2
-2.4
-2.3
46
~
48
49
50
53
0
58
59
60
13
14
16
14
-1
174
172
?13
312
::*
0
0
3!96
3.57
79
36
23.95
7/21
14:00
258
80
0
81
82
83
147
86
148
146
148
5.9
0
7.5
6.8
7.0
-2.2
0
-2.1
-2.3
-2.2
44
0
48
50
52
52
,71
59
60
62
12
14
14
14
-1
166
182
324
324
•;A
0
0
5.21
6.10
5.66
80
41
23.96
271
SHEET B29
-------
UTAH POWER AND LIGHT COMPANY
HUNTiNOTON CANYON |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
c
c
B
C
C
C
C
C
C
c
c
B
C
C
C
C
C
c
c
c
c
B
B
B
C
C
c
B
B
B
B
C
C
B
B
B
B
B
B
DATE
TIME
LOAD
FLOWS
FEEDWATER
MAIN STEAM
SUPERHEAT SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY
EXT. STH. TO STM. AH 2-1
EXT. STM. 'TO STM. AH 2-2
Aux. STM. TO STM. AH 2-1
Aux. STH. TO STM. AH 2-2
Aux. STM. TO SJAE
AIR FLOW TO BOILER
PRESSURES
STEAM AND WATER
FEEDWATER TO ECONOMIZER
BOILER DRUM
TURBINE THROTTLE
TURBINE IST STAGE
RH INLET, LEFT
RH INLET, RIGHT
RH INLET, AVERAGE
RH OUTLET
HP HTH. 2-7 STM. IN
AIR AND GAS
FD FAN DISCHARGE R
FD FAN DISCHARGE L
FD FAN DISCHARGE Avc.
AH 2-1 AIR DIFF. PRESS. R
AH 2-2 AIR Dirr. PRESS. L
AH AIR DIFF. PRESS. Avo.
WINDBOX PRESS. R
WINDBOX PRESS. L
WINDBOX PRESS. Avc.
FURNACE DRAFT
SH DRAFT DIFF.
ECON. DRAFT DIFF.
AH 2-1 GAS OUT PRESS. R
AH 2-2 GAS OUT PRESS. L
AH GAS OUT PRESS. AVG.
ID FAN 2-1 INLET PRESS. R
ID FAN 2-2 INLET PRESS. L
ID FAN INLET PRESS. AVG.
BOARD t COMPUTER DATA
1 2
1975
MW
PSIG
"H20
9/18
17:00
430
2945
3050
0
0
0
58.8
58.8
0
0
3.0
3200
2808
2713
2434
1820
571
575
573
535
358
9.5
9.5
9.5
3.4
3.9
3.7
4.0
4.0
4.0
-0.6
1.91
2.37
-12.7
-11.3
-12.2
-15.4
-12.6
-14,0
9/18
17:25
426
2889
3030
0
0
0
58.8
58.8
0
0
3.0
3210
2814
2708
2411
1814
568
573
571
532
361
9.6
9.6
9.6
3.4
3.9
3.7
3.9
3.9
3.9
-0.6
1.93
2.37
-12.6
-11.5
-12.1
-15.6
-12.6
-14.1
9/20
13:15
431
2871
2975
0
0
21.3
58.8
58.8
0
0
3.0
3260
2798
2703
2417
1816
572
576
574
532
360
8.6
8.5
8.6
3.5
4.0
3.7
3.3
3.3
3.3
-1.1
1.93
2.50
-13.7
-12.5
-13.1
-16.8
-13.1
-15.0
12/13
14:00
356
2291
2350
0
0
0
31.0
36.2
0
0
2.0
2510
2717
2625
2420
1444
462
465
464
422
382
7.1
7.0
7.0
2.5
2.9
2.7
3.5
3.5
3.5
-1
1.2
2.21
-10.1
-9.1
-9.6
-12.6
-10.1
-11.4
io/n
16:30
351
2261
2350
0
0
0
14.4
14.2
0
0
2.9
2410
2691
2624
2422
NA
NA
NA
NA
420
383
6.3
6.3
6.3
2.3
2.6
2.4
2.8
2.8
2.S
-1
1.05
1.65
-10.2
-9.4
-9.8
-11.8
-10.1
-11.0
10/12
15:00
360
2336
2400
0
0
0
25.3
25.3
0
0
3.0
2650
2694
2615
2406
NA
NA
NA
NA
436
374
8.4
8.4
8.4
2.5
3.0
2.8
4.4
4.4
4.4
-1
1.33
1.83
-10.5
-9.8
-10.2
-12.2
-10.5
-11.4
10/12
10:00
257
1648
1600
0
0
0
25.4
25.5
0
0
3.0
1750
2592
2536
2416
NA
NA
NA
NA
294
406
2.8
2.8
2.8
1.4
1.6
1.5
0.6
0.3
0.5
-1
0.45
0.92
-6.6
-6.1
-6.4
-7.6
-6.6
-7.1
10/5
21:30
271
1603
1650
29.0
25.6
0
58.8
58.8
0
0
3.0
1850
2591
2535
2420
1009
339
340
340
306
409
4.0
4.0
4.0
1.4
1.6
1.5
1.5
1.5
1.5
-1
0.54
1.05
-6.9
-6.9
-6.9
-7.8
-7.1
-7.5
C = COMPUTER DATA; B » BOARD DATA
272
SHEET B30
-------
UTAH POWER AND LIGHT COMPANY
HUNTtNGTON CANYON #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STODY
TEST NO.
c
c
B
C
c
c
c
c
c
c
c
B
C
c
c
c
c
c
c
c
c
B
B
B
C
C
C
B
B
B
B
C
C
B
B
B
B
B
B
DATE
TIME
LOAD
FLOWS
TEEDVATER
MAIN STEAM
SUPERHEAT SPRAY L
SUPERHEAT SPRAY R
REHEAT SPRAY
EXT. STM. TO STH. AH 2-1
EXT. STM. -TO STH. AH 2-2
Aux. STM. TO STM. AH 2-1
Aux. STM. TO STH. AH 2-2
Aux. STM. TO SJAE
AIR FLOW TO BOILER
PRESSURES
STEAM AND WATER
FEEDVATER TO ECONOMIZER
BOILER DRUM
TURBINE THROTTLE
TURBINE !ST STAGE
RH INLET, LEFT
RH INLET, .RIGHT
RH INLET, AVERAGE
RH OUTLET
HP HTH. 2-7 STH. In
AIR AND GAS.
FD FAN DISCHARGE R
FD FAN DISCHARGE L
FD FAN DISCHARGE A vs.
AH 2-1 AIR DIFF. PRESS. R
AH 2-2 AIR DIFF. PRESS. L
AH AIR DIFF. PRESS. AVG.
WINDBOX PRESS. R
WINOBOX PRESS. L
WINDBOX PRESS. Avc.
FURNACE DRAFT
SH DRAFT DIFF.
ECON. DRAFT DIFF.
AH 2-1 GAS OUT PRESS. R
AH 2-2 GAS OUT PRESS. L
AH GAS OUT PRESS. Avc.
ID FAN 2-1 INLET PRESS. R
ID FAN 2-2 INLET PRESS. L
ID FAN INLET PRESS. Ava.
BOARD t COMPUTER DATA
9 10 11
12
13
15
1975 9/19
14:35
MW 427
2938
3050
0
0
0
58.8
58.8
0
0
3.0
3400
PSIG
2826
2718
2420
1824
571
576
574
533
359
"H-O
Z 9.9
9.9
9.9
3.6
4.2
3.9
4.0
4.0
4.0
-O.B
2.11
2.55
-13.9
-12.6
-13.3
-16.8
-13.8
-15.3
9/18
09:45
429
2897
3000
0
0
26.2
58.8
58.8
0
0
3.0
3480
2813
2721
2414
1829
575
579
577
535
359
10.4
10.4
10.4
3.8
4.3
4.0
3.9
3.9
3.9
-O.B
2.06
2.72
-14.5
-13.1
-13.8
-17.8
-14.3
-16.0
9/18
14:10
430
2882
3000
0
0
30.5
58.8
58.8
0
0
3.0
3430
2805
2722
2417
1823
574
579
577
535
360
10.4
10.4
10.4
3.8
4.3
4.1
4.0
4.0
4.0
-0.4
2.11
2.72
-13.95
-12.0
-13.3
-17.2
-13.7
-15.4
10/11
14:45
351
2273
2360
0
0
0
58.8
58.8
0
0
2.9
2610
2668
2622
2397
NA
NA
NA
NA
420
383
8.2
8.2
8.2
2.6
3.0
2.8
4.0
4.0
4.0
-1
1.25
1.B4
-11.1
-10.4
-10.8
-12.9
-11.2
-12.1
12/13
1 2 : 00
356
2321
2367
0
0
0
44.6
44.2
0
0
2.0
2730
2739
2612
2434
1438
460
463
462
426
381
7.8
7.5
7.6
2.94
3.38
3.16
4.2
4.2
4.2
-1.1
1.48
2.48
-11.6
-10.5
-11.0
-14.3
-11.5
-12.9
12/13
10:15
357
2302
2350
0
0
2.7
43.9
43.8
0
0
2.0
2360
2738
2625
2425
1441
460
463
462
425
381
8.0
8.0
8.0
3.02
3.51
3.26
4.2
4.2
4.2
-1.0
1.38
2.55
-12.1
-11.3
-11.7
-14.9
-12.2
-13.6
7/23
10:40
256
1557
1500
4.7
0
0
6.3
6.2
0
0
3.0
1700
2536
2489
2392
927
307
308
308
274
412
3.1
3.1
3.1
.3
.4
.4
.2
.2
.2
-0.5
0.40
0.77
-5.6
-5.1
-5.4
-6.7
-5.4
-6.1
7/24
09: =,5
259
1584
1500
19.2
9.1
0
9.3
9.3
0
0
3.0
1700
2544
2495
2397
939
312
314
313
280
406
3.1
3.0
3.1
.2
.4
.3
.1
.1
.1
-0.5
0.48
0.61
-5.7
-5.1
-5.4
-7.1
-5.6
-5.9
C = COMPUTER DATAJ B - BOARD DATA
273
SHEET B31
-------
UTAH POWER AND LIOHT COMPANY
HUNTINGTON CANYON IS
C-E POWER SYSTEMS
FIELD TESTINO »NO
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
c
B
B
B
B
DATE
TIME
LOAD
TEMPERATURES
AIR AND GAS
AH 2-1 AIR IN
AH 2-2 AIR IN
Avo. AIR IN
AH 2-1 AIR OUT
AH 2-2 AIR OUT
Avc. AIR OUT
AH 2-1 GAS IN
AH 2-2 GAS IN
Avo. GAS IN
AH 2-1 GAS OUT
AH 2-2 GAS OUT (1 )
Avo. GAS OUT
STEAM AND WATER
FW IN TEMP. TO ECON.
ECON. OUT Avc.
BOILER DOWNCOHER
SH DESH INLET L
SH DESH INLET R
SH DESH INLET Avo
SH DESH OUTLET L
SH DESH OUTLET R
SH DESH OUTLET Avo
SH OUTLET
THROTTLE STEAM
RH TURBINE L
RH TURBINE R
RH TURBINE Ave
RH BOILER L
RH BOILER R
RH BOILER Avo
RH OUTLET
HP HTR 2-7 STM. IN
HP HTR 2-7 FW IN
HP HTR. 2-7 DRAIN
Aux. STEAM TEMP.
FAN DAMPER POSITION
FO FANS
ID FANS
SPRAY VALVE POSITION
SH SPRAY
RH SPRAY
BOARD & COMPUTER DATA
1975
MM
*F
% OPEN
% OPEN
9/18
7:00
430
106
99
103
520
540
530
715
716
716
266
278
272
484
571
678
744
756
750
751
759
755
967
955
599
599
599
595
595
595
993
601
416
424
514
72
62
0
0
9/18
17:25
426
106
100
103
515
537
526
705
706
706
264
277
271
484
570
678
744
754
748
749
752
751
976
964
607
607
607
604
603
604
1008
606
415
423
508
71
62
0
1
9/20
13:15
431
105
98
102
516
542
529
707
718
713
265
278
272
485
571
677
750
753
752
757
755
756
995
981
621
622
622
596
585
591
1014
623
415
424
518
70
65
0
24
12/13
14:00
356
105
104
104
498
502
500
657
626
642
255
258
256
463
534
673
733
733
733
737
737
737
1005
998
598
601
600
NA
NA
NA
1001
599
398
403
571
60
53
0
0
10/11
16:30
351
109
108
108
511
515
513
664
664
664
264
267
266
462
542
749
753
751
750
758
754
994
985
NA
NA
NA
575
578
577
994
589
398
404
545
60
52
0
9
10/12
15:00
360
112
113
112
499
507
503
660
660
660
258
261
260
466
543
672
744
745
745
744
749
747
1006
996
NA
NA
NA
592
593
593
1017
602
400
407
546
64
55
0
8
10/12
10:00
257
117
118
118
472
474
473
598
597
598
249
252
251
430
501
667
738
746
742
744
750
747
1006
994
NA
NA
NA
543
554
550
1000
552
372
376
552
46
41
0
0
10/5
21:30
271
114
117
116
481
482
482
614
616
615
254
253
254
436
508
669
751
759
755
729
736
732
1006
999
554
566
560
551
561
556
1018
561
372
380
533
48
43
30
0
C <= COMPUTER DATA; B
(1) TC READING OPEN
BOARD DATA
274
SHEET B32
-------
UTAH POWER AND LIGHT COMPANY
HUNTINOTON CANYON 12
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
BOARD I COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
TEMPERATURES
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
C
AIR AND GAS
AH 2-1 AIR IN
AH 2-2 AIR IN
AVG. AIR IN
AH 2-1 AIR OUT
AH 2-2 AIR OUT
AVG. AIR OUT
AH 2-1 GAS IN
AH 2-2 GAS IN
Ava. GAS IN
AH 2-1 GAS OUT
AH 2-2 GAS OUT (1 )
Ava. GAS OUT
STEAM AND WATER
FW IN TEMP. TO ECON.
ECON. OUT Avo.
BOILER OOWNCOMER
SH DESH INLET L
SH DESH INLET R
SH DESH INLET Avo
SH DESH OUTLET L
SH DESH OUTLET R
SH DESH OUTLET AVG
SH OUTLET
THROTTLE STEAM
RH TURBINE L
RH TURBINE R
RH TURBINE AVG
RH BOILER L
RH BOILER R
RH BOILER AVG
RH OUTLET
HP HTR 2-7 STM. IN
HP HTR 2-7 FW IN
HP HTR 2-7 DRAIN
Aux. STEAM TEMP.
1975
MW
°F
FAN DAMPER POSITION
B FD FANS
B 10 FANS
SPRAY VALVE POSITION
B SH SPRAY
B RH SPRAY
% OPEN
t OPEN
C - COMPUTER DATA; B
(1) TC READING OPEN
BOARD DATA
11
12
13
14
15
16
»/19
1:35
427
105
105
105
520
542
531
719
719
719
268
278
273
484
574
678
744
754
749
751
759
755
964
955
599
600
600
596
596
596
995
600
415
423
512
74
63
0
0
9/18
09:45
429
103
99
101
516
537
527
710
707
709
267
276
272
486
575
679
745
751
761
753
760
757
992
980
622
622
622
588
575
582
998
619
415
423
521
75
65
0
3D
9/18
14:10
430
104
98
101
520
542
531
717
717
717
267
279
273
485
576
678
755
765
760
761
765
763
990
981
623
623
623
572
556
569
1007
621
415
424
525
74
65
0
34
10/11
14:45
351
110
110
110
504
513
509
661
662
662
260
265
263
462
544
671
752
754
753
753
759
756
995
988
NA
NA
NA
584
588
586
1005
591
398
404
554
66
57
0
0
12/13
12:00
356
100
103
102
498
504
501
671
671
671
254
260
257
463
539
674
743
740
742
746
744
745
1000
995
596
601
598
573
582
578
1000
591
397
403
571
64
56
0
0
i?/n
10:15
357
103
104
104
499
505
5O2
673
639
656
257
259
258
463
540
674
743
740
742
744
743
744
1008
998
596
602
599
590
581
586
1005
598
398
403
565
65
58
O
3
"/ - ''
1^:40
256
102
108
105
474
477
476
602
594
598
248
NA
248
425
494
665
745
745
745
742
747
745
1006
998
552
560
549
549
556
553
1000
555
367
370
573
46
40
5
0
7/24
09:55
259
104
104
104
472
478
475
599
589
594
246
NA
246
428
496
665
750
751
751
735
741
738
1002
995
549
558
554
547
555
551
1000
554
368
371
569
46
40
16
0
275
SHEET B33
-------
UT»H POWER AND LIGHT COMPANY
HUNTINGTON CANYON f2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
BOARD I COMPUTER DATA
c
c
c
c
c
c
c
c
c
c
c
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
C
C
C
C
B
B
C
C
C
C
C
B
B
B
DATE
TIME
LOAD
MILL DATA
MILL 2-1
MILL 2-2
MILL 2-3
MILL 2-4
MILL 2-5
COAL AIR TEMP. MILL 2-1
COAL AIR TEMP. MILL 2-2
COAL AIR TEMP. MILL 2-3
COAL AIR TEMP. MILL 2-4
COAL AIR TEMP. MILL 2-5
MILL 2-1 EXH. DISCHARGE
MILL 2-2 EXH. DISCHARGE
MILL 2-3 EXH. DISCHARGE
MILL 2-4 EXH. DISCHARGE
MILL 2-5 EXH. DISCHARGE
MILL 2-1 SUCTION
MILL 2-2 SUCTION
MILL 2-3 SUCTION
MILL 2-4 SUCTION
MILL 2-5 SUCTION
MILL 2-1 COAL FLOW
MILL 2-2 COAL FLOW
MILL 2-3 COAL FLOW
MILL 2-4 COAL FLOW
MILL 2-5 COAL FLOW
MILL 2-1 FEEDER SPEED (l)
MILL 2-2 FEEDER SPEED
MILL 2-3 FEEDER SPEED
MILL 2-4 FEEDER SPEED
MILL 2-5 FEEDER SPEED
BURNER TILT
POSITION LF
POSITION LR
POSITION RF
POSITION RR
Ml SCELLANEOUS
DRUM LEVEL, IN. - NORM. H.O LEVEL
FD FAN 2-1 d
FD FAN 2-2
ID FAN 2-1
ID FAN 2-2
FLUE GAS SO. IN STACK
FLUE GAS NCr IN STACK
FLUE GAS COMBUSTIBLES L
FLUE GAS COMBUSTIBLES R
FLUE GAS (L L
FLUE GAS 0? R
FLUE GAS 0? Ava.
AMBIENT TEMP.
AMBIENT REL. HUMIDITY
BAROMETRIC PRESSURE
1975
MM
AMPS
AMPS
AMPS
AMPS
AMPS
•F
•F
"F
°F
°F
"H-0
"H?0
"HTO
"tfo
"HfO
"HIO
"H?0
"H£°
"«o
o "fa
10fLB/HR
IO£LB/HR
10ILB/HJ
lOILB/HR
10T.B/H?
%
*
%
%
%
- DEGREES
AMPS
AMPS
AMPS
AMPS
PPM
PPM
%
%
%
%
•F
%
"Ho
9/18
17:00
430
NA
NA
NA
NA
NA
154
148
147
148
149
5.5
7.4
8.4
10.1
8.4
-3.2
-1.6
-1.5
-1.4
-1.6
0
80
79
79
80
26
95
94
94
94
+6
+8
+6
46
-1
209
230
380
388
NA
NA
0.06
0
3.33
2.49
2.91
72
24
23.76
9/18
17:25
426
NA
NA
NA
NA
NA
148
154
146
148
148
8.2
7.6
5.5
10.5
8.5
-1.5
-1.7
-2.7
-1.4
-1.6
85
81
0
79
80
95
96
NA
95
94
-3
-1
-4
-3
-1
209
231
380
389
NA
NA
0.05
0
2.85
3.41
3.3
65
28
23.61
9/20
13:15
431
NA
NA
NA
NA
NA
148
148
147
148
147
7.1
7.1
8.0
10.0
NA
-1.5
-1.4
-1.4
-1.4
NA
86
84
82
82
0
96
96
94
95
NA
-8
-4
-7
-6
0.0
208
228
385
393
NA
NA
0.06
0
2.16
4.00
3.08
71
21
24.20
12/13
14:00
356
60.3
93.0
87.4
88.0
87.6
157
149
149
148
151
4.5
7.1
7.0
7.5
7.4
-2.9
-1.8
-1.7
-1.8
-1.9
0
68
62
61
62
24
82
80
80
80
+17
+17
+13
+18
-0.5
342
349
342
348
NA
NA
0.17
0
2.27
2.70
2.48
31
82
23.30
10/11
16:30
351
NA
NA
NA
NA
NA
149
148
88
147
150
7.9
NA
7.3
7.5
7.5
-1.8
NA
-1.8
-2.0
-1.7
71
0
68
66
67
82
NA
80
80
80
-10
-7
-9
-9
-1
NA
NA
345
348
NA
400
0.07
0
3.11
2.58
2.85
62
20
23.65
10/12
15:00
360
NA
NA
NA
NA
NA
148
148
148
97
150
7.5
6.5
7.4
NA
6.8
-1.9
-1.8
-1.6
NA
-1.6
72
70
69
0
70
S3
83
82
NA
84
-10
-6
-11
-9
-1
NA
NA
350
352
NA
NA
0.09
0
2.85
2.89
2.87
54
45
23.58
10/12
10:00
257
NA
NA
NA
NA
NA
75
146
146
145
149
NA
6.6
6.2
6.5
6.2
NA
-2.4
-2.4
-2.4
-2.3
0
51
50
50
51
NA
62
60
60
60
+6
+6
+5
+6
-1
NA
NA
312
312
NA
400
0.1
0
3.97
3.02
3.50
53
47
23.66
10/5
21:30
271
NA
NA
NA
NA
NA
148
112
147
145
149
7.0
6.5
NA
6.5
6.5
-2.3
-2.3
NA
-2.4
-2.4
55
50
0
48
50
64
60
NA
58
60
-8
-5
-8
-8
0
NA
NA
171
181
28
380
0.08
0
3.08
3.85
3.47
56
37
23.96
C = COMPUTER DATA; B = BOARD DATA
(1) FEEDER SPEED IN % or CONTROL SIGNAL
276
SHEET B34
-------
UTAH POWER AND LIGHT COMPANY
HUNTINOTOH CANYON IS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
BIASED FIRING OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
MILL DATA
C
C
C
C
C
C
C
C
C
C
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
B
MILL
MILL
MILL
MILL
MILL
COAL
COAL
COAL
COAL
COAL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
MILL
2-1
2-2
2-3
2-4
2-5
AIR
AIR
AIR
AIR
AIR
2-1
2-2
2-3
2-4
2-5
2-1
2-2
2-3
2-4
2-5
2-1
2-2
2-3
2-4
2-5
2-1
2-2
2-3
2-4
2-5
TEMP. MILL 2-1
TEMP. MILL 2-2
TEMP. MILL 2-3
TEMP. MILL 2-4
TEMP. MILL 2-5
EXH. DISCHARGE
EXH. DISCHARGE
EXH. DISCHARGE
EXN. DISCHARGE
EXH. DISCHARGE
SUCTION
SUCTION
SUCTION
SUCTION
SUCTION
COAL FLOW
COAL FLOW
COAL FLOW
COAL FLOW
COAL FLOW
FEEDER SPEED (1)
FEEDER SPEED
FEEDER SPEED
FEEDER SPEED
FEEDER SPEED
BOARD t COMPUTER DATA
9 10 11
3 NORM. H20 LEVEL
BURNER TILT
B POSITION LF
B POSITION LR
8 POSITION RF
B POSITION RR
MISCELLANEOUS
B DRUM LEVEL, IN.
C FD FAN 2-1
C FD FAN 2-2
C ID FAN 2.1
C ID FAN 2-2
B FLUE GAS SO
B FLUE SAS NO ...
C FLUE GAS COMBUSTIBLES L
C FLUE GAS COMBUSTIBLES R
C FLUE GAS 0 L
C FLUE GAS 0? R
C FLUE GAS CC Avo.
B AMBIENT TEMP.
B AMBIENT REL. HUMIDITY
B BAROMETRIC PRESSURE
C = COMPUTER DATA; B = BOARD DATA
(1) FEEDER SPEED IN % or CONTROL SIGNAL
IN STACK
IN STACK
12
13
14
15
16
1975
MM
AMPS
AMPS
AMPS
AMPS
AMPS
•F
°F
"F
°F
•F
"HO
"H?0
"HrO
"HfO
nnQ
"H?0
"HfO
"H?O
"VrO
3 "*&
102.B/HR
10i.B/HR
lOiB/HR
lOrtB/HR
10T.B/HR
a
f
£
£
%
'• DEGREES
AMPS
AMPS
AMPS
AMPS
PPM
PPM
nf
%
J
°F
"Ho
9/19
14:35
427
NA
NA
NA
NA
NA
117
148
146
147
148
5.5
7.5
8.2
10.0
8.5
-3.1
-1.6
-1.4
-1.4
-1.5
0
84
83
82
81
26
100
99
96
90
+16
+17
+15
+18
-1
NA
NA
212
236
W
NA
0.08
0
4.09
3.76
3.92
79
27
23.80
9/18
09:45
429
NA
NA
NA
NA
NA
148
148
147
147
147
8.1
5.5
8.4
10.3
B.6
-1.5
-3.0
-1.4
-1.4
-1.6
79
0
79
78
79
90
NA
94
94
94
+9
+10
+9
+9
-1.1
NA
NA
216
241
NA
NA
0.11
0
4.74
3.83
4.29
67
38
23.83
9/18
14:10
430
NA
NA
NA
NA
NA
149
148
147
147
149
8.5
7.5
6.2
8.0
B.5
-1.6
-1.7
-1.5
-3.0
-1.6
84
80
79
0
80
94
94
94
NA
94
+2
+4
+2
+2
-1
NA
NA
215
239
NA
NA
0.07
0
4.09
4.01
4.05
74
27
23.83
10/11
14:45
351
NA
NA
NA
NA
NA
156
149
149
147
150
NA
5.8
7.3
7.4
7.3
NA
-3.2
-1.5
-1.7
-1.5
0
76
76
74
75
NA
91
90
91
89
+5
+6
+5
+6
-1
NA
NA
348
352
NA
396
0.05
0
3.77
3,87
3.82
68
20
23.66
12/13
12:00
356
94.8
91.4
64.7
86.7
85.5
150
160
148
147
150
8.0
7.5
5.0
7.2
7.3
-1.7
-1.8
-2.8
-1.8
-1.9
75
64
0
58
59
79
79
NA
7B
78
+7
+10
+7
+9
-0.5
358
364
358
364
NA
NA
0.16
0
3.52
4.6
4.06
31
81
23.33
12/13
10:15
357
95.6
91.8
86.5
86.8
61.9
150
149
148
148
147
6.1
7.5
7.1
7.5
4.1
-1.6
-1.8
-1.7
-1.8
-2.9
75
65
58
59
0
78
78
76
76
NA
-8
-6
-9
-8
-0.5
358
366
357
366
NA
NA
0.16
0
3.06
5.16
4.11
30
85
23.38
7/23
10: 4C
256
79.6
77.6
79.8
85.3
148
NA
148
146
148
5.5
NA
7.2
6.5
7.0
-2.3
NA
-2.3
-2.5
-2.3
43
0
40
47
56
49
NA
49
58
68
+11
+12
+13
+13
-1
171
171
311
310
NA
NA
0.1
0
3.54
4.10
3.85
87
28
24.00
7/24
09:55
259
81.0
76.4
60.0
NA
B4.5
147
NA
148
88
149
5.5
6.1
7.6
NA
7.1
-2.2
-2.6
-2.2
NA
-2.3
48
35
45
0
55
56
42
55
NA
67
+10
+12
+13
+11
-0.5
171
170
312
310
NA
NA
0.09
0
3.28
3.90
3.59
79
36
24.05
277
SHEET B35
-------
UTAH POWER AND LIGHT COMPANY
HUNTinoTON CANYON IS
C-E POWEB SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATEB
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM & "WATER
C FEEOWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1ST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
AIR i GAS
1975
MW
103LB/HR
PS IS
"H20
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE Avs.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DlFF. PRESS. L
C AH AIR DIFF. PRESS. Avc.
B WINDBOX PRESS. R
BWINDBOX PRESS. L
B WINDBOX PRESS. AVG.
8 FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAH 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
9/17
10:20
428
2676
3000
0
0
9.1
12.2
12.2
0
0
3.0
3460
2806
2716
2409
1826
572
575
574
531
360
10.3
10.3
10.3
3.80
4.34
4.07
4.0
4.0
4.0
-0.68
1.95
2.66
-14.5
-12.8
-13.6
-17.3
-14.0
-15.6
9/26
09:40
430
2893
3040
0
0
7.8
58.9
58.9
0
0
3.0
3380
2815
2720
2422
1828
573
578
575
535
359
9.5
9.5
9.5
3.73
4.21
3.97
3.5
3.5
3.5
-1.0
2.19
2.53
-15.0
-13.0
-14.0
-18.5
-14.0
-16.2
9/26
11:30
430
2900
3038
0
0
7.2
58.8
58.8
0
0
3.0
3380
2820
2721
2420
1828
573
578
575
534
360
9.5
9.5
9.5
3.70
4.19
3.94
3.4
3.4
3.4
-1.1
2.01
2.69
-15.0
-12.9
-14.0
-19.0
-14.0
-16.5
9/86
15:30
430
2895
3025
0
0
28.2
58.8
58.8
0
0
3.0
3380
2816
2720
2420
1828
575
579
577
536
360
10.0
10.0
10.0
3.70
4.21
3.96
3.3
3.3
3.3
-1.0
1.91
2.75
-15.0
-13.0
-14.0
-18.5
-14.0
-16.2
9/26
17:15
431
2901
3050
0
0
22.4
58.8
58.8
0
0
3.0
3380
2821
2725
2427
1833
577
581
579
538
359
10.0
10.0
10.0
3.70
4.22
3.96
3.3
3.3
3.3
-1.1
2.13
2.81
-15.0
-12.6
-13.9
-16.5
-14.0
-16.2
10/1
18:00
430
2893
3038
0
0
0
53.8
58.8
0
0
3.0
3060
2814
2717
2418
1826
572
575
574
532
360
9.5
9.5
9.5
3.25
3.65
3.45
4.5
4.5
4.5
-1.0
1.81
2.24
-12.5
-13.5
-13.0
-15.0
-15.0
-15.0
10/1
19:30
428
2910
3040
0
0
0
58.8
58.8
0
0
3.0
3130
2815
2716
2416
1825
571
575
573
533
359
9.S
9.2
9.2
3.28
3.70
3.49
3.7
3.7
3.7
-1.0
1.91
2.49
-12.8
-13.8
-13.3
-15.0
-15.1
-15.0
10/1
21:00
428
2903
3040
0
0
0
58.6
56.6
0
0
3.0
3150
2811
2715
2413
1824
571
575
573
532
362
8.8
8.8
8.8
3.30
3.72
3.51
3.2
3.2
3.2
-1.0
1.95
2.44
-12.9
-13.7
-13.3
-15.0
-15.1
-15.0
BOARD DATA
COMPUTER DATA
278
SHEET 836
-------
UTAH POWER AND LIGHT COMPANY
HUNTINOTON CANYON fs
C-E POWER SYSTEHS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST HO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STE"AM & "PATER
C FEEDWATER TO ECon.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1sT STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
All; A GAS
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE AVG.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. Avc.
B WINDBOX PRESS. R
B WINOBOX PRESS.
B WINOBOX PRESS.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
L
AVG.
10
11
12
13
14
15
16
1975
Mrf
10\B/HR
PSIG
"H20
9/27
13:30
426
2885
3033
0
0
0
58.8
58.8
0
0
3.0
3770
2810
2703
2423
1812
567
571
569
531
366
11.0
11.0
11.0
4.42
5.02
4.72
3.5
3.5
3.5
-1.0
2.54
3.16
-15.0
-15.0
-15.0
-21.5
-17. f
-19.5
9/27
12:00
429
2881
3050
0
0
0
58.9
58.9
0
0
3.1
3710
2318
2716
2417
1827
569
573
571
530
362
11.8
11.8
11.8
4.41
4.84
4.62
4.3
4.3
4.3
-1.0
2.26
3.08
-15.0
-15.0
-15.0
-19.1
-19.1
-19.1
9/27
14:00
429
2891
3050
0
0
0
58.8
58.8
0
0
3.0
3730
2818
2719
2420
1828
570
573
572
531
359
11.8
11.8
11.8
4.40
4. 64
4.62
4.5
4.5
4.5
-1.0
2.36
3.11
-15.0
-15.0
-15.0
-19.0
-19.0
-19.0
10/5
13:45
427
2909
3000
0
0
0
58.8
58.8
0
0
3.0
3130
2813
2719
2415
1829
573
577
575
533
360
9.3
9.3
9.3
3.37
3.81
3.59
3.5
3.5
3.5
-1.0
1.82
2.44
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/4
16:00
434
2B53
3000
0
0
'17.3
58.8
58.8
0
0
3.0
3250
2814
2718
2420
1829
576
579
578
536
359
9.8
9.8
9.8
3.56
3.98
3.77
3.8
3.8
3.8
-1.2
1.95
2.51
-14.3
-14.3
-14.3
-16.9
-15.4
-16.2
10/5
12:00
422
2889
3000
0
0
0
58.8
58.8
0
0
3.0
3140
2807
2705
2411
1806
565
569
567
528
362
9.2
9.2
9.2
3.33
3.73
3.53
3.4
3.4
3.4
-1.0
1.73
2.31
-13.5
-13.4
-13.4
-15.6
-14.5
-15.0
10/4
14:15
429
2882
3000
0
0
0
58.8
58.8
0
0
3.0
3200
2812
2713
2417
1623
572
575
574
533
361
9.1
9.1
9.1
3.42
3.90
3.66
3.5
3.5
3.5
-1.0
1.84
2.41
-13.6
-13.6
-13.6
-16.0
-14.8
-15.4
10/3
18:30
427
2904
3050
0
0
7.9
58.8
58.8
0
0
3.0
3190
2808
2713
2415
1824
573
577
575
534
360
9.5
9.5
9.5
3.44
3.90
3.67
3.5
3.5
3.5
-1.0
1.82
2.39
-13.5
-13.4
-13.4
-16.0
-14.5
-15.2
BOARD DATA
COMPUTER DATA
279
SHEET B37
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANTON 02
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEOWATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM tTJATER
C FEEDWATEH TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1ST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET Avo.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
AIR i GAS
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE Avs.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. Avc.
B WINDBOX PRESS. R
B WINDBOX PRESS. L
B WINDBOX PRESS. AVG.
B FURNACE DRAFT
C SH DRAFT OIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
B = BOARD DATA
C * COMPUTER DATA
1975
MW
10\B/HS
PSIG
17
18
19
20
21
22
S3
24
10/3
22:30
423
2926
3100
0
0
22.9
58.8
58.8
0
0
3.0
3180
2813
2715
2418
1826
574
578
576
535
357
9.0
8.9
9.0
3.35
3.79
3.57
3.1
3.1
3.1
-1.2
1.93
2.45
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/3
20:30
430
2885
3038
0
0
18.7
58.8
58.8
0
0
3.0
3240
2806
2711
2413
1824
574
579
576
535
350
9.4
9.4
9.4
3.44
3.88
3.66
3.5
3.5
3.5
-1.2
2.00
2.61
-13.8
-13.8
-13.8
-16.0
-15.0
-15.5
10/6
19:00
417
2900
3050
0
0
0
58.8
58.8
0
0
3.0
3100
2813
2715
2415
1824
572
576
574
524
359
8.8
8.8
8.8
3.23
3.64
3.44
3.3
3.3
3.3
-1.0
1.85
2.43
-13.3
-12.8
-13.0
-15.5
-14.0
-14.8
10/8
10:30
426
290B
3050
0
0
0
58.8
58.8
0
0
3.2
3110
2816
2720
2419
1829
571
575
573
532
363
8.5
8.5
8.5
3.30
3.72
3.51
3.0
3.0
3.0
-1.0
1.77
2.45
-13.8
-13.2
-13.5
-15.5
-14.0
-14.8
10/10
01:45
356
2333
2400
0
0
0
58.8
58.8
0
0
3.0
2460
2705
2628
2416
1442
464
468
460
428
380
4.8
4.6
4.7
2.21
2.58
2.40
1.0
1.0
1.0
-1.0
1.13
1.71
-10.6
-9.8
-10.2
-11.6
-10.6
-11.1
10/9
01:15
358
2307
2400
0
0
4.5
58.8
58.8
0
0
3.1
2640
2701
2631
2420
1438
465
469
467
429
384
6.8
6.6
6.7
2.50
2.87
2.68
S.5
2.5
2.5
-1.0
1.33
1.80
-10.0
-10.0
-10.0
-11.6
-10.5
-11.2
10/12
08:15
253
1665
1650
0
0
0
28.2
28.5
0
0
3.0
1800
2592
2537
2416
NA
NA
NA
NA
293
404
2.5
2.5
2.5
1.36
1.52
1.44
0
0
0
-1.0
0.53
0.98
-6.8
-6.0
-6.4
-7.5
-6.8
-7.2
10/5
18:45
266
1657
1650
0
0
0
58.8
58.8
0
0
3.0
1810
2593
2532
2414
1008
334
336
335
301
408
2.5
2.5
2.5
1.38
1.57
1.48
0
0
0
-1.0
0.60
0.88
-6.8
-6.6
-6.7
-8.0
-7.6
-7.8
280
SHEET B38
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON JS
C-E POWER SYSTEMS
FIELD TESTING AND
PERrORMANCt RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEOWATCR
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STH. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM t WATER
C FEEDWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1sT STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
GAS
L
AVG.
B FD FAN DISCHARGE R
B FD FAN DISCHARGE: L
B FD FAN DISCHARGE Avo.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINOBOX PRESS. R
B WINDBOX PRESS.
B WINDBOX PRESS.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH S-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. Avo.
B ID FAN 2-1 INLET PRESS, R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
10
11
12
13
15
16
1975
MM
103LB/HR
PSIG
"H20
9/27
13:30
428
2885
3033
0
0
0
58.8
58.8
0
0
3.0
3770
2810
2703
2423
1812
567
571
569
531
366
11.0
11.0
11.0
4.42
5.02
4.72
3.5
3.5
3.5
-1.0
2.54
3.16
-15.0
-15.0
-15.0
-21.5
-17.5
-19.5
9/27
12:00
429
2881
3050
0
0
0
58.9
58.9
0
0
3.1
3710
2818
2716
2417
1827
569
573
571
530
362
11.8
11.8
11.8
4.41
4.84
4.62
4.3
4.3
4.3
-1.0
2.26
3. OB
-15.0
-15.0
-15.0
-19.1
-19.1
-19.1
9/27
14:00
429
2891
3050
0
0
0
58.8
58.8
0
0
3.0
3730
2818
2719
2420
1828
570
573
572
531
359
11.8
11.8
11.8
4.40
4.84
4.62
4.5
4.5
4.5
-1.0
2.36
3.11
-15.0
-15.0
-15.0
-19.0
-19.0
-19.O
10/5
13:45
427
2909
3000
0
0
0
58.8
58.8
0
0
3.0
3130
2813
2719
2415
1829
573
577
575
533
360
9.3
9.3
9.3
3.37
3.81
3.59
3.5
3.5
3.5
-1.0
1.82
2.44
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/4
16:00
434
2853
3000
0
0
17.3
58.8
58.6
0
0
3.0
3250
2614
2718
2420
1B29
576
579
578
536
359
9.8
9.8
9.8
3.56
3.98
3.77
3.8
3.8
3.8
-1.2
1.95
2.51
-14.3
-14.3
-14.3
-16.9
-15.4
-16.2
10/5
12:00
422
2889
3000
0
0
0
58.8
58.8
0
0
3.0
3140
2607
2705
2411
1806
565
569
567
528
362
9.2
9.2
9.2
3.33
3.73
3.53
3.4
3.4
3.4
-1.0
1.73
2.31
-13.5
-13.4
-13.4
-15.6
-14.5
-15.0
10/4
14:15
429
2862
3000
0
0
0
58.8
58.8
0
0
3.0
3200
2812
2713
2417
1823
572
575
574
533
361
9.1
9.1
9.1
3.42
3.90
3.66
3.5
3.5
3.5
-1.0
1.84
2.41
-13.6
-13.6
-13.6
-16.0
-14.8
-15.4
n/2
18:30
427
2904
3050
0
0
7.9
58. B
58.6
0
0
3.0
3190
2808
2713
2415
1624
573
577
575
534
360
9.5
9.5
9.5
3.44
3.90
3.67
3.5
3.5
3.5
-1.0
1.82
2.39
-13.5
-13.4
-13.4
-16.0
-14.5
-15.2
BOARD DATA
COMPUTER DATA
279
SHEET B37
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM ATJATER
C FEEDWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE IST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
Alft 4 GAS
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
5 FD FAN DISCHARGE AVG.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESS. R
B WINDBOX PRESS. L
B WINDBOX PRESS. AVG.
6 FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. ORAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
B a BOARD DATA
C = COMPUTER DATA
BOARD AND COMPUTER
1975
MW
.B/ffi
PSIG
"HgO
J7
10/3
22:30
423
2926
3100
0
0
22.9
58.8
58.8
0
0
3.0
3180
2813
2715
2418
1826
574
578
576
535
357
9.0
8.9
9.0
3.35
3.79
3.57
3.1
3.1
3.1
-1.2
1.93
2.45
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
!§
10/3
20:30
430
2885
3038
0
0
18.7
58.8
58.8
0
0
3.0
3240
2606
2711
2413
1824
574
579
576
535
360
9.4
9.4
9.4
3.44
3.88
3.66
3.5
3.5
3.5
-1.2
2.00
2.61
-13.8
-13.8
-13.8
-16.0
-15.0
-15.5
DATA
1*
10/6
19:00
417
2900
3050
0
0
0
58.8
58.8
0
0
3.0
3100
2813
2715
2415
1824
572
576
574
524
359
8.8
8.8
8.8
3.23
3.64
3.44
3.3
3.3
3.3
-1.0
1.85
2.43
-13.3
-12.8
-13.0
-15.5
-14.0
-14.6
20
10/8
10:30
426
2908
3050
0
0
0
58.8
58.8
0
0
3.8
3110
2816
2720
2419
1829
571
575
573
532
363
8.5
8.5
8.5
3.30
3.72
3.51
3.0
3.0
3.0
-1.0
1.77
2.45
-13.8
-13.2
-13.5
-15.5
-14.0
-14.8
21
10/10
01:45
356
2333
2400
0
0
0
58.8
58.6
0
0
3.0
2460
2705
2628
2416
1442
464
468
460
428
380
4.8
4.6
4.7
2.21
2.58
2.40
1.0
1.0
1.0
-1.0
1.13
1.71
-10.6
-9.8
-10.2
-11.6
-10.6
-11.1
22
10/9
01:15
358
2307
2400
0
0
4.5
58.8
58.8
0
0
3.1
2640
2701
2631
2420
1438
465
469
467
429
384
6.8
6.6
6.7
2.50
2.87
2.66
S.5
2.5
2.5
-1.0
1.33
1.80
-10.0
-10.0
-10.0
-11.8
-10.5
-11.2
23
10/12
06:15
253
1665
1650
0
0
0
28.2
28.5
0
0
3.0
1800
2592
2537
2416
NA
NA
NA
NA
293
404
2.5
2.5
2.5
1.36
1.52
1.44
0
0
0
-1.0
0.53
0.98
-6.8
-6.0
-6.4
-7.5
-6.8
-7.2
24
10/5
18:45
266
1657
1650
0
0
0
58.8
58.8
0
0
3.0
1810
2593
2532
2414
1008
334
336
335
301
408
2.5
2.5
2.5
1.38
1.57
1.48
0
0
0
-1.0
0.60
0.88
-6.8
-6.6
-6.7
-8.0
-7.6
-7.8
280
SHEET B38
-------
UTAH POWER AND LIGHT COMPANY
HUNTINSTON CANYON f£
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OYERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STH. TO STM. AH 2-1
C EXT. STH. TO STM. AH 2-2
C Aux. STH. TO STH. AH 2-1
C Aux. STH. TO STH. AH 2-2
C Aux. STH. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
StEAH fgATER
C FEEDWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1ST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET Avs.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
PSIG
10
11
12
13
15
16
1975 9/27
13:30
MW 428
10\B/B3
2685
3033
0
0
0
58.8
58.8
0
0
3.0
3770
9/27
12:00
429
2681
3050
0
0
0
58.9
58.9
0
0
3.1
3710
9/27
14:00
429
2891
3050
0
0
0
58.8
58.8
0
0
3.0
3730
10/5
13:45
427
2909
3000
0
0
0
58.8
58.8
0
0
3.0
3130
10/4
16:00
434
2853
3000
0
0
17.3
58. B
56.8
0
0
3.0
3250
10/5
12:00
422
2B89
3000
0
0
0
58.8
58.8
0
0
3.0
3140
10/4
14:15
429
2882
3000
0
0
0
58.8
58.8
0
0
3.0
3200
10/3
18:30
427
2904
3050
0
0
7.9
56. B
58. 8
0
0
3.0
3190
2810
2703
2423
1812
567
571
569
531
386
2818
2716
2417
1627
569
573
571
530
362
2818
2719
2420
1828
570
573
572
531
359
2813
2719
2415
1829
573
577
575
533
360
2814
2718
2420
1829
576
579
578
536
359
2807
2705
2411
1806
565
569
567
528
362
2812
2713
2417
1823
572
575
574
533
361
2308
2713
2415
1824
573
577
575
534
360
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE Avs.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. Avo.
B WINOBOX PRESS. R
B WINDBOX PRESS. L
B WINOBOX PRESS. Ava.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. Avo.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
11.0
11.0
11.0
4.42
5.02
4.72
3.5
3.5
3.5
-1.0
2.54
3.16
-15.0
-15.0
-15.0
-21.5
-17.5
-19.5
11.8
11.8
11.8
4.41
4.84
4.62
4.3
4.3
4.3
-1.0
2.26
3.08
-15.0
-15.0
-15.0
-19.1
-19.1
-19.1
11.8
11.8
11.8
4.40
4.84
4.62
4.5
4.5
4.5
-1.0
2.36
3.11
-15.0
-15.0
-15.0
-19.0
-19.0
-19.0
9.3
9.3
9.3
3.37
3.81
3.59
3.5
3.5
3.5
-1.0
1.82
2.44
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
9.8
9.8
9.8
3.56
3.98
3.77
3.8
3.8
3.8
-1.2
1.95
2.51
-14.3
-14.3
-14.3
-16.9
-15.4
-16.2
9.2
9.2
9.2
3.33
3.73
3.53
3.4
3.4
3.4
-1.0
1.73
2.31
-13.5
-13.4
-13.4
-15.6
-14.5
-15.0
9.1
9.1
9.1
3.42
3.90
3.66
3.5
3.5
3.5
-1.0
1.84
2.41
-13.6
-13.6
-13.6
-16.0
-14.8
-15.4
9.5
9.5
9.5
3.44
3.90
3.67
3.5
3.5
3.5
-1.0
1.82
2.39
-13.5
-13.4
-13.4
-16.0
-14.5
-15.2
BOARD DATA
COMPUTER DATA
279
SHEET B37
-------
UTAH POWER AND LIGHT COMPANY
HUNTING-TON CANYON Je
C-E POWER SYSTEMS
FIELD TESTiNO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATCR
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STH. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STH. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAH t "WATER
C FEEDWATER TO EeoN.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE IST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IH
PRESSURES
AIR i GAS
BOARD AND COMPUTER DATA
17 18 19
1975
MW
PSIG
"HgO
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE AVG.
C AH 2-1 AIR Dirr. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESS. R
B WINDBOX PRESS. L
B WINDBOX PRESS. AVG.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
20
21
22
23
24
10/3
22:30
423
2926
3100
0
0
22.9
58.8
58.8
0
0
3.0
3180
2813
2715
2418
182E
574
578
576
535
357
9.0
8.9
9.0
3.35
3.79
3.57
3.1
3.1
3.1
-1.2
1.93
2.45
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/3
20:30
430
2885
3038
0
0
18.7
58.8
58.8
0
0
3.0
3240
2806
2711
2413
1824
574
579
576
535
360
9.4
9.4
9.4
3.44
3.88
3.66
3.5
3.5
3.5
-1.2
2.00
2.61
-13.8
-13.8
-13.8
-16.0
-15.0
-15.5
10/6
19:00
417
2900
3050
0
0
0
58.8
58.8
0
0
3.0
3100
2813
2715
2415
1824
572
576
574
524
359
8.8
8.8
a. 8
3.23
3.64
3.44
3.3
3.3
3.3
-1.0
1.85
2.43
-13.3
-12.8
-13.0
-15.5
-14.0
-14.8
10/8
10:30
426
2908
3050
0
0
0
58.8
58.8
0
0
3.2
3110
2816
2720
2419
1829
571
575
573
532
363
8.5
8.5
8.5
3.30
3.72
3.51
3.0
3.0
3.0
-1.0
1.77
2.45
-13.B
-13.2
-13.5
-15.5
-14.0
-14.8
10/10
01:45
356
2333
2400
0
0
0
58.8
58.8
0
0
3.0
2460
2705
2628
2416
1442
464
46B
460
428
380
4.8
4.6
4.7
2.21
2.58
2.40
1.0
1.0
1.0
-1.0
1.13
1.71
-10.6
-9.8
-10.2
-11.6
-10.6
-11.1
10/9
01:15
358
2307
2400
0
0
4.5
58.8
58.8
0
0
3.1
2640
2701
2631
2420
1438
465
469
467
429
384
6.8
6.6
6.7
2.50
2.87
2.68
2.5
2.5
2.5
-1.0
1.33
1.80
-10.0
-10.0
-10.0
-11.8
-10.5
-11.2
10/12
08:15
253
1665
1650
0
0
0
28.2
28.5
0
0
3.0
1800
2592
2537
2416
NA
NA
NA
NA
293
404
2.5
2.5
2.5
1.36
1.52
1.44
0
0
0
-1.0
0.53
0.98
-6.8
-6.0
-6.4
-7.5
-6.8
-7.2
10/5
18:45
266
1657
1650
0
0
0
58.8
58.8
0
0
3.0
1810
2593
2532
2414
1008
334
336
335
301
408
2.5
2.5
2.5
1.38
1.57
1.48
0
0
0
-1.0
0.60
0.88
-6.8
-6.6
-6.7
-8.0
-7.6
-7.8
BOARD DATA
COMPUTER DATA
280
SHEET B38
-------
UTAH POWER AND LIOHT COMPANY
HUNTINQTON CANYON iS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDUATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STH. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STH. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM & "MATER
C FEEDVATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1st STAGE
C RH INLET LETT
C RH INLET RIGHT
C RH INLET Ava.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
AIR & GAS.
L
Ava.
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE AVG.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR Dirr. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESS. R
B WINDBOX PRESS.
B WINOBOX PRESS.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT Dirr.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B 10 FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
B = BOARD DATA
C «• COMPUTER DATA
10
11
12
13
14
15
IS
1975
1
Mrf
io\B/m
PSIG
"H20
9/27
13:30
428
2885
3033
0
0
0
58.8
56,8
0
0
3.0
3770
2810
2703
2423
1B12
567
571
569
531
366
11.0
11.0
11.0
4.42
5.02
4.72
3.5
3.5
3.5
-1.0
2.54
3.16
-15.0
-15.0
-15.0
-21.5
-17.5
-19.5
9/27
12:00
429
2881
3050
0
0
0
58.9
58.9
0
0
3.1
3710
2818
2716
2417
1827
569
573
571
530
362
11.8
11.8
11.8
4.41
4.84
4.62
4.3
4.3
4.3
-1.0
2.26
3.08
-15.0
-15.0
-15.0
-19.1
-19.1
-19.1
9/27
14:00
429
2891
3050
0
0
0
58.8
58.8
0
0
3.0
3730
2818
2719
2420
1828
570
573
572
531
359
11.8
11.8
11.8
4.40
4.84
4.62
4.5
4.5
4.5
-1.0
2.36
3.11
.15.0
-15.0
-15.0
-19.0
-19.0
-19.0
10/5
13:45
427
2909
3000
0
0
0
58.8
58.8
0
0
3.0
3130
2813
2719
2415
1829
573
577
575
533
360
9.3
9.3
9.3
3.37
3. 81
3.59
3.5
3.5
3.5
-1.0
1.82
2.44
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/4
16:00
434
2853
3000
0
0
17.3
58.8
58.8
0
0
3.0
3250
2814
2718
2420
1829
576
579
578
536
359
9.8
9.8
9.8
3.56
3.98
3.77
3.8
3.8
3.8
-1.2
1.95
2.51
-14.3
-14.3
-14.3
-16.9
-15.4
-16.2
10/5
1S:00
422
2889
3000
0
0
0
58.8
58.8
0
0
3.0
3140
2807
2705
2411
1806
565
569
567
528
362
9.2
9.2
9.2
3.33
3.73
3.53
3.4
3.4
3.4
-1.0
1.73
2.31
-13.5
-13.4
-13.4
-15.6
-14.5
-15.0
):/;
14:15
429
2882
3000
0
0
0
58.8
58.8
0
0
3.0
3200
2812
2713
2417
1823
572
575
574
533
361
9.1
9.1
9.1
3.42
3.90
3.66
3.5
3.5
3.5
-1.0
1.84
2.41
-13.6
-13.6
-13.6
-16.0
-14.8
-15.4
10/3
18:30
427
2904
3050
0
0
7.9
58.8
58.8
0
0
3.0
3190
2808
2713
2415
1824
573
577
575
534
360
9.5
9.5
9.5
3.44
3.90
3.67
3.5
3.5
3.5
-1.0
1.82
2.39
-13.5
-13.4
-13.4
-16.0
-14.5
-15.2
279
SHEET B37
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON K
C-E POWER SYSTEMS
FIELD TCSTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
FLOWS
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STH. TO STH. AH 2-1
C EXT. STH. TO STH. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM t WATER
C FEEOWATCR TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE IST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET Avc.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
A if) i GAS
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE Avc.
C AH 2-1 AIR Dirr. PRESS. R
C AH 2-2 AIR Dirr. PRESS. L
C AH AIR DIFF. PRESS. Avc.
B WINDBOX PRESS. R
B WINDBOX PRESS. L
B WINDBOX PRESS. Avc.
B FURNACE DRAFT
C SH DRAFT Dirr.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
8 AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. Avo.
BOARD AND COMPUTER
1975
MW
.B/HR
PSIG
"HgO
J7
10/3
22:30
423
2926
3100
0
0
22.9
58.8
58.8
0
0
3.0
3180
2813
2715
2418
1826
574
578
576
535
357
9.0
8.9
9.0
3.35
3.79
3.57
3.1
3.1
3.1
-1.2
1.93
2.45
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
Jfl
10/3
20:30
430
2885
3038
0
0
18.7
58.8
58.8
0
0
3.0
3240
2806
2711
2413
1824
574
579
576
535
360
9.4
9.4
9.4
3.44
3.88
3.66
3.5
3.5
3.5
-1.2
2. 00
2.61
-13.8
-13.8
-13.8
-16.0
-15.0
-15.5
DATA
15
10/6
19:00
417
2900
3050
0
0
0
58.8
58.8
0
0
3.0
3100
2813
2715
2415
1824
572
576
574
524
359
8.8
8.8
8.8
3.23
3.64
3.44
3.3
3.3
3.3
-1.0
1.85
2.43
-13.3
-12.8
-13.0
-15.5
-14.0
-14.8
20
10/8
10:30
426
2908
3050
0
0
0
58.8
58.8
0
0
3.2
3110
2816
2720
2419
1829
57T
575
573
532
363
8.5
8.5
8.5
3.30
3.72
3.51
3.0
3.0
3.0
-1.0
1.77
2.45
-13.8
-13.2
-13.5
-15.5
-14.0
-14.8
21
10/10
01:45
356
2333
2400
0
0
0
58.8
58.8
0
0
3.0
2460
2705
2628
2416
1442
464
468
460
428
380
4.8
4.6
4.7
2.21
2.58
2.40
1.0
1.0
1.0
-1.0
1.13
1.71
-10.6
-9.8
-10.2
-11.6
-10.6
-11.1
22
10/9
01:15
358
2307
2400
0
0
4.5
58.8
58.8
0
0
3.1
2640
2701
2631
2420
1438
465
469
467
429
384
6.8
6.6
6.7
2.50
2.87
2.68
2.5
2.5
2.5
-1.0
1.33
1.80
-10.0
-10.0
-10.0
-11.8
-10.5
-11.2
23
10/12
08:15
253
1665
1650
0
0
0
28.2
28.5
0
0
3.0
1800
2592
2537
2416
NA
NA
NA
NA
293
404
2.5
2.5
2.5
1.36
1.52
1.44
0
0
0
-1.0
0.53
0.98
-6.8
-6.0
-6.4
-7.5
-6.8
-7.2
24
10/5
18:45
266
1657
1650
0
0
0
58.8
58.8
0
0
3.0
1810
2593
2532
2414
1008
334
336
335
301
408
2.5
2.5
2.5
1.38
1.57
1.48
0
0
0
-1.0
0.60
0.88
-6.8
-6.6
-6.7
-8.0
-7.6
-7.8
BOARD DATA
COMPUTER DATA
280
SHEET B38
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTOH CANYON 12
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEOWATER
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
B AIR FLOW TO BOILER
PRESSURES
STEAM I WATER
C FEEOWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE IST STAGE
C RH INLET LEFT
C RH INLET RIGHT
C RH INLET Avc.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
AIR & GAS.
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE AVG.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESS. R
B WINDBOX PRESS. I
B WINDBOX PRESS. Avc.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT DIFF.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. Avo.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
B = BOARD DATA
C = COMPUTER DATA
1975
MW
10
I\B/I
'H?
PSIG
"H20
10
11
12
13
14
15
16
9/27
13:30
428
2885
3033
0
0
0
58.8
58,8
0
0
3.0
3770
2810
2703
2423
1812
567
571
569
531
366
11.0
11.0
11.0
4.42
5.02
4.72
3.5
3.5
3.5
-1.0
2.54
3.16
-15.0
-15.0
-15.0
-21.5
-17.5
-19.5
9/27
12:00
429
2681
3050
0
0
0
58.9
58.9
0
0
3.1
3710
2818
2716
2417
1827
569
573
571
530
362
11.8
11.8
11.8
4.41
4.84
4.62
4.3
4.3
4.3
-1.0
2.26
3.08
-15.0
-15.0
-15.0
-19.1
-19.1
-19.1
9/27
14:00
429
2891
3050
0
0
0
58.8
58.8
0
0
3.0
3730
2818
2719
2420
1828
570
573
572
531
359
11.8
11.8
11.8
4.40
4.84
4.62
4.5
4.5
4.5
-1.0
2.36
3.11
-15.0
-15.0
-15.0
-19.0
-19.0
-19.0
10/5
13:45
427
2909
3000
0
0
0
58.8
58.8
0
0
3.0
3130
2813
2719
2415
1829
573
577
575
533
360
9.3
9.3
9.3
3.37
3.81
3.59
3.5
3.5
3.5
-1.0
1.82
2.44
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
10/4
16:00
434
2853
3000
0
0
17.3
5B.8
58.8
0
0
3.0
3250
2814
2718
2420
1829
576
579
578
536
359
9.8
9.8
9.8
3.56
3.98
3.77
3.8
3.8
3.8
-1.2
1.95
2.51
-14.3
-14.3
-14.3
-16.9
-15.4
-16.2
10/5
12:00
422
2889
3000
0
0
0
58.8
58.8
0
0
3.0
3140
2807
2705
241 1
1806
565
569
567.
528
352
9.2
9.2
9.2
3.33
3.73
3.53
3.4
3.4
3.4
-1.0
1.73
2.31
-13.5
-13.4
-13.4
-15.6
-14.5
-15.0
10/4
14:15
429
2882
3000
0
0
0
58.8
58.8
0
0
3.0
3200
2812
2713
2417
1823
572
575
574
533
361
9.1
9.1
9.1
3.42
3.90
3.66
3.5
3.5
3.5
-1.0
1.84
2.41
-13.6
-13.6
-13.6
-16.0
-14.8
-15.4
10/3
18:30
427
2904
3O50
0
0
7.9
58.8
58.8
0
0
3.0
3190
2808
2713
2415
1824
573
577
575
534
360
9.5
9.5
9.5
3.44
3.90
3.67
3.5
3.5
3.5
-1.0
1.82
2.39
-13.5
-13.4
-13.4
-16.0
-14.5
-15.2
279
SHEET 637
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON /2
C-E POWER SYSTEMS
FIELD TESTiNO AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
FLOWS
C FEEDWATCR
B MAIN STEAM
C SUPERHEAT SPRAY L
C SUPERHEAT SPRAY R
C REHEAT SPRAY
C EXT. STM. TO STM. AH 2-1
C EXT. STM. TO STM. AH 2-2
C Aux. STM. TO STM. AH 2-1
C Aux. STM. TO STM. AH 2-2
C Aux. STM. TO SJAE
8 AIR FLOW TO BOILER
PRESSURES
STEAKt &"WATER
C FEEDWATER TO ECON.
C BOILER DRUM
C TURBINE THROTTLE
C TURBINE 1ST STAOE
C RH INLET LEFT
C RH INLET RIQHT
C RH INLET AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
PRESSURES
A|H t GAS
B FD FAN DISCHARGE R
B FD FAN DISCHARGE L
B FD FAN DISCHARGE Ava.
C AH 2-1 AIR DIFF. PRESS. R
C AH 2-2 AIR DIFF. PRESS. L
C AH AIR DIFF. PRESS. AVG.
B WINDBOX PRESS. R
B WINDBOX PRESS. L
B WINDBOX PRESS. AVG.
B FURNACE DRAFT
C SH DRAFT DIFF.
C ECON. DRAFT Dirr.
B AH 2-1 GAS OUT. PRESS. R
B AH 2-2 GAS OUT. PRESS. L
B AH GAS OUT. PRESS. AVG.
B ID FAN 2-1 INLET PRESS. R
B ID FAN 2-2 INLET PRESS. L
B ID FAN INLET PRESS. AVG.
r?
1975 10/3
22:30
MW 423
2926
3100
0
0
22.9
58.8
58.8
0
0
3.0
3180
PSIG
2813
2715
2418
1826
574
578
576
535
357
9.0
8.9
9.0
3.35
3.79
3.57
3.1
3.1
3.1
-1.2
1.93
2.45
-13.5
-13.5
-13.5
-15.8
-14.8
-15.3
JS
10/3
20:30
430
2885
3038
0
0
18.7
58.8
58.8
0
0
3.0
3240
2806
2711
2413
1824
574
579
576
535
360
9.4
9.4
9.4
3.44
3.88
3.66
3.5
3.5
3.5
-1.2
2.00
2.61
-13.8
-13.8
-13.8
-16.0
-15.0
-15.5
15
10/6
19:00
417
2900
3050
0
0
0
58.8
58.8
0
0
3.0
3100
2813
2715
2415
1824
572
576
574
524
359
8.8
8.8
8.8
3.23
3.64
3.44
3.3
3.3
3.3
-1.0
1.85
2.43
-13.3
-12.8
-13.0
-15.5
-14.0
-14.8
20
10/8
10:30
426
"2908
3050
0
0
0
58.8
58.8
0
0
3.2
3110
2816
2720
2419
1829
571
575
573
532
363
8.5
8.5
8.5
3.30
3.72
3.51
3.0
3.0
3.0
-1.0
1.77
2.45
-13.8
-13.2
-13.5
-15.5
-14.0
-14.8
«
10/10
01:45
356
2333
2400
0
0
0
58.8
58.8
0
0
3.0
2460
2705
2628
2416
1442
464
468
460
428
380
4.8
4.6
4.7
2.21
2.58
2.40
1.0
1.0
1.0
-1.0
1.13
1.71
-10.6
-9.8
-10.2
-11.6
-10.6
-11.1
22
10/9
01:15
358
2307
2400
0
0
4.5
58.8
58.8
0
0
3.1
2640
2701
2631
2420
1438
465
469
467
429
384
6.8
6.6
6.7
2.50
2.87
2.68
2.5
2.5
S.5
-1.0
1.33
1.80
-10.0
-10.0
-10.0
-11.8
-10.5
-11.2
23
10/12
08:15
253
1665
1650
0
0
0
28.2
28.5
0
0
3.0
1800
2592
2537
2416
NA
NA
NA
NA
293
404
2.5
2.5
2.5
1.36
1.52
1.44
0
0
0
-1.0
0.53
0.98
-6.8
-6.0
-6.4
-7.5
-6.8
-7.2
24
10/5
18:45
266
1657
1650
0
0
0
58.8
58.8
0
0
3.0
1810
2593
2532
2414
1008
334
336
335
301
408
2.5
2.5
2.5
1.38
1.57
1.48
0
0
0
-1.0
0.60
0.88
-6.8
-6.6
-6.7
-8.0
-7.6
-7.8
BOARD DATA
COMPUTER DATA
280
SHEET B38
-------
UTAH POWER AND LIOHT COMPANY
HUNTING-TON CANYON |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
BOARD AND COMPUTER DATA
1 2 3
TEMPERATURES
AIR S GAS
C AH 2-1 AIR IN TEMP.
C AH 2-2 AIR IN TEMP.
C AH AIR IN TEMP. Avo.
C AH 2-1 AIR OUT TEMP.
C AH 2-2 AIR OUT TEMP.
C AH AIR OUT TEMP, Avo.
C AH 2-1 GAS IN TEMP.
C AH 2-2 GAS IN TEMP.
C AH GAS IN TEMP. Avs.
C AH 2-1 GAS OUT TEMP.
C AH 2-2 GAS OUT TEMP.*
C AH GAS OUT TEMP. AVG.
TEMPERATURES
STEAM & WATER
C FW IN TEMP. TO ECON.
C ECON. OUT. Avc.
C BOILER DOVNCOMER
C SH DESH INLET L
C SH DESH INLET R
C SH DESH INLET Avo.
C SH DESH OUTLET L
C SH DESH OUTLET R
C SH DESH OUTLET AVB.
C SH OUTLET .
C THROTTLE STEAM
C RH TURBINE L
C RH TURBINE R
C RH TURBINE AVG.
C RH BOILER L
C RH BOILER R
C RH BOILER AVG.
C RH OUTLET
C HP HTR. 2-7 STH. IN
C HP HTR. 2-7 FW IN
C HP HTR. 2-7 DRAIN
C Aux. STEAM TEMP.
FAN DAMPER POSITION
B FD FANS
B ID FANS
SPRAY VALVE POSITION
B SH SPRAY
B RH SPRAY
1975
f OPEN
OPEN
1/17
):20
428
103
98
100
521
544
532
722
722
722
268
279
274
4B4
576
678
752
759
756
758
764
761
987
976
616
617
616
601
595
598
995
615
415
423
528
75
67
0
15
9/26
09:40
430
108
94
101
513
546
530
714
701
708
261
286
274
485
577
678
749
763
756
754
764
759
983
971
613
613
613
598
592
595
1004
611
415
423
528
73
66
0
14
9/26
11:30
430
108
94
101
513
548
530
715
703
709
261
287
274
485
577
678
751
759
755
756
763
760
983
973
613
614
614
600
595
598
1002
612
415
423
529
74
65
0
13
9/26
15:30
430
109
91
100
511
545
528
710
703
706
261
286
274
486
574
678
749
757
753
755
759
757
989
979
619
620
619
576
562
569
994
619
416
424
530
74
66
0
28
9/26
17:15
431
109
91
100
512
547
530
711
708
710
261
288
274
486
575
679
750
756
753
757
759
758
987
974
616
616
616
581
569
575
1002
614
416
424
530
74
66
0
25
10/1
18:00
430
96
110
103
534
534
534
716
707
712
282
264
273
485
570
678
745
755
750
751
760
756
991
980
619
619
619
615
614
614
1020
618
415
424
531
70
60
0
0
10/1
19:30
428
96
109
102
532
535
534
714
707
710
280
265
272
484
570
678
747
756
752
753
758
756
980
971
612
613
612
608
608
608
1011
612
415
424
530
70
63
0
0
10/1
21:00
428
95
109
102
533
536
534
713
709
711
279
265
272
485
571
678
749
760
754
755
761
758
982
974
615
615
615
611
610
610
1014
613
416
424
531
70
62
0
0
BOARD DATA
COMPUTER DATA
TC READING OPEN
281
SHEET B39
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON fS
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
TEMPERATURES
AIR t GAS
C AH 2-1 AIR IN TEMP.
C AH 2-2 AIR IN TEMP.
C AH AIR IN TEMP. Avo.
C AH 2-1 AIR OUT TEMP.
C AH 2-2 AIR OUT TEMP.
C AH AIR OUT TEMP. Avs.
C AH 2-1 GAS IN TEMP.
C AH 2-2 GAS IN TEMP.
C AH GAS IN TEMP. Ava.
C AH 2-1 GAS OUT TEMP.
C AH 2-2 GAS OUT TEMP.*
C AH GAS OUT TEMP. Avc.
TEMPERATURES
C FW IN TEMP. TO ECON.
C ECON. OUT. Avc.
C BOILER DOVNCOMER
C SH DESH INLET L
C SH DESH INLET R
C SH DESH INLET Ava.
C SH DESH OUTLET L
C SH DESH OUTLET R
C SH DESH OUTLET AVG.
C SH OUTLET
C THROTTLE STEAM
C RH TURBINE L
C RH TURBINE R
C RH TURBINE Avs.
C RH BOILER L
C RH BOILER R
C RH BOILER Ava.
C RH OUTLET
C HP HTR. 2-7 STM. IN
C HP HTR. 2-7 FW IN
C HP HTR. 2-7 DRAIN
C Aux. STEAM TEMP.
FAN DAMPER POSITION
8 FD FANS"
B ID FANS
SPRAY VALVE POSITION
B SH SPRAY!
B RH SPRAY
BOARD AND COMPUTER DATA
9 10 Jl
1975
MW
•F
12
13
14
15
16
% OPEN
OPEN
9/27
13:30
426
105
9B
102
512
543
528
724
713
718
266
282
274
485
584
678
751
758
754
757
761
759
983
973
613
614
614
609
609
609
1012
613
413
423
525
80
74
0
0
9/27
12:00
429
96
104
100
530
545
538
728
733
730
281
270
276
484
586
678
758
762
760
765
769
767
994
980
620
620
620
616
616
616
1012
621
415
423
542
79
71
0
0
9/27
14:00
429
96
105
100
531
545
538
729
731
730
282
271
276
484
587
678
759
762
760
766
770
768
993
982
621
621
621
618
616
617
1011
620
415
423
545
80
71
0
0
10/5
13:45
427
101
103
102
527
540
534
715
714
714
276
274
275
484
571
678
748
748
748
753
753
753
977
967
609
609
609
605
604
604
1006
608
415
424
525
72
63
0
0
10/4
16:00
434
100
103 '
102
531
541
536
724
716
720
277
273
275
486
574
678
748
761
754
754
765
760
1006
997
634
635
634
612
603
608
1026
635
416
424
577
73
65
0
23
10/5
12:00
422
101
104
102
524
536
530
710
709
710
274
273
274
484
568
677
742
742
742
748
749
748
969
960
602
603
602
600
599
600
991
602
414
423
518
71
62
0
0
10/4
14:15
429
100
104
102
526
538
532
714
709
712
275
272
274
485
571
678
744
751
748
750
756
753
988
977
617
618
618
611
610
610
1017
616
415
424
530
72
64
0
3
10/3
18:30
427
99
104
102
526
535
530
711
714
712
275
270
272
485
570
678
740
751
746
747
757
752
978
968
611
611
611
596
588
592
995
609
415
423
526
72
64
0
15
BOARD DAT*
COMPUTER DATA
TC READING OPEN
282
SHEET B40
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON JZ
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TIME
C LOAD
TEMPERATURES
AIR & GAS
C AH 2-1 AIR IN TEMP.
C AH 2-2 AIR IN TEMP.
C AH AIR IN TEMP. AVG.
C AH 2-1 AIR OUT TEMP.
C AH 2-2 AIR OUT TEMP.
C AH AIR OUT TEMP. AVG.
C AH 2-1 GAS IN TEMP.
C AH 2-2 GAS IN TEMP.
C AH GAS IN TEMP. AVG.
C AH 2-1 GAS OUT TEMP.
C AH 2-2 GAS OUT TEMP.*
C AH GAS OUT TEMP. AVG.
TEMPERATURES
STEAM & WATER
C FW IN TEMP. TO ECON.
C ECON. OUT. AVG.
C BOILER DOWHCOHER
C SH DESH INLET L
C SH DESH INLET R
C SH DESH INLET AVG.
C SH DESH OUTLET L
C SH DESH OUTLET R
C SH DESH OUTLET AVG.
C SH OUTLET
C THROTTLE STEAM
C RH TURBINE L
C RH TURBINE R
C RH TURBINE AVG.
C RH BOILER L
C RH BOILER R
C RH BOILER AVG.
C RH OUTLET
C HP HTR. 2-7 STM. IN
C HP HTR. 2-7 FW IN
C HP HTR. 2-7 DRAIN
C Aux. STEAM TEMP.
FAN DAMPER POSITION
B FD FANS
B ID FANS
SPRAY VALVE POSITION
B SH SPRAY'
B RH SPRAY
V7
175 10/3
22:30
MW 423
98
104
101
524
534
529
708
708
708
274
271
272
•F
484
569
678
739
752
746
746
750
748
961
951
597
597
597
555
544
550
965
594
415
423
511
»EN
70
63
PEN
0
25
J8
10/3
20:30
430
97
103
100
527
538
532
715
721
718
275
272
274
486
573
678
747
759
753
753
758
756
989
981
622
623
622
595
581
588
1007
620
416
424
533
70
62
0
22
J9
10/6
19:00
417
102
104
103
524
534
529
710
702
706
273
272
272
484
567
678
744
742
743
744
747
746
961
958
602
603
602
599
599
599
987
603
415
424
518
70
60
0
0
20
10/8
10:30
426
97
103
100
522
532
527
710
702
706
272
271
272
484
568
678
739
743
741
744
748
746
972
960
603
603
603
601
599
600
991
602
415
423
513
68
60
0
0
SI
10/10
01:45
356
109
108
108
504
511
508
659
655
657
262
266
264
464
539
672
738
742
740
743
744
744
983
976
579
585
582
577
579
578
983
580
399
405
530
57
53
0
0
22
10/9
01:15
358
110
112
111
505
510
508
672
673
672
262
259
260
464
545
673
751
757
754
758
756
757
995
989
591
596
594
576
573
574
1002
591
400
405
552
61
55
0
12
23
10/12
08:15
253
116
118
117
468
470
469
592
591
592
248
250
249
430
498
668
730
733
732
734
737
736
973
963
NA
NA
NA
519
529
524
954
529
371
375
519
46
41
0
0
24
10/5
18:45
266
115
117
116
476
476
476
608
607
608
252
254
253
434
504
668
740
741
740
741
746
744
1005
996
550
562
556
547
557
552
988
556
374
377
535
46
41
7
0
BOARD DATA
COMPUTER DATA
TC READING OPEN
283
SHEET B41
-------
UTAH POWER AND LIGHT COMPANY
HUNT INGTON CANYON 12
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
BOARD AND COMPUTER DATA
TEST NO.
DATE
TINE
C LOAD
HILL DATA
C MILL 2-1
C MILL 2-2
C MILL 2-3
C MILL 2-4
C MILL 2-5
C COAL AIR TEMP. MILL 2-1
C COAL AIR TEMP. MILL 2-2
C COAL AIR TEMP. MILL 2-3
C COAL AIR TEMP. MILL 2*4
C COAL AIR TEMP. MILL 2-5
B MILL 2-1 EXM. DISCH.
B MILL 2-2 EXH. DISCH.
B MILL 2-3 EXH. DISCH.
B MILL 2-4 EXH. DISCH.
B MILL 2-5 EXH. DISCH.
B MILL 2-1 SUCTION
B MILL 2-2 SUCTION
B MILL 2-3 SUCTION
B MILL 2-4 SUCTION
B MILL 2-5 SUCTION
B MILL 2-1 COAL FLOW
B MILL 2-2 COAL FLOW
B MILL 2-3 COAL FLOW
B MILL 2-4 COAL FLOW
B MILL 2-5 COAL FLOW
B MILL 2-1 FEEDER SPEED •
8 MILL 2-2 FEEDER SPEED
B MILL 2-3 FEEDER SPEED
B MILL 2-4 FEEDER SPEED
B MILL 2-5 FEEDER SPEED
BURNER TILT
B POSITION LF
B POSITION LR
8 POSITION RF
B POSITION RR
MISCELLANEOUS
B DRUM LEVEL " - NORM. H00 LEVEL
C FD FAN 2-1 *
C FD FAN 2-2
C ID FAN 2-1
C ID FAN 2-2
B FLUE GAS SO IN STACK
B FLUE GAS NO IN STACK
C FLUE GAS COMBUSTIBLES L
C FLUE GAS COMBUSTIBLES R
C FLUE GAS 0- L
C FLUE GAS C? R
C FLUE GAS Or Avc.
B AMBIENT TEMP.
B AMBIENT REL. HUMIDITY
B BAROMETRIC PRESS.
B = BOARD DATA
C = COMPUTER DATA
* FEEDER SPEED IN % or CONTROL Slant
10?
10,
1°Q
10,
10 ,
1975
MW
AMPS
AMPS
AMPS
AMPS
AMPS
•F
"F
•F
•F
"F
till Q
"H?0
"(Co
"H?0
"HrO
"tro
"(CO
"H?0
"ICO
nH?0
LB/HR
LB/HR
IB/HR
LB/HR
LB/HR
%
%
%
%
%
_1
9/17
10:20
426
NA
NA
NA
NA
NA
148
148
147
146
148
7.0
7.0
8.0
9.0
8.0
-1.8
-2.0
-1.8
-1.7
-2.0
66
64
63
63
63
75
76
75
75
75
2_
9/26
09:40
430
NA
NA
NA
NA
NA
149
150
148
148
149
6.0
6.4
7.0
8.7
7.2
-1.7
-1.9
-1.8
-1.7
-2.0
67
65
63
64
65
76
76
75
77
77
3
9/26
11:30
430
NA
NA
NA
NA
NA
148
150
147
148
149
6.2
6.5
7.0
8.3
7.3
-1.8
-1.9
-1.9
-1.7
-2.1
68
66
63
63
64
78
77
75
77
76
4
9/26
15:30
430
NA
NA
NA
NA
NA
149
150
147
148
149
6.0
6.5
7.0
8.8
7.9
-1.8
-2.0
-1.9
-1.8
-2.0
69
66
64
64
64
79
78
76
77
77
5
9/26
17:15
431
NA
NA
NA
NA
NA
149
150
147
148
149
6.0
6.5
7.0
8.5
7.5
-1.8
-2.0
-1.9
-1.7
-2.0
68
66
64
64
65
78
77
76
78
77
6
10/1
18:00
430
NA
NA
NA
NA
NA
150
150
149
146
148
7.4
6.8
7.0
7.0
7.4
-2.0
-2.0
-1.8
-2.0
-1.8
69
66
65
64
66
79
79
78
78
78
7
10/1
19:30
428
NA
NA
NA
NA
NA
150
150
149
146
148
7.1
7.1
7.0
7.0
7.0
-2.0
-2.0
-1.9
-2.1
-1.9
67
64
63
63
64
77
76
76
76
77
8
10/1
21:00
428
NA
NA
NA
NA
NA
149
149
147
146
149
7.3
6.7
7.0
7.0
7.4
-2.0
-1.9
-1.9
-2.1
-2.0
69
66
65
64
66
79
79
77
78
78
' DEGREES
AMPS
AMPS
AMPS
AMPS
PPM
PPM
%
%
%
f
%
•F
*
"Ho
+6
+7
45
46
-1
216
240
397
405
NA
NA
0.11
0.0
4.13
4.06
4.10
73
43
23.86
-11
-9
-10
-10
0
215
235
389
424
NA
627
0.11
0.0
4.52
3.62
4.07
67
29
23.97
-11
.9
-12
-10
0
214
235
385
419
NA
NA
0.10
0.0
4.16
3.86
4.01
74
25
23.96
-14
-12
-14
-14
0
214
235
385
419
NA
515
0.06
0.0
4.05
3.77
3.91
74
20
23.93
-14
-10
-15
-13
0
214
235
385
416
NA
580
0.06
0.0
3.71
4.19
3.95
70
24
23.92
+9
+10
+7
+9
0
208
229
400
373
60
400
0.06
0.0
2.96
2.54
2.75
64
28
24.05
+9
4-10
48
410
0
SOB
228
404
376
60
408
0.08
0.0
2.31
2.49
2.40
57
33
24.05
+10
+10
+8
+11
0
207
226
400
374
70
400
0.08
0.0
2.24
3.64
2.94
54
35
24.07
284
SHEET B42
-------
UTAH POWER AND LIOMT COMPANY
HUNTINGTON CANYON |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OVERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
MILL
C MILL
C MILL
C MILL
C MILL
C COAL
C COAL
C COAL
C COAL
C COAL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
DATA
2-
2-2
2-3
2-4
2-5
AIR TEMP
AIR TEMP
AIR TEMP
AIR TEMP
AIR TEMP
2-1 EXH.
2-2 EXH.
2-3 EXH.
2-4 EXH.
2-5 EXH.
2-1 SUCTION
2-2 SUCTION
2-3 SUCTION
2-4 SUCTION
2-5 SUCTION
2-1 COAL FLOW
2-2 COAL FLOW
2-3 COAL FLOW
2-4 COAL FLOW
2-5 COAL FLOW
2-1 FEEDER SPEED
2-2 FEEDER SPEED
2-3 FEEDER SPEED
2-4 FEEDER SPEED
2-5 FEEDER SPEED
MILL 2-1
MILL 2-2
MILL 2-3
MILL 2-4
MILL 2-5
DtSCH.
DlSCH.
DlSCH.
DlSCH.
DlSCH.
BURNER TILT
B POSITION LF
B POSITION LR
B POSITION RF
B POSITION RR
MlSCELLANEOUS|
B DRUM LEVEL " -
C FO FAN 2-1
C FD FAN 2-2
C ID FAN 2-1
C ID FAN 2-2
B FLUE GAS SO,
NORM. HgO LEVEL
IN STACK
o ri,i/b w«» ^v. I n wi*»vf*
B FLUE GAS NO IN STACK
C FLUE GAS COMBUSTIBLES L
C FLUE GAS COMBUSTIBLES R
C FLUE GAS 0 L
C FLUE GAS 0? R
C FLUE GAS di AVG.
B AMBIENT TEHP.
B AMBIENT REL. HUMIDITY
B BAROMETRIC PRESS.
B - BOARD DATA
C = COMPUTER DATA
• FEEDER SPEED IN % or CONTROL SIGNAL
BOARD AND COMPUTER
2
1°^
10,
10"
10J
1975
Mrf
AMPS
AMPS
AMPS
AMPS
AMPS
°F
°F
°F
°F
"F
"H.O
"H?0
"H^O
"H?0
"HfO
"HfO
"H?0
"HfO
"(TO
"HfO
1B/HR
LB/H?
.LB/HR
LB/HR
LB/HR
$
%
i
%
9
9/27
13:30
428
NA
NA
NA
NA
NA
148
149
147
141
148
5.8
7.0
7.0
8.5
7.5
-1.9
-2.0
-1.8
-1.7
-2.0
60
66
64
64
66
69
.79
77
78
78
JO
9/27
12:00
429
NA
NA
NA
NA
NA
149
149
147
146
148
7.2
6.9
7.0
6.9
7.2
-1.9
-1.8
-1.7
-2.0
-1.9
69
67
65
64
66
79
79
77
77
78
DATA
11
9/27
14:00
429
NA
NA
NA
NA
NA
149
150
148
146
149
7.2
6.8
7.0
7.0
7.5
-1.9
-1.8
-1.8
-2.0
-1.9
68
66
64
63
65
78
78
76
78
78
J2
10/5
13:45
427
NA
NA
NA
NA
NA
148
148
147
145
149
8.0
6.7
7.3
7.3
7.0
-1.9
-2.0
-1.9
-2.2
-2.0
72
65
60
60
61
83
78
73
74
75
13
10/4
16:00
434
NA
NA
NA
NA
NA
150
149
146
145
149
6.6
6.8
7.3
7.0
7.1
-2.1
-1.9
-1.8
-2.0
-2.0
60
67
66
65
67
69
79
79
79
79
J4
10/5
12:00
422
11A
NA
NA
NA
NA
148
148
147
145
148
8.0
7.0
7.0
7.1
7.3
-2.0
-2.0
-2.1
-2.2
-2.1
71
65
60
60
61
83
77
72
71
73
15
10/4
14:15
429
NA
NA
NA
NA
NA
150
150
146
145
149
6.9
7.0
7.1
7.0
7.4
-2.1
-2.0
-1.9
-2.1
-2.0
60
67
66
65
67
69
80
78
78
79
16
11/3
18:30
427
NA
NA
NA
NA
NA
148
150
147
145
149
7.5
6.9
7.4
7.0
7.1
-2.0
-1.9
-1.8
-2.1
-2.0
67
64
63
62
64
77
76
75
77
77
DECREES
AMPS
AMPS
AMPS
AMPS
PPM
PPM
f
4
t
*f
f
"Ho
+10
+10
+9
+11
0
230
255
435
461
107
400
0.07
0.0
5.12
5.35
5.24
77
20
23.97
+16
+17
+15
+18
0
231
258
475
419
50
408
0.11
0.0
5.51
5.75
5.63
64
38
24.20
+12
+12
+11
+13
0
230
256
477
419
50
400
0.06
0.0
5.20
6.06
5.63
70
30
24.18
-20
-19
-S3
-19
0
207
228
392
385
30
370
0.06
0.0
2.67
4.14
3.40
75
28
24.03
-1
+1
0
0
0
210
233
400
390
40
360
0.07
0.0
3.27
3.50
3.38
73
24
24.00
-23
-19
-23
-20
0
207
228
390
383
10
360
0.11
0.0
2.72
4.10
3.41
72
31
24.05
-1
+1
0
0
0
208
230
396
387
40
358
0.09
0.0
3.45
3.41
3.43
75
26
24.03
+21
+24
+20
+23
0
210
232
398
388
63
373
0.08
0.0
3.41
3.53
3.47
62
22
24.03
285
SHEET B43
-------
UTAH POWER AND LIGHT COMPANY
HUNTINGTON CANYON f2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
OYERFIRE AIR OPERATION STUDY
TEST NO.
DATE
TIME
C LOAD
MILL
C WILL
C MILL
C MILL
C MILL
C MILL
C COAL
C COAL
C COAL
C COAL
C COAL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
B MILL
MILL 2-1
MILL 2-2
MILL 2-3
MILL 2-4
DATA
2-2
2-3
2-4
2-5
AIR TEMP
AIR TEMP
AIR TEMP
AIR TEMP
AIR TEMP. MILL 2-5
2-1 EXH. DISCH.
2-2 EXH. DISCH.
2-3 EXH. DISCH.
2-4 EXH. DISCH.
2-5 EXH. DISCH.
2-1 SUCTION
2-2 SUCTION
2-3 SUCTION
2-4 SUCTION
2-5 SUCTION
2-1 COAL FLOW
2-2 COAL FLOW
2-3 COAL FLOW
2-4 COAL FLOW
2-5 COAL FLOW
2-1 FEEDER SPEED *
2-2 FEEDER SPEED
2-3 FEEDER SPEED
2-4 FEEDER SPEED
2-5 FEEDER SPEED
BOARD AND COMPUTER DATA
LEVEL
BURNER TILT
B POSITION LF
B POSITION LR
B POSITION RF
B POSITION RR
HISCELLANEOUS
B DRUM LEVEL IN. - NORM. H90
C FD FAN 2-1
C FD FAN 2-2
C ID FAN 2-1
C ID FAN 2-2
B FLUE GAS SO IN STACK
8 FLUE GAS NO IN STACK
C FLUE G«s COMBUSTIBLES L
C FLUE GAS COMBUSTIBLES R
C FLUE GAS 0_ L
C FLUE GAS K R
C FLUE GAS 0? AVG.
B AMBIENT TEMP.
B AMBIENT REL. HUMIDITY
B BAROMETRIC PRESS.
B = BOARD DATA
C = COMPUTER DATA
* FEEDER SPEED IN % or CONTROL SIGNAL
1975
Mrt
AMPS
AMPS
AMPS
AMPS
AMPS
°F
°F
°F
°F
°F
"H.O
"(CO
"(CO
"nO
"HfO
"HfO
"H|O
"H!O
"H^O
"iro
10J.B/&?
10ILB/HR
10fLB/HR
10iB/HR
loas/m
*
X
*
%
DEGREES
AMPS
AMPS
AMPS
AMPS
PPM
PPM
*
%
%
I
%
°F
%
"Ho
r?
10/3
22:30
423
NA
NA
NA
NA
NA
148
150
146
145
149
7.3
7.1
7.0
7.0
7.0
-2.1
-2.0
-1.9
-2.1
-2.0
67
65
64
63
65
77
76
75
76
77
0
+1
-2
0
0
207
228
392
385
73
365
0.09
0.0
3.75
3.29
3.52
52
33
24.06
1$.
10/3
30:30
430
NA
NA
NA
NA
NA
149
150
147
145
149
7.5
6.9
7.1
7.0
7.3
-2.0
-2.0
-1.8
-2.1
-1.9
69
67
65
65
66
79
79
78
78
78
+21
+24
+20
+23
0
210
232
395
387
BO
373
0.08
0.0
2.96
3.51
3.24
56
28
24.03
.I9.
10/6
19:00
417
NA
NA
NA
NA
NA
148
148
147
146
149
7.5
6.5
7.3
7.5
7.0
-2.0
-2.0
-1.9
-2.1
-2.1
70
67
66
66
66
80
80
79
79
79
0
+1
0
0
0
204
226
391
385
40
373
0.09
0.0
2.70
3.63
3.16
64
28
23.77
20
10/8
10:30
426
NA
NA
NA
NA
NA
146
148
147
146
148
7.4
6.5
7.0
7.0
7.0
-2.0
-2.0
-2.0
-2.1
-2.0
66
66
64
64
64
77
76
76
75
75
0
+2
0
0
0
208
229
391
387
80
400
0.10
0.0
3.50
3.21
3.36
44
48
23.90
11
10/10
01:45
356
NA
NA
NA
NA
NA
148
147
147
145
145
6.5
6.0
6.5
7.0
6.6
-2.2
-2.3
-2.1
-2.3
-2.3
55
45
56
56
58
63
54
67
68
68
0
+1
-2
0
0
186
199
348
350
NA
400
0.10
0.0
3.11
3.14
3.12
40
55
23.96
22
10/9
01:15
358
NA
NA
NA
NA
NA
149
148
147
91
149
7.5
6.4
7.3
NA
7.0
-2.0
-1.9
-1.8
NA
-1.9
65
69
68
NA
69
74
82
81
NA
81
0
+1
0
0
0
195
211
354
352
183
400
0.10
0.0
2.79
3.73
3.26
34
67
23.98
23
10/12
08:15
253
NA
NA
NA
NA
NA
78
146
146
145
149
NA
6.1
6.3
6.5
6.1
NA
-2.4
-2.4
-2.5
-2.4
NA
52
50
49
50
NA
61
59
59
60
+1
+1
0
0
0
NA
NA
313
313
NA
400
0.10
0.0
3.07
3.50
3.28
49
54
23.66
24
10/5
18:45
266
NA
NA
NA
NA
NA
148
146
94
145
149
6.6
NA
6.5
6.5
6.3
-2.4
NA
-2.3
-2.4
-2.3
55
NA
49
49
50
64
NA
58
59
60
0
0
0
0
0
168
177
322
316
40
368
0.08
0.0
3.63
4.07
3.85
64
27
23.96
286
SHEET B44
-------
Utah Power & Light Company C-E Power Systems
Huntington Canyon #2 Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
BASELINE TEST
Probe Probe Coupon
Loc. No. No.
1 3 1
2
3
4
2 I 1
2
3
4
•
3 4 1
2
3
4
4 X 1
2
3
4
5 Z 1
2
3
4
Initial Wt.
9
192.6190
193.4064
192.9291
193.5940
198.8883
201.0329
198.0410
195.5068
192.7191
194.8814
193.0414
191.3704
191.5552
192.4223
193.2662
193.4873
193.6625
191.0583
192.9096
192.5761
Final Wt.
g
192.2669
193.0755
192.7393
193.5159
198.6551
200.8816
197.9497
195.4417
192.5353
194.6926
192.9217
191.2839
191.3449
192.2041
193.1064
193.3807
193.3771
190.8201
192.7892
192.5329
Wt. Loss
9
.3521
.3309
.1898
.0781
.2332
.1513
.0913
.0651
.1838
.1888
.1197
.0865
.2103
.2182
.1598
.1066
.2854
.2382
.1204
.0432
Wt. Loss/
Coupon
mg/cmz
6.9809
6.5605
3.7630
1.5484
4.6235
2.9997
1.8101
1 .2907
3.6441
3.7432
2.3732
1.7150
4.1695
4.3261
3.1683
2.1135
5.6584
4.7226
2.3871
.8565
Avg. Wt. Loss/
Probe
mg/cmz
4.7132
2.6810
2.8689
3.4444
3.4062
Avg. Wt. Loss/Test 3.4266 mg/cm2
287 SHEET B45
-------
Utah Power & Light Company C-E Power Systems
Huntington Canyon #2 Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
OVERFIRE AIR TEST
Probe Probe Coupon
Loc. No. No.
1 1 1
2
3
4
2 5 1
2
3
4
3 V 1
2
3
4
4 U 1
2
3
4
5 L 1
2
3
4
Initial Wt.
a
191.9684
192.4812
192.9861
191.5205
193.4934
193.3895
193.2459
192.2109
193.8941
192.2687
193.1048
194.6248
192.0607
191.8937
191.6559
192.3558
202.3430
200.5759
202.4755
197.4743
Final Wt.
a
191.8866
192.3816
192.9142
191.4367
193.3406
193.1540
193.0711
192.0909
193.7867
192.1525
193.0082
194.5362
191.9105
191.7479
191.5016
192.1947
202.1440
200.4172
202.3190
197.3718
Wt. Loss
q
.0818
.0996
.0719
.0838
.1528
.2355
.1748
.1200
.1074
.1162
.0966
.0886
.1502
.1458
.1542
.1611
.1990
.1587
.1565
.1025
Wt. Loss/
Coupon
nig/an^
1.6218
1.9747
1 .4255
1.6614
3.0294
4.6691
3.4656
2.3791
2.1293
2.3038
1.9152
1 .7589
2.9818
2.8945
3.0613
3.1982
3.9506
3.1506
3.1069
2.0349
Avg. Wt. Loss/
Probe
mg/cm2
1 .6709
3.3858
2.0268
3.0340
3.0608
Avg. Wt. Loss/Test 2.6357 mg/cm2
288 SHEET B46
-------
APPENDIX C
TEST DATA & RESULTS
FOR
ALABAMA POWER COMPANY
BARRY STATION
UNIT #2
-------
ALABIMA POWER COMPANY
BARRY |2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
NOX TEST DATA SUMMARY
BASELINE STUDY BEFORE MODIFICATION
TEST NO.
10
11
12
13
14
PURPOSE or TEST
DATE
LOAD
MAIN STEAM FLOW
4 CLEAN FURNACE
EXCESS AIR ECON. OUTLET
THEO. AIR TO FUEL
FlRINQ ZOME
FUEL ELEVATIONS IN SERVICE
FUEL NOZZLE TILT
1973
MM
KQ/S
rf
DEO
•- /\ AUX
wo ~"~
p P
S tO 2 "
4 £ 6. ^>
u E
rf 5 "
a V
V FUEL
AUX
3" FUEL
< AUX/AUX
I FUEL
AUX
3" FUEL
/ AUX
SHO TEMPERATURE
RHO TEMPERATURE
UNIT EFFICIENCY
GAS Wr. ENT. A.M.
N0x
S
CO2
CO
HC
CXRBON Loss IN FLYASH
•c
•c
KQ/S
PPM-0* 0
NO/3
PPM-0* 0.
NO/3
PPM-0* 0
NO/3
PPM-0* 0
?! AH in
!( AH OUT
— - *
•*
11/30
£6
61
35.5
130.6
ABC
+3
20
30
20
30
20/20
30
20
0
0
529
488
88.3
97.8
631
319.3
2298
1617.0
24
7.5
0.144
5.6
7.3
0.29
1/2 LOAD —
11/30
65
62
17.5
117.1
ABC
+7
0
30
0
30
20/10
30
10
0
n
498
446
88.2
100.0
489
246.0
2318
1622.7
142
43.5
0.160
3.2
5.6
0.97
fc-
11/30
67
59
58.9
151.3
ABC
+3
50
30
50
30
50/50
30
50
0
0
548
517
87.6
114.4
718
362.8
1644
1156.3
8
24.8
0.0
7.9
9.1
0.17
3/4
1/18/74
93
88
12.6
109,2
ABC
+B
30
20
60
20
80/80
20
50
0
0
500
499
89.3
107.2
429
214.0
1635
1139.1
39
11.9
0.0
2.4
5.1
0.9G
•«
11/14
124
112
22.7
117.9
ALL
+3
60
20
100
SO
100/100
20
100
20
100
539
514
89.0
153.9
494
248.6
1641
1150.0
31
9.6
0.509
4.0
6.2
0.48
11/26
123
113
11.7
107.2
ALL
0
100
30
100
30
100/100
30
100
30
100
539
524
89.1
160.6
357
181.8
1434
1016.1
153
47.3
0.0
2.3
4.6
0.57
AV.LOO «IH
fr.
FULL
11/28
123
112
30.8
125.3
ALL
0
100
100
100/100
30
100
v\
JO
100
538
524
89.5
164.4
664
335.1
1455
1021.8
33
10.1
0.0
5.0
6.9
0.20
v«n i « 1 1 \m •
4— MOD.
LOAD
11/15
126
114
21.5
116.9
ALL
48
60
100
100/100
30
100
in
oU
100
548
533
89.6
157.5
421
P13.5
1171
825.9
46
14.1
0.61
3.8
5.3
0.16
DIRTY FURN
11/19
122
112
13.0
108.5
ALL
-22
100
100
100/100
30
100
on
Jv
533
510
89.6
139.4
361
178.6
2052
1414.4
432
130.2
0.128
2.5
4.6
0.27
. „
*
11/19
124
112
26.0
120.8
ALL
-22
too
100
30
100/100
30
100
TO
O"J
100
544
531
89.6
156.9
set
286.1
2179
1493.0
5
1.6
1.54
4.4
6.6
0.05
•*• 1/2
12/5
66
59
32.7
128.0
ABC
0
20
•an
JU
20
30
20/20
30
20
0
518
476
88.3
89.7
2348
1629.2
298
90.3
0.0
5.3
7.0
0.58
DIRTY FURNACE p.
LOAD-*.
12/4
74
57
51.2
144.1
ABC
0
50
•an
JU
50
50/50
30
50
0
548
508
87.9
1O2.5
658
327.2
2164
1496.8
220
66.9
0.0
7.2
8.6
0.20
-•-FULL
11/16
125
114
20.7
115.7
ALL
-22
100
100
100/100
30
100
100
539
522
89.2
154.4
499
247.7
1917
1322.7
41
12.4
0.513
3.7
6.0
0.17
LOAD — *•
11/16
125
113
24.3
119.2
ALL
-22
100
TO
^J
100
30
100/100
30
100
30
100
543
529
89.3
157.5
586
292. 6
1370
951.8
34
10.3
0.397
4.2
6.4
0.10
-------
ALABAMA POWER COMPANY
BARKY Is
C-E POWER SYSTEMS
FIELD TESTINB AND
PERFORMANCE RESULTS
NOXTEST DATA SUMMARY
BIASED FIRING STUDY
TEST NO.
PURPOSE or TEST
DATE
LOAD
MAIN STEAM FLOW
EXCESS AIR ECON. OUT
THEO. AIR TO FUEL FIRING
FUEL ELEVATIONS IN SERVICE
FUEL NOZZLE TILT
DEO
/\
"A"
"B"
_^<|
"C"
"0"
V
AUX
FUEL
AUX
FUEL
AUX/AUX
FUEL
AUX
FUEL
AUX
SHO TEMPERATURE
RHO TEMPERATURE
UNIT ErriciENCv
GAS WT. ENTERING AH
NO
NO£
SO?
so?
CO2
CO
HC
CARBON Loss IN FLYASH
'C
•C
KG/S
PPM-0* 0
NO/3
PPM-0* 0
ua/5
PPM-0* 0
NO/5
PPM-0* 0
% AH IB
% All OUT
.15
1/2
•/ c
1/19/74
66
55
50.1
105.8
ABC
-9
50
20
50
20
50/50
20
50
100
100
546
496
87. 9
94.7
594
268. 0
1721
1161.0
33
9.B
0.0
7.1
B.5
0.32
J6J7_18Jj)202J[2223
D 1 A^tTr\ r »n i iirv * r-i n-i r-i rn s*i IT nr «»i-r»i» i ft- A i n fNAttnr*n0 xw^fti
24
•>3f •»
1/18/74
96
82
26.7
121.7
ABC
0
50
20
50
20
50/50
20
50
100
100
539
506
89. 3
119.4
543
272.8
1682
1175.6
29
8.9
0.0
4.5
7.2
0.34
12/3/73
100
87
81.1
116.5
ABC
-15
50
30
50
30
50/50
30
50
100
100
529
501
69.1
1S1.9
397
200.6
2422
1704.6
46
14.0
0.0
3.7
6.1
0.46
12/4/73 12/5/73
103
89
22.2
117.5
ABD
-15
50
30
50
30
50/100
100
50
30
50
543
520
89.3
126.4
373
189.2
2553
1799.9
38
11.9
0.012
3.9
5.8
0.37
99
89
21.8
117.2
ACD
-10
50
30
100
100
50/50
30
50
30
50
523
486
08.9
118.9
387
189.9
2292
1562. B
35
10.6
0.012
3.8
6.3
0.42
18/6/73
102
87
24.2
94.7
BCD
-5
100
100
50
30
50/50
30
50
30
50
544
515
88.8
125.3
285
143.1
2277
1591.0
27
8.1
0.0
4.3
7.3
0.25
w •*
1/18/74
94
86
29.0
97.3
BCD
+10
100
100
50
20
50/50
20
•50
20
50
512
469
89.6
120. B
331
166.2
1566
1093.4
31
9.5
0.0
4.8
8.4
0.30
1/19/74
64
58
48.0
112.5
BCD
0
100
100
50
20
50/50
20
50
20
50
501
448
87.8
100.0
520
268.5
1861
1335.9
29
9.1
0.0
6.9
8.4
0.20
1/19/74
64
59
47.0
141.4
ACD
0
50
20
100
100
50/50
20
50
20
50
507
454
87.9
100.3
4B5
249.1
2245
1602.7
22
7.0
0.0
6.B
8.6
0.11
1/19/74
66
56
47.0
141.3
ABD
-15
50
20
50
20
50/100
100
50
20
50
544
513
87.7
98.9
609
306.2
1807
1263.0
28
8.4
0.0
6.8
6.9
0.21
-------
ALABAMA POWER COMPANY
BARRY |2
NOXTEST DATA SUMMARY
BASELINE STUDY AFTER MODIFICATION
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
TEST NO.
10
11
PURPOSE or TEST
DATE
LOAD
MAIN STEAM FLOW
EXCESS AIR ECON. OUTLET
THEO. AIR TO FUEL
FIRINO ZONE
MW
KG/SEC
I
i
•FUEL £LEV. IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
c
t
.§ 7
g — gj
W TT
rfncw. >
siti c
5
O "C
X.
SHO TEMPERATURE
RHO TEMPERATURE
UNIT EFFICIENCY
~1 OFA
~ OFA
^ AUX
" FUEL
AUX
I" FUEL
<. AUX/AUX
* FUEL
AUX
11 FUEL
S AUX
GAS Wr. ENT. AIR HTR.
HO.
NO*
sf
CO2
CO
HC
Of
CXRBON Loss IN FLY ASH
DEC
DEC
•c
"C
*
KG/SEC
PPM-0* 0,,
NG/3
PPM-Oi 0
uo/3
ppM-og o.
NO/3
PPM-0* 0
/AH IS
AH -OUT
*
6/85/74
68
61
33.5
187.1
ABC
0
3
0
0
80
30
80
30
80/20
30
80
0
0
492
435
88.4
93
444
881.9
3678
856.0
88
8.4
0.0
5.4
7.4
0.89
EXCESS AIR VARIATION
1/8 LOAD •» 3/4
6/25/74
68
59
16.0
113.4
ABC
0
6
0
0
0
30
0
30
10/10
30
10
0
0
468
402
88.8
75
335
167.4
3621
252.0
376
114.4
0.0
3.0
5.5
0.83
6/85/74
64
60
64.7
155.4
ABC
0
-14
0
0
50
30
50
30
50/50
30
50
0
0
536
499
87.4
115
640
319.8
8611
181.7
35
10.6
0.0
8.4
9.7
1.06
6/27/74
92
87
15.5
111.0
ABC
0
2
0
0
30
80
60
80
80/80
20
50
0
0
504
466
89.8
111
327
163.4
8634
183.3
110
33.4
0.0
8.9
5.5
0.11
CLEAN TURN
6/19/74
131
185
21.0
115.3
ALL
0
-13
0
0
80
30
100
30
100/100
30
1OO
30
100
528
488
88.4
165
404
202.1
2251
156.7
86
8.0
0.0
3.7
7.4
0.75
6/27/74
127
188
18.4
107.1
ALL
0
-3
0
0
100
30
100
30
100/100
30
100
30
100
584
487
89.2
152
330
165.3
2677
186.3
127
38.7
0.0
2.4
5.8
0.51
6/87/74
185
117
85.4
119.5
ALL
0
-22
0
0
100
35
100
35
100/100
35
100
35
100
518
480
89.5
155
477
838.8
2707
188.4
22
6.6
0.0
4.3
7.0
0.74
-_ FA VAD
^r" LA VPK,
i A*n
6/80/74
130
188
17.8
118.3
ALL
0
-81
0
0
80
30
100
30
100/100
30
100
30
100
526
486
89.0
157
470
235.3
1941
135.1
24
7.4
0.0
3.2
6.8
0.22
kjrus
- HUU.
6/80/74
189
184
18.1
106.9
ALL
0
-17
0
0
80
30
100
30
100/100
30
100
30
100
528
483
88.9
151
334
167.0
2488
178.7
97
89.6
0.0
8.3
6.2
0.48
IMOTV fc^_
UIKI T-^
6/88/74
185
119
26.6
120.5
ALL
0
-16
0
0
100
30
100
30
100/100
30
100
30
100
524
480
89.5
162
431
215.4
8500
174.0
84
7.2
0.0
4.5
7.5
0.61
~~
__
—
4 EA VflK. - DIRTY FURN.
«• 1/2 LOAD-* -4- MAX
6/26/74
65
68
30.9
124.6
ABC
0
-16
0
0
20
30
20
30
/
80/80
30
20
0
0
507
457
89.3
101
373
186. 8
8558
178.0
26
8.0
0.0
5.0
7.6
0.17
6/86/74
68
61
63.1
154.0
ABC
0
-16
0
0
50
30
50
30
50/50
30
50
0
0
531
498
88.0
116
686
318.9
8461
171.3
84
7.3
0.0
8.2
10.8
0.05
6/88/74
126
120
28.0
116.8
ALL
0
-6
0
0
100
30
100
30
100/100
30
100
30
100
524
496
89.0
160
391
195.6
2564
178.4
83
7.1
0.0
3.9
7.3
0.36
1 f
LOAD-*-
6/28/74
125
118
25.9
119.9
ALL
0
-6
0
0
100
30
100
30
100/100
30
100
30
100
589
499
89.4
168
431
815.4
8689
183.0
83
7.0
0.0
4.4
7.2
0.25
-------
ALABAMA POWER COMPANY
BARRY 12
NOX TEST DATA SUMMARY
OFA LOCATION, RATE AND VELOCITY VARIATION
C-E POWER SYSTEMS
FIELD TESTING .AND
PERFORMANCE RESULTS
. TEST NO.
PURPOSE or TEST
DATE
LOAD
MAIN STEAM FLOW
EXCESS AIR ECON. OUT
THEO. AIR TO FUEL FIRING ZONE
FUEL ELEVATIONS IN SERVICE
OFA NOZZLE TILT
FUEL NOZZLE TILT
23
w
"A"
"B"
i^^f\
"C"
"0"
XT'
OFA
OFA
FUEL
AUX
FUEL
AUX/AUX
FUEL
AUX
FUEL
AUX
SHO TEMPERATURE
RHO TEMPERATURE
UNIT EFFICIENCY
GAS WT. ENT. AH
NO
NO*
SO*
50°
CO2
CO
HC
CARBON Loss IN FLY ASH
7/10/74
MM
KG/SEC
%
$
DEO
DEO
"C
"C '
£
KG/SEC
PPM-0* 0.
NG/3
PPM-Og 0
uo/3
PPM-0* 0
NO/3
PPM-0* 0
f AH I ft
% AH OUT
%
97
93
28.5
114.5
BCD
0
-5
0
0
0
0
50
30
50/50
30
50
30
50
518
457
90.0
127
345
178.7
1892
ni.6
28
8.6
0.0
4.7
6.5
0.51
7/10/74
9B
94
27.1
96.7
BCD
0
-5
100
0
0
0
50
30
50/50
30
50
30
50
510
452
• 89.8
124
254
127.3
1973
137.3
30
9.1
O.O
4.6
6.5
0.59
7/10/74
100
94
25.6
95.8
BCD
0
-5
0
100
0
0
50
30
50/50
30
50
30
50
514
457
89.7
123
254
127.3
2092
145.6
32
9.9
0.0
1.H
6.1
O.63
7/12/74
too
96
26.6
84.8
BCD
0
-4
too
100
0
0
50
30
50/50
30
50
30
50
524
476
89.6
129
229
114.4
2391
166.8
48
14.6
0.0
4.5
6.3
0.54
7/11/74
100
94
24.8
89.3
BCD
0
.4
50
50
0
0
50
30
50/50
30
50
30
50
521
486
89.3
130
232
116.1
2684
186.8
39
11.9
0.0
4.3
6.1
0.32
7/11/74
100
96
25.4
100.5
BCD
0
-4
0
0
100
0
50
30
50/50
30
50
30
50
524
479
90.2
130
323
161.7
1821
126.8
29
8.8
0.0
4.3
6.1
0.49
7/12/74
102
95
25.4
117.4
ABC
0
-4
0
0
100
too
50
30
50/50
30
50
0
0
532
498
90.1
132
483
P4t.7
1814
126.2
25
7.7
0.0
4.3
6.1
0.46
7/12/74
102
95
27.9
90.4
ABC
0
-4
too
too
too
100
50
30
50/50
30
50
0
0
524
491
89.0
137
329
164.6
2259
157.2
26
7.8
0.0
4.7
6.5
0.54
»•
7/12/74
102
96
28.1
96.9
ABC
0
-4
50
50
50
50
50
30
50/50
30
50
0
0
521
485
89.1
137
336
168.1
2417
168.2
25
7.7
0.0
4.7
6.7
0.60
-------
ALABAMA POWER COMPANY
BARRY JS
NOJEST DATA SUMMARY
OFA TILT AND LOAD VARIATION
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
X
n
8
TEST NO.
PURPOSE or TEST
DATE
LOAD
MAIN STEAM FLOW
Excess AIR ECON.
84
•4
85
— OFA t
86
FUEL NOZZLE
87
28
29
TILT VARIATION b
OUT
MM
KG/S
%
THCO. AIR TO FUEL FIRING ZONE %
FUEL ELEVATIONS
OFA NOZZLE TILT
FUEL NOZZLE TILT
r
U| X *
f- —
5 — z ~
^§85 ^
ui D
M 3!
Kl ^
82
SHO TEMPERATURE
RHO TEMPERATURE
UNIT EFFICIENCY
GAS Wr. ENTERING
NO
NO*
so*
so!
CO8
CO
HC
o|
N SERVICE
1 OFA
1 OFA
^~ AUX
'A1*! FUEL
1 AUX
"5"! FUEL
>^ AUX/AUX
'CT FUEL
AUX
•b" FUEL
^S AUX
AH
CARBON Loss IN FLY ASH
DEC
DEO
•c
•c
f
KG/S
PPM-0^ 0
NG/3
ppM-o* o-
PPM-Og 0,
NG/3
PPM-Og 0
% AM in
% AH OUT
7/29/74
124
113
25.9
94.2
ALL
0
-5
100
100
100
100
50
30
50/50
30
50
30
50
538
532
89.6
152
339
169.6
2450
170.5
25
7.7
0.0
4.4
5.9
0.37
7/39/74
124
116
23.7
92.4
ALL
n
-23
100
100
100
100
50
30
50/50
30
50
30
50
521
508
89.3
157
290
14-5.5
2920
203.3
27
8.3
0.0
4.1
6.0
0.37
7/89/74
124
114
25.1
93.2
ALL
0
+19
100
100
100
100
50
30
50/50
30
50
30
50
524
527
88.9
163
368
183.9
3310
230.4
32
9.7
0.0
4.3
6.2
0.40
7/29/74
125
113
22.3
94.5
ALL
-30
-5
100
100
too
100
50
x30
50/50
30
50
30
50
527
533
89.3
155
344
172.2
3160
219.9
22
6.7
0.0
3.9
6.0
0.29
7/29/74
125
115
20.2
89.6
ALL
-30
+22
100
100
100
100
50
30
50/50
30
50
30
50
524
535
88.6
163
404
202.1
3370
234.5
28
8.6
0.0
3.6
5.8
0.29
7/29/74
124
116
23.7
92.6
ALL
+30
-21
100
100
100
100
50
30
50/50
30
50
30
50
521
505
89.4
151
285
142.4
3240
2S5.5
49
15.0
0.0
4.1
6.4
0.49
30
MAX
7/30/74
125
116
21.6
90.7
ALL
0
-4
100
100
100
100
50
30
50/50
30
50
30
50
538
536
89.0
159
339
169.6
1680
116.9
26
8.0
0.0
3.8
5.3
0.61
31
38
3/4 1/2
7/31/74
97
87
85.2
89.4
ABC
-12
-16
100
100
100
100
50
30
50/50
30
50
0
0
525
514
89.1
127
338
169.1
1730
120.5
26
8.0
0.0
4.3
5.7
0.39
7/31/74
65
57
46.9
88.5
AB
0
-5
100
100
100
100
50
30
50/0
0
0
0
0
535
514
89.2
95
396
197.8
1740
121.1
24
7.4
0.0
6.8
8.2
0.32
33
OPTIMUM
MAX
7/31/74
122
114
27.4
94.6
ALL
-22
-22
100
100
100
100
50
30
50/50
30
50
30
50
521
521
89.0
162
333
166.5
2430
169.2
25
7.5
0.0
4.6
6.3
0.24
34
/•/Mir*
7/31/74
95
86
27.4
90.6
ABC
-22
-22
100
100
100
100
50
30
50/50
30
50
0
0
506
493
88. 2
131
291
145.2
2490
173.3
26
8.0
0.0
4.6
6.8
0.33
35
I/*
8/1/74
64
57
45.9
88.5
AB
-10
-15
100
100
100
100
50
30
50/50
0
0
0
0
512
493
89.0
91
313
156.4
2420
166.2
25
7.6
0.0
6.7
8.4
0.15
-------
ALABAMA POWER Co.
BARRY #2
C-E POWER SYSTEMS
FIELD TESTING AND
PERFORMANCE RESULTS
N>
\0
Ul
WATERWALL ABSORPTION RATES, KG-CAL/HR
RIGHT WALL CENTERLIME TUBE RATES
-CM2
r>
ON
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
1
11 8' -6"
2.02
2. 35
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
9.65
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
35 '-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
25 '-7"
__ _
_ »
_«
__ <_
— _-
—-_
___
__-.
___
•_•
___
-__
—
—
—
—
—
—
—
—
—
—
—
-------
EF CO,
C-F. POWER Sv STEMS
FIELD TESTING AND
PFPFORMANCE RESULTS
ro
\o
V)
m
WATERWALL ABSORPTION RATES, KG-CAL/HR-CM2
FRONT WALL CENTERLINE TUBE RATES
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
B.18
B.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
5.68
3.20
38 51
59' -7" 49' -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-
ro
RIGHT WALL
HORIZONTAL AVERAGE
TUBE RATES
CO
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
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
.07
.52
.42
.51
6.28
6.04
9.74
9.61
.53
,14
9.21
12.18
12.01
10.85
8.53
10.44
9.11
9.05
6.
7.
6.
5.
7.
8.
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
14.16
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
WATERWALL CORROSION COUPON
DATA SUMMARY
WEIGHT LOSS EVALUATION
Coupon
No.
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
Avg. Wt. Loss/Test 2.6381 MG/CM*
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/
Coupon
HG/CM*
3.1643
3.4418
2.9719
2.1789
2.8609
3.5647
2.8213
1.9885
2.9541
2.6507
1.6852
1.249
3838
1769
282
1.8359
3.874
3.4299
2.8609
Avg. Wt. Loss/
Probe
MG/Cir
2.9392
2.8088
2.13475
1.91965
3.38826
298
SHEET C9
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
Probe
No.
B
WATERWALL CORROSION COUPON
DATA SUMMARY
Coupon
No.
1
2
3
4
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
WEIGHT LOSS EVALUATION
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/CET
6.0411
5.9499
5.9678
5.5593
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/crr
5.8795
4.3777
3.4081
3.8201
5.7289
3.9078
Avg. Wt. Loss/Test 4.6429 MG/CtT
299
SHEET CIO
-------
Alabama Power Company
Barry #2
C-E Power Systems
Field Testing and
Performance Results
WATERWALL CORROSION COUPON
DATA SUMMARY
Coupon
No.
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
1
2
3
4
WEIGHT LOSS EVALUATION
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/ChT
4.3876
5.0815
5.1235
3.5053
5.5554
3.3540
3.3540
3.3540
5.4344
6.1958
6.4654
6.0649
4292
8872
8729
2.8729
4.0525
3.8979
Avg. Wt. Loss/
Probe
MG/CfT
4.5244
3.9044
6.0401
3.7656
3.9752
Avg. Wt. Loss/Test 4.4419 HG/CM2
300
SHEET Cll
-------
APPENDIX D
COMPFLOW
WINDBOX COMPARTMENT AIR FLOW
DISTRIBUTION COMPUTER PROGRAM
-------
APPENDIX D
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.
'x
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
Loss a# (Velocity) .
Utilizing these assumptions, it follows that
2 * [^X "
- K(I)
2
- const.
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"
302
-------
Equation (1) yields
Q(I) A(I)/v/K(T)
M = M
1=1 1=1
By definition
" =
(2)
Using Equations (1) and (3), we have
PT PT (I) PT
2 * C TX " Ty ] = 2 *[ TX -
nm 2
y] - [SUl] = [K(I) - 1]
Hu;
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.,
2 *
PT PT (I)
X " Ty ] = [KD(I) +
Kgo(I) + 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.
COMMENT
Typical t£ = 45
LOSS
Miter bend, K^ (I)
90° bend, Kg0(I)
Friction, Kf(I)
Nozzle, KN(I)
Damper, KD(!)
Using the above values, Equations (4) and (5) yield
2
VALUE
0.3
1.2
0.1
0
Figure 1
; Kf = f{j
f » 0.02, j-
- 1; Assume C = 1
Assumed to include inlet loss
REFERENCE
2
2
2
3
4
(6)
303
-------
For coal fired units the mill air must be taken into account. Using
Equation (2) for the secondary air flow, it follows that
* Wl + X(I) * W2
(7)
Wl + WZ 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
304
-------
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
305
-------
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
K(I) 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
Kp, 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/100%
2
from Equation (6), K/100%«* 1 + 1.7 *
2
for existing geometries, 0<[] < 0.29
therefore, with KO ^ K/100%, 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.
306
-------
5. N. D. Brown, "VMndbox Compartment Flow Tests," Test Report 72-6
Project No. 412003. March 2, 1972.
307
-------
DAMPER LOSS COEFFICIENT
VS.
POSITION
_ 2(P - P
% Open = (6/90) x 100
(Q/Ar
PT1 = Total Pressure @ "1"
PT2 = Total Pressure @ "2"
R = Fluid Density
Q = Volume Pate of Flnw
A = Flow Area
(J)
i
-if-
*7??
1 Blade
2 Blades
3 Blades
20
40 60
DAMPER POSITION - % OPEN
308
80
100
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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)
.44
.55
18.03
6.55
.44
.44
.55
18.03
6.55
9.44
9.
6.
9.
9.
6.
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
3.64
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)
9.44
6.55
18.03
6.55
9.44
9.44
6.55
18.03
6.55
9.44
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
309
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COMPFLOW
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 Ab?)g Burner Zone)(100 + % Excess Air)
to Burner Zone.
310
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COMPARTMENT LOSS COEFFICIENT
VS.
DAMPER POSITION
2(s
2
TX = Total Pressure @ "x"
sy = Static Pressure 9 "y"
R = Fluid Density
Q = Volume Rate of Flow
A = Nozzle Exit Area
— - 0 534 - Nozzle Exit Area
B v-™1* - compart. Inlet Area
25
20
15
10
K= 1 + (1.6+KD) x
LEGEND
SYMBOL
O
D
A/B
0.322
0.136
20
40
60
80
100
DAMPER POSITION - % OPEN
311
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TECHNICAL REPORT DATA
(Please read iHttrueiioiis on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-117
. RECIPIENT'S ACCESSION NO.
4. T.TLE AND SUBTITLE Overfire Air Technology for Tangen-
tially Fired Utility Boilers Burning Western U.S. Coal
REPORT DATE
October 1977
PERFORMING ORGANIZATION CODE
7.AUTHOR.S) Richard L Burrington, John D. Cavers,
and Ambrose P. Selker
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
C-E Power Systems
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor. Connecticut 06095
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-1486
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 6/74-3/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES !ERL_RTp project officer for this report is David G. Lachapelle,
Mail Drop 65, 919/541-2236.
&•
is. ABSTRACT Tne report gives results of an in yes tigation and evaluation of the effective-
ness of overfire air in reducing NOx emissions from tangentially fired boilers burning
Western U.S. coal. Results are compared with those obtained during phase n, 'Pro-
gram for Reduction of NOx from Tangentially Coal Fired Boilers,' EPA contract 68-
02-1367. Both programs investigated the effect that variations in excess air, unit slag-
ging, load, and overfire air had on unit performance and emissions. The effect of
(biasing combustion air through various out-of-service fuel nozzle elevations was also
(investigated. The effect of overfire air operation on waterwall corrosion potential was
evaluated during 30-day baseline and overfire air corrosion coupon tests. Overfire
air operation for low NOx optimization did not significantly increase corrosion coupon
degradation. Overfire air operation and reductions in excess air levels were effective
in reducing NOx emissions. NOx reductions of 20-30% were obtained when operating
with 15-20% overfire air. These reductions occurred with the boilers operating at a
total unit excess air of about 15-25%% measured at the economizer outlet. Unit loading
exhibited a minimal effect on NOx emissions. Waterwall slag conditions had wide and
inconsistent effects on NOx emission levels.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Flold/GtOUp
,ir Pollution
fitrogen Oxides
lombustion Control
Boilers
Utilities
Air Pollution Control
Stationary Sources
NOx Reduction
Tangential Firing
Combustion Modification
Overfire Air
13B
07B
21B
21D
13A
8. DISTRIBUTION STATEMfcNT
Unlimited
19. SECURITY CLASS (Tint Keport)
Unclassified
21. NO. OF PAGES
327
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
312
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