U.S. Environmental Protection Agency Industrial Environmental Research
Office of Research and Development Laboratory
Research Triangle Park, North Carolina 27711
EPA-600/7'77-137
WET/DRY COOLING SYSTEMS
FOR FOSSIL-FUELED POWER
PLANTS: WATER CONSERVATION
AND PLUME ABATEMENT
Interagency
Energy-Environment
Research and Development
Program Report
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EPA-600/7-77-137
November 1977
WET/DRY COOLING SYSTEMS
FOR FOSSIL-FUELED POWER PLANTS:
WATER CONSERVATION
AND PLUME ABATEMENT
by
M.C. Hu and G.A. Englesson
United Engineers and Constructors, Inc.
30 South 17th Street
Philadelphia, Pennsylvania 19101
Contract No. 68-03-2202
Program Element No. EHE624
EPA Project Officer: Theodore G. Brna
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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ABSTRACT
The technical and economic feasibilities of wet/dry cooling towers for water
conservation and vapor plume abatement are studied. Results of cost optimi-
zations of wet/dry cooling for 1000-MWe fossil-fueled power plants are pre-
sented. Six sites (five in the western coal region and one in New York) are
evaluated for water conservation, and four urban sites (Seattle, Cleveland,
Newark, and Charlotte) are used in the plume abatement analyses.
Results are given as the total evaluated cost (TEC) of the cooling system.
Separate cost components include initial capital cost, operating expenses
and penalties for the cooling system operation capitalized over a plant life
of forty years. The plant start-up date is 1985.
For the water conservation analyses, optimized wet and dry cooling towers
are the reference systems. The wet/dry system has separated wet and dry
mechanical draft towers. Costs are related to the make-up water requirement
expressed as a percentage of the water required by a wet system. Parametric
and sensitivity analyses show the effect of changing the system design and
economic factors.
A parallel air-flow hybrid wet/dry tower is used in the plume abatement
studies. Costs are presented for an allowable number of hours of fogging.
A wet system, optimized solely for cost, serves as the reference.
ii
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CONTENTS
Abstract ji
Tables t Vl
Figures JX
Acknowledgments XX
1. Introduction 1
Purpose 1
Background 1
Report Organization. 3
2. Summary and Conclusions 6
Summary 6
Conclusions 7
3. System Description and Method of Economic Evaluation 8
Characteristics of the Reference Power Plant 8
Cooling Tower Configurations 8
Wet and Dry Towers 8
Wet/Dry Cooling Towers for Water Conservation 9
Design and Operation of Series Flow
Wet/Dry Systems 9
Design and Operation of Parallel Flow
Wet/Dry Systems * H
Wet/Dry Cooling Towers for Plume Abatement 11
Method of Economic Evaluation 12
Economic Penalty Evaluation 13
Capacity and Energy Penalties 13
Cooling System Make-up Water Cost Penalty 15
Cooling System Maintenance Cost Penalty 15
Total Evaluated Costs 16
Optimization Procedure '. 16
4. Results of Optimization of Wet/Dry Towers for Water
Conservation 26
Introduction 26
Site Location 26
Method of Optimization 27
Optimized Systems at Selected Sites... 27
Results for Kaiparowits 28
Plant Performance 28
Variation in Water Usage 29
Site Comparisons 30
Comparison Including Water Supply Costs 30
Comparison Excluding Water Supply Costs 30
5. Engineering Evaluation and Economic Sensitivity Analysis of
Wet/Dry Cooling Systems for Water Conservation 57
iii
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Introduction 57
Evaluation of System Configuration and Operating Mode..... 57
Operating Mode • 57
Mechanical Series vs. Mechanical Parallel 58
Mechanical Series vs. Natural Series 58
Comparison of the Three Types of Wet/Dry Cooling
Systems 59
Economic Sensitivity Analysis 59
Results of Economic Sensitivity Analysis 60
Conclusion of Economic Sensitivity Analysis 61
6. Mathematical Model for Plume Abatement Analysis 83
Introduction •« 83
Plume Rise and Dispersion 83
Plume Rise 83
Length and Spread of the Visible Plume 85
Criteria for Ground Level Fogging 88
Meteorological Data Base for Plume Abatement Analysis 88
Fogging During Aerodynamic Downwash 90
7. Economic Optimization of Wet/Dry Towers for Plume Abatement.... 92
Introduction 92
Design and Optimization of Wet/Dry Towers for Plume
Abatement 92
Optimization Results for Plume Abatement Tower Systems.... 93
Optimization Results for Seattle Site 93
Mechanical Draft Wet Towers 93
Mechanical Draft Wet/Dry Towers 94
Optimization Results for Cleveland Site 94
Optimization Results for Newark Site 95
Optimization Results for Charlotte Site 95
Psychometric Discussion. 96
Plume Abatement Conclusions 96
References 114
Appendices
A. Major Equipment List 116
B. Assessment of Economic Factors 118
C. Plume Abatement Sites 120
D. Raw Water Quality for the Various Sites and Water Treatment
Analysis for Kaiparowits, Utah 121
E. Description of Codes of Accounts for Capital Cost Elements 124
F. Kaiparowits, Utah - Reference and Mechanical Series Wet/Dry
Cooling Sys terns 127
G. Kaiparowits, Utah - Mechanical Series Wet/Dry Cooling
Systems: S2 Mode 145
H. Kaiparowits, Utah - Mechanical Parallel Wet/Dry Cooling
Systems : Pi Mode 151
I. Kaiparowits, Utah - Natural Series Wet/Dry Cooling Systems:
Si Mode 157
J. San Juan, New Mexico - Reference and Mechanical Series Wet/Dry
Cooling Systems. 163
K. Colstrip, Montana - Reference and Mechanical Series Wet/Dry
Cooling Systems 174
iv
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L. Young, North Dakota - Reference and Mechanical Series Wet/Dry
Cooling Systems 135
M. Rock Springs, Wyoming - Reference and Mechanical Series
Wet/Dry Cooling Systems 196
N. New Hampton, New York - Reference and Mechanical Series
Wet/Dry Cooling Systems 207
0. Site Comparisons 218
P. Mechanical Wet and Hybrid Wet/Dry Cooling Systems for Plume
Abatement 241
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TABLES
Number Page
4.1 Major Economic and Site Data 32
4.2 Major Design Data for the Optimized Cooling Tower Systems,
(Kaiparowits3 Mechanical Series (SI)) 33
4.3 Major Cost Summary for Optimized Cooling Tower
Systems ($106), (Kaiparowits, Mechanical Series (Si)) 34
4.4 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10^), (Kaiparowits, Mechanical
Series (Si)) 35
4.5 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($106), (Kaiparowits, Mechanical Series (Si))... 36
4.6 Major Cost Summary for Optimized Cooling Tower Systems
($106) , (San Juan) 37
4.7 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($10^), (San Juan) 38
4.8 Major Cost Summary for Optimized Cooling Tower Systems
($106), (Colstrip) 39
4.9 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($106), (Colstrip) 40
4.10 Major Cost Summary for Optimized Cooling Tower Systems
($106), (Young) 41
4.11 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($106), (Young) 42
4.12 Major Cost Summary for Optimized Cooling Tower Systems
($10°), (Rock Springs) 43
4.13 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($10^), (Rock Springs) 44
4.14 Major Cost Summary for Optimized Cooling Tower Systems
($106) , (New Hampton) 45
VI
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Number
4.15 Base Cooling System Cost and Make-up Water Penalty Cost
Components ($10^), (New Hampton) 46
5.1 Major Design Data for the Optimized Cooling Tower Systems,
(Kaiparowits, Mechanical Series (S2)) 62
5.2 Major Cost Summary for Optimized Cooling Tower Systems
($106), (Kaiparowits, Mechanical Series (S2)) 63
5.3 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10^), (Kaiparowits, Mechanical
Series (S2)) 64
5.4 Major Design Data for the Optimized Cooling Tower Systems,
(Kaiparowits, Mechanical Parallel (Pi)) 65
5.5 Major Cost Summary for Optimized Cooling Tower Systems
($106), (Kaiparowits, Mechanical Parallel (PI)) 66
5.6 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10^), (Kaiparowits, Mechanical
Parallel (Pi)) 67
5.7 Major Design Data for the Optimized Cooling Tower Systems,
(Kaiparowits, Natural Series (Si)) 68
5.8 Major Cost Summary for Optimized Cooling Tower Systems
($106), (Kaiparowits, Natural Series (SI)) 69
5.9 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10^), (Kaiparowits, Natural
Series (Si)) 70
5.10 Factors Used for Economic Sensitivity Analysis 71
5.11 Impact of Changing Economics on Total Evaluated Cost
(Kaiparowits, Mechanical Series, Si Mode) 72
7.1 Major Cost Summary for the Optimized Mechanical Wet
Cooling Systems ($106), (Seattle) 97
7.2 Major Capital and Penalty Cost Components for the Optimized
Mechanical Wet Cooling Systems ($106), (Seattle) 98
7.3 Major Cost Summary for the Optimized Wet/Dry and Reference
Cooling Systems ($106), (Seattle) 99
7.4 Major Capital and Penalty Cost Components for the Optimized
Wet/Dry and Reference Cooling Systems ($10^), (Seattle).... 100
vii
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Number Page
7.5 Major Cost Summary for the Optimized Mechanical Wet
Cooling Systems ($106), (Cleveland) 101
7.6 Major Capital and Penalty Cost Components for the Optimized
Mechanical Wet Cooling Systems ($10*>), (Cleveland), 102
7.7 Major Cost Summary for the Optimized Wet/Dry and Reference
Cooling Systems ($106), (Cleveland) 103
7.8 Major Capital and Penalty Cost Components for the Optimized
Wet/Dry and Reference Cooling Systems ($106), (Cleveland)..104
7.9 Major Cost Summary for the Optimized Wet/Dry and Mechanical
Wet Cooling Systems ($10 ), (Newark) 105
7.10 Major Capital and Penalty Cost Components for the Optimized
Wet/Dry and Mechanical Wet Cooling Systems ($10^),
(Newark) 106
7.11 Major Cost Summary for the Optimized Mechanical Wet Cooling
Systems ($106), (Charlotte) 107
7.12 Major Capital and Penalty Cost Components for the Optimized
Mechanical Wet Cooling Systems ($106), (Charlotte) 108
viii
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FIGURES
Number Page
1.1 Scheduled and Projected Installation of Thermal Electric
Power Plants in WSWC Member States Including Plants With
Dry Cooling or Ocean Cooling (2) 4
1.2 Cooling Water Needs for Scheduled and Projected Coal
Fired and Nuclear Power Plants to 1990 (2) 5
3.1 Heat Rate Correction Curve for a Plant with a Conventional
Turbine 18
3.2 Heat Rate Correction Curve for a Plant with a High Back
Pressure Turbine 19
3.3 Series-Water Flow Wet/Dry Tower 20
3.4 Wet/Dry Tower - Mode 1 Operation 21
3.5 Wet/Dry Tower - Mode 2 Operation 21
3.6 Parallel-Water Flow Wet/Dry Tower 22
3.7 Parallel Path Wet/Dry Tower for Plume Abatement 23
3.8 Ambient Temperature Duration and Corresponding Plant
Per f o rmance 24
3.9 Definitions of Temperatures in the Cooling Systems 25
4.1 Coal Fields of the United States and Sites for the Water
Conservation Analysis , 47
4.2 Typical Capital and Penalty Trade-Off for Mechanical Wet Tower
Systems (Kaiparowits, Constant Approach = 19°F (10.5°C)) 48
4.3 Effect of Approach Temperature on the Optimum Selection of the
Wet Tower System (Kaiparowits, Mechanical Wet Tower, 1985)...49
4.4 Optimization of a 10 Percent Wet/Dry System for a Series of
Specified Design Back Pressures (Kaiparowits, Mechanical
Series, Si Mode) 50
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Number Page
i Vr*
4.5 Optimum Selection and Economic Trade-Offs of a 10 Percent
Wet/Dry System (Kaiparowits, Mechanical Series, Si Mode) 51
4.6 Performance Curves for a 10 Percent Mechanical Series Wet/
Dry Cooling System at Kaiparowits, Utah 52
4.7 Total Make-up Requirement for Each Monthly Period at
San Juan, New Mexico 53
4.8 Maximum Make-up Flow Rate for Each Monthly Period at
San Juan, New Mexico .....54
4.9 Comparison of Alternate Sites Including Water Supply Costs 55
4.10 Comparison of Alternate Sites Excluding Water Supply Costs 56
5.1 Total Evaluated Costs of Optimized Wet/Dry Systems Operating
in Si Mode for Various Specified Design Back Pressures
(Kaiparowits, Mechanical Series, 1985) 73
5.2 Total Evaluated Costs of Optimized Wet/Dry Systems Operating
in S2 Mode for Various Specified Design Back Pressures
(Kaiparowits, Mechanical Series, 1985) 74
5.3 Comparison of the Optimized Systems Operating in the Si and
S2 Modes (Kaiparowits, Mechanical Series, 1985) 75
5.4 Comparison of Series (Si) and Parallel (PI) Mechanical
Wet/Dry Cooling Tower Systems (Kaiparowits) 76
5.5 Comparison of Natural Series and Mechanical Series Wet/Dry
Cooling Tower Systems (Kaiparowits, SI Mode) 77
5.6 Comparison of Three Types of Wet/Dry Systems (Kaiparowits,
1985) 78
5.7 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, Mechanical Wet) 79
5.8 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, Mechanical Dry)... ; 80
5.9 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, 270 Wet/Dry) 81
5.10 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, 20% Wet/Dry) 82
6.1 Relationship Between Liquid Water Content of Fogs and
Visibility (12) 91
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Number Page
7.1 Total Evaluated Cost of Wet and Wet/Dry Cooling Systems
Which Produce 5 Hours of Ground Fog as a Function of
Heat Exchanger Size (Seattle, 1985) 109
7.2 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Seattle, 1985) 110
7.3 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Cleveland, 1985) Ill
7.4 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Newark, 1985) 112
7.5 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Charlotte, 1985) 113
7.6 Psychrometric Chart for Two Plume Exhaust Conditions 113A
xi
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TABLES IN APPENDICES
Number
F-l Summary of Design Data for the Optimized Reference
Cooling Systems at Kaiparowits, Utah 128
F-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10^) at Kaiparowits, Utah
- 1985 131
F-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10^) at Kaiparowits, Utah
- 1985 132
F-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Kaiparowits, Utah - Mechanical Series - Si
Mode 133
F-5 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10°) at Kaiparowits, Utah -
Mechanical Series - Si Mode - 1985 136
F-6 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10^) at Kaiparowits, Utah -
Mechanical Series - Si Mode - 1985.... 137
G-l Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Kaiparowits, Utah - Mechanical Series - S2
Mode 146
G-2 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($106) at Kaiparowits, Utah -
Mechanical Series - S2 Mode - 1985 149
G-3 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($106) at Kaiparowits, Utah -
Mechanical Series - S2 Mode - 1985 150
II-1 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Kaiparowits, Utah - Mechanical Parallel - PI
Mode 152
H-2 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10^) at Kaiparowits, Utah -
Mechanical Parallel - PI Mode - 1985 155
xii
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Number Page
H-3 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10°) at Kaiparowits, Utah -
Mechanical Parallel - Pi Mode - 1985. 156
1-1 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Kaiparowits, Utah - Natural Series - Si Mode 158
1-2 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10") at Kaiparowits, Utah -
Natural Series - Si Mode - 1985 161
1-3 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10°) at Kaiparowits, Utah -
Natural Series - Si Mode - 1985 162
J-l Summary of Design Data for the Optimized Reference Cooling
Systems at San Juan, New Mexico 164
J-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10°) at San Juan, New Mexico
- 1985 167
J-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10°) at San Juan, New Mexico
- 1985 168
J-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at San Juan, New Mexico - Mechanical Series - SI
Mode 169
J-5 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10°) at San Juan, New Mexico -
Mechanical Series - Si Mode - 1985 172
J-6 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10^) at San Juan, New Mexico -
Mechanical Series - Si Mode - 1985 173
K-l Summary of Design Data for the Optimized Reference Cooling
Systems at Colstrip, Montana 175
K-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10°) at Colstrip, Montana
- 1985 178
K-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10°) at Colstrip, Montana
- 1985. 179
xiii
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Number
K-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Colstrip, Montana - Mechanical Series - Si
Mode 180
K-5 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10^) at Colstrip, Montana -
Mechanical Series - Si Mode - 1985 183
K-6 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10**) at Colstrip, Montana -
Mechanical Series - Si Mode - 1985 184
L-l Summary of Design Data for the Optimized Reference Cooling
Systems at Young, North Dakota 186
L-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10^) at Young, North Dakota
- 1985 189
L-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10^) at Young, North Dakota
- 1985 190
L-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Young, North Dakota - Mechanical Series - SI
Mode 191
L-5 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($106) at Young, North Dakota -
Mechanical Series - Si Mode - 1985 194
L-6 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($106) at Young, North Dakota -
Mechanical Series - Si Mode - 1985 195
M-l Summary of Design Data for the Optimized Reference Cooling
Systems at Rock Springs, Wyoming 197
M-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10^) at Rock Springs, Wyoming -
1985 200
M-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10^) at Rock Springs, Wyoming
- 1985 201
M-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at Rock Springs, Wyoming - Mechanical Series - si
Mode 202
xiv
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Number
M-5 Summary of Capital Investment Cost for the Optimized
Wet/Dry Cooling Systems ($10^) at Rock Springs, Wyoming -
Mechanical Series - Si Mode - 1985 205
M-6 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry Cooling Systems ($10*>) at Rock Springs, Wyoming -
Mechanical Series - Si Mode - 1985 206
N-l Summary of Design Data for the Optimized Reference Cooling
Systems at New Hampton, New York 208
N-2 Summary of Capital Investment Cost for the Optimized
Reference Cooling Systems ($10^) at New Hampton, New York
- 1985 211
N-3 Penalty Breakdown and Cost Summary for the Optimized
Reference Cooling Systems ($10*>) at New Hampton, New York
- 1985 212
N-4 Summary of Design Data for the Optimized Wet/Dry Cooling
Systems at New Hampton, New York - Mechanical Series -
Si Mode 213
N-5 Summary of Capital Investment Cost for the Optimized Wet/Dry
Cooling Systems ($10 ) at New Hampton, New York - Mechanical
Series - Si Mode - 1985 216
N-6 Penalty Breakdown and Cost Summary for the Optimized Wet/Dry
Cooling Systems ($10^) at New Hampton, New York - Mechanical
Series - Si Mode - 1985 217
0-1 Major Design Data for the Optimized Cooling Tower Systems,
(San Juan, New Mexico) 219
0-2 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10$), (San Juan, New Mexico) 220
0-3 Major Design Data for the Optimized Cooling Tower Systems,
(Colstrip, Montana). 221
0-4 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($106), (Colstrip, Montana) 222
0-5 Major Design Data for the Optimized Cooling Tower Systems,
(Young, North Dakota) 223
0-6 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($106), (Young, North Dakota) 224
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Number Page
0-7 Major Design Data for the Optimized Cooling Tower Systems,
(Rock Springs , Wyoming)
0-8 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($10^), (Rock Springs, Wyoming) ....... 226
0-9 Major Design Data for the Optimized Cooling Tower Systems,
(New Hampton, New York) ..................................... 227
0-10 Major Capital and Penalty Cost Components for Optimized
Cooling Tower Systems ($106) , (New Hampton, New York) ....... 228
P-l Summary of Design Data for the Optimized Mechanical Wet
Cooling Systems, (Seattle) .................................. 242
P-2 Penalty Breakdown and Cost Summary for the Optimized
Mechanical Wet Cooling Systems ($106), (Seattle) ............ 245
P-3 Summary of Capital Investment Cost for the Optimized
Mechanical Wet Cooling Systems ($106), (Seattle) ............ 246
P-4 Summary of Design Data for the Optimized Wet/Dry and Reference
Cooling Systems, (Seattle) ........................... . ...... 247
P-5 Penalty Breakdown and Cost Summary for the Optimized
Wet/Dry and Reference Cooling Systems ($10°), (Seattle) ..... 250
P-6 Summary of Capital Investment Cost for the Optimized
Wet/Dry and Reference Cooling Systems ($10°), (Seattle) ..... 251
P-7 Summary of Design Data for the Optimized Mechanical Wet
Cooling Systems , (Cleveland) ................................ 252
P-8 Penalty Breakdown and Cost Summary for the Optimized
Mechanical Wet Cooling Systems ($106), (Cleveland) .......... 255
P-9 Summary of Capital Investment Cost for the Optimized
Mechanical Wet Cooling Systems ($106), (Cleveland) .......... 256
P-10 Summary of Design Data for the Optimized Wet/Dry and Reference
Cooling Systems, (Cleveland) ................................ 257
P-ll Penalty Breakdown and Cost Summary for the Optimized Wet/Dry
and Reference Cooling Systems ($10°) , (Cleveland) ........... 260
P-12 Summary of Capital Investment Cost for the Optimized Wet/Dry
and Reference Cooling Systems ($10^), (Cleveland) ........... 261
P-13 Summary of Design Data for the Optimized Wet/Dry and
Mechanical Wet Cooling Systems , (Newark) .................... 262
xvi
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Number Page
P-14 Penalty Breakdown and Cost Summary for the Optimized Wet/Dry
and Mechanical Wet Cooling Systems ($106), (Newark) 265
P-15 Sumnary of Capital Investment Cost for the Optimized Wet/Dry
and Mechanical Wet Cooling Systems ($106), (Newark)........ 266
P-16 Summary of Design Data for the Optimized Mechanical Wet
Cooling Systems, (Charlotte) 267
P-17 Penalty Breakdown and Cost Summary for the Optimized Mechanical
Wet Cooling Systems ($106), (Charlotte) 270
P-18 Summary of Capital Investment Cost for the Optimized Wet/Dry
and Mechanical Wet Cooling Systems ($106), (Charlotte) 271
xvii
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FIGURES IN APPENDICES
Number
F-l Performance Curves for a High Back Pressure Mechanical
Dry Cooling System at Kaiparowits, Utah 138
F-2 Performance Curves for a Conventional Low Back Pressure
Mechanical Dry Cooling System at Kaiparowits, Utah 139
F-3 Performance Curves for a Mechanical Wet Cooling System
at Kaiparowits, Utah 140
F-4 Performance Curves for a 2% Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah 141
F-5 Performance Curves for a 20% Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah 142
F-6 Performance Curves for a 30% Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah ,.... 143
F-7 Performance Curves for a 40% Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah 144
0-1 Temperature Duration Curves: Kaiparowits, Utah 229
0-2 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (Kaiparowits, Mechanical Series,
SI Mode, 1985) 230
0-3 Temperature Duration Curves: San Juan, New Mexico 231
0-4 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (San Juan, Mechanical Series,
Si Mode, 1985) 232
0-5 Temperature Duration Curves: Colstrip, Montana 233
0-6 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (Colstrip, Mechanical Series,
Si Mode, 1985) 234
0-7 Temperature Duration Curves: Young, North Dakota 235
xviii
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Number
0-8 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (Young, Mechanical Series,
SI Mode, 1985) 236
0-9 Temperature Duration Curves: Rock Springs, Wyoming 237
0-10 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (Rock Springs, Mechanical Series,
SI Mode, 1985) 238
0-11 Temperature Duration Curves: New Hampton, New York 239
0-12 Total Evaluated Cost and the Penalty and Capital Components
for the Optimized Systems (New Hampton, Mechanical Series,
SI Mode, 1985) 240
P-l Temperature Duration Curves: Seattle, Washington 272
P-2 Temperature Duration Curves: Cleveland, Ohio 273
P-3 Temperature Duration Curves: Newark, New Jersey.. .274
P-4 Temperature Duration Curves: Charlotte, North Carolina 275
xlx
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ACKNOWLEDGMENTS
"A Study of Wet/Dry Cooling Systems for Fossil Power Plants: Water Conser-
vation and Plume Abatement" is a study directed to the development and under-
standing of the economic impact of wet/dry cooling systems on power plant
operations. The project was completed under the direction of T. G. Brna,
Project Officer for the U.S. Environmental Protection Agency (EPA), B. A.
Tichenor and J. A. Chasse, former EPA Project Officers, G. A. Englesson,
Project Manager for the United Engineers & Constructors Inc. (UE&C), and
J. H. Crowley, Manager of the Advanced Engineering Department, UE&C Inc.
Principal contributors were: M. C. Hu, Principal Investigator; J. C. Bentz
and N. H. Lee, evaluation of water conservation wet/dry towers; S. R. Buerkel
and D. S. Wiggins, economic evaluation of wet/dry towers for plume abatement;
J. E. Pinkerton and J. B. Robinson, plume analysis; F. P. Maiuri, water
treatment analysis; D. E. Pennline, economic sensitivity analysis.
Acknowledgments are due to T. Thoem and Gi Parker of EPA Region VIII, H.
Lunenfeld of EPA Region II and W. F. Savage, Manager of Advanced Concepts
Branch, U.S. Energy Research and Development Administration, for their inter-
est and contributions to this study.
Acknowledgments are due to the following utilities and their representatives
for providing data used in this study for various sites: R. S. Currie and
K. A. Gulbrand of Southern California Edison Company; E. D. Kist and S. F.
Anderson of Public Service Company of New Mexico; L. V. Hillier of Minnkota
Power Cooperative, Inc.; R. J. Labrie of The Montana Power Company; and B. Z.
Baxter, Jr. and R. H. Metzger of Orange and Rockland Utilities, Inc.
Acknowledgments are also due to the following cooling tower and turbine
manufacturers and their representatives for providing data and consultation
during this study; namely, M. W. Larinoff and E. C. Smith of Hudson Products;
R. Landon and C. A. Baird of Marley Company; G. E. Collins and M. R. Lefevre
of Research-Cottrel; J. A. Brown of Ecodyne; H. H. von Cleve and G. Hesse of
GEA-Gesellschaft Fur Luftkondensation m.b.H.; P. J. Harris of GKN Birwelco
Limited; J. E. Pugh of General Electric Company; and G. J. Silvestri, Jr. of
Westinghouse Electric Corporation.
XX
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SECTION 1
INTRODUCTION
1.1 PURPOSE
The purpose of this report, prepared for the Environmental Protection Agency
(EPA) by United Engineers & Constructors Inc. (UE&C) is twofold:
1. Document an economic and engineering evaluation of separate
wet and dry cooling towers operating in combination to limit
consumptive water use.
2. Document an economic and engineering evaluation of hybrid
wet/dry cooling towers designed to minimize ground
fogging.
This study is limited to an evaluation of wet/dry cooling for fossil-fueled
generating stations with special emphasis on specific site conditions. Com-
bination wet/dry systems for water conservation were evaluated at six loca-
tions (five in the coal areas of the Western United States and one in New
York State) and hybrid wet/dry systems for plume abatement were evaluated
at four urban sites (Seattle, WA; Cleveland, OH; Charlotte, NC; and Newark,
NJ). A separate and complementary study of the use of wet/dry cooling for
water conservation for light water reactor fueled stations was completed
by UE&C for the Energy Research and Development Administration (ERDA)(1).
In the ERDA study wet/dry cooling systems were evaluated at three hypothet-
ical sites representing the Southwest, Southeast, and Northeast regions of
the United States. This ERDA study included engineering and economic sensi-
tivity analyses which formed the basis for the site specific analyses per-
formed for the EPA. Both studies used the same basic analytic and evaluation
tools.
1.2 BACKGROUND
The increasing use of evaporative (wet) cooling towers to dissipate power
plant waste heat loads has focused attention on two inherent characteristics
of such devices: consumptive water use and vapor plume emissions. Con-
sumptive water use, because of its cumulative impact, is evolving as a major
environmental concern in all parts of the United States. An immediate con-
cern is the development of the coal resources of the Western United States.
The limiting factor in this development may be the availability of water
for cooling purposes.
Many efforts to determine the impacts of water consumption and energy pro-
duction in the coal-rich regions of the Western United States have been
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initiated. One such effort reported in Reference 2, entitled "Western
States Water Requirements for Energy Development to 1990", was prepared by
the Western States Water Council (WSWC). Figure 1.1 taken from that report
shows the cumulative capacity of projected installation of thermal electric
power plants in the states which are members of the WSWC.
Figure 1.2 shows the quantity of water consumed by evaporative cooling in
meeting those power plant projections.
The Western United States is an area of highly regulated water flow. Much
of this flow has been allocated significantly into the future, and in
drought years the annual allocation exceeds the annual stream flow. Devel-
opment of the regional coal resources will require significant amounts of
water. Since no new water sources are expected, existing water Users may
be required to change their patterns of use to accomodate energy develop-
ment. Intense competition for the limited water resources between indus-
trial, agricultural, recreational, urban, and energy segments of the economy
as well as the in-stream flow needs of fish and wildlife will provide a
major dilemma to local and regional planners.
The resolution of these conflicts will not be based on a conventional price/
demand relationship. The WSWC believes that an increased price of water
would not have a significant effect on the amount of water used for energy
production. Even if the price was to increase substantially, the percentage
of water cost to total cost of generation would remain low. This lack of
cost sensitivity does not apply to all water users. Agricultural and muni-
cipal growth would both be significantly impacted by changing water costs.
In the introduction to its report the WSWC states, "Unless planners and
administrators recognize the energy industry's needs for water and its small
dollar incentive for water conservation, much of the water resource planning
in the past and in the future could be for naught" (2). In the future, the
problems associated with the consumptive use of water will not be confined
to the Western United States.
Another potentially adverse impact associated with evaporative cooling sys-
tems is the creation of ground fog or the aggravation of natural fogging
conditions. This can be an especially important consideration for power
plants which are sited in urban areas and are required to operate on a
closed-cycle system.
One technology which can virtually remove both of these site constraints is
dry cooling. However, the application of dry cooling would require signifi-
cantly greater capital expenditures and incur substantial losses in plant
performance during high temperature periods as compared with wet systems.
The costs associated with the construction and operation of a dry cooling
system are approximately three times those associated with wet tower opera-
tion. Substitution of dry cooling for wet cooling as determined in this
study could increase the total cost of generation by 10 to 15 percent.
Wet/dry cooling systems combine desirable features of wet and dry cooling
towers into one operational unit. When a wet/dry system is designed for
water conservation, the dry tower limits the quantity of water evaporated
-------
and the wet tower limits the losses in plant performance. When a wet/dry
system is designed for plume abatement, the dry sections cause a reduction of
the relative humidity of the plume from the tower and its fogging potential.
With respect to economics, the combination of wet and dry operation presents
the opportunity for numerous trade-offs between capital costs and operating
penalties. In addition, these systems have significant implications for
power plant site selection.
Two basic criteria for fossil plant site selection are fuel and water
availability. Planners must evaluate the economic and environmental trade-
offs of transporting coal and water to the plant and transmitting electrical
energy to the load center. In this report} for the mine-mouth sites the
cost of coal ranges from $0.47 to $1.10 per million Btu in 1985, while the
fuel cost at the New Hampton, N.Y. site is projected to be $5.44 per million
Btu. The cost of transporting make-up water to the plant site can also be
large. To provide condenser cooling water for a wet cooling system at the
Kaiparowits, Utah site (30 miles from and 3600 ft. in elevation above Lake
Powell) would cost. 35 million dollars in capital and pumping costs over the
plant lifetime. Water transportation costs usually limit sites selected
for power plants using evaporative cooling to areas within 25 to 30 miles
of a major water source or require the construction of a major impoundment
along a smaller waterway. The use of wet/dry cooling permits relaxation
of the water supply criterion and greatly increases the number of possible
sites. The use of wet/dry cooling may also enable power plant siting
in sensitive areas (e.g., urban) which have a high potential for ground fog
formation.
The economic analysis provided in this report attempts to identify the op-
timum or minimum cost cooling system, wherein the capital costs of the
cooling system are balanced with the economic penalties associated with
operating the cooling system. The sum of the capital and penalty costs is
defined as the Total Evaluated Cost (TEC). The economic optimum occurs
because of the nature of the capital and penalty cost functions. For most
cases, the more capital paid initially for the cooling system the smaller
will be the capitalized penalty^ and vice versa. These costs and penalties
can, therefore, be balanced to provide an economic optimum.
1.3 REPORT ORGANIZATION
The general system description and cost evaluation method are given in
Section 3. The comparative results for six sites evaluated for water con-
servation are given in Section 4. Section 5 presents the results of a
detailed engineering and economic sensitivity analysis at one water conser-
vation site. The model which was used for plume analysis is described in
Section 6 and the results of the system optimization for plume abatement
at four sites are given in Section 7.
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O
64
60 •
52
48
40
38
32
28
24 -
20
16 •
12
8
4
0
Htstortc-j^-*-Planned -*. |-*Projacted
1970
1980
1990
Figure 1.1 Scheduled and Projected Installation of Thermal Electric
Power Plants in WSWC Member States Including Plants With Dry
Cooling or Ocean Cooling (2)
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0)
I
0)
o
o
o
*l
o
o
4J
•r-i
4J
c
cd
Evaoorative
Cooling
1970
1975
1980
1965
1990
Figure 1.2 Cooling Water Needs for Scheduled and Projected Coal
Fired and Nuclear Power Plants to 1990 (2)
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SECTION 2
SUMMARY AND CONCLUSIONS
2.1 SUMMARY
This report presents the results of a design cost study for wet/dry cooling
tower systems used in conjunction with 1000 MWe coal-fired power plants to
reject waste heat while either conserving water or minimizing ground
fogging. The purpose of this report, prepared for EPA by UE&C, is to docu-
ment:
1. An economic and engineering evaluation of separate wet and dry
cooling towers operating in combination to limit consumptive
water use
2. An economic and engineering evaluation of wet/dry cooling
towers designed to minimize ground fogging
The wet/dry cooling tower designed for water conservation is one which com-
bines physically separated wet towers and dry towers into an operational
system. In designing the wet/dry system, a dry cooling tower is sized to
carry the plant heat load at low ambient temperatures, and a separate wet
tower is added to augment the heat rejection of the dry tower at higher
ambient temperatures. These wet/dry systems are designed to operate with
conventional low back-pressure turbines. The component wet and dry towers
are state-of-the-art designs.
The wet/dry cooling tower designed for plume abatement is one which com-
bines wet and dry heat exchanger modules into a single structure. In de-
signing the wet/dry tower for plume abatement, the wet cooling tower is
sized to carry the plant heat load at all ambient temperatures and separate
dry modules are integrated into the cooling tower structure, physically
oriented so that the air stream which cools the dry heat exchangers dries
the wet plume.
The method used in the economic analysis is a fixed source-fixed demand
method. A reference plant is assumed to have a constant energy input rate
(fixed heat source) and a constant fixed demand for its output. It is
against this fixed demand that each cooling system must be gauged. In-
ability to meet this demand is charged as a penalty cost which is added to
the capital cost of the cooling system. Other penalty costs include the
cost of supplying make-up water and the cooling system maintenance cost.
The sum of the penalty costs and the capital cost of the cooling system is
called the total evaluated cost (TEC).
-------
The evaluations of wet/dry towers designed for water conservation were per-
formed for five mine-mouth sites in the coal-rich Western United States and
one Eastern site which will require coal shipment for operation. The eval-
uations of wet/dry towers designed for plume abatement were performed for
four urban sites in the United States. The basic economic factors used to
develop the system costs are shown below:
Plant Start-up Date 1985
Average Plant Capacity Factor 0.75
Annual Fixed Charge Rate 18%
Plant Life 40 years
Capacity Penalty Charge Rate $485/kWe
2.2 CONCLUSIONS
1. Wet/dry cooling tower systems can be designed to provide a
significant economic advantage over dry cooling, yet closely
match the dry tower's ability to conserve water. The wet/dry
systems which save as much as 98 percent of the make-up water
required by a wet tower can maintain that economic advantage.
Therefore, for power plant sites where water is in short supply,
wet/dry cooling is the economic choice over dry cooling. Even
where water supply is remote from the plant site, this advan-
tage holds.
2. Where water is available, wet cooling will continue to be the
economic choice in most circumstances. However, for sites
with remote water supply sources, the advantage of wet cooling
over wet/dry cooling may be small. In cases where resource
limitations or environmental criteria make water costs excess-
ive, wet/dry cooling can reach economic parity with wet cooling.
3. Ground fogging from low profile wet cooling towers can be
significantly reduced by increasing the number of cells, thereby
reducing the liquid water concentration in the plume. These
design changes can be made without significantly increasing
the total evaluated cost of the wet cooling tower. In cases
of restrictive site conditions or fogging limitations, hybrid
wet/dry cooling towers may be used effectively at costs which
approximate those of enlarged wet towers.
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SECTION 3
SYSTEM DESCRIPTION AND METHOD OF ECONOMIC EVALUATION
3.1 CHARACTERISTICS OF THE REFERENCE POWER PLANT
The reference power plant for the wet/dry cooling tower system evaluation
is a nominal 1000 MWe coal-fired electric generating station. The power
plant steam supply is assumed to be constant and fixed at 2541 MW thermal.
This heat source may be coupled with either a conventional low back-
pressure turbine, which has an operating limitation ranging from 5 to 6 in-
HgA (127 to 152.4 mm-HgA) depending on the turbine manufacturer, or a high
back-pressure turbine. When coupled with the conventional turbine, the
generator for the reference plant delivers 1039 MWe at a back-pressure of
2 in-HgA (50.8 mm-HgA). This output, which is assumed equal to the constant
fixed demand, is referred to as the base output of the reference plant. The
selection of these quantities was based on a typical coal-fired plant design
as described in Reference 3.
The high back-pressure turbine is of the intermediate annulus type with an
operating limitation of 15 in-HgA (381 mm-HgA). This type of turbine is
offered by the General Electric Company for fossil plants. A 330 MWe fossil
unit with dry cooling towers, which is currently under construction at the
Wyodak Station near Gillette, Wyoming, will utilize such a turbine. Accord-
ing to General Electric, the maximum rating commercially available is 750
MWe. In this study, the high back-pressure turbine is only used with dry
towers.
The effect of cooling system performance on the turbine-generator output is
calculated using the heat rate versus back-pressure curves shown in Figures
3.1 and 3.2. Figure 3.1 shows the typical heat rate curve for a steam plant
in the 1000 MWe range coupled with a conventional turbine. Figure 3.2 shows
a hypothetical heat rate curve projected for the same plant coupled with a
high back-pressure turbine of the intermediate annulus type.
3.2 COOLING TOWER CONFIGURATIONS
3.2.1 Wet and Dry Towers
Three types of wet and dry towers were considered in the design of combina-
tion wet/dry towers. These are:
1. Mechanical draft wet tower
2. Mechanical draft dry tower
3. Natural draft dry tower
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All three towers are of conventional state-of-the-art designs. A descrip-
tion of these towers can be found in Appendix A.
The mechanical draft wet and dry towers can be either of modular design or
integral design, such as the currently marketed round mechanical tower. The
modular configuration, selected for investigation in this study, allows more
flexibility in the design and evaluation of the wet and wet/dry towers. The
natural draft dry tower was assumed to be a concrete tower with fin-tube
heat exchangers mounted vertically around the base of the tower.
Specific designs commonly offered by cooling tower manufacturers were used
for the mechanical draft wet tower module, the dry tower module, and the
finned-tube heat exchanger module of the natural draft dry tower. The de-
sign specifications of these three modules are given in Appendix A.
In addition to their use as components of the wet/dry towers, the mechanical
draft wet and the mechanical draft dry towers were also evaluated indepen-
dently. These tower systems are referred to as reference tower systems, and
they serve as benchmarks for comparison with the wet/dry towers. ;
3.2.2 Wet/Dry Cooling Towers for Water Conservation
A number of possible arrangements exists for combining separate wet and dry
towers into wet/dry towers which can conserve make-up water. Many of these
wet/dry towers have been described in the literature (4,5). Evaluation of
all possible arrangements is beyond the scope of this study. After prelimi-
nary evaluation and discussions with the EPA, the following wet/dry combina-
tions were selected for evaluation:
1. Mechanical series wet/dry tower - This system combines separate
mechanical draft wet and dry towers by means of a cooling
water circuit which flows through the dry and wet towers in
series.
2. Mechanical parallel wet/dry tower - This system combines
separate mechanical draft wet and dry towers by means of a
cooling water circuit which flows through the wet and dry
towers in parallel.
3. Natural series wet/dry tower - This system combines separate
natural draft dry towers and mechanical draft wet towers by
means of a series water circuit.
The separate arrangement of wet and dry towers provides flexibility in tower
design and operation. It allows independent sizing and control of the com-
ponent wet and dry towers, thus making possible different size combinations
and operational modes. These design variables affect both the thermal per-
formance and water consumption.
3.2.2.1 Design and Operation of Series Flow Wet/Dry Systems--
A schematic diagram for the series water flow towers is shown in Figure 3.3.
The two cooling towers are connected so that water flows first to the dry
tower and then to the wet cooling tower.
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The dry tower is designed to reject the entire heat load at a low ambient
temperature while maintaining the turbine back-pressure within a specified
limit. The other equipment sized at this design point are the condenser,
and the circulating water pumps and pipeline. The performance of the dry
tower is then evaluated at the peak ambient temperature and the specified
limiting back pressure to determine the heat rejection capability of the
dry tower at these conditions. This result is then used to size the wet
helper tower needed to reject the remaining waste heat.
For the three wet/dry cooling systems evaluated, dry cooling is the basic
heat rejection mechanism, and wet cooling is used to provide supplementary
heat rejection. The dry tower is designed to operate continuously during
the year although provision is included to shut down dry cells if they are
not needed at low ambient temperatures.
Two different modes of operation were analyzed and are described below.
Mode Si - The first mode is termed the Si mode (S for series). The
main objective of this mode is to operate the wet helper tower as
little as practically possible. During the peak summer ambient
temperature, both the wet and dry towers are operated at full
capacity. As the ambient temperature falls, the wet cells are
turned off in succession to maintain the turbine back-pressure
essentially constant at the wet tower design value. The back-
pressure of a typical turbine operating with this system is schemat-
ically presented in Figure 3.4. When Point 3 is reached, all of
the wet cells have been shutdown and the dry tower can reject the
entire heat load. The back pressure curve between Points 2 and 3
is saw-tooth shape because a discrete number of wet cells are taken
out of service as the ambient temperature and the turbine back-
pressure decrease. Although operation of the tower system produces
a characteristic saw-tooth operation for the Si mode, throughout
this document, all subsequent figures will show the wet tower
operation at the constant back-pressure as shown by Point 2 in
Figure 3.4
Mode Si requires continuous feedback controls for the operation of
the wet towers. Most new stations are being designed with sufficient
computer capacity to provide for this additional measure of station
control. The cost of this control system has not been included in
the wet/dry cooling costs described in this study.
It should be noted that, for the Si mode, the cut-off point for
wet cooling is, in general, at a higher ambient temperature than
the dry tower design temperature (Figure 3.4).
Mode S2 - The second mode of operation analyzed represents a
system operating with much less control of the wet tower. In this
mode, all the wet cells are operated continuously until the dry
tower design temperature is reached. As the ambient temperature
decreases, the turbine back-pressure is allowed to fall. When the
10
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dry tower design temperature is reached, all of the wet cells are
shutdown and the entire heat load is handled by the dry tower. A
schematic of this system operation is presented in Figure 3.5. As
the ambient temperature passes through the dry tower design point,
an apparent instantaneous jump in back-pressure occurs. However,
in reality, this transition would occur over a long enough time
span so as not to create any damaging thermal shock to the turbine
and associated equipment. Mode S2 is more energy conservative at
the expense of higher water consumption than the same system
operating in the Si mode.
3.2.2.2 Design and Operation of Parallel Flow Wet/Dry Systems—
Figure 3.6 is a schematic diagram of the parallel water flow wet/dry
cooling system. The cooling water leaving the condenser is divided into
two streams which flow through the wet and dry towers in parallel. The
two streams are rejoined before entering the condenser.
The design procedure is similar to that of the series water flow wet/dry
towers. One major difference between parallel and series flow is that
during wet/dry operation, the dry tower operates with partial flow. The
modes of operation considered are described below.
Mode Pi - This mode (P for parallel) is analogous to the series SI
mode with the following exceptions:
1. During wet/dry operation, the dry tower operates
with partial water flow.
2. As the wet cells are sequentially shutdown, the
water is diverted back through the dry cells.
Mode P2 - The second mode is analogous to the S2 mode with the
following exceptions:
1. During wet/dry operation, the dry tower operates
with a constant partial water flow.
2. When the ambient temperature reaches the design
dry bulb temperature, all the wet cells are taken
out of service, and the entire wet tower flow is
returned to the dry tower.
3.2.3 Wet/Dry Cooling Towers for Plume Abatement
The wet/dry cooling system for plume abatement is schematically depicted in
Figure 3.7. The cooling tower design consists of a conventional evaporative
fill section atop which are located dry heat exchangers.
The hot water from the condenser travels through the dry section and then
falls through the evaporative fill. In many cases, due to size limitations
of the heat exchanger and the design temperatures of the cooling system,
only a portion of the total circulating water travels through the dry sec-
11
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tion. At all times during operation, however, the entire flow is cooled in
the evaporative fill section.
Air flows in parallel streams through the wet and dry sections during wet/
dry operation. In the fan stack, the saturated air from the wet section
mixes with the hot dry air from the dry section before exiting from the
tower. Air inlet louvers are provided to close off the air flow through the
dry section during times when plume abatement is not required. With the
air flow through the dry section blocked, the tower operates in an all wet
mode and all of the air travels through the wet section.
Due to reduced efficiency during wet/dry operation, the wet/dry towers for
plume abatement are designed to operate in the wet/dry mode only when plume
fogging potential is great. This operation can be accomplished through the
use of meteorological monitoring and a cooling tower control system connected
to the computer control system for the plant. The cost of such a system has
not been included in the wet/dry cooling system costs described in this
report.
3.3 METHOD OF ECONOMIC EVALUATION
For a valid economic comparison of alternate cooling systems, the costs of
different systems are assessed on a common basis. The method used in this
study for the cooling tower system is consistent with that used in Reference
6. The method may be classified as a fixed source-fixed demand approach.
It assumes that the reference plant has a fixed energy input rate and that
there is a constant fixed demand for the plant output. The demand is fixed
to establish a basis for system comparison. As the plant performance changes
due to the change in cooling system performance, the plant output is compared
to the fixed demand. Since the energy input rate to the plant is fixed,
any deficit between output and demand is provided by an outside source. A
penalty equivalent to an increase in capital cost of the outside source is
added to the capital cost of the cooling system. A credit is taken if the
plant operates above the demand. A penalty is also assessed for the cooling
system power and energy requirements.
The treatment of the loss of plant performance is illustrated in Figure 3.8.
The figure shows the typical gross plant output of the reference power plant
as a function of ambient temperature over an annual cycle. The ambient
temperatures affect the plant output since the performance of a cooling sys-
tem determines the lowest temperature of the thermodynamic cycle, and con-
sequently, the plant output. The figure also shows the net plant output
which is determined by deducting from the gross plant output the power re-
quired to run the cooling system auxiliary equipment.
The maximum plant capacity deficit with respect to the fixed demand occurs
at the highest ambient temperature and represents the capacity replacement
needed. This includes both the maximum loss of gross plant output (AkW)raax,
and the coincidental auxiliary power requirement, (HP)aux- The hatched
area in Figure 3.8 above the gross plant output curve represents the energy
deficit caused by the changes in cooling system performance, whereas the
hatched area between the gross plant output and the net plant output curves
12
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represents the energy requirement by the cooling system auxiliary equipment;
e.g., pumps and fans.
In general, as the size of the cooling system becomes larger, its performance
improves and its capital cost increases, but the penalty cost decreases.
At some point, a minimum exists for the combined cost of capital and penalty
which represents the best trade-off between the two costs. Such a cooling
system is called an optimum or optimized system. The purpose of the econom-
ic evaluation is to determine and compare these optimum systems.
3.3.1 Economic Penalty Evaluation
The cost of a cooling system is composed of its capital cost plus the penal-
ties which are assessed to reflect the cost associated with its operation.
These penalties evaluated on an annual basis include degradation of plant
performance, cooling system power and energy requirements, water supply
costs, and system maintenance.
3.3.1.1 Capacity and Energy Penalties —
The equations used to evaluate the penalty costs associated with loss of
plant output and cooling system operation are given below. In evaluating
these penalties, it is assumed that the plant has an average capacity fac-
tor and operates at full capacity or is off-line.
Capacity Penalty (P, ) :
(3-1)
Replacement Energy Penalty (?2) :
f8760 r T
P0 = CF I 0AM + F»HR(T) AkW(T)dt (3-2)
/ /0 L. J
Cooling System Auxiliary Power (P_) :
(3-3)
Cooling System Auxiliary Energy (PA):
r8760
P4 = CF J COAM + FlHR(T)] HP(T)dt (3-4)
where (AkW)max, AkW(T), (HP)aux, and HP(T) are shown in Figure 3.8 and:
afcr = annual fixed charge rate, %/100.
CF a average capacity factor of the plant, 70/100.
13
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(HP)
aux
HP(T)
HR(T)
K
AkW(T)
0AM
= fuel cost for the generating unit used to make up
the loss of energy, $/Btu ($/KJ).
= cooling system auxiliary power requirement at
Tmax> kW'
- cooling system auxiliary power requirement at
ambient temperature T, kW.
= heat rate as a function of ambient temperature for
the generating unit used to make up the loss of
energy, Btu/kWh (kJ/kWh) •
= capacity penalty charge rate, $/kW.
= maximum loss of capacity, kW.
= loss of capacity at ambient temperature T, kW.
= operation and maintenance cost for the generating
unit used, $/kWh.
= ambient temperature (T is a function of time), °F
max
= peak ambient temperature, °F (°C).
i
= time, hr.
The capacity penalty, P^, and auxiliary power penalty, Pj, are first cost
penalties. They represent the capital expenditure of generating equipment
needed to supply the extra power, either by the addition of peaking units,
e.g., gas turbine or pumped storage generating units, or by providing excess
capacity from base load units in the utility system.
The replacement energy penalty, ?£, and the cooling system auxiliary energy,
P^, are cost penalties which will accrue over the lifetime of the plant.
They are evaluated by capitalizing the respective annual energy costs charged
to the cooling system. These annual energy costs are evaluated by integra-
ting the energy costs for a series of time periods which add up to a year.
Each time period has a constant ambient dry bulb temperature and a coinci-
dent and constant wet bulb temperature.
The sources of capacity replacement which serve as the basis for the assess-
ment of the associated economic factors K, F and 0AM may include any of the
following:
1. high capital cost, low operating cost base load units
2. low capital cost, high operating cost peaking units
3. a mixture of generating unit types
A. purchased power from another utility system
14
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The selection of the capacity replacement is dependent on economics and on
the type of duty. For duties which require relatively constant loads or
large amounts of energy, the replacement choice, on economic grounds, should
be a base load capacity. Such is the case for the auxiliary power and the
capacity loss due to ambient temperature change for the wet/dry and dry
cooling concepts. Therefore, all the economic factors used in this study
were assessed on the basis of base load units similar to the reference plant.
A discussion of the economic factors is given in Appendix B; the numerical
values of these factors are given in Table 4.1.
3.3.1.2 Cooling System Make-up Water Cost Penalty-
One of the disadvantages of wet cooling towers is the requirement of large
amounts of make-up water to replenish the water evaporated and the water
lost in blowdown. When wet cooling is used to augment dry cooling in wet/
dry towers, the water requirement can be substantially reduced. In situa-
tions where the cost of supplying the make-up water is high, this penalty
cost can be a significant factor in comparing dry, wet, and wet/dry towers.
The cost of supplying the make-up water to a plant consists of three compo-
nents :
1. Annualized capital cost for the make-up water system which
includes pipelines, pumps, and associated structures (Ci)
2. Pumping cost which includes both the capacity charge for the
power required by the pumps and the energy charge for pumping
the water (C2)
3. Water purchase and treatment cost
For the specific power plant sites considered in the study, all these com-
ponent costs can be separately estimated.
Make-up Water Penalty
P5 = G! + C2 + C3 (3-5)
3.3.1.3 Cooling System Maintenance Cost Penalty —
The cooling system maintenance penalty is the cost charged to a cooling sys-
tem for services which include periodic maintenance and replacement of parts.
It is calculated on the basis of in-house engineering data, condenser tube
cleaning costs and data supplied by cooling tower vendors. Cooling tower
maintenance mainly consists of:
1. Lubrication and general inspection of the fan motors and gearboxes
2. Partial replacement of motors and gearboxes
3. Cleaning of the cold water basins of the wet towers
4. Partial replacement of finned tubes for the heat exchangers in
the dry towers
5. Cleaning of dry heat exchangers
Condenser tube cleaning was assumed to be required yearly. The circulating
water pumps, motors and associated equipment will require periodic mainten-
15
-------
ance. All of the maintenance costs were calculated, based on a percentage
of the capital cost of the three components: condensers, pumps, and cooling
towers.
Cooling System Maintenance Penalty (P6):
P6 = aCc + bC + cCT (3-6)
where:
Cc = capital cost of condensers.
C • capital cost of pumps.
CT = capital cost of cooling towers.
a,b&c = coefficients for estimating the penalty cost for each
component; a=»0.0075, b=0.0750, cdry^O.OHS, and cwet=0.0122.
3.3.2 Total Evaluated Costs
In summary, there are six penalties which are essential to the evaluation
of cooling systems. These penalty costs are evaluated on an annual basis
as shown in Equations 3-1 through 3-6. These penalty costs are then capi-
talized over the plant lifetime and added to the capital cost of the cooling
system. The sum of the capital cost and the capitalized penalty cost is
called the total evaluated cost and is expressed by the following equation:
P. (3-7)
where:
C = total evaluated cost, $.
C = capital cost of cooling system, $.
afcr = annual fixed charge rate, 70/100.
PS = annualized economic penalties, $.
This total evaluated cost represents the lifetime capital cost of the cooling
system and serves as the criterion for cooling system optimization and
comparison.
3.4 OPTIMIZATION PROCEDURE
In this study, cooling system optimization is governed by one of two con-
straints: the amount of water consumed or the duration of ground fog pro-
16
-------
duced. The particular design and optimization procedure is dependent upon
the constraint applicable and details are provided in the sections on water
conservation and plume abatement. The basic procedures used in the optimi-
zation are as follows:
1. Size and cost the major components comprising the cooling
system for a set of design parameters. The parameters for
sizing the water conservation wet/dry towers systems, for
example, include:
a) Turbine back-pressure for sizing the wet tower
b) Dry bulb temperature for sizing the dry tower
c) Condenser cooling range
d) Dry tower initial temperature difference
e) Wet tower approach
f) Mode of operation of the wet/dry tower
The definitions of temperatures in condensers and cooling
towers are illustrated in Figure 3.9.
2. Evaluate the performance of the cooling system in response to
ambient temperature changes during the annual cycle. The
annual cycle is divided into a series of time intervals; each
has a constant ambient dry bulb temperature and a coincident,
constant wet bulb temperature.
3. Determine the impact of cooling system operation on the plant
performance at the off-design conditions. For each time
interval, the gross turbine output, the pump and fan capacity
and energy requirements, and either the water consumption or
fogging potential are evaluated.
4. Assess the penalties due to loss of performance, make-up
supply, and cooling system maintenance. Penalties are calcu-
lated for each time interval, summed over the annual cycle,
and then capitalized over the plant life.
5. Calculate the total evaluated cost of the cooling system which
includes the capital cost as well as penalty costs.
6. Change the cooling tower and condenser design parameters and
repeat the procedure until the design with the lowest total
evaluated cost consistent with the system constraint is found.
The evaluation of the wet/dry cooling system for water conservation is
described in Sections 4 and 5, and the evaluation of the wet/dry cooling sys-
tem for plume abatement is described in Section 7. The evaluation includes
the detailed design procedures used to obtain the optimized systems and the
trade-offs among capital costs and penalty costs for representative systems.
17
-------
00
7.0 -p
» 6.0 - -
set
I 5-° • -
«-*
Q>
S 4.0 -.
«j
a)
=s 3.0
c
-1.0 ..
Base Plant Heat Rate = 7698 Btu/kWh (8128 kJ/kifti)
Base Plant Output - 1039 MWe
Back Pressure (nn-HgA)
Back Pressure (in-HgA)
Figure 3.1 Heat Rate Correction Curve for a
Plant with a Conventional Turbine
-------
16 ^
14 • •
12 --
Base Plant Heat Rate - 7698 Btu/kWh (8128 kJ/kWh)
Base Plant Output = 1039 MWe
S-l
'-W
10 -•
VO
t«
01
8 --
6 - •
01
00
2 • •
100
J
Back Pressure (mm-HgA)
200
. i I l I
300
i
I
3
I
4
I
5
I
6
l
8
I
10
11
12
I
13
14
15
Back Pressure (in-HgA)
Figure 3.2 Heat Rate Correction Curve for a Plant with a
High Back Pressure Turbine
-------
Dry Tower
Condenser
|S3
O
C
Wet
Tower of
6 Cells
Figure 3.3 Series-Wat^er Flow Wet/Dry Tower
-------
01
u
3
W
05
0)
0)
c
3
H
Wet Tower Design Back Pressure
3
1 —. Dry Tower Design Back Pressure
Cut-off
for Wet
Cooling
Dry Tower Design
*Wet Tower
Design 1
Annual. Cumulative Duration (year) 1
Figure 3.4 Wet/Dry Tower-Mode 1 Operation
o>
LI
3
VI
PL,
.*
O
3
H
•Wet Tower Design Back Pressure
•Dry Tower Design Back Pressure
Wet Tower Design
Annual Cumulative Duration (year) \
Figure 3.5 Wet/Dry Tower-Mode 2 Operation
21
-------
to
N5
Condenser
Dry Tower
Wet
Tower
Cells
Figure 3.6 Parallel-Water Flow Wet/Dry Tower
-------
Air
Hot
Water
»
Inlet,
Dry
Air
Intermediate
Water
Section
Hot
Water
Inlet
Cold Water
Figure 3.7 Parallel Path Wet/Dry Tower for
Plume Abatement
23
-------
Annual Temperature Duration Curve
Plant Fixed Demand (kWbase)
Gross Plant Output
Net Plant Output » Gross Output -
Cooling System
Auxiliary
Annual Cumulative Duration (year)
Figure 3.8 Ambient Temperature Duration and Corresponding Plant Performance
24
-------
Circulating Water
Steam
S
Condensate
Cooling Tower
Air in
T4
Condenser
Air out
T5
Cooling Range
Tower Approach
Initial Temperature
Difference
Terminal Temperature
Difference (Tj_ = T6)
Wet Tower
T3 - T2
T2 - T4 (Wet Bulb)
T3 - T4 (Wet Bulb)
Tl -
Dry Tower
T3 - T2
T2 - T4 (Dry Bulb)
T3 - T4 (Dry Bulb)
Figure 3.9 Definitions of Temperatures in the Cooling Systems
25
-------
SECTION 4
RESULTS OF OPTIMIZATION OF WET/DRY TOWERS FOR WATER CONSERVATION
4.1 INTRODUCTION
The studies of wet/dry systems for water conservation involve evaluations
at six specific sites, five of which are located in the coal-rich regions
of the Western United States. One of these sites (Kaiparowits, Utah) was
selected for more detailed parametric and sensitivity analyses. Those
results are reported in Section 5. In this section, results are given
for wet, dry, and mechanical series wet/dry (Si mode) cooling systems at
the six water conservation sites.
4.2 SITE LOCATION
Because the cooling water supply constraint is expected to be most severe
for power plant sites in the West, the emphasis of these studies is on that
region, in addition to the five sites in the Western United States, a sixth
site in New York State was studied for comparison. The sites, which are
shown in Figure 4.1, are:
Kaiparowits - Southern California Edison Company, Arizona Public
Service Company and San Diego Gas & Electric Com-
pany were, until mid-1976, planning to build a
3000 MWe coal-fired plant on the west side of Lake
Powell in Utah. This site was selected for more
detailed economic sensitivity analyses.
San Juan - Public Service Company of New Mexico operates a
plant at Farmington, New Mexico. The first water
conservation wet/dry towers for utility application
in the United States are planned to service two
additional 450 MWe units at this site.
Colstrip - Montana Power Company operates a plant at this
southeastern Montana location. Two units of 330 MWe
are in operation; two additional 700 MWe units are
planned for 1980 and 1981.
Young - Minnkota Power Cooperative, Inc. is operating a 250
MWe unit at Center, North Dakota.
Rock Springs - Pacific Power and Light Company operates a 1000 MWe
plant at this southwest Wyoming location.
26
-------
New Hampton - Orange and Rockland Utilities, Inc. has proposed
a plant at this southeastern New York site.
Utilities operating, constructing, or planning power plants at these loca-
tions were contacted to obtain economic and site data for use in the evalua-
tion. Some of these data are shown in Table 4.1. Data on make-up water
quality are in Appendix D, and the annual coincident ambient wet and dry
bulb temperature distributions are contained in Appendix 0.
4.3 METHOD OF OPTIMIZATION
The general optimization procedure is given in Section 3.4. Specific ex-
amples of the procedure applied for the wet, dry and wet/dry (water conser-
vation) cooling systems are provided in this section.
For the reference (wet and dry) cooling systems, different designs were
obtained by systematically varying the range and approach temperatures. For
each design, the capital cost and the capitalized operating penalties were
determined. The system with the lowest total evaluated cost was selected
as the optimum for a given set of design parameters. An example of the
trade-off between the capital cost and penalty cost for a reference wet
tower system is shown in Figure 4.2. This figure shows that, for a constant
approach, as the range increases, the capital cost decreases and the penalty
cost increases. These costs are added to identify the cooling system with
the minimum total evaluated cost. This procedure is performed for a series
of approach temperatures as shown in Figure 4.3. For the matrix of design
parameters, the least cost system is identified.
For wet/dry systems designed to conserve water, it is not realistic to de-
termine the optimum systems solely on the basis of economics. Therefore,
the make-up water requirement was used as an additional optimization
criterion. The make-up water requirement of a wet/dry system is defined
as the percentage of the total annual make-up water needed by the optimum
wet reference system. The method of optimization is as follows: by
varying the design parameters listed in Section 3.4, wet/dry systems with a
specific make-up are sized; from these systems the lowest total evaluated
cost system is selected as the optimum system for that make-up water require-
ment. Figure 4.4 is an illustration of the total evaluated cost of a ten
percent make-up system (10% of all-wet) as a function of range for a series
of specified turbine back-pressures. The least cost systems for a set of
design back-pressures are plotted on Figure 4.5 from which the optimum ten
percent system is obtained.
4.4 OPTIMIZED SYSTEMS AT SELECTED SITES
Detailed engineering and economic evaluations given in Section 5 and Refer-
ence 1 have indicated that there is a slight economic advantage of the
series-connected over the parallel-connected wet/dry systems and of the Si
mode over the S2 mode of operation. A larger economic advantage may be
available if natural draft instead of mechanical draft dry towers are used
in the wet/dry systems. For the analysis performed to compare the effects of
site conditions, the mechanical series type wet/dry system was selected
27
-------
because there is no natural draft dry tower experience in this country.
4.4.1 Results for Kaiparowits
The results of the optimized wet/dry tower systems designed for various water
make-up requirements and reference tower systems are shown in Tables 4.2
through 4.4. The make-up requirement is expressed as a percentage of the
annual make-up required by an optimized wet tower system.
Table 4.2 shows a summary of the major design data for the optimized cooling
systems. Included in this table are the number of tower modules and opera-
ting mode, the maximum operating back pressure, the gross generator output,
the condenser or tower heat load at the maximum back pressure, the heat load
distribution between the wet and dry towers at the maximum back pressure,
and the annual water make-up for the tower systems. All of the wet/dry sys-
tems had the minimum cost when designed to operate in Mode Si.
These data indicate that dry cooling tower systems of manageable size can
be designed for utility application by peak shaving the heat load with
evaporative helper towers. The number of dry cells needed for the wet/dry
option are comparable to or less than that required for the dry cooling
system using the high back-pressure turbine. The data also show that the
capacity deficit incurred with the dry tower and high back-pressure turbine
(121.8 MWe) can be reduced more than 70 MWe even with the wet/dry system
requiring two percent make-up.
Table 4.3 summarizes the major capital cost and the penalty cost elements
for the tower systems described in Table 4.2. As previously discussed, the
operating penalties are capitalized over the 40-year lifetime of the plant.
For the wet/dry systems, the costs range between the dry and the wet systems
and decrease monotonically as the make-up water requirement increases. The
total evaluated costs for all of the wet/dry systems are significantly
higher than those for the wet system, but significantly lower than that for
the dry system. As shown in Table 4.3, the total evaluated cost for the 40
percent make-up wet/dry system is 40 percent higher than the cost of the wet
system. The major capital and penalty cost elements are itemized in Table
4.4.
Additional design and cost details are included in Appendix F. The data in-
dicate that the tower cost of each of the wet/dry systems constitutes approx-
imately 30 to 40 percent of the capital cost of the cooling system and ap-
proximately 20 to 30 percent of the total evaluated cost. An examination of
the elements of the penalty cost shows that, for the two percent make-up wet/
dry system, the replacement energy cost is small. This occurs because the
low percentage make-up systems require a larger number of dry tower cells to
control water consumption. Operation of these dry tower cells at low ambient
temperature conditions allows this system to attain low back-pressure and
consequently high gross output.
4.4.1.1 Plant Performance—
An example of the change in plant output in response to changes in ambient
28
-------
temperatures during the year is shown in Figure 4.6 for the ten percent
make-up wet/dry tower. The figure also shows the variation in turbine
back-pressure and cooling tower make-up water flow rate.
When the wet and dry towers are operating together, the turbine back-
pressure is maintained near its design value of 4.5 in-HgA (114.3 mm-HgA),
and the gross and net plant outputs are at their lowest values. The wet
tower modules are gradually taken out of service as the ambient temperature
decreases. The dry tower takes over completely when it is able to carry
the plant heat load while maintaining the turbine back-pressure at or below
the design value. At this point all the wet towers are out of service and
no water is required as shown by the make-up curve. When the dry tower
operates alone and the dry bulb temperature falls, the efficiency of the dry
tower system increases, the back-pressure decreases, and the gross and net
generator outputs increase.
4.4.1.2 Variation in Water Usage—
An important factor in the design of cooling systems is the make-up water
requirement, whether determined on a daily, monthly, or annual basis. The
annual make-up is determined as the summation of the water usage during
each increment of an ambient temperature cycle.
Figures 4.7 and 4.8 show, for each month, the total amount of make-up re-
quired and the maximum flow rate for the San Juan site. The data were gener-
ated for San Juan and not for Kaiparowits for two reasons: (1) comparative
data are available in Reference 1 for a nuclear plant of the same nominal
capacity, and (2) monthly temperature distribution data were not available
for Kaiparowits. The data are typical of water consumption expected for the
western sites.
Although the annual make-up is small, the maximum flow rate can be large.
For example, even for the two percent make-up systems, the maximum make-up
flow rate is almost one-third that required by the wet system. The informa-
tion such as that given in Figures 4.7 and 4.8 can be used to determine
whether stream flow conditions match the make-up requirements, or to size a
reservoir or impoundment. All water supply evaluations reported in this
study used the maximum water flow conditions to size the water supply system.
There are many factors which influence the water supply costs for specific
sites; among them are water quality, distance from supply to the site, eleva-
tion differences, and legal requirements. The water supply costs should be
developed during a preliminary engineering or site selection phase of an en-
gineering program and added to total evaluated cost to compare the systems.
In the design and evaluation of the wet/dry cooling system for a specific
water make-up requirement, the optimization analysis is independent of the
water supply. All of the systems designed for a specific water make-up quan-
tity have essentially the same water supply cost. In this method of analysis,
water treatment and supply costs can be determined for each make-up require-
ment. The water supply costs can then be added directly to the total evalua-
ted costs of the wet and wet/dry cooling systems to permit a comparison. The
29
-------
capital and penalty costs are detailed in Table 4.5 to emphasize the water
supply cost.
The make-up supply capital cost, pumping power and energy cost, and the
water purchase and treatment cost are shown in Table 4.5. These three
quantities are summed to determine the total make-up water penalty cost.
4.4.2 Site Comparisons
Major cost summaries for the other sites are given in Tables 4.6 through
4.15. Details of the design and costs are given in Appendices J through 0.
4.4.2.1 Comparison Including Water Supply Costs—
A graphical comparison of the total evaluated costs for the six sites is
presented in Figure 4.9. Costs at the New Hampton site are significantly
greater than at the mine-mouth western sites primarily because of the higher
fuel costs. The effect of fuel cost on system selection is further illus-
trated in the cost summaries for the six sites. At the mine-mouth sites,
dry tower operation with a high back-pressure turbine is consistently less
expensive than a dry tower optimized with a low back-pressure turbine. How-
ever, at New Hampton, with fuel costs five to ten times higher, the reverse
is true because the high back-pressure turbine suffers significant fuel
penalties in the low pressure (1 to 5 in-HgA) region.
The total evaluated costs in Figure 4.9 include the cost of transporting the
make-up water from the source to the plant site. The water supply system
is designed to meet the maximum flow requirements. The associated costs
include the capital investment in pumps and pipelines and the operating
charges. Additional economic advantages may be obtained by optimizing the
water supply system (e.g., evaluating the trade-offs between on-site make-up
storage and pipeline capacity).
The results presented in Figure 4.9 reflect the site-specific water supply
conditions. For instance, the Kaiparowits cooling system is more expensive
than comparable systems for the other western sites primarily because of
costs associated with pumping water up 2600 ft (792 m) over 30 mi (48.3 km).
The general conclusion based on these results is that wet cooling maintains
a significant cost advantage over the wet/dry option. It is apparent that
the selection of wet/dry over wet cooling may be strongly influenced by
water availability and/or legal restrictions rather than traditional market
considerations.
Tables 4.6 through 4.15 break down the capital and penalty costs to emphasize
the make-up water supply costs for sites other than Kaiparowits.
4.4.2.2 Comparison Excluding Water Supply Costs--
The results shown in Figure 4.10 remove some of the site specificity by
excluding water supply costs. The water treatment and purchase costs shown
in Table 4.1 are included.
30
-------
With the water supply cost removed, the costs of comparable cooling systems
at the western sites differ by less than 20 percent. Again, the New Hampton
costs are significantly greater because of the fuel charges.
31
-------
TABLE 4.1
MAJOR ECONOMIC AND SITE DATA
Plant Start-up Date:
Annual Fixed Charge Rate:
Plant Size (Gross Output):
Average Plant Capacity Factor:
Plant Life;
Capacity Penalty Charge Rate:
1985
m
1039 MWe
0.75
40 years
$485/kWe
Levelized Coal Fuel Cost, c/MBtu (c/GJ)
Operation and Maintenance Costs,
Mills/kHhr
Make-up Water Purchase and Treatnent
Charge. $/1000 gal <$/«3)
Site Elevation, ft (•)
Maxima Dry Bulb/Wet Bulb
Temperatures, °F/°F (°C/°C)
Average Bry Bulb/Wet Bulb
Temperatures, °F/°F (°C/°C)
(take-up Pipeline Length, mi (km)
Make-up Pipeline Elevation Change,
ft (m)
Cycles of Concentration for
Circulating Water
Kaiparouits,
Utah
100 (94.7)
Z.54
0.34 (0.090)
6100 (1859)
103/77
(39.4/25.0)
45.7/39.2
(7.6/4.0)
30 (48.3)
2600 (792)
9
San Juan,
New Mexico
110 (104.2)
2.54
0.30 (0.079)
5500 (1676)
102/63
(38.9/17.2)
57.4/42.5
(14.1/5.8)
5 (8.0)
200 (61)
10
Colstrip,
Montana
94 (89.0)
2.54
0.30 (0.079)
3250 (991)
102/67
(38.9/19.4)
52.6/40.7
(11.4/4.8)
30 (48.3)
700 (213)
9
Young,
North Dakota
47 (44.5)
3.56
0,30 (0.079)
1960 (597)
104/70
(40.0/21.1)
46.8/37.6
(8.2/3.1)
13 (20.9)
0 (0)
12
Rock Springs ,
Wyoming
103.4 (97.9)
2.54
0.32 (0.085)
6750 (2057)
93/56
(33.9/13.3)
47.7/35.7
(8.7/2.1)
40 (64.4)
0 (0)
12
New Hampton,
New York
544 (515.2)
2.54
0.02 (0.005)
400 (122)
99/75
(37.2/23.9)
54.3/46.3
(12.4/7.9)
25 (40.2)
400 (122)
10
-------
TABLE 4.2
MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOHER SYSTB1S
SITE: KAIPAROWITS, UTAH BASE OUTPUT: 1039 HWe WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower /Dry Tower
Maximum Operating Back
Pressure Pgax, in-HgA
Omm-HgA)
Gross Plant Output at
pmax> *«e
Heat toad at V^m. 10*
Btu/hr (1012 j/hr)
Heat Load Dletribution
at PBax> (Wet Tower/Dry
Tower), %
Annual Make-up Water
for Wet Towers, 10& gal
(106 B3)
Hech.
Dry (H)*
0/113
13.36
(339.3)
914.3
4.77
(5.03)
O.O/
100.0
0.0
(0.0)
Mech.
Dry(L)'
0/290
5.03
(127.8)
989.0
4.62
(4.88)
O.O/
100.0
0.0
(0.0)
percentage Matce-up Requirement?
Mechanical Series Wet/Dry
2
9/126
5.0
(127.0)
989.8
4.62
(4.88)
51. 6/
48.4
0.518
(0.196)
10
13/93
4.5
(114.3)
999.1
4.59
(4.84)
69. 8/
30.2
2.59
(0.98)
20
16/77
4.0
(101.6)
1009.5
4.55
(4.80)
78. 8/
21.2
5.19
(1.97)
30
17/61
4.0
(101.6)
1009.5
4.55
(4.80)
82. 3/
17.7
8.57
(3.24)
40
19/52
4.0
(101.6)
1009.5
4.55
(4.80)
84. 7/
15.3
11.14
( 4.22)
Mech.
Wet
22/0
3.60
(91.4)
1017.4
4.53
(4.78)
100. O/
0.0
27.91
(10.57)
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimiEed wet tower
-------
TABLE 4.3
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS (S1Q6)
SITE: KAIPAROWITS, UTAH YEAR: 1985 HET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Hater
& Maintenance)
Total Evaluated
Cost (Sura of Capital &
Penalty Costs)
Mech.
Dry (H)*
79.37
71.16
38.56
189.09
Mech.
Dry (L)'
179.90
46.63
22.17
248.70
Percentage Make-up Requirement*7
Mechanical Series Wet/ Dry
2
120.42
39.35
17.78
177.55
10
105.37
33.44
20.46
159.27
20
101.85
28.49
21.22
151.56
30
95.58
28.14
23.97
147.69
40
92.28
27.83
25.08
145.19
Mech.
Met
68.84
20.59
15.37
104.80
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.4
MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR OPTIMIZED COOLING TOWER SYSTEMS (S106)
SITE! KAIPAROWITS, UTAH
YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Hater System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost;
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
39.42
10.78
7.91
0.00
5.39
15.87
79.37
60.48
10.67
26.47
8.29
0.00
3.81
109.72
Mech.
Drya)'
101.06
15.07
14.43
0.00
13.27
35.97
179.90
24.27
22.36
-0.76
14.32
0.00
8.61
68.80
Percentage Make-up Reauirement-Mech. Ser. Wet/Dry
2
49.23
11.80
11.75
15.48
8.08
24.08
120.42
24.00
15.35
3.29
9.35
0.10
5.04
57.13
10
40.07
10.10
9.20
18.52
6.41
21.07
105.37
19.34
14.11
8.11
7.68
0.49
4.18
53.91
20
36.26
10.12
9.28
20.08
5.74
20.37
101.85
14.30
14.19
8.53
7.75
0.98
3.95
49.70
30
31.30
10.18
9.36
20.64
4.98
19.12
95.58
14.30
13.85
10.54
8.15
1.62
.3.67
52.13
40
29.34
9.83
8.94
21.13
4.58
18.46
92.28
14.30
13.54
11.26
8.20
2.11
3.52
52.93
Hech.
Wet
12.98
10.28
6.68
23.58
1.56
13.76
68.84
10.49
10.10
1.31
6.94
5.27
1.84
35.95
* H-Hlgh Back Pressure Turbine
f I.-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.5
BASE COOLING SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS ($106J
SITE: KAIPAROWITS, UTAH
YEAR: 1985
WET/DKY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water System
Electric Equipment
Indirect Cost
Total Capital Cost of
Base Cooling System**
Penalty Cost:
Capacity Loss
Power for Tower Fans &
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Pumping Energy
Cooling System Maintenance
Total Penalty Coat of
Base Cooling System**
Make-up Water Penalty Cost:
Make-up Water Purchase &
Treatment Cost
Capital Cost for Make-up
Water Supply Facllltleett
Power and Energy Cost for
Pumping Make-up Water
Total Make-up Water Penalty
Colt
Total Evaluated Cost of the
Complete Cooling System
Mech.
Dry 00*
39.42
10.78
7.91
5.39
15.87
79.37
60.48
9.67
26.47
8,29
3.81
109.72
0.00
0.00
0.00
0.00
189.09
Mech.
Dry (L)t
101.06
15.07
14.43
13.27
35.98
179.90
24.27
22.36
-0.76
14.32
8.61
68.80
0.00
0.00
0.00
0.00
248.70
Percentage Make-up Requirement #
Mechanical Series Wet/Dry
2
49.23
11.80
11.75
8.08
20.21
101.07
24.00
12.96
3.29
9.30
5.04
34.59
0.10
19.35
2.44
21.89
177.55
10
40.07
10.10
9.20
6.41
16.44
82.22
19.34
10.88
8.11
7.42
4.18
49.92
0.49
23.15
3.50
27.14
159.27
20
36.26
10.12
9.28
5.74
15.35
76.75
14.30
10.52
8.53
7.23
3.95
44.53
0.98
25.10
4.20
30.28
151.56
30
31.30
10.16
9.36
4.98
13.96
69.78
14.30
10.02
10.54
7.28
3.67
45.58
1.62
25.80 .
4.70
32.11
147.69
40
29.34
9.83
8.94
4.58
13. 18
65.87
14.30
9.57
11.26
7.08
3.52
45.71
2.11
26.41
5.10
33.62
145. 19
Mech.
Wet
12.98
10.28
6.68
1.56
7.87
39.37
10.49
5.43
1.31
4.17
1.84
23.25
5.27
29.47
7.44
42.18
104.80
* H - High Back Pressure Turbine
t L - Low Back Pressure Turbine
<> Percentage of annual make-up required by optimized wet tower
36
• Base Cooling System - Cooling
system without make-up and
water treatment facilities
rIncluding 25% direct capital cost as
Indirect capital cost
-------
TABLE 4.6
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($10 )
SITE: SAN JUAN, NEW MEXICO YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (Si)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Bower)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
79.43
68.70
42.76
190.89
Mech.
Drya>'
168.75
47.64
26.10
242.49
percentage natce-up Requirement »
Mechanical Series Wet/Dry
2
122.74
39.36
22.42
184.51
10
101.92
31.81
22.78
156.51
20
92.43
. 25.84
22.41
140.68
30
87.90
20.99
21.11
130.00
40
81.33
19.84
21.66
. 122.83
Mecb.
Wet
47.63
12.04
13.49
73.16
* H-Hlgh Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.7
BASE COOLING SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS (SIP6)
SITE: SAN JUAN, NEW MEXICO YEAR: 1985 WET/DRV TYPE: MECHANICAL SERIES (SI)
Capital Coat:
Cooling Tower
Condenser
Circulating Water System
Electric Equipment
Indirect Coat
Total Capital Cost of
Base Cooling System**
Penalty Cost:
Capacity Loss
Power for Tower Fans &
Circulating Water Pumpa
Replacement Energy
Fan Energy & Circulating
Water Pumping Energy
Cooling System Maintenance
Total Penalty Cost of
Baae Cooling System**
Make-up Water Penalty Cost:
Make-up Water Purchase &
Treatment Cost
Capital Coat for Make-up
Water Supply Facilities**
Power and Energy Cost for
Pumping Make-up Water
Total Make-up Water Penalty
Cost
Total Evaluated Cost of the
Complete Cooling System
Mech.
Dry (H)*
39.07
11.26
7.86
5.36
15.88
79.43
57.54
11.16
29.62
9.23
3.91
111.46
0.00
0.00
0.00
0.00
190.89
Mech.
Dry (L)t
95.58
14.46
12.51
12.45
33.75
168.75
24.27
23.37
0.49
17.45
8.15
73.73
0.00
0.00
0.00
0.00
242.48
Percentage Make-up Requirement*
Mechanical Series Wet/Dry
2
60.20
12.07
11.70
9.81
23.45
117.23
24.01
15.18
4.48
12.19
5.64
61.50
0.10
5.50
0.18
5.78
184.31
10
47.27
10.81
10.26
7.60
18.98
94.92
19.37
12.17
8.04
9.52
4.71
53.81
0.48
7.00
0.30
7.78
156.51
20
41.84
10.12
9.16
6.62
16.92
84.66
14.30
11.22
8.54
8.62
4.19
46.88
1.00
7.76
0.38
9.14
140.68
30
38.11
10.14
9.40
6.01
15.91
79.57
9.64
10.99
7.00
8.51
4.04
40.18
1.47
8.32
0.45
10.24
130.00
40
34.43
9.66
8.82
5.29
14.55
72.75
9.64
9.82
7.98
7.82
3.75
39.01
1.98
8.59
0.50
11.07
122.83
Mech.
Wet
12.39
10.13
6.50
1.52
7.63
38.17
6.48
5.12
2.23
4.23
1.81
19.87
4.92
9.46
0.74
15.12
73.16
* H - High Back Pressure Turbine
* L - Lou Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
Base Cooling System - Cooling
system without make-up and
water treatment facilities
' Including 25% direct capital cost
as indirect capital cost
38
-------
SITE: COLSTRIP, MONTANA
TABLE 4.8
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS (?106j
YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
79.14
68.23
37.38
184.75
Mech.
Dry(L)'
168.62
47.28
22.94
238.84
Percentage Make-up Requirement #
Mechanical Series Wet/Dry
2
127.58
38.65
18.64
184.87
10
107.11
32.08
20.09
159.28
20
100.56
26.53
20.59
147.68
30
100.99
21.88
19.32
142.19
40
96.22
21.09
19.63
136.94
Mech.
Wet
66.30
14.86
13.60
94.76
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.9
BASE COOLINQ SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS ($106)
SITE: COLSTRIP, MONTANA YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Coat:
Cooling Tower
Condenser
Circulating Water System
Electric Equipment
Indirect Cost
Total Capital Cost of
Base Cooling System**
Penalty Cost:
Capacity Loss
Power for Tower Fana t,
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Pumping Energy
Cooling System Maintenance
Total Penalty Cost of
Base Cooling System**
Make-up Water Penalty Cost:
Make-up Water Purchase &
Treatment Cost
Capital Cost for Make-up
Water Supply Facilities It-
Power and Energy Cost for
Pumping Make-up Water
Total Make-up Water Penalty
Cost
Total Evaluated Cost of the
Complete Cooling System
Mech.
Dry (H)*
39.07
10.82
3.06
5.36
15.83
79.14
57.43
10.60
25.67
7.91
3.79
105.61
0.00
0.00
0.00
0.00
184.75
Mech.
Dry (L)t
93.49
14.46
14.65
12.30
33.72
168.62
24.27
23.02
-0.13
14.98
8.09
70.23
0.00
0.00
0.00
0.00
238.85
Percentage Make-up Requirement*
Mechanical Serial Wet/Dry
2
57.44
11.26
11.06
9.34
22.27
111.37
23.98
13.77
3.38
9.73
5.42
56.28
0.09
16.21
0.92
17.22
184.87
10
41.36
10.81
10.43
6.75
17.33
86.68
19.34
11.39
7.32
7.74
4.38
50.17
0.51
20.42
1.50
22.43
159.28
20
36.94
10.10
9.48
5.93
15.62
78.07
14.30
10.64
8.08
7.25
3.99
44.26
1.01
22.48
1.86
25.35
147.68
30
36.74
9.85
9.02
5.66
15.32
76.59
9.65
10.44
6.43
7.13
3.92
37.57
1.45
24.39
2.19
28.03
142.19
40
33.40
9.63
8.90
4.99
14.22
71.14
9.65
9.56
6.92
6.66
3.65
36.44
1.91
25.07
2.38
29.36
136.94
Mech.
Wet
11.80
10.44
7.43
1.55
7.82
39.04
7.41
5.31
1.75
3.89
1.95
20.31
4.78
27.27
3.36
35.41
94.76
* H - High Back Pressure Turbine
t L - Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
Base Cooling System - Cooling
system without make-up and
water treatment facilities
Including 257. direct capital coat
Indirect capital cost
40
-------
TABLE 4.10
MAJOR COST SUMMARY FDR OPTIMIZED COOLING TOWER SYSTEMS ($106)
SITE: YOUNG, NORTH DAKOTA YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
78.89
68.61
28.22
175.72
Mech.
Dry(L)'
171.16
48.13
18.73
238.02
percentage MaKe-up Requirement 7
Mechanical Series Wet/Dry
2
113.63
37.71
14.46
165.80
10
90.39
34.74
16.17
141.30
20
90.75
25.35
15.17
131.27
30
82.68
24.19
16.30
123.17
40
76. 66
23.86
17.46
117.98
Mech.
Wet
53.45
14.81
10.54
78.80
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.11
BASE COOLINQ SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS ($106)
SITE: YOUNG, NORTH DAKOTA
YEAR: 1985
WET/DOT TYPE: MECHANICAL SERIES (SI)
Capital Coat;
Cooling Tower
Condenser
Circulating Wacer System
Electric Equipment
Indirect Cost
Total Capital Cost of
Base Cooling System**
Penalty Cost:
Capacity Loss
Power for Tower Fans &
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Pumping Energy
Cooling System Maintenance
Total Penalty Coat of
Base Cooling System**
Make-up Water Penalty Cost:
Make-up water Purchase &
Treatment Cost
Capital Cost for Make-up
Water Supply Facilities-H-
Power and Energy Coat for
Pumping Make-up Water
Total Make-up Water Penalty
Cose
Total Evaluated Cost of the
Complete Cooling System
Mech.
Dry (H)*
38.72
11.23
7.85
5.32
15.77
78.89
57.49
11.12
18.45
5.88
3.89
96.83
0.00
0.00
0.00
0.00
175.72
Mech.
Dry (L)t
93.83
15.77
14.80
12.52
34.24
171.16
24.27
23.87
-0.35
10.64
8.44
66.87
0.00
0.00
0.00
0.00
238.02
Percentage Make-up, Requirement*
Mechanical Series Wet/Dry
2
51.08
11.79
11.62
8.41
20.72
103.62
23.90
13.52
2.48
6.79
5.08
51.77
0.10
10.02
0.29
10.41
165.80
10
37.63
10.09
9.16
6.13
15.75
78.76
23.86
10.51
6.57
5.18
3.96
50.08
0.44
11.62
0.40
12.46
141.30
20
37.42
9.87
8.94
5.91
15.53
77.67
14.30
10.59
5.09
5.18
3.99
39.15
0.86
13.08
0.51
14.45
131.27
30
31.97
9.59
8.83
4.92
13.81
69.12
14.30
9.40
6.64
4.68
3.59
38.61
1.32
13.56
0.56
15.44
123.17
40
27.45
9.63
8.91
4.28
12.56
62.83
14.30
9.06
7.53
4.66
3.34
38.89
1.82
13.84
0.60
16.26
117.98
Mech.
Wet
12.39
10.11
6.50
1.52
7.63
38.15
9.05
5.16
1.32
2.77
1.81
20.11
4.40
15.31
0.83
20.54
7S.80
* H - High Back Pressure Turbine
* I. - Low Back Pressure Turbine
# P«rc«ntei(« of annual make-up required
by optlmlced wet tower
42
** Base Cooling System - Cooling
system without make-up and
water treatment facilities
tt Including 25% direct capital cost as
Indirect capital cost
-------
TABLE 4.12
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($IQ)
SITS: ROCK SPRINGS, WYOMING
YEAR: 1985 WET/DKY TYPE: MECHANICAL SERIES (SI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replaceaent & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
76.32
62.84
39.41
178.57
Mech.
Dry(L)'
146.01
43.92
21.50
211.44
Percentage Make-up Requirement?
Mechanical Secies Wet/Dry
2
115.75
36.71
18.85
171.30
10
110.18
26.71
18.73
155.62
20
103.63
21.54
18.72
143.88
30
98.92
20.52
19.81
139.25
40
94.00
19.74
20.20
133.94
Mech.
Wet
69.95
11.93
13.61
95.49
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.13
BASE COOLING SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS ($108)
SITU: ROCK SPRINGS, WYOMING YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (Si)
Capital Cost:
Cooling Tower
Condenaer
Circulating Water System
Electric Equipment
Indirect Cost
Total Capital Coat of
Base Cooling Eye tern**
Penalty Cost:
Capacity Loss
Power for Tower Fans &
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Hater Pumping Energy
Cooling System Maintenance
Total Penalty Coat of
Base Cooling System**
Make-up Water Penalty Cost:
Make-up Water Purchase &
Treatment Cost
Capital Cost for Make-up
Water Supply FacllitlestT
Power and Energy Cost for
Pumping Make-up Water
Total Make-up Water Penalty
Cost
Total Evaluated Cose of the
Complete Cooling System
Much.
Dry (H)*
37.67
10.79
7.40
5.19
15.26
76.32
52.39
10.46
27.49
8.22
3.70
102.25
0.00
0.00
0.00
0.00
178.57
Mech.
Dry
-------
TABLE 4.14
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($106>
SITE: NEW HAMPTON, HEW YORK YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Hater
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
75.34
64.70
156.86
296.90
Mech.
DryCL)'
141.14
44.54
68.64
254.32
Percentage Make-up Requirement f
Mechanical Series Wet/Dry
2
115.22
37.74
68.52
221.48
10
110.83
27.78
66.30
204.91
20
107.49
22.80
63.70
193.99
30
99.31
21.80
67.75
188.86
40
92.95
21.43
70.71
185.09
Mech.
Wet
68.92
13.64
28.94
111.50
.p-
in
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 4.15
BABE COOLINO SYSTEM COST AND MAKE-UP WATER PENALTY COST COMPONENTS QlO6)
SITE: HEW HAMPTON, NEW YORK YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (Si)
Capital Cost:
Cooling Tower
Condenser
Circulating Water System
Electric Equipment
Indirect Cost
Total Capital Cost of
Base Cooling System**
Penalty Cost:
Capacity Loss
Power for Tower Fans &
Circulating Water Pumps
Replacement Energy
Fan Energy & Circulating
Water Pumping Energy
Cooling System Maintenance
Total Penalty Cost of
Base Cooling System**
Make-up Water Penalty Cost:
Make-up Water Purchase &
Treatment Cost
Capital Cost for Make-up
Water Supply Facilities?*
Power and Energy Cost for
Pumping Make-up Hater
Total Make-up Water Penalty
Colt
Total Evaluated Cost of the
Complete cooling System
Mech.
Dry (H)*
36.98
10.79
7.40
5.11
15.06
75.34
54.29
10.41
118.09
35.11
3.66
221.56
0.00
0.00
0.00
0.00
296.90
Mech.
Dry (L)t
75.69
14.39
12.67
10.16
28.23
141.14
24.72
19.83
1.03
60.62
6.98
113.13
0.00
0.00
0.00
0.00
254. -n
Percentage Make-up Requirement*
Mechanical Series Wet/Dry
2
49.70
11.82
11.63
8.20
20.33
101.68
23.99
13.14
21.20
42.24
5.00
105.57
0.01
13.54
0.68
14.23
221.48
10
46.01
10.82
10.58
7.42
18.71
93.54
14.30
12.54
23.45
37.66
4.75
92.70
0.03
17.29
1.35
18.67
204.91
20
42.67
10.45
10.53
6.77
17.60
88.02
9.65
12.00
22.18
36.00
4.65
84.48
0.06
19.47
1.96
21.49
193.99
30
37.82
10.15
9.48
5.73
15.79
78.97
9.65
10.90
28.99
33.46
4.01
87.01
0.09
20.34
2.45
22.88
188.86
40
32.94
10.17
9.56
5.04
14.42
72.13
9.64
10.51
32.13
33.11
3.74
89.13
0.12
20.82
2.89
23.83
185.09
Mech.
Wet
15.93
10.83
7.53
1.92
9.06
45.27
5.99
6. 09
2.36
20.16
2.21
36.81
0.30
23.66
5.46
29.42
111.50
* II - High Back Pressure Turbine
t L - Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
46
** Base Cooling Syecem - Cooling
system without make-up and
water treatment facilities
tt Including 25% direct capital cost ae
Indirect capital cost
-------
ROCK SPRINGS, WYOMING
NEW HAMPTON, NEW YORK
KAIPAROWITS,
UTAH
YOUNG, NORTH DAKOTA
SAN JUAN,
NEW MEXICO
Figure 4.1 Coal Fields of the United States and Sites for the Water Conservation Analysis
-------
120 -,
100 -J
80 -J
v£>
O
S 60
40 -
20 -
0
Total Evaluated Cost
Range (°C)
10
15
I I
1'8 20
26
Range (°F)
30
32
Figure 4.2 Typical Capital and Penalty Trade-dff for Mechanical
Wet Tower Systems (Kaiparowits, Constant Approach =
19°F
48
-------
130 4-
s
•a 110
a
41
I
<-4
I
^ 100
Curve
1
2
3
4
5
10
Approach, °F (°C)
16 ( 8.9)
18 (10.0)
20 (11.1)
22 (12.2)
25 (13.9)
Range (°C)
15
2!)
A
24
Range
28
30
32
Figure 4.3 Effect of Approach Temperature on the Optimum Selection of Che
Wet Tower System (Kaiparowits, Mechanical -Wet Tower, 1985)
34
-------
m
a
r-
3
fi
190- -
ISO" -
170- *
160- •
150- .
u
16
Curve
A
B
C
D
10
ITD, °F (°C)
60 (33.3)
66 (36.7)
71 (39.4)
74 (41.1)
Design Back Pressure,
In-HgA, (wn-HgA)
3.5
4.0
4.5
5.0
( 88.9)
(101.6)
(114.3)
(127.0)
Range (°C)
15
_J
18
20
22
24
Range
26
~T
28
T~
30
32
-r
34
Figure 4.4 Optimization of a 10 Percent Wet/Dry System for a Series of Specified Design
Back Pressures (Kaiparouits, Mechanical Series, SI Mode)
-------
150
100
o
l-i
•co-
4J
to
50 --
0
Total Evaluated Cost
Capital Cost
Penalty Cost
Specified Design Back Pressure
80
I
100
(mm-HgA)
120
**t I ,1 I
3.0 4.0
Specified Design Back Pressure (in-HgA)
Figure 4.5 Optimum Selection and Economic Trade-offs
of a 10 Percent Wet/Dry System
(Kaiparowits, Mechanical Series, Si Mode)
5.0
51
-------
NJ
Or
12
•r-l
U
a
•u
u
*
1040 .
1020 .
1000
980 _
960 _
940 _
Base Generator Output
Gross Generator Output
Net Generator Output
1000
2000
3000 4000 5000 6000
Cumulative Duration (hrs)
7000
8000
120
-.100
80
60
40
20
9000
Figure 4.6
Performance Curves for a 10 Percent Mechanical Series
Wet/Dry Cooling System at Kaiparowits, Utah
(0
CO
(U
u
O
08
-------
3 ..
2 - -
a
M
1 . .
•- 1.0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 4.7 Total Make-up Requirement for Each Monthly Period at San Juan, New Mexico
NOTE: Curves are drawn through the discrete points to facilitate visual observation
-------
9000 • •
8000 ••
7000 -•
6000 • •
5000 • -
4000 •
3000 .
2000 •
1000 •
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nob Dec
Figure 4.8 Maximum Make-up Flow Rate for Each Monthly Period at San Juan, New Mexico
NOTE: Curves are drawn through the discrete points to facilitate visual observation
-------
vO
O
225 . .
200 --
175 --
150 --
125 --
I 100 +
0
u
&
50 --
25 --
New Hampton, Mew York
Kaiparowits, Utah
Colstrip, Montana
Rock Springs, Wyoming
San Juan, New Mexico
Young, North Dakota
10 20 30 40 50 60 70
Percentage Make-up Requirement (7. of Wet System)
80
90 100
Figure 4.9 Comparison of Alternate Sites Including Water Supply Costs
-------
225 „_
200 . .
175.-
150 - -
vO
s
CO
~ 125
a
a
u
75 . .
50 . .
25 --
New Hampton, New York
Cols trip, Montana —-.
San Juan, New Mexico
Kaiparowits, Utah
Young, North Dakota
Rock Springs, Wyoming
10 20 30 40 50 60 70
Percentage Make-up Requirement (7. of Wet System)
80
90 100
Figure 4.10 Comparison of Alternate Sites Excluding Water Supply Costs
-------
SECTION 5
ENGINEERING EVALUATION AND ECONOMIC SENSITIVITY ANALYSIS OF
WET/DRY COOLING SYSTEMS FOR WATER CONSERVATION
5.1 INTRODUCTION
This chapter describes the engineering and economic evaluation of wet/dry
cooling towers for water conservation. The major objectives of this
evaluation are to determine the effect of the wet/dry tower system design
parameters on the economics of wet/dry cooling and to compare the costs of
the three types (see Section 3.2.2) of wet/dry tower systems. To accomplish
these objectives, a systematic study of each of the three systems was per-
formed using the Kaiparowits, Utah site conditions. Two operational modes,
Si and S2, were considered. Conventional low back-pressure turbines limited
to 5 in-HgA (127 mm-HgA) were employed.
5.2 EVALUATION OF SYSTEM CONFIGURATION AND OPERATING MODE
This section presents the results of a cost comparison of the operating
modes and the wet/dry system configurations (mechanical series, mechanical
parallel, natural series). All comparisons are based on optimized systems.
5.2.1 Operating Mode
An optimization was performed for mechanical series wet/dry tower systems
operating in both the Si and S2 modes. For each of the operational modes,
the optimized systems were obtained for a series of specific make-up water
requirements in increments of five percent. Comparison was made between
the two modes to select the least cost system.
Figure 5.1 shows the total evaluated cost versus percentage make-up for
wet/dry systems operating in the Si mode optimized at constant specified
back-pressures. Each constant back-pressure curve is obtained by plotting
the minimum total evaluated cost of different percentage make-up systems
optimized at that back-pressure. Figure 5.2 shows similar information for
systems operating in Mode S2. Comparison of these two figures shows a
fundamental difference. Operating in Mode Si, the optimum design back-pres-
sure changes as the percentage make-up requirement changes. For systems
operating in Mode S2, however, the minimum cost system always occurs at the
maximum specified design back-pressure (5 in-HgA Q.27 mm-HgA]).
The summary results of the design, cost and penalty of the optimized systems
for the Si mode are given in Tables 4.2 through 4.5 for the Kaiparowits site.
The summary results of design, cost and penalty of the optimized systems for
57
-------
the S2 mode are given in Tables 5.1, 5.2 and 5.3 Detailed results are given
in Appendices F and G.
Comparisons between the tabulated results for the S2 mode and the corres-
ponding results for the Si mode presented in Section 4 indicate for the same
make-up percentage: 1) the system optimized for the Si mode requires more
wet cells and less dry cells than that for the S2 mode, and 2) the optimum
systems designed for the Si mode have consistently lower capacity penalty
cost, but higher energy cost.
A graphical comparison of the total evaluated costs of the optimized systems
for the Si and S2 modes are given in Figure 5.3. The figure shows that ex-
cept for the 40 percent system the costs of the wet/dry systems designed to
operate in the Si mode are consistently less expensive than those designed
to operate in the S2 mode. For this reason, the optimized systems presented
in Section 4 for the mechanical series are all designed to operate in the Si
mode.
5.2.2 Mechanical Series vs. Mechanical Parallel
Detailed calculations for the parallel water flow configurations were
limited to Mode PI because, analogous to series-connected wet/dry systems,
this operational mode was consistently less expensive than Mode P2.
A summary of the data for the optimized systems is given in Tables 5.4
through 5.6. Detailed results are given in Appendix H. A direct comparison
of the capital and penalty costs for the series and parallel systems is
given in Figure 5.4.
The comparison shows that the parallel systems are consistently more expen-
sive than the corresponding series systems. For systems with percentage
make-up less than 20 percent, the capital costs of the two types of systems
are approximately equal with the penalty costs accounting for most of the
difference in the total. For systems greater than 20 percent, the cost dis-
advantage of the parallel system is primarily in the capital cost.
5.2.3 Mechanical Series vs. Natural Series
In comparison with mechanical draft towers, the capital cost of the natural
draft cooling towers designed for the same heat rejection capability can be
more expensive than the mechanical draft because of the costs associated
with the massive concrete shell. The natural draft system can be less
expensive in terms of total evaluated cost because of the elimination of
both capacity and energy penalties for the cooling tower fans and a reduc-
tion in electrical equipment costs. To determine if there is an economic
advantage available with the use of natural draft dry towers, an evaluation
of the natural series wet/dry cooling system was performed.
A summary of the data for the optimized systems is given in Tables 5.7
through 5.9. Detailed results are given in Appendix I. A direct comparison
of capital, penalty, and total evaluated costs for the mechanical series
and natural series systems is given in Figure 5.5. The comparison of total
58
-------
evaluated costs demonstrates an economic advantage of natural over mechanical
series systems, for higher percentage make-up requirements.
This comparison clearly shows the trade-off of capital and auxiliary penalty
costs between the two types of systems. For the twenty percent make-up sys-
tem, the auxiliary penalty advantage of the natural draft system is practi-
cally offset by the capital cost of the tower, and the overall advantage of
the natural draft system is small. This advantage increases with increasing
percentage make-up requirement.
5.2.4 Comparison of the Three Types of Wet/Dry Cooling Systems
The overall comparison of the total evaluated cost of the three types of
wet/dry tower systems is shown in Figure 5.6. This comparison is included
to better portray the relative economic advantages of the three systems.
While the natural draft system enjoys a cost advantage, the economic and
performance data available from the manufacturers for natural draft dry
towers are limited. For this reason, there is some uncertainty associated
with the economics and performance values developed. The major advantage
of the mechanical draft system is its engineering and operational flexi-
bility. The modules are small, easily isolated for maintenance and repair.
The operation can be reasonably well predicted since the airflow is control-
led.
5.3 ECONOMIC SENSITIVITY ANALYSIS
The results presented in Sections 4 and 5.2 are projected 1985 costs based
on one set of economic factors. The principal economic factors which in-
fluence the cooling system design and system costs are: replacement capacity
charge ($/kWe), fuel cost ($/MBtu or $/Joule), annual fixed charge rate
(percent) and escalation rates of material, equipment and labor (percent).
A comprehensive economic sensitivity analysis was completed to determine
the effects that changes in the economic parameters will have on system size,
capital cost, and the total evaluated cost.
All of the systems described so far were optimized using a base set of
economic data representative of a 1985 start-up date. These systems are
referred to as the "base systems". The economic sensitivity analysis is
divided into two parts. In the first part, each cooling system was reopti-
mized using the economic factors shown in Table 5.10. This part of the
sensitivity analysis is called "optimization analysis". For this optimiza-
tion, each of the four factors was varied sequentially while keeping the
other three factors constant. In this way, optimized systems for each new
set of economic factors were obtained.
A second part of the sensitivity analysis is called "transfer analysis".
In this analysis, the "base system" design is kept unchanged, and the indi-
vidual elements of the capital and penalty costs are adjusted by prorating
the cost elements affected by the new economic factors. Finally, a compari-
son is made between the results of the "transfer" and "optimization" analyses,
59
-------
The objectives of the sensitivity analysis were: (1) to determine how much
change would occur in the total evaluated cost of each of the optimized
cooling systems in response to the changes in economic factors; (2) to
determine how sensitive is the selection of the optimum design to changes
in the economic factors; and (3) to determine whether the "transfer" type
analysis can be used to estimate the minimum total evaluated cost of cooling
systems without introducing significant errors.
5.3.1 Results of Economic Sensitivity Analysis
The sensitivity of the total evaluated cost corresponding to the change in
economics is shown in Table 5.11. In this table, the data are given in
terms of percentage change in the total evaluated costs relative to the
base values. The results presented can be used to estimate the total evalua-
ted costs of the tower systems for economic factors other than those used in
the base analysis.
The transfer analysis is performed by taking the "base system" design and
adjusting the total evaluated cost for the new economics. For example, if
the escalation rate was 12 percent per year, rather than 6 percent, all of
the capital cost elements would be increased proportionately to provide a
new total evaluated cost value. Comparisons of the results of the "trans-
ferred analysis" and the optimization analysis are shown in Figures 5.7
through 5.10. The format for each of the figures is described below:
1. A single bar representing the optimum base 1985 cooling system
(fixed charge rate of 18 percent, fuel cost of $1.00/MBtu
C$0.95/Gj], replacement capacity of $485/kWe, material escala-
tion multiplier of 1.91 and labor escalation multiplier of
2.29).
2. Two sets of bars which represent the impact of the fixed
charge rate (12.5% and 25%).
3. Three sets of bars which represent the impact of material/labor
cost escalations (07o/0%, 12.2%/16.6%, 19%/21%).
4. Three sets of bars which represent the three fuel costs ($0.50,
$2.50 and $5/MBtu [$0.47, $2.37 and $4.74/Gj]).
5. Three sets of bars which represent the three replacement
capacity charges ($225, $700 and $970/kWe).
By referring to the results shown in Figures 5.7 through 5.10, the following
observations can be made:
1. In most cases, variations of economic factors result in differ-
ent optimum cooling system designs. This is reflected in the
bar graphs by the slight difference in capital costs between
the optimized systems and the "transferred" systems. Among
the four factors studied, the trend is as follows:
a) Capital costs escalations (material and labor) have the
strongest effect of the selection of the optimized
systems. In almost all cases involving the effect of
60
-------
capital cost escalation, the reoptimized systems result
in significantly different designs compared to the "trans-
ferred" systems.
b) Variation of annual fixed charge rate has minimal effect
on the selection of optimum systems, resulting in almost
the same costs for the optimized and the "transferred"
systems.
2. Even for the large variations used in this study, e.g., material
and labor cost escalations which are three times the base
value, fuel charges five times the vase value and capacity
charges two times the base value, the difference in total
evaluated cost between the optimized and transferred systems
is less than four percent.
5.3.2 Conclusion of Economic Sensitivity Analysis
An important conclusion can be drawn from the sensitivity analysis which
is useful for cost estimating purposes. In response to changing economics,
the minimum total evaluated cost of a cooling system can be estimated from
an optimized "base system" without requiring reoptimization using the new
set of economic factors. The adjustment can be made by simply prorating
the cost elements comprising the total evaluated cost of the base system.
A similar economic sensitivity analysis performed for nuclear power plant
cooling systems (1) has reached the same conclusion.
61
-------
TABLE 5.1
MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: KAIPAROWITS, UTAH BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (S2)
Item
Number of Tower Cells,
Wet Tower/Dry Tower
Maximum Operating Back
Pressure ?__.., in-HgA
(inn-HgA)
Gross Plant Output at
Heat Load at Pmax» lo<)
Btu/hr (1012 J/hr)
Heat Load Distribution
at P,aax» (Wet Tower/Dry
Tower) , %
Annual Make-up Water
for Wet Towers, 10° gal
(106
-------
TABLE 5.2
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($10 )
SITE: KAIPAROWITS, UTAH YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (S2)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
**
Mech.
Dry(L)f
**
Percentage Make-up Requirement*
Mechanical Series Wet/Dry
10
109.94
38.40
16.76
165.10
20
101.15
37.76
16.74
155.65
30
94.88
36.85.
16.50
148.23
40
89.02
36.39
17.09
142.50
Mech.
Wet
**
O»
id
* H-Hlgh Back Pressure Turbine
L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
** Given in Table 4.3
-------
TABLE 5.3
MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR OPTIMIZED COOLIHG TOWER SYSTEMS ($10 )
SITE: KAIPAROWITS, UTAH
YEAR: 1985
WET/DRY TYPE: MECHANICAL SERIES
-------
TABLE 5.4
MAJOR DESIGN DATA FOR THE OPTIMIZED COOLIHG TOWER SYSTEMS
SITE: KAIPAROHITS, UTAH BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL PARALLEL (PI)
Item
Number of Tower Cells,
Het Tower/Dry Tower
Maximum Operating Back
Pressure Pmax, in-HgA
(mn-HgA)
Gross Plant Output at
Poax- MWe
Heat Load at ?___, 109
Btu/hr (1012 JThr)
Heat Load Distribution
at Pmax, (Wet Tower/Dry
Tower), %
Annual Make-up Water
for Wet Towers, 108 gal
(106 m3)
Mech.
Dry (H)*
**
'. •"
Mech.
**
Percentage Make-up Requires*
Mechanical Parallel Wet/Dr
2
9/123
5.0
(127.0)
989.8
4.62
(4.87)
35. 9/
64.1
0.607
(0.230)
10
11/88
5.0
(127.0)
989.8
4.62
(4.87)
39. 1/
60.9
2.78
(1.05)
20
16/77
4.0
(101.6)
1009.5
4.55
(4.80)
42. 7/
57.3
5.21
(1.97)
ent#
30
17/64
4.0
(101.6)
1009.5
4.55
(4.80)
47, 3/
52.7
8.35
(3.16)
Mech.
Wet
**
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
** Given in Table 4.2
-------
TABLE S.5
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($106)
SITE: KAIPAKOHITS, UTAH
YEAR: 1985 WET/DRY TYPE: MECHANICAL PARALLEL (PI)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sun of Capital &
Penalty Costs)
Hech.
Dry
** Given In Table 4.3
* K-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 5.6
MAJOR CAPITAL AND PEHALTY COST COMPONENTS FOR OPTIMIZED COOLING TOWER SYSTEMS ($106)
SITE: KAIPAROWITS, UTAH
YEAR: 1985
WET/DRY TYPE: MECHANICAL PARALLEL (PI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water Systea
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
**
Mech.
Dry a)'
**
Percentage Make-up Requtremeiit-Mech. Para. Wet/Dry
2
48.19
11.79
12.31
16.41
7.99
24.17
120.87
23.86
15.42
3.53
9.32
0.12
5.10
57.36
10
37.13
10.44
10.59
19.09
6.20
20.86
104.31
23.86
13.77
9.86
7.45
0.52
4.33
59.80
20
36.26
10.83
12.03
21.38
6.09
21.64
108.22
14.30
15.21
7.99
7.73
0.98
4.65
50.86
30
32.36
10.44
11.73
21.80
5.47
20.45
^02.24
14.30
14.63
10.05
7.62
1.58
4.44
52.62
P Mech.
Wet
**
* H-High Back Pressure Turbine
'* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
** Given in Table 4.4
-------
TABLE 5.7
MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: KAIPAROW1TS, UTAH BASE OUTPUT: 1039 MWe WET/DRY TYPE: NATURAL SERIES (SI)
Item
Number of Wet Tower Cells
Number of Dry Towers
Number of Heat Exchangers
per Tower
Diameter/Height, ft (a)
Maximum Operating Back Pres
sure P , In-HgA (ma-ggA)
max
Gross Plant Output at
Heat Load at P_aK, 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at P,nax» (Wet Tower/Dry
Tower) , t
Annual Make-up Water
for Wet Towers, ICr gal
(106 m3)
Mech.
Dry (H)*
**
Mech.
Dry CD*
**
Percentage Make-up Requirement £
Natural Series Wet/Dry
2
10
2
268
441/449
(134/137)
5.0
(127.0)
989.8
4.62
(4.87)
61. 6/
38.4-
0.583
(0,221)
10
12
1
302
497/495
(151/151)
5.0
(127.0)
989.8
4.62
(4.87)
76. 1/
23.9
2.75
(1.04)
20
17
1
298
490/442
(149/135)
4.0
(101.6)
1009.5
4.55
(4.80)
87. 1/
12.9
5.40
(2.04)
30
18
1
240
395/400
(120/122)
4.0
(101.6)
1009.5
4.55
(4.80)
89. 7/
10.3
8.23
(3.12)
40
18
1
198
326/352
(99/107)
4.0
(101.6)
1009.5
4.55
(4.80)
92. 0/
8.0
11.51
(4.36)
Mech.
Wet
**
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
** Given in Table 4.2
-------
TABLE 5.8
MAJOR COST SUMMARY FOR OPTIMIZED COOLING TOWER SYSTEMS ($106)
SITE: KAIPAROWITS, UTAH
YEAR: 1985 WET/DRY TYPE: NATURAL SERIES ,(Sl)
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated
Cost (Sum of Capital &
Penalty Costs)
Mech.
Dry (H)*
**
Mech.
Dry (1.)'
**
Percentage Make-up Requirement*
Natural Series Wet/Dry
2
144.97
31.45
9.63
186.05
10
111.92
31.90
15.66
159.48
20
111.40
23.32
14.94
149.65
30
103.12
23.46
17.82
144.40
40
96.32
23.57
20.23
140.13
Mech.
Wet
**
* H-High Back Pressure Turbine
f L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
** Given in Table 4.3
-------
TABLE 5.9
MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR OPTIMIZED COOLIHG TOWER SYSTEMS ($10b)
SITE: KAIPAROWITS, UTAH
YEAR: 1985
WET/DRY TYPE: NATURAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
**
Mech.
Dry (D*
**
Percentage Make-up Requirement-Nat. Ser. Wet/Dry
2
72.19
12.41
12.90
17.09
1.40
29.00
144.97
23.86
7.59
2.94
2.48
0.11
4.10
41.08
10
46.37
11.25
11.06
19.48
1.37
22.38
111.92
23.86
8.05
9.29
2.63
0.52
3.21
47.56
20
46.91
10.15
9.21
21.34
1.50
22.28
111.40
14.30
9.02
7.65
3.20
1.02
3.07
38.26
30
46.01
10.13
9.21
21.76
1.54
20.63
103.12
14.30
9.16
9.60
3.74
1.55
2.92
41.27
40
40.37
10.10
9.22
22.08
1.54
19.26
96.32
14.31
9.27
10.84
4.42
2.17
2.79
43.81
Mech.
Wet
**
* H-High Back Pressure Turbine
'* I-Conventional Low Back Pressure Turbine
** Given in Table 4.4
-------
TABLE 5.10
FACTORS USED FOR ECONOMIC SENSITIVITY ANALYSIS*
Variable
Replacement Capacity, $/kWe
Fuel Cost, c/MBtu (c/GJ)
Annual Fixed Charge Rate, %
ESCALATION
MULTIPLIER
(ANNUAL BATE)
MATERIAL
AND
EQUIPMENT
LABOR
BASE
1985
485
100 (95)
18
1.91
(6.0%)
2.29
(8.0%)
225
50 (47)
700
250 (237)
970
500 (474)
12.5 25
1.10
(0.0%)
1.10
(0.0%)
3.30
(12.2%)
4.75
(16.6%)
5.75
(19.0%)
6.75
(21.0%)
* The economic sensitivity analysis is performed by holding any three
of the Base 1985 values constant and changing the fourth value.
71
-------
TABLE 5.11
IMPACT OF CHANGING ECONOMICS ON TOTAL EVALUATED COST
-------
v£>
o
CD
8
•O
QJ
4J
to
w
4J
o
H
225 --
200
175 --
150 --
125 --
100
Parameter: Design Back Pressure
in-HgA (mra-HgA)
4 (101.6)
10
15
20
25
30
35
40
Percentage Make-up Requirement (%)
Figure 5.1 Total Evaluated Costs of Optimized Wet/Dry Systems Operating in Si Mode for Various
Specified Design Back Pressures (Kaiparowits, Mechanical Series, 1985)
-------
ID
O
to
8
•o
-------
en
200-
175 —
150 --
m
O
o
Cfl
W
(0
125 --
100-
Mode S2
Mode Si
10 15 20 25
Percentage Make-up Requirement (%)
30
35
40
Figure 5.3 Comparison of the Optimized Systems Operating in the
SI and S2 Modes (Kaiparowits, Mechanical Series, 1985)
-------
200
160
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P - Mechanical Wet/Dry Parallel Fl
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10
20
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Percentage Make-up Requirement,(%)
Figure 5.4 Comparison of Series (SI) and Parallel (PI) Mechanical
Wet/Dry Cooling Tower Systems (Kaiparowits)
76
-------
200 r-
160 -
120 -
vO
O
r-l
•CO-
CO
8
cti
CO
80 -
40
M - Mechanical Series Wet/Dry
N - Natural Series Wet/Dry
- Capital Cost of Cooling Tower
- Capital Cost of Other Equipment
Auxiliary Power & Energy Penalties
—
lm
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-
M
V
N
s
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7
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2 10 20 30
Percentage Make-up Requirement (%)
40
I'igure 5.5
Comparison of Natural Series and Mechanical Series
Wot/Dry Cooling Tower Systems (Kaiparowits, Si Mode)
77
-------
oo
200
175 --
o 150
T-l
-------
LLJ
700-
100-
IZZl- RE-OPTIMIZED COOLING SYSTBHOPTiMiZATiON ANALYSIS)
^^-BASE SYSTEM
TRANSFERRED (TRANSFER ANALYSIS)
BASE ECONOMICS
FIXED CHARGE RATE =
• 182
MATERIAL ESCALATION = 1.91
LABOR ESCALATION -
FUEL COST =
REPLACEMENT
2.29
»l.UU/nBTU l»U.S:>/Ud.»
CAPACITY = $485/KWE
ESCALATION
1) MATERIAL-1.10
LABOR-l.lJJ
2) MATERIAL;?. 30
LABOR-*!. 75
3) MATER IAL-5. 75
LABOR-6.75
3
FlffD f.HARGF
1985 BASE
SYSTEM
1 9- 1
- IT
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z
RATE
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12
75
1
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FUEL COST
REPLACEMENT CAPACITY
1) $O.WfflTii (fO.W5-1)
2) $2.50/MBTU ($2.37/6J) J) $225/KHe
3) $5.00/MBTU C$q.71/6J) 2) $700/KME
, 3) $970/K«E
3 ^
2 , , <,' 2 , 77
1 t fp ^ /V l t 'PJ -. ^
5|/r3/ z ' z / u^ u*/ W ' _/ z / z ui ^ tu>
z xsr uj , lu o. ^ ft. , ^ , z tu ai / o. _/ a.
£ /£^ ^ / V './, 0. / gj1 °- ' °-/ ^ x
. ^ u ^ ^ ;^ Tel ^ ;^ ., ^
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lj_ ,'" CJ flL ' *J ^fjj- ft* ^ ^ ^^*J ^i- ^J
°^x "/:/ ^/ °x/°% "%
Figure 5.7 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, Mechanical Wet)
-------
,-QQ LZH- RE-OPTIMIZED COOLING SYSTEM (OPTIMIZATION ANALYSIS)
cj •
S2flG--
DJ
10&--
- BASE SYSTEM TRANSFERRED
BASE ECONOMICS
FIXED CHARGE RATE = 18Z
MATERIAL ESCALATION = 1.91
LABOR ESCALATION - 2.29
FUEL COST = $1.00/MB™ ($0.95/6J)
REPLACEMENT CAPACITY = $485/Klfc
FIXED CHARGE
RATE
(TRANSFER ANALYSIS)
1985 BASE
SYSTEM-
1) 12.5Z
2) 25.QZ
4
MATERIAL AND LABOR
ESCALATION
1) MATERIAL-1.10
LABOR-1.10
2) MATERIAL'S.30
LABOR-
-------
40G--
LH3 -fcE-CPTlnlZED COOLING SYSTEM (OPTIMIZATION ANALYSIS)
-BASE SYSTEM TRANSFERRED (TRANSFER ANALYSIS)
RASE ECONOMICS
FIXED CHARGE RATE » 18%
MATERIAL ESCALATION = LSI
LABOR ESCALATION = 2.29
FUEL COST = $l,00/MBnj ($0.05/GJ)
KEPLACEfCNT MATERIAL AND LABOR
CAPACITY = $4«5/K'flE ESCALATION
300--
t
3
a
20C--
100--
1985 BASE
SYSTEM
FIXED CHARGE
RATE
1) 12.52
2) 25.0%
(THESE SYSTEMS
OPTIMIZED AT
THE BASE CASE
DESIGN POINT
1) MATERIAL-1.10
LABOR-1.10
2) MATERIAL-3.30
LABOR-4.75
3) HATERIAL-5,75
FUEL COST
1) $0.50/MBTU ($OA7/GJ)
2) $2.50/MBTU ($2.37/6J)
3) S5.00/MBTU ($4.7V6J)
3
REPLACEMENT CAPACITY
1) S225/KWE
2) S700/KWE
3) $970M'E
Figure 5.9 Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, 2% Wet/Dry)
-------
400 4-
300
-HE-OPTIMIZED COOLING SYSTEM (OPTIMIZATION ANALYSIS)
-BASE SYSTEM TRANSFERRED (TRANSFER ANALYSIS)
BASE ECONOMICS
FIXED CHARGE RATE = 18%
MATERIAL ESCALATION = 1.91
LABOR ESCALATION = 2.29
FUEL COST = Sl.OO/MBru ($0.95/GJ) 3
REPLACEMENT
CAPACITY = W85/KKE
8
2004-
100
1985 BASE
SYSTEM
FIXED CHARGE
RATE
1) 12.5Z
2) 25.0%
(THE SYSTEMS
OPTIMIZED AT
THE BASE CASE
DESIGN POINT;
1
" 2
MATERIAL AND LABOR
ESCALATION
IAL- 1
- 1.10
.10
1) MATERIAL-
LABOR
2) MATERIAL-3,30
LABOR-4.75
3, MATERIAL-5,75
LABOR-R.?1)
FUEL COST
1) $0,50/HPTu ($O.WGJ)
2) $2.50/MBTu (S2.37/GJ)
3) S5.00/MBTU (11,71/GJ)
REPLACEhENT CAPACITY
1) $225/K«E
2) S700/KHE
3) $970/KWE
Figure 5.10
Effect of Economic Factors on Costs Obtained by Optimization
and Transfer Analyses (Kaiparowits, 20% Wet/Dry)
-------
SECTION 6
MATHEMATICAL MODEL FOR PLUME ABATEMENT ANALYSIS
6.1 INTRODUCTION
Fog from cooling towers occurs when a visible vapor plume containing liquid
water vapor droplets impacts the ground and reduces ambient visibility. Two
methods can be used to minimize this occurrence: (1) raise the height of the
visible plume centerline, or (2) reduce the moisture content of the plume.
The purpose of the plume abatement study was to assess the economic impact of
adding dry cooling sections on top of low profile mechanical draft cooling
towers to reduce the frequency of ground fogging. A tower designed with both
dry and wet sections contained in one structure and functioning as a single
unit is termed a hybrid wet/dry cooling tower and is shown in Figure 3.7.
In this section, the mathematical model for evaluating the plume impact of
cooling towers is presented. The optimization analysis which combines the
fogging evaluation and economic evaluation of the hybrid wet/dry tower is
presented in Section 7.
6.2 PLUME RISE AND DISPERSION
In order to determine whether the plume from an evaporative cooling tower
will touch the ground and cause surface fogging, the final height of the
plume, and the length, spread and density of the visible plume must be eval-
uated.
6.2.1 Plume Rise
Cooling tower plumes have been observed to be highly turbulent (8). One ex-
planation for this highly turbulent nature is that the energy released in the
form of latent heat enhances convective mixing within the plume and does not
significantly contribute to the overall rise of the plume. Following this
line of reasoning, only the sensible heat portion of the total heat in the
plume was used in the plume rise calculation. This same assumption has been
used by several investigators of plume rise from cooling towers (9, 10). The
calculated plume rises which result from the use of sensible heat alone repre-
sent conservative values because the predicted final rise of the plume is
lower than would be predicted by including the latent heat. This lower final
plume rise increases the probability that the plume will impact the ground
causing fog.
83
-------
One of the more widely accepted formulae for predicting plume rise has been
proposed by Briggs (It) and is stated as follows:
Ah = 1.6 F1/3 X 2/3 IT1 (6-D
where :
Ah = plume rise above stack, ft (m).
F = buoyancy flux parameter, ft/s (m /sj).
" (1 - ?0/?> gWoro2.
0 = density of plume at tower exit, Ib/ft^ (g/nr).
^ = density of ambient air, lb/ft3 (g/m3).
g = acceleration due to gravity, ft/s^ (m/s^).
W = plume exit velocity, ft/s (m/s).
r = radius of tower at top, ft (m).
U ™ average wind speed at top of tower, ft/s (m/s).
X = horizontal distance downwind of tower, ft (m).
Equation 6-1 expresses the plume rise as a function of downwind distance in
a neutral or unstable atmosphere. The maximum plume rise occurs at a down-
wind distance Xmax- Briggs reports this distance to be 119F2/5 for neutral
and unstable conditions.
Under stable conditions, Briggs recommends the following formula for the
maximum rise of the plume centerline (11) :
F 1/3
" 2-9 C-flg-) (6-2)
where:
S = restoring acceleration per unit vertical displacement
for adiabatic motion in the atmosphere (s~2).
9 = potential temperature of the atmosphere, °R (°K)
T » absolute temperature of the atmosphere, °R (°K) .
Z • elevation above ground, ft (m) .
84
-------
The constant 1.6 in Equation 6-1 is associated with an entrainment parameter
of &= 0.6, which has been postulated for chimney plumes (12) as indicated
below:
C = 1.6 when ^=0.6
In both plume rise formulae 6-1 and 6-2, the constants are proportional to
^
It has been noted that a cooling tower plume is highly turbulent and it
should be expected that this turbulence is accompanied by increased entrain-
ment as compared with a chimney-stack plume. This expectation has been
supported by observational evidence of cooling tower plumes presented by
Slawson et al. (10). Slawson found best agreement between observed and cal-
culated plume rises by assuming a constant of 1.0 or 1.5 in Equation 6-1.
An entrainment parameter of % =* 0.8 corresponds to a constant of 1.3, and is
a reasonable fit to data reported by Slawson.
As a result, an entrainment parameter of "K= 0.8 has been assumed for the
cooling tower plume rise. This results in a reduction of estimated plume
rise, and Equations 6-1 and 6-2 now become:
Ah = 1.3 F1/3 X 2/3 IT1 (6-4)
For natural draft towers, the entire amount of sensible heat in the plume is
assumed to contribute to plume rise. For the rectangular (line) induced
draft towers, the sensible heat from two cells is used to simulate the rise
of the plume from a bank of cells. This assumption is supported by an analy-
sis of a bank of seven mechanical draft towers as reported by the Applied
Physics Laboratory of Johns Hopkins University (12).
This study concluded that the seven-port plume trajectory was best predicted
by assuming: (1) the exit conditions and buoyancy flux of a single-port
plume, and (2) an entrainment constant of *&= 0.55. This is approximately
equivalent to using the buoyancy flux (F) for two cells and an entrainment
parameter of 0.8. Hence, the use of the sensible heat emitted from two cells
in Equations 6-4 and 6-5 is compatible with the conclusion of the Johns
Hopkins Study (12).
At present there have been no studies published which describe the behavior
of plumes from very large installations of mechanical draft towers. It is
recognized that the cooling towers studied in this report (25 to 40 cells)
are significantly larger than the 'seven- cell tower studied by Meyer (12).
However, based upon common design practice, the number of cells per bank has
been limited to less than 13 in this study. For the 25-cell cooling tower,
one bank of 12 cells and one of 13 cells were assumed. The 40-cell tower is
assumed to have four banks of ten cells each. A distance of one-half of the
85
-------
length of a bank is provided between banks. For example, approximately 230
feet separate the two banks of the 25-cell tower. Due to this large initial
separation of the plumes, it is reasonable to assume that the plumes grow
independently. The extrapolation of the results from a seven-cell cooling
tower study to a 10-to 13-cell bank utilizes the best data available for the
prediction of cooling tower plume behavior.
6.2.2 Length and Spread of the Visible Plume
The length of the visible plume is a function of tower operating conditions:
ambient saturation deficit, wind speed, and the rate of entrainment of am-
bient air into the cooling tower plume. At the end of the visible plume, a
sufficient amount of drier ambient air has been mixed with the moist cooling
tower effluent to reduce the water content of the plume to a level below the
saturation value.
One method of estimating the spread of the plume is to express the radius of
the plume as a function of the initial radius, exit velocity, wind speed,
plume centerline heights, and entrainment parameter. This type of relation-
ship has been used by Meyer et al. (12), and Hanna (13):
W_ 1/2
R = RO (-?-) + *s (Ah) (6-6)
where:
R = radius of visible plume, ft (m).
RQ =* initial radius of plume, ft (m).
WQ = exit velocity of plume, ft/s (m/s).
\f = entrainment parameter for plume spread.
S
Ideally, the value for Ah would be determined by using either Equation 6-4 or
6-5, depending on atmospheric stability. However, Equation 6-5 applies only
to the maximum rise in the stable case, and would not describe the radius of
the plume at distances other than point of maximum rise. For the stable
case, Briggs has noted that the plume follows the "2/3 power law" to the
point of maximum rise given by Xn,ax = -Xt US"^ (8) . For this reason, the ex-
pansion of the plume under all atmospheric conditions is described by using
Equation 6-4 to calculate &h. Substituting this Equation 6-4 into 6-6 yields
the following expression for the plume radius as a function of downwind
distance X:
RX = R0 (~-> + *s <1'3 p X
The maximum height of the centerline of the plume is given by Equation 6-4
with Xmax = 119F2'5 (neutral or unstable cases), or by Equation 6-5 (stable
cases) .
The visible plume is considered to continue expanding beyond the distance of
maximum rise by Equation 6-7 for those situations where the plume is visible
86
-------
beyond Xmax. It should be noted that for both natural draft and induced
draft towers the entire buoyancy flux (F) of the plume was utilized in the
analysis of the spread of the plume. This assumption is consistent with the
results of the study performed by Meyer et al. (12), which concluded that the
visible length was best handled by assuming entrairiment into the plume from
all seven cells.
Since the plume rise has been estimated from formulae where X- 0.8, it
might be assumed that tfs = 0.8 should be substituted in Equation 6-7. It
is noted, however, that Slawson obtained the best agreement with observed
visible plumes by using a value of tfs = 0.3. Likewise, Meyer et al. found
it necessary to "tune" their model for visible plume length by introducing
a "peak factor". The apparent inconsistency probably arises, as suggested
by Meyer (12), from a model which assumes a uniform water vapor content
across the entire visible plume, as opposed to a real condition of a concen-
tration of water vapor toward the center of the plume. It is the edges of
the plume which are eroded most by the ambient atmosphere.
The relative shielding of the plume core from the drier environmental air can
be accounted for by assuming "Xs => 0.3 in Equation 6-7. However, possible
plume impaction on the ground requires an almost saturated environment.
Under such a condition the edge effect may be less predominant, i.e.,
>$ s>0.3, than with lower relative humidities encountered in most field ex-
periments. This consideration of the physical situation, and the observa-
tions summarized in References 9 and 10, led to an estimation of plume shapes
from Equation 6-7 through the use of both ^s = 0.3 and tfs = 0.6. Possible
ground impaction was calculated for these alternative values of )JS.
The volumetric flow rate of the plume at distance X is:
Vx = TvURx2 (6-8)
A water vapor balance for the plume yields the following expression for the
water vapor in the plume at any downwind distance X:
\ - -^-
-------
v
Tx - -^- (T0 - Te) + Te (6-10)
X
where: '
TX = temperature of plume at distance X, °R (°K).
TQ = plume exit temperature, °R (°K).
Te » temperature of ambient air, °R (°K).
In order for the plume to be visible at a given downwind distance X, the
plume must be supersaturated, i.e., the water vapor content of the plume, dx,
must be greater than the saturation value at the plume temperature, ds
The difference between dx and ds in an estimate of the liquid water content
of the plume. At the end of the visible plume, the liquid water content is
assumed to be zero.
6.2.3 Criteria for Ground Level Fogging
In order for the tower plume to cause ground level fogging at a certain dis-
tance from the tower, it is assumed that two conditions must be met simul-
taneously:
1. The plume must be visible (contain liquid water droplets).
2. The radius of the plume must exceed the sum of the plume rise
and tower height.
If the plume has been determined to impact the ground for a particular
weather observation, the liquid water content of the plume and corresponding
visibility reductions are calculated. An experimentally determined relation-
ship developed by Radford and reported by George (14), is used to estimate
the visibility in the plume from the liquid water content. Figure 6-1 gives
the relationship in graphical form. The calculated visibility within the
plume is then compared to the natural visibility to determine if (1) the
plume has enhanced (thickened) any existing natural fog, or (2) if it has
caused the occurrence of ground level fog.
The total number of occurrences or hours of fog caused or enhanced by the
cooling tower within a radius of five kilometers of the tower under construc
tion is used as a measure of the tower's "fogging potential". Each occur-
rence of fog is counted as three hours in the results presented in the next
section because the meteorological data used in the fogging analysis were
recorded at three-hour intervals.
6.3 METEOROLOGICAL DATA BASE FOR PLUME ABATEMENT ANALYSIS
In performing the plume abatement analysis, the following ambient meteoro-
logical information is needed:
88
-------
1. Ambient dry bulb temperature
2. Relative humidity
3. Wind speed and direction
4. Visibility
5. Cloud cover
6. Ceiling height
This information is available from surface weather observations. Ten recent
years of surface weather observations for each of the four geographical loca-
tions studied in this section were obtained on TD 1440 format tapes from the
National Climatic Center, Asheville, North Carolina. Each ten-year record
contains data for eight observations per day taken at three-hour intervals.
The number of ambient data points for ten years is too numerous to be con-
sidered in the calculations. Therefore, a two-step selection process is
performed for each site to reduce the number of ambient data points for plume
abatement analysis.
First, all weather observations with relative humidity less than 92 percent
are eliminated. It has been often observed, with the use of the UE&C cooling
tower fogging model, that cases of fogging seldom occur when the ambient
relative humidity is less than about 92 percent.
Second, three years of ambient data with maximum fogging potential are select-
ed from the ten-year data. This is done by performing the plume analysis for
the optimized wet tower system with the data obtained in Step 1 and then
selecting the three years which have the worst fogging conditions.
This selection process yields a different three year data base for each cool-
ing tower location studied. The data bases are presented in Section 7.
In addition to the data selection process described above, the Pasquill
Stability Class is estimated from the surface data and used in the plume rise
portion of the model.
Since the wind speed recorded near the surface is not representative of the
wind speed at the top of the cooling tower, the following power law adjustment
is made:
H °'2
U ' Uo <-£->
where:
U = wind speed at tower exit height, ft/s (m/s).
U0 = measured wind speed, ft/s (m/s).
H = height of cooling tower, ft (m).
ZQ = height at which wind speed is measured, ft (m).
89
-------
A minimum wind speed of 2 knots is assigned to those observations recorded
as calm.
In order to better represent the ambient air entrained into the cooling tower
plume, thre relative humidity is adjusted to account for its vertical gradi-
ent, in certain cases, the relative humidity at plume height will be greater
than that recorded near the surface; in other cases it will be less.
When low clouds are present, the mean humidity between the surface and plume
height is assumed to be the mean value of the surface relative humidity and
100 percent, the value assumed at the cloud base. This adjustment is made
whenever the ceiling height is less than 900 feet.
Another special case which required an adjustment is the nighttime surface
observation with clear sky or scattered clouds, high ground level relative
humidity, and a stable atmosphere (E, F or G Pasquill Stability Category).
This condition usually occurs when the air near the ground is cooled by ra-
diation and brought near the point of saturation. When this occurs, the air
a few hundred feet above the ground is generally drier than the near-surface
air. To more accurately represent the humidity of the entrained air, the
surface relative humidity is reduced by three percent.
A similar adjustment of relative humidity is performed on those observations
where the relative humidity is reported to be above 97 percent when the
ceiling is greater than 800 feet. For these observations, an average rela-
tive humidity of 97 percent is assumed.
6.4 FOGGING DURING AERODYNAMIC DOWNWASH
A cooling tower structure presents an obstacle to the normal flow of the
wind. As a result, a high pressure zone is created on the windward side of
the tower while a low pressure zone in the form of a wake is present immedi-
ately downwind of the tower. When a large turbulent wake is formed, the
vapor plume exiting from the top of the tower can be deflected downward and
captured by the wake. This phenomenon is known as aerodynamic downwash. In
certain cases, enough of the plume is drawn into the wake to cause fogging
immediately downwind of the tower.
In general, the turbulent wake extends between 10 and 20 tower heights down-
wind. As a result, any occurrence of cooling tower fog caused by aerodynamic
downwash is expected to be quite localized and limited to the plant site.
The hours of fog presented in this report do not include downwash fogging.
In order to evaluate the cooling tower impact on the area surrounding the
plant site, the far-field model presented in Section 6.2 was utilized.
Fogging impact was analyzed at distances ranging from 0.3 to 5'kilometers,
and the 16 cardinal directions.
90
-------
10.0-,
1.0-
<0
0)
U
•rl
|
V)
e>
C
s
T3
•H
3
cr
0.1-
.01
10
I I
100 1000
Horizontal Visibility, feet
1
10000
Figure 6.1 Relationship Between Liquid Water
Content of Fogs and Visibility (12)
91
-------
SECTION 7
ECONOMIC OPTIMIZATION OF WET/DRY TOWERS FOR PLUME ABATEMENT
7.1 INTRODUCTION
The optimization of wet/dry tower systems for plume abatement includes the
following elements: (1) the determination of sizes and total evaluated costs
of various cooling systems, (2) the determination of fogging potentials of
these cooling systems during annual operation, and (3) the selection of min-
imum total evaluated cost systems from the systems with the same fogging
potentials.
The scope of the plume abatement study includes the evaluation of both the
mechanical draft wet and the mechanical draft hybrid wet/dry tower systems
at four urban sites across the conterminous United States. The four sites
are: Seattle, Washington; Cleveland, Ohio; Charlotte, North Carolina; and
Newark, New Jersey. These sites are selected on the basis of potential
fogging problems expected from the tower plume and geographic consideration
of sites. A discussion of site selection is given in Appendix C.
Based on the selection process, described in Section 6, to determine the me-
teorological data base at each site, the following data bases are used in the
analysis:
Location Data Base Period
Seattle, Washington 1964, 1965, 1966
Cleveland, Ohio 1964, 1966, 1973
Charlotte, North Carolina 1968, 1972, 1973
Newark, New Jersey 1971, 1972, 1975
7.2 DESIGN AND OPTIMIZATION OF WET/DRY TOWERS FOR PLUME ABATEMENT
The design and operational characteristics of wet/dry towers for plume abate-
ment are discussed in Section 3.2.3. These wet/dry towers are assumed to
operate in the wet/dry mode only when the plume fogging potential is great.
This controlled operation is accomplished through the use of meteorological
and plume monitoring and control systems which are connected into the plant's
computer system.
The wet/dry tower systems for plume abatement are. optimized for specified
fogging potential. The fogging potential is expressed in terms of the ex-
92
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pected number of hours per year during which the visible plume impacts the
ground and causes the natural visibility to be reduced to a quarter mile or
less. The optimization analysis is performed in the following three steps.
In the first step, different wet tower systems are designed to handle the
plant heat load by varying the wet tower approach and the cooling range.
The tower systems are then evaluated for thermal performance, capital and
penalty costs, and fogging potential. From these wet tower systems, all of
the systems with the same fogging potential are identified, and the minimum
cost system is selected as the optimized system for each specified fogging
potential. An optimized wet tower system, selected solely on the basis of
economics (Section 3), is referred to as the reference system.
For the economic penalty evaluation, the cumulative ambient dry bulb and co-
incident wet bulb temperature data are used to determine the thermal perfor-
mance of the cooling systems. For the fogging potential, the meteorological
data as discussed in Section 6 are used. The method of economic penalty
evaluation is described in Section 3. The method of evaluating the fogging
potential of a cooling system is described in Section 6.
In the second step, the hybrid wet/dry tower systems are evaluated in a
similar manner with the exception that the plume abatement analyses are per-
formed on the basis of wet/dry mode of operation. The analysis is performed
for hybrid wet/dry towers with dry sections of 5-foot finned tube length in-
crements, starting with a 5-foot section. The minimum cost hybrid wet/dry
system is then identified for each specified fogging potential.
In the third and final step, the minimum cost systems obtained in the above
two steps for wet and wet/dry systems for each specified fogging potential
are compared, and the minimum cost is identified as the optimized system for
the specified fogging potential.
7.3 OPTIMIZATION RESULTS FOR PLUME ABATEMENT TOWER SYSTEMS
7.3.1 Optimization Results for Seattle Site
Seattle has a climate which typically produces much more natural ground fog
than the other sites. During these periods of natural fog, cooling tower
operation in many instances enhances the natural ground fog, further reducing
visibility. Of the total number of hours of cooling tower ground fogging at
Seattle, approximately 75% are associated with the occurrence of natural
ground fog. Results of this study at Seattle are presented in two sets of
tables. One set contains design and cost information pertaining to wet
mechanical draft tower systems, and the other set contains information on the
wet/dry systems.
7.3.1.1 Mechanical Draft Wet Towers--
The optimized wet tower system selected solely on the basis of economics is
referred to as the reference system in Tables 7.1 and 7.2. The cost and
fogging potential of this reference system serve as the bases for comparison
with respect to both cost and environmental impact. The total evaluated cost
93
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of the optimized mechanical draft cooling system is $70.52 million. This
system operating at Seattle would produce 60 hours of ground fog per year.
About 45 hours of this is enhanced ground fog.
This impact can be significantly mitigated by altering the design tempera-
tures so that a larger cooling tower is required. Operation of this tower
results in a lower exit temperature of the saturated plume in comparison to
the reference tower. When analyzed for ground fogging, this "larger" tower
creates less fog than the reference tower. The larger cooling system has a
higher capital cost; however, a reduction in the operating penalties results
from more efficient operation so that the total evaluated cost is not signi-
ficantly affected.
The summary costs for the optimum wet systems that have specific degrees of
ground fog are presented in Tables 7.1 and 7.2. Associated design data and
detailed cost data for these systems are presented in Appendix P. The opti-
mized reference wet system mentioned above has a cooling tower consisting
of 26 cells. The design cold water temperature of this system is 82°F (27.8°
C). By decreasing the design cold water temperature to 78°F (25.6°C), the
required tower size increases to 33 cells and the ground fogging is reduced
to 32 hours per year. The total evaluated cost of this system is $73.10
million.
Further reduction in ground fogging is obtained by decreasing the design cold
water temperature and, consequently, increasing the required tower size. The
economics of the wet systems, which result in 5, 10, 20 and 30 hours of ground
fogging per year, are presented in Tables 7.1 and 7.2, and in Appendix P.
7.3.1.2 Mechanical Draft Wet/Dry Towers—
Three mechanical draft wet/dry towers are designed for plume abatement. As
mentioned earlier, the cost associated with any control and/or monitoring
systems required for this tower system have not been included in the total
evaluated costs in the accompanying tables. The wet/dry tower cell of the
three systems differ only in the cross section of the dry heat exchanger in-
stalled above the wet tower fill. The width of the heat exchanger is approx-
imately the width of the cell; the variable cross section is obtained by
varying the tube length of the exchanger. Tables 7.3 and 7.4 present the
cost summaries of three wet/dry systems and a wet system having the same five
hours per year of ground fogging. Figure 7.1 is a plot of the total evalua-
ted cost as a function of the heat exchanger tube length for systems that
create five hours of ground fog. This plot indicates that there is some
savings associated with the wet/dry system if the criterion used is less than
13 hours per year of ground fog. If the ground fogging criterion is relaxed
to 13 or more hours per year, the wet tower is preferred. These results are
indicated in Figure 7.2 where the wet and wet/dry system costs are plotted as
a function of ground fogging impact.
7.3.2 Optimization Results for Cleveland Site
Cleveland typically has much less natural ground fog than Seattle; almost
all of the ground fog is produced by cooling tower operation. The reference
94
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wet mechanical draft cooling system, optimized solely on economics, has a
total evaluated cost of $72.62 million and creates 38 hours per year of
ground fog. This system costs more than the wet system at Seattle due to
the higher ambient wet bulb temperatures characteristic of the site during
the summer months. These higher temperatures result in higher turbine back
pressures and, therefore, larger capacity and energy penalties.
Two sets of tables are presented for the systems designed for Cleveland.
Tables 7.5 and 7.6 summarize the costs for the optimized wet systems. The
costs of wet systems that create 5, 10, 20 and 30 hours of ground fog per
year are tabulated. These systems are designed, as in the case at Seattle,
by changing the design temperatures to increase the required tower size.
For the five hours per year ground fog criterion, mechanical draft wet/dry
towers that are designed for Cleveland have a slight cost advantage over the
wet system. Tables 7.7 and 7.8 present the summary of costs for these wet
and wet/dry systems.
The total evaluated cost of wet and wet/dry systems as a function of ground
fogging is plotted on Figure 7.3. The wet systems are less costly than the
wet/dry systems when the ground fogging potential is greater than six hours
per year.
7.3.3 Optimization Results for Newark Site
Cooling towers situated at Newark generate very little ground fogging in com-
parison to the other sites studied. The optimized mechanical draft wet cool-
ing system has a total evaluated cost of $76.85 million and creates 16 hours
per year of ground fog. This system and that designed for Charlotte are
more expensive than the Seattle or Cleveland designs due to the high peak wet
bulb temperature at these sites. Due to the low fogging potential of the
optimized wet system, wet/dry towers do not offer any advantage at Newark.
Tables 7.9 and 7.10 present cost summaries for the optimized wet system and
two wet systems having 5 and 10 hours of ground fogging. In addition, the
wet/dry system having a fogging potential of five hours per year is included
for comparison. This wet/dry system incorporates a heat exchanger with five-
foot long tubes in the dry section.
Due to the nominal amount of ground fogging created by the optimum wet sys-
tem, a reduction to five hours per year can easily be obtained by reducing
the design cold water temperature to 86°F (30°C) and increasing the tower
size from 25 to 31 cells. The cost of all the wet and wet/dry tower systems
designed at Newark are graphed as a function of fogging potential in
Figure 7.4.
7.3.4 Optimization Results for Charlotte Site
The optimized wet cooling system at Charlotte has a total evaluated cost of
$75.32 million and impacts the site with 61 hours of ground fogging. Approx-
imately two thirds of the ground fogging that occurs is enhanced fog. The
wet systems at both Charlotte and Newark optimized at a lower condenser range
95
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(22°F (12.2°C)) than the other sites studied and, consequently, have a
larger capital cost. This increased capital cost is a result of the require-
ment for larger pumps, pipelines and condensers to handle the larger circu-
lating water flowrate associated with the lower range. The replacement
energy penalty at Charlotte is larger than at the other sites due to the
higher wet bulb temperature characteristic of the site. These higher wet
bulb temperatures result in higher turbine back pressures which result in
less efficient operation of the plant throughout the year.
A summary of cost for four wet systems with varying degrees of ground fogging
impact are presented in Tables 7.11 and 7.12. Figure 7.5 shows the costs of
all the system designs at Charlotte as a function of ground fogging poten-
tial. As shown in Figures 7.2 to 7.4, there is little additional expense
associated with reducing the potential from 61 to 20 or to 10 hours of ground
fog.
7.4 PSYCHOMETRIC DISCUSSION
The wet systems can be designed at a number of different approach tempera-
tures which result in different tower sizes, performance and fogging impact.
The effect which a reduction in plume temperature has on visibility is illus-
trated by Figure 7.6. The amount of water present in the plume at various
stages of dilution is given by a line which connects the tower exit condition
with the ambient condition. The plume mixing line of the optimized mechani-
cal draft system can be represented by Line A presented in Figure 7.6. The
maximum excess water contained in this plume is given as distance 1 between
this plume mixing line and the saturation line.
If another wet system is designed based on a lower approach temperature
and/or range, a plume at a lower exit temperature will result. The plume
mixing line for this tower is represented by Line B. There is a reduction
of the maximum excess water (distance 2) contained in this tower plume when
compared with the economically optimized system.
Figure 7.6 does not show the effects on fogging potential of the increased
volumetric flowrate and the decreased plume height associated with the lower
temperature system. However, it does indicate that there is some degree of
control of the maximum excess water content in the plume through the varia-
tion of the design tower approach and range. The reduction of this excess
water is one of the contributing factors which reduces the ground fog of the
wet mechanical draft tower.
7.5 PLUME ABATEMENT CONCLUSIONS
Two major conclusions have been developed in this study.
1. Ground fogging from low profile wet mechanical draft towers
can be significantly reduced by changing the design tempera-
tures so that the required tower size increases.
The intermediate results of the wet cooling tower optimiza-
tion discussed in Section 4 are presented in Figure 4.3.
96
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This figure shows that there are many wet cooling systems
with different design conditions but with costs within one
to two percent of the minimum. These systems all have
different fogging potential. Systems with lower approach
temperatures are larger and have higher capital cost but
lower operating penalties. The resulting total evaluated
cost can be slightly higher, but these systems would have
much less fogging potential.
2. In most of the situations analyzed, the hybrid wet/dry cooling
system is more expensive than a comparable wet tower and would
not be recommended.
Special site conditions, i.e., existing sites which must be
backfitted to closed cycle cooling, may require some special
treatment. For new sites, the development of the hybrid wet/
dry cooling tower will, in general, not be necessary for the
purpose of minimizing ground fogging from the tower.
96A
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TABLE 7.1
MAJOR COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTB1S C$106)*
SITE: SEATTLE, WASHINGTON
YEAR: 1985
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated Cost
(Sun of Capital &
Penalty Costs)
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
56.41
9.85
13.92
80.18
10
55.59
9.34
13.72
78.65
20
51.84
10.39
14.01
76.24
30
50.25
9.37
13.48
73.10
Reference
60
44.82
10.96
14.74
70.52
* Design data for these systems are in Table P-l, p. 242.
-------
TABLE 7.2
MAJOR CAPITAL AMD PENALTY COST COMPONENTS FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTB4S ($106)
SITE: SEATTLE, WASHINGTON
YEAR: 1985
Cost Breakdown:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
24.05
10.29
6.16
2.32
2.30
11.28
56.41
4.00
5.85
-0.22
11.48
0.39
2.27
23.77
10
22.93
10.69
6.27
2.30
2.27
11.12
55.59
3.40
5.95
-0.66
11.71
0.39
2.27
23.06
20
20.70
10.30
6.16
2.26
2.05
10.37
51.84
4.95
5.44
0.76
10.74
0.39
2.12
24.40
30
18.46
10.95
6.63
2.22
1.95
10.05
50.25
3.82
5.55
0.01
11.00
0.39
2.08
22.85
Here re nee
60
14.54
10.87
6.63
2.15
1.67
8.96
44.82
5.89
5.07
2.36
10.09
0.40
1.89
25.70
vo
00
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TABLE 7.3
MAJOR COST SUMMARY FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS ($106)
5 HOURS PER YEAR GROUND FOG
SITE: SEATTLE, WASHINGTON
YEAR: 1985
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Hater
& Maintenance)
Total Evaluated Cost
(Sum of Capital &
Penalty Costs)
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
53.92
10.40
14.95
79.27
10 ft
54.08
9.91
14.39
78.38
5 ft
54.74
9.98
14.17
78.89
Mechanical
Wet System
56.41
9.85
13.92
80.18
VO
to
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TABLE 7.4
MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR THE OPTIMIZED WET/DRY AMD REFERENCE COOLING SYSTEMS ($106)
5 HOURS PER YEAR GROUND FOG
SITE: SEATTLE, WASHINGTON
YEAR: 1985
Cost Breakdown:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Oast
Total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
21.50
10.90
6.71
2.18
1.84
10.79
53.92
4.82
5.58
1.09
11.10
0.40
2.36
25.35
10 ft
21.51
10.93
6.71
2.20
1.92
10.81
54.08
..
4.29
5.62
0.51
11.15
0.39
2.34
24.30
5 ft
22.61
10.64
-6.27
' 2.24
2.03
10.95
54.74
4.35
5.63
0.33
11.13
0.39
2.32
24.15
Mechanical
Wet System
24.05
10.29
6.16
2.32
2.30
11.28
56.41
4.00
5.85
-0.22
11.48
0.39
2.27
23.77
o
o
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TABLE 7.5
MAJOR COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS ($106)*
SITE: CLEVELAND, OHIO
YEAR: 1985
Item
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Hater
& Maintenance)
Total Evaluated Coat
(Sum of Capital &
Penalty Costs)
GROUND FOGGING HOURS - MECHANICAL WET TONERS
5
54.75
10.51
14.52
79.78
10
51.73
10^25
14.25
76.23
20
47.88
11.07
14.76
73.71
30
47.02
11.02
15.13
73.17
1
Reference
36
44.80
42,10-
15.72
72.62
* Design data for these systems are In Table P-7, p. 2S2.
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TABLE 7.6
MAJOR CAPITAL AMP PENALTY COST COMPONENTS FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS ($106)
SITE: CLEVELAND, OHIO
YEAR: 1985
Cost Breakdown:
Cooling Tower
Condenser
Circulating Hater System
Make-up Facility
Electrical Equipment
Indirect Cost
total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Hater
Cooling System Maintenance
Total Penalty
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
22.38
10.57
6.28
2.34
2.23
10.95
54.75
4.64
5.87
0.39
11.50
0.40
2.24
25.04
10
19.57
10.87
6.63
2.28
2.03
10.35
51.73
4.56
5.69
0.55
11.18
0.40
2.12
24.50
20
16.78
10.83
6.63
2.23
1.83"
9.58
47.88
5.73
5.34
1.82
10.55
0.40
1.99
25.83
30
15.10
11.19
7.29
2.20
"1.84
9.40
47.02
5.66
5.36
1.99
10.63
0.40
2.11
26.15
Keterence
38
14.54
10.81
6.63
2.19
1.67
8.96
44.80
7.04
5.06
3.38
10.05
0.40
1.89
27.82
o
10
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TABLE 7.7
MAJOR COST SUMMARY FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS ($106)
5 HOURS PER YEAR GROUND FOG
SITE: CLEVELAND, OHIO
YEAR: 1985
I tea
Total Capital Cose
(Direct & Indirect
Capital Costa)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated Cost
(Sum of Capital &
Penalty Costs)
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
52.14
11.78
16.26
80.18
10 ft
53.36
10.85
14.28
78.49
5 ft
53.06
10.74
14.87
78.67
Mechanical
Wet System
54.75
10.51
14.52
79.78
o
u
-------
TABLE 7.8
MAJOR CAPITAL AND PENALTY COST COMPOHENTS FOR THE OPTIMIZED WET/DRY AMD REFERENCE COOLING SYSTEMS ($106)
SITE: CLEVELAND, OHIO
5 HOURS PER YEAR GROUND FOG
YEAR: 1985
Cast Breakdown:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
DRY HEAT EXCHANGER LENGTH
15 ft
20.02
10.99
6.73
2.20
1.77
10.43
52.14
6.20
5.58
2.54
11.09
0.40
2.23
28.04
10 ft
20.82
11.02
6.73
2.23
1.89
10.67
53.36
5.17
5.68
1.32
10.25
0.40
2.31
25.13
5 ft
20.67
10.85
6.71
2.25
1.97
10.61
53.06
5.17
5.58
1.20
11.00
0.40
2.26
25.61
Mechanical
Wet System
22.38
10.57
6.28
2.34
2.23
10.95
54.75
4.64
5.87
0.39
11.49
0.40
2.24
25.03
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TABLE 7.9
MAJOR COST SUfttARY FOR THE OPTIMIZED WET/DRY AND MECHANICAL WET COOLIHG SYSTEMS ($106)*
SITE: NEWARK, NEW JERSEY
YEAR: 1985
I ten
Total Capital Cost
(Direct & Indirect
Capital Costs)
Total Capacity
Penalty (Capacity
& Auxiliary Pouer)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Water
& Maintenance)
Total Evaluated Cost
(Sum of Capital &
Penalty Costs)
Mechanical
Wet/Dry Towers
(5 ' Exchanger)**
5 Hours
52.03
13.46
15.64
81.13
MECHANICAL WET TOWER - (GROUND FOGGING)
5 Hours
48.62
14.72
15.38
78.72
10 Hours
48.74
13.34
15.18
77.26
Reference
16 Hours
46.44
14.39
16.02
76.85
* Design data for these systems are in Table P-13, p. 262.
** Dry heat exchanger tube length is 5-foot.
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TABLE 7.10
MAJOR CAPITAL AMD PENALTY COST COMPONENTS FOR THE OPTIMIZED WET/DRY AHD MECHANICAL WET COOLIHG SYSTEMS (SIP6)
SITE: NEWARK, NEW JERSEY
YEAR: 1985
Cost Breakdown:
Cool Lag Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Coat
Total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mechanical
Wet /Dry Towers
(51 Exchanger)
5 hours
18.09
11.59
7.77
2.21
1.96
10.41
52.03
7.63
5.82
1.32
11.55
0.40
2.37
29.09
GROUND FOGGING HOURS-MECHANICAL WET TOWERS
5
17.34
10.81
6.63
2.25
1,87
9.72
48.62
9.25
5.46
2.10
10.79
0.40
2.02
30.10
10
15.66
11.59
7.65
2.21
1.88
9.75
48.74
7.63
5.71
1.32
11.31
0.40
2.15
28.52
Reference
16
13.98
11.58
7.65
2.19
1.75
9.29
46.44
8.89
5.49
2.62
10.93
0.40
2.08
30.41
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TABLE 7.11
MAJOR COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS ($106)*
SITE: CHARLOTTE, NORTH CAROLINA
YEAR: 1985
Item
Total Capital Coat
(Direct & Indirect
Capital Oasts)
Total Capacity
Penalty (Capacity
& Auxiliary Power)
Total Operating Penalty
(Replacement & Auxiliary
Energies, Make-up Hater
& Maintenance)
Total Evaluated Cost
(Sum of Capital &
Penalty Costs)
MECHANICAL MET TOWER - GROUND FOGGING
10
51.73
11.33
15.54
78.60
20
50.10
11.17
15.78
77.05
30
47.88
12.24
16.30
76.42
Reference
61
46.45
12.00
16.87
75.32
* Design data for these systems are In Table P-16, p. 267.
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TABLE 7.12
MAJOR CAPITAL AMD PENALTY COST COMPONENTS FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS (S106)
SI IE: CHARLOTTE, NORTH CAROLINA
YEAR: 1985
Cost Breakdown:
Cooling Toner
Condenser
Circulating Water System
HaVe-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost Breakdown:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
GROUND FOGGING HOURS-MECHANICAL WET TOWERS
10
19.58
10.85
6.63
2.30
2.03
10.34
51.73
5.67
5.66
1.82
11.17
0.43
2.12
26.87
20
17.34
11.19
7.29
2.26
2;«0
10.02
50.10
5.56
5.61
2.01
11.12
0.43
2.22
26.95
30
16.78
10.82
6.63
2.25
1.82
9.58
47.88
6.91
5.32
3.34
10.55
0.43
1.99
28.54
Reference
61
13.98
11.58
7.65
2.19
1.76
9.29
46.45
6.56
5.43
3.53
10.84
0.43
2.08
28.87
g
-------
o
NO
814-
o
t-l
UJ
8
CO
3
w
80-1-
794-
78 +
Heat Exchanger Tube Length (m)
1 2 3
I
10
I
15
Heat Exchanger Tube Length (ft)
Figure 7.1 Total Evaluated Cost of Wet and Wet/Dry Cooling Systems Which Produce 5 Hours
of Ground Fog as a Function of Heat Exchanger Size (Seattle, 1985)
-------
\O
o
85 --
80 --
CD
8
•o
S 75
§
r-4
OS
&
(0
a 70
t
0
Wet/Dry Tower
(10-foot tube length)*
Wet/Dry Tower
(5-foot tube length)*
Wet Tower-
10
20
30
40
50
* dry heat exchanger
tube length
60
70
Hours of Ground Fogging Per Year
Figure 7.2 Total Evaluated (tost as a Function of Ground Fogging for Various
Wet and Wet/Dry Cooling Towers (Seattle, 1985)
-------
85--
g 80 +
•CO-
CO
8
i7S +
w
s
£ 70 +
T
Wet/Dry Tower (5-foot exchanger)
Wet Tower
* dry heat exchanger
tube length
0
10 20
Hours of Ground Fogging Per Year
30
40
Figure 7.3 Total Evaluated Cost as a Function of Ground Fogging
for Various Wet and Wet/Dry Cooling Towers (Cleveland, 1985)
-------
cii
•U
90 --
85
o
I-H
•cn-
co
8
5 80
n)
75 --
Wet/Dry Tower (5-foot exchanger)'
Wet Tower
*dry heat exchanger
tube length
0
5 10
Hours of Ground Fogging Per Year
15
Figure 7.4 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Newark, 1985)
-------
85 --
\o
o
80 --
0)
8
•o
S 75
3
ca
g 70
I
0
10
Wet/Dry Tower (5-foot exchanger)1
Wet Tower
* dry heat exchanger
tube length
20
30
40
50
60
70
Hours of Ground Fogging Per Year
Figure 7.5 Total Evaluated Cost as a Function of Ground Fogging for
Various Wet and Wet/Dry Cooling Towers (Charlotte, 1985)
-------
Exhaust Condition A
o
I
01
Exhaust
Condition B
B
Ambient Condition
Dry Bulb Temperature
Figure 7.6 Psychrometric Chart for Two
Plume Exhaust Conditions
113A
-------
REFERENCES
1. Engineering and Economic Evaluation of Wet/Dry Cooling Towers for Water
Conservation, Report Number UE&C-ERDA-761130, United Engineers & Con-
structors Inc., Philadelphia, Pa., November 1976. (National Technical
Information Service, Springfield, Virginia, COO-2442-1)
2. Western States Water Requirements for Energy Development to 1990,
Western States Water Council, Salt Lake City, Utah, November 1974.
3. 1000 MWe Central Station Power Plants - Investment Cost Study, Volume
III. WASH-1230, United Engineers & Constructors Inc., Philadelphia,
Pa., 1972.
4. M. W. Larinoff, and L. L. Forster, "Dry and Wet-Peaking Tower Cooling
Systems for Power Plant Application", Journal of Engineering for Power,
Trans. ASME. Volume 98, Series A, pp. 335-348, 1976.
5. H. H. von Cleve, Comparison of Different Combinations of Wet and Dry
Cooling Towers. ASME, 75-WA/Pwr-10.
6. Heat Sink Design and Cost Study for Fossil and Nuclear-Power Plants,
WASH-1360, United Engineers & Constructors Inc., Philadelphia, Pa.,
December 1974.
7. Technical and Economic Assessment of the Direct-Cycle Gas-Cooled Reactor
Plant. ERDA-109, United Engineers & Constructors Inc., Oak Ridge Nation-
al Laboratory, and NASA-Lewis Research Center, October 1975.
8. G. J. Woffinden, P. R. Harrison, and J. A. Anderson, Cooling Tower Plume
Survey. Volume 1. Technical Summary, Chalk Point Cooling Tower Project,
Maryland Power Plant Siting Program, November 30, 1976.
9. G. W. Israel, and T. J. Overcamp, "Drift Deposition Model for Natural
Draft Cooling Towers", Cooling Tower Environment - 1974, NTIS CONF
740302, pp. 614-628, 1975.
10. P. R. Slawson, J. H. Coleman, and J. W. Frey, "Some Observations on
Cooling Tower Plume Behavior at the Paradise Steam Plant", Cooling Tower
Environment - 1974. NTIS CONF 740302, pp. 147-160, 1975.
11. G. A. Briggs, Plume Rise. AEC Critical Review Series, 1969.
114
-------
12. J. H. Meyer, e_t al., "Mechanical Draft Cooling Tower Visible Plume
Behavior: Measurements, Models, Predictions", Cooling Tower Environment
- 1974, NTIS COM 740302, pp. 307-352, 1975.
13. S. R. Hanna, Meteorological Effects of the Mechanical Draft Cooling
Towers of the Oak Ridge Gaseous Diffusion Plant, Environmental Research
Laboratories, Air Resources, Atmospheric Turbulence and Diffusion
Laboratory, NOAA, Oak Ridge, ATDL Contribution 89, 1974.
14. J. J. George, "Fog", Compendium of Meteorology, pp. 1179-1189, ed. T. F-
Malone, American Meteorological Society, Boston, Massachusetts, 1951.
115
-------
APPENDIX A
MAJOR EQUIPMENT LIST
Item
Condensers
Circulating Water
Pumps and Motors
Cooling Towers
1. Mechanical Draft
Wet Cooling Tower
2. Mechanical Draft
Dry Tower
Description
Each cooling system has three field-tubed main
surface condensers with fabricated steel water
boxes and steel shell. Each condenser has 1 in
(2.54 cm) O.D., 20 BWG gauge, 304 stainless steel
tubes and a design water velocity of 7.0 ft/s
(2.1 m/s). The condenser has two tube passes.
Condenser design data for each cooling system can
be found in Appendices F through N, and P.
The circulating water pumps are each of the verti-
cal, wet-pit, motor-driven type with 4160 volts,
3 phase, 60-hertz motors. The pumps have carbon
steel casings with chrome steel shaft and bronze
impeller. Pump design data for each system can be
found in Appendices F through N, and P.
The following are descriptions of the cooling
towers. The design data for each alternative can
be found in Appendices F through N, and P.
The mechanical draft wet tower cells or modules
are the induced draft, cross-flow type of concrete
construction with 41 ft (12.5 m) fill height.
Each cell has a fan; the fan has a diameter of
28 ft (8.6 m) and is driven by a 200 horsepower
(149 KW) motor. The cell dimensions are 71 ft
(21.6 ra) wide, 36 ft (11.0 m) long, and 54 ft
(16.5 m) high.
The mechanical draft dry tower cells are the in-
duced flow type. The cells are arranged back-to-
back to form towers. Each cell has 776 tubes
arranged in four rows and two passes and is equipped
with a 150 horsepower (111.9 KW) motor and a 28 ft
(8.6 m) diameter fan. The overall cell dimensions
are 41 ft (12.5 m) wide, 61 ft (18.6 m) long and
65 ft (19.8 m) high. The tubes are 1 in (2.54
cm) O.D. and 52 ft (15.8 m) long, admiralty tubes,
with aluminum fins. The fin dimensions are 10 fins/
116
-------
3. Natural Draft
Dry Tower
4. Mechanical Draft
Wet/Dry Hybrid
Cooling Tower
in (4 fins/cm) with a fin height of 0.625
in (1.59 cm).
The natural draft tower has a hyperbolic concrete
shell with a maximum base diameter of 500 ft
(152.4 m) and a minimum thickness of 6 in
(15.24 cm). The finned-tube heat exchanger mod-
ules are arranged vertically around the tower base.
Each module has 264 tubes in 6 rows and 2
passes. The tubes are 1 in (2.54 cm) O.D. and
50 ft (15.2 m) long, admiralty tubes, with alumi-
num fins. The fin dimensions are 10 fins/in
(4 fins/cm) with a fin height of 0.625 in
(1.59 cm).
The mechanical draft wet/dry tower cells are in-
duced draft with a 41 ft (12.5 m) cross-flow
type fill of concrete construction. Atop the
fill are located heat exchangers having 1 in
(2.54 cm) O.D. admiralty tubes with 10 aluminum
fins/inch (4 fins/cm) and a fin height of
0.625 in (1.59 cm) arranged in 4 rows and
2 passes. Each cell has a separate fan, and is
driven by a 200 horsepower (149 KW) motor. The
cell dimensions are 71 ft (21.6 m) wide and 36
ft (11.0 m) long.
117
-------
APPENDIX B
ASSESSMENT OF ECONOMIC FACTORS
A brief economic analysis is made to obtain a number of the economic
factors used in this report. The economic climate, utility make-up, finan-
cial standing and performance, capital floatation costs and the general
complexity of these factors are beyond the scope of this document.
The values described here represent approximations obtained by means of
simplified economic equations to establish the major components of the eco-
nomic factors used in this study.
INTEREST RATE
The interest rate used in power plant analysis represents an average cost
of capital to the utility. This cost of capital for most utilities includes
a cost associated with common equity, preferred stock and debt. The table
shown below indicates how the cost of capital was obtained. A general rate
of inflation of six percent is assumed. The fraction of capitalization is
assumed for typical utility operation.
COMPONENT
COMMON EQUITY
PREFERRED STOCK
DEBT
TOTAL
FRACTION OF
CAPITALIZATION
0.35
0.10
0.55
COMPONENT
COST (%)
12
10
9
WEIGHTED
COST (7.)
4.2
1.0
4.9
10.1
FIXED CHARGE RATE
There are certain fixed charges, dependent only upon the initial investment,
which a utility will incur every year for the life of the plant. The higher
the initial investment, the more these fixed charges will be. The annual
fixed charges, F, are given by:
F=P+D+S+T (B-l)
118
-------
where:
P = annual charges for property taxes and insurance
D - annual depreciation of the plant
S = annual return on investment
T = annual income taxes
S is equal, in our analysis, to the cost of capital which is 10 percent.
The other factors represent an additional 8 percent, thus, the resulting
fixed charge rate is 18 percent.
CAPITAL COST ESCALATION
All capital costs are presented in a manner that reflects a January, 1985
start up. Costs were escalated from a capital cost data base representing
July, 1974 costs. The base escalation multipliers are 1.91 and 2.29 for
material and labor respectively; these were calculated using annual escala-
tion rates of 6 percent for material and 8 percent for labor and an interest
rate of 10 percent. The construction period for the cooling system is
assumed to be two years.
Base costs were escalated to the midpoint of construction, and interest
during construction was computed from the midpoint of construction to the
date of operation. The particular cash flow curve for the cooling system
was not considered; however, experience at UE&C has shown that this method
is an excellent approximation when the construction period is short.
The base escalation multipliers were determined as follows:
Material: (1.06)9'5 vears (1.10)1'0 vear = 1.91 (B-2)
Labor: (1.08)9'5 V6ars (1.10)1-0 vear - 2.29 (B-3)
CAPACITY PENALTY CHARGE RATE
For each base analysis presented in this report, an incremental base load
plant cost of $485/kW was used for the replacement capacity penalty charge.
The value represents the capital cost assigned to the incremental capacity
of the same type but next larger size unit than the reference plant. This
capacity penalty was calculated using the cost data given in Reference 7.
FUEL COST
For the analyses reported in Sections 4 and 5, the fuel costs were obtained
from the utilities. The fuel cost of 315
-------
APPENDIX C
PLUME ABATEMENT SITES
The locations chosen for the plume abatement analysis were selected from a
list of United States cities which was prepared by UE&C staff meteorologists.
Using rule of thumb criteria, such as overall regional estimations and ground
rules assuming ambient temperatures less than 50°F (10°C), relative humidity
near 100 percent, and wind speed 8 mph (3.58 m/s) or less, 13 sites were
evaluated. Four of these were selected and studied in detail for geographic
balance and different climatological data that represented distinct areas of
the United States. The results of the analysis, listed by cities in descend-
ing order of fogging potential, are shown below:
1. Seattle, Washington
Data period: 1951-1960
2. Cleveland, Ohio
Data period: 1951-1960
3. Bedford, Massachusetts
Data period: 1961-1970
4. Scranton, Pennsylvania*
Data period: 1956-1960
5. Charlotte, North Carolina**
Data period: 1951-1960
6. Chicago, Illinois
Data period: 1951-1960
7. St. Louis, Missouri
Data period: 1951-1960
* Representing New Hampton, N.Y. for which there were no available data
** Representing Cliffside, N.C. for which there were no available data
*** Breakdown of the fogging criterion for extremely low temperature may
mean that the fogging potential value here is much too low. The UE&C
cooling tower model has not been examined for such extreme conditions
8. Montgomery, Alabama
Data period: 1951-1960
9. Fargo, North Dakota***
Data period: 1951-1960
10. Atlanta, Georgia
Data period: 1951-1960
11. Tuscon, Arizona
Data period: 1956-1960
12. Miami, Florida
Data period: 1951-1960
13. Newark, New Jersey
Data period: 1951-1960
120
-------
APPENDIX D
RAW WATER QUALITY FOR THE VARIOUS SITES AND WATER TREATMENT ANALYSIS
FOR KAIPAROWITS, UTAH
SITE WATER QUALITY
The chemical constituent average values which are needed for a water analysis
at each site are presented as ppra of
Kaiparowits San Juan Colstrip Young Rock Springs New Hampton
Ca
Mg
Na
Cl
so4
HC03
Si02
(as Si02)
232
135
255
133
359
129
17
165
37
110
20
174
118
11
115
70
96
8
140
127
12
[1641
140
4
146
154
7
142
86
108
12
178
156
6
53
20
23
54
19
50
-
WATER TREATMENT ANALYSIS FOR KAIPAROWITS, UTAH
The raw water analysis for Kaiparowits is presented above. The raw water
is treated by a cold lime-soda process to reduce the hardness by precipita-
tion. After treatment, a chemical analysis of the effluent shows the follow-
ing composition:
pH - 10.8
Si02 (as Si02) - 14
Ca
Mg
Na
TDS
- 35
- 33
- 492
- 560
Cl -
S04 -
HC03 -
OH -
133
359
35
33
All values except the Si02 are expressed as ppm of
121
-------
Sulfuric acid is added to the circulating cooling water for control of alka-
linity and pH. If the circulating water is limited to nine cycles of concen-
tration, precipitation will not occur in the cooling tower circulating water.
At nine cycles of concentration with H2S04 addition, the chemical analysis of
the water gives a composition of;
Ca - 315 Cl - 1197 pH - 6.9
Mg - 297 S04 - 3813 Si02 (as Si02) - 126
Na - 4428 HC03 - 30
IDS - 5040 OH - 0
The nine cycles of concentration limitation is based upon the following
rules: the product of Si02 (as Si02) and Mg (as CaC03> ionic concentra-
tions should not exceed approximately 37,000, and the product of Ca (as
Ca) and SO^ (as SO^) should not exceed approximately 400,000.
(as Si02> x Mg (as
126 x 297 = 37,422
Ca (as Ca) x 804 (as SO, )
126 x 3660 - 461,160
these products of the ionic concentrations are based upon standard industrial
practice. Recent recommendations in the literature (1) have advocated using
a range of 600,000 to 1,000,000 as the product of Ca and 804. Accordingly, a
value of 461,160 for the product of Ca and 804 is 15 percent over the base
value of 400,000, but is within recent acceptable limits.
The estimated required chemical dosages necessary for the water treatment
are:
1. hydrated lime - 93% Ca(OH)2 - 1.8 lbs/1000 gal
2. soda ash - 98% Na2C03 - 2.1 lbs/1000 gal
3. sulfuric acid - 93% H2S04 - 0.5 lbs/1000 gal
4. polyelectrolyte - 0.025 lbs/1000 gal
For a 1000 MWe fossil- fueled plant, the clarifier-softener for a wet cooling
system would be designed to treat about 12,500 gpm of make-up water. This
clarifier-softener would require approximately 700 to 1,000 Ibs of chlorine
in a 24 hour period. This chlorine requirement is based on a chlorine demand
in the raw influent of 5 ppm. Additional chlorine is necessary to assure
destruction of biological substances which can enter the circulating water
through the air-water interface in the cooling tower. In addition, some
chlorine residual is necessary to insure total destruction of biological
122
-------
substances. The residual level is generally pre-determined and serves as a
control function to determine the end of the chlorination period.
The water treatment analysis for the other five sites is performed in a
manner similar to the preceding discussion for Kaiparowits. The five sites
in the western coal region require the cold lime-soda process for water
treatment; the New Hampton site does not require this water treatment pro-
cess.
(1) G. J. Grits, and G. Glover, "Cooling Slowdown in Cooling Towers",
Water and Wastes Engineering, Volume 12, Number 4, pp. 45-52, April
1975.
123
-------
APPENDIX E
DESCRIPTION OF CODES OF ACCOUNTS FOR CAPITAL COST ELEMENTS
This appendix contains the definitions of capital cost account numbers used
to identify detailed capital cost data for the fossil power plants that are
given in Appendices F through N, and P.
In the capital cost list, the total indirect charges were assumed to be a
constant 25 percent of the total direct capital cost. The direct capital
cost items are identified by letters as described below:
Letter Cost Item
L Labor
E Equipment (pump, cooling tower, etc.)
M Material (pipe, cable, etc.)
T Total (L + E + M)
124
-------
118L Circulating Water Pump Structures
Circulating water pump house including concrete work, excava-
tion and backfill, temporary sheeting, rip-rap, permanent
sheet piling, and miscellaneous iron
132.2 Circulating Water System
1. Circulating water pumps and drives
2. Circulating water intake, discharge and connecting
pipelines including excavation, backfill, supports,
etc
132.3 Cooling Towers
1. Cooling tower basins and foundations including excava-
tion and backfill, forms, reinforcing steel, concrete,
concrete finish and miscellaneous iron
2. Cooling towers which are mechanical draft dry, mechan-
ical draft wet, natural draft dry, mechanical draft
hybrid wet/dry
133.1 Condensers
114 &
132.1 Make-up Facilities
1. Intake structures including excavation, concrete work,
reinforcing steel, miscellaneous iron, cofferdam
2. Water intake facilities including traveling screens,
trash racks, trash rakes, stop logs, pumps and drives
3. Intake lines including connections from pump discharges
to cooling system, steel pipeline, excavation and back-
fill, coating and wrapping pipe, welding
4. Water treatment facilities including clarifier-softeners
and chemical feeders
14 Electrical Equipment
1. Station service including switchgear and controls for
traveling screens, trash rake, circulating water pumps,
screen wash pumps and cooling tower fans
2. Station service and startup transformers which are the
incremental transformer capacities involved
125
-------
3. Cable trays and supports
4. Conduit
5. Station service power wiring
126
-------
APPENDIX F
KAIPAROWITS, UTAH - REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains three different items for the Kaiparowits, Utah site:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems operating
in the Si mode
3. Performance curves for the optimized reference and wet/dry
cooling systems
127
-------
TABLE F-l. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS AT KAIPAROWITS, UTAH
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (nm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1Q12 j/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106.m3)
Mechanical Dry
(High BP Turbine)
90.0 (32.2)
66.0 (18,9)
130.0 (54.4)
24.0 (13.3)
64.0 (35.6)
9.43 (239.5)
13,36 (339.3)
4.77 (5.03)
945.7
0.0
Mechanical Dry*
(Low BP Turbine)
103.0 (39.4)
75.0 (23.9)
118.0 (47.8)
11.0 (6.1)
26.0 (14.4)
5.03 (127.8)
5.03 (127.8)
4.62 (4.87)
989.0
0.0
Mechanical Wet
(Low BP Turbine)
90.0 (32.2)
66.0 (18.9)
86.0 (30.0)
25.0 (13.9)
20.0 (11.1)
3.08 (78.2)
3.60 (91.4)
4.50 (4.75)
1026.2
27.91 (10.57)
10
oo
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE F-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (m-Vmin)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
(High BP Turbine)
722 (67.1)
53,500
51.5 (15.7)
398 (1507)
4
61.4 (18.7)
2000 (1491)
1732 (1292)
Mechanical Dry*
(Low BP Turbine)
1010 (93.8)
113,100
34.1 (10.4)
841 (3184)
5
49.3 (15.0)
3000 (2237)
2352 (1754)
Mechanical Wet
(Low BP Turbine)
679 (63.1)
48,400
53.6 (16.3)
360 (1363)
2
92.1 (28.1)
5000 (3729)
4697 (3503)
-------
TABLE F-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
114/1190 (290/363)
114/1240 (290/378)
86/1060 (218/323)
113
120/1190 (305/363)
120/1240 (305/378)
120/1060 (305/323)
290
108/1200 (274/366)
108/1480 (274/451)
108/410 (274/125)
22
-------
TABLE F-2. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106) AT KA1PAROWITS, UTAH - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Hater Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
a
(T
Make-up Facilities (E
(M
(L
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
a
(T
Indirect Cost
Total Capital Cost
Mechanical Dry
(High BP Turbine)
0.846
0.676
1.522
1.951
0.020
0.211
2.182
2.162
2.043
4.205
0.344
0.620
0.964
34.133
0.345
3.973
38.451
6.825
0.034
3.923
10.782
-
1.494
1.123
2.771
5.388
44.403
4.874
14.216
63.493
15.873
79.366
Mechanical Dry*
(Low EP Turbine)
1.117
0.893
2.010
3.774
0.038
0.263
4.045
4.376
3.994
8.370
0.886
1.594
2.480
87.597
0.885
10.201
98.683
9.911
0.050
5.104
15.065
-
3.654
2.745
6.870
13.269
104.906
10.097
28.919
143.922
35.980
179.902
Mechanical Wet
(Low BP Turbine)
0.816
0.653
1.469
1.815
0.018
0.105
1.938
1.744
1.527
3.271
1.427
2.567
3.994
5.406
0.055
3.527
9.988
6.460
0.032
3.788
10.280
3.576
6.848
13.154
23.578
0.648
0.487
0.424
1.559
17.905
11.426
25.744
55.075
13.769
68.844
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE F-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($1(>6) AT KAIPAROWITS, UTAH - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Sunmary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
60.484
26.466
2.784
2.257
7.889
6.030
0.0
0.0
3.813
109.723
79.366
189.089
Mechanical Dry*
(Low BP Turbine)
24.267
-0.760
4.726
3.636
17.633
10.682
0.0
0.0
8.613
68.797
179.902
248.699
Mechanical Wet
(Low BP Turbine)
10.490
1.313
3.775
2.916
1.657
1.252
5.273
7.443
1.843
35.962
68.844
104.806
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE F-4. SOM1ARX OF DESIGN DATA FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS AX KAIPAROWITS, UTAH - MECHANICAL SERIES- SI MODE
Variable
General Design Data
Mode of Vet/Dry Tower Operation
Design Parameters for Dry Towers:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Cold Water Temperature, °F (°C)
Cooling Range, °F (°C)
Tower ITD, °F (°C)
Condenser Heat Load, 109 Btu/hr (1012 J/hr)
Design Parameters for Wet Helper Tower:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Tower Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
Pnax. in-EgA (nm-HgA)
Condenser Heat Load at Pm^, 10 Btu/hr (10 J/hr
Heat Load Distribution at P,,^- Wet Tower/
Dry Tower, %
Annual Make-up Hater Requirement, 10 8 gal (106 m3)
Percentage Hake-up Requirement
2
SI
65.0/52.0 (18.3/11.1)
99.0 (37.2)
18.0 (10.0)
52.0 (28.9)
4.53 (4.78)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
5.0 (127.0)
4.62 (4.88)
51.6/48.4
0.518 (0.196)
10
SI
45.0/40.0 (7.2/4.4)
90.0 (32,2)
26.0 (14.4)
71.0 (39.4)
4.52 (4.77)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
4.5 (114.3)
4.59 (4.84)
69.8/30.2
2.59 (0.98)
20
SI
30.0/28.0 (-1.1/-2.2)
85.0 (29.4)
26.0 (14.4)
81.0 (45.0)
4.50 (4.74)
103.0/77.0 (39.4/25.0)
17.1 (9.5)
4.0 (101.6)
4.55 (4.80)
78.8/21.2
5.190 (1.96)
30
SI
10.0/10.0 (-12.2/-12.2)
81.0 (27.2)
26.0 (14.4)
97.0 (53.9)
4.48 (4.73)
103.0/77.0 (39.4/25.0)
17.0 (9.4)
4.0 (101.6)
4.55 (4.80)
82.3/17.7
8.57 (3.24)
40
SI
0.0/0.0 (-17.8/-17.8)
85.0 (29.4)
28.0 (15.6)
113.0 (62.8)
4.51 (4.75)
103.0/77.0 (39.4/25.0)
15.1 (8.4)
4.0 (101.6)
4.55 (4.80)
84.7/15.3
11.14 (4.22)
-------
TABLE F-4 (continued)
Variable
Surface Area, 103 ft2 (103 m2)
•naber of Tubes
Tuba Length, ft (•)
Circulating Hater Flow & Pu«p
Circulating Hater Flew Kate, 103 gpai (m3 /Bin)
Buaber of fuapi
Pooping Bead, ft (») of Hater
Motor Rating, hp (kH) per pump
Motor Brake Boraepomr, hp (W) per pup
Flo* & Booater CUBP for Vet Tower
Percentage of Circulating Water to Wat Helper TMer
RuBber of PUBJM
Fasting Hod, ft (•) of Water
Motor Bating, hp (HI) per pump
Motor Brake Horaepcmr, hp (kW) per puap
Percentage Make-up Eequireuent
2
793 (73.7)
67,700
44.7 (13.6)
503 (1904)
3
£3.7 (19.4)
3500 (2610)
3031 (2260)
41.5
2
41.0 (12.5)
1500 (1119)
1213 (905)
10
662 (61.5)
46,800
54.0 (16.5)
348 (1317)
2
69.9 (21.3)
4000 (2983)
3447 (2570)
93
2
41.0 (12.5)
2500 (1864)
1882 (1403)
20
667 (62.0)
46,500
54.7 (16.7)
346 (1310)
2
76.6 (23.3)
4500 (3356)
3758 (2802)
100
2
41.0 (12.5)
2500 (1864)
2012 (1500) '
30
674 (62.6)
46,400
55.5 (16.9)
345 (1306)
2
88.6 (27.0)
4500 (3356)
4333 (3231)
100
2
41.0 (12.5)
2500 (1864)
2004 (1494)
40
642 (59.7)
43,300
56.6 (17.3)
322 (1219)
2
97.2 (29.6)
5000 (3729)
4440 (3311)
100
2
41.0 (12.5)
2500 (1864)
1872 (1396)
-------
•CABLE F-4 (continued)
Variable
Circulating Hater Pipelines
Condenser Intake:
Buster of Lines
Diane ter /Length , In/ft (c»/m)
Condenser Discharge:
Ikssber of Lines
Dimeter/Length, in/ft (cm/m)
Connecting Pipelines:
Kusfcer of Lines
Diaaeter /Length, in/ft (cm/n)
Cooling Toner
Size (Number of Cells):
Dry Toner
Wet Toner
Percentage Make-up Requirement
2
1
132/2000 (335/610)
1
132/1600 (335/448)
1
132/650 (335/198)
126
9
10
1
108/2000 (274/610)
1
108/1600 (274/488)
1
108/650 (274/198)
93
13
20
1
108/2000 (274/610)
1
108/1600 (274/488)
1
108/650 (274/198)
77
16
30
1
108/2000 (274/610)
1
108/1600 (274/488)
1
108/650 (274/198)
61
17
40
1
102/2000 (259/610)
1
102/1600 (259/488)
1
102/650 (259/198)
52
19
-------
TABLE F-5. SIMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT KAIPAROWITS, UTAH - MECHANICAL SERIES - SI MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(M
(L
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
a
(I
Indirect Cost
Total Capital Cost
Percentage Make-up Requirement
2
0.924
0.737
1.661
3.462
0.035
0.263
3.760
3.541
2.782
6.323
0.968
1.743
2.711
40.244
0.407
5.870
46.521
7.554
0.038
4.209
11.801
2.239
4.533
8.704
15.476
1.947
1.463
4.669
8.079
55.446
11.909
28.978
96.333
24.084
120.417
10
0.806
0.643
1.450
3.075
0.031
0.211
3.317
2.338
2.100
4.438
1.129
2.029
3.158
31.241
0.316
5.353
36.910
6.323
0.032
3.740
10.095
2.764
5.394
10.359
18.517
1.629
1.224
3.556
6.409
45.032
11.269
27.991
84.292
21.073
105.365
20
0.804
0.643
1.447
3.154
0.032
0.211
3.397
2.338
2.100
4.438
1.274
2.292
3.566
27.148
0.274
5.270
32.692
6.349
0.032
3.744
10.125
3.022
5.840
11.216
20.078
1.531
1.150
3.055
5.736
41.204
11.744
28.531
81.479
20.370
101.849
30
0.804
0.641
1.445
3.233
0.033
0.211
3.477
2.338
2.100
4.438
1.291
2.322
3.613
22.593
0.228
4.869
27.690
6.393
0.032
3.756
10.181
3.112
5.999
11.523
20.634
1.404
1.055
2.524
4.983
36.736
11.780
27.945
76.461
19.115
95.576
40
0.783
0.625
1.408
3.233
0.033
0.211
3.477
2.116
1.942
4.058
1.392
2.505
3.897
20.396
0.206
4.866
25.438
6.135
0.031
3.664
9.830
3.191
6.141
11.796
21.128
1.335
1.003
2.246
4.584
34.260
11.705
27.885
73.820
18.456
92.276
-------
TABLE F-6. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10°)
AT KAIPAROWITS, UTAH - MECHANICAL SERIES - Si MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.996
3.289
4.629
2.891
8.330
6.406
0.098
2.444
5.045
57.129
120.417
177.546
10
19.335
8.110
4.283
2.561
6.592
4.856
0.489
3.496
4.182
53.903
105.365
159.268
20
14.297
8.533
4.637
3.106
5.883
4.123
0.980
4.196
3.953
49.708
101.849
151.557
30
14.297
10.538
5.093
3.862
4.924
3.417
1.618
4.696
3.670
52.115
95.576
147.691
40
14.297
11.257
5.072
3.994
4.494
3.081
2.105
5.097
3.515
52.912
92.276
145.188
U3
•-J
-------
1040
Gross Generator Output
Cumulative Duration (hrs)
Figure F-l. Performance Curves for a High Back Pressure
Mechanical Dry Cooling System at Kaiparowits, Utah
-------
US
1040
1020
ft
u
Oj
1
1000
980 --
960
940 --
Gross Generator Output
Base Generator Output
Net Generator Output
Back Pressure
1000
2000
3000 4000 5000 6000
Cumulative Duration (hrs)
7000
8000
Figure F-2. Performance Curves for a Conventional Low Back Pressure
Mechanical Dry Cooling System at Kaiparowits, Utah
- - 120
--100
- - 80 7
H
3
- - 60
- - 40
--20
9000
-------
1040 --
1020
1000
u
«
ex
980 --
960 - -
940 --
•Base Generator Output
Gross Generator Butput
Net Generator Output
1000 2000
3000 4000 5000 6000
Cumulative Duration (hrs)
7000 8000
9000
--80
-_ 60
-.49
0)
14
CD
CD
0)
I
--20
Figure F-3. Performance Curves for a Mechanical Wet Cooling System at Kaiparowits, Utah
-------
1040
Base Generator Output
Gross Generator Output
Net Generator Output
Back Pressure
1000
2000
3000 4000 5000 6000
Cumulative Duration (hrs)
7000
8000
Figure F-4.
Performance Curves for a 21 Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah
-120
- -100
. . 80
- - 60
-- 40
--20
0
9000
0)
M
3
CO
m
o>
1-1
•On
u
05
M
-------
01
1040-L
1020 -t
10004-
u
at
a.
8
a
9804-
960 +
9404-
Base Generator Output
Back Pressure
Gross Generator Output
Net Generator Output
0
Figure F-5.
3000 4000 5000 600'0
Cumulative Duration (hrs)
Performance Curves for a 20% Mechanical Series Wet/Dry
Cooling System at Kaiparowits, Utah
-------
1040 - -
Base Generator Output
-- 120
1020
1000--
Back Pressure
•Gross Generator Output
•Net Generator Output
1000 2000
Figure F-6.
3000 4000 5000 6000
Cumulative Duration (hrs)
7000
-- 100
-. 80
-t 30 . .
-------
1040.
102Qr
I 100QL
•Base Generator Output
-- 120
•Back Pressure
•Gross Generator Output
•Net Generator Output
y 30
0)
03
1
i 20
i-i
Pn
-- 100
-- 80 *
Q)
60 n
-------
APPENDIX G
KAIPAROWITS, UTAH - MECHANICAL SERIES WET/DRY COOLING SYSTEMS: S2 MODE
This appendix contains design data, capital investment and penalty break-
downs for the optimized mechanical series wet/dry cooling systems operating
in the S2 Mode at Kaiparowits, Utah.
145
-------
TABLE 6-1. SBWARY OF DESIGN DATA FOR THE OPTIMIZED MET/DRV COOLING SYSTEMS AT KAIPAROWITS, UTAH - MECHANICAL SERIES - S2 MODE
Variable
General Design Data
Mode of Wet/Dry Tower Operation
Design Parameters for Dry Towers:
Dry Bulb/Wet Bulb Temperatures, °F <°C)
Cold Water Temperature, °F (°C)
Cooling Range, °f (°C)
Tower 1TD, °F (°C)
Condenser Heat Load, 109 Btu/hr (1012 J/hr)
Design Parameters for Wet Helper Tower:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Tower Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
'max. In-HgA (nnflgA)
Condenser Heat Load at P-.,, 109 Btu/hr
(10*2 J/hr)
Heat Load Distribution at tmxK- Wet Tower/
Dry Tover, X
Annual Make-up Water Requirement, Id8 gal (10* m3)
Percentage Kake-up Requirement
10
S2
60.0/50.0 (15.6/10.0)
101.0 (38.3)
22.0 (12.2)
63.0 (35.0)
4.S7 (4.82)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
4.99 (126.7)
4.62 (4.87)
59.5/40.5
2.85 (1.08)
20
S2
50.0/44.0 (10.0/6.7)
100. 0 (37.8)
24.0 (13.3)
74.0 (41.1)
4.58 (4.83)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
4.99 (126.7)
4.62 (4.87)
65.7/34.3
5.55 (2.10)
30
S2
35.0/33.0 (1.7/0.6)
92.0 (33.3)
28.0 (15.6)
85.0 (47.2)
4.55 (4.80)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
4.98 (126.5)
4.62 (4.87)
70.4/29.6
8.37 (3.17)
40
S2
20.0/20.0 (-6.7/-6.7)
87.0 (30.6)
32.0 (17.8)
99.0 (55.0)
4.54 (4.79)
103.0/77.0 (39.4/25.0)
19.2 (10.7)
4.98 (126.5)
4.62 (4.87)
74.8/25.2
10.99 (4.16)
-------
TABLE G-l (continued)
Variable
Coodcnseir
Surface Area, 103 ft2 (103 •*)
Number of Tubes
Tube Length, ft (=)
Circulating Water Flow & Pump
Circulating Water Flow Eate, 103 gpm (m3 /min)
Number of Pumps
Raping Head, ft (m) of Water
Motor Rating, hp (Vy) per pump
Motor Brake Horsepower, hp (BO per pump
Finn & Booster Funp for Wet Tower
Percentage of Circulating Water, to Wet Helper Tower
Huaber of POBDS
Pumping Head, ft (») of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower, hp (kW) per pump
Percentage Make-up Requirement
10
724 (67.3)
56,000
49.4 (15.1)
416 (1575)
3
66.3 (20.2)
3000 (2238)
2606 (1944)
58.2
2
41.0 (12.5)
2000 (1492)
1408 (1050)
20
693 (64.4)
51,400
51.5 (15.7)
382 (1446)
3
72.0 (21.9)
3000 (2238)
2598 (1938)
67.9
2
41.0 (12.5)
2000 (1492)
1507 (1124)
30
638 (59.3)
43,700
55.7 (17.0)
325 (1230)
2
72.7 (22.2)
4000 (2984)
3352 (2501)
85.9
2
41.0 (12.5)
2000 (1492)
1623 (12U)
40
597 (55.5)
38.200
59.7 (18.2)
284 (1075)
3
82.0 (25.0)
2500 (1865)
2201 (1642)
100.0
2
41.0 (12.5)
2000 (1492)
1651 (1232)
-------
WILE G-l (continued)
Variable
Circulating Hater Pipelines
Condenser Intake:
ftater of Lines
Dimeter /Length, in/ft (cm/n)
Condenser Discharge:
NoMber of Lines
Ma»eter /Length, in/ft (CB/B)
Connecting Pipelines:
Somber of Lines
Master/Length, In/ft (cm/")
Cooling Toner
Slse (Nuaber of Cells):
Dry Tover
Wet Toner
Percentage Make-up Requirement
10
1
120/2000 (30S/610)
1
120/1600 (305/488)
1
120/650 (305/198)
105
11
20
1
114/2000 (290/610)
1
114/1600 (290/488)
1
114/650 (290/198)
87
11
30
1
108/2000 (274/610)
1
108/1600 (274/488)
1
108/650 (274/198)
75
12
40
1
96/2000 (244/610)
1
96/1600 (244/488)
1
96/650 (244/198)
63
13
-------
TABLE G-2. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS (S106)
AT KAIPAROWITS, UTAH - MECHANICAL SERIES - S2 MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
a
(T
Condensers, Installed (E
(M
a
(T
Make-up Facilities (E
(M
0.
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Percentage Make-up Requirement
10
0.861
0.687
1.548
3.179
0.032
0.263
3.474
2.691
2.432
5.123
1.035
1.862
2.897
34.384
0.347
5.455
40.187
6.885
0.035
3.955
10.875
2.478
4.916
9.441
16.834
1.731
1.300
3.982
7.013
48.657
11.217
28.077
87.952
21.988
109.940
20
0.835
0.666
1.501
3.179
0.032
0.263
3.474
2.514
2.265
4.778
0.980
1.763
2.743
28.938
0.292
4.817
34.047
6.602
0.033
3.847
10.483
2.649
5.200
9.986
17.836
1.534
1.153
3.369
6.056
42.902
11.039
26.977
80.918
20.230
101.148
30
0.787
0.627
1.414
2.833
0.029
0.211
3.072
2.338
2.100
4.438
1.008
1.814
2.822
25.592
0.259
4.553
30.404
6.112
0.031
3.659
9.802
2.778
5.417
10.404
18.599
1.385
1.041
2.927
5.352
38.700
10.910
26.295
75.903
18.976
94.879
40
0.749
0.598
1.346
2.921
0.030
0.263
3.214
1.826
1.788
3.614
1.037
1.864
2.901
22.185
0.224
4.295
26.704
5.764
0.029
3.524
9.317
2.902
5.630
10.814
19.346
1.253
0.941
2.579
4.773
35.025
10.466
25.726
71.217
17.804
89.021
-------
TABLE G-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106)
AT KAIPAROWITS, UTAH - MECHANICAL SERIES - S2 MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
10
23.823
3.312
4.273
2.631
7.539
5.503
0.539
3.050
4.486
55.157
109.940
165.097
20
23.820
3.489
4.344
2.851
6.552
4.723
1.048
3.596
4.078
54.501
101.148
155.649
30
23.671
3.332
3.999
2.798
5.929
4.303
1.580
4.091
3.651
53.354
94.879
148.233
40
23.648
3.617
3.980
2.971
5.295
3.875
2.077
4.563
3.456
53.482
89.021
142.503
-------
APPENDIX H
KAIPAROWITS, UTAH - MECHANICAL PARALLEL WET/DRY COOLING SYSTEMS: PI MODE
This appendix contains design data, capital investment and penalty break-
downs for the optimized mechanical parallel wet/dry cooling systems at
Kaiparowits, Utah.
151
-------
TABLE H-l. STOMAKY OF DESKS DATA FOR THE OPTIMIZED HEI/DHX COOLING SYSTEMS AT KAIPARQWITS, UTAH - MECHANICAL PARALLEL - PI MODE
Variable
General Design Data
Mode of Vet/Dry Tower Operation
Design Parameters for Dry Towers:
Dry Bulb /He t Bulb Temperatures, °F (°C)
Cold Hater Temperature, °F (°C)
Cooling Bange, °F (°C)
Tower ITD, °F (°C)
Condenser Heat Load, 109 Btu/hr (1012 J/hr)
Design Parameters for Wet Helper Toner:
Dry Bulb/Wet Bulb Temperatures, °F (°C>
Tower Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
Paax> in-HgA (onBgA)
Condenser Heat Load at Fmas, 10 Btu/hr
Heat Load Distribution at P^x" Wet Tower/
Dry Tower* X
Annual Make-up Hater Requirement, 10S gal (106 m3)
Percentage Make-up Requirement
2
PI
55.0/46.0 (12.8/7.8)
89.0 (31.7)
18.0 (10.0)
52.0 (28.9)
4.48 (4.73)
103.0/77.0 (39.7/25.0)
20.0 (11.1)
5.0 (127.0)
4.62 (4.87)
35.9/64.1
0.607 (0.230)
10
PI
40.0/37.0 (4.4/2.8)
88.0 (31.1)
24.0 (13.3)
72.0 (40.0)
4.50 (4.75)
103.0/77.0 (39.7/25.0)
19.9 (11.1)
5.0 (127.0)
4.62 (4.87)
39.1/60.9
2.78 (1.05)
20
PI
30.0/28.0 (-1.1/-2.2)
87.0 (30.6)
22.0 (12.2)
79.0 (43.9)
4.49 (4.74)
103.0/77.0 (39.7/25.0)
18.6 (10.3)
4.0 (101.6)
4.55 (4.80)
42.7/57.3
5.21 (1.97)
30
PI
20.0/20.0 (-6.7/-6.7)
88.0 (31.1)
24.0 (13.3)
92.0 (51.1)
4.50 (4.75)
103.0/77.0 (39.7/25.0)
16.5 (9.17)
4.0 (101.6)
4.55 (4.80)
47.3/52.7
8.35 (3.16)
-------
H-l (continued)
Variable
Condenser
Surface Area, 10J ft2 (103 M2)
Ninber of Tubes
Tube Length, ft («)
Circulating Hater Flow & Pimp
Circulating Hater flow Kate, 103 gpn (m3 /mln)
Muster of FUBPB
Pimping Bead, ft (m) of Hater
Motor Rating, hp (VI) per ponp
Motor Brake Horsepower, hp (KB) per pump
flow & Booster Piag for Wet Toner
Percentage of Circulating Hater to Vet Helper Tower
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (KW) per punp
Motor Brake Horsepower, hp (VW) per pump
Percentage Make-up Requirement
2
794 (73.8)
67,000
45.3 (13.8)
498 (1885)
3
67.9 (20.7)
3500 (2611)
3194 (2383)
33.7
9
41.0 (12.5)
350 (261)
217 (162)
10
691 (64.2)
50,500
52.3 (15.9)
375 (1420)
3
75.0 (22.9)
3000 (2238)
2661 (1985)
57.1
11
41.0 (12.5)
350 (26U
226 (169)
20
723 (67.2)
54,900
50.3 (15.3)
408 (1544)
3
81.8 (24.9)
3500 (2611)
3156 (2354)
79.2
16
41.0 (12.5)
350 (261)
235 (175)
30
691 (64.2)
50,500
52.3 (15.9)
375 (1420)
3
90.6 (27.6)
3500 (2611)
3213 (2397)
81.2
17
41.0 (12.5)
350 (261)
208 (155)
-------
TABLE H-l (continued)
Variable
Circulating Hater ripelimes
Condenser Intake:
Ruaber of Lines
Diaaeter /Length, in/ft (ca/a)
Conoenaer Discliarge *
Nuaber of Line*
Diane ter/Length, In/ft (ca/a)
Connecting Pipelines:
Nuater of Lines
Diaaeter/Langth, In/ft (cn/n)
Cooling Toner
Sise (Itaaber of Cells):
Dry Tower
Hat lover
Percentage Hake-up Raquireotent
2
1
132/2000 (33S/610)
1
132/1500 (335/457)
2
90/900 (229/274)
123
9
10
1
114/2000 (290/610)
1
114/1500 (290/457)
2
78/900 (198/274)
88
11
20
1
120/2000 (305/610)
1
120/1500 (305/457)
2
84/900 (213/274)
77
16
30
1
114/2000 (290/610)
1
114/1500 (290/457)
2
78/900 (198/274)
64
17
-------
TABLE H-2. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106-)
AT KAIPAROWITS, UTAH - MECHANICAL PARALLEL - PI MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Hater Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(K
tt
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
-------
TABLE H-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106)
AT KAIPAROWITS, UTAH - MECHANICAL PARALLEL - PI MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
,;•
23.859
3.531
4.635
3.005
8.140
6.258
0.115
2.711
5.105
57.358
120.868
178.227
10
23.859
9.861
4.209
2.597
6.172
4.567
0.524
3.676
4.330
59.797
104.308
164.104
20
14. 297
7.992
5.314
3.156
5.858
4.047
0.984
4.566
4.648
50.862
108.222
159.084
30
14.297
10.050
5.297
3.305
5.171
3.472
1.577
5.005
4.449
52.622
102.240
154.862
-------
APPENDIX I
KAIPAROWITS, UTAH - NATURAL SERIES WET/DRY COOLING SYSTEMS: Si MODE
This appendix contains design data, capital investment and penalty break-
downs for the optimized natural series wet/dry cooling systems at
Kaiparowits, Utah.
157
-------
TABLE 1-1. S1BMABX OF DESIGN DATA FOR THE OPTIMIZED WET/OUST COOLING SYSTEMS At KAIPAROWITS, UTAH - NATURAL SERIES - SI MODE
Variable
General Design Data
Mode of Vet/Dry Toner Operation
Design Parameters for Dry Towers:
Dry Bulb/bet Bulb Temperatures, °F (°C)
Cold Hater Temperature, °F (°C)
Cooling Range, °F (°C)
lower ITD. °F (°C)
Condenser Heat Load, 10* Btu/hr (1012 J/hr)
Design Parameters for Wet Helper Tower:
Dry Bulb/Wee Bulb Temperatures, °F (°C)
Tower Approach Tenperature, °F (°C)
Design and Maxim Operating Back Pressure
Pmax. In-HgA (tmflgA)
Condenser Heat load at P , 109 Btu/hr
(W12 J/hr) *™
Heat Load Distribution at P^^- Wet Tower/
Dry Tower, %
Annual Make-up Water Requirement, TO8 gal (106 m3)
Percentage Mafee-up Requirement
2
SI
60.0/50.0 (15.6/10.0)
97.0 (36.1)
16.0 (8.89)
53.0 (29.4)
4.51 (4.76)
103.0/77.0 (39.4/Z5.0)
20.0 (11.1)
5.0 (127.0)
4.62 (4.87)
61.6/38.4
0.583 (0.221)
10
SI
40.0/37.0 (4.4/2.8)
93.0 (33.9)
20.0 (11.1)
73.0 (40.6)
4.51 (4.76)
103.0/77.0 (39.4/25.0)
20.0 (11.1)
5.0 (127.0)
4.62 (4.87)
76.1/23.9
2.75 (1.04)
20
SI
30.0/28.0 (-1.1/-2.2)
83.0 (28.3)
26.0 (14.4)
79.0 (43.9)
4.49 (4.74)
103.0/77.0 (39.4/25.0)
17.1 (9.5)
4.0 (101.6)
4.55 (4.80)
87.1/12.9
5.40 (2.04)
30
SI
20.0/20.0 (-6.7/-6.7)
85.0 (29.4)
26.0 (14.4)
91.0 (50.6)
4.50 (4.75)
103.0/77.0 (39.4/25.0)
17.1 (9.5)
4.0 (101.6)
4.55 (4.80)
89.7/10.3
8.23 (3.12)
•id
SI
10.0/10.0 (-12.2/-12.2)
89.0 (31.7)
26.0 (14.4)
105.0 (58.3)
4.52 (4.77)
103.0/77.0 (39.4/25.0)
17.2 (9.6)
4.0 (101.6)
4.55 (4.80)
92.0/8.0
11.51 (4.36)
-------
TABI£ 1-1 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (»)
Circulating Water Flow & Pump
Circulating Water Flow Rate, 103 gpa (m3 /min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kw) per pump
i
i
Motor Brake Horsepower, hp (kw) per pump
i
Flow & Booster Pump for Wet Tower
Percentage of Circulating Water to Wet Helper Tower
"Number of Pumps
Pumping Read, ft (a) of Hater
Motor Rating, hp (kw) per pump
Motor Brake Horsepower, hp (kw) per pump
Percentage Make-up Requirement
2
836 (77.7)
75,800
42.1 (12.8)
563 (2131)
4
47.0 (14.3)
2250 (1678)
1880 (1402)
39.6
2
41.0 (12.5)
1750 (1306)
1297 (968)
10
753 (70.0)
60,600
47.4 (14.4)
451 (1707)
3
48.4 (14.8)
2500 (1865)
2064 (1540)
58.0
2
41.0 (12.5)
2000 (1492)
1521 (1135)
20
670 (62.2)
46,500
55.1 (16.8)
345 (1306)
2
55.5 (16.9)
3000 (2238)
2720 (2029)
100.0
2
41.0 (12.5)
2500 (1865)
2008 (1498)
30
667 (62.0)
46,500
54.7 (16.7)
346 (1310)
2
55.4 (16.9)
3000 (2238)
2716 (2026)
100.0
2
41.0 (12.5)
2500 (1865)
2012 (1501)
40
. 1
663 (61.6)
46,800
54.2 (16.5)
347 (1314) i
2
55.1 (16.8)
3000 (2238)
2715 (2025)
100.0
2
41.0 (12.5)
2500 (1865)
2021 (1508)
-------
i-l (continued)
Variable
Circulating lister Pipelines
Condenser Intake:
taber of Line*
Hotter /Length, la/ft (CM/B)
Condenser Discharge:
Muster of Line*
Dlaneter /Length, in/ft (CB/B)
Connecting Pipelines:
thaber of tines
Diameter/Length, in/ft (CB/B)
Cooling Toser
Dry Tover
Diameter/Height, ft (•}
Busber of lovers
Barter of Beat Exchangers per lover
Wet Tover
•tnber of Cells
Percentage Make-up Requirement
2
1
138/1870 (351/570)
1
138/1440 (351/439)
2
96/890 (244/271)
441/449 (134/137)
2
268
10
10
1
126/1870 (320/570)
1
126/1440 (320/439)
2
90/890 (229/271)
497/495 (151/151)
1
302
12
20
1
108/1870 (274/S70)
1
108/1440 (274/439)
2
78/890 (198/271)
490/442 (149/135)
1
298
17
30
1
108/1870 (274/570)
1
108/1440 (274/439)
2
78/890 (198/271)
395/400 (120/122)
1
240
18
40
1
108/1870 (274/570)
1
108/1440 (274/439)
2
78/890 (198/271)
326/352 (99/107)
1
198
18
-------
TABLE 1-2. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT KAIPAROHITS, UTAH - NATURAL SERIES - SI MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
-------
TABLE 1-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT KAIPAROWITS, UTAH - NATURAL SERIES - SI MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pimping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary :
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.859
2.945
4.064
2.403
0.691
0.016
0.110
2.895
4.096
41.078
144.974
186.052
10
23.859
9.292
3.711
2.271
0.833
0.078
0.519
3.785
3.213
47.561
111.916
159.477
20
14.297
7.648
3.799
2.447
1.192
0.205
1.020
4.576
3.072
38.256
111.395
149.651
30
14.297
9.602
3.799
2.604
1.210
0.304
1.554
4.982
2.923
41.274
103.123
144.397
40
14.308
10.845
3.806
2.851
1.220
0.409
2.174
5.406
2.790
43.808
96.322
140.130
-------
APPENDIX J
SAN JUAN, NEW MEXICO
REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains two different items for San Juan, New Mexico:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems, Si mode
163
-------
TABLE J-l. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED EEEEBEN.CE COOLING SYSTEMS AT SAN JUAN, NEW MEXICO
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1012 j/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106 m3)
Mechanical Dry
(High BP Turbine)
96.0 (35.6)
62.0 (16.7)
137.0 (58.3)
22.0 (12.2)
63.0 (35.0)
10.61 (269.5)
12.60 (320.0)
4.80 (5.06)
935.8
0.0
Mechanical Dry*
(Low BP Turbine)
102.0 (38.9)
63.0 (17.2)
117.0 (47.2)
12.0 (6.7)
27.0 (15.0)
5.00 (127.0)
5.03 (127.8)
4.62 (4.87)
989.0
0.0
Mechanical Wet
(Low BP Turbine)
96.0 (35.6)
62.0 (16.7)
85.0 (29.4)
26.0 (14.4)
23.0 (12.8)
3.08 (78.2)
3.12 (79.2)
4.50 (4.75)
1026.2
29.53 (11.18)
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE J-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (m-vmin)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
(High BP Turbine)
761 (70.7)
58,800
49.4 (15.1)
437 (1654)
3
63.6 .(19.4)
3000 (2237)
2626 (1958)
Mechanical Dry*
(Low BP Turbine)
974 (90.5)
103,700
35.9 (10.9)
770 (2915)
5
50.5 (15.4)
2500 (1864)
2209 (1647)
Mechanical Wet
(Low BP Turbine)
667 (62.0)
46,500
54.7 (16.7)
346 (1310)
2
90.4 (27.6)
5000 (3729)
4434 (3306)
Ul
-------
TABLE J-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
120/1190 (305/363)
120/540 (305/165)
84/1180 (213/360)
112
114/1190 (290/363)
114/540 (290/165)
114/1180 (290/360)
274
108/1120 (274/341)
108/940 (274/287)
78/710 (198/216)
21
-------
TABLE J-2. SIMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106) AT SAN JUAN, NEW MEXICO - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
a
(T
Condensers , Installed (E
(M
(L
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Mechanical Dry
(High BP Turbine)
0.877
0.701
1.577
2.246
0.023
0.158
2.427
2.032
1.821
3.853
0.342
0.614
0.956
33.831
0.342
3.940
38.113
7.172
0.036
4.053
11.261
-
1.516
1.139
2.702
5.357
44.765
4.790
13.988
63.543
15.887
79.430
Mechanical Dry *
(Low BP Turbine)
1.081
0.863
1.944
3.545
0.036
0.263
3.844
3.621
3.101
6.722
0.837
1.505
2.342
82.764
0.836
9.638
93.238
9.472
0.048
4.937
14.457
-
3.397
2.552
6.504
12.453
99.179
9.011
26.810
135.000
33.750
168.750
Mechanical Wet
(Low BP Turbine)
0.804
0.643
1.447
1.815
0.018
0.105
1.938
1.641
1.472
3.113
1.362
2.450
3.812
5.160
0.052
3.366
8.578
6.349
0.032
3.744
10.125
2.030
1.929
3.608
7.567
0.634
0.476
0.408
1.517
15.989
6.314
15.797
38.100
9.526
47.626
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE J-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS (?106)
AT SAN JUAN, NEW MEXICO - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Towejr Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
57.535
29.617
3.166
2.769
7.999
6.458
0.0
0.0
3.913
111.456
79.430
190.886
Mechanical Dry*
(Low BP Turbine)
24.267
0.489
4.439
3.680
18.933
13.770
0.0
0.0
8.156
73.734
168.750
242.484
Mechanical Wet
(Low BP Turbine)
6.480
2.234
3.564
2.965
1.554
1.265
5.579
0.740
1.809
*
26.190
47.626
73.816
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE J-4. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED HEI/DIY COOLING SYSTEMS AT SAN JUAN, NEW MEXICO - MECHANICAL SERIES - SI MODE
Variable
General Design Data
Mode of Wet /Dry Toaer Operation
Design Parameters for Dry Towers:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Cold Water Temperature, °F (°C)
Cooling Range, °F (°C)
Tower ITD, °F (°C)
Condenser Heat Load, 10* Btu/hr (1012 J/hr)
Design Parameters for Wet Helper Toner:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Tower Approach Temperature, °F (°C)
Design and Maxlmun Operating Back Pressure
?max* in-HgA (moBgA)
Condenser Heat Load at t^^, 10* Btu/hr (1012J/hr)
Heat Load Distribution at »_„- Wet Tower/
Dry Toner, %
Annual Make-up Water Requirement, 108 gal (106 m3)
Percentage Make-up Requirement
2
SI
70.0/51.5 (21.1/10.8)
95.0 (35.0)
17.0 (9.4)
42.0 (23.3)
4.50 (4.75)
102.0/63.0 (38.9/17.2)
26.0 (14.4)
5.0 (127.0)
4.62 (4.87)
38.7/61*3
0.625 (0.237)
10
SI
60.O/45.0 (15.6/7.2)
95.0 (35.0)
22.0 (12.2)
57.0 (31.7)
4.53 (4.78)
102.0/63.0 (38.9/17.2)
26.0 (14.4)
4.5 (114.3)
4.59 (4.84)
60.9/39.1
2.90 (1.10)
20
SI
45.0/36.5 (7.2/2.5)
86.0 (30.0)
26.0 (14.4)
67.0 (37.2)
4.50 (4.75)
102.0/63.0 (38.9/17.2)
26.0 (14.4)
4.0 (101.6)
4.55 (4.80)
73.2/26.8
5.97 (2.26)
30
SI
35.0/30.0 (1.7/-1.1)
S4.0 (28.9)
26.0 (14.4)
75.0 (41.7)
4.49 (4.74)
102.0/63.0 (38.9/17.2)
26.0 (14.4)
3.5 (88.9)
4.52 (4.77)
82.2/17.8
8.85 (3.35)
40
SI
20.0/16.5 (-6.7/-B.6)
78.0 (25.6)
30.0 (16.7)
88.0 (48.9)
4.48 (4.73)
102.0/63.0 (38.9/17.2)
22.3 (12.4)
3.5 (88.9)
4.52 (4.77)
85.0/15.0
11.90 (4.50)
-------
TABLE J-4 (continued)
Variable
Surface area. 103 ft2 (103 «Z)
•naber of Tubea
tnbe length, ft (m)
Circulating Water Floe & PUMP
Circulating Water now late. 103 gpn (M3 /win)
Bomber of Pimpe
Flawing Bead, ft (•) of Water
Motor Rating, hp (kW) per pimp
Motor Brake Boraepower, hp (kW) per pimp
Plow & Booater Pimp for Bet Tower
Percentage of Circulating Water to Wat Helper Tower
•Briber of Poepe
Pimping Head, ft (•) of Water
Motor Rating, hp (kW) per pimp
Motor Brake Boraepower, hp (kW) per pimp
Percentage Make-up Requirement
2
812 (73.4)
71,300
43.5 (13.3)
529 (2002)
3
C2.5 (19.1)
3500 (2610)
3128 (2333)
23.2
2
41.0 (12.5)
1000 (746)
716 (534)
10
719 (66.8)
55,400
49.6 (15.1)
412 (1560)
3
66.3 (20.2)
3000 (2237)
2583 (1926)
50.2
2
41.0 (12.5)
1500 (1119)
1202 (896)
20
666 (61.9)
46,600
54.6 (16.6)
346 (1310)
2
71.5 (21.8)
4000 (2983)
3512 (2619)
79
2
41.0 (12.5)
2000 (1491)
1591 (1186)'
30
669 (62.2)
46,500
54.9 (16.7)
345 (1306)
2
76.3 (23.3)
4000 (2983)
3740 (2789)
98.2
2
41.0 (12.5)
2500 (1864)
1974 (1472)
40
632 (58.7)
40,200
60.0 (18.3)
299 (1132)
2
80.5 (24.5)
4000 (2983)
3413 (2545)
100
2
41.0 (12.5)
2000 (1491)
1738 (1296)
-------
TABLE J-4 (continued)
Variable
Circulating Water Pipelines
Condenser Intake:
RjBber of Lines
Diameter/Length, in/ft (cx/rn)
Condenser Discharge;
Umber of Lines
Diaaeter/Length, in/ft (cm/m)
Connecting Pipelines:
Ntaiber of Mnes
Dimeter/Length, in/ft (cm/n)
Cooling Toner
Size (Number of Cells):
Dry Tower
Wet Tower
Percentage Make-up Bequiremenc
2
1
132/1980 (335/604)
I
132/1490 (335/454)
2
96/760 (244/232)
161
7
10
1
120/1980 (305/604)
1
120/1490 (305/454)
2
84/760 (213/232)
117
11
20
1
108/1980 (274/604)
1
108/1490 (274/454)
2
78/760 (198/232)
98
13
30
1
108/1980 (274/604)
1
108/1490 (274/454)
2
78/760 (198/232)
84
15
40
1
102/1980 (259/604)
1
102/1490 (259/454)
2
72/760 (183/232)
70
17
-------
TABLE J-5. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS
-------
TABLE J-6. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT SAN JUAN, NEW MEXICO - MECHANICAL SERIES - SI MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
24.007
4.479
3.771
3.208
11.410
8.979
0.104
0.177
5.641
61.776
122.737
184.513
10
19.373
8.039
4.079
2.872
8.092
6.643
0.483
0.298
4.710
54.589
101.918
156.507
20
14.297
8.544
4.101
2.935
7.123
5.684
0.995
0.382
4.191
48.252
92.432
140.684
30
9.638
6.995
4.592
3.504
6.398
5.007
1.474
0.450
4.044
42.102
87.896
129.998
40
9.638
7.982
4.140
3.409
5.683
4.419
1.983
0.499
3.743
41.496
81.331
122.827
w
-------
APPENDIX K
^
COLSTRIP, MONTANA - REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains two different items for Colstrip, Montana:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems, Si mode
174
-------
TABLE K-l. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS AT COLSTRIP, MONTANA
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (min-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1Q12 J/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106 m3)
Mechanical Dry
(High BP Turbine)
95.0 (35.0)
63,0 (17.2)
134.0 (56.7)
24.0 (13.3)
63.0 (35.0)
10.37 (263.4)
12.58 (319.6)
4.80 (5.06)
937.9
0.0
Mechanical Dry*
(Low BP Turbine)
102.0 (38.9)
63.0 (17.2)
117.0 (47.2)
12.0 (6.7)
27.0 (15.0)
5.03 (127.8)
5.03 (127.8)
4.62 (4.87)
989.0
0»0
Mechanical Wet
(Low BP Turbine)
95.0 (35.0)
63.0 (17.2)
87.0 (30.6)
24.0 (13.3)
24.0 (13.3)
3.08 (78.2)
3.23 (82.0)
4.50 (4.75)
1026.2
28.66 (10.85)
•si
Ul
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE K-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (m3/min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per .pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
(High BP Turbine)
726 (67.4)
53,800
51.5 (15.7)
400 (1514)
3
64.0 (19.6)
3000 (2238)
2420 (1805)
Mechanical Dry*
(Low BP Turbine)
974 (90.4)
103,700
35.9 (10.9)
770 (2915)
6
53.5 (16.3)
2250 (1678)
1949 (1454)
Mechanical Wet
(Low BP Turbine)
692 (64.3)
50,400
52.4 (16.0)
375 (1420)
3
89.2 (27.2)
3500 (2611)
3160 (2357)
-------
TABLE K-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
114/2090 (290/637)
114/1820 (290/555)
112
114/2090 (290/637)
114/1820 (290/555)
268
114/1680 (290/512)
114/1530 (290/466)
20
-------
TABLE K-2. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS (S106) AT COLSTRIP, MOSTAXA - 1935
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Prasp (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
a
(T
Condensers, Installed (E
(M
a
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Mechanical Dry
(High BP Turbine)
0.848
0.678
1.526
2.002
0.020
0.158
2.181
2.269
2.084
4.353
0.342
0.614
0,956
33.831
0.342
3.940
38.112
6,857
0.034
3.934
10.82S
-
1.516
1.139
2.702
5.357
44.206
4.994
14.109
63.310
15.827
79.137
Mechanical Dry*
(Low BP Turbine)
1.081
0.863
1.944
3.648
0.037
0.316
4.000
4.538
4.168
8.706
0.817
1.472
2.290
80.942
0.818
9.427
91.196
9.472
0.048
4.937
14.457
-
3.365
2.528
6.412
12.304
97.437
9.867
27.595
134.898
33.725
168.623
Mechanical Wet
(Low BP Turbine)
0.829
0.662
1.491
2.122
0.021
0.158
2.301
1.931
1.711
3.642
1.297
2.334
3.630
4.914
0.050
3.206
8.170
6.577
0.033
3.833
10.444
2.034
6.828
It. 949
21.810
0.636
0.478
0.437
1.551
16.283
11.467
25.290
53.040
13.260
66.300
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE K-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106) AT COLSTRIP, MONTANA - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
57.433
25.673
2.917
2.258
7.882
5.653
0.0
0.0
3.793
105.608
79.137
184.745
Mechanical Dry*
(Low BP Turbine)
24.267
-0.126
4.699
3.456
18.317
11.523
0.0
0.0
8.091
70.226
168.623
238.849
Mechanical Wet
(Low, BP Turbine)
7.409
1.750
3.810
2.813
1.507
1.079
4.777
3.361
1.946
28.452
66.300
94.752
VJ
VO
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLB K-4. SUMUES OF DESIGN DATA FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS AI COLSTRIP, HONIARA - MECHANICAL SERIES - SI MODE
Variable
General Design Data
Mode of Wet/Dry Toner Operation
Design Parameters for Dry Towers:
Dry Balb/Hct Bulb Temperatures , °F (°C)
Cold Hater Temperature, °F <°C)
Cooling Range, °F (°C)
Tower ITD, °F (°C)
Condenser Heat Load, 1C)9 Bturtir in-Hg* (nnfigA)
Condenser Heat Load at F , 109 Btu/br
(1012 J/hr) M*
Beat Load Distribution at P,..,,- Het Tower/
' Dry Tower, 1
Annual Make-up Water Requirement, 108 gal (106 m3)
Percentage Make-up Requireoent
2
SI
70.0/52.0 (21.1/11.1)
95.0 (35.0)
20.0 (11.1)
45.0 (25.0)
4.52 (4.77)
102.0/67.0 (38.9/19.4)
26.0 (14.4)
5.01 (127.3)
4.62 (4.87)
42.3/57.7
0.51S (0.196)
10
SI
50.0/42.0 (10.0/5.6)
90.0 (32.2)
22.0 (12.2)
62.0 (34.4)
4.50 (4.75)
102.0/67.0 (38.9/19.4)
25.0 (14.4)
4.50 (114.3)
4.59 (4.84)
64.3/35.7
3.05 (1.15)
20
SI
40.0/34.0 (4.4/1.1)
88.0 (31.1)
26.0 (14.4)
74.0 (41.1)
4.51 (4.76)
102.0/67.0 (38.9/19.4)
26.0 (14.4)
4.00 (101.6)
4.55 (4.80)
75.6/24.4
6.03 (2.28)
so
SI
30.0/25.0 (-1.1/-3.9)
83.0 (28.3)
28.0 (15.6)
81.0 (45.0)
4.50 (4.75)
102.-0/67.0 (38.9/19.4)
20.4 (11.3)
3.50 (88.9)
4.52 (4.77)
83.7/16.3
8.72 (3.30)
40
SI
15.0/11.0 (-9.4/-11.7)
80.0 (26.7)
30.0 (16.7)
95.0 (52.8)
4.49 (4,74)
102.0/67.0 (38.9/19.4)
18.4 (10.2)
3.50 (88.9)
4.52 (4.77)
86.1/13.9
11.45 (4.33)
-------
TABLE K-4 (continued)
Variable
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (•)
Circulating Water Flow & Pump
Circulating Water Flow Rate, 103 gpm (m3 /min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kw) per pump
Motor Brake Horsepower, hp (kw) per pump
Flow & Booster Pump for Wet Tower
Percentage of Circulating Water to Wet Helper lover
Number of Pumpa
Pumping Head, ft (m) of Water
Motor Rating, hp (kw) per pump
Motor Brake Horsepower, hp (kw) per pump
Percentage Make-up Requirement
2
753 (70.0)
60,800
47.3 (14.4)
452 (1711)
3
59.8 (18.2)
3000 (2238)
2554 (1905)
36.2
2
41.0 (12.5)
1500 (1119)
951 (709)
10
720 (66.9)
55,100
49.9 (15.2)
409 (1548)
3
70.6 (21.5)
3000 (2238)
2731 (2037)
60.7
2
41.0 (12.5)
2000 (1492)
1446 (1079)
20
664 (61.7)
46,700
54.3 (16.6)
347 (1314)
2
75.5 (23.0)
4000 (2984)
3718 (2774)
94.4
2
41.0 (12.5)
2500 (1865)
1906 (1422)'
30
645 (59.9)
43,200
57.0 (17.4)
321 (1215)
2
81.5 (24.8)
4000 (2984)
3717 (2773)
100.0
2
41.0 (12.5)
2500 (1865)
1868 (1394)
40
i
627 (58.3) ]
40,300
59.5 (18.1)
299 (1132)
2
84.8 (25. 8) I
4000 (2984)
3600 (2686)
i
1
100.0
1
1
2
41.0 (12.5)
2000 (1492)
1742 (1300)
-------
TABLE K-4 (continued)
Variable
Circulating Water Pipelines
Condenser Intake:
Suaber of Lines
Diameter /Length, in/ft (en/a)
Condenser Discharge:
ftaber of Lines
Dicaeter /Length, in/ft (OT/H)
Connecting Pipelines:
HoBber of Lines
Diane ter /Length, in/ft (cn/n)
Cooling Tower
Size (Kunber of Cells):
Dry Tower
Wet Toner
Percentage Make-up Requlreaent
2
1 :'•
126/1770 (320/539)
1
126/1900 (320/579)
2
M/680 (229/207)
153
7
10
1
120/1770 (305/539)
1
120/1900 (305/579)
2
M/680 (213/207)
100
11
20
1
108/1770 (274/539)
I
108/1900 (27*/579)
2
78/680 (198/207)
84
13
30
1
102/1770 (259/539)
1
102/190O (259/579)
2
72/680 (183/207)
75
18
40
1
102/1770 (259/539)
1
102/1900 (259/579)
2
72/680 (183/207)
62
20
-------
TABLE K-5. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS (510 )
AT COLSTRIP, MONTANA - MECHANICAL SERIES - SI MODE - 1985
Acct. So.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pimp (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
tt
(I
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
-------
TABLE K-6. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106)
AT COLSTRIP, MONTANA - MECHANICAL SERIES - SI MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary :
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.979
3.383
3.843
2.332
9.925
7.401
0.086
0.924
5.417
57.291
127.578
184.869
10
19.335
7.323
4.455
2.785
6.933
4.961
0.508
1.496
4.376
52.171
107.106
159.277
20
14.297
8.076
4.519
2.970
6.123
4.287
1.006
1.856
3.988
47.121
100.559
147.680
30
9.647
6.434
4.489
3.128
5.943
4.005
1.453
2.185
3.920
41.205
100.994
142.199
40
9.647
6.924
4.293
3.139
5.267
3.515
1.908
2.380
3.651
40.723
96.222
136.945
00
-------
APPENDIX L
YOUNG, NORTH DAKOTA - REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains two different items for Young, North Dakota:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems, Si mode
185
-------
TABLE L-l. SUMMARY OF DESIGN DATA FOR THE OPTIMIZES REFERENCE COOLING SYSTEMS AT YOUNG, NORTH DAKOTA
Variable
General Design Data
Design Temperatures, °F (°C):
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1012 j/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106 m3)
Mechanical Dry
(High BP Turbine)
95.0 (35.0)
66.0 (18.9)
134.0 (56.7)
22.0 (12.2)
61.0 (33.9)
9.89 (251.2)
12.59 (319.8)
4.78 (5.04)
941.9
0.0
Mechanical Dry*
(Low BP Turbine)
104.0 (40.0)
71.0 (21.7)
119.0 (48.3)
10.0 (5.6)
25.0 (13.9)
5.00 (127.0)
5.03 (127.8)
4.62 (4.87)
989.0
0.0
Mechanical Wet
(Low BP Turbine)
95.0 (35.0)
66.0 (18.9)
87.0 (30.6)
26.0 (14.4)
21.0 (11.7)
3.26 (82.8)
3.43 (87.1)
4.51 (4.76)
1023.3
26.43 (10.0)
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE L-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpo (m-Vmin)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
(High BP Turbine)
758 (70.4)
58,500
49.4 (15.1)
435 (1647)
3
63.8 (19.4)
3000 (2237)
2626 (1958)
Mechanical Dry*
(Low BP Turbine)
1049 (97.5)
124,400
32.2 (9.8)
925 (3501)
7
51.6 (15.7)
2250 (1678)
1933 (1441)
Mechanical .Wet
(Low BP Turbine)
665 (61.8)
46,600
54.4 (16.6)
347 (1314)
2
90.2 (27.5)
5000 (3729)
4436 (3308)
00
-4
-------
TABLE L-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
oo
00
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
120/1190 (305/363)
120/540 (305/165)
84/1180 (213/360)
111
126/1190 (320/363)
126/540 (320/165)
126/1180 (320/360)
269
108/1120 (274/341)
108/940 (274/287)
78/710 (198/216)
21
-------
TABLE L-2. SUMMARY OF CAPITAL INVESTMEST COST FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS (S106) AT YOUNG, NORTH DAKOTA - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Hater Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(M
(L
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Mechanical Dry
(High BP Turbine)
0.875
0.698
1.573
2.246
0.023
0.158
2.427
2.032
1.821
3.853
0.338
0.609
0.947
33.529
0.339
3.903
37.771
7.148
0.036
4.044
11.228
_
-
-
-
1.505
1.131
2.679
5.315
44.428
4.773
13.913
63.114
15.778
78.892
Mechanical Dry*
(Low BP Turbine)
1.157
0.925
2.083
4.255
0.043
0.369
4.666
4.483
3.568
8.051
0.821
1.477
2.298
81.254
0.821
9.461
91.536
10.420
0.052
5.301
15.773
_
-
-
-
3.449
2.591
6.481
12.521
99.377
9.969
27.581
136.927
34.232
171.159
Mechanical Wet
(Low BP Turbine)
0.806
0.643
1.449
1.815
0.018
0.105
1.938
1.641
1.472
3.113
1.362
2.450
3.812
5.160
0.052
3.366
8.578
6.336
0.032
3.742
10.110
2.010
3.543
6.686
12.239
0.634
0.476
0.408
1.518
15.955
7.930
18.874
42.759
10.689
53.448
s
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE L-3. PENALTY BREAKDOWN AMD COST SUMARY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106)
AT YOUNG, NORTH DAKOTA - 1985
Item
Penalty Breakdown:
Capacity Penalty
Keplacement Energy Penalty
Penalty for Circulating Hater
Ptmplng Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Pouer Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Hater Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling Systen Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
57.489
18.447
3.165
1.770
7.959
4.112
0.0
0.0
3.890
96.833
78.892
175.725
Mechanical Dry*
(Low BP Turbine)
24.267
-0.349
5.436
2.935
18.431
7.704
0.0
0.0
8.444
66.868
171.159
238.027
Mechanical Wet
(Lou BP Turbine)
9.056
1.322
3.565
1.930
1.597
0.834
4.404
0.828
1.809
25.345
53.448
78.793
* This is not an optimized system because of the turbine back pressure limitation..
-------
TABLE L-4. SUMMARY OF DESIGN DAI* FOR THE OPTIMIZED WEI/WH COOLIKC SYSTQIS AT YOUNG, NORTH DAKOTA - MECBAKICAL SERIES - SI MODE
Variable
General Design Data
Mode of Wet/Dry Tower Operation
Design Parameters for Dry Towers:
Dry Bulb /Wet Bulb Temperatures, °F (°C)
Cold Water Temperature, °F (°C)
Coaling Kange, °F (°C)
Tower 1TD, °F (°C)
Condenser Heat Load, 10* Btu/hr {10iz J/br)
Design Parameters for Wet Helper Tover:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Toner Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
pmax< In-BgA (nmRgA)
Condenser Heat Load at P,^, 109 Btu/hr (l012J/or
Heat Load Distribution at P,^^^- Bet Tower/
Dry Tower, %
Annual Make-up Water Requirement, 10* gal (106 m3)
Percentage Make-up Requirement
2
SI
60.0/50.0
89.0
18.0
47.0
4.48
104.0/70.0
26 .0
5.0
4.62
49.4/50.6
0.613
10
51
50.0/43.0
93.0
26.0
69.0
4.54
104.0/70.0
26.0
5.0
4.62
64.4/35.6
2.61
20
SI
35.0/31.0
32.0
28.0
75.0
4.49
104.0/70.0
22.0
4.0
4.55
J8.5/21.5
5.18
30
SI
40
SI
i
20.0/17.0
83.0
30.0
93.0
4.51
104.0/70.0
20.1
4.0
4.55
82.6/17.4
7.94
0.0/-3.0
80.0
30.0
110.0
4.49
104.0/70.0
20.0
4.0
4.55
85.5/14.5
10.92
-------
X&BLE L-4 (continued)
Variable
Conaenaer
Surface Area, 103 ft2 (103 m2)
•uwber of Tube*
Tube Length, ft (m)
Circulating Hater Plow & Patp
Circulating Water Flow late, 103 gpa (w.3 /win)
HUHWIT of Pmps
Poping Head, ft (n) of Water
Motor Rating, hp (kV) per p«a)
Motor Brake Horsepower, hp (W) per pop
Flow & Booster Fnap for Wet Tower
Percentage of Circulating Hater to Wet Helper Toner
•vaber of Punps
Planting Head, ft (•) of Water
Motor Rating, hp (fcW) per punp
Motor Brake Horsepower, hp (kW) per puop
Percentage Bake-up Requirement
I
794 (73.8)
67,000
45.3 (13.8)
498 (1885)
3
66.1 (20.1)
3500 (2610)
3109 (2318)
39.3
2
41.0 (12.5)
1500 (1119)
1138 (849)
10
662 (61.5)
47,000
53.8 (16.4)
349 (1321)
2
73.3 (22.3)
4000 (2983)
3634 (2710)
73.3
2
41.0 (12.5)
2000 (1491)
1489 (1110)
20
647 (60.1)
43,200
57.2 (17.4)
321 (1215)
2
79.2 (24.1)
4000 (2983)
3605 (2688)
100
2
41.0 (12.5)
2500 (1664)
1866 (1391)
30
622 (57.8)
40,400
58.8 (17.9)
300 (1136)
2
84.2 (25.7)
4000 (2983)
3587 (2675)
100
2
41.0 (12.5)
2000 (1491)
1747 (1303)
40
627 (58.3)
40.300
59.5 (18.1)
299 (1132)
2
97.3 (29.7)
4500 (3356)
4131 (3080)
100
2
41.0 (12.5)
2000 (1491)
1742 (1299)
-------
TABLE L-4 (continued)
Variable
Circulating Hater Pipelines
Condenser Intake:
SMber of Lines
Dimeter/Length, In/ft (ca/n)
Condenser Discharge:
Umber of Lines
Diameter /Length , In/ft (cm/n)
Connecting Pipelines:
Number of Lines
Diameter/Umgth, In/ft (cn/a)
Cooling Toger
Size (Slumber of Cells):
Dry Tower
Wet Tower
Percentage Make-up Requirement
2
1
132/1980 (335/604)
1
132/1490 (335/454)
2
90/760 (229/232)
133
8
10
1
108/1980 (274/604)
1
108/1490 (Z74/454)
2
78/760 (W8/232)
91
10
20
1
102/1980 (259/604)
1
102/1490 (259/454)
2
72/760 (183/232)
82
15
30
1
102/1980 (259/604)
1
102/1490 (259/454)
2
72/760 (183/232)
63
17
40
1
102/1980 (259/604)
1
102/1490 (254/454)
2
72/760 (183/232)
50
17
-------
TABLE L-5. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED HET/DRY COOLESG SYSTEMS ($10°)
AT YOUNG, NORTH DAKOTA - MECHAHICAL SERIES - SI MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
-------
TABLE L-6. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106)
AT YOUNG, NORTH DAKOTA - MECHANICAL SERIES - SI MODE - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.900
2.484
4.663
2.098
8.855
4.687
0.102
0.293
5.084
52.166
113.630
165.796
10
23.859
6.570
4.117
1.810
6.389
3.376
0.435
0.402
3.955
50.913
90.391
141.304
20
14.297
5.092
4.397
2.037
6.197
3.140
0.864
0.508
3.990
40.522
90.753
131.275
30
14.297
6.637
4.286
2.165
5.113
2.524
1.323
0.561
3.587
40.493
82.680
123.173
40
14.297
7.529
4.720
2.548
4.337
2.120
1.820
0.604
3.340
41.315
76.660
117.975
vo
-------
APPENDIX M
ROCK SPRINGS, WYOMING
REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains two different items for Rock Springs, Wyoming:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems, Si mode
196
-------
TABLE M-l. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS AT ROCK SPRINGS, WYOMING
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1012 j/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106 m3)
Mechanical Dry
(High BP Turbine)
88.0 (31.1)
55.0 (12.8)
131.0 (55.0)
24.0 (13.3)
67.0 (37.2)
9.65 (245.1)
11.21 (284.7)
4.78 (5.04)
943.8
0.0
Mechanical Dry*
(Low BP Turbine)
93.0 (33.9)
56.0 (13.3)
108.0 (42.2)
21.0 (11.7)
36.0 (20.0)
5.03 (127.8)
5.03 (127.8)
4.62 (4.87)
989.0
0.0
Mechanical Wet
(Low BP Turbine)
88.0 (31.1)
55.0 (12.8)
83.0 (28.3)
26.0 (14.4)
28.0 (15.6)
2.91 (73.9)
2.94 (74.7)
4.49 (4.74)
1028.8
28.03 (10.61)
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE M-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (m^/min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
(High BP Turbine)
723 (67.2)
53,600
51.5 (15.7)
398 (1507)
3
62.6 (19.1)
3000 (2238)
2356 (1758)
Mechanical Dry*
(Low BP Turbine)
750 (69.7)
59,300
48.3 (14.7)
440 (1666)
3
53.0 (16.2)
2500 (1865)
2207 (1646)
Mechanical Wet
(Low BP Turbine)
670 (62.2)
46,500
55.1 (16.8)
345 (1306)
2
90.6 (27.6)
5000 (3730)
4436 (3309)
oo
-------
TABLE M-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
114/1190 (290/363)
114/540 (290/165)
84/1180 (213/360)
108
120/1190 (305/363)
120/540 (305/165)
84/1180 (213/360)
249
108/1120 (274/341)
108/710 (274/216)
78/940 (198/287)
20
-------
TABLE M-2. St3
-------
TABLE M-3. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106)
AT ROCK SPRINGS, WYOMING - 1985
Item
Penalty Breakdown;
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pumping Power Requirement
Penalty for Circulating Water
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary;
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
52.389
27.488
2.841
2.364
7.616
5.853
0.0
0.0
3.704
102.254
76.319
178.573
Mechanical Dry*
(Low BP Turbine)
24.267
0.369
2.660
2.104
16.994
12.194
0.0
0.0
6.836
65.425
146.010
211.435
Mechanical Wet
(Low BP Turbine)
5.145
1.744
3.565
2.826
1.478
1.149
4.983
2.868
1.783
25.541
69.951
95.492
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE M-4. SDHHAK7 OF DESIGN DATA FOR THE OPTIMIZED MET/BBS COOLING StSTEMS AT BOCK SPRINGS, HTOMUG - MECHANICAL SERIES - SI MODE
Variable
General Design Data
Mode of Vet /Dry lover Operation
Design Parameters for Dry lovers:
Dry Bulb/lfet Bulb Temperature a . °F (°C)
Cold Water Temperature, °F (°C)
CooUng Range, °F (°C)
Tower ITD, °F <°C)
Condenser Heat Load, 109 Btu/hr (1012 J/hr)
Design Parameters for Het Helper Tover:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Tover Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
Vnex, in-BgA (mmHgA)
Condenser Heat Load at P , 109 Btu/hr
(1012 J/hr)
Heat Load Distribution at f^^- Wet lower/
Dry Tower, X
Annual Make-up Water Requirement, 108 gal (ID6 m3)
Percentage Make-up Requirement
1
SI
_
55.0/41.5 (12.8/5.3)
87.0 (30.6)
20.0 (11.1)
52.0 (28.9)
4.48 (4.73)
93.0/S6.0 <33. 9/13.3)
32.0 (17. 8)
5.00 (127.0)
4.62 (4.87)
34.6/65.4
0.551 (0.209)
10
SI
45.0/36.0 (7.2/2.2)
86.0 (30.6)
22.0 (12.2)
63.0 (35.0)
4.48 (4.73)
93.0/56.0 (33.9/13.3)
32.0 (17.8)
4.00 (101.6)
4.55 (4.80)
57.5/42.5
2.78 (1.05)
20
SI
30.0/25.5 (-1.1/-3.6)
79.0 (26.1)
26.0 (14.4)
75.0 (41.7)
4.47 (4.72)
93.0/56.0 (33.9/13.3)
32.0 (17.8)
3.50 (88.9)
4.52 (4.77)
70.7/29.3
5.88 (2.23)
30
SI
15.0/13.0 (-9.4/-10.6)
72.0 (22.2)
32.0 (17.8)
89.0 (49.4)
4.47 (4.72)
93.0/56.0 (33.9/13.3)
26.5 (14.7)
3.50 (88.9)
4.52 (4.77)
76.2/23.8
8.58 (3.25)
40
31
0.0/-2.0 (-17.8/-16.7)
72.0 (22.2)
34.0 (18.9)
106.0 (58.9)
4.48 (4.73)
93.0/56.0 (33.9/13.3)
24.1 (13.4)
3.50 (88.9)
4.52 (4.77)
80.2/19.8
11.63 (4.40)
-------
TABLE H-4 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
limber of Tubes
Tube Length, ft («)
Circulating Water Flow & Pump
Circulating Water Flow Rate, 103 gpm (m3 /min)
Ninaber of Ptu^s
Pumping Head, ft (m) of Water
Motor Rating, hp (kH) per punp
Motor Brake Horsepower, hp (ISO per pimp
FloH & Booster Pump for Wet Tower
Percentage of Circulating Hater to Wet Helper Toner
Humber of Pumps
Pumping Read, ft (m) of Water
Motor Rating, hp (kw) per pump
Motor Brake Horsepower, hp (kW) per pump
Percentage Make-up Requirement
2
758 (70.4)
60,300
48.0 (14.6)
448 (1696)
3
64.4 (19.6)
3000 (2238)
2727 (2034)
26.1
2
41.0 (12.5)
1000 (746)
679 (507)
10
724 (67.3)
54,800
50.4 (15.4)
408 (1544)
3
70.4 (21.5)
3000 (2238)
2713 (2024)
56.1
2
41.0 (12.5)
2000 (1492)
1330 (992)
20
679 (63.1)
46,300
56.0 (17.1)
344 (1302)
2
76.5 (23.3)
4000 (2934)
3734 (2786)
93.6
2
41.0 (12.5)
2500 (1865)
1872 (1397)-
30
591 (54.9)
37,600
60. 0 (18.3)
279 (1056)
2
82.3 (25.1)
4000 (2984)
3262 (2433)
100
2
41.0 (12.5)
2000 (1492)
1625 (1212)
40
557 (51.7)
35,500
60.0 (18.3)
263 (996)
2
85.1 (25.9)
3500 (2611)
3182 (2374)
100
2
41.0 (12.5)
2000 (1492)
1533 (1144)
-------
TABLE M-4 (continued)
Variable
Circulating Mater Pipelines
Condenaer Intake:
Rwber of Lines
Diameter /Length, In/ft (cn/»)
Condenser Discharge:
Umber of Lines
Dimeter/Length, In/ft (cm/a)
Connecting Pipelines:
Huiber of Lines
Dine t*r /Length, in/ft (cm/n)
Cooling Tower
Site (Nucber of Cells):
Dry Tower
Wet Toner
Percentage Make-up Requirement
2
1
126/1980 (320/604)
1
126/1490 (320/454)
2
90/760 (229/232)
129
6
10
1
120/1980 (305/604)
1
120/1490 (305/454)
2
84/760 (213/232)
103
10
20
1
108/1980 (274/604)
1
108/1490 (274/454)
2
78/760 (198/232)
85
12
30
1
96/1980 (244/604)
1
96/1490 (244/454)
2
66/760 (168/232)
72
16
40
1
96/1980 (244/604)
1
96/1490 (244/454)
2
66/760 (168/232)
58
18
-------
TABLE M-5. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT ROCK SPRINGS, WYOMING - MECHANICAL SERIES - Si MODE - 1985
Acct. Ho.
118L
132.211
132.25
132.3211
132.3212
133.1
.114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
-------
TABLE M-6. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZE) WET/DRY COOLING SYSTEMS ($106)
AT ROCK SPRINGS, WYOMING - MECHANICAL SERIES - SI MODE - 1965
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Water
Pulping Power Requirement
Penalty for Circulating Water
Pumping Energy Requireaent
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.859
4.478
3.288
2.666
8.959
6.745
0.098
0.626
4.836
55.555
115.748
171.303
10
14.297
5.345
4.340
2.894
7.075
5.468
0.495
1.116
4.414
45.444
110.177
155.621
20
9.638
5.683
4.506
3.127
6.167
4.636
1.045
1.465
3.986
40.254
103.629
143.883
30
9.638
7.198
3.928
2.997
5.599
4.136
1.524
1.707
3.604
40.331
98.922
139.253
40
9.638
7.728
3.789
3.038
4.867
3.585
2.068
1.917
3.309
39.939
93.996
133.935
-------
APPENDIX N
NEW HAMPTON, NEW YORK
REFERENCE AND MECHANICAL SERIES WET/DRY COOLING SYSTEMS
This appendix contains two different items for New Hampton, New York:
1. Design data, capital investment and penalty breakdowns for the
optimized reference cooling systems
2. Design data, capital investment and penalty breakdowns for the
optimized mechanical series wet/dry cooling systems, Si mode
207
-------
TAELE N-l. SUMMARY OF DESIGN DATA. FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS AT NEW HAMPTON, NEW YORK
Variable
General Design Data
Design Temperatures, °F (°C):
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
ITD (Dry Tower) or
Approach (Wet Tower)
Design Turbine Back Pressure,
in-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1Q12 j/hr)
Plant Capacity at Cooling
System Design Point, MWe
Annual Make-up Water Requirement,
108 gal. (106 m3)
Mechanical Dry
(High BP Turbine)
92.0 (33.3)
72.0 (22.2)
131.0 (55.0)
24.0 (13.3)
63.0 (35.0)
9.65 (245.1)
11.72 (297.7)
4.78 (5.04)
943.8
0.0
Mechanical Dry*
(Low BP Turbine)
96.0 (35.6)
74.0 (23.3)
114.0 (45.6)
12.0 (6.7)
30.0 (16.7)
4.65 (118.1)
5.07 (128.8)
4.60 (4.85)
996.5
0.0
Mechanical Wet
(Low BP Turbine)
92.0 (33.3)
72.0 (22.2)
87.0 (30.6)
22.0 (12.2)
15.0 (8.3)
.2.91 (73.9)
3.05 (77.5)
4.49 (4.74)
1028.8
26.96 (10.21)
K>
O
oo
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE N-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 ra2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (nP/min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
Mechanical Dry
{High BP Turbine)
723 (67.2)
53,600
51.5 (15.7)
398 (1507)
3
63.1 (19.2)
3000 (2237)
2375 (1771)
Mechanical Dry*
(Low BP Turbine)
969 (90.0)
103,100
35.9 (10.9)
766 (2900)
6
55.2 (16.8)
2250 (1678)
2000 (1491)
Mechanical Wet
(Low BP Turbine)
723 (67.2)
54,900
50.3 (15.3)
408 (1544)
3
86.7 (26.4)
4000 (2983)
3345 (2494)
to
o
-------
TABLE N-l (continued)
Variable
Mechanical Dry
(High BP Turbine)
Mechanical Dry*
(Low BP Turbine)
Mechanical Wet
(Low BP Turbine)
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Size (Number of Cells):
Dry Tower
Wet Tower
114/1190 (290/363)
114/540 (290/165)
84/1180 (213/360)
106
114/1190 (290/363)
114/540 (290/165)
114/1180 (290/360)
217
120/1120 (305/341)
120/940 (305/287)
84/710 (213/216)
27
-------
TABLE H-2. SUMMARY OF CAPItAL INVESTMENT COST FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS (S106) AT NEW HAMPTON, NEW YORK - 1985
Acct. Ho.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
(I.
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
a
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Mechanical Dry
(High BP Turbine)
0.848
0.678
1.526
2.003
0.020
0.158
2.181
1.943
1.754
3.697
0.323
0.581
0.904
32.018
0.324
3.728
36.070
6.833
0.034
3.925
10.792
_
_
.
.
V
1.450
1.090
2.565
5.105
42.303
4.582
13.390
60.275
15.068
75.343
Mechanical Dry*
(Low BP Turbine)
1.079
0.863
1.942
3.647
0.037
0.316
4.000
3.621
3.101
6.722
0.663
1.191
1.854
65.547
0.662
7.632
73.841
9.427
0.047
4.919
14.393
^
.
»
.
2.808
2.110
5.244
10.162
81.429
8.220
23.265
112.914
28.228
141.142
Mechanical Wet
(Low BP Turbine)
0.856
0.682
1.538
2.240
0.023
0.158
2.421
1.890
1.679
3.569
1.752
3.151
4.903
6.635
0.067
4.328
11.030
6.857
0.034
3.939
10.830
2.015
5.841
11.068
18.924
0.786
0.591
0.545
1.922
18.534
11.054
25.550
55.138
13.784
68.922
* This is not an optimized system because of the turbine back pressure limitation.
-------
TABLE H-3. PENALTY BREAKDOWN ADD COST SUMAKY FOR THE OPTIMIZED REFERENCE COOLING SYSTEMS ($106)
AT NEW HAMPTON, HEW YORK - 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating filter
Pumping Power Requirement
Penalty for Circulating Hater
Punplng Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty for Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Hafce-up Water Punplng Energy
and Capacity Penalty
Cooling systen Maintenance Penalty
Cost Suaaary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Mechanical Dry
(High BP Turbine)
54.290
118.089
2.863
10.204
7.549
24.900
-
-
3.661
221.556
75.343
296.899
Mechanical Dry*
(Low BP Turbine)
24.715
1.030
4.823
16.131
15.002
44.498
-
-
6.980
113.179
141.142
254.321
Mechanical Wet
(Low BP Turbine)
5.990
2.359
4.032
13.495
2.056
6.676
0.299
5.461
2.205
42.573
69.922
111.495
* This Is not an optimized system because of the turbine back pressure limitation.
-------
TABLE H-4. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS AT NEW HAMPTON, NEW TtOHK - MECHANICAL SERIES - SI MODE
Variable
General Design Data
Mode of Wet/Dry Toner Operation
Design Parameters for Dry Towers:
Dry Bulb/Het Bulb Temperatures, °F (°C)
Cold Hater Temperature, °F (°C)
Cooling SADge, °F (°C)
Toner ITD, °F (°C)
Condenser Heat Load, 109 Btu/hr (1012 J/nr)
Design Fsraeters for Wet Helper Tower:
Dry Bulb/Wet Bulb Temperatures, °F (°C)
Tower Approach Temperature, °F (°C)
Design and Maximum Operating Back Pressure
Pmax. in-BgA (™*!gA)
Condenser Heat Load at P , 10 Btu/br
(1012 j/hr) •«
Heat Load Distribution at tmax- Wet Tower/
Dry Tower, X
Annual Make-up Water Requirement, ID8 gal (ID6 m3)
Percentage Make-up Requirement
2
SI
70.0/59.5 (21.1/15.3)
100.0 (37.8)
18.0 (10.0)
48.0 (26.7)
4.54 (4.79)
99.0/75.0 (37.2/23.9)
20.0 (11.1)
5.0 (127.0)
4.62 (4.87)
39.4/60.6
0.518 (0.196)
10
SI
55.0/49.0 (12.8/9.4)
89.0 (31.7)
22.0 (12.2)
56.0 (31.1)
4.50 (4.75)
99.0/75.0 (37.2/23.9)
20.0 (11.1)
4.0 (101.6)
4.55 (4.80)
62.5/37.5
2.71 (1.03)
20
SI
45.0/39.0 (7.2/3.9)
86.0 (30.0)
24.0 (13.3)
65.0 (36.1)
4.49 (4.74)
99.0/75.0 (37.2/23.9)
16.4 (9.1)
3.5 (88.9)
4.52 (4.77)
74.9/25.1
5.44 (2.06)
30
SI
30.0/26.0 (-1.1/-3.3)
83.0 (28.3)
26.0 (14.4)
79.0 (43.9)
4.49 (4.74)
99.0/75.0 (37.2/23.9)
14.4 (8.0)
3.5 (88.9)
4.52 (4.77)
79.3/20.7
8.22 (3.11)
40
SI
15.0/12.0 (-9.4/-11.1)
82.0 (27.8)
26.0 (14.4)
93.0 (51.7)
4.48 (4.73)
99.0/75.0 (37.2/23.9)
14.3 (7.9)
3.5 (88.9)
4.52 (4.77)
82.4/17.6
10.90 (4.13)
-------
IABLE N-4 (continued)
Variable
Condenser
Surface Area, 103 ft2, (103 m2)
Number of Tabes
Tube Length, ft (•)
Circulating Water Flow & Pump
3 3
Circulating Water Flow Rate, 10 gpm (nT /mln)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (fey) per pump
Motor Brake Horsepower, hp (Hi) per pump
Flow & Booster Pump for Wet Tover
Percentage of Circulating Water to Wet Helper Tover, I
Number of Pumps
Pumping Head, ft (n) of Water
Motor Rating, hp (VW) per pump
Motor Brake Horsepower, hp QcW) per pump
Percentage Make-up Requirement
2
794 (73.8)
67,800
44.7 (13.6)
504 (1908)
3
66.8 (20.4)
3500 (2610)
3182 (2373)
32.0
2
41.0 (12.5)
1500 (1119)
937 (699)
10
721 (67.0)
55,000
50.1 (15.3)
409 (1548)
3
68.2 (20.8)
3000 (2237)
2636 (1966)
81.6
2
41.0 (12.5)
2500 (1864)
1941 (1447)
20
693 (64.4)
50,400
52.6 (16.0)
374 (1416)
3
74.2 (22.6)
3000 (2237)
2625 (1957)
100.0
3
41.0 (12.5)
2000 (1491)
1451 (1082)
30
670 (62.2)
46,500
55.1 (16.8)
345 (1306)
2
81.9 (25.0)
4500 (3356)
4010 (2990)
100..0
2
41.0 (12.5)
2500 (1864)
2008 (1497)
40
672 (62.4)
46,400
55.3 (16.9)
345 (1306)
2
93.4 (28.5)
5000 (3729)
4570 (3408)
100.0
2
41.0 (12.5)
2500 (1864)
2006 (1496)
-------
TABLE N-4 (continued)
Variable
Circulating Hater Pipelines
Condenser Intake:
Bwber of Lines
Dime ter /Length , in/ft (cm/m)
Condenser Discharge:
Umber of Lines
Diameter/length, In/ft (cn/m)
Connecting Pipelines:
Huaber of Lines
Dimeter /Length, in/ft (cm/m)
Cooling lover
Sice (Number of Cells):
Dry Toner
Wet Toner
Percentage Make*up Reauireaent
2
1
132/1980 (335/604)
1
132/1490 (335/454)
2
90/760 (229/232)
129
8
10
1
120/1980 (305/604)
1
120/1490 (305/454)
2
84/760 (213/232)
110
13
20
1
114/1980 (290/604)
1
114/1490 (290/454)
2
78/760 (198/232)
92
18
30
1
108/1980 (274/604)
1
108/1490 (274/454)
2
78/760 (198/232)
73
21
40
1
108/1980 (274/604)
1
108/1490 (274/454)
2
78/760 (198/232)
59
21
-------
TABLE N-5. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($10 )
AT NEW HAMPTON, NEW YORK - MECHANICAL SERIES - Si MODE - 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(M
(L
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
Percentage Make-up Requirement
2
0.924
0.740
1.664
3.262
0.033
0.263
3.558
3.547
2.858
6.405
0.913
1.644
2.557
40.918
0.413
5.816
47.147
7.564
0.038
4.213
11.815
1.034
3.383
6.415
10.832
1.965
1.477
4.758
8.200
54.742
10.728
26.709
92.179
23.045
115.224
10
0.855
0.685
1.540
3.421
0.035
0.263
3.719
2.800
2.521
5.321
1.180
2.123
3.303
36.390
0.368
5.951
42.709
6.845
0.034
3.937
10.816
1.423
4.287
8.124
13.834
1.847
1.388
4.184
7.419
49.927
10.947
27.788
88.662
22.166
110.828
20
0.829
0.662
1.491
3.767
0.038
0.316
4.121
2.580
2.336
4.916
1.450
2.608
4.058
32.173
0.325
6.112
38.610
6.585
0.033
3.836
10.454
1.634
4.817
9.127
15.578
1.757
1.320
3.689
6.766
45.915
11.392
28,687
85.994
21.499
107.493
30
0.804
0.641
1.445
3.154
0.032
0.211
3.397
2.437
2.201
4.638
1.587
2.856
4.443
27.176
0.274
5.929
33.379
6.368
0.032
3.749
10.149
1.715
5.028
9.527
16.270
1.561
1.173
2.995
5.729
39.973
11.367
28.109
79.449
19.863
99.312
40
0.804
0.641
1.445
3.233
0.033
0.211
3.477
2.437
2.201
4.638
1.545
2.778
4.323
22.947
0.232
5.436
28.615
6.382
0.032
3.753
10.167
1.759
5.145
9.750
16.654
1.441
1.082
2.517
5.040
35.763
11.310
27.286
74.359
18.590
92.949
-------
TABLE N-6. PENALTY BREAKDOWN AND COST SUMMARY FDR THE OPTIMIZED WET/DRY COOLING SYSTEMS ($106)
AT NEW HAMPTON, NEW YORK - MECHANICAL SERIES - SI HOVE - 1985
I tea
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Penalty for Circulating Hater
Pumping Power Re qui resent
Penalty for Circulating Hater
Pumping Energy Requirement
Penalty for Cooling Tower Fan
Power Requirement
Penalty far Cooling Tower Fan
Energy Requirement
Make-up Water Purchase and
Treatment Penalty
Make-up Hater Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
Percentage Make-up Requirement
2
23.986
21.196
4.590
13.306
8.558
28.993
0.006
0.679
4.999
106.253
115.224
221.477
10
14.297
23.448
4.737
12.471
7.799
25.199
0.030
1.351
4.750
94.082
110.828
204.910
20
9.647
22.183
4.914
14.278
7.083
21.725
0.060
1.956
4.650
86.496
107.493
193.989
30
9.647
28.986
4.836
15.333
6.075
18.126
0.091
2.448
4.006
89.548
99.312
188.860
40
9.638
32.146
5.285
17.632
5.225
15.472
0.121
2.888
3.736
92.143
92.949
185.092
-------
APPENDIX 0
SITE COMPARISONS
This appendix contains the design data, and capital and penalty costs in-
formation developed for the wet/dry towers for water conservation during
the alternate site evaluations.
218
-------
TABLE O-l. MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: SAN JUAN, NEW MEXICO BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (Si)
Item
Number of Tower Cells,
Wet Tower/Dry Tower
Maximum Operating Back
Pressure ?__„. In-HgA
(nm-HgA)
Gross Plant Output at
Heat Load at P.™, 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at Pqaxj (Wet Tower/Dry
Tower) , 7.
Annual Make-up Water
for Wet Towers, 10® gal
(106 m3)
Mech.
Dry (H)*
0/112
12.60
(320.0)
920.4
4.86
(5.13)
0.0/100.0
0.0
(0.0)
Mech.
Dry(L)f
0/274
5.03
(127.8)
989.0
4.62
(4.87)
0.0/100.0
0.0
(0.0)
Percentage Make-up Requirement #
Mechanical Series Wet/Dry
2
7/161
5.0
(127.0)
989.5
4.62
(4.87)
38.7/61.3
0.625
(0.237)
10
11/117
4.5
(114.3)
999.1
4.59
(4.84)
60.9/39.1
2.90
(1.10)
20
13/98
4.0
(101.6)
1009.5
4.55
(4.80)
73.2/26.8
5.97
(2.26)
30
15/84
3.5
(88.9)
1019.1
4.52
(4.77)
82.2/17.8
8.85
(3.35)
40
17/70
3.5
(88.9)
1019.1
4.52
(4.77)
85.0/15.0
11.90
(4.50)
Mech.
Wet
21/0
3.12
(79.2)
1025.6
4.50
(4.75)
100.0/0.0
29.53
(11.18)
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 0-2. MAJOR CAPITAL AND PENALTY COST COMPONENTS
SITE: SAN JUAN, NEW MEXICO YEAR: 1985
FOR OPTIMIZED COOLING TOWER SYSTEMS ($106)
WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Hater System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Keen.
Dry (H)*
39.07
11.26
7.86
0.00
5.36
15.88
79.43
57.54
11.16
29.62
9.23
0.0
3.91
111.46
Mech.
Drya)*
95.58
14.46
12.51
0.00
12.45
33.75
168.75
24.27
23.37
0.49
17.45
0.0
8.15
73.73
Percentage Make-up Requirement-Mech. Ser. Wet/Dry
2
60.20
12.07
11.70
4.41
9.81
24.55
122.74
24.01
15.35
4.48
12.20
0.10
5.64
61.78
10
47.27
10.81
10.26
5.60
7.60
20.38
101.92
19.37
12.44
8.04
9.55
0.48
4.71
54.59
20
41.84
10.12
9.16
6.21
6.62
18.48
92.43
14.30
11.55
8.54
8.68
0.99
4.19
48.25
30
38.11
10.14
9.40
6.66
6.01
17.58
87.90
9.64
11.35
7.00
8.60
1.47
4.04
42.10
40
34.43
9.66
8.82
6.87
5.29
16.26
81.33
9.64
10.20
7.98
7.95
1.98
3.75
41.50
rtech.
Wet
12.39
10.13
6.50
7.56
1.52
9.53
47.63
6.48
5.56
2.23
4.53
4.92
1.81
25.53
K>
s
* H-High Back Pressure Turbine
* 1-Conventional Low Back Pressure Turbine
-------
TABLE 0-3. MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: COLSTRIP, MONTANA BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower /Dry Tower
Maximum Operating Back
Pressure ?„,.,,, in-HgA
(on-HgA)
Gross Plant Output at
pmax> MWe
Heat Load at P-.^, 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at P^x, (Wet Tower/Dry
Tower) , %
Annual Make-up Water
for Wet Towers, 10^ gal
(106 m3)
Mech.
Dry (H)*
0/112
12.58
(319.6)
920.6
4.62
(4.87)
O.O/
100.0
0.0
(0.0)
Mech.
0/268
5.03
(127.8)
988.9
4.86
(5.13)
O.O/
100.0
0.0
(0.0)
Percentage Make-up Requirement*
Mechanical Series Wet/Dry
2
7/153
5.01
(127.3)
989.6
4.52
(4.77)
42. 7/
57.7
0.518
(0.196)
10
11/100
4.50
(114.3)
999.1
4.50
(4.75)
64. 3/
35.7
3.05
(1.15)
20
13/84
4.00
(101.6)
1009.5
4.51
(4.76)
75.6/
24.4
6.03
(2.28)
30
18/75
3.50
(88.9)
1019.1
4.50
(4.75)
83. 7/
16.3
8.72
(3.30)
40
20/62
3.50
(88.9)
1019.1
4.49
(4.74)
86. 1/
13.9
11.45
(4.33)
Mech.
Wet
20/0
3.23
(82.0)
1023.7
4.50
(4.75)
100. O/
0.0
28.66
(10.85)
* H-High Back Pressure Turbine
I— Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 0-4. MAJOR CAPITAL AND PENALTY COST COMPONENTS
SITE: eOLSTRIP, MONTANA YEAR: 1985
FOR OPTIMIZED COOLING TOWER SYSTQ1S (S106)
WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
* Indirect Cost
total Capital Cost
Penalty Cost:
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
39.07
10.82
8.06
0.00
5.36
15.83
79.14
57.43
10.80
25.67
7.91
0.00
3.79
105.61
Mech.
Dry (L)*
93.49
14.46
14.65
0.00
12.30
33.72
168.62
24.27
23.02
-0.13
14.98
0.00
8.09
70.23
Percentage Make-up Requirement -Mech. Ser. Net/Dry
2
57.44
11.26
11.06
12.96
9.35
25.52
127.58
23.98
14.67
3.38
9.76
0.09
5.42
57.29
10
41.36
10.81
10.43
16.34
6.75
21.42
107.11
19.34
12.75
7.32
7.88
0.51
4.38
52.17
20
36.94
10.10
9.48
17.99
5.93
20.11
100.56
14.30
12.23
8.08
7.52
1.01
3.99
47.12
30
36.74
9.85
9.02
19.52
5.66
20.20
100.99
9.65
12.24
6.43
7.51
1.45
3.92
41.20
40
33.40
9.63
8.90
20.06
4.99
19.24
96.22
9.65
11.44
6.92
7.15
1.91
3.65
40.72
Mech.
Wet
11.80
10.44
7.43
21.81
1.55
13.26
66.30
7.41
7.47
1.75
5.12
4.78
1.95
28.45
ro
M
* H-High Back Pressure Turbine
'r 1-Conventional Low Back Pressure Turbine
-------
TABLE 0-5. MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: YOUNG, NORTH DAKOTA BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower/ Dry Tower
Maximum Operating Back
Pressure P-.a-t in-HgA
(mm-HgA)
Gross Plant Output at
Heat Load at fmx, 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at Pjnajj, (Wet Tower /Dry
Tower) , %
Annual Make-up Water
for Wet Towers, 108 gal
(106 m3)
Mech.
Dry (H)*
0/111
12.59
(319.8)
920.5
4.86
(5.13)
O.O/
100.0
0.0
(0.0)
Mech.
0/269
5.03
(127.8)
989.0
4.62
(4.87)
O.O/
100.0
0.0
(0.0)
Percentage Make-up Requirement?
Mechanical Series Wet/ Dry
2
8/133
5.0
(127.0)
989.7
4.62
(4.87)
49. 4/
50.6
0.613
(0.232)
10
10/91
5.0
(127.0)
989.8
4.62
(4.87)
64. 4/ ,
35.6
2,61
(0.99)
20
15/82
4.0
(101.6)
1009.5
4.55
(4.80)
78. 5/
21.5
5.18
(1.96)
30
17/63
4.0
(101.6)
1009.5
4.55
(4.80)
82.67
17.4
7.94
(3.01)
40
17/50
4.0
(101.6)
1009.5
4.55
(4.80)
85. 5/
14.5
10.92
(4.13)
Mech.
Wet
21/0
3.43
(87.1)
1020.3
4.52
(4.77)
100.07
0.0
26.43
(10.00)
* H-High Back Pressure Turbine
1 L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 0-6. MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR OPTIMIZED COOLING TOWER SYSTEMS ($106)
SITE: YOUNG, NORTH DAKOTA YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water Systen
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost;
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Hater
Cooling Systen Maintenance
Total Penalty
Mech.
Dry 00*
38.72
11.23
7.85
0.0
5.32
15.77
78.89
57.49
11.12
18.45
5.88
0.0
3.89
96.83
Mech.
Dry(L)*
93.83
15.77
14.80
0.0
12.52
34.24
171.16
24.27
23.87
-0.35
10.64
0.0
8.44
66.87
Percentage Make-up Requirement -Mech. Ser. Wet/Dry
2
51.08
11.79
11.62
8.01
8.41
22.73
113.63
23.90
13.81
2.48
6.79
0.10
5.08
52.16
10
37.63
10.09
9.16
9.30
6.13
18.08
90.39
23.86
10.88
6.57
5.21
0.44
3.96
50.92
20
37.42
9.87
8.94
10.46
5.91
18.15
90.75
14.30
11.06
5.09
5.22
0.86
3.99
40.52
30
31.97
9.59
8.83
10.84
4.92
16.53
82.68
14.30
9.89
6.64
4.76
1.32
3.59
40.50
40
27.45
9.63
8.91
11.06
4.28
15.33
76.66
14.30
9.56
7.53
4.77
1.82
3.34
41.32
Mech.
Wet
*
12.39
10.11
6.50
12.24
1.52
10.69
53.45
9.06
5.75
1.32
3.00
4.40
1.81
25.34
* H-Hlgh Back Pressure Turbine
* 1-Conventional Low Back Pressure Turbine
-------
TABLE 0-7. MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
SITE: ROCK SPRINGS, WYOMING BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower /Dry Tower
Maximum Operating Back
Pressure V^^, in-HgA
(ora-HgA)
Gross Plant Output at
Heat Load at P-,,., 109
Btu/hr (1012 J/hr)
Heat Load Distribution
at PO^JJ. (Wet Tower/Dry
Tower) , 7.
Annual Make-up Water
for Wet Towers, 10® gal
(106 m3)
Mech.
Dry (H)*
0/108
11.21
(284.7)
931.0
4.82
(5.08)
O.O/
100.0
0.0
(0.0)
Mech.
Drytt.)*
0/249
5.03
(127.8)
989.0
4.62
(4.87)
O.O/
100.0
0.0
(0.0)
Percentage Make-up Requirement?
Mechanical Series Wet/ Dry
2
6/129
5.00
(127.0)
989.8
4.62
(4.87)
34.6/
65.4
0.551
(0.209)
10
10/103
4.00
(101.6)
1009.5
4.55
(4.80)
57. 5/
42.5
2.78
(1.05)
20
12/85
3.50
(88.9)
1019.1
4.52
(4.77)
70. 7/
29.3
5.88
(2.23)
30
16/72
3.50
(88.9)
1019.1
4.52
(4.77)
76. 2/
23.8
8.58
(3.25)
40
18/58
3.50
(88.9)
1019.1
4.52
(4.77)
80. 2/
19.8
11.63
(4.40)
Mech.
Wet
20/0
2.94
(74.7)
1028.4
4.49
(4.74)
100. O/
0.0
28.03
(10.61)
N)
10
* H-High Back Pressure Turbine
* L-Conventional Low Back Pressure Turbine
# Percentage of annual make-up required by optimized wet tower
-------
TABLE 0-8. MAJOR CAPITAL AND PENALTY COST COMPONESTS
SITE: ROCK SPRINGS, WYOMING YEAR: 1965
FOR OPTIMIZED COOLING TOWER SYSTEMS ($10°)
WET/DRY TYPE: MECHANICAL SERIES (SI)
, Capital Cost:
Cooling Tower
Condenser
Circulating Water Systen
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost:
Capacity
; Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
37.67
10.79
7.40
0.00
5.19
15.26
76.32
52.39
10.46
27.49
8.22
0.0
3.70
102.25
Mech.
DryCL)*
86.86
11.18
7.74
0.00
11.02
29.20
146.01
24.27
19.66
0.37
14.30
0.0
6.84
65.42
Percentage Make-up Requirenent-Mech. Ser. Wet/Dry
2
48.49
11.28
: 10.86
14.00
7.97
23.15
115.75
23.86
12.85
4.48
9.43
0.10
4.84
55.56
10
41.81
10.84
10.33
18.29
6.87
! 22.04
110.18
14.30
12.42
5.34
8.48
0.50
4.41
45.44
20
36.69
10.22
9.40
20.66
5.94
20.73
103.63
9.64
11.90
5.68
8.00
1.04
3.99
.40.25
30
(
33.51
9.25
| 7.98
22.04
5.36
19.78
98.92
9.64
10.88
7.20
7.48
1.52
3.60
40.33
40
30.84
8.90
7.87
22.95
4.64
18.80
94.00
9.64
10.10
7.73
7.10
2.07
3.31
39.94
Mech.
Wet
11.80
10.15
6.50
26.04
1.48
13.99
69.95
5.14
6.79
1.74
5.10
4.98
1.78
25.54
* H-Hlgh Back Pressure Turbine
* L-Conventioanl Low Back Pressure Turbine
-------
TABLE 0-9.
SITE: HEW HAMPTON, NEW
MAJOR DESIGN DATA FOR THE OPTIMIZED COOLING TOWER SYSTEMS
YORK BASE OUTPUT: 1039 MWe WET/DRY TYPE: MECHANICAL SERIES (SI)
Item
Number of Tower Cells,
Wet Tower/ Dry Tower
Maximum Operating Back
Pressure P.—.., in-HgA
(om-HgA)
Gross Plant Output at
Pmaif » MWe
Heat Load at P_.x, 109
Btu/hr (1012 J/nr)
Heat Load Distribution
at P^ax, (Wet Tower/ Dry
Tower) , 7.
Annual Make-up Water
for Wet Towers, 108 gal
(106 ra3)
Mech.
Dry(H)*
0/106
11.72
(297.7)
927.1
4. S3
(5.10)
O.O/
100.0
0.0
(0.0)
Hech.
Dry(L)*
0/217
5.07
(128.8)
988.0
4.63
(4.88)
O.O/
100.0
0.0
(0.0)
Percentage Make-up Requirement #
Mechanical Series Wet/Dry
2
8/129
5.0
(127.0)
989.5
4.62
(4.87)
39. 4/
60.6
0.518
(0.196)
10
13/110
4.0
(101.6)
1009.5
4.55
(4.80)
62. 5/
37.5
2.71
(1.03)
20
18/92
3.5
(88.9)
1019.1
4.52
(4.77)
74. 9/
25.1
5.44
(2.06)
30
21/73
3.5
(88.9)
1019.1
4.52
(4.77)
79. 3/
20.7
8.22
(3.11)
40
21/59
3.5
(88.9)
1019.1
4.52
(4.77)
82. 4/
17.6
10.90
(4.13)
Mech.
Wee
27/0
3.05
(77.5)
1026.6
4.49
(4.74)
100. O/
0.0
26.96
(10.21)
* H-High Back Pressure Turbine
L-Conventional Low Back Pressure Turbine
f Percentage of annual make-up required by optimized wet tower
-------
TABLE 0-10. MAJOR CAPITAL AND PENALTY COST COMPONENTS FOR OPTIMIZED COOLING TOWER SYSTEMS <$106)
SITE: NEW HAMPTON, NEW YORK YEAR: 1985 WET/DRY TYPE: MECHANICAL SERIES (SI)
Capital Cost:
Cooling Tower
Condenser
Circulating Water System
Make-up Facility
Electrical Equipment
Indirect Cost
Total Capital Cost
Penalty Cost;
Capacity
Auxiliary Power
Replacement Energy
Auxiliary Energy
Make-up Water
Cooling System Maintenance
Total Penalty
Mech.
Dry (H)*
36.97
10.79
7.40
-
5.11
15.07
75.34
54.29
10.42
118.09
35.10
-
3.66
221.56
Mech.
DryCD*
75.69
14.39
12.67
-
10.16
28.23
141.14
24.72
19.82
1.03
60.63
-
6.98
113.18
Percentage Make-up Requirement -Mech. Ser. Wet/Dry
2
49.70
11.82
11.62
10.83
8.20
23.05
115.22
23.99
13.75
21.20
42.30
0.01
5.00
106.25
10
46.01
10.82
10.58
13.83
7.42
22.17
110.83
14.30
13.48
23.45
38.07
0.03
4.75
94.08
20
42.67
10.45
10.52
15.58
5.77
21.50
107.49
9.65
13.16
22.18
36.80
0.06
4.65
86.50
30
37.82
10.15
9.48
16.27
5.73
19.86
99.31
9.65
12.14
28.99
34.67
0.09
4.01
89.55
40
32.94
10.17
9.56
16.65
5.04
18.59
92.95
9.64
11.80
32.15
34.69
0.12
3.74
92.14
Mech.
Wet
15.94
10.83
7.53
18.92
1.92
13.78
68.92
5.99
7.64
2.36
24.07
0.30
2.21
42.57
* H-High Back Pressure Turbine
f L-Conventional Low Back Pressure Turbine
-------
10
VO
100 --
3000 4000 5000 6000
Cumulative Duration (hrs)
Figure 0-1 Temperature Duration Curves: Kaiparowits, Utah
40
30
_ 20
-20 -L
- 10
0
- -10
- -20
J -30
u
o
0)
f-f
0)
o.
-------
250-
225-
200-
175-
"o 150-
£
J125-
M
§ 100-
1-4
a
3
-« 75-
M
4Jt
H
50-
25-
0
^
^
V
V
^1
\
\ '
\-
x
x
1. -..
\c
s\
^_^
^ K
§
\/
X
1 — 1
t
fc
— i-
^
1
p^q Cooling System Coupled With A
11
pq
^
*•
—
^
§
B^l High Back Pressure turbine
\
^
g
S
^
t;
<
| — 1 Cooling System Coupled With A
x ' . I I Conventional Low Back Pressure
-«s
I
£
3
— . — .
•we
I
J
t
O
Turbine
—•
|
s
i
1-
§
1
^"^-^
N
>.
<
"
—
j
2
i
u
Dry " J 10 20 5o 4b 50 66 70 rfo 96 1*00
Percentage Make-up Requirement (% of Wet System)
Figure 0-2 Total Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
(Kaiparowits, Mechanical Series, SI Mode, 1985)
-------
100 t-
SO -
60 -
10
P.
H
40 -
20 -
1000 2000 3000
4000 5000 6000
Cumulative Duration (hrs)
Figure 0-3 Temperature Duration Curves: San Juan, New Mexico
7000 8000
. 40
30
- 20
0)
S-l
4J
8
- 10
0
- -10
^000
-------
N)
U>
250-
225-
200-
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80
90
100
Figure 0-4 Total Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
(San Juan, Mechanical Series, Si Mode, 1985)
-------
to
.100-
40
4000 5000 6000
Cumulative Duration (hrs)
8000
30
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Figure 0-5 Temperature Duration Curves: Colstrip, Montana
-20
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-------
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200 -
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€ 150 -
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!
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Figure 0-6
Percentage Make-up Requirement (% of Wet System)
Total Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
(Colstrip, Mechanical Series, Si Mode, 1985)
-------
100. .
to
u
ui
1000
2000
3000
-20- -
4000 500
Cumulative Duration (hrs)
Figure O-7 Temperature Duration Curves: Young, North Dakota
BOOT
30
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2
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-10
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Percentage Make-up Requirement (% of Wet System)
80
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Figure 0-8 Total Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
(Young, Mechanical Series, SI Mode, 1985)
-------
100 --
40
NJ
80 - -
Dry Bulb
1000
2000
7000
-20 _L
3000 4000 5000 6000
Cumulative Duration (hrs)
Figure 0-9 Temperature Duration Curves: Rock Springs, Wyoming
8000
30
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Percentage Make-up Requirement (% of Wet System)
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Figure 0-10 Total
(Rock
Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
Springs, Mechanical Series, Si Mode, 1985)
-------
100
40
ro
CJ
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80 --
60
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Cumulative Duration (hrs)
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Figure 0-11 Temperature Duration Curves: New Hampton, New York
-------
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Figure 0-12
Percentage Make-up Requirement (% of Wet System)
Total Evaluated Cost and the Penalty and Capital Components for the Optimized Systems
(New Hampton, Mechanical Series. SI Mode, 1985)
-------
APPENDIX P
MECHANICAL WET AND HYBRID WET/DRY COOLING SYSTEMS FOR PLUME ABATEMENT
This appendix contains design data, capital investment and penalty break-
downs for the optimized mechanical wet and hybrid wet/dry cooling systems
operating at Seattle, Washington; Cleveland, Ohio; Newark, New Jersey; and
Charlotte, North Carolina.
241
-------
TABLE P-l. SIM4ARY OF DESIGN DATA FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS
SITE: SEATTLE, WASHINGTON
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
tn-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (1Q12 J/hr)
Plant Capacity at Cooling
System Design Point, MWe
Ground Fogging (hrs/year)
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
80.0 (26.7)
64.0 (17.8)
74.0 (23.3)
30.0 (16.7)
10.0 (5.6)
2.54 (64.5)
2.78 (70.6)
4.47 (4.72)
1033.9
5
10 Hours
80.0 (26.7)
64.0 (17.8)
75.0 (23.9)
28.0 (15.6)
11.0 (6.1)
2.45 (62.2)
2.69 (68.3)
4.47 (4.71)
1034.9
9
20 Hours
80.0 (26.7)
64.0 (17.8)
76.0 (24.4)
30.0 (16.7)
12.0 (6.7)
2.68 (68.1)
2.91 (73.9)
4.48 (4.72)
1032.1
19
30 Hours
80.0 (26.7)
64.0 (17.8)
78.0 (25.6)
26.0 (14.4)
14.0 (7.8)
2.52 (64.0)
2.75 (69.9)
4.47 (4.72)
1034.1
32
60 Hours
80.0 (26.7)
64.0 (17.8)
82.0 (27.8)
26.0 (14.4)
18.0 (10.0)
2.83 (71.9)
3.04 (77.2)
4.48 (4.73)
1030.0
60
-------
TABLE P-l (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 ra2)
Number of tubes
Tube Length, ft (a)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (mJ/Bin)
Number of Pumps
Pumping Head, ft (ra) of Hater
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
630 (58.5)
40,100
60.0 (18.3)
298 (1128)
2
87.4 (26.6)
4000 (2984)
3695 (2756)
10 Hours
664 (61.7)
42,900
59.1 (18.0)
319 (1208)
2
88.4 (26.9)
4500 (3357)
3999 (2983)
20 Hours
631 (58.6)
40,200
60.0 (18.3)
298 (1128)
2
87.6 (26.7)
4000 (2984)
3709 (2767)
30 Hours
682 (63.3)
46,300
56.3 (17.2)
344 (1302)
2
86.0 (26.2)
4500 (3357)
4194 (3129)
60 Hours
672 (62.4)
46,400
55.3 (16.9)
345 (1306)
2
85.4 (26.0)
4500 (3357)
4178 (3117)
-------
TABLE F-l (continued)
Variable
Circulating Water Pipelines
• Condenser Intake:
Number of Lines
Diameter/Length, In/ft (cra/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ft (cm/a)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Number of Cells
Heat Exchanger Tube Length, ft (m)
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
1
102/1120
(259/341)
1
102/940
(259/287)
2
72/710
(183/216)
43
10 Hours
1
102/1120
(259/341)
1
102/940
(259/287)
2
72/710
(183/216)
41
20 Hours
1
102/1120
(259/341)
1
102/940
(259/287)
2
72/710
(183/216)
37
30 Hours
1
108/1120
(259/341)
1
108/940
(259/287)
2
78/710
(198/216)
33
60 Hours
1
108/1120
(259/341)
1
108/940
(259/287)
2
78/710
(198/216)
26
-------
TABLE P-2. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS ($106)
SITE: SEATTLE, WASHINGTON YEAR: 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
i
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
4.004
-.220
2.969
5.985
2.782
5.376
, 0.393
.215
2.267
23.771
56.406
80.177
10
3.392
-.657
3.214
6.475
2.645
5.115
0.393
.213
2.266
23.056
55.589
78.645
20
4.949
.760
2.981
6.014
2.372
4.603
0.393
.211
2.114
•
24.397
51.840
76.237
30
3.816
.008
3.371
6.796
2.099
4.083
0.394
.209
2.073
27.849
50.246
73.095
Reference
60
5.893
2.357
3.358
6.784
1.627
3.187
0.399
.207
1.891
25.703
44.815
70.518
-------
TABLE P-3. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS (S106)
SITE: SEATTLE, WASHINGTON
PRICING YEAR: 1985
Acct. Ho.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers , Installed (E
(H
(L
(T
Make-up Facilities (E
(M
(L
(T
Electrical Equipment (E
(M
a
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
0.762
0.609
1.371
1.656
0.017
0.105
1.778
1.660
1.351
3.011
2.791
5.020
7.810
8.917
0.090
7.234
16.242
6.653
0.033
3.604
10.291
0.561
0.652
1.110
2.323
0.891
0.669
0.740
2.299
18.678
6.674
19.773
45.125
11.281
56.406
10
0.781
0.623
1.404
1.736
0.018
0.105
1.859
1.660
1.351
3.011
2.661
4.786
7.447
8.501
0.086
6.897
15.484
6.956
0.035
3.701
10.692
0.555
0.646
1.100
2.301
0.893
0.671
0.710
2.274
18.641
6.558
19.273
44.472
11.117
55.589
20
0.762
0.609
1.371
1.656
0.017
0.105
1.778
1.660
1.351
3.011
2.401
4.319
6.720
7.673
0.078
6.224
13.975
6.661
0.033
3.607
10.301
0.545
0.635
1.081
2.261
0.802
0.602
0.650
2.054
17.337
6.188
17.496
41.471
10.369
51.840
30
0.802
0.641
1.443
1.736
0.018
0.105
1.859
1.853
1.472
3.325
2.141
3.852
5.993
6.843
0.069
5.551
12.463
7.142
0.036
3.769
10.947
0.534
0.623
1.061
2.218
0.777
0.583
0.589
1.949
17.032
6.125
17.040
40.197
10.049
50.246
Reference
60
0.804
0.641
1.445
1.736
0.018
0.105
1.859
1.853
1.472
3.325
1.687
3.034
4.721
5.391
0.054
4.374
9.819
7.077
0.036
3.753
10.866
0.517
0.605
1.031
2.153
0.674
0.506
0.483
1.663
15.395
5.563
14.893
35.851
8.962
44.815
-------
TABLE P-4. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS
5 HOURS PER YEAR GROUND FOG
SITE: SEATTLE, WASHINGTON
Variable
General Design Data
Design Temperatures, °f (°C) :
Dry Bulb
Net Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
In-HgA (inm-IlgA)
Maximum Operating Back Pressure,
in-HgA (mra-IlgA)
Design Heat Load,
109 Btu/hr (1Q12 J/hr)
Plant Capacity at Cooling
System Design Point, MUe
Ground Fogging (hrs/year)
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
80.0 (26.7)
64.0 (17.8)
80.0 (26.7)
26.0 (14.4)
16.1 (8.9)
2.67 (67.9)
2.90 (73.7)
4.48 (4.73)
1032.2
4
10 ft
80.0 (26.7)
64.0 (17.8)
79.0 (26.1)
26.0 (14.4)
15.0 (8.3)
2.60 (65.9)
2.82 (71.6)
4.47 (4.72)
1033.2
4
5 ft
80.0 (26.7)
64.0 (17.8)
77.0 (25.0)
28.0 (15.6)
13.0 (7.2)
2.60 (65.9)
2.83 (71.9)
4.47 (4.72)
1033.2
4
. Wet Tower
System
80.0 (26.7)
64.0 (17.8)
74.0 (23.3)
30.0 (16.7)
10.0 (5.6)
2.54 (64.5)
2.78 (70.6)
4.47 (4.72)
1033.9
5
-------
TABLE P-4 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
(lumber of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpra (m'/mln)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
676 62.8
46,300
55.8 (17.0)
344 (1302)
2
93.5 (28.5)
5000 (3730)
4560 (3405)
10 ft
679 (63.1)
46.300
56.0 (17.1)
344 (1302)
2
91.1 (27.8)
5000 (3730)
4444 (3314)
5 ft
658 (61.1)
42,900
58.4 (17.8)
319 (1207)
2
90.8 (27.7)
4500 (3356)
4109 (3064)
Wet Tower
System
630 (58.5)
40,100
60.0 (18.3)
298 (1128)
2
87.4 (26.6)
4000 (2984)
3695 (2756)
to
4>
00
-------
TABLE P-4 (continued)
Variable'
CirculattnR Watec Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, In/ft (cm/m)
Condenser Discharge:
Number of Lines
Diameter/Length, In/ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ ft (cm/m)
Cooling; Tower
Number of Cells
Heat Exchanger Tube Length, ft (in)
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
29
15
10 ft
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
31
10
5 ft
1
102/1120(259/341)
1
102/940(259/287)
2
72/710(183/216)
35
5
Wet Tower
System
1
102/1120(259/341)
1
102/940(259/287)
2
72/710(183/216)
43
s
-------
TABLE P-5. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS (S106)
5 HOURS PER YEAR GROUND FOG
SITE: SEATTLE, WASHINGTON
YEAR: 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
4.818
1.095
3.670
7.405
1.829
3.570
0.396
.207
2.360
25.350
53.919
79.269
10 ft
4.289
.512
3.570
7.203
1.964
3.826
0.395
.208
2.336
.
24.303
54.077
78.380
5 ft
4.347
.330
3.307
6.669
2.235
4.342
0.393
.210
2.316
24.149
54.742
78.891
Wet Tower
System
4.004
-.220
2.969
5.985
2.782
5.376
0.393
0.215
2.267
23.771
56.406
80.177
-------
TABLE P-6. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS ($106)
SITE: SEATTLE, WASHINGTON PRICING YEAR: 1985
Acct. No.
118L
132.211 •
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
a
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers, Installed (E
(M
(L
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
HEAT EXCHANGER TUBE LENGTH
15 ft.
0.804
0.641
1.445
1.815
0.018
0.105
1.938
1.853
1.472
3.325
1.881
3.385
5.266
8.912
0.090
7.232
16.234
7.108
0.036
3.760
10.904
0.524
0.612
1.043
2.179
0.750
0.564
0.529
1.843
19.109
5.858
18.167
43.134
10.785
53.919
10 ft.
0.802
0.641
L.443
1.815
0.018
0.105
1.938
1.853
1.472
3.325
2.011
3.618
5.629
8.717
0.088
7.072
15.877
7.125
0.036
3.765
10.926
0.529
0.618
1.052
2.199
0.780
0.586
0.559
1.925
18.966
6.012
18.284
43.262
10.815
54.077
5 ft.
0.781
0.625
1.406
1.736
0.018
0.105
1.859
1.660
1.351
3.011
2.271
4.085
6.356
8.925
0.090
7.241
16.256
6.912
0.035
3.689
10.636
0.539
0.629
1.071
2.239
0.806
0.606
0.618
2.030
18.918
6.090
18.785
43.793
10.949
54.742
Wet lower
System
0.762
0.609
1.371
1.656
0.017
0.105
1.778
1.660
1.351
3.011
2.791
5.020
7.811
8.917
0.090
7.234
16.241
6.653
0.033
3.604
10.290
0.561
0.652
1.110
2.323
0.890
0.669
0.740
2.299
ii-.m
19.773
45.124
11.282
56.406
-------
TABLE P-7. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS
SITE: CLEVELAND, OHIO
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Met Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
In-HgA (nm-HgA)
Maximum Operating Back Pressure,
in-HgA (mra-HgA)
Design Heat Load,
10s Btu/hr (1012 J/hr)
Plant Capacity at Cooling
System Design, Point, MWe
Ground Fogging (hrs/year)
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
90.0 (32.2)
71.0 (21.7)
80.0 (26.7)
28.0 (15.6)
9.0 ( 5.0)
2.83 (71.9)
2.87 (72.9)
4.48 (4.73)
1030.0
4
10 Hours
90.0 (32.2)
71.0 (21.7)
82.0 (27.8)
26.0 (14.4)
11.0 ( 6.1)
2.83 (71.9)
2.86 (72.6)
4.48 (4.73)
1030.0
11
20 Hours
90.0 (32.2)
71.0 (21.7)
84.0 (28.9)
26.0 (14.4)
13.0 ( 7.2)
2.99 (76.1)
3.02 (76.7)
4.49 (4.74)
1027.6
21
30 Hours
90.0 (32.2)
71.0 (21.7)
86.0 (30.0)
24.0 (13.3)
15.0 ( 8.3)
2.99 (76.1)
3.01 (76.5)
4.49 (4.74)
1027.6
31
38 Hours
90.0 (32.2)
71.0 (21.7)
86.0 (30.0)
26.0 (14.4)
15.0 ( 8.3)
3.17 (80.5)
3.19 (81.0)
4.50 (4.75)
1024.8
38
-------
TABLE P-7 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpn (m3/min)
Number of Pumps
Pimping Head, ft (m) of Hater
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (KH) per pump
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
651(605)
43,100
57.7(17.6)
320(1211)
2
87.6(26.7)
4500(3357)
3978(2967)
10 Hours
672(624)
46,400
55.3(16.9)
345(1306)
2
85.4(26.0)
4500(3357)
4178(3117)
20 Hours
669(621)
46,500
54.9(16.7)
345(1306)
2
85.7(26.0)
4500(3357)
4174(3114)
30 Hours
694(64.5)
50,400
52.6(16.0)
374(1416)
3
83.9(25.6)
3500(2611)
2969(2215)
38 Hours
666(61.9)
46,600
54.6(16.6)
346(1310)
2
84.9(25.9)
4500(3357)
4172(3112)
-------
TABLE P-7 (continued)
Variable
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (ca/m)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ ft (cm/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Number of Cells
Heat Exchanger Tube Length, ft (m)
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
1
102/1120
(259/341)
1
102/940
(259/287)
2
72/710
(183/216)
40
10 Hours
1
108/1120
(274/341)
1
108/940
(274/287)
2
78/710
(198/216)
35
20 Hours
1
108/1120
(274/341)
1
108/940
(274/287)
2
78/710
(198/216)
30
30 Hours
1
114/1120
(296/341)
1
114/940
(290/287)
2
78/710
(198/216)
27
38 Hours
1
105/1120(267/341)
1
108/940(274/287)
2
78/710
(198/216)
26
-------
TABLE P-8. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS
SITE: CLEVELAND, OHIO YEAR: 1985
($106)
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
5
GROUND FOGGING HOURS - MECHANICAL WET TOWERS
5
4.637
0.392
3.197
6.447
2.583
4.924
0.399
0.218
2.236
25.033
54.747
79.780
10
4.564
0.553
3.358
6.773
2.238
4.285
0.398
0.214
2.120
24.503
51.730
76.230
20
5.726
1.820
3.354
6.774
1.895
3.652
0.400
0.212
1.991
25.824
47.880
73.704
30
5.663
1.992
3.579
7.229
1.691
3.271
0.401
0.210
2.114
26.150
47.016
73.166
Reference
38
7.041
3.377
3.353
6.779
1.623
3.147
0.403
0.210
1.888
27.821
44.799
72.628
-------
TABLE P-9. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS CS106)
SITE: CLEVELAND, OHIO PRICING YEAR: 1985
Acct. No.
1181.
132.211
132.25
132.3211
132.3212
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
Ul
Oi
-------
TABLE P-10. SUM4ARY OF DESIGN DATA FOR THE OPTIMIZED NET/DRY AND REFERENCE COOLING SYSTEMS
5 HOURS PER YEAR GROUND FOG
SITE: CLEVELAND, OHIO
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
in-HgA (ran-HgA)
Maximum Operating Back Pressure,
in-HgA (nm-HgA)
Design Heat Load,
109 Btu/hr (1012 J/hr)
Plant Capacity at Cooling
System Design Point, MWe
Ground Fogging (hrs/year)
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
90.0 (32.2)
71.0 (21.7)
86.0 (30.0)
25.0 (13.9)
15.0 ( 8.3)
3.08 (78.2)
3.08 (78.2)
4.50 (4.75)
1026.2
4
10 ft
90.0 (32.2)
71.0 (21.7)
84.0 (28.9)
25.0 (13.9)
13.0 ( 7.2)
2.91 (73.9)
2.95 (74.9)
4.49 (4.74)
1028.8
4
5 ft
90.0 (32.2)
71.0 (21.7)
83.0 (28.3)
26.0 (14.4)
12.0 ( 6.7)
2.91 (73.9)
2.94 (74.7)
4.49 (4.74)
1028.8
4
Wet Tower
System
90.0 (32.2)
71.0 (21.7)
80.0 (26.7)
28.0 (15.6)
9.0 ( 5.0)
2.83 (71.9)
2.87 (72.9)
4.48 (4.73)
1030.0
4
-------
TABLE P-10 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 m2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
1Q3 gpm (m3/min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
679 (63.1)
48,400
53.6 (16.3)
360 (1363)
2
92.8 (28.3)
5000 (3730)
4737 (3532)
10 ft
682 (63.4)
48,300
53.9 (16.4)
359 (1359)
2
90.5 (27.6)
5000 (3730)
4609 (3437)
5 ft
670 (62.2)
46,500
55.1 (16.8)
345 (1306)
2
87.9 (26.8)
5000 (3730)
4302 (3209)
Wet Tower
System
651 (60.5)
43,100
57.7 (17.6)
320 (1211)
2
87.6 (26.7)
4500 (3357)
3978 (2968)
to
Ul
00
-------
TABLE P-10 (continued)
Variable
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ ft (cm/a)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ ft (cm/ra)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ft (cm/m)
Cooling Tower
Number of Cells
Heat Exchanger Tube Length, ft (m)
DRY HEAT EXCHANGER TUBE LENGTH
IS ft
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
27
15 (4.6)
10 ft
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
30
10 (3.0)
5 ft
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
32
5 (1.5)
Wet Tower
System
1
102/1120(259/341)
1
102/940(259/287)
2
72/710(183/216)
40
3
-------
TABLE P-ll. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED MET/DRY AND REFERENCE COOLING SYSTEMS ($106)
5 HOURS PER YEAR GROUND FOG
SITE: CLEVELAND, OHIO YEAH: 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pimping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Coat Summary;
.Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
DRY HEAT EXCHANGER TUBE LENGTH
15 ft
6.198
2.537
3.807
7.693
1.692
3,272
0.402
0.210
2.230
28.041
52.144
80.185
10 ft
5.168
1.321
3.703
7.476
1.895
2.651
0.400
0.211
2.308
25.133
53.355
78.488
5 ft
5.166
1.198
3.457
6.977
2.032
3.905
0.399
0.213
2.264
25.611
53.060
78.671
Mechanical
Wet System
4.637
0.392
3.197
6.447
2.583
4.924
0.399
0.218
2.236
25.033
54.747
79.780
-------
TABLE P-12. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY AND REFERENCE COOLING SYSTEMS (S106)
SITE: CLEVELAND, OHIO PRICING YEAR: 1985
Acct. No.
1I8L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
-------
TABLE P-13. StMKARY OF DESIGN DATA. FOR THE OPTIMIZED WET/DRY AND MECHANICAL WET COOLING SYSTEMS
SITE: NEWARK, NEW JERSEY
Variable
General Design Data
Design Temperatures, °F (°C):
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
in-HgA (mm-HgA)
Maximum Operating Back Pressure,
in-HgA (nm-HgA)
Design Heat Load,
109 Btu/hr (1012 J/hr)
Plant Capacity at Cooling
System Design Point, MWe
Ground Fogging (hrs/year)
Mechanical
Wet/ Dry Towers
(5* Exchanger)
5 Hours
92.0 (33.3)
75.0 (23.9)
88.0 (31.1)
22.0 (12.2)
13.0 (7.2)
2.99 (76.1)
3.26 (82.8)
4.49 (4.74)
1027.6
3
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
92.0 (33.3)
75.0 (23.9)
86.0 (30.0)
26.0 (14.4)
11.0 (6.1)
3.17 (80.5)
3.46 (87.9)
4.50 (4.75)
1024.8
3
10 Hours
92.0 (33.3)
75.0 (23.9)
88.0 (31.1)
22.0 (12.2)
13.0 (7.2)
2.99 (76.1)
3.26 (82.8)
4.49 (4.74)
1027.6
10
Reference
16 Hours
92.0 (33.3)
75.0 (23.9)
90.0 (32.2)
22.0 (12.2)
15.0 (8.3)
3.17 (80.5)
3.41 (86.6)
4.50 (4.75)
1024.8
16
to
0»
N>
-------
TABLE P-13 (continued)
Variable
Condenser
Surface Area. 103 ft2 (103 n2)
Number of Tubes
Tube Length, ft (o)
Circulating Water Flow 6. Pump
Circulating Water Flow Rate,
103 gpa (ra-Vmin)
Number of Pumps
Pumping Head, ft (a) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per purap
Mechanical
Wet/Dry Towers
(5' Exchanger)
5 Hours
722 (67.1)
55000
50.2 (15.3)
408 (1544)
3
84.3 (25.7)
4000 (2954)
3257 (2430)
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
666 (61.9)
46600
54.6 (16.6)
346 (1310)
2
84.9 (25.9)
4500 (3337)
4172 (3112)
10 Hours
722 (67.1)
55000
50.2 (15.3)
408 (1544)
3
81.8 (24.9)
3500 (2611)
3159 (2357)
Reference
16 Hours
720 (66.9)
55100
49.9 (15.2)
409 (1548)
3
81.6 (21.9)
3500 (2611)
3159 (2357)
-------
TABLE P-13 (continued)
Variable
Circulating Hater Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, in/ft (crn/rn)
Condenser Discharge:
limber of Lines
Diameter/Length, In/ft (cu/m)
Connecting Pipelines:
Number of Lines
Diameter/Length, In/ft (cm/m)
Cooling Tower
Number of Cells
Heat Exchanger Tube Length, ft (ra)
Mechanical
Met/ Dry lowers
(S1 Exchanger)
5 Hours
1
120/1120(305/341)
1
120/940 (305/287)
2
84/710(213/216)
26
5
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
1
108/1120(274/341)
1
108/940(274/287)
2
78/710(198/216)
31
10 Hours
1
120/1120(305/341)
1
120/940(305/287)
2
84/710(213/216)
28
Reference
16 Hours
1
120/1120(305/341)
1
120/940(305/287)
2
84/710(213/216)
25
-------
TABLE P-14. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED WET/DRY AHD MECHANICAL WET COOLIHG SYSTEMS ($106)
SITE: NEWARK, NEW JERSEY YEAR: 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Hater Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Summary:
Total Penalty Cost
Total Capital Coat
Total Evaluated Cost
]
Mechanical
Wet/ Dry Towers
(5' Exchanger)
5 Hours
7.633
1.321
3.926
7.925
1.813
3,498
0.398
0.210
2.370
29.094
52.034
81.128
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
9.254
2.176
3.353
6.772
2.024
3.893
0.397
0.212
2.016
30.097
48.624
78.721
10 Hours
7.633
1.321
3.808
7.685
1.813
3.498
0.398
0.210
2.156
28.522
48.736
77.258
Reference
16 Hours
8.892
2.616
3.808
7.695
1.604
3.109
Q.400
0.209
2.079
30.412
46.439
76.851
-------
TABLE P-15. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY AND MECHANICAL WET COOLING SYSTEMS (S106)
SITE: NEWARK, NEW JERSEY PRICING YEAR: 1985
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
a
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers , Installed (E
(M
(L
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(I
Indirect Cost
Total Capital Cost
Mechanical
Wet/Dry Towers
5 hours
0.856
0.682
1.538
2.241
0.023
0.158
2.422
2.133
1.679
3.812
1.816
3.268
5.084
7.140
0.072
5.794
13.006
7.611
0.038
3.939
11.588
0.533
0.622
1.059
2.214
0.802
0.602
0.559
1.963
18.327
6.162
17.138
41 .627
10.407
52.034
MECHANICAL WET TOWER - GROUND FOGGING
5 Hours
0.804
0.643
1.447
1.736
0.018
0.105
1.859
1.853
1.472
3.325
2.011
3.618
5.629
6.429
0.065
5.217
11.711
7.035
0.035
3.743
10.813
0.542
0.631
1.075
2.248
0.747
0.561
0.559
1.867
16.489
5.978
16.432
38.899
9.725
48.624
10 Hours
0.856
0.682
1.538
2.122
0.021
0.158
2.301
2.133
1.679
3.812
1.816
3.268
5.084
5.805
0.059
4.711
10.575
7.611
0.038
3.939
11.588
0.533
0.622
1.059
2.214
0.753
0.565
0.559
1.877
16.824
6.110
16.055
38.989
9.747
48.736
Reterence
16 Hours
0.856
0.685
1.541
2.122
0.021
0.158
2.301
2.133
1.679
3.812
1.622 '
2.917
4.539
5.183
0.052
4.207
9.442
7.600
0.038
3.937
11.575
0.526
0.615
1.046
2.187
0.708
0.533
0.513
1.754
16.139
5.870
15.142
37.151
9.288
46 .439
-------
TABLE P-16. SUMMARY OF DESIGN DATA FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS
SITE: CHARLOTTE, NORTH CAROLINA
Variable
General Design Data
Design Temperatures, °F (°C) :
Dry Bulb
Wet Bulb
Cold Water
Cooling Range
Approach
Design Turbine Back Pressure,
in-HgA (ran-HgA)
Maximum Operating Back Pressure,
in-HgA (mm-HgA)
Design Heat Load,
109 Btu/hr (10 12 J/hr)
Plant Capacity at Cooling
System Design Point, MWe
Ground Fogging (hr a/year)
MECHANICAL NET TOWER - GROUND FOGGING
10
97.0 (36.1)
73.0 (22.8)
83.0 (28.3)
26.0 (14.4)
10.0 (5.6)
2.91 (73.9)
3.01 (76.5)
4.49 (4.74)
1028.8
11
20
97.0 (36.1)
73.0 (22.8)
85.0 (29.4)
24.0 (13.3)
12.0 (6.7)
2.91 (73.9)
3.00 (76.2)
4.49 (4.74)
1028.8
20
30
97.0 (36.1)
73.0 (22.8)
85.0 (29.4)
26.0 (14.4)
12.0 (6.7)
3.08 (78.2)
3.17 (80.5)
4.50 (4.75)
1026.2
32
Reference
61
97.0 (36.1)
73.0 (22.8)
89.0 (31.7)
22.0 (12.2)
16.0 (8.9)
3.08 (78.2)
3.13 (79.5)
4.50 (4.75)
1026.2
61
-------
TABLE P-16 (continued)
Variable
Condenser
Surface Area, 103 ft2 (103 ra2)
Number of Tubes
Tube Length, ft (m)
Circulating Water Flow & Pump
Circulating Water Flow Rate,
103 gpm (m3/min)
Number of Pumps
Pumping Head, ft (m) of Water
Motor Rating, hp (kW) per pump
Motor Brake Horsepower,
hp (kW) per pump
MECHANICAL WET TOWER - GROUND FOGGING
10
670 (62.2)
46,500
55.1 (16.8)
345 (1306)
2
85.3 (26.0)
4500 (3357)
4176 (3115)
20
695 (64.6)
50,300
52.7 (16.1)
374 (1416)
3
84.0 (25.6)
3500 (2611)
2970 (2216)
30
667 (62.0)
46,500
54.7 (16.8)
346 (1310)
2
85.1 (25.9)
4500 (3357)
4173 (3113)
Reterence
61
721 (67.0)
55,000
50.1 (15.3)
409 (1548)
3
81.7 (24.9)
3500 (2611)
3159 (2357)
oo
-------
TABLE P-16 (continued)
Variable
Circulating Water Pipelines
Condenser Intake:
Number of Lines
Diameter/Length, In/ ft (cm/ra)
Condenser Discharge:
Number of Lines
Diameter/Length, in/ ft (cra/ra)
Connecting Pipelines:
Number of Lines
Diameter/Length, in/ ft {cm/ra )
Cooling Tower
Number of Cells
Heat Exchanger Tube Length, ft (ra)
MECHANICAL WET TOWER - GROUND FOGGING
10
1
108/1120 (274/341)
1
108/940 (214/287)
2
78/710 (198/216)
35
20
1
114/1120 (290/341)
1
114/940 (290/287)
2
78/710 (198/216)
31
30
1
108/1120 (274/341)
1
108/940 (274/287)
2
78/710 (198/216)
30
Reference
61
1
120/1120 (305/341)
1
120/940 (305/287)
2
84/710 (213/216)
25
to
en
-------
TABLE P-17. PENALTY BREAKDOWN AND COST SUMMARY FOR THE OPTIMIZED MECHANICAL WET COOLING SYSTEMS ($106)
SITE: CHARLOTTE, HORTH CAROLINA YEAR: 1985
Item
Penalty Breakdown:
Capacity Penalty
Replacement Energy Penalty
Circulating Water Pumping
Power Penalty
Circulating Water Pumping
Energy Penalty
Cooling Tower Fan
Power Penalty
Cooling Tower Fan
Energy Penalty
Make-up Water Purchase and
Treatment Penalty
Make-up Water Pumping Energy
and Capacity Penalty
Cooling System Maintenance Penalty
Cost Suraraary:
Total Penalty Cost
Total Capital Cost
Total Evaluated Cost
. . . 5
MECHANICAL WET TOWER - GROUND FOGGING
10
5.667
1.819
3.356
6.777
2.214
4.266
0.429
0.225
2.119
26.872
51.728
78.600
20
5.559
2.006
3.580
7.231
1.945
3.760
0.427
0.222
2.216
26.946
50.103
77.049
30
6.909
3.338
3.353
6.781
1.878
3.638
0.427
0.221
1.991
28.536
47.883
76.419
Reference
61
6.560
3.526
3.808
7.700
1.544
3.007
0.427
0.218
2.080
28.870
46.454
75.324
-------
TABLE P-18. SUMMARY OF CAPITAL INVESTMENT COST FOR THE OPTIMIZED WET/DRY AND MECHANICAL WET COOLING SYSTEMS (S106)
SITE: CHARLOTTE, NORTH CAROLINA PRICING YEAR: 1985
_____
Acct. No.
118L
132.211
132.25
132.3211
132.3212
133.1
114 &
132.1
14
Equipment Item
Circulating Water Pump (M
Structures (L
(T
Circulating Water Pumps (E
and Motors (M
(L
(T
Concrete Pipelines (M
(L
(T
Cooling Tower Basin (M
and Foundation (L
(T
Cooling Towers, Installed (E
(M
(L
(T
Condensers , Installed (E
(M
(L
(T
Make-up Facilities (E
(M
a
(T
Electrical Equipment (E
(M
(L
(T
Direct Capital Cost of (E
Cooling System (M
(L
(T
Indirect Cost
Total Capital Cost
MECHANICAL WET TOWER - GROUND FOGGING
10
0.804
0.641
1.445
1.736
0.018
0.105
1.859
1.853
1.472
3.325
2.271
4.085
6.356
7.257
0.073
5.888
13.218
7.064
0.035
3.749
10.848
0.555
0.646
1.100
2.301
0.806
0.606
0.618
2.030
17.418
6.306
17.659
41.383
10.345
51.728
20
0.829
0.662
1.491
2.122
0.021
0.158
2.301
1.950
1.550
3.500
2.011
3.618
5.629
6.429
0.065
5.217
11.711
7.321
0.037
3.838
11.796
0.544
0.634
1.079
2.257
0.796
0.598
0.605
1.999
17.212
6.145
16.727
40.084
10.020
50.103
30
0.804
0.643
1.447
1.736
0.018
0.105
1.859
1.853
1.472
3.325
1.946
3.501
5.447
6.221
0.063
5.047
11.331
7.043
0.035
3.744
10.822
0.542
0.631
1.075
2.248
0.733
0.551
0.543
1.827
15.275
5.901
16.130.
38.306
9.576
47.883
61
0.856
0.685
1.541
2.122
0.021
0.158
2.301
2.133
1.679
3.812
1.622
2.917
4.539
5.183
0.052
4.207
9.442
7.606
0.038
3.937
11.581
0.528
0.616
1.050
2.194
0.709
0.533
0.513
1.755
16.148
5.171
15.146
37.165
9.291
46.454
-------
100-,-
I-J
1000
2000
3000
4000
5000
6000
7000
8000
Cumulative Duration (hrs)
9000
Figure P-l Temperature Duration Curves: Seattle, Washington
-------
100 --
80 --
o
it
3
4J
2 60
40 _>
20 _.
-20 _L
1000
2000
3000 4000 5000 6000
Cumulative Duration (hrs)
7000
40
• -20
Figure P-2 Temperature Duration Curves: Cleveland, Ohio
-------
to
-•J
-p-
100 - .
Dry Bulb
3000 4000 5000 6000
Cumulative Duration (hts)
Figure P-3 Temperature Duration Curves: Newark, New Jersey
8000
40
30
20
3
4J
rt
i-i
10 Q)
&
-10
-20
-------
120 - -
NJ
1000 2000- 3000 400D 5000 6000
Cumulative Duration (hrs)
7000
8000
9000
Figure P-4 Temperature Duration Curves: Charlotte, North Carolina
-------
1. REPORT NO.
EPA-600/7-77-137
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
|3. RECIPIENT'S ACCESSION NO.
2.
4. TITLE AND SUBTITLE
Wet/Dry Cooling Systems for Fossil-Fueled Power
Plants: Water Conservation and Plume Abatement
6.
7. AUTHOR(S)
M.C. HuandG.A. Englesson
s. PERFOR"MTNG ORGANIZATION REP
UEandC-EPA-771130
9. PERFORMING ORGANIZATION NAME AND ADDRESS
United Engineers and Constructors, Inc.
30 South 17th Street
Philadelphia, Pennsylvania 19101
10. PROGRAM ELEMENT INU.
EHE624
11. CONTRACT/GHAr
68-03-2202
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: 6/75-9/77
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES T£RL-RTP project officer for this report is Theodore G. Brna,
Mail Drop 61, 919/541-2683.
16. ABSTRACT Tne report gives results of a study of technical and economic feasiDillties of
wet/dry cooling towers for water conservation and vapor plume abatement. Results of
cost optimizations of wet/dry cooling for 1000-MWe fossil-fueled power plants are
presented. Five sites in the western coal region and one in New York are evaluated
for water conservation; four urban sites (Seattle, Cleveland, Newark, and Charlotte)
are used in the plume abatement analyses. Results are given as the total evaluated
cost of the cooling system. Separate cost components include initial capital cost,
operating expenses, and penalties for the cooling system operation capitalized over a
plant life of 40 years. The year of pricing is 1985. For the water conservation ana^-
ses, optimized all-wet and all-dry cooling towers are reference systems. The wet/
dry system has separate wet and dry mechanical draft towers. Costs are related to
the make-up water requirement expressed as a percentage of the water required by
an all-wet system. Parametric and sensitivity analyses show the effect of changing
the system design and economic factors. A parallel air-flow hybrid wet/dry tower is
used in the plume abatement studies. Costs are presented for an allowable number of
hours of fogging. An all-wet system, optimized solely for cost, is the reference.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Cooling Towers
Fossil Fuel
Electric Power Plants
Water Conservation
Vapors
Plumes
Pollution Control
Stationary Sources
Wet/Dry Cooling
13B
13A,07A
21D
10B
02C
07D
2 IB
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
PAGES
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
276
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