Palisades Nuclear Plant 

Application for Renewed 

Operating License 

March 22, 2005 
Page-i 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

TECHNICAL AND ADMINISTRATIVE INFORMATION

Contents

1.0 Administrative Information - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-1

1.1 Application Format and Content - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-2

1.2 Plant Description - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-4

1.3 Information Required by 10 CFR 54.17 and 10 CFR 54.19 - - - - - - - - - - - - - - - - - - 1-4

1.3.1 Name of Applicant - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-4

1.3.2 Address of Applicant - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-4

1.3.3 Description of Business or Occupation of Applicant - - - - - - - - - - - - - - - - - 1-5

1.3.4 Organization and Management of Applicant - - - - - - - - - - - - - - - - - - - - - 1-6

1.3.5 Class of License, Use of Facility, and Period of Time for which the License is Sought 1-11

1.3.6 Earliest and Latest Dates for Alterations, if Proposed - - - - - - - - - - - - - - - - 1-11

1.3.7 Listing of Regulatory Agencies Having Jurisdiction and News Publications - - - - - - 1-12

1.3.8 Conforming Changes to Standard Indemnity Agreement - - - - - - - - - - - - - - - 1-12

1.3.9 Restricted Data Agreement - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-13

1.4 Current Licensing Basis Changes During NRC Review - - - - - - - - - - - - - - - - - - - - 1-13

1.5 Abbreviations - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-14

1.6 Communications- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-26

Section 1.0 References - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 1-27

2.0 Scoping and Screening Methodology for Identifying Structures and Components Subject to 

Aging Management Review, and Implementation Results - - - - - - - - - - - - - - - - - 2-1

2.1 Scoping and Screening Methodology- - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-1

2.1.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-1

2.1.1.1 Plant Information Sources - - - - - - - - - - - - - - - - - - - - - - - - 2-2

2.1.1.2 License Renewal Tools - - - - - - - - - - - - - - - - - - - - - - - - - - 2-5

2.1.1.3 Interim Staff Guidance Discussions - - - - - - - - - - - - - - - - - - - - 2-6

2.1.1.4 Consideration of Power Uprating in License Renewal Evaluation Process - 2-14

2.1.1.5 Industry Guidance - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-14

2.1.2 Scoping Methodology- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-14

2.1.2.1 Application of License Renewal Scoping Criteria - - - - - - - - - - - - - 2-15

2.1.2.2 Mechanical Discipline-Specific Scoping Methodology - - - - - - - - - - - 2-28

2.1.2.3 Civil/Structural Discipline-Specific Scoping Methodology - - - - - - - - - 2-30

2.1.2.4 Electrical and I&C Discipline-Specific Scoping Methodology - - - - - - - - 2-32
Page-ii 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

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Contents

2.1.3 Screening Methodology- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-32

2.1.3.1 Active/Passive Determination - - - - - - - - - - - - - - - - - - - - - - - 2-33

2.1.3.2 Identification of Short-lived Components and Consumables - - - - - - - - 2-34

2.1.3.3 Screening of Stored Equipment - - - - - - - - - - - - - - - - - - - - - - 2-36

2.1.3.4 Screening of Thermal Insulation - - - - - - - - - - - - - - - - - - - - - 2-36

2.1.3.5 Identification of Component Intended Functions - - - - - - - - - - - - - - 2-37

2.2 Plant Level Scoping Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-42

2.3 Scoping and Screening Results: Mechanical Systems - - - - - - - - - - - - - - - - - - - - 2-49

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System - - - - - - - - - - - - - - - 2-49

2.3.1.1 Primary Coolant System - - - - - - - - - - - - - - - - - - - - - - - - - 2-49

2.3.1.2 Reactor Vessel - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-57

2.3.1.3 Reactor Vessel Internals - - - - - - - - - - - - - - - - - - - - - - - - - 2-60

2.3.1.4 Replacement Steam Generators - - - - - - - - - - - - - - - - - - - - - 2-64

2.3.2 Engineered Safety Features - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-69

2.3.2.1 Engineered Safeguards System - - - - - - - - - - - - - - - - - - - - - 2-69

2.3.3 Auxiliary Systems- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-81

2.3.3.1 Chemical and Volume Control System - - - - - - - - - - - - - - - - - - 2-81

2.3.3.2 Circulating Water System- - - - - - - - - - - - - - - - - - - - - - - - - 2-88

2.3.3.3 Component Cooling Water System - - - - - - - - - - - - - - - - - - - - 2-90

2.3.3.4 Compressed Air System - - - - - - - - - - - - - - - - - - - - - - - - - 2-95

2.3.3.5 Containment Air Recirculation and Cooling System - - - - - - - - - - - - 2-100

2.3.3.6 Emergency Power System - - - - - - - - - - - - - - - - - - - - - - - - 2-103

2.3.3.7 Fire Protection System - - - - - - - - - - - - - - - - - - - - - - - - - - 2-112

2.3.3.8 Fuel Oil System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-117

2.3.3.9 Heating, Ventilation, and Air Conditioning System - - - - - - - - - - - - - 2-121

2.3.3.10 Miscellaneous Gas System - - - - - - - - - - - - - - - - - - - - - - - - 2-131

2.3.3.11 Radwaste System - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-137

2.3.3.12 Service Water System - - - - - - - - - - - - - - - - - - - - - - - - - - 2-141

2.3.3.13 Shield Cooling System - - - - - - - - - - - - - - - - - - - - - - - - - - 2-147

2.3.3.14 Spent Fuel Pool Cooling System - - - - - - - - - - - - - - - - - - - - - 2-150

2.3.3.15 Waste Gas System - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-154

2.3.3.16 Domestic Water System - - - - - - - - - - - - - - - - - - - - - - - - - 2-158

2.3.3.17 Chemical Addition System - - - - - - - - - - - - - - - - - - - - - - - - 2-160
Page-iii 

Palisades Nuclear Plant

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TECHNICAL AND ADMINISTRATIVE INFORMATION

Contents

2.3.4 Steam and Power Conversion Systems - - - - - - - - - - - - - - - - - - - - - - - 2-164

2.3.4.1 Condensate and Condenser System - - - - - - - - - - - - - - - - - - - 2-164

2.3.4.2 Demineralized Makeup Water System - - - - - - - - - - - - - - - - - - 2-169

2.3.4.3 Feedwater System - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-173

2.3.4.4 Heater Extraction and Drain System - - - - - - - - - - - - - - - - - - - 2-181

2.3.4.5 Main Air Ejection and Gland Seal System - - - - - - - - - - - - - - - - - 2-184

2.3.4.6 Main Steam System - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-187

2.3.4.7 Turbine Generator System - - - - - - - - - - - - - - - - - - - - - - - - 2-194

2.4 Scoping and Screening Results: Containments, Structures, and Component Supports - - - - 2-200

2.4.1 Auxiliary Building - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-200

2.4.2 Component Supports - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-207

2.4.3 Containment - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-222

2.4.4 Containment Interior Structures - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-228

2.4.5 Discharge Structure - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-232

2.4.6 Feedwater Purity Building- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-234

2.4.7 Intake Structure - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-236

2.4.8 Miscellaneous Structural and Bulk Commodities- - - - - - - - - - - - - - - - - - - 2-240

2.4.9 Switchyard and Yard Structures- - - - - - - - - - - - - - - - - - - - - - - - - - - 2-247

2.4.10 Turbine Building - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-250

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls - - - - - - - - - 2-259

2.5.1 Commodity Group Descriptions - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-260

2.5.2 Cables and Terminations Commodity - - - - - - - - - - - - - - - - - - - - - - - - 2-266

2.5.3 Containment Isolation and Penetration System - - - - - - - - - - - - - - - - - - - 2-268

2.5.4 Control Rod Drive System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-271

2.5.5 Neutron Monitoring System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-276

2.5.6 Radiation Monitoring System - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-278

2.5.7 Reactor Protective System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-285

2.5.8 Station Power System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-287

2.5.9 Switchyard System - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2-291

3.0 Aging Management Review Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-1

3.0.1 Aging Management Review Results Display Method- - - - - - - - - - - - - - - - - 3-1
Page-iv 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

TECHNICAL AND ADMINISTRATIVE INFORMATION

Contents

3.1 Aging Management of Reactor Coolant System - - - - - - - - - - - - - - - - - - - - - - - 3-12

3.1.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-12

3.1.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-12

3.1.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-13

3.1.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-17

3.1.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-29

3.1.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-29

3.2 Aging Management of Engineered Safety Features- - - - - - - - - - - - - - - - - - - - - - 3-64

3.2.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-64

3.2.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-64

3.2.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-64

3.2.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-66

3.2.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-69

3.2.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-69

3.3 Aging Management of Auxiliary Systems - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-80

3.3.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-80

3.3.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-81

3.3.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-83

3.3.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-101

3.3.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-111

3.3.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-111

3.4 Aging Management of Steam and Power Conversion System- - - - - - - - - - - - - - - - - 3-204

3.4.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-204

3.4.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-204

3.4.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-205

3.4.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-212
Page-v 

Palisades Nuclear Plant

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3.4.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-215

3.4.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-215

3.5 Aging Management of Containments, Structures, and Component Supports - - - - - - - - - 3-254

3.5.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-254

3.5.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-254

3.5.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-256

3.5.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-266

3.5.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-299

3.5.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-300

3.6 Aging Management of Electrical and Instrumentation and Controls - - - - - - - - - - - - - - 3-401

3.6.1 Introduction- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-401

3.6.2 Results - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-401

3.6.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs- - - - - - - - - - - - - - - - - - - - - - - - - - 3-402

3.6.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1801

 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-409

3.6.2.3 Time-Limited Aging Analysis - - - - - - - - - - - - - - - - - - - - - - - 3-410

3.6.3 Conclusion - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 3-410

4.0 Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-1

4.1 Identification of Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - - - - - - - - 4-1

4.1.1 Process for Identification of Time-Limited Aging Analyses - - - - - - - - - - - - - - 4-1

4.1.1.1 CLB Search for TLAAs - - - - - - - - - - - - - - - - - - - - - - - - - - 4-2

4.1.1.2 Industry Document Search for TLAAs - - - - - - - - - - - - - - - - - - - 4-2

4.1.2 Identification of Exemptions - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-3

4.1.3 Evaluation Process of Potential Time Limited Aging Analyses - - - - - - - - - - - - 4-3

4.2 Reactor Vessel Neutron Embrittlement - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-10

4.2.1 Upper Shelf Energy- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-11

4.2.2 Pressurized Thermal Shock- - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-13

4.2.3 Pressure-Temperature (P-T) Limits - - - - - - - - - - - - - - - - - - - - - - - - - 4-15

4.2.4 Low Temperature Overpressure Protection (LTOP) PORV Setpoints- - - - - - - - - 4-16
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Palisades Nuclear Plant

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4.3 Metal Fatigue - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-16

4.3.1 Evaluation of Fatigue in Vessels, Piping, and Components - - - - - - - - - - - - - 4-16

4.3.2 Reactor Vessel Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - - 4-21

4.3.3 Reactor Vessel Head Closure Stud Fatigue Analysis - - - - - - - - - - - - - - - - 4-22

4.3.4 Control Rod Drive Mechanism (CRDM) Housing Fatigue Analyses- - - - - - - - - - 4-23

4.3.5 Steam Generator Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - 4-24

4.3.6 Pressurizer Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-25

4.3.7 Regenerative Heat Exchanger Fatigue Analyses - - - - - - - - - - - - - - - - - - 4-28

4.3.8 ASME III Class A Primary Coolant Piping Fatigue Analyses - - - - - - - - - - - - - 4-29

4.3.9 Revised NRC Bulletin 88-11 Fatigue Analysis of the Hot Leg to Pressurizer Surge Line 

Nozzle, Surge Line, and Pressurizer Surge Nozzle - - - - - - - - - - - - - - - - - 4-31

4.3.10 Revised Fatigue Analysis of Nozzles from PCS Cold Legs 1B and 2A to Pressurizer Spray 

and of the Pressurizer Spray Nozzle - - - - - - - - - - - - - - - - - - - - - - - - 4-34

4.3.11 Pressurizer Auxiliary Spray Line Tee Fatigue Analysis in Response to NRC Bulletin 

88-08- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-35

4.3.12 Absence of a TLAA for ASME III Class 1 HELB Locations and Leak-Before-Break Analyses 

Based on Fatigue Usage Factor- - - - - - - - - - - - - - - - - - - - - - - - - - - 4-36

4.3.13 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction Factor in 

Piping and Components - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-36

4.3.14 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and Components 

(Generic Safety Issue 190) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-38

4.4 Environmental Qualification of Electrical Equipment - - - - - - - - - - - - - - - - - - - - - 4-41

4.5 Concrete Containment Tendon Prestress Analysis - - - - - - - - - - - - - - - - - - - - - - 4-44

4.6 Containment Liner Plate and Penetrations Load Cycles- - - - - - - - - - - - - - - - - - - - 4-45

4.6.1 Containment Liner Plate Load Cycles - - - - - - - - - - - - - - - - - - - - - - - - 4-46

4.6.2 Containment Penetration Load Cycles - - - - - - - - - - - - - - - - - - - - - - - 4-48

4.7 Other Plant-Specific Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - - - - - - 4-51

4.7.1 Crane Load Cycles - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-51

4.7.2 Alloy 600 Nozzle and Safe End Life Assessment Analyses - - - - - - - - - - - - - 4-52

4.7.3 ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld Category B-L-1 

Inspection Interval from 10 Years to 40 Years - - - - - - - - - - - - - - - - - - - - 4-61

4.7.4 Risk-Informed Inservice Inspection Program Calculations - - - - - - - - - - - - - - 4-63
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Palisades Nuclear Plant

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4.7.5 Absence of a TLAA for Reactor Coolant Pump Flywheel Fatigue or Crack Growth 

Analysis - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4-64

A1.0 Appendix A Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-1

A2.0 Summary Descriptions of Aging Management Programs- - - - - - - - - - - - - - - - - - A-2

A2.1 Alloy 600 Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-2

A2.2 ASME Section XI, Subsections IWB, IWC, IWD, IWF Inservice Inspection Program - - - - - - A-2

A2.3 Bolting Integrity Program- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.4 Boric Acid Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.5 Buried Services Corrosion Monitoring Program- - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.6 Closed Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.7 Containment Inservice Inspection Program- - - - - - - - - - - - - - - - - - - - - - - - - - A-4

A2.8 Containment Leakage Testing Program - - - - - - - - - - - - - - - - - - - - - - - - - - - A-4

A2.9 Diesel Fuel Monitoring and Storage Program- - - - - - - - - - - - - - - - - - - - - - - - - A-4

A2.10 Fire Protection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-5

A2.11 Flow Accelerated Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-5

A2.12 Non-EQ Electrical Commodities Condition Monitoring Program - - - - - - - - - - - - - - - - A-5

A2.13 One-Time Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-5

A2.14 Open Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-6

A2.15 Overhead Load Handling Systems Inspection Program - - - - - - - - - - - - - - - - - - - - A-7

A2.16 Reactor Vessel Integrity Surveillance Program - - - - - - - - - - - - - - - - - - - - - - - - A-7

A2.17 Reactor Vessel Internals Inspection Program- - - - - - - - - - - - - - - - - - - - - - - - - A-7

A2.18 Steam Generator Tube Integrity Program - - - - - - - - - - - - - - - - - - - - - - - - - - A-8

A2.19 Structural Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-8

A2.20 System Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-8

A2.21 Water Chemistry Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-9

A3.0 Summary Descriptions of Time Limited Aging Analysis Management Programs - - - - - A-10

A3.1 Electrical Equipment Qualification Program- - - - - - - - - - - - - - - - - - - - - - - - - - A-10

A3.2 Fatigue Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-10
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A4.0 Evaluation Summaries of Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - - A-11

A4.1 Reactor Vessel Neutron Embrittlement - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-11

A4.1.1 Upper Shelf Energy- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-11

A4.1.2 Pressurized Thermal Shock- - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-12

A4.1.3 Pressure-Temperature (P-T) Limits - - - - - - - - - - - - - - - - - - - - - - - - - A-14

A4.1.4 Low Temperature Overpressure Protection (LTOP) PORV Setpoints- - - - - - - - - A-14

A4.2 Metal Fatigue - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-14

A4.2.1 Reactor Vessel Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - - A-14

A4.2.2 Reactor Vessel Head Closure Stud Fatigue Analysis - - - - - - - - - - - - - - - - A-15

A4.2.3 Control Rod Drive Mechanism (CRDM) Housing Fatigue Analyses- - - - - - - - - - A-16

A4.2.4 Steam Generator Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - A-17

A4.2.5 Pressurizer Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-18

A4.2.6 Regenerative Heat Exchanger Fatigue Analyses - - - - - - - - - - - - - - - - - - A-20

A4.2.7 ASME III Class A Primary Coolant Piping Fatigue Analyses - - - - - - - - - - - - - A-22

A4.2.8 Revised Bulletin 88-11 Fatigue Analysis of the Hot-Leg-to-Pressurizer-Surge-Line Nozzle, 

Surge Line, and Pressurizer Surge Nozzle - - - - - - - - - - - - - - - - - - - - - A-23

A4.2.9 Revised Fatigue Analysis of Nozzles from PCS Cold Legs 1B and 2A to Pressurizer Spray 

and of the Pressurizer Spray Nozzle - - - - - - - - - - - - - - - - - - - - - - - - A-26

A4.2.10 Pressurizer Auxiliary Spray Line Tee Fatigue Analysis in Response to NRC Bulletin 

88-08- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-27

A4.2.11 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction Factor in 

Piping and Components - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-28

A4.2.12 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and Components 

(Generic Safety Issue 190) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-30

A4.3 Environmental Qualification of Electrical Equipment - - - - - - - - - - - - - - - - - - - - - A-33

A4.4 Containment Liner Plate, Metal Containments and Penetrations Fatigue Analysis - - - - - - - A-35

A4.4.1 Concrete Containment Tendon Prestress Analysis - - - - - - - - - - - - - - - - - A-35

A4.4.2 Containment Liner Plate Load and Penetrations Load Cycles - - - - - - - - - - - - A-35

A4.5 Other Plant-Specific Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - - - - - - A-37

A4.5.1 Fuel Handling Crane Load Cycles- - - - - - - - - - - - - - - - - - - - - - - - - - A-37

A4.5.2 Alloy 600 Nozzle and Safe End Life Assessment Analyses - - - - - - - - - - - - - A-38
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A4.5.3 ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld Category B-L-1 

Inspection Interval from 10 Years to 40 Years - - - - - - - - - - - - - - - - - - - - A-39

A4.5.4 Risk-Informed Inservice Inspection Program Calculations - - - - - - - - - - - - - - A-41

B1.0 Appendix B Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-1

B1.1 Overview - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-1

B1.2 Quality Assurance Program and Administrative Controls - - - - - - - - - - - - - - - - - - - B-3

B1.3 Operating Experience - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-5

B1.4 Aging Management Programs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-5

B1.5 Time Limited Aging Analyses Management Programs: - - - - - - - - - - - - - - - - - - - - B-6

B2.0 Aging Management Programs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-7

B2.1 Aging Management Programs Details - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-11

B2.1.1 Alloy 600 Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-11

B2.1.2 ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program - - - - - - - - B-17

B2.1.3 Bolting Integrity Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-25

B2.1.4 Boric Acid Corrosion Program- - - - - - - - - - - - - - - - - - - - - - - - - - - - B-32

B2.1.5 Buried Services Corrosion Monitoring Program - - - - - - - - - - - - - - - - - - - B-37

B2.1.6 Closed Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - B-41

B2.1.7 Containment Inservice Inspection Program - - - - - - - - - - - - - - - - - - - - - B-49

B2.1.8 Containment Leakage Testing Program - - - - - - - - - - - - - - - - - - - - - - - B-58

B2.1.9 Diesel Fuel Monitoring and Storage Program - - - - - - - - - - - - - - - - - - - - B-65

B2.1.10 Fire Protection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-71

B2.1.11 Flow Accelerated Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - B-81

B2.1.12 Non-EQ Electrical Commodities Condition Monitoring Program - - - - - - - - - - - B-87

B2.1.13 One-Time Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - B-97

B2.1.14 Open Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - B-107

B2.1.15 Overhead Load Handling Systems Inspection Program - - - - - - - - - - - - - - - B-114

B2.1.16 Reactor Vessel Integrity Surveillance Program - - - - - - - - - - - - - - - - - - - B-120

B2.1.17 Reactor Vessel Internals Inspection Program - - - - - - - - - - - - - - - - - - - - B-126

B2.1.18 Steam Generator Tube Integrity Program - - - - - - - - - - - - - - - - - - - - - - B-131

B2.1.19 Structural Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - B-136
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B2.1.20 System Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-146

B2.1.21 Water Chemistry Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-153

B3.0 Time Limited Aging Analyses Management Programs - - - - - - - - - - - - - - - - - - - B-160

B3.1 Electrical Equipment Qualification Program- - - - - - - - - - - - - - - - - - - - - - - - - - B-160

B3.2 Fatigue Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-164

Appendix B References - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-172

C1.0 Appendix C - Not Used - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - C-1

D1.0 Appendix D - Technical Specifications Changes - - - - - - - - - - - - - - - - - - - - - - D-1

E1.0 Appendix E - Environmental Report - - - - - - - - - - - - - - - - - - - - - - - - - - - - E-1
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Table 2.1-1 Intended Function Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-38

Table 2.2-1 Plant Level Scoping Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-42

Table 2.3.1-1 Primary Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-55

Table 2.3.1-2 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-58

Table 2.3.1-3 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-63

Table 2.3.1-4 Replacement Steam Generators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-67

Table 2.3.2-1 Engineered Safeguards System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-79

Table 2.3.3-1 Chemical and Volume Control System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-86

Table 2.3.3-2 Circulating Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-90

Table 2.3.3-3 Component Cooling Water System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-94

Table 2.3.3-4 Compressed Air System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-100

Table 2.3.3-5 Containment Air Recirculation and Cooling System . . . . . . . . . . . . . . . . . . . . . . . . 2-103

Table 2.3.3-6 Emergency Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-111

Table 2.3.3-7 Fire Protection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-117

Table 2.3.3-8 Fuel Oil System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-120

Table 2.3.3-9 Heating, Ventilation, and Air Conditioning System . . . . . . . . . . . . . . . . . . . . . . . . . 2-130

Table 2.3.3-10 Miscellaneous Gas System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-136

Table 2.3.3-11 Radwaste System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-141

Table 2.3.3-12 Service Water System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147

Table 2.3.3-13 Shield Cooling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-150

Table 2.3.3-14 Spent Fuel Pool Cooling System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-153

Table 2.3.3-15 Waste Gas System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-157

Table 2.3.3-16 Domestic Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-160

Table 2.3.3-17 Chemical Addition System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-163

Table 2.3.4-1 Condensate and Condenser System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-168

Table 2.3.4-2 Demineralized Makeup Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-172

Table 2.3.4-3 Feedwater System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-180

Table 2.3.4-4 Heater Extraction and Drain System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-184

Table 2.3.4-5 Main Air Ejection and Gland Seal System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-187

Table 2.3.4-6 Main Steam System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-194

Table 2.3.4-7 Turbine Generator System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-199

Table 2.4.1-1 Auxiliary Building. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-204

Table 2.4.2-1 Component Supports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-211

Table 2.4.3-1 Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-226
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Table 2.4.4-1 Containment Interior Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-230

Table 2.4.5-1 Discharge Structure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-234

Table 2.4.6-1 Feedwater Purity Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-235

Table 2.4.7-1 Intake Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-238

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities . . . . . . . . . . . . . . . . . . . . . . . . . . 2-243

Table 2.4.9-1 Switchyard and Yard Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-249

Table 2.4.10-1 Turbine Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-254

Table 2.5-1 Electrical Commodity Groups . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-265

Table 3.0-1 Service Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor 

Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-30

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-37

Table 3.1.2-2 Reactor Coolant System - Reactor Vessel - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-44

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-49

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-56

Table 3.2.1 Summary of Aging Management Evaluations in Chapter V of NUREG-1801 for Engineered 

Safety Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-70

Table 3.2.2-1 Engineered Safety Features - Engineering Safeguards System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-73

Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary 

Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-113

Table 3.3.2-1 Auxiliary Systems - Chemical and Volume Control System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-118

Table 3.3.2-2 Auxiliary Systems - Circulating Water System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-122

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-123

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-130

Table 3.3.2-5 Auxiliary Systems- Containment Air Recirculation and Cooling System - Summary of 

Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-137

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-141
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Table 3.3.2-7 Auxiliary Systems- Fire Protection System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-153

Table 3.3.2-8 Auxiliary Systems - Fuel Oil System - Summary of Aging Management Evaluation

 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-158

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of 

Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-162

Table 3.3.2-10 Auxiliary Systems - Miscellaneous Gas System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-171

Table 3.3.2-11 Auxiliary Systems- Radwaste System - Summary of Aging Management Evaluation

 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-174

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-179

Table 3.3.2-13 Auxiliary Systems - Shield Cooling System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-187

Table 3.3.2-14 Auxiliary Systems- Spent Fuel Pool Cooling System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-189

Table 3.3.2-15 Auxiliary Systems - Waste Gas System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-192

Table 3.3.2-16 Auxiliary Systems - Domestic Water System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-194

Table 3.3.2-17 Auxiliary Systems - Chemical Addition System - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-196

Table 3.4.1 Summary of Aging Management Evaluations in Chapter VIII of NUREG-1801 for Steam 

and Power Conversion System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-217

Table 3.4.2-1 Steam and Power Conversion System - Condensate and Condenser System - Summary 

of Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-220

Table 3.4.2-2 Steam and Power Conversion System - Demineralized Makeup Water System - Summary 

of Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-224

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-227

Table 3.4.2-4 Steam and Power Conversion System - Heater Extraction and Drain System - Summary 

of Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-235

Table 3.4.2-5 Steam and Power Conversion System - Main Air Ejection and Gland Seal System - 

Summary of Aging Management Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-239

Table 3.4.2-6 Steam and Power Conversion System - Main Steam System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-243

Table 3.4.2-7 Steam and Power Conversion System - Turbine Generator System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-248
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TECHNICAL AND ADMINISTRATIVE INFORMATION

Tables

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for 

Structures and Component Supports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-301

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-309

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-317

Table 3.5.2-3 Structures and Component Supports - Containment - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-342

Table 3.5.2-4 Structures and Component Supports - Containment Interior Structures - Summary of 

Aging Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-345

Table 3.5.2-5 Structures and Component Supports - Discharge Structure - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-349

Table 3.5.2-6 Structures and Component Supports - Feedwater Purity Building - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-352

Table 3.5.2-7 Structures and Component Supports - Intake Structure - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-355

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - 

Summary of Aging Management Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-360

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-375

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-380

Table 3.6.1 Summary of Aging Management Evaluations in Chapter VI of NUREG-1801 for Electrical 

Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-412

Table 3.6.2-1 Electrical Components - Electrical Commodity Groups - Summary of Aging Management 

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-414

Table 4.1-1 Time Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-4

Table 4.2-1 Estimated Palisades Fluence on March 24, 2031 . . . . . . . . . . . . . . . . . . . . . . . . . 4-11

Table 4.2.1-1 Estimated USE on March 24, 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-12

Table 4.2.2-1 Estimated RTPTS on March 24, 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-14

Table 4.3.1-1 Primary Coolant system Design Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-19

Table 4.3.1-2 Applicable Codes for Palisades Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-21

Table 4.3.14-1 Summary of Fatigue Usage Factors at NUREG/CR-6260 Sample Locations Applicable to 

Palisades . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-40

Table 4.7.2-1 Summary of Fracture Mechanics Assessment of Susceptible Pressurizer and Primary 

Coolant System Alloy 600 Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-54
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TECHNICAL AND ADMINISTRATIVE INFORMATION

Figures

Figure 3.0-1 Table 1 - Table 3.x.1, Summary of Aging Management Evaluations in Chapter _____ of 

NUREG-1801 for ____________ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10

Figure 3.0-2 Table 2 - Table 3.x.2-y, Section 3 Title - Plant Specific System - Summary of Aging 

Management Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-11
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Palisades Nuclear Plant

Application for Renewed Operating License

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1.0 Administrative Information

This License Renewal application (LRA) has been prepared to provide the administrative, technical 

and environmental information required by 10 CFR 54 (Reference 1) and 10 CFR 51 (Reference 2) 

to support the renewal of the Operating License for the Palisades Nuclear Plant.

This LRA is being submitted on CD-ROM in accordance with 10 CFR 54.7 and 10 CFR 50.4. The 

FSAR, LR scoping boundary drawings, and other references cited within the application are for 

information only, and are not incorporated by reference into this application. The LR drawings cited 

within this application will not necessarily be kept up to date for the life of the plant. 

This section of the application provides the following information:

1. Information on the organization of the application (Section 1.1).

2. A general plant description (Section 1.2).

3. The administrative information required by 10 CFR 54.17 and 10 CFR 54.19 (Section 1.3).

4. Summary of abbreviations and passive function code definitions (Section 1.5).

5. A distribution list for written communications related to the application (Section 1.6).
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Palisades Nuclear Plant

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1.1 Application Format and Content

The following discussion describes the content of the Palisades Nuclear Plant License 

Renewal Application. The Application format and content, including Section 3 tables, have 

been constructed as described in NEI 95-10, Rev. 4.

Section 1.0 provides the administrative information required by Part 54 of Title 10 of the Code 

of Federal Regulations, Sections 17 and 19 (10 CFR 54.17 and 10 CFR 54.19).

Section 2.0 provides the scoping and screening methodology. Section 2 also describes and 

justifies the methodology used to determine the systems, structures, and components within 

the scope of license renewal and the structures and components subject to an aging 

management review (AMR). The system groupings in Sections 2 and 3 are organized to be 

consistent with NUREG-1800 (Reference 5). Table 2.2-1, Plant Level Scoping Results, 

provides listings of the plant mechanical systems, structures, and electrical/instrumentation 

and controls (I&C) systems, and identifies those plant systems and structures that are and are 

not within the scope of license renewal. Section 2.3, Section 2.4 and Section 2.5 provide a 

description of systems, their intended functions, and for information only, cross references to 

FSAR sections and license renewal drawings. Each system subsection has a table listing 

component groups subject to an AMR and their passive intended functions. The drawings and 

FSAR are provided as separate files for use as review tools.

Section 3.0 describes the results of the AMRs for the components and structures requiring 

AMR. Section 3 identifies the components and structures subject to aging management 

review, summarizes the technical results of those reviews, and provides a comparison of the 

Palisades results with the corresponding results identified in the NRC’s “Generic Aging 

Lessons Learned (GALL) Report,” NUREG-1801 (Reference 6). The information is organized 

into six “super-groups” to be consistent with NUREG-1801 and NUREG-1800.

Within each “super-group”, the plant-specific AMR results are provided in a set of system, 

structure or commodity tables. These tables provide aging management information including 

component type, intended function, material, environment, aging effect requiring 

management, and the selected aging management programs for each component type. 

These tables also include cross-references to NUREG -1801, Volume 2 and Volume 1, line 

items to facilitate comparison. Finally the last column of each table in Section 3 is set aside for 

notes or additional explanatory information specific to that line item. In addition these tables 

have hyperlinked cross references to the aging management program descriptions in 

Appendix B. A more detailed description of table construction and interrelationships is 

provided in Section 3.

Section 4.0 includes a list of time-limited aging analyses (TLAAs), as defined by 10 CFR 54.3. 

It includes the identification of the component or subject, and an explanation of the time 
Page 1-3 

Palisades Nuclear Plant

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Technical and Administrative Information

dependent aspects of the calculation or analysis. For each TLAA, Section 4 demonstrates that 

the analyses remain valid for the period of extended operation, the analyses have been 

projected to the end of the period of extended operation, or the effects of aging on the 

intended function(s) will be adequately managed for the period of extended operation. Section 

4 also states that there are no 10 CFR 50.12 exemptions granted to Palisades that are based 

on a time-limited aging analysis as defined in 10 CFR 54.3. 

Appendix A, Final Safety Analysis Report (FSAR) Supplement, contains a summary 

description of the programs relied on for managing the effects of aging during the period of 

extended operation. A summary description of the evaluation of time-limited aging analyses 

for the period of extended operation is also included.

Appendix B, Aging Management Programs, describes Palisades’ aging management 

programs and demonstrates that the effects of aging on the components and structures within 

the scope of the license renewal will be managed such that the components and structures 

will continue to perform their intended functions consistent with the current licensing basis for 

the period of extended operation. Where a Palisades program is similar to a corresponding 

program in NUREG-1801, the applicable NUREG-1801 program is referenced.

Appendix C is not used for this application.

Appendix D, Technical Specification Changes, is not used for this application. No technical 

specification changes were identified as being necessary to manage the effects of aging 

during the period of extended operation.

Appendix E, Environmental Report, contains an environmental report analyzing the potential 

environmental impacts of license renewal, as provided for in NRC regulations 10 CFR 

51.53(c) and 10 CFR 54.23. The NRC has determined that nuclear power plant license 

renewal decisions are major federal actions requiring preparation of an environmental impact 

statement [10 CFR 51.20(a)(2) and 51.95(c)]. In an effort to streamline the license renewal 

environmental review, the NRC conducted a generic analysis and published the results in 

NUREG-1437, Generic Environmental Impact Statement for the License Renewal of Nuclear 

Power Plants (GEIS). To fulfill NEPA requirements, the NRC is required to publish site-specific 

analyses in the form of a supplemental environmental impact statement to the GEIS. This 

Palisades Environmental Report provides input to the NRC staff for use in meeting NEPA 

requirements as they apply to license renewal.

In summary, the information in Section 1 fulfills the requirements of 10 CFR 54.17 and 54.19. 

The information in Section 2, Section 3, and Appendix B fulfills the requirements of 10 CFR 

54.21(a). Section 1.4 discusses how the requirements of 10 CFR 54.21(b) will be met. The 

information in Section 4 fulfills the requirements in 10 CFR 54.21(c). The information in 
Page 1-4 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Appendix A and Appendix D fulfill the requirements in 10 CFR 54.21(d) and 10 CFR 54.22, 

respectively. Appendix E provides the Environmental Report, as required by 10 CFR 54.23.

1.2 Plant Description

The site for the Palisades Nuclear Plant consists of approximately 432 acres on the eastern 

shore of Lake Michigan, in Covert Township, approximately four and one-half miles south of 

South Haven, Michigan. The Nuclear Steam Supply System consists of a pressurized water 

reactor with two closed loops. The NSSS was originally expected to have adequate margin to 

obtain an ultimate output of 2,650 MWt. The steam and power conversion equipment was 

designed for a maximum expected gross capability of 865 MWe. Palisades is currently 

licensed for a thermal power of 2565.4 MWt. At present, Consumers Energy does not plan to 

pursue an increase in the licensed power level.

Descriptions of Palisades’ systems and structures can be found in the Final Safety Analysis 

Report (FSAR). Additional descriptive information about the systems, structures, and 

components is provided in Sections 2, 3, and 4 of this application, and references to the FSAR 

are provided where pertinent.

The current license (Facility Operating License No. DPR-20) expires on March 24, 2011. 

Nuclear Management Company will be named as the exclusive operator licensee on the 

renewed operating license. Consumers Energy Company will be named as the exclusive 

owner licensee on the renewed operating license.

1.3 Information Required by 10 CFR 54.17 and 10 CFR 54.19

1.3.1 Name of Applicant

Nuclear Management Company (NMC), the operating licensee, hereby applies for a 

renewed operating license for the Palisades Nuclear Plant. NMC submits this application 

individually and as agent for the owner licensee named on the operating license. The owner 

licensee is Consumers Energy Company.

1.3.2 Address of Applicant

Addresses of Applicant Companies:

Nuclear Management Company, LLC

700 First Street

Hudson, Wisconsin 54016
Page 1-5 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Consumers Energy Company

One Energy Plaza

Jackson, MI 49201

Address of the Palisades Nuclear Plant:

Palisades Nuclear Plant

27780 Blue Star Hwy

Covert, MI 49043

1.3.3 Description of Business or Occupation of Applicant

Nuclear Management Company, LLC (NMC)

NMC is engaged in the operation of nuclear power plants. NMC operates Palisades Nuclear 

Plant for Consumers Energy Company, a subsidiary of CMS Energy Corporation; Duane 

Arnold Energy Center for Interstate Power and Light Company, a subsidiary of Alliant 

Energy Corporation, Central Iowa Power Cooperative and Corn Belt Power Cooperative; 

Prairie Island Nuclear Generating Plant and Monticello Nuclear Generating Plant for 

Northern States Power Company, a subsidiary of Xcel Energy Inc.; Point Beach Nuclear 

Plant Units 1 and 2 for Wisconsin Electric Power Co, doing business as We Energies; and 

Kewaunee Nuclear Power Plant for Wisconsin Public Service Corporation and Wisconsin 

Power and Light Company, a subsidiary of Alliant Energy Corporation. The combined 

electric generation of the six plants is in excess of 4,500 MW.NMC is the exclusive licensed 

operator of the Palisades Nuclear Plant, which is the subject of this application. NMC' s 

corporate purpose is to provide services in connection with the operation and eventual 

decommissioning of licensed nuclear facilities on behalf of and for the benefit of the owner 

utilities.

NMC is organized as a Wisconsin limited liability company and is owned by Consumers 

Nuclear Services, LLC, WEC Nuclear Corporation, WPS Nuclear Corporation, NSP Nuclear 

Corporation, and Alliant Energy Nuclear, LLC. Consumers Nuclear Services, LLC, is a 

wholly owned subsidiary of Consumers Energy Company. WEC Nuclear Corporation is a 

wholly owned subsidiary of Wisconsin Energy Corporation, the parent holding company of 

Wisconsin Electric Power Co. WPS Nuclear Corporation is a wholly owned subsidiary of 

WPS Resources, Inc., the parent holding company of Wisconsin Public Service Corporation. 

NSP Nuclear Corporation is a wholly owned subsidiary of Northern States Power Company. 

Alliant Energy Nuclear, LLC is a wholly owned subsidiary of Alliant Energy Corporation, the 

parent holding company of IES Utilities. 

Consumers Energy Company

Consumers Energy Company is a combination electric and gas utility company serving 

Michigan’s Lower Peninsula, and is a wholly owned subsidiary of CMS Energy Corporation. 

Consumers is the owner licensee of Palisades.
Page 1-6 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Consumers Energy’s electric utility operations include the generation, purchase, distribution 

and sale of electricity. Consumers Energy serves customers in 61 of the 68 counties of 

Michigan’s Lower Peninsula, including the principal cities of Battle Creek, Flint, Grand 

Rapids, Jackson, Kalamazoo, Midland, Muskegon, and Saginaw.

Consumers Energy provides natural gas and/or electricity to almost 6 million of Michigan’s 

10 million residents. To serve electricity to these residents, Consumers Energy operates 44 

electric generating facilities in Michigan (including Palisades) with a total owned generation 

of 6,431 MWs (2003 Summer Net Demonstrated Capability).

Consumers Energy is an electric utility as defined by the NRC regulations at 10 CFR 50.2. 

Pursuant to the Nuclear Power Plant Operating Services Agreement between Consumers 

Energy and NMC, all costs, including costs for the operation, maintenance, repair, 

decontamination and decommissioning of Palisades, and the Independent Spent Fuel 

Storage Installation at the plant, are liabilities of Consumers Energy when incurred and 

accrued, and Consumers Energy has committed to provide NMC with funds to pay these 

costs.

Consumers Energy will be named as the exclusive licensed owner of Palisades on the 

renewed operating licenses.

1.3.4 Organization and Management of Applicant

Consumers Energy Company is a public utility; it is a wholly owned subsidiary of CMS 

Energy Corporation. CMS is incorporated under the laws of the State of Michigan, with its 

principal office located in Jackson, Michigan. NMC is a limited liability company incorporated 

under the laws of the State of Wisconsin, with its principal office located in Hudson, 

Wisconsin. Consumers Energy and NMC make this application on their own behalf, and are 

not acting as agents or representatives of any other person. 

CMS Energy and NMC are not owned, controlled, or dominated by an alien, a foreign 

corporation, or a foreign government. The names and business addresses of CMS Energy 

and NMC directors and principal officers are listed below. All persons listed are U.S. 

citizens. 
Page 1-7 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

CMS Energy Corporation

CMS Energy Corporation Directors

Name Address

Kenneth Whipple One Energy Plaza

Jackson, MI 49201

S. Kinnie Smith, Jr. One Energy Plaza

Jackson, MI 49201

Earl D. Holton One Energy Plaza

Jackson, MI 49201

Merribel S. Ayres One Energy Plaza

Jackson, MI 49201

David W. Joos One Energy Plaza

Jackson, MI 49201

Michael T. Monahan One Energy Plaza

Jackson, MI 49201

Joseph F. Paquette, Jr. One Energy Plaza

Jackson, MI 49201

William U. Parfet One Energy Plaza

Jackson, MI 49201

Percy A. Pierre One Energy Plaza

Jackson, MI 49201

Kenneth L. Way One Energy Plaza

Jackson, MI 49201

John B. Yasinsky One Energy Plaza

Jackson, MI 49201
Page 1-8 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Consumers Energy Company Principal Officers

Name Address

Kenneth Whipple

Chairman of the Board

One Energy Plaza

Jackson, MI 49201

S. Kinnie Smith, Jr.

Vice Chairman of the Board

One Energy Plaza

Jackson, MI 49201

David W. Joos

Chief Executive Officer

One Energy Plaza

Jackson, MI 49201

John G. Russell

President and Chief Operating Officer

One Energy Plaza

Jackson, MI 49201

Thomas J. Webb

Executive Vice President and Chief 

Financial Officer

One Energy Plaza

Jackson, MI 49201

John F. Drake

Senior Vice President, Human 

Resources and Administrative Services

One Energy Plaza

Jackson, MI 49201

Robert A. Fenech

Senior Vice President, Nuclear, Fossil, 

and Hydro Operations

One Energy Plaza

Jackson, MI 49201

Frank Johnson

Senior Vice President, Electric 

Transmission and Distribution

One Energy Plaza

Jackson, MI 49201

David G. Mengebier

Senior Vice President, Governmental 

and Public Affairs/Community Services

One Energy Plaza

Jackson, MI 49201

Paul N. Preketes

Senior Vice President, Gas Operations

One Energy Plaza

Jackson, MI 49201

Glenn P. Barba

Vice President, Controller, and Chief 

Accounting Officer

One Energy Plaza

Jackson, MI 49201

James E. Brunner

Vice President and General Counsel

One Energy Plaza

Jackson, MI 49201
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Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

James R. Coddington

Vice President, Fossil Operations

One Energy Plaza

Jackson, MI 49201

William E. Garrity

Vice President, Electric and Gas Supply

One Energy Plaza

Jackson, MI 49201

Laura L. Mountcastle

Vice President and Treasurer

One Energy Plaza

Jackson, MI 49201

Jon R. Robinson

Vice President, Utility Law and 

Regulation

One Energy Plaza

Jackson, MI 49201

Michael J. Shore

Vice President and Chief Risk Officer

One Energy Plaza

Jackson, MI 49201

Susan C. Swan

Vice President, Customer Operations

One Energy Plaza

Jackson, MI 49201

Michael D. VanHemert

Vice President, Corporate Secretary and 

Chief Compliance Officer

One Energy Plaza

Jackson, MI 49201

Theodore J. Vogel

Vice President and Chief Tax Counsel

One Energy Plaza

Jackson, MI 49201
Page 1-10 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Nuclear Management Company, LLC

Nuclear Management Company Directors

Nuclear Management Company Principal Officers

Name Address

David W. Joos Consumers Energy Corp.

212 West Michigan Ave.

Jackson, MI 49201

Frederick Kuester Wisconsin Electric Power Co.

231 West Michigan Street

Milwaukee, WI 53201

Michael B. Sellman Nuclear Management Company, LLC

700 First Street

Hudson, WI 54016

David M. Wilks Xcel Energy

4653 Table Mountain Dr.

Golden, CO 80403

Eliot G. Protsch Alliant Energy Corp.

200 First Street SE

Cedar Rapids, IA 52406

Charles Schrock Wisconsin Public Service Corp.

700 North Adams St.

Green Bay, WI 54307

Name Address

Michael B. Sellman

President and Chief Executive Officer

700 First Street

Hudson, Wisconsin 54016

John Paul Cowan

Executive Vice President and Chief 

Nuclear Officer

700 First Street

Hudson, Wisconsin 54016

Greg Palmer

Vice President and Chief Financial 

Officer

700 First Street

Hudson, Wisconsin 54016
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Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

1.3.5 Class of License, Use of Facility, and Period of Time for which the License is Sought

NMC requests renewal of the Class 104b operating license for Palisades Nuclear Plant 

(license number DPR-20) for a period of 20 years beyond the expiration of the current 

license. License renewal would extend the operating license from midnight March 24, 2011, 

until midnight March 24, 2031. This application includes a request for renewal of those NRC 

source material, special nuclear material, and byproduct material licenses that are included 

within the current operating license and that were issued pursuant to 10 CFR Parts 30, 40 

and 70.

The facility will continue to be known as the Palisades Nuclear Plant.

1.3.6 Earliest and Latest Dates for Alterations, if Proposed

NMC does not propose to construct or alter any production or utilization facility in connection 

with this renewal application. The current licensing basis will be continued and maintained 

throughout the period of extended operation.

Lyle H. Bohn

Senior Vice President - Nuclear Support 

Programs

700 First Street

Hudson, Wisconsin 54016

Jonathan M. Rogoff

Vice President, General Counsel, and 

Secretary

700 First Street

Hudson, Wisconsin 54016

Douglas E. Cooper

Senior Vice President - Group 

Operations

700 First Street

Hudson, Wisconsin 54016

Craig G. Anderson

Senior Vice President - Group 

Operations

700 First Street

Hudson, Wisconsin 54016
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Application for Renewed Operating License

Technical and Administrative Information

1.3.7 Listing of Regulatory Agencies Having Jurisdiction and News Publications

The Federal Energy Regulatory Commission (FERC) and the Michigan Public Service 

Commission are the principal regulators of Consumers’ electric operations. 

The area news publications and their associated addresses are provided below

1.3.8 Conforming Changes to Standard Indemnity Agreement

The requirements at 10 CFR 54.19(b) state that license renewal applications must include 

“conforming changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to 

account for the expiration term of the proposed renewed license.” The current indemnity 

agreement No. B-40 for Palisades states, in Article VII, that the agreement shall terminate at 

the time of expiration of that license specified in Item 3 of the attachment to the agreement, 

which is the last to expire. Item 3 of the attachment to the indemnity agreement, as revised 

Secretary

Federal Energy Regulatory Commission

888 First Street, NE, Room 1A

Washington, DC 20426

Chairperson

Michigan Public Service Commission

PO Box 30221

Lansing, Michigan 48909-7721

The Herald-Palladium

PO Box 128

St. Joseph, Michigan 49085

The Kalamazoo Gazette

401 S. Burdick

Kalamazoo, Michigan 49007

South Haven Tribune

255 Center St.

South Haven, Michigan 49090
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by Amendment No. 1, lists DPR 20 as the applicable operating license number. Should the 

operating license number be changed upon issuance of the renewed license, NMC requests 

that conforming changes be made to Item 3 of the attachment, and any other sections of the 

indemnity agreement as appropriate.

1.3.9 Restricted Data Agreement

This application does not contain restricted data or other national defense information, nor is 

it expected that subsequent amendments to the license application will contain such 

information. However, pursuant to 10 CFR 54.17(g) and 10 CFR 50.37, NMC, as a part of 

the application for a renewed operating license, hereby agrees that it will not permit any 

individual to have access to or any facility to possess Restricted Data or classified National 

Security Information until the individual and/or facility has been approved for such access 

under the provisions of 10 CFR Parts 25 and/or 95.

1.4 Current Licensing Basis Changes During NRC Review

Each year, following the submittal of the Palisades License Renewal Application and at least 

three months before the scheduled completion of the NRC review, NMC will submit an 

amendment to the application pursuant to 10 CFR 54.21(b). This amendment will identify any 

changes to the Current Licensing Basis of the facility that materially affect the contents of the 

License Renewal Application, including the FSAR supplement, that have not already been 

submitted.
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1.5 Abbreviations

This section contains the abbreviations that pertain to the administrative and technical 

information within the license renewal application. The abbreviations that pertain to the 

environmental information are included as part of Appendix E (Environmental Report).

AAC Alternate Alternating Current 

AC Alternating Current 

ACI American Concrete Institute 

ACSR Aluminum Conductor Steel Reinforced 

AEC Atomic Energy Commission 

AFW Auxiliary Feedwater 

AISC American Institute of Steel Construction 

AMMS Advanced Maintenance Management System

AMP Aging Management Program

AMR Aging Management Review

AMSAC ATWS Migrating System Actuation Circuit 

ANSI American National Standards Institute 

APP R 10 CFR 50 Appendix R

AR Action Request

ASME American Society of Mechanical Engineers

ASME III American Society of Mechanical Engineers Boiler 

and Pressure Vessel Code, Section III

ASSY Assembly 

ASTM American Society for Testing of Materials

ATWS Anticipated Transients Without a Scram 

AUX Auxiliary 

B&W Babcock and Wilcox 

BAW Babcock and Wilcox

BOP Balance of Plant
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BTP Branch Technical Position

BWR Boiling Water Reactor 

BWOG B & W Owners Group

CASS Cast Austenitic Stainless Steel

CB Control Building

CBD Class Boundary Diagram

CCS Component Cooling System

CCCW Closed Cycle Cooling Water

CCW Component Cooling Water

CD-ROM Compact Disk-Read Only Memory 

CDS Condensate System

CE Condition Evaluation

CFR Code of Federal Regulations

CHECWORKS The suite of products developed to evaluate power 

plants for the most common forms of corrosion that 

degrade their performance and shorten the operating 

life of critical components.

CIV Containment Isolation Valve 

CIS Containment Isolation System

CLB Current Licensing Basis 

CMAA Crane Manufactures Association of America

CMS CMS Energy Corporation

Co Company 

CPCo Consumers Power Company

CR Condition Report 

CRD Control Rod Drive

CRDM Control Rod Drive Mechanism 

CS Carbon Steel
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CSR Cable Spreading Room 

CSS Containment Spray System

CST Condensate Storage Tank 

CSW Critical Service Water

CUF Cumulative Usage Factors

CV Control Valve

CVCS Chemical and Volume Control System

CWS Circulating Water System

DBA Design Basis Accident

DBD Design Basis Document 

DBE Design Basis Event

DC Direct Current 

DG Diesel Generator or Design Guide

DI Deionized

DMW Demineralized Water

DNB Departure from Nucleate Boiling 

DNBR Departure from Nucleate Boiling Ratio 

EAB Emergency Breathing Air

ECCS Emergency Core Cooling System 

ECT Eddy Current Testing 

EDG Emergency Diesel Generator

EEQ Electrical Equipment Qualification

EFPY Effective Full Power Years

EIN Equipment Identification Number 

EL Elevation 

EOCI Electric Overhead Crane Institute

EOLE End Of Life - Extended
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EPA Electrical Penetration Assemblies 

EPDM Ethylene Propylene Diene Monomer 

EPR Ethylene Propylene Rubber 

EPRI Electric Power Research Institute 

EQ Environmental Qualification

ESF Engineered Safety Feature 

ESFAS Engineered Safety Features Actuation System

F Fahrenheit 

FAC Flow-Accelerated Corrosion 

FatiguePro Automated Cycle Counting and Fatigue Monitoring 

Program 

FE Flow Element 

FERC Federal Energy Regulatory Commission

FHAR Fire Hazards Analysis Report

FP Fire Protection

FPER Fire Protection Evaluation Report

FM Frequency Modulation 

FSAR Final Safety Analysis Report 

GALL Generic Aging Lessons Learned

GDC General Design Criterion 

GEIS Generic Environmental Impact Statement 

GL Generic Letter

GSI Generic Safety Issues 

GTR Generic Technical Report

HAZ Heat-Affected Zone

HELB High Energy Line Break 
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HEPA High Efficiency Particulate Filter

HMWPE High Molecular Weight Polyethylene 

Hr Hour 

HVAC Heating, Ventilating and Air Conditioning 

HX Heat Exchanger 

I&C Instrumentation & Controls

I/P Current to Pressure Converter 

IA Instrument Air

IASCC Irradiation Assisted Stress Corrosion Cracking

ID Identification or Inside Diameter

IE Inspection and Enforcement 

IEB Inspection and Enforcement Bulletin 

IEEE Institute of Electrical and Electronics Engineers, Inc.

IF Intended Function

IGA Intergranular Attack

IGSCC Intergranular Stress Corrosion Cracking

ILRT Integrated Leak Rate Test

IN Information Notice or Inch

INPO Institute of Nuclear Power Operations 

IPA Integrated Plant Assessment 

IR Insulation Resistance or Inspection Report 

ISG Interim Staff Guidance 

ISI Inservice Inspection

ITG Issues Task Group 

IWB ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class 1 Components of 

Light-Water Cooled Power Plants
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IWC ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class 2 Components of 

Light-Water Cooled Power Plants

IWD ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class 3 Components of 

Light-Water Cooled Power Plants

IWE ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class MC and Metallic Liners of 

Class CC Components if Light-Water Cooler Power 

Plants

IWF ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class 1, 2, 3, and MC Component 

Supports of Light-Water Cooled Power Plants

IWL ASME Boiler and Pressure Vessel Code, Section XI, 

Requirements for Class CC Concrete Components of 

Light-Water Cooled Power Plants

KIC Reference Stress Intensity Factor As A Function Of 

the Metal Temperature (T) and the Metal References 

Nil-Ductility Temperature (RTNDT)

KIP 1000 lb; or 1 Kilo-pound

KIR ASME Fracture Toughness Curve

Ksi One KIP per Square Inch, 1000 psi

KV Kilovolts 

KWe Kilowatt Electric

Lb Pound 

LBB Leak-Before-Break

LEFM Leading Edge Flow Meter

LER Licensee Event Report

LLC Limited Liability Company 

LO Lubricating Oil 
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LOCA Loss-Of-Coolant-Accident

LR License Renewal

LRA License Renewal Application

LTOP Low-Temperature Overpressure Protection

LWR Light Water Reactor

Mat'l Material

MIC Microbiologically Induced Corrosion 

MIRVP Master Integrated Reactor Vessel Surveillance 

Program

Misc. Miscellaneous 

MRP EPRI Materials Reliability Program

MS Main Steam

MSIV Main Steam Isolation Valve

MSLB Main Steam Line Break

MT Magnetic Particle Test 

MW Megawatts

MWD Megawatt-Day 

MWe Megawatt Electric

MWt Megawatt Thermal 

NA OR N/A Not Applicable 

NaOH Sodium Hydroxide 

NCR Non-Conformance Report

NDE Non-Destructive Examination 

NEI Nuclear Energy Institute

NEPA National Environmental Policy Act

NES Nuclear Engineering Services

NFPA National Fire Protection Association
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NMC Nuclear Management Company 

NPS National Pipe Size

NQAP Nuclear Quality Assurance Program 

NRC Nuclear Regulatory Commission 

NSAC Nuclear Safety Analysis Center 

NSP Northern States Power 

NSR Non-Safety Related

NSSS Nuclear Steam Supply System

NUMARC Nuclear Utility Management and Resource Council 

NUREG Nuclear Regulation Document 

OCCW Open Cycle Cooling Water

ODSCC Outside Diameter Stress Corrosion Cracking

OEM Original Equipment Manufacturer 

P&ID Piping and Instrument Diagram

P-T Pressure - Temperature 

PAS Post Accident Sampling

PBD Program Basis Document

PCP Primary Coolant Pump

PCS Primary Coolant System

PDI Performance Demonstration Initiative 

PM Preventative Maintenance 

PNP Palisades Nuclear Plant

PORV Power-Operated Relief Valve

PPAC Palisades Periodic Activity Control

PPB Parts Per Billion 

PPC Plant Process Computer

PS Pipe Support 
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PSI Pounds Per Square Inch

PSIA Pounds per Square Inch Absolute

PSIG Pounds Per Square Inch Gauge

PT Penetrant Testing 

PTS Pressurized Thermal Shock 

PVC Poly Vinyl Chloride

PWR Pressurized Water Reactor 

PWSCC Primary Water Stress Corrosion Cracking

PZR Pressurizer 

Q-List Quality List

QA Quality Assurance

RAI Request for Additional Information

RCS Reactor Coolant System

RCCA Rod Control Cluster Assembly

RCP Reactor Coolant Pump

RCPB Reactor Coolant Pressure Boundary 

RCS Reactor Coolant System

REV Revision

RG Regulatory Guide

RHR Residual Heat Removal

RI-ISI Risk Informed Inservice Inspection Program

RIA Radiation Monitoring

RPS Reactor Protection System

RPV Reactor Pressure Vessel

RTD Resistance Temperature Detectors 

RTNDT Reference Temperature for Nil Ductility Transition 
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RTPTS Reference Temperature for Pressurized Thermal 

Shock 

RV Reactor Vessel or Relief Valve 

RVI Reactor Vessel Internals

RWST Refueling Water Storage Tank

S&PC Steam and Power Conversion 

SA Service Air

SBO Station Blackout

SC Structure and Component 

SCBA Self-Contained Breathing Apparatus 

SCC Stress Corrosion Cracking 

SER Safety Evaluation Reports

SFP Spent Fuel Pool

SG Steam Generator

SGBD Steam Generator Blowdown 

SGTR Steam Generator Tube Rupture

SI Safety Injection

SIRW Safety Injection and Refueling Water

SIS Safety Injection System or Safety Injection Signal

SOC Statement Of Considerations

SOER INPO Significant Operating Event Report

SV Solenoid Valve 

SR Safety Related

SRP Standard Review Plan

SRP-LR Standard Review Plan for License Renewal

SS Stainless Steel or Sampling System

SSAR Safe Shutdown Analysis Report

SSC System, Structure, or Component 
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SSE Safe Shutdown Equipment

SWS Service Water System

TAVG PCS Average Temperature

TB Turbine Building

TID Total Integrated Dose

TLAA Time-Limited Aging Analysis 

TR Technical Report 

TRM Training Requirements Manual 

TS Technical Specifications 

TSC Technical Support Center 

U.S. United States

UHS Ultimate Heat Sink

USE Upper Shelf Energy

USI Unresolved Safety Issue

USNRC United States Nuclear Regulatory Commission 

UT Ultrasonic Testing

UTS Ultimate Tensile Strength

UV Ultraviolet 

VAC Volts-Alternating Current 

VCT Volume Control Tank

VDC Volts-Direct Current 

Vol. Volume 

Vs. Versus 

VT Visual Examination 

WCAP Westinghouse Commercial Atomic Power 
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WO Work Order

WOG Westinghouse Owners Group

XLPE Cross-Linked Polyethylene 

YARD Yard Structures 

Zn Zinc
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1.6 Communications

Written communications on this application should be directed to:

Mr. Daniel J. Malone

Site Vice President

Palisades Nuclear Plant

27780 Blue Star Highway

Covert, MI 49043

With copies to:

Mr. Darrel G. Turner

License Renewal Project Manager

Palisades Nuclear Plant

27780 Blue Star Highway

Covert, MI 49043

And

Mr. Douglas F. Johnson

Director, Plant Life Cycle Issues

Nuclear Management Company, LLC

700 First Street

Hudson, WI 54016
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Section 1.0 References

1. 10 CFR 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants, U.S. 

Nuclear Regulatory Commission.

2. 10 CFR 51, Environmental Protection Regulations for Domestic Licensing and Related 

Regulatory Functions, U.S. Nuclear Regulatory Commission.

3. Not used

4. NEI 95-10, Industry Guideline for Implementing the Requirements of 10 CFR Part 54 -The 

License Renewal Rule, Rev. 4, Nuclear Energy Institute, October 2004.

5. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants, U.S. Nuclear Regulatory Commission, July 2001.

6. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory 

Commission, July 2001.
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2.0 Scoping and Screening Methodology for Identifying Structures and 

Components Subject to Aging Management Review, and Implementation 

Results

This section describes the process for identification of structures and components subject to aging 

management review in the Palisades Integrated Plant Assessment (IPA). For those systems, 

structures, and components (SSCs) within the scope of license renewal, 10CFR54.21(a)(1) 

requires a license renewal applicant to identify and list structures and components subject to aging 

management review. Furthermore, 10CFR54.21(a)(2) requires that methods used to identify these 

structures and components be described and justified. Technical information in this chapter serves 

to satisfy these requirements.

The scoping and screening methodology is described in Section 2.1. The results of the assessment 

to identify the systems and structures within the scope of license renewal (plant level scoping) are 

in Section 2.2. The results of the identification of the components and structural components 

subject to aging management review (screening) are in Section 2.3 for mechanical systems, 

Section 2.4 for structures, and Section 2.5 for electrical and instrumentation and controls systems.

Table 2.1-1 defines the terms used in the Scoping/Screening results tables to represent the 

intended functions of components, subcomponents, and structural members. Intended functions 

are the specific intended functions performed by in-scope passive components in support of system 

or structure intended functions. Passive components are components that perform an intended 

function without moving parts or without a change in configuration or properties.

2.1 Scoping and Screening Methodology

2.1.1 Introduction

Palisades conducted scoping and screening using the NEI 95-10, Industry Guideline for 

Implementing the Requirements of 10 CFR Part 54 - the License Renewal Rule, as a 

primary guide. The scoping process defined the entire plant in terms of systems and 

commodity groups and identified their system level functions. These were then evaluated 

against the scoping criteria set forth in 10 CFR 54.4 (a)(1), (2), and (3), to determine 

whether they performed or supported a license renewal system intended function. Even if 

only a portion of a system or commodity group met the scoping criteria of 10 CFR 54.4, the 

system or commodity group was identified as in scope for license renewal. 

An evaluation was performed to determine which components performed or supported the 

system intended functions identified previously. Not all components within an in-scope 

system or structure were found to be in-scope for license renewal. The in-scope boundary is 

depicted on the License Renewal Boundary Drawings (See Palisades Plant Scoping 

Boundary Drawing Index ), which show the in-scope components highlighted in color. 
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The screening process evaluated the in-scope structures and components to determine 

which were long-lived and passive. The result was a list of long-lived, passive components 

that would be subject to an aging management review (AMR). Boundary descriptions, 

scoping, and screening results are contained in the appropriate sections of this application.

The Aging Management Review methodology is discussed in Section 3.0 of the LRA. 

2.1.1.1 Plant Information Sources

A number of different information sources played a role in how scoping and 

screening was performed at PAL. The principal sources are discussed below.

2.1.1.1.1 Current Licensing Basis

The Current Licensing Basis (CLB) for license renewal purposes is defined in 

10 CFR 54.3. The documents that comprise the CLB for PAL have been 

defined in accordance with this guidance. Therefore, where the term CLB is 

used in the LRA, its definition is consistent with 10 CFR 54.

2.1.1.1.2 Design Basis Events (DBEs)

The safety classifications for SSCs at Palisades were established based on a 

set of Design Basis Events (DBE), which include design basis accidents, 

anticipated operational occurrences, natural phenomena, and external events. 

The DBEs considered are consistent with the Palisades CLB. Chapter 2 and 

Chapter 14 of the Palisades FSAR describe these DBEs. 

2.1.1.1.3 Safety Classifications

Safety classifications for systems, structures, and components at Palisades, for 

License Renewal purposes, fall into one of the following:

• Safety Related (SR)

• Non-Safety Related Affecting Safety Related (NSAS)

• Non-Safety Related (NSR)

Safety Related 

Safety related structures, systems, and components are those that are relied 

upon to remain functional during and following design basis events to ensure:

• The integrity of the reactor coolant pressure boundary

• The capability to shut down the reactor and maintain it in a safe shutdown 

condition
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• The capability to prevent or mitigate the consequences of accidents that 

could result in potential off site exposures comparable to the guideline 

exposures set forth in 10CFR100.11

An item is considered “relied upon” if failure of the item, in conjunction with a 

single active failure, results in the inability to perform a safety function 

(assuming that the item is designed for that purpose, and assuming that offsite 

power may or may not be available).

The safety related classification includes Electrical/Instrumentation and Control 

(I&C) systems whose purpose is to initiate automatic safety features or operator 

actions that are required for accident prevention and mitigation, or to shutdown 

the reactor and maintain it in a safe shutdown condition.

Non-Safety Related Affecting Safety Related 

10 CFR 54.4(a)(2) specifies that the scope of systems, structures, and 

components (SSC) addressed by the license renewal rule includes “All 

non-safety related systems, structures, and components whose failure could 

prevent satisfactory accomplishment of any of the functions identified in 

paragraphs (a)(1)(i), (ii), or (iii) of this section” (i.e., the functions identified as 

safety related).

Non-Safety Related

Systems, structures, and components whose failure would not affect the safety 

of the plant or any safety related SSC.

Within the Palisades equipment database, components are coded as safety 

related and/or one of several other classifications based on design and safety 

functions. Components are not coded as non-safety per se, but several of the 

codes relate to non-safety related design considerations. The combination of 

codes determines whether the components are subject to the Consumers 

Energy Quality Program (i.e., Q-listed). All safety related components, and 

some non-safety related components, are identified as Q-Listed in the 

equipment database. The portion of the database which contains the various 

codes is called the Q-List, and is formally controlled. This list was used for the 

classification of equipment for license renewal.

2.1.1.1.4 Palisades Equipment Database

Component information for systems and equipment at Palisades can be found 

in the Palisades Equipment Database (EDB). The Palisades Equipment 

Database is a relational database system that is used by the entire site for 
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maintenance and modifications. Components which have unique equipment 

identification numbers are identified in the EDB. The EDB does not include 

commodity items such as cables, raceways, conduits, piping, fireproofing, 

general construction items (e.g., nuts, bolts), or consumable materials (e.g., 

boric acid, diesel fuel, resins, etc.).

The EDB is the repository for Palisades Quality List (Q-List) information and 

contains component information data fields, including design related 

information and maintenance related information. The EDB was the primary 

source of component information used for determining the Q-List classification 

of each component.

2.1.1.1.5 Design Basis Documents 

Design Basis Documents (DBDs) were available for a number of support and 

accident mitigation systems, selected licensing issues, and FSAR Chapter 14 

Accident Analyses. DBDs are a tool to explain the requirements behind a 

design rather than describe the design itself. DBDs are not part of the CLB. 

However, DBDs were used to complement information obtained from other 

sources and to identify potential reference documents. These reference 

documents include, as applicable: 

• FSAR and Technical Specifications 

• Industry Codes, Standards, and Regulations

• Regulatory Correspondence and Documents

• Technical Correspondence, Analyses, and Reports

• Calculations

• Drawings, Specifications, Modifications, and Other Documents

• Vendor Reports, Specifications, and Drawings

2.1.1.1.6 Drawings

Reference Drawings

Controlled plant drawings were used as references when performing system, 

structure, and component evaluations for license renewal. In addition, the 

color-coded In Service Inspection (ISI) P&IDs were used to aid in identification 

of safety to non-safety related boundaries, and the color coded Appendix R 

Safe Shutdown Equipment P&IDs were used to aid identification of SSCs and 

flowpaths to support Appendix R requirements. 
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License Renewal Scoping Boundary Drawings

For mechanical, electrical, and civil/structural engineering disciplines, scoping 

boundary drawings were generated during the Boundary Evaluation phase of 

the scoping process (See Section 2.1.2.3). Boundary evaluations used 

controlled plant drawings, along with system/structure/component level scoping 

information. Color-coded drawings were generated to show the scoping 

boundaries. (See Palisades Plant Scoping Boundary Drawing Index )

2.1.1.1.7 Maintenance Rule Information

Maintenance Rule Scoping information for Palisades was the primary basis for 

system and structure level functions. This information included a 

comprehensive list of system functions originally considered by the 

Maintenance Rule Expert Panel. 

2.1.1.2 License Renewal Tools

2.1.1.2.1 License Renewal Database

A license renewal database was used as the information repository for system, 

structure, and component evaluations, and to provide a platform for the 

administration of equipment data and output reports. The database design is 

consistent with the process guidance in NEI 95-10, and the process 

requirements of 10 CFR 54.

2.1.1.2.2 License Renewal Database Population

The license renewal database was initially populated with system and 

component level information from the Palisades Equipment Database, and 

system function information from the Palisades Maintenance Rule database. 

Component information within the Palisades Equipment Database relevant to 

license renewal, such as the equipment identifications, descriptions, and Q List 

information, was included. Additional system/component/commodity 

information was added as needed.

2.1.1.2.3 License Renewal Database Outputs

The license renewal database is a tool to assist in performing the license 

renewal process for Palisades. As such, it is not the official record for 

documentation. The license renewal database outputs were packaged into 

reports and then reviewed and approved outside of the database. The 

approved reports are considered the permanent plant records supporting the 

application.
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2.1.1.3 Interim Staff Guidance Discussions

The NRC staff has identified a number of issues for which additional clarification 

was considered necessary, and has documented those clarifications in Interim 

Staff Guidance (ISG) documents. While many of the ISGs do not relate to scoping 

and screening, all are discussed here for completeness. 

The ISGs determined to be in final form are as follows:

1) Staff Guidance on the Position of the GALL Report Presenting One Acceptable 

Way to Manage Aging Effects for License Renewal (ISG-1)

2) Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements 

of the Station Blackout (SBO) Rule (10 CFR 50.63) for License Renewal (10 

CFR 54.4(a)(3)) (ISG-2) 

3) Proposed Revision of Chapters II and III of Generic Aging Lessons Learned 

(GALL) Report on Aging Management of Concrete Elements (ISG-3)

4) Aging Management of Fire Protection Systems for License Renewal (ISG-4)

5) Addition of Aging Management Program (AMP) for Fuse Holders (ISG-5) 

6) Updating the Approved Guidance Documents ISG Process (ISG-8)

7) “Class of 03” Standard License Renewal Application Format (ISG-10)

8) Environmental Assisted Fatigue for Carbon/Low Alloy Steel (ISG-11)

NRC action has not been completed on some ISGs. However, those draft ISGs 

that were publicly available during preparation of this application, were 

considered. In addition to the final form ISGs discussed above, the following draft 

ISGs were also considered:

1) Identification and Treatment of Housing for Active Components (Draft ISG-6)

2) Scoping Guidance for Fire Protection (FP) Systems, Structures and 

Components (Draft ISG-7)

3) Scoping Criteria 54.4(a)(2) (Draft ISG-9)

4) Addition of GALL Aging Management Program XI.M35, “One-Time Inspection 

of Small-Bore Piping” (Draft ISG-12)

5) Management of Loss of Preload on Reactor Vessel Internals Bolting Using the 

Loose Parts Monitoring System (Draft ISG-13)

6) Operating Experience with Cracking in Bolting (Draft ISG-14)

7) Revision to Generic Aging Lessons Learned (GALL) Aging Management 

Program (AMP) XI.E2 (Draft ISG-15)
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8) Time Limited Aging Analyses Supporting Information for license renewal 

applications (Draft ISG-16)

9) Periodic Inspections of Bus Ducts and Develop GALL AMP XI.E4 for bus ducts 

(Draft ISG-17)

10)Revision to GALL AMP XI.E3 for Inaccessible Cable (Draft ISG-18)

11)Revision of Aging Management Program XI.M11 (Draft ISG-19)

12)Revision of Aging Management Program XI.M19 (Draft ISG-20)

For the convenience of NR reviewers, discussions are provided in Sections 

2.1.1.3.1 through 2.1.1.3.20 to summarize how Palisades considered the ISGs.

2.1.1.3.1 Staff Guidance on the Position of the GALL Report Presenting One 

Acceptable Way to Manage Aging Effects for License Renewal (ISG-1)

This ISG highlights that the GALL is only one acceptable way to manage aging 

for license renewal. No response is necessary.

2.1.1.3.2 Staff Guidance on Scoping of Equipment Relied on to Meet the 

Requirements of the Station Blackout (SBO) Rule (10 CFR 50.63) for 

License Renewal (10 CFR 54.4(a)(3)) (ISG-2)

ISG-2 establishes the NRC position that the SSCs relied on for recovery from 

Station Blackout (SBO), in addition to SSCs relied on for coping with an SBO, 

should be in scope for License Renewal, even if it is outside of the plant’s CLB. 

The staff position is that the plant system portion of the offsite power system 

should be included in scope. 

For Palisades, including the SBO recovery equipment into the scope of license 

renewal brings into scope various electrical components and associated 

structures associated with providing offsite power via the switchyard to the two 

2400 VAC safety related buses. 

In summary, the following components support plant recovery from an SBO 

event, and have been included in the scope of license renewal in accordance 

with ISG-2.

• Switchyard disconnects and associated high voltage conductors, 

insulators and bus 

• Safeguards transformer and direct buried cables to the safeguards bus

• Safeguards bus and building

• Non-segregated bus, isolation breakers and medium voltage cables to 

the 2400 VAC safety related buses
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• High voltage overhead lines and towers from the switchyard to the 

startup transformers

• Startup transformers and load isolation breakers and associated 

medium voltage cables to the 2400 VAC safety related buses

The passive, long-lived electrical commodities associated with the restoration 

path for offsite power that are subject to an aging management review are:

• High-voltage transmission conductors

• High-voltage insulators

• High-voltage switchyard bus and connectors

• Inaccessible medium voltage cables and connections 

• Non-segregated phase bus and connections

• Electrical cables and connections

2.1.1.3.3 Proposed Revision of Chapters II and III of Generic Aging Lessons 

Learned (GALL) Report on Aging Management of Concrete Elements 

(ISG-03)

ISG-3 summarized the changes as a result of the performance of aging 

management reviews of in-scope concrete components. Palisades has 

concluded that many of these components do not require aging management 

for the period of extended operation. This conclusion is based on a review of 

the material of construction, the environment, and industry and plant-specific 

operating experience for these components. However, for accessible concrete 

portions of the containment (NUREG-1801, Section IIA), the examination 

requirements and inspection intervals of ASME Section XI, Subsection IWL 

remain applicable as an aging management program (AMP) for the period of 

extended operation. NUREG-1801, Section IIIA structures, that are subject to 

an aging management review, are subject to similar inspections as part of the 

Structural Monitoring Program.

NUREG-1801 does not require plant specific aging management programs for 

concrete components in inaccessible areas for which the applicant can 

demonstrate a non-aggressive environment and the use of high quality 

concrete. The environment to which inaccessible concrete at Palisades is 

exposed, is not aggressive; Palisades concrete structures are constructed 

using ingredients conforming to ACI and ASTM standards and practices, which 

provide for a good quality, dense, well cured, and low permeability concrete. 

Therefore, further aging management inspections of normally inaccessible 

structures will only be considered when aging effects on accessible concrete 
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structures indicate that potential detrimental aging effects could also be 

occurring in inaccessible areas. In addition, based on a long history of water 

chemistry data, with test results documenting a non-aggressive environment, a 

formal program to perform lake or ground water chemistry monitoring is 

unnecessary. 

2.1.1.3.4 Aging Management of Fire Protection Systems for License Renewal 

(ISG-4)

ISG-04 clarifies the NRC staff position concerning GALL Report Section 

XI.M26, “Fire Protection,” and XI.M27, “Fire Water System,” with regard to wall 

thinning of fire protection piping due to internal corrosion, testing of sprinkler 

heads, and valve line-up inspections of Halon/Carbon Dioxide fire suppression 

systems. Palisades considered this ISG during the preparation of the LRA, and 

the Palisades Fire Protection program is consistent with the aging management 

program elements presented in ISG-04.

2.1.1.3.5 Addition of Aging Management Program (AMP) for Fuse Holders (ISG-5) 

The NRC ISG for screening of fuse holders determined that fuse holders that 

are not part of an active component or assembly, such as switchgear, power 

supplies, power inverters, battery chargers, and circuit boards, are considered 

to be passive electrical components and, therefore, require an aging 

management review. Such fuse holders are evaluated for license renewal in the 

same manner as terminal blocks and other types of electrical connections. The 

NRC ISG also determined that fuse holders, that are piece parts of an active 

assembly, are not subject to aging management review, because they would be 

subject to periodic inspection and maintenance in accordance with the 

maintenance and surveillance activities applicable to the active assembly.

Using the criteria of ISG-5, a review of Palisades’ fuse holders was performed. 

The review determined there are some fuse holders that meet these criteria but 

there is no aging mechanism that would warrant aging management. 

Therefore, it was concluded that no aging management activity is required for 

this commodity group. See Section 3.6 for additional information.

2.1.1.3.6 Identification and Treatment of Housing for Active Components (Draft 

ISG-6)

ISG-6 reiterates the philosophy that, during the extended period of operation, 

safety related functions should be maintained in the same manner and to the 

same extent as during the current licensing term. Examples of structures and 
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components that perform passive functions are listed in 10 CFR 54.21(a)(1)(ii), 

which states, “These structures and components include, but are not limited to, 

pump casings, valve bodies....”

Pumps and valves were just an example here, meant to focus the AMR process 

on the passive function of an SSC. That passive function is not limited to the 

pressure boundary of the Reactor Coolant System. The exclusion of an SSC 

due to its active nature only applies to that portion of the SSC with an active 

function and not to those portions of the SSC with a passive function. 

Therefore, at Palisades, pump casings, valve bodies, fan housings and damper 

housings are considered to be within scope and subject to an AMR.

2.1.1.3.7 Scoping Guidance for Fire Protection (FP) Systems, Structures and 

Components (Draft ISG-7)

The Palisades Fire Protection System scoping takes into consideration the 

interim staff guidance (ISG-7) that was developed to clarify the requirements of 

10 CFR 54.4(a)(3) as it pertains to 10 CFR 50.48. This includes General Design 

Criterion 3, Appendix R and associated license conditions, and the proposed 

revisions to NUREG-1800, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants” concerning incorporation of 

this guidance into the improved license renewal guidance documents when this 

ISG is finalized.

The Fire Protection Program (FPP) was developed to maintain compliance with 

10 CFR 50.48, Appendix R to 10 CFR 50, and Appendix A of Branch Technical 

Position APCSB 9.5-1 by meeting the following objectives in fire areas 

important to safety (the effects of fires on SSCs “important to safety” are 

addressed in 10 CFR 50.48 and provide a general level of protection that is 

afforded to all systems, not only those required for safe shutdown):

• Reduce the likelihood of fires.

• Promptly detect and extinguish fires that do occur.

• Maintain safe-shutdown capability if a fire does occur.

• Prevent release of a significant amount of radioactive material if a fire does 

occur.

The Palisades Fire Protection Program also includes the fire protection 

equipment required for insurance purposes for facilities such as the Service, 

Support, Security, and Dry Fuel Support Buildings, temporary trailers, etc. The 

SSCs that are not important to safety have been excluded from the scope of 

license renewal.
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A review has been performed to identify the specific SSCs that fall within the 

scope of license renewal for the Fire Protection Program, including the SSCs 

relied upon in the Fire Hazards Analysis. As a result of this review, the following 

features and equipment have been included within the scope of license renewal 

for fire protection: 

• Fire detection and suppression equipment

• Fire barriers (includes doors, walls, gap covers, penetration seals, etc.)

• Safe shutdown equipment (Appendix R), if not included in other systems

• Reactor coolant pump oil collection sub-system

• Fire fighting support (communications, lighting, bottled air/SCBA, fire hose, 

extinguishers)

• Panels

• Post-fire repair equipment (required for cold shutdown)

• Radiant energy shields

The screening methodology applied to the Appendix R post-fire repair 

equipment that is maintained in storage was also considered and is discussed 

below.

In response to the NRC letter from Chris Grimes to Doug Walters (NEI) dated 

February 11, 1999, Subject: Screening of Equipment Kept in Storage, a review 

has been performed to identify equipment that (1) is maintained in storage, (2) 

is reserved for installation in the plant in response to a design basis event 

(DBE), and (3) requires an AMR. In addition to passive components, the review 

has also considered stored active components that are not routinely inspected, 

tested, and maintained. The Appendix R stored equipment is used to restore 

power to pre-selected plant components and to provide cooling to certain areas 

after a fire in order to attain cold shutdown. 

This scoping methodology used at Palisades is in accordance with the 

guidelines of the draft ISG-7.

2.1.1.3.8 Updating the Approved Guidance Documents ISG Process (ISG-8)

This discusses an administrative process to update guidance documents. No 

response is required.

2.1.1.3.9 Scoping Criteria 54.4(a)(2) (Draft ISG-9)

By letters dated December 3, 2001, and March 15, 2002, the NRC issued a 

staff position to the Nuclear Energy Institute (NEI) which described areas to be 
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considered and options it expects licensees to use to determine what systems, 

structures, or components (SSCs) meet the 10 CFR 54.4(a)(2) criterion.

Palisades considered the guidance contained in this ISG during the enhanced 

license renewal (a)(2) scoping process.

2.1.1.3.10“Class of 03” Standard License Renewal Application Format (ISG-10)

This ISG endorsed the NEI-proposed application format later embodied in NEI 

95-10 Revision 4. This application has been prepared consistent with this 

guidance.

2.1.1.3.11Aging Management of Environmental Fatigue for Carbon/Low-Alloy Steel 

(Draft ISG-11)

This draft ISG was closed by the NRC in 2003. No response is required.

2.1.1.3.12Addition of GALL Aging Management Program XI.M35, “One-Time 

Inspection of Small-Bore Piping” (Draft ISG-12)

ISG-12 clarifies the circumstances under which the NRC expects a one-time 

inspection for small bore Class 1 piping to provide additional assurance that 

small-bore piping is not aging, or that the effects of aging will be insignificant 

during the extended period of operation. See Appendix B to the LRA for 

additional information.

2.1.1.3.13Management of Loss of Preload on Reactor Vessel Internals Bolting 

Using the Loose Parts Monitoring System (Draft ISG-13)

This ISG is under NRC development and has not been issued for use. No 

response is required.

2.1.1.3.14Operating Experience with Cracking in Bolting (Draft ISG-14)

This ISG is under NRC development and has not been issued for use. No 

response is required.

2.1.1.3.15Revision to Generic Aging Lessons Learned (GALL) Aging Management 

Program (AMP) XI.E2 (Draft ISG-15)

This ISG provides clarification to the NUREG-1801 Aging Management 

Program X1.E2 to allow specific calibrations or surveillance in lieu of Technical 

Specification surveillance. 

Consistent with the ISG, the Palisades program for aging management of 

electrical cables and connections used in instrumentation circuits that are 
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sensitive to reduction in conductor IR requires periodic testing of cables in 

applicable circuits. See the Non-EQ Electrical Commodities Condition 

Monitoring Program discussion in Appendix B for additional information.

2.1.1.3.16Time Limited Aging Analyses Supporting Information for license 

renewal applications (Draft ISG-16)

Draft ISG-16 provides guidance on information that should be provided about 

plant specific time-limited aging analyses (TLAAs). The guidance in draft 

ISG-16 was considered in the development of the information included in 

section 4.0, “Time-Limited Aging Analyses.”

2.1.1.3.17Periodic Inspections of Bus ducts and Develop GALL AMP XI.E4 for bus 

ducts (Draft ISG-17)

This ISG provides direction to review bus insulation due to water intrusion in 

bus ducts and bus bar connections due to thermal cycles, and develops a 

NUREG-1801 Aging Management Program X1.E4 for bus ducts. 

Consistent with Draft ISG-17, the Palisades program for non-segregated phase 

bus and connections requires periodic inspections. See the Non-EQ Electrical 

Commodities Condition Monitoring Program discussion in Appendix B for 

additional information.

2.1.1.3.18Revision to GALL AMP XI.E3 for inaccessible cable (Draft ISG-18)

This ISG provides an enhancement to NUREG-1801 Aging Management 

Program X1.E3 to prevent moisture collection in manholes where 

medium-voltage cables are located. 

Consistent with Draft ISG-18, the Palisades program for Inaccessible 

medium-voltage cables and connections requires periodic inspection of 

manholes that contain in scope medium-voltage cables. See the Non-EQ 

Electrical Commodities Condition Monitoring Program discussion in Appendix B 

for additional information.

2.1.1.3.19Revision of Aging Management Program XI.M11 (Draft ISG-19)

This ISG is under NRC development and has not been issued for use. No 

response is required.

2.1.1.3.20Revision of Aging Management Program XI.M19 (Draft ISG-20)

This ISG is under NRC development and has not been issued for use. No 

response is required.
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2.1.1.4 Consideration of Power Uprating in License Renewal Evaluation Process

Palisades has implemented a 1.4% power uprate associated with margin 

uncertainty recapture. This small power uprate was considered in the evaluations 

supporting License Renewal. No further power uprates are currently anticipated.

2.1.1.5 Industry Guidance

In addition to NRC-issued guidance, a number of EPRI reports, vendor reports, 

and other nuclear industry documents were used as input to the IPA process. A 

primary reference for the design of license renewal work processes and the 

format of this application was NEI 95-10, Industry Guideline for Implementing 

the Requirements of 10 CFR Part 54 - the License Renewal Rule. 

2.1.2 Scoping Methodology

10 CFR 54 provides specific criteria for determining which systems, structures, and 

components should be reviewed and evaluated for inclusion in the scope of License 

Renewal. Specifically, 10 CFR 54.4 of the rule states that:

(a) Plant systems, structures, and components within the scope of this part are:

(1) Safety related systems, structures, and components which are those relied 

upon to remain functional during and following design basis events (as defined 

in 10 CFR 50.49(b)(1)) to ensure the following functions:

(i) The integrity of the reactor coolant pressure boundary;

(ii) The capability to shut down the reactor and maintain it in a safe shutdown 

condition; or

(iii) The capability to prevent or mitigate the consequences of accidents that 

could result in potential off-site exposures comparable to those referred to 

in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as 

applicable.

(2) All non-safety related systems, structures, and components whose failure 

could prevent satisfactory accomplishment of any of the functions identified in 

paragraphs (a)(1)(I), (ii), or (iii) above.

(3) All systems, structures, and components relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the 

NRC’s regulations for fire protection (10 CFR 50.48), environmental 

qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), 

anticipated transients without scram (10 CFR 50.62), and station blackout (10 

CFR 50.63).
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(b) The intended functions that these systems, structures, and components must be 

shown to fulfill in 10 CFR 54.21 are those functions that are the bases for 

including them within the scope of License Renewal as specified in paragraphs 

(a)(1) - (3) of this section.

The Scoping Process defined the entire plant in terms of major license renewal systems, 

structures, and commodity groups. System, structure, and commodity group system-level 

functions were identified and evaluated against criteria provided in 10 CFR 54.4(a)(1), (2), 

and (3), to determine whether the system, structure, or commodity should be considered 

in-scope for license renewal. Even if only a portion of a system, structure, or commodity 

fulfilled a scoping criterion, the system/structure/commodity was identified as in-scope for 

license renewal and received further screening. System boundaries were adjusted as 

needed to permit more efficient treatment of in-scope SSC.

The scoping methodology utilized by Palisades is consistent with the guidance provided in 

NEI 95-10. Existing plant documentation was used for this review, including the Palisades 

Current Licensing Basis documents, controlled drawings, and the equipment database. 

Once the systems and structures were identified for inclusion in the scope, they were further 

evaluated with the next step in the IPA process - screening.

2.1.2.1 Application of License Renewal Scoping Criteria

2.1.2.1.1 Scoping Criterion 1 - Safety Related Systems and Structures

The first scoping category in 10 CFR 54.4 involves safety related systems, 

structures, and components. The license renewal criteria for safety related 

SSCs are consistent with Palisades CLB, Q-List, and Maintenance Rule 

classification criteria. Therefore, SSCs that support a safety related function as 

defined in the CLB are considered in-scope of license renewal. In addition, a 

review was made of SSCs that have a safety related designation within the 

Q-List or the Maintenance Rule. 

The Palisades CLB definition of Safety Related is not identical to the definition 

provided within the license renewal rule. 10 CFR 54 cites 10 CFR 50 Section 

50.67(b)(2) and Section 50.34(a)(1), in addition to Section 100.11, as causing 

SSC to fall within the definition of safety related, and the Palisades CLB cites 

only Section 100.11. The differences related to §50.34(a)(1) and §50.67(b)(2) 

were investigated, and this did not result in any components being considered 

safety related in addition to those identified using the CLB.
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2.1.2.1.2 Scoping Criterion 2 - Non-Safety Related Systems and Structures 

Affecting Safety Related Functions 

10 CFR 54.4(a)(2) states that SSCs within the scope of License Renewal 

include non-safety related SSCs whose failure could prevent satisfactory 

accomplishment of any of the functions identified for safety related SSCs. 

Components meeting the scoping criterion of 10 CFR 54.4(a)(2) will generally 

fall into the three categories listed below: 

(1) Current Licensing Basis (CLB). The Palisades CLB includes a number of 

specific issues that identify non-safety related SSCs that meet the intent of 

10 CFR 54.4(a)(2).

(2) Non-safety related SSCs directly connected to safety related SSCs 

(typically piping systems).

(3) Non-safety related SSCs that are not directly connected to safety related 

SSCs. 

Categories 2 and 3 apply to non-safety related systems and components that 

may not be specifically identified in the CLB. These two categories were part of 

an expanded scoping effort conducted by Palisades relatively late in the 

application development process.

In many cases components were brought into scope in more than one category. 

Each of the three categories is described in the following text.

(1) Non-Safety Related SSCs Identified in the CLB

a. High Energy Line Break (HELB)

Non-safety related whip restraints, jet impingement shields, blowout 

panels, etc., that are designed and installed to protect safety related 

equipment from the effects of a HELB, are part of the CLB and should be 

included within the scope of license renewal per 54.4(a)(2) as mitigative 

features. These protective features are typically associated with the 

structure, and addressed in the Civil/Structural area review. 

The CLB design is based on HELB analysis that typically assumes failure 

only occurs at specific locations. If the mitigative option was chosen, then 

it was necessary to demonstrate that the choice of break locations remain 

valid for all potential aging mechanisms, or the mitigative features are 

adequate to address all potential failure locations that could result from 

aging. Otherwise, it was necessary to include all or part of the piping 

system within the scope of license renewal per 54.4(a)(2). 
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b. Internal/External Flooding

If level instrumentation and alarms are utilized to warn the operators of 

flood conditions, and operator action is necessary to mitigate the flood, 

then these instruments and alarms are within the scope of license renewal 

per 10 CFR 54.4(a)(2). If non-safety related sump pumps, piping and 

valves, are necessary to mitigate the effects of a flood which threatens 

safety related SSCs intended functions, then these components are also 

within the scope of license renewal per 10 CFR 54.4(a)(2). 

Non-safety related walls, curbs, dikes, doors, etc., that provide flood 

barriers to protect safety related SSCs, are within the scope of license 

renewal per 10 CFR 54.4(a)(2). These are typically included as part of the 

building structure, and evaluated in the civil/structural area review.

c. Internal/External Missiles

Missiles can be generated from internal or external events such as failure 

of rotating equipment or tornados. Inherent non-safety related features 

that protect safety related equipment from missiles are within the scope of 

license renewal per 10 CFR 54.4(a)(2). These protection features (missile 

barriers) are typically included as part of the building structure, and 

evaluated in the civil/structural area review. 

d. Heavy Load Lifting Equipment

The overhead-handling systems from which a load drop could result in 

damage to any system that could prevent the accomplishment of a safety 

related function, are considered to meet the criteria of 10 CFR 54.4(a)(2) 

and are within the scope of license renewal. These are included as part of 

the building structure, and evaluated in the civil/structural area review.

e. Operator Habitability and Access

Civil/Structural components/commodities that support operator habitability 

and access to operate safety related equipment in the Auxiliary Building 

and Turbine Building are included in-scope of license renewal. These 

items are evaluated by the license renewal civil/structural discipline.

(2) Non-Safety Related SSCs Directly Connected to Safety Related SSCs

For non-safety related SSCs directly connected to safety related SSCs, there 

are two primary areas of concern to address. First was the possibility that the 

pressure boundary related spatial interactions (pipe whip, jet impingement, 

spray, flood, etc.) of the non-safety piping could damage adjacent safety 
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related components. This is addressed the same as the non-safety related 

SSCs not directly connected to safety related SSCs discussed in category 

(3) below.

The second issue was to ensure the attached non-safety related piping and 

supports maintain their structural integrity to ensure the structural integrity of 

the attached safety related piping. This was accomplished by ensuring the 

pipe supports up to and including the first seismic or equivalent seismic 

anchor beyond the safety/non-safety interface, were within the scope of 

license renewal per 54.4(a)(2).

a) Initial (a)(2) Scoping Effort for NSR Directly Connected to SR

The initial (a)(2) scoping effort for NSR directly connected to SR was based 

on industry experience and the positions take by early applicants for license 

renewal. The philosophy was that if pipe supports of the connected NSR 

piping are age managed using a spaces approach, and the connected piping 

itself was subject to the same aging management (e.g., chemistry control) as 

the safety-related piping, then there was no need to explicitly identify the 

locations of anchors or scoping boundaries. The connected NSR piping was 

determined to be in scope for license renewal, but a generic definition of the 

piping and supports, similar to a commodity, was considered to be sufficient. 

This position was later revised and the scoping effort was expanded to more 

explicitly define the scoping boundaries.

b) Expanded (a)(2) Scoping Effort for NSR Directly Connected to SR

For non-safety SSCs directly connected to safety-related SSCs (typically 

piping systems), the non-safety piping and supports, up to and including the 

first seismic or equivalent seismic anchor beyond the safety/non-safety 

interface, are within the scope of license renewal per 54.4(a)(2). For this 

purpose, Palisades defined the “first seismic or equivalent seismic anchor” 

such that the failure in the non-safety related pipe run beyond the first 

seismic or equivalent seismic anchor would not render the safety-related 

portion of the piping unable to perform its intended function under CLB 

design conditions. An actual seismic anchor is taken to be a physical 6-way 

support (restraint against forces and moments in each of three orthogonal 

directions) that can be either a fabricated restraint or a base mounted 

component (e.g., pump, heat exchanger, tank, etc.). If a base mounted 

component is credited as an anchor, it is included in scope. An equivalent 

seismic anchor is typically defined as at least two rigid supports in each of 
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the three orthogonal directions. Components that are part of the non-safety 

related piping segment up to and including the first seismic or equivalent 

seismic anchor were included in the scope of license renewal, and a more 

detailed description of the scoping boundary was provided for the affected 

components. 

3) Non-Safety Related SSCs Not Directly Connected to Safety Related 

SSCs

For non-safety related SSCs that are not directly connected to safety related 

SSCs, or are connected downstream of the first seismic or equivalent 

seismic anchor, the non-safety related SSCs may be in-scope if their failure 

could prevent the performance of the safety function of a safety related SSC. 

The failures to be considered are two-fold: consequences due to the loss of 

pressure boundary of the non-safety related piping on adjacent SSCs (e.g., 

pipe whip, jet impingement, spray, flooding, etc.); and loss of support of the 

non-safety related piping resulting in it potentially falling on adjacent SSCs 

(seismic II/I).

a) Pressure Boundary Spatial Interactions

To determine which non-safety related SSCs may be in-scope for 54.4(a)(2) 

due to pressure boundary spatial interaction, including HELB, two options 

exist: a mitigative option or a preventive option. These options are discussed 

in the following text:

Mitigative Option

Palisades defines “mitigative” consistent with NEI-95-10. It means that the 

effects of failures of a non-safety related SSC on safety related SSCs are 

mitigated by some means. This mitigation is such that the failure of the 

non-safety related SSC will not prevent the performance of a safety related 

SSC intended function identified in 54.4(a)(1). If the mitigative option is used, 

then the mitigative features (whip restraints, spray shields, supports, barriers, 

etc.) need to be included within the scope of license renewal per 54.4(a)(2), 

and the non-safety system can be excluded from the scope of license 

renewal provided the mitigative features are adequate to address all potential 

failure locations that could result from aging. 

This option typically includes non-safety related SSCs identified in the CLB 

as discussed in Category 1 above.
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Preventive Option

If mitigative features are not installed, or cannot be shown to adequately 

protect safety related SSCs, then the preventive option is used. For the 

preventive option, vulnerable safety related components in proximity to the 

non-safety related systems are identified. This is performed via review of 

plant documentation and/or via walkdowns to identify non-safety systems, or 

portions of systems, that have spatial interaction potential (e.g., pipe whip, jet 

impingement, spray, flooding, etc.) with vulnerable safety related equipment 

assuming a failure anywhere along the length of the non-safety system. 

Palisades initially conducted scoping under this preventive option using 

industry precedents and judgment to exclude certain components from 

scope, but subsequently expanded the license renewal scope under this 

category by removing those exclusions guidelines.

• Original (a)(2) Scoping Effort for Preventive Option

Originally, Palisades used specific limitations that were based upon 

engineering judgment and earlier applications. For example, the 

spatial interactions evaluations initially relied upon were based upon 

consequence analysis work that had already been completed for 

another project. Limitations in that work included use of the analysts' 

judgment on spray distances as well as only considering active 

components as being susceptible targets.

• Expanded (a)(2) Scoping Effort for Preventive Option

Based upon recent NRC questions, current NRC expectations require 

a comprehensive strategy whereby there is no limitation to the 

duration of exposure to spray/leakage. This necessitates 

consideration of passive as well as active components to potential 

functional failure due to spray/leakage.

Additionally, current expectations are that there be no distance or 

other subjective criteria allowed in assessing whether a safety related 

component may be excluded from consideration if it exists in the 

same general area as the non-safety related piping system. General 

area is defined as being on the same floor of a building with no barrier 

walls between the fluid source and the safety related component. The 

original criteria did permit judgment to be exercised in determining 

susceptibility to spray or leakage.

Thus, the augmented methodology required that all pressurized 

liquid/steam systems in the general area of safety related 

components, passive or active, be considered in scope for license 
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renewal. This expanded approach was applied to a review of SSCs 

not already in scope for license renewal. SSCs already in-scope were 

not reevaluated. A significant amount of additional non-safety related 

piping and components were brought into scope for license renewal 

because of this expanded scoping effort.

At Palisades, both the preventive and mitigative options were utilized. All 

mitigative SSCs were identified via review of the CLB and included in-scope 

as discussed in Category 1 above. In addition, a review of potential 

consequences due to pressure boundary failure was performed for all 

non-safety related piping in the plant. Consequences that affect the ability of 

safety related components to perform their intended functions were identified 

and those systems, or portions of systems, were included in-scope. This was 

performed by use of piping failure consequence information developed from 

detailed plant documentation reviews (CLB, Design Basis Documents, piping 

area drawings, equipment layout drawings, flooding analysis, HELB analysis, 

etc.) augmented by walkdown inspections, assuming failure anywhere along 

the pipe.

b) Seismic II/I

Potential spatial interaction of non-safety piping systems that may fall on or 

otherwise physically impact safety related SSCs is considered as seismic II/I. 

Palisades was not originally designed to seismic II/I criteria. To address 

seismic II/I considerations at Palisades, guidance from NEI 95-10 was 

utilized.

In accordance with NEI 95-10, NUREG CR-6239 (section 4.2.6) reviewed 

earthquake experience data, including aged pipe, and concluded the 

following: 

• No experience data exists of welded steel pipe segments falling due to a 

strong motion earthquake.

• Falling of piping segments is extremely rare and only occurs when there 

is a failure or unzipping of the supports.

• These observations hold for new and aged pipe.

Piping supports for non-seismic piping need to be intact in order to prevent 

physical impacts on safety related equipment during a seismic event. 

Consistent with leak-before-break philosophy, it can also be assumed that 

piping which has retained its functional integrity will remain supported as long 

as its supports do not fail. If aged non-safety related piping does not fall 
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during a seismic event, it will also not fall due to the aging process of the 

pipe, as long as its supports are intact.

Therefore, as long as the supports for these piping systems are managed, 

falling of piping sections is not credible, and the piping section itself would 

not be in-scope for 54.4(a)(2) due to physical impact hazard (although the 

leakage/spray/flooding hazard may still apply).

All supports for non-seismic piping systems with a potential for spatial 

interaction with safety-related SSCs are included within the scope of license 

renewal. These supports are addressed in a commodity fashion within the 

civil / structural area utilizing a “spaces” approach wherein all pipe supports 

that exist in areas that contain safety related components are included 

in-scope.

4) Non-Safety Related Structures That Can Affect Safety Related 

Structures or Components

With regards to failure of non-safety related structures affecting the function 

of safety related structures and components, only the turbine building 

contains safety related components whose functions could be affected by 

failure of the non-safety related turbine building. The turbine building and 

discharge structure (warm water recirculating pump P-5 pumphouse, 

specifically) are both non-safety related structures that contain non-safety 

related components that could affect safety related components. There are 

no non-safety related structures that have been identified whose failure could 

affect the ability of a safety related structure from performing its safety 

related function

2.1.2.1.3 Scoping Criterion 3 - Systems and Structures Required by Other 

Regulations Identified in 10 CFR 54

The third scoping category in 10 CFR 54.4 involves SSCs relied upon by five 

regulated events identified in the Rule. Specifically, 10 CFR 54.4(a)(3) defines 

in-scope SSCs as those relied on in safety analyses or plant evaluations to 

perform a function that demonstrates compliance with one or more of the 

regulated events: 

1) Fire Protection (10 CFR 50.48)

2) Environmental Qualification (10 CFR 50.49)

3) Pressurized Thermal Shock (10 CFR 50.61)
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4) Anticipated Transients Without Scram (10 CFR 50.62)

5) Station Blackout (10 CFR 50.63)

Any system, structure, or component that is required to meet one or more of 

these regulations is identified as a Criterion 3 component. All criterion 3 

systems/components are considered to be in-scope of License Renewal.

A separate section is provided below for each of these regulations that 

describes the methodology used to determine any system, structure, or 

component that is required to support the regulations.

1) Fire Protection (FP)

The design of the Palisades Fire Protection program is based upon the 

defense in depth concept. Multiple levels of protection are provided so that 

should a fire occur, it will not prevent safe plant shutdown and the risk of a 

radioactive release to the environment will be minimized. These levels of 

protection include Fire Prevention, Fire Detection and Mitigation, and the 

Capability to Achieve and Maintain Safe Shutdown should a fire occur. This 

protection is provided through commitments made to Branch Technical 

Position APCSB 9.5 1, Appendix A, 10 CFR 50.48, and 10 CFR 50 Appendix 

R. Fire protection features and commitments are described in detail in the 

Fire Protection Program Report (FPPR). The SSCs at Palisades that support 

these multiple levels of protection are considered to be within the scope of 

license renewal. Note that Palisades’ scoping and screening process is 

consistent with the NRC Staff's guidance on consumables provided in 

NUREG-1800, Table 2.1 3. For fire protection, this would include such items 

as fire extinguishers, fire hoses, portable lighting, and air packs.

Information sources used in performing this portion of the scoping effort were 

the Post Fire Safe Shutdown Analysis Report (PSSA), the Safe Shutdown 

Equipment drawings, and the Fire Hazards Analysis Report (FHA). These 

are further discussed below.

a. Safe Shutdown Analysis Report 

Section III.G.1 of Appendix R to 10 CFR 50 requires that fire protection 

features be provided for systems, structures and components important to 

safe shutdown. In order to meet these requirements, all equipment required 

for safe shutdown, including the associated power and control cables, and 

any equipment which could adversely affect safe shutdown if spuriously 

actuated by fire-induced faults, have been identified for every fire area in the 

plant in order to assess the fire protection required. Safe shutdown for 
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Palisades is defined as hot standby conditions as a minimum, with the 

capability to proceed to cold shutdown should conditions warrant. Using this 

information, a Safe Shutdown Analysis was performed to determine the 

impact of a postulated fire on the safe shutdown equipment and circuitry 

within each fire area. Where a safe shutdown function was prevented, 

corrective actions (e.g., cable rerouting, cable protection, procedure 

changes, etc.) have been implemented to resolve the concern, or operator 

manual actions have been specified. In some cases credit is taken for 

equipment (other than the redundant counterpart) that provides a redundant 

function to the equipment affected by a postulated fire. 

b. Safe Shutdown Equipment

The first step of the safe shutdown analysis process was to establish the safe 

shutdown functions required to be performed. This was followed by selection 

of the systems, specific system equipment, and electrical/control circuits 

required to accomplish these functions. The selection of systems and how 

the systems fulfill the Appendix R performance goals were then depicted on 

system-level logic diagrams. Process flow paths for each of the required 

systems were then traced on plant flow diagrams. Based on these system 

flow paths, the minimum equipment necessary to bring the plant to cold 

shutdown was compiled. This compilation contains all power generation and 

distribution equipment (e.g., diesel generators, batteries, switchgear, motor 

control centers, power panels, etc.) that are required for the operation of the 

listed equipment. In addition, it includes equipment that, although not 

required for safe shutdown, could adversely affect safe shutdown if 

spuriously actuated by a fire-induced electrical fault. Safe shutdown 

equipment is shown on the color coded Appendix R safe shutdown 

equipment drawings.

c. Fire Hazards Analysis (FHA)

A systematic approach was used for the review of the fire hazards and their 

exposure to safety related equipment and components necessary for safe 

shutdown within the area. The type and quantity of combustible materials, 

type of fire hazards these materials present in the area, and the fire 

protection features (passive, active and manual) for the area were reviewed. 

The effects of postulated fires on the performance of safe shutdown functions 

and the minimization of radioactive releases to the environment were 

evaluated for each fire area. These evaluations identify those portions of the 
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plant Fire Protection System that are relied on to support the safe shutdown 

function of Appendix R.

Using the described information sources, the components in the Palisades 

equipment database were reviewed to determine those required to support 

the safe shutdown function for Fire Protection. Components supporting safe 

shutdown but not included in the equipment database were added to the 

license renewal database as necessary. Specifically, the FHA was the 

primary source of information to identify the classical fire protection related 

components to be included in-scope of license renewal. Components 

supporting fire detection, barriers (i.e., dampers), suppression, and fire 

fighting were identified primarily by the FHA and fire implementing 

procedures. Components and commodities of systems other than the Fire 

Protection System that support Appendix R safe shutdown requirements 

were identified primarily by use of the Appendix R color coded drawings. 

Structural components included in-scope of license renewal were identified 

by review of the Fire Protection area drawings that depict Appendix R fire 

barriers and boundaries, as well as by review of the mechanical systems, 

and their locations, credited for Appendix R.

2) Environmental Qualification (EQ)

The criteria for determining which equipment requires environmental 

qualification is defined by 10 CFR 50.49. 

Electric equipment covered in 10 CFR 50.49 is characterized as follows:

a) Safety related electric equipment that is relied upon to remain functional 

during and following design basis events to ensure -

(i) The integrity of the reactor coolant boundary,

(ii) The capability to shut down the reactor and maintain it in a safe 

shutdown condition, or

(iii) The capability to prevent or mitigate the consequences of accidents 

that could result in potential offsite exposures comparable to the 

guidelines in §50.34(a)(1), §50.67(b)(2), or §100.11 of Title 10 CFR. 

Design Basis Events are defined as conditions of normal operation, including 

anticipated operational occurrences, design basis accidents, external events, 

and natural phenomena for which the plant must be designed to ensure 

functions (i) through (iii) of this paragraph.
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Requirements for (1) dynamic and seismic qualification of electric equipment 

important to safety, (2) protection of electric equipment important to safety 

against other natural phenomena and external events, and (3) environmental 

qualification of electric equipment important to safety located in a mild 

environment are not included within the scope of the EEQ Program. A mild 

environment is an environment that would at no time be significantly more 

severe than the environment that would occur during normal plant operation 

or during anticipated operational occurrences.

b) Non-safety related electric equipment whose failure under postulated 

environmental conditions could prevent satisfactory accomplishment of 

safety functions. 

c) Certain post-accident monitoring equipment (Refer to Regulatory Guide 

1.97, Revision 3, “Instrumentation for Light-Water-Cooled Nuclear Power 

Plants to Assess Plant and Environs Conditions During and Following an 

Accident”).

The components, that meet these criteria for Palisades, are identified on the 

“Environmental Qualification Master Equipment List (MEL).”

Electrical equipment is qualified to withstand the normal and accident 

environments. In addition, consideration is given to all significant types of 

age-related degradation that can have an effect on the functional capability of 

the equipment.

The following documents describe the Palisades approach to environmental 

qualification of electrical equipment, give instructions for determining which 

equipment is qualified and for which environmental parameters, and identify 

the electrical equipment that has currently been qualified:

Environmental Qualification Master Equipment List (MEL) 

The Palisade MEL defines for Palisades all equipment determined to be 

within the scope of 10 CFR 50.49. The equipment is listed by equipment tag 

number or by commodity group. Any newly installed 10 CFR 50.49 

equipment is added to this list.

Harsh Environments List (HEL)

The Palisade HEL contains the accident temperature and pressure profiles 

for the containment building, and the normal and accident environments for 

all harsh environment areas of the plant.
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For scoping and screening at Palisades, the MEL was used as the basis for 

determining if a SSC is in-scope of license renewal. Specifically, components 

and their associated systems were identified in the MEL. These systems 

were placed in-scope of license renewal for EQ and the components from the 

MEL defined the boundary. Similarly, the structure that the component is 

located was identified from the MEL and the structure was included in-scope 

of license renewal since it supports and protects the components. Applicable 

commodities, such as cables, Raychem, conduit seals, etc., were also 

included in the license renewal database. 

3) Pressurized Thermal Shock (PTS)

This event deals with operations and inspections of equipment to minimize 

and monitor pressurized thermal transients to pressurized vessels. The only 

SSC relied on for pressurized thermal shock is the Reactor Vessel. Note 

there are no structures that are relied on for this scoping criterion.

4) Anticipated Transients Without a Scram (ATWS)

The Palisades design for accommodating ATWS events is described in 

Section 7.4 of the Palisades FSAR. The ATWS provides circuitry 

independent of the reactor protective system (RPS) to shut down the reactor, 

trip the turbine, and start the turbine driven auxiliary feedwater pump 

following a transient in which the Reactor Protective System (RPS) does not 

trip in the normal fashion. 

5) Station Blackout (SBO)

Methodologies acceptable to the NRC to achieve compliance with the SBO 

Rule are provided in NUMARC 87-00 and NRC Regulatory Guide 1.155. 

Palisades provided responses to the SBO rule in four submittals from 1989 to 

1991. The Palisades design satisfies the SBO Rule by providing adequate 

power to maintain Hot Standby conditions.

In support of Palisades responses to the SBO Rule, a minimum acceptable 

station blackout (SBO) duration of four hours was determined. Palisades 

selected coping as the means of maintaining the plant in a safe shutdown 

condition (hot standby) independent of AC power for the required SBO 

duration. Selected systems and design characteristics provide the 

availability, adequacy, and capability to achieve and maintain safe shutdown 

and to recover from an SBO for a four hour coping duration. Relevant 

analyses, in conjunction with plant Emergency Operation Procedures and 

the SBO SER, were used as the basis to determine the systems and system 
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functions required to support the SBO Rule. System boundaries and the 

components required to support those system functions were identified and 

included in-scope of license renewal due to SBO.

Systems and components were identified that are required to restore offsite 

power consistent with the direction given by the NRC in ISG-2. An April 1, 

2002 letter from the NRC to NEI (Interim Staff Guidance ISG-2) states the 

NRC's position “...that the plant system portion of the offsite power system 

that is used to connect the plant to the offsite power source should be 

included within the scope of the rule.” 

The preferred source of offsite power is via the motor operated disconnect 

24F1, fed from the front bus of the switchyard, which has multiple sources of 

supply from the transmission system to the Safeguards transformer. The 

scoping boundary for the preferred source of offsite power is via the motor 

operated disconnect 24F1, Safeguards transformer 1-1, direct buried cables, 

Safeguards bus, non-segregated bus, medium voltage cables, and isolation 

breakers. The alternate source of offsite power is via the motor operated 

disconnect 24R2, which is fed from the rear bus of the 345 KV switchyard, 

which has multiple sources of supply from the 345 KV transmission system. 

The scoping boundary for the alternate source of offsite power is via the 

motor operated disconnect 24R2, high voltage overhead lines and towers, 

startup transformers, load isolation breakers, and medium voltage cables.

2.1.2.2 Mechanical Discipline-Specific Scoping Methodology

The mechanical discipline was responsible for scoping evaluations for the plant 

mechanical piping systems. License renewal systems were initially based on the 

equipment database and Palisades Maintenance Rule system designations and 

boundaries. System level functions were also initially obtained from the 

Maintenance Rule database. The Maintenance Rule and License Renewal Rule 

have slightly differing criteria for system or structure inclusion. Therefore, system 

functions in-scope for the Maintenance Rule would not necessarily be in-scope for 

license renewal. In addition, the Maintenance Rule system functions were 

augmented to include functions to address the license renewal criterion as 

necessary.
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To determine whether a system was in-scope for license renewal, all system level 

functions were evaluated against the criteria specified in 10 CFR 54.4 (a)(1), (2), 

and (3). Those that met the criteria were considered in-scope of License Renewal. 

There are unique clarifications and exceptions to this:

• When all in-scope components are “Active,” the system was considered 

in-scope of license renewal but had no components requiring AMR.

• Similarly, when the only in-scope portion of the system was comprised of 

components that were subject to a commodity group evaluation (e.g. fire 

barriers, equipment supports, cables, etc.), that system or structure could be 

identified as not being within the scope of license renewal. These instances are 

clearly documented and the commodity group evaluation was referenced.

Some components within a system were removed from the mechanical system 

scoping if they were addressed generically in commodity groups. For example, 

system pipe supports were removed from their respective mechanical systems 

since they are handled as component support commodities by the civil/structural 

discipline.

Electrical components contained in the mechanical system were usually left in 

their respective systems since the majority are active and were screened out later. 

Some electrical components were also kept in their respective mechanical 

systems where they served a passive pressure boundary function.

Within most systems, new assets or subcomponents were created in the license 

renewal database to ensure that all necessary assets/components were 

accurately described and addressed in the license renewal process. Some of 

these decisions were based on the knowledge of what would subsequently be 

needed for screening or aging management. The following examples were used in 

the mechanical area: 

• Instrument manifolds, isolation, test, and vent valves, are not typically shown on 

P&IDs nor are they identified with individual component identifiers beyond the 

root valves. For this reason, a tubing and valve sub component was created for 

in-scope instruments. This represents all tubing, valves, and manifolds that 

would be associated with that instrument.

• A new asset of 'fastener' was created for each system that utilizes pressure 

boundary bolting.

• Heat exchangers were divided into subcomponents as necessary to identify all 

applicable material/environment/intended function combinations (i.e., HX ID 

tubes, HX ID - tube sheet, HX ID shell, etc.).
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• Piping assets were created to identify all applicable materials.

Evaluation Boundaries

Application of all three10CRF54.4 criteria generated a listing of SSC that are 

considered in-scope for license renewal. Not every component of a system 

supports the system intended functions. Therefore, some components within an 

in-scope system are not in-scope for license renewal. A description of the 

in-scope boundaries was provided along with a listing of components within the 

boundaries. Where convenient, these boundaries were depicted on drawings with 

color overlays. The colored portions of each drawing are in-scope, and the black 

portions are not in-scope. (Note that not all colored portions of the drawings are 

subject to AMR; i.e., they may be in boundary but screen out as active, 

periodically replaced, etc.).

In some instances, components were reviewed as part of another interfacing 

system in order to more accurately portray system functional boundaries, or to 

streamline the overall license renewal process. In a few cases, all in-scope 

components for a single system could be reviewed as part of another interfacing 

system. When components were reassigned to commodity groups or other 

systems, the system function associated with those components was also 

reassigned to the new commodity/system, and that function was deleted (if no 

other components used that function) from the original system. In this way, some 

systems were de-populated of in-scope functions, and therefore shown to be out 

of scope. However, most Palisades systems were ultimately determined to be in 

scope. Table 2.2-1 provides a list of Palisades license renewal systems and 

indicates whether they are in or out of scope for license renewal.

2.1.2.3 Civil/Structural Discipline-Specific Scoping Methodology

Civil/Structural scoping was performed in a manner to ensure that all plant 

buildings and yard structures, and their constituent parts, were considered for 

License Renewal. The scoping was performed using a structures and commodity 

approach to ensure all C/S components and commodities that serve a license 

renewal intended function were identified and evaluated for aging management. 

Grouping of C/S structures, components and commodities varied over the course 

of the project. They were grouped and evaluated in a comprehensive manner for 

initial scoping, but were then regrouped to facilitate aging management review 

and final License Renewal Application reporting to best serve the requirements of 

each stage of the LR process.
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Information sources used in C/S scoping included the FSAR, Q-List, Design Basis 

Documents (DBDs), Maintenance Rule Documentation, AMMS equipment 

database, Civil and other drawings, specifications, codes/standards, plant 

procedures, interviews with plant personnel, walkdowns of plant buildings and 

yard, as well as NEI 95-10 rev 4 (i.e., Appendix B “Typical Structure, Component 

and Commodity Groupings and Active/Passive Determinations for the Integrated 

Plant Assessment”).

The first step in C/S scoping involved identification of all site structures. The 

Maintenance Rule list of structures was used as a starting point. That list was 

augmented by review of the information sources discussed above and walkdowns 

to develop a final list of all plant structures, sub-structures, or groups of structures. 

The resulting structures were then loaded into the license renewal database for 

scoping evaluation. Structure functions were then developed and a determination 

of whether a structure was in-scope of license renewal was made based on: 1) 

whether the structure was safety related per the CLB; 2) whether its failure could 

prevent any safety related structure, system or component from performing its 

intended function; or 3) whether it performed a protection or support intended 

function for any in-scope system or component. 

Then, generic commodity components (i.e., assets) were created based on design 

function, structure (or yard), material, and environment to aid in the AMR 

evaluation process. For example, structural steel framing components consisting 

of columns, brackets, beams, girders, stiffeners, trusses, etc. would be 

represented by an asset entitled “Building Framing Commodity- Auxiliary Bldg, 

Carbon Steel, Protected.” The specific structural components to be included in 

each generic commodity asset were defined. Assets were only created for 

in-scope intended functions of the structures and commodity groups.

For aging management review, the structural commodity assets were regrouped 

into five (5) AMR groups to more effectively perform AMR evaluations and 

NUREG 1801 Volume 2 (GALL) alignments. The five groups developed for AMR 

evaluations were: Containment Pressure Boundary (GALL Section II), Component 

Supports (GALL Section IIIB), Structural Concrete Commodities (GALL Section 

IIIA), Structural Steel Commodities (GALL Section IIIA), and Miscellaneous and 

Bulk Commodities (GALL Section VII and non-GALL).

Finally, in order to align with the standard license renewal application format, C/S 

scoping and AMR results were regrouped and are presented by individual 

structures, the component support commodity group, and the miscellaneous and 

bulk commodity group. 
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Evaluation Boundaries

Building evaluation boundaries were established at the building column lines 

and/or physical barriers. Flexibility exists in determining the exact location of a 

boundary between adjacent structures and is discussed in detail in the 

system/boundary descriptions. 

2.1.2.4 Electrical and I&C Discipline-Specific Scoping Methodology

The Electrical discipline was responsible for performing scoping evaluations on 

plant electrical and instrumentation and control (I&C) systems for their 

applicability to license renewal rule requirements. License renewal system 

boundaries were initially based on the associated Palisades Equipment Database 

and Palisades Maintenance Rule system boundaries.

During the Scoping Process, evaluation boundaries were established for each 

system or commodity group based on the system functions. In some instances, 

components were reviewed as part of another interfacing system in order to more 

accurately portray system functional boundaries or to streamline the overall 

license renewal process. In a few cases, all in-scope components for a single 

system could be reviewed as part of another interfacing system. Junction boxes, 

panels, cabinets, and electrical penetration assemblies are identified in the 

Palisades equipment database, but the individual cables are not. The cables are 

all listed in a separate data base. 

A cable asset was added to each Mechanical and Electrical system in the license 

renewal database, and then transferred to a cable commodity. The cable 

commodity was then broken down into commodities to evaluate the Non-EQ 

electrical cables and connections, inaccessible medium voltage cables and 

connections, Non-EQ connections in instrument circuits that are sensitive to 

reduction in conductor insulation resistance, and the Non-EQ electrical and I&C 

penetration assemblies. Asset commodities were also created for fuse holders, 

non-segregated phase bus and connectors, high-voltage transmission 

conductors, high-voltage switchyard bus and connections, and high-voltage 

insulators.

2.1.3 Screening Methodology

The Screening Process identified the components from the in-scope systems, and 

commodity groups that would be subject to an aging management review. These 

components were those that performed a component level intended function (IF) without 
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moving parts or change in configuration or properties, and were not subject to replacement 

based on a qualified life or specified time period. 

The screening process consisted of the following distinctive steps:

• Identification of the components that were subject to aging management review (long 

lived and passive) for each in-scope system, structure, or commodity.

• Identification of the component level IF(s) for all components subject to aging 

management review. A component level IF is one that supports the system / structure / 

commodity level IFs.

• Identification of the applicable references used during the screening process to make the 

determinations.

Components that are subject to an aging management review are those that perform 

component level IF(s) without moving parts or without a change in configuration or 

properties and are not subject to replacement based on a qualified life or specified time 

period.

2.1.3.1 Active/Passive Determination

As part of the screening process, components that were within the license renewal 

evaluation boundary, that functioned with moving parts or with a change in 

configuration or properties (i.e. active components), were identified. Appendix B to 

NEI 95-10 provided guidance regarding component types that are generally 

considered to be passive or active. 

Most electrical and I&C system components are active per NEI 95-10, Appendix 

B. Using the license renewal database, active component types were identified 

and screened out since they do not require aging management review per 10 CFR 

54. For “passive, long-lived” electrical components, a commodity group was 

established for Non-EQ electrical cables and connections, inaccessible medium 

voltage cables and connections, Non-EQ connections in instrument circuits that 

are sensitive to reduction in conductor insulation resistance, Non-EQ electrical 

and I&C penetration assemblies, fuse holders, non-segregated phase bus and 

connectors, high-voltage transmission conductors, high-voltage switchyard bus 

and connections, and high-voltage insulators. 

Some components were screened uniquely:

• Temperature elements (TE) are typically active components per NEI 95-10. 

However, since Palisades does not typically identify thermowells as unique 

components in the Palisades equipment database, a review of Palisades 

documentation and interviews with system engineers was performed to 
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determine those that are pressure boundary related. The TE components 

identified as pressure boundary related, or which could not be determined, 

were identified as passive in order to represent the pressure boundary function 

(either the thermowell or other fittings if it was a direct immersion TE).

• Solenoid valves (SVs) are also typically active components. However, in some 

cases, the solenoid valve body will actually need to perform a pressure 

boundary function. All SVs were reviewed against this criteria, and those that 

were needed to maintain a pressure boundary were identified as passive.

• All instruments are considered active unless they form an integral part of the 

pressure-retaining boundary, such as level glasses, flow glasses, and in-line 

flow switches.

• Fans and dampers are normally considered active components, but, in 

accordance with ISG-6, fan and damper housings were considered passive and 

subject to an AMR.

Since Civil / Structural components and commodities (assets) were only created 

for in-scope structures and commodity groups, and all (with the exception of some 

crane components) are long-lived and passive, there was very little screening 

required. With the exception of some crane related components, all civil/structural 

components that were included in scope of License Renewal received aging 

management review. Therefore, in general, “in-scope” and “requires aging 

management review” are synonymous for civil structural components.

2.1.3.2 Identification of Short-lived Components and Consumables

The screening process identified those components that can be treated as 

short-lived. If a work control document was found to provide for the periodic 

replacement of the component, or the component was found to have an 

established qualified life (e.g., for EQ purposes), the component was identified as 

short-lived and an aging management review is not required for that component. 

Consumables are a special class of short-lived items that can include packing, 

gaskets, component seals, O-rings, oil, grease, component filters, system filters, 

fire extinguishers, fire hoses, and air packs. Many types of consumables are part 

of a component such as a valve or a pump and, therefore, have not been 

identified uniquely during scoping or screening. Items potentially treatable as 

consumables have been evaluated consistent with the information presented in 

Table 2.1-3 of NUREG-1800. The results of that evaluation are presented below.
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Packing, Gaskets, Component Seals, and O-Rings

Packing, gaskets, component mechanical seals, and O-rings are typically used to 

provide a leak-proof seal when components are mechanically joined together. 

These items are commonly found in components such as valves, pumps, heat 

exchangers, ventilation units/ducts, and piping segments. These types of 

consumables are considered subcomponents of the identified components and, 

therefore, are not subject to their own condition or performance monitoring. 

Therefore, the AMR for the component included an evaluation of the sealing 

materials in those instances where it could not be demonstrated that one of the 

following conditions exist:

1) The sealing materials are short-lived because they are replaced on a fixed 

frequency or have a qualified life established (e.g., for EQ purposes), or

2) The sealing materials are not relied on in the CLB to maintain any of the 

following:

• Leakage below established limits

• System pressure high enough to deliver specified flow rates

• A pressure envelope for a space

Oil, Grease, and Filters

Oil, grease, and filters (both system and component filters) have been treated as 

consumables because either:

1) A program for periodic replacement exists, or

2) A monitoring program (e.g., predictive analysis activities, condition 

monitoring) exists that replaces these consumables, based on established 

performance criteria, when their condition begins to degrade but before there 

is a loss of intended function.

Fire Extinguishers, Fire Hoses, and Air Packs

Components such as fire hoses, fire extinguishers, self-contained breathing 

apparatus (SCBA), and SCBA cylinders are considered to be consumables and 

are routinely tested or inspected. The Fire Protection Program complies with the 

applicable NFPA safety standards, which specify performance and condition 

monitoring programs for these specific components. Fire hoses and fire 

extinguishers are inspected and hydrostatically tested periodically, and must be 

replaced if they do not pass the test or inspection. SCBA and SCBA cylinders are 

inspected and periodically tested and must be replaced if they do not pass the test 

or inspection. The Fire Protection Program determines the replacement criterion 
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of these components that are routinely checked by tests or inspections to assure 

operability. Therefore, while these consumables are in the scope of license 

renewal, they do not require an AMR.

2.1.3.3 Screening of Stored Equipment

In response to the NRC letter from Chris Grimes to Doug Walters (NEI) dated 

February 11, 1999, Subject: Screening of Equipment Kept in Storage, a review 

has been performed to identify equipment that (1) is maintained in storage, (2) is 

reserved for installation in the plant in response to a design basis event (DBE), 

and (3) requires an AMR. In addition to passive components, the review has also 

considered stored active components that are not routinely inspected, tested, and 

maintained.

The Appendix R stored equipment is used to restore power to pre-selected plant 

components and to provide cooling to certain areas after a fire in order to attain 

cold shutdown. Related components were identified and included in the Fire 

Protection System for consistency, and given their Appendix R intended functions. 

Spare motors and portable fan units retained in storage were treated as active 

components, however, since they are tested and maintained in accordance with 

the Preventive Maintenance Program. The stored Appendix R cables are included 

in the Non-EQ electrical cables and connections commodity.

2.1.3.4 Screening of Thermal Insulation

Palisades has reviewed the current licensing basis and determined that only a 

small portion of the thermal insulation is in scope for license renewal. Through 

AMR, Palisades further determined that insulation is not subject to any aging 

effects requiring management. The Palisades methods and conclusions are 

consistent with those precedents established by and for the majority of past 

applicants. 

Palisades operating experience has shown no exposure to aggressive chemicals, 

such as sulfur dioxide in industrial areas and salt air in marine seashore areas.

There are 2 plant-specific situations where thermal insulation is within the scope 

of license renewal. They are the insulation at (1) the main feedwater and main 

steam penetrations that has the environmental control intended function to limit 

the adjacent concrete temperatures to less than 179F; and (2) the stainless steel 

mirror insulation on the reactor vessel supplied as part of the seismically qualified 

NSSS system for their spatial impact on safety related components. 
Page 2-37 

Palisades Nuclear Plant

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There are no plant locations within Palisades where insulation on piping and 

components is credited to reduce heat transfer for individual room heat load 

calculations in support of accident analyses or safe shutdown for regulated 

events. In particular, (1) the HVAC calculations for the diesel generator rooms did 

not credit actual heat losses from the diesel generator exhaust, and (2) there are 

no operating experience of AFW pump tests reporting localized failure of 

insulation leading to overheating failure of the AFW pump.

Individual insulation systems were designed, selected, and installed for the 

specific service and conditions. Passive degradation of insulation systems in 

indoor and outdoor environments is not expected. Gross failure of insulation 

materials is not credible. Therefore, degradation of insulation systems is not an 

aging concern, and will not result in degradation/failure of the underlying metal. 

2.1.3.5 Identification of Component Intended Functions

Component level IFs were identified and loaded into the license renewal 

database. A component level IF is a function that is required for the system to 

perform its system level IF(s). If a component did not have at least one component 

level IF, the component was not subject to aging management review. A list of 

component level IFs considered for all disciplines is provided in Table 2.1-1. 
Page 2-38 

Palisades Nuclear Plant

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Technical and Administrative Information

Table 2.1-1 Intended Function Definitions

INTENDED FUNCTION DEFINITION

Component Structural Support Provide structural support to safety-related components

Containment Isolation Provide containment isolation

Direct Flow Provide spray shield or curbs for directing flow (e.g. 

safety injection flow to containment sump)

Electrical Connections Provide electrical connections to specified sections of an 

electrical circuit to deliver system voltage and current

Expansion/Separation Provide for thermal expansion and / or seismic 

separation

Filtration Provide filtration

Fire Barrier Provide rated fire barrier to confine or retard a fire from 

spreading to or from adjacent areas of the plant

Flood Protection Provide flood protection barrier (internal and external 

flooding event)

Flow Measurement Orifice for purpose of fluid flow measurement

Flow Restriction Provide flow restriction (throttle)

Fluid Pressure Boundary Provide fluid pressure boundary

Gaseous Discharge Path Provide path for release of filtered and unfiltered 

gaseous discharge

Heat Sink Provide heat sink during SBO or design basis accidents.

Heat Transfer Provide heat transfer

HELB Shielding Provide shielding against high energy line breaks
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IA Pressure Boundary Part of IA Pressure Boundary for AOV

IA Supply Pressure Boundary Part of IA Supply Pressure Boundary to AOV

Missile Barrier Provide missile barrier (internally or externally 

generated)

Pipe Whip Restraint Provide pipe whip restraint

Pressure Boundary Provide pressure-retaining boundary so that sufficient 

flow at adequate pressure is delivered

Pressure Boundary/Fission 

Product Retention

Provide pressure boundary or fission product retention 

barrier to protect public health and safety in the event of 

any postulated design basis events.

Prevent Core Displacement Prevent excessive core displacement if the core barrel 

fails

Radiation Shielding Provide shielding against radiation

Reduce Flow Inequalities Reduce core inlet flow inequalities

Shelter/Protection Provide shelter/protection to safety-related components

Shutdown Cooling Water Provide source of cooling water for plant shutdown.

Spray Pattern Provide spray pattern at discharge nozzle

Structural Support for 

Non-Safety Related

Provide structural support to non-safety related 

components whose failure could prevent satisfactory 

accomplishment of any of the required safety-related 

functions

Structural Support for Safety 

Related

Provide structural and / or functional support to 

safety-related components

Table 2.1-1 Intended Function Definitions

INTENDED FUNCTION DEFINITION
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Palisades Nuclear Plant

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Structural Support for Regulated 

Events

Provide structural and/or functional support to Regulated 

Events components

Structure Functional Support Provide structural and / or functional support to 

safety-related equipment

Water Suppression Support Provide support of automatic water suppression for the 

protection of safe shutdown systems

Table 2.1-1 Intended Function Definitions

INTENDED FUNCTION DEFINITION
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Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Section 2.1 References 

1. Letter of March 10, 2003 from David B. Matthews of the NRC to Alan Nelson of NEI, 

Subject: Interim Staff Guidance (ISG) - 5 on the Identification and Treatment of 

Electrical Fuse Holders for License Renewal.

2. Letter of February 11, 1999 from Christopher I. Grimes of the NRC to Doug Walters of 

NEI, Subject: Request for Additional Information Regarding Generic License Renewal 

Issue No. 98-0102, Screening of Equipment that is Kept in Storage.

3. Standard Review Plan for Review of License Renewal Applications for Nuclear Power 

Plants, NUREG-1800, U.S. Nuclear Regulatory Commission, July 2001.

4. Letter of December 3, 2001 from Christopher I. Grimes of the NRC to Alan Nelson of 

NEI, Subject: License Renewal Issue: Scoping of Seismic II/I Piping Systems.

5. Letter of April 1, 2002 from David B. Matthews of the NRC to Alan Nelson of NEI, 

Subject: Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements 

of the Station Blackout (SBO) Rule (10 CFR 50.63) for License Renewal (10 CFR 

54.4(a)(3)).
Page 2-42 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

2.2 Plant Level Scoping Results

The systems, structures, and commodities at Palisades were evaluated to determine whether 

they were within the scope of license renewal, using the methodology described in Section 

2.1. The results are shown in Table 2.2-1.

.

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments

SRP Evaluation Group: Reactor Vessel, Internals, and Reactor Coolant System

Primary Coolant System

(Section 2.3.1.1)

Yes This system includes Class 1 piping, 

pressurizer, and coolant pumps

Reactor Vessel 

(Section 2.3.1.2)

Yes Includes Control Rod Drive Mechanisms

Reactor Vessel Internals

(Section 2.3.1.3)

Yes Includes passive components not directly 

attached to the reactor vessel

Replacement Steam 

Generators 

(Section 2.3.1.4)

Yes Includes primary, secondary and internal 

structural components

SRP Evaluation Group: Engineered Safety Features

Engineered Safeguards 

System 

(Section 2.3.2.1)

Yes This system includes Containment Spray, 

Engineered Safety Features Actuation, High 

Pressure Safety Injection, Low Pressure 

Safety Injection, Normal Shutdown and 

Design Basis Accident Sequencers, Safety 

Injection Tanks, Shutdown Cooling, Safety 

Injection and Refueling Water Tank, and 

Containment Sump Suction.

SRP Evaluation Group: Auxiliary Systems

Chemical Addition System

(Section 2.3.3.17)

Yes Portions of this system are in License 

Renewal scope for Criterion 2 only.

Chemical and Volume Control 

System 

(Section 2.3.3.1)

Yes This system includes Chemical and Volume 

Control and Concentrated Boric Acid.
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Technical and Administrative Information

Circulating Water System

(Section 2.3.3.2)

Yes Portions of this system are in License 

Renewal scope for Criterion 2 only.

Component Cooling Water 

System 

(Section 2.3.3.3)

Yes

Compressed Air System

(Section 2.3.3.4)

Yes This system includes Feedwater Purity Air, 

High Pressure Air, and Instrument and 

Service Air.

Containment Air Recirculation 

and Cooling System 

(Section 2.3.3.5)

Yes

Domestic Water System

(Section 2.3.3.16)

Yes Portions of this system are in License 

Renewal scope for Criterion 2 only.

Dry Fuel Storage System No Dry Fuel Storage Systems are managed 

under 10 CFR 72 and do not fall under the 

requirements of 10 CFR 54.

Emergency Power System

(Section 2.3.3.6)

Yes This system includes Emergency Diesel 

Generators, Fire Pump Diesels, 125-Volt Vital 

DC Power, 120-Volt Preferred AC Power, and 

Emergency Lighting. Passive electrical 

components for 125-Volt Vital DC Power, 

120-Volt Preferred AC Power, and Emergency 

Lighting are included in the Cables and 

Terminations Commodity Group.

Fire Protection System

(Section 2.3.3.7)

Yes This system includes the Primary Coolant 

Pump oil collection equipment. Fire rated 

assemblies are included in the Miscellaneous 

and Bulk Structural Commodities Group.

Fuel Handling System No System is not in scope for license renewal. 

Selected components are addressed in 

civil/structural commodity groups.

Fuel Oil System 

(Section 2.3.3.8)

Yes

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
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Palisades Nuclear Plant

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Technical and Administrative Information

Heating, Ventilation, and Air 

Conditioning System 

(Section 2.3.3.9)

Yes This system includes Containment Purge; 

Control Room HVAC; Electrical Equipment, 

Switchgear, and Cable Spreading Room 

HVAC; Emergency Diesel Generator Room 

Fans; Engineered Safeguards Room HVAC; 

Fuel Handling Area Ventilation; and 

Penetration and Fan Room HVAC.

Miscellaneous Gas System

(Section 2.3.3.10)

Yes This system includes Hydrogen Monitoring 

and Miscellaneous Gas (e.g., nitrogen).

OSHA Safety Items

No This “system” exists primarily to categorize 

maintenance man-hours spent on improving 

Safety. The only plant equipment within this 

system is emergency showers and eye wash 

stations. The system contains no assets that 

are required to support a 10 CFR 54.4 

intended function.

Post Accident Sampling No The Post Accident Sampling System was 

originally installed as a post-TMI item. The 

requirement for system has subsequently 

been deleted from Technical Specifications 

and alternate methods are used to assess 

post-accident fuel damage. Since all systems 

that interface with Post Accident Sampling 

have their own license renewal boundaries, or 

are not in-scope, there are no system 

functions that meet 10 CFR 54.4 criteria, and 

this system is not in license renewal scope.

Radwaste 

(Section 2.3.3.11)

Yes This system includes Liquid Radwaste and 

Solid Radwaste.

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
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Palisades Nuclear Plant

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Security No The Security System consists of equipment 

used by the security forces to fulfill their 

responsibilities. Major components include 

security cameras, E-Field detectors, fence, 

crash barriers, locked doors and hatches, 

door and hatch alarms, hand scanners, card 

readers, and the access control computer. 

The system contains no assets that are 

required to support a 10 CFR 54.4 intended 

function.

Service Water 

(Section 2.3.3.12)

Yes This system includes Critical Service Water, 

Non-Critical Service Water, and Ultimate Heat 

Sink.

Shield Cooling 

(Section 2.3.3.13)

Yes Evaluated under Closed Cooling Water

Spent Fuel Pool Cooling

(Section 2.3.3.14)

Yes Evaluated under Closed Cooling Water

Waste Gas 

(Section 2.3.3.15)

Yes This system includes Waste Gas and 

Hydrogen Recombiners.

SRP Evaluation Group: Steam and Power Conversion System

Condensate and Condenser

(Section 2.3.4.1)

Yes

Demineralized Makeup Water

(Section 2.3.4.2)

Yes

Feedwater 

(Section 2.3.4.3)

Yes This system includes Auxiliary Feedwater and 

Feedwater.

Heater Extraction and Drain

(Section 2.3.4.4)

Yes Some components are in-scope due to 

criterion a(2)

Main Air Ejection and Gland 

Seal 

(Section 2.3.4.5)

Yes Some components are in-scope due to 

criterion a(2)

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
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Palisades Nuclear Plant

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Main Steam 

(Section 2.3.4.6)

Yes This system includes Main Steam and Steam 

Generator Blowdown.

Turbine Generator 

(Section 2.3.4.7)

Yes This system includes the main turbines, main 

electrical generator and various supporting 

subsystems.

SRP Evaluation Group: Containments, Structures and Component Supports

Auxiliary Building 

(Section 2.4.1)

Yes

Component Supports 

(Section 2.4.2)

Yes Includes supports for mechanical and 

electrical components

Containment 

(Section 2.4.3)

Yes

Containment Interior 

Structures 

(Section 2.4.4)

Yes

Cooling Towers No The Cooling Towers, including the basins, are 

non-safety related structures. The basins are 

concrete structures and the cooling towers 

are primarily made of wood materials. The 

basins are not used as a backup source of 

water for safety functions. 

Cooling Tower Pump House No The Cooling Tower Pump House contains the 

two pumps which circulate the tube side 

condenser cooling water up to the cooling 

tower inlet near the tower top. the The failure 

of the structure would not result in the release 

of radioactivity and would not prevent reactor 

shutdown but may interrupt power generation. 

Discharge Structure 

(Section 2.4.5)

Yes

Feedwater Purity Building

(Section 2.4.6)

Yes

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
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Palisades Nuclear Plant

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Technical and Administrative Information

Intake Structure 

(Section 2.4.7)

Yes

Miscellaneous and Bulk 

Structural Commodities

(Section 2.4.8)

Yes Includes elastomers, fire barriers, cranes, and 

other miscellaneous commodities

Minor Buildings Inside and 

Outside Protected Area

No Includes Construction Building, Construction 

Fabrication shop, Ground Water Remediation 

Building, Building and Grounds Shop Building, 

Dry Fuel Storage Building, Training (Outage) 

Building, Warehouse.

Radwaste Buildings No Consists of five radwaste storage buildings 

separated from the main plant, including 

South Radwaste Storage Building, Radwaste 

Storage Pole Building, North Radwaste 

Storage Building, East Radwaste Storage 

Building, and Old Steam Generator Storage 

Building.

Service, Support and Security 

Buildings

No Consists of four buildings, including Service 

Building, Service Building Expansion, Support 

Building, and Security Building.

Small Electrical, Mechanical, 

Fire Equipment Shelters and 

Storage Buildings

No Consists of various small buildings, sheds, 

and shelters outside the Protected Area 

Switchyard and Yard 

Structures 

(Section 2.4.9)

Yes

Turbine Building 

(Section 2.4.10)

Yes

SRP Evaluation Group: Electrical and Instrumentation and Controls

Cables and Terminations

(Section 2.5.2)

Yes

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
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Technical and Administrative Information

Containment Isolation and 

Penetration System 

(Section 2.5.3)

Yes Electrical system only. No Assets Subject to 

AMR. Containment isolation valves and piping 

are included in their respective mechanical 

systems. Containment structural penetrations 

are included in Containment structure.

Control Rod Drive System

(Section 2.5.4)

Yes Electrical system only. No Assets Subject to 

AMR. Pressure boundary components are 

included with the Reactor Vessel.

Neutron Monitoring 

(Section 2.5.5)

Yes Electrical system only. No assets subject to 

AMR.

Portable Measuring and Test 

Equipment

No “System” contains equipment used for test or 

calibrate activities. This equipment is not 

associated with permanently installed plant 

equipment. 

Radiation Monitoring 

(Section 2.5.6)

Yes Electrical system only. Pressure boundary 

components are included in their respective 

mechanical systems.

Reactor Protection 

(Section 2.5.7)

Yes All components are active. No assets subject 

to AMR.

Station Power

(Section 2.5.8)

Yes

Switchyard 

(Section 2.5.9)

Yes

Table 2.2-1 Plant Level Scoping Results

Description Within Scope of 

License Renewal?

Comments
Page 2-49 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

2.3 Scoping and Screening Results: Mechanical Systems

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

The following systems are addressed in this section:

• Primary Coolant System (Section 2.3.1.1)

• Reactor Vessel (Section 2.3.1.2)

• Reactor Vessel Internals (Section 2.3.1.3)

• Replacement Steam Generators (Section 2.3.1.4)

2.3.1.1 Primary Coolant System 

System Description

The Primary Coolant System (PCS) is designed to remove heat from the 

reactor core and internals and transfer it to the secondary (steam generating) 

system by the controlled circulation of pressurized borated water which serves 

both as a coolant and a neutron moderator. The PCS serves as a barrier to the 

release of radioactive material to the Containment building, and is equipped 

with controls and safety features that assure safe conditions within the system.

The system contains two steam generators to transfer the heat generated in the 

Primary Coolant System to the secondary system. The steam generators are 

vertical U-tube heat exchangers. The steam generators operate with the 

primary coolant in the tube side and the secondary fluid on the shell side.

All mechanical components of the PCS are located within the Containment 

building. The system includes two identical heat transfer loops connected in 

parallel to the reactor vessel. Each loop contains one steam generator, two 

circulating pumps, flow and temperature instrumentation, and connecting 

piping. A pressurizer is connected to one of the reactor vessel outlet pipes by 

means of a surge line. The pressurizer is located with its base at a higher 

elevation than the reactor vessel piping. This eliminates the need for a separate 

drain on the pressurizer and ensures that it is drained before maintenance 

operations. 

System pressure is maintained by regulation of the water temperature in the 

pressurizer where steam and water are held in thermal equilibrium. Steam is 

either formed by the pressurizer heaters or condensed by the pressurizer spray 

to limit the pressure variations caused by contraction or expansion of the 

primary coolant.
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Overpressure protection is provided by spring-loaded safety valves connected 

to the top of the pressurizer. Steam discharged from the valves is cooled and 

condensed by water in a quench tank. 

A subsystem of the PCS is the pressurizer pressure and level control system. 

The Pressurizer Pressure and Level Control is a redundant control system 

designed to maintain pressurizer level and pressure during heatup, cooldown 

and load changes. Level is accomplished by controlling the rate of water added 

to or removed from the PCS. Pressure is controlled by energizing electrical 

heaters or activating steam space spray water to the pressurizer.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Primary Coolant System are non-safety related and their failure could affect the 

capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to ATWS, Environmental 

Qualification, Fire Protection, and Station Blackout in accordance with 10 CFR 

54.4(a)(3).

The boundaries of the in-scope portions of the Primary Coolant System are 

described as follows: 1) The PCS discharge from the reactor vessel safe ends 

to the steam generators, from the steam generators to the primary coolant 

pumps, and return to the safe ends of the reactor vessel inlet; 2) the PCS surge 

line to the pressurizer and through the RVs and PORVs to the quench tank; 3) 

The primary coolant pump seal flow paths; 4) the PCS lubricating oil system 

components (seismic only); and 5) the PCS piping that penetrates Containment 

penetration 40. The PCS also contains non-safety related components spatially 

oriented that could affect safety related components.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

PCS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment

PCS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 
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Technical and Administrative Information

components types include piping, fittings, fasteners (to maintain the pressure 

boundary), and valves. The components are located in the Auxiliary Building 

and Containment.

The portions of the Primary Coolant System containing components subject to 

an AMR include the PCS Class 1 piping, valves, and associated fittings; steam 

generators; pressurizer; and primary coolant pump casings. The NSAS 

components brought into scope by the 10 CFR 54.4(a)(2) boundary expansion 

are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Class 1 portions of the 

Primary Coolant System (including Class 1 piping, steam generators, and 

pressurizer) is provided in the summary below.

System Function: PCS-01 Cri 1 Cri 2 Cri 3

Circulate subcooled water through the reactor core 

to remove core heat and reject it to the secondary 

side via the steam generators.

FP EQ PTS AT SB

X

Comment: The PCS cools the reactor fuel under normal and accident conditions and 

thus maintains the fuel within the specified acceptable design limits and 

transfer heat from the reactor core to the steam generators where steam is 

produced.

System Function: PCS-02 Cri 1 Cri 2 Cri 3

Serve as a fission product boundary between the 

reactor core and the containment environment or 

interfacing systems.

FP EQ PTS AT SB

X

Comment: The PCS serves as a barrier to the release of fission products from the 

reactor core to the environment.

System Function: PCS-03 Cri 1 Cri 2 Cri 3

Automatically isolate the PCS sample lines and 

quench tank spray line containment isolation 

valves on CHP or CHR.

FP EQ PTS AT SB

X

Comment: This system function automatically isolates the Primary Make-up Water to 

the Quench Tank and is associated with the valves and pipe required to 

ensure containment isolation in the PCS system. Components associated 

with the processing of electrical signals to initiate automatic isolation upon 

containment high pressure (CHP) and containment high radiation (CHR) 

are dispositioned under the Containment Isolation and Penetration 

System. The penetrations are dispositioned within the Containment 

structure evaluation.
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System Function: PCS-04 Cri 1 Cri 2 Cri 3

Maintain PCS pump pressure boundary while 

minimizing and recycling (via CVC and RWS) PCS 

leakage.

FP EQ PTS AT SB

Comment: This system function maintains PCS inventory control, but is not a license 

renewal IF. PCS-02 is the applicable license renewal IF.

System Function: PCS-05 Cri 1 Cri 2 Cri 3

Provide for the release or removal of steam or gas 

bubbles in the reactor vessel head or pressurizer.

FP EQ PTS AT SB

X

Comment: This system function is designed to permit the operator to vent the reactor 

vessel head or the pressurizer steam space from the control room under a 

variety of post-accident conditions.

System Function: PCS-06 Cri 1 Cri 2 Cri 3

Provide PCS parameter indications and alarms to 

operators and provide signal inputs to other 

systems.

FP EQ PTS AT SB

X

Comment: This is a normal operation system function. It provides operation 

parameters and signal inputs to various trip and actuation functions.

System Function: PCS-07 Cri 1 Cri 2 Cri 3

Provide high pressure lift oil (with or without AC 

power) to primary coolant pump motors.

FP EQ PTS AT SB

Comment: This is a normal operation system function that protects the PCP and 

maintains the PCS heat removal system function.

System Function: PCS-08 Cri 1 Cri 2 Cri 3

Provide anti-reverse rotation function on primary 

coolant pump motors with backstop oil system on 

Allis Chalmers motors and locking pawls on 

Westinghouse motor.

FP EQ PTS AT SB

Comment: This is a normal operation system function that prevents reverse flow in 

the PCS loops.

System Function: PCS-09 Cri 1 Cri 2 Cri 3

Provide capture and quenching of rejected 

inventory from the pressurizer, SDC system, SITs 

and CVC relief valves and transfers excessive 

inventory to RWS.

FP EQ PTS AT SB

Comment: This system function provides collection of excess coolant, and is not a 

license renewal IF.
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Palisades Nuclear Plant

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Technical and Administrative Information

System Function: PCS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: The PCS system contains components that are required for Anticipated 

Transients Without Scram.

System Function: PCS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The PCS system contains components that are required per 10 CFR 

50.49.

System Function: PCS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The PCS system contains components that are required for “Appendix R” 

safe shutdown. The PCP oil leakage collection subsystem is evaluated for 

license renewal in the Fire Protection System.

System Function: PCS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: PCS has components in scope for Criterion 2, potential seismic and spatial 

interaction.

System Function: PCS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: The PCS system contains components that are required for SBO.

System Function: PZR-01 Cri 1 Cri 2 Cri 3

Provide automatic and manual level control of the 

Primary Coolant System.

FP EQ PTS AT SB

Comment: This system function maintains PCS inventory.

System Function: PZR-02 Cri 1 Cri 2 Cri 3

Provide automatic, manual and passive pressure 

control of the Primary Coolant System.

FP EQ PTS AT SB

Comment: This system function maintains PCS pressure control.
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Palisades Nuclear Plant

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Technical and Administrative Information

FSAR Reference

Additional Primary Coolant System details are provided in Section 4.1 and 

Section 4.3 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Primary Coolant System are listed 

below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.1-1 along with each Component Group’s intended 

function(s). The Reactor Vessel and Reactor Vessel Internals are addressed 

separately and therefore are not identified in Table 2.3.1-1. Only the main loop 

piping, Steam Generators, Pressurizer, PCPs, and interfacing systems’ piping 

are addressed in this table.

System Function: PZR-03 Cri 1 Cri 2 Cri 3

Provide PCS heat removal via the PORVs on once 

through cooling.

FP EQ PTS AT SB

Comment: The PORVs depressurize the PCS and provide a flow path.

System Function: PZR-04 Cri 1 Cri 2 Cri 3

Provide pressurizer level and pressure indications. FP EQ PTS AT SB

X

Comment: This system function provides safety related indication per Reg. Guide 

1.97.

System Function: PZR-05 Cri 1 Cri 2 Cri 3

Provide pressure boundary between primary 

coolant system and containment environment.

FP EQ PTS AT SB

X

Comment: This system function provides a barrier to the release of fission products 

from the PCS to the environment.

LR-M-201, Sheet 1

LR-M-201, Sheet 2

LR-M-202, Sheet 1

LR-M-202, Sheet 1B

LR-M-203, Sheet 1

LR-M-203, Sheet 2

LR-M-204, Sheet 1

LR-M-209, Sheet 1

LR-M-210, Sheet 2

LR-M-214, Sheet 4

LR-M-214, Sheet 5

LR-M-219, Sheet 1B

LR-M-219, Sheet 2

LR-M-212, Sheet 4
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Table 2.3.1-1 Primary Coolant System 

Component Group Intended Function

Alloy 600 Cladding Shelter / Protection

Alloy 600 Safe Ends Fluid Pressure Boundary

Alloy 600 Thermal Sleeves Shelter / Protection

Bolting and Fasteners Fluid Pressure Boundary

Carbon Steel Nozzles Fluid Pressure Boundary

Carbon Steel Pipe (30” and 42”) Fluid Pressure Boundary

Flow Element

(PCP Controlled Bleed)

Fluid Pressure Boundary

Non-CASS Valves in PCS and 

Connected Systems Fluid Pressure Boundary

PCS Spray and Drain Nozzles Fluid Pressure Boundary

PORV Isolation, Quench Tank 

Spray Manual Valves Fluid Pressure Boundary

PORV Isolation Valves Fluid Pressure Boundary

Pressurizer Alloy 600 Instrument 

Penetrations Fluid Pressure Boundary

Pressurizer Heater Sleeves Fluid Pressure Boundary

Pressurizer Heaters Fluid Pressure Boundary

Pressurizer Integral Support Weld Fluid Pressure Boundary

Pressurizer Manway and Flange 

Bolting Fluid Pressure Boundary

Pressurizer Manway and Flanges Fluid Pressure Boundary

Pressurizer Quench Tank Fluid Pressure Boundary
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Pressurizer Quench Tank Shell and 

Heads Fluid Pressure Boundary

Pressurizer Spray Head Spray Pattern

Primary Coolant Pump Casing Fluid Pressure Boundary

Primary Coolant Sample Heat 

Exchanger Shell Fluid Pressure Boundary

Reactor Head Vent Fluid Pressure Boundary

Reactor Head Vent Orifice Fluid Pressure Boundary

Sample Point

(Quench Tank Liquid, Loop 2 Hot 

Leg, Pressurizer Surge Line)

Fluid Pressure Boundary

Small Bore Stainless Steel Pipe

(PCS and Connected Systems)

Fluid Pressure Boundary

SS Cladding Shelter/ Protection

Stainless Steel Pipe

(PCS and Connected Systems)

Fluid Pressure Boundary

Stainless Steel Safe Ends

(Pressurizer and Connected 

Systems)

Fluid Pressure Boundary

Stainless Steel Thermal Sleeves Shelter / Protection

Stainless Steel Tubing Fluid Pressure Boundary

Vessels, Pressure

(Pressurizer)

Fluid Pressure Boundary

Table 2.3.1-1 Primary Coolant System 

Component Group Intended Function
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2.3.1.2 Reactor Vessel

Component Description

The Reactor Vessel (RVG) is the pressure vessel used to contain the core, core 

supports, and nuclear fuel in a Pressurized Water Reactor. The reactor vessel 

is an integral part of the PCS, which provides the means of removing heat from 

the fuel and generating steam in the steam generator. The reactor vessel is 

operated at a pressure high enough to ensure that the bulk primary coolant 

remains in a liquid phase. The reactor vessel and top head are designed in 

accordance with ASME B&PV Code, Section III, Class A, 1965, W65a.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). In addition, some SSCs are 

considered in-scope due to Pressurized Thermal Shock in accordance with 10 

CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Reactor vessel include the 

following: shells and lower head; removable head and closure bolts; control rod 

tube lateral supports; vessel primary coolant nozzles and safe ends; control rod 

drive nozzles, flanges, pressure housings and fasteners; in-core 

instrumentation nozzles, tubes, flanges, and fasteners; head vent line; vessel 

supports (covered in structural area); and attachments (core stabilizer and stop 

lugs, surveillance capsule holder, flow skirt, and lifting lugs).

The portions of the Reactor Vessel containing components subject to an AMR 

include nozzles, o-rings, flow skirt, upper shell, intermediate shell, lower shell, 

safe ends, seal ledge ring, stop lugs, studs, nuts, washers, capsule holders, 

upper shell flange, and Control Rod Drive Mechanism supports.

System Function Listing

A comprehensive listing of functions associated with the Reactor Vessel is 

provided in the summary below.

System Function: RVG-01 Cri 1 Cri 2 Cri 3

Serve as a fission product boundary between the 

reactor core and the containment building.

FP EQ PTS AT SB

X

Comment: This RVG System Function also includes CRD-04, Maintain PCS Pressure 

Boundary, for the CRDM housings and seals, and the Incore Instrument 

Assembly Pressure Boundary. The cladding that protects the carbon steel 

components from the primary borated water is also included in this system 

function.
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FSAR Reference

Additional Reactor Vessel details are provided in Section 3.3 and Section 4.3 of 

the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Reactor Vessel are listed below:

Subcomponents Subject to an Aging Management Review

The subcomponents of the Reactor Vessel that require aging management 

review are addressed in Table 2.3.1-2 along with each subcomponent’s 

intended function(s).

System Function: RVG-02 Cri 1 Cri 2 Cri 3

Provide structural support of the reactor core 

support barrel.

FP EQ PTS AT SB

X

Comment: The core support barrel which is part of the reactor vessel internals, 

carries all the weight of the reactor internals and is suspended from the 

core barrel support ledge. Other supports included in this system function 

are the reactor head, vessel flange, and primary coolant nozzles and safe 

ends for CRDM, control rods, incore instrumentation, core stabilizing and 

stop lugs, under-head tube supports, reactor closure head lifting lugs, and 

surveillance capsule holders.

System Function: RVG-PTS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Pressurized Thermal Shock.

FP EQ PTS AT SB

X

Comment: 10CFR50.61, Pressurized Thermal Shock, provides design requirements 

for RVG fracture toughness and the protection against Pressurized 

Thermal Shock events.

LR-M-201, Sheet 1

Table 2.3.1-2 Reactor Vessel 

Subcomponent Intended Function

CRDM Seal Pressure Housing Pressure Boundary/Fission 

Product Retention

CRDM Upper Pressure Housing & 

Flange

Pressure Boundary/Fission 

Product Retention
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CRDM/Incore Instrument Bolting Pressure Boundary/Fission 

Product Retention

Incore Instrument Closure Flanges Pressure Boundary/Fission 

Product Retention

Internal SS Cladding Pressure Boundary/Fission 

Product Retention

Reactor Vessel Column Support Structure Functional Support

Reactor Vessel Bottom Head Pressure Boundary/Fission 

Product Retention

Reactor Vessel Closure Head

Component Structural Support

Pressure Boundary/Fission 

Product Retention

Reactor Vessel Closure Head 

Lifting Lugs Component Structural Support

Reactor Vessel Core Stabilizer 

Lugs Structure Functional Support

Reactor Vessel CRDM Nozzles

Structure Functional Support

Pressure Boundary/Fission 

Product Retention

Reactor Vessel Flow Skirt Reduce Flow Inequalities

Reactor Vessel Head O-ring 

Leakage Monitoring

Pressure Boundary/Fission 

Product Retention

Reactor Vessel Head Vent Nozzle Pressure Boundary/Fission 

Product Retention

Reactor Vessel Incore Instrument 

Nozzles

Pressure Boundary/Fission 

Product Retention

Reactor Vessel Intermediate Shell Pressure Boundary/Fission 

Product Retention

Table 2.3.1-2 Reactor Vessel 

Subcomponent Intended Function
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2.3.1.3 Reactor Vessel Internals

Component Description

The Reactor Vessel Internals (RVI) support and orient the reactor core fuel 

bundles and control rods, absorb the control rod dynamic loads and transmit 

these and other loads to the reactor vessel flange, provide a passageway for 

the reactor coolant, and support incore instrumentation.

The reactor vessel internals safely perform their functions during all 

steady-state conditions and during normal operating transients. The internals 

Reactor Vessel Lower Shell Pressure Boundary/Fission 

Product Retention

Reactor Vessel Nozzle Safe Ends Pressure Boundary/Fission 

Product Retention

Reactor Vessel Primary Coolant 

Nozzles

Pressure Boundary/Fission 

Product Retention

Structure Functional Support

Reactor Vessel Seal Ledge Ring Pressure Boundary/Fission 

Product Retention

Reactor Vessel Stop Lugs Prevent Core Displacement

Reactor Vessel Studs, Nuts, 

Washers

Pressure Boundary/Fission 

Product Retention

Reactor Vessel Surv. Capsule 

Holder Structure Functional Support

Reactor Vessel Upper Shell Pressure Boundary/Fission 

Product Retention

Reactor Vessel Upper Shell Flange Pressure Boundary/Fission 

Product Retention

Under Head CRDM Support Structure Functional Support

Table 2.3.1-2 Reactor Vessel 

Subcomponent Intended Function
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safely withstand the forces due to deadweight, handling, system pressure, flow 

impingement, temperature differential, shock and vibration. All reactor 

components are considered Class 1 for seismic design.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). 

The boundaries of the in-scope portions of the Reactor Internals include the 

following: core support barrel (including the lower core support structure and 

core shroud); the upper guide structure (including the control rod shrouds, and 

the incore instrumentation guide tubes); and the flow skirt (flow skirt is 

addressed as part of the reactor vessel).

The portions of the Reactor Vessel Internals containing components subject to 

an AMR include control rod shroud assemblies, core shroud assembly, core 

support barrel assembly, incore instrument guide tubes, lower internals 

assembly, and upper guide structure.

System Function Listing

A comprehensive listing of functions associated with the Reactor Vessel 

Internals is provided in the summary below.

System Function: RVI-01 Cri 1 Cri 2 Cri 3

Provide a nuclear chain reaction to generate heat 

for power production.

FP EQ PTS AT SB

Comment: The reactor core, together with its control systems and the reactor 

protection system, is designed to function over it lifetime without 

exceeding fuel damage limits of excessive fuel temperature, cladding 

strain and cladding stress during normal operating conditions and 

anticipated transients. The fuel bundles are designed to maintain their 

structural integrity under steady-state and transient operating conditions, 

as well as for normal handling, shipping and refueling loads.

Providing a nuclear chain reaction to generate heat for power production is 

a normal operating system function that is not in boundary of License 

Renewal.
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System Function: RVI-02 Cri 1 Cri 2 Cri 3

Provide controlled distribution of PCS flow through 

the core while limiting the amount of core bypass 

flow.

FP EQ PTS AT SB

X

Comment: The flow skirt is used to reduce inequalities in core inlet flow distributions 

and to prevent formation of large vortices in the lower plenum. The skirt 

provides a nearly equalized pressure distribution across the bottom of the 

core support barrel. The core shroud follows the perimeter of the core and 

limits the coolant bypass flow. The core barrel directs the reactor coolant 

flow to the core and after leaving the core directs the flow to the outlet 

nozzles.

System Function: RVI-03 Cri 1 Cri 2 Cri 3

Provide alignment of the fuel bundles and control 

rods, structural support of the core, in-core nuclear 

instrumentation and other internals; and prevent lift 

out of the fuel bundles during accident conditions.

FP EQ PTS AT SB

X

Comment: The Upper Guide Structure Assembly consists of a flanged grid structure, 

45 control rod shrouds, a fuel bundle alignment plate and a ring shim. The 

upper guide structure aligns and supports the upper end of the fuel 

bundles, maintains the control rod channel spacing, prevents fuel bundles 

from being lifted out of position during a severe accident condition and 

protects the control rods from the effect of coolant cross flow in the upper 

plenum. It also supports the incore instrumentation guide tubing. The 

upper guide structure is handled as one unit during installation and 

refueling.

System Function: RVI-04 Cri 1 Cri 2 Cri 3

Provide a fission product boundary via fuel 

cladding.

FP EQ PTS AT SB

X

Comment: Fuel rods are clad with Zircaloy-4 tubing and sealed by welding end caps 

to each end. The atmosphere within the rods is pressurized helium. This 

pressure will assure that the fuel rod cladding will be free-standing under 

all anticipated reactor operating conditions.

System Function: RVI-05 Cri 1 Cri 2 Cri 3

Provide neutrons to ensure neutron monitors can 

monitor for criticality at low power levels.

FP EQ PTS AT SB

Comment: This function is associated with neutron sources. Performance criteria is 

startup visibility of neutron population, which is a normal operation system 

function and is not in boundary of License Renewal.

System Function: RVI-06 Cri 1 Cri 2 Cri 3

Provide Reactor Vessel Level Monitoring 

(RVLMS).

FP EQ PTS AT SB

Comment: The components in boundary of License Renewal that monitor PCS 

inventory are being evaluated in Primary Coolant System (function 

PCS-06).
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FSAR Reference

Additional Reactor Vessel Internals details are provided in Section 3.2, Section 

3.3, Figure 3-1, Figure 3-10, Figure 3-11 and Figure 3-12 of the FSAR.

Scoping Boundary Drawings

The boundaries of Reactor Vessel Internals components in scope of license 

renewal are shown in FSAR Figure 3-1, Figure 3-10, Figure 3-11, and Figure 

3-12.

Subcomponents Subject to an Aging Management Review

The subcomponents of the Reactor Vessel Internals that require aging 

management review are addressed in Table 2.3.1-3 along with each 

subcomponent’s intended function(s).

Table 2.3.1-3 Reactor Vessel Internals

Subcomponent Intended Function

IV.B3.2 - CEA Shroud Assemblies:

Control Rod Shroud, Shroud 

Support Lug, Fuel Guide Pin, Fuel 

Guide Pin Nuts, Shroud Top 

Support, Control Rod Support Lug, 

Fuel Plate Cap Screw

Structure Functional Support

IV.B3.4 - Core Shroud Assembly:

Anchor Block, Centering Plate, 

Core Shroud Plate, Anchor Screw 

& Pin, Centering Screw & Pin, 

Positioning Screw, Shroud Bolt & 

Pin, 

Structure Functional Support

IV.B3.3 - Core Support Barrel 

Assembly

Core Support Barrel, Core Support 

Barrel Integral Upper Flange

Structure Functional Support
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2.3.1.4 Replacement Steam Generators

Component Description

The two (2) replacement steam generators are of the vertical pressurized water 

type wherein the heating surface and steam separation equipment are in the 

same vessel. The steam generators have been designed and fabricated as 

Class 1 vessels as defined in ASME Boiler and Pressure Vessel Code, Section 

Incore Instrument Guide Tube (Not 

Addressed in GALL IV.B3)

Instrument Guide Tube, Guide 

Tube Bracket, Guide Tube Plugs, 

Guide Tube Plug Screw, Guide 

Tube Support

Structure Functional Support

IV.B3.5 - Lower Internal Assembly

Core Support Plate, Core Support 

Column, Core Support Barrel 

Snubber Lug, Core Support Barrel 

Cap Screws, Fuel Alignment Pins, 

Core Support Column Support 

Beams and Tie Rods

Structure Functional Support

Upper Guide Structure - Not in 

GALL

Spacer Shim, Instrument Sleeve

Structure Functional Support

IV.B3.1 - Upper Internal Assembly

Fuel Alignment Plate, Fuel Plate 

Align Lug, Fuel Plate Cap Screw, 

Fuel Plate Guide Pin, Holddown 

Ring Plunger, Holddown Ring 

Strap, Holddown Ring, Brace Grid 

Beam, Cross Brace Screw, Shroud 

Grid Ring

Structure Functional Support

Table 2.3.1-3 Reactor Vessel Internals

Subcomponent Intended Function
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III, 1977 Edition. Materials of construction are as specified in ASME Code, 

Section III.

Each steam generator is a vertical U-tube heat exchanger which operates with 

the primary coolant on the tube side and secondary coolant on the shell side. A 

vertical divider plate separates the inlet and outlet plenums of the primary head. 

Secondary system feedwater enters the steam generator through the feed ring, 

mixes with the recirculating water from the moisture separators, and flows down 

the annulus between the tube bundle wrapper plate and the steam generator 

shell. Here it turns, flows inward around the base of the tube bundle and then 

upward around the tubes. As it flows up past the tubes, it is heated to saturation 

temperature and boils. The wet steam passes through sets of moisture 

separators and steam driers in the upper portion of the steam generator and 

leaves as dry steam through the outlet flow restricting nozzle at the top. 

Manways and handholes are provided for access to the steam generator 

internals for inspection or repairs.

The primary side steam generator boundaries are: the lower hemispherical 

head of the vessel, the tubesheet, and the 8,219 tubes. The primary head 

divider plates divide the head into two (2) separate plenums. Reactor coolant 

enters the inlet plenum through one (1) inlet nozzle, flows through the U-tubes 

to the outlet plenum, and exits through two (2) outlet nozzles.

The secondary side steam generator boundaries are: the lower shell, conical 

transition section, upper shell, top head, outside the tubes, and the secondary 

side of the tubesheet. Connections are provided in the shells and head for 

feedwater, steam outlet, emergency feedwater, pressure tap, bottom blowdown, 

sampling, recirculation, and water level instrumentation connections. Nozzle 

safe-ends are provided on the emergency feedwater and feedwater nozzles. 

Thermal sleeves are provided in the feedwater nozzles and the recirculating 

nozzle. The upper shell is provided with two (2) 18-inch nominal I.D. gasketed 

manways. The manway cover seats externally and is held in place by sixteen 

(16) studs and nuts. The lower shell is provided with four (4) 6-inch nominal I.D. 

gasketed handholes for inspection of the tube bundle. The handhole cover 

seats externally and is held in place by ten (10) studs and nuts.
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System Function Listing

A comprehensive listing of functions associated with the Replacement Steam 

Generators is provided in the summary below.

System Function: RSG-01 Cri 1 Cri 2 Cri 3

Provide a Primary Coolant System pressure 

boundary

FP EQ PTS AT SB

X

Comment: Components within the Class 1 Piping/Components System perform this 

primary design system function by containing the coolant for heat transfer 

and serving as a closed pressure boundary that limits leakage to the 

Containment Building Structure and interconnecting systems.The 

replacement steam generators serve as a fission product boundary 

between the reactor core and the containment environment and 

interfacing systems.

System Function: RSG-02 Cri 1 Cri 2 Cri 3

Provide a Main Steam System and Feedwater 

System pressure boundary

FP EQ PTS AT SB

X

Comment: The replacement steam generators serve as a fission product boundary 

between the reactor core and the containment environment and 

interfacing systems.

System Function: RSG-03 Cri 1 Cri 2 Cri 3

Transfer heat from the PCS to the secondary 

systems

FP EQ PTS AT SB

X

Comment: Heat is transferred from the reactor core to the steam generators where 

steam is produced.

System Function: RSG-04 Cri 1 Cri 2 Cri 3

Provide a closed system in-side containment 

pressure boundary, or fission product retention 

barrier to protect public health and safety in the 

event of a postulated accident

FP EQ PTS AT SB

X

Comment: The RSG serves as a barrier to the release of fission products from the 

reactor core to the environment.

System Function: RSG-05 Cri 1 Cri 2 Cri 3

Provide a throttling function to limit steam flow in 

the event of a postulated steam line break

FP EQ PTS AT SB

X

Comment: Steam outlet nozzles incorporate an integral flow restriction feature which 

will serve to limit the steam generator blowdown during a main steam line 

break accident.

Closure of MSIVs isolates the affected steam generator from the intact 

steam generator and minimizes radiological releases.
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FSAR Reference

Additional Replacement Steam Generators details are provided in Section 4.3 

and Section 4.4 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Replacement Steam Generators are 

listed below:

Subcomponents Subject to an Aging Management Review

The subcomponents of the Replacement Steam Generators that require aging 

management review are addressed in Table 2.3.1-4 along with each 

subcomponent’s intended function(s).

LR-M-201, Sheet 1 LR-M-207, Sheet 2

LR-M-207, Sheet 1 LR-M-218, Sheet 2

Table 2.3.1-4 Replacement Steam Generators

Subcomponent Intended Function

Alloy 690 Tube Plugs Fluid Pressure Boundary

Handhole Cover Fluid Pressure Boundary

Tube Bundle Support Assembly Structural Support for Safety 

Related

Tube Bundle Wrapper Direct Flow

Lower Head Fluid Pressure Boundary

Primary Manway Cover Fluid Pressure Boundary

Manway Cover Diaphragm Fluid Pressure Boundary

Nozzle Safe Ends Fluid Pressure Boundary

Primary Divider Plate Fluid Pressure Boundary

Primary Inlet and Outlet Nozzles Fluid Pressure Boundary

Feedwater Inlet Nozzles and 

Thermal Sleeves Fluid Pressure Boundary
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Steam Outlet Nozzle and Flow 

Limiter, Blowdown Nozzle Fluid Pressure Boundary

Secondary Side Inspection Port 

Cover Fluid Pressure Boundary

Wide and Narrow Range Water 

Level Nozzles, Sampling and 

Instrument Nozzles

Fluid Pressure Boundary

Shells (Lower, Upper, Transition) Fluid Pressure Boundary

Tubesheet Fluid Pressure Boundary

Upper Head Fluid Pressure Boundary

U-Tubes

Fluid Pressure Boundary’

Heat Transfer

Fasteners Fluid Pressure Boundary

Table 2.3.1-4 Replacement Steam Generators

Subcomponent Intended Function
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2.3.2 Engineered Safety Features

The following systems are addressed in this section:

• Engineered Safeguards System (Section 2.3.2.1)

2.3.2.1 Engineered Safeguards System

System Description

The Engineered Safeguards System (ESS) is a two train independent and 

diverse system designed to identify inadequate core cooling, and then start the 

necessary pumps and open the needed valves to establish adequate core 

cooling conditions. The system is subdivided functionally into seven mechanical 

subsystems: 1) High Pressure Safety Injection (HPSI), 2) Low Pressure Safety 

Injection (LPSI), 3) Containment Spray (CSS), 4) Safety Injection Tanks (SIT), 

5) Safety Injection and Refueling Water (SIRW) Tank and Containment Sump 

Suction, 6) Shutdown Cooling (SDC), 7) Reactor Cavity Flood (RCF), and two 

electrical subsystems: 1) Engineered Safety Features (ESF) Actuation, and 2) 

Normal shutdown (NSD) and Design Basis Accident (DBA) Sequencers. 

Except for Reactor Cavity Flood, the mechanical subsystems use most of the 

same system components for the various subsystem functions, and those 

components are hydraulically interconnected. Therefore, ESS is most 

accurately presented as a single system, and the groups of components that 

provide each major function are characterized as subsystems for license 

renewal purposes.

The ESF Actuation subsystem (electrical) consists of two independent and 

isolated circuits that initiate operation of redundant engineered safeguards 

equipment. These control circuits monitor whether offsite and/or emergency 

power is available and select load groups in accordance with the available 

power supply. The sensors are arranged in a two out of four matrix, which, in 

turn, actuates two safety injection control circuits. Within each control circuit, 

relays are provided to initiate redundant devices so that individual relay failure 

will not cause a complete circuit failure. Each circuit is supplied by a separate 

AC source.

The Normal Shutdown and Design Basis Accident Sequencer (electrical) is 

designed to sequentially load the safe shutdown equipment on to the 

emergency buses and diesel generators. Sequencing of loads ensures that the 

equipment is energized when needed while preventing excessive step loads 

from being imposed on the diesel generator which could result in loss of the 

diesel generator. This subsystem is evaluated as part of the electrical 

Containment Isolation System and is listed here only for completeness.
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The High Pressure Safety Injection subsystem is designed to supply high 

pressure cooling water to the Primary Coolant System (PCS) under accident 

conditions. The major components of this system are two High Pressure Safety 

Injection pumps and eight high-pressure injection valves.

The Low Pressure Safety Injection subsystem is designed to supply low 

pressure cooling water to the PCS under accident conditions. The major 

components of this system are two Low Pressure Safety Injection pumps, four 

Safety Injection Tanks, the Safety Injection and Refueling Water (SIRW) Tank, 

and multiple control valves.

The Containment Spray subsystem is designed to limit post-accident 

containment pressure and remove heat from the containment atmosphere 

under accident conditions. The major components of this system are three 

Containment Spray pumps, two sets of full capacity (100%) spray headers and 

nozzles, and two full capacity (100%) pump suction lines from both the SIRW 

Tank and the containment sump.

The four Safety Injection Tanks are designed to flood the core with borated 

water following a depressurization of the PCS.

The SIRW And Containment Sump Suction subsystem delivers water to the 

Engineered Safeguards System pumps through one of four paths. It provides 

the suction source for High Pressure Injection, Low Pressure Injection, 

Containment Spray subsystems, and Chemical and Volume Control System.

The Shutdown Cooling subsystem is designed to transfer heat from the PCS to 

the Component Cooling System after reactor shutdown and after an accident, 

and to maintain a suitable temperature for refueling and maintenance during 

plant shutdowns.

The Reactor Cavity Flood subsystem consists of a network of floor drain piping 

designed to 1) collect normal expected floor drains and transport these drains 

to the containment sump for subsequent disposal outside the containment, and 

2) collect a portion of the containment spray water during accident conditions 

and transport this water into the cavity (annulus) between the biological shield 

and reactor vessel for flooding and cooling the outside of the reactor vessel 

bottom head. Neither function is safety related or credited in the FSAR accident 

analyses.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Engineering Safeguards System are non-safety related and their failure could 

affect the capability of safety related SSCs to perform their safety function, they 

are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In 
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addition, some SSCs are considered in-scope due to Environmental 

Qualification and Fire Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Engineering Safeguards System 

are described as follows: 1) the piping and valves from the SIRW Tank through 

the SIRW Tank Recirculation pump, the SIRW heat exchanger (tube side only) 

and return to the SIRW, 2) the piping from the SIRW to manual valve 

MV-ES3263, 3) the piping, valves and components from the SIRW Tank 

through Containment Spray pumps, the LPSI pumps, the HPSI pumps, through 

the shutdown heat exchangers, and to the LPSI flow path to the PCS loop 

nozzles, the Containment spray headers, and the recirculation/spray 

recirculation headers back to the SIRW Tank, 4) the piping, valves and 

components from the safety injection tanks, including the tanks to the LPSI 

injection headers, 5) the nitrogen supply piping, valves and components from 

the SIRW Tank to the Containment sump, 6) the piping, valves and components 

from the Containment sump to the ESS pumps, 7) the piping and valves from 

the ESS pumps and SIRW Tank to the process sampling system, 8) the Spent 

Fuel Pool cooling pumps recirculation piping located downstream of 

MV-SFP126 to the SIRW and 10) the Reactor Cavity Flood filter Canisters.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

ESS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building.

ESS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include fasteners (to maintain the pressure boundary), 

piping, fittings and valves. The components are located in the Auxiliary 

Building.

The portions of the Engineered Safeguards System containing components 

subject to an AMR include accumulators, heat exchangers, fasteners, baskets, 

pipe and fittings, pumps, and valves. The NSAS components brought into 

scope by the 10 CFR 54.4(a)(2) boundary expansion are subject to AMR.
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System Function Listing

A comprehensive listing of functions associated with the Engineered 

Safeguards System is provided in the summary below.

System Function: CSS-01 Cri 1 Cri 2 Cri 3

Limit post-accident containment pressure by 

spray-cooling the containment atmosphere 

following a LOCA or MSLB.

FP EQ PTS AT SB

X

Comment: Credit is taken for containment spray in the LOCA and MSLB accident 

analyses.

System Function: CSS-02 Cri 1 Cri 2 Cri 3

Provide cooled suction water supply to the HPSI 

pumps following a Recirculation Actuation Signal.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.

System Function: CSS-03 Cri 1 Cri 2 Cri 3

Isolate the containment spray system containment 

isolation valves to ensure containment integrity.

FP EQ PTS AT SB

X

Comment: Containment spray containment isolation valves are closed during normal 

plant operation and are automatically opened on containment high 

pressure (CHP). The isolation maintains containment integrity during 

normal plant operation.

This function is associated with containment spray valves and piping 

required to ensure containment isolation. Components associated with the 

processing of electrical signals to initiate automatic isolation upon CHP 

and Containment high radiation (CHR) are included in the Containment 

Isolation System (electrical). The Containment penetrations are included 

in the Containment Structure evaluation.

System Function: CSS-04 Cri 1 Cri 2 Cri 3

Provide an alternate source of shutdown cooling. FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. This function provides the 

operator with the flexibility of using the containment spray pumps instead 

of the LPSI pumps for shutdown cooling, if desired. For this function to be 

required, multiple equipment failures would have to occur, which is beyond 

the required single active failure coincident with a loss of offsite power. 

System Function: ESF-01 Cri 1 Cri 2 Cri 3

Initiate SIS on pressurizer low-low pressure or 

CHP and automatically initiate the necessary 

engineered safeguards equipment with or without 

offsite power available.

FP EQ PTS AT SB

X

Comment: Credit is taken for ESF actuation in the LOCA accident analyses.
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System Function: ESF-02 Cri 1 Cri 2 Cri 3

Allow blocking of Safety Injection during normal 

shutdown conditions to prevent spurious actuation.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. Blocking of Safety Injection 

occurs during normal plant shutdowns. It is not a post-accident function.

System Function: ESF-03 Cri 1 Cri 2 Cri 3

Initiate CHP signal on high containment pressure 

which will automatically initiate Containment spray, 

Containment isolation, Safety Injection, Main 

Steam Isolation, and Control Room HVAC 

emergency mode.

FP EQ PTS AT SB

X

Comment: Credit is taken for ESF actuation in the LOCA accident analyses.

System Function: ESF-04 Cri 1 Cri 2 Cri 3

Initiate CHR on containment area alarms or 

refueling monitor alarm which will automatically 

initiate Containment isolation, prevent auto start of 

ESS rooms sump pumps, and initiate Control 

Room HVAC emergency mode.

FP EQ PTS AT SB

X

Comment: These actions mitigate the consequences of the accident.

System Function: ESF-05 Cri 1 Cri 2 Cri 3

Initiate Recirculation Actuation Signal (RAS) on 

low SIRW tank level which automatically transfers 

suction of HPSI and containment spray pumps 

from SIRW tank to containment sump, stops LPSI 

pumps and provides Component Cooling and 

maximum Service Water to SDC Heat Exchanger.

FP EQ PTS AT SB

X

Comment: Credit is taken for RAS in the LOCA accident analyses.

System Function: ESF-06 Cri 1 Cri 2 Cri 3

Initiate a low steam generator pressure signal with 

initiation logic to initiate Main Steam Isolation 

Signal (MSIS).

FP EQ PTS AT SB

X

Comment: Credited in main steam line break (MSLB) accident analyses. MSIS will 

isolate the steam generators in the event of a steam generator tube failure 

following a MSLB. It will also prevent release to the containment of the 

contents of the secondary sides of both steam generators in the event of a 

MSLB inside containment.

System Function: ESS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The ESS system contains components that are required per 10 CFR 50.49
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System Function: ESS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The ESS system contains components that are required for “Appendix R” 

safe shutdown.

System Function: ESS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

spray and flooding.

System Function: HPI-01 Cri 1 Cri 2 Cri 3

Automatically provide borated water at high 

pressure to the PCS following a Safety Injection 

actuation.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.

System Function: HPI-02 Cri 1 Cri 2 Cri 3

Isolate the HPSI system to containment to ensure 

containment integrity.

FP EQ PTS AT SB

X

Comment: HPI containment isolation valves are closed during normal plant operation 

and are automatically opened on Safety Injection actuation. The isolation 

maintains reactor coolant pressure boundary integrity as well as 

containment integrity during normal plant operation.

This function is associated with high pressure safety injection valves and 

piping required to ensure containment isolation. Components associated 

with the processing of electrical signals to initiate automatic isolation upon 

CHP and CHR are included in the electrical Containment Isolation System. 

The penetrations are included in the Containment Structure evaluation.

System Function: HPI-03 Cri 1 Cri 2 Cri 3

Provide simultaneous hot and cold leg injection to 

the PCS following a LOCA to ensure core flushing 

flow is maintained and excessive boron 

precipitation and core flow blockage is prevented.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.
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System Function: HPI-04 Cri 1 Cri 2 Cri 3

Provide an alternate borated water flow path 

during shutdown conditions.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. The function provides for the use 

of HPSI pumps as emergency makeup for shutdown cooling if both LPSI 

and CSS pumps are unavailable. For this to occur, multiple equipment 

failures would have to occur, which is beyond the required single active 

failure coincident with a loss of offsite power. It is noted that the HPSI 

system is normally made inoperable during shutdown conditions due to 

Low Temperature Overpressure Protection concerns.

System Function: LPI-01 Cri 1 Cri 2 Cri 3

Automatically provide large volumes of borated 

water at low pressures to the PCS following a 

Safety Injection actuation.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.

System Function: SDC-01 Cri 1 Cri 2 Cri 3

Provide core decay heat removal and circulation of 

the PCS during cooldown and shutdown 

conditions, and provide heat removal capability 

during the recirculation mode of a LOCA, via heat 

rejection to Component Cooling.

FP EQ PTS AT SB

X

Comment: This function applies to the use of the SDC Heat Exchangers with ESF 

pumps. The SDC Heat Exchangers are used during plant shutdowns in 

conjunction with the LPSI pumps, piping and valves to remove core decay 

heat. For the design basis LOCA, the SDC Heat Exchangers are used in 

conjunction with the containment spray pumps, piping and valves to 

remove heat during the recirculation phase of the accident.

System Function: SDC-02 Cri 1 Cri 2 Cri 3

Provide two independent means of reactor vessel 

level and temperature indication while in mid loop 

operation.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. It applies to normal plant 

shutdowns (PCS level lowered to mid-loops). It is not a post-accident 

function.

System Function: SDC-03 Cri 1 Cri 2 Cri 3

Provide alternate cooling to the spent fuel pool. FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. It provides operators with the 

flexibility of using the SDC Heat Exchangers to cool the Spent Fuel Pool, if 

required.
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System Function: SDC-04 Cri 1 Cri 2 Cri 3

Isolate the shutdown cooling system lines from 

containment to ensure containment isolation.

FP EQ PTS AT SB

X

Comment: SDC/LPSI containment isolation valves are normally closed during normal 

plant operation and are automatically opened on Safety Injection 

actuation, or manually opened during plant shutdowns. The isolation 

maintains reactor coolant pressure boundary integrity as well as 

containment integrity.

This function is associated with SDC/LPSI valves and piping required to 

ensure containment isolation. Components associated with the processing 

of electrical signals to initiate automatic isolation upon CHP and CHR are 

included in the electrical CIS System. The penetrations are included in the 

Containment Structure evaluation.

System Function: SIT-01 Cri 1 Cri 2 Cri 3

Passively discharge borated water into the PCS at 

low pressures during accident conditions.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.

System Function: SIT-02 Cri 1 Cri 2 Cri 3

Isolate the safety injection tank drain lines from 

containment to ensure containment isolation.

FP EQ PTS AT SB

X

Comment: SIT drain line containment isolation valves are locked closed during 

normal plant operation. Isolation maintains containment integrity during 

normal plant operation. 

This function is associated with safety injection tank valves and piping 

required to ensure containment isolation. Components associated with the 

processing of electrical signals to initiate automatic isolation upon CHP 

and CHR are included in the electrical CIS System. The penetrations are 

included in the Containment Structure.

System Function: SIT-03 Cri 1 Cri 2 Cri 3

Isolate or vent the safety injection tanks to prevent 

nitrogen cover gas from being discharged into the 

PCS.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. The SIT MOVs are closed during 

normal plant shutdowns. During normal operation, the SIT MOVs are open 

and power is removed from motor operators to prevent inadvertent 

closure. SIT vent lines are normally isolated. SIT level alarms will alert the 

operator to fill the tank with borated water if water level drops. This is not a 

post-accident function.
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System Function: SSS-01 Cri 1 Cri 2 Cri 3

Maintain suction source of water to all engineered 

safeguards pumps via the SIRW tank or the 

containment sump.

FP EQ PTS AT SB

X

Comment: Credited in accident analyses as part of emergency core cooling.

System Function: SSS-02 Cri 1 Cri 2 Cri 3

Control pH in the containment sump to retain 

iodine in solution via passive addition of trisodium 

phosphate.

FP EQ PTS AT SB

X

Comment: This is a safety related function. The trisodium phosphate (TSP) baskets in 

containment are credited in the accident analysis. The LOCA radiological 

consequences analysis takes credit for iodine retention in the sump 

solution.

System Function: SSS-03 Cri 1 Cri 2 Cri 3

Provide SIRW tank water to the suction of the 

charging pumps.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. The charging pumps are used to 

test certain HPSI valves during cold shutdown.

System Function: SSS-04 Cri 1 Cri 2 Cri 3

Maintain minimum water temperature in SIRW 

tank.

FP EQ PTS AT SB

Comment: The lower limit of 40 degrees F on SIRW tank water temperature is 

assumed in the accident analysis and temperatures below this limit could 

have an adverse effect on the accident analysis. During normal operation, 

the SIRW tank temperature is maintained, per Technical specification 

3.5.4, greater than 40 degrees F.

The tank is equipped with a heating steam heat exchanger and pump to 

maintain water temperature above this limit during normal operation. Since 

the heating steam is not needed to mitigate a DBE, only the tube side of 

the SIRW tank heat exchanger is in boundary of license renewal. 

Therefore, this system function is not in boundary of license renewal. 

System Function: RCF-01 Cri 1 Cri 2 Cri 3

Collect a portion of containment spray water and 

transport the water into the cavity between the 

biological shield and reactor vessel for flooding 

and cooling the outside of the reactor vessel 

bottom head following an accident

FP EQ PTS AT SB

Comment: RCF benefits post-LOCA recovery but is not credited in accident analyses. 

This function is not in scope of license renewal because it does not meet 

any of the three criteria. The RCF subsystem is not safety-related per 

FSAR 6.8. Failure of RCF components would not prevent the satisfactory 

accomplishment of Criterion 1 functions.
Page 2-78 

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FSAR Reference

Additional Engineering Safeguards System details are provided in Section 6.1, 

Section 6.2, Section 6.4, Section 6.8, Section 7.3, Section 8.4, Section 10.2, 

Section 14.14, Section 14.17, Section14.18, and Section 14.22, of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Engineering Safeguards System are 

listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.2-1 along with each Component Group’s intended 

function(s). 

System Function: RCF-02 Cri 1 Cri 2 Cri 3

Collect normal expected floor drainage and 

transport this drainage to the containment sump 

for disposal outside the containment.

FP EQ PTS AT SB

Comment: This function is not in-scope of license renewal because it does not meet 

any of the three license renewal Criteria. The RCF subsystem is 

non-safety-related per FSAR 6.8. Failure of RCF components would not 

prevent the satisfactory accomplishment of Criterion 1 functions.

System Function: RCF-03 Cri 1 Cri 2 Cri 3

The RCF system contains components that are 

safety related for seismic considerations.

FP EQ PTS AT SB

X

Comment:

System Function: RCF-NSAS Cri 1 Cri 2 Cri 3

Filter canisters prevent core debris from entering 

the sump and ESF system.

FP EQ PTS AT SB

Comment: This function is not in scope of license renewal because the filter canisters 

slow the release of core debris to the Containment sump after a core 

meltdown. This is not a safety function.

LR-M-201, Sheet 1

LR-M-203, Sheet 1

LR-M-203, Sheet 2

LR-M-204, Sheet 1

LR-M-204, Sheet 1A

LR-M-204, Sheet 1B

LR-M-209 Sheet 1

LR-M-209 Sheet 2

LR-M-212 Sheet 4

LR-M-218 Sheet 2

LR-M-219, Sheet 1B

LR-M-221, Sheet 2

LR-M-225 Sheet 1

LR-M-225 Sheet 1A
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Table 2.3.2-1 Engineered Safeguards System

Component Group Intended Function

SIRW Tank Fluid Pressure Boundary

Safety Injection Tank Fluid Pressure Boundary

SDC HX Shell Fluid Pressure Boundary

SIRWT HX Shell Fluid Pressure Boundary

SDC, SIRWT HX Shell Fluid Pressure Boundary

SIRWT HX Shell Fluid Pressure Boundary

SDC HX Shell Fluid Pressure Boundary

SDC HX Channel Head Fluid Pressure Boundary

SDC HX Tube Sheet shell side Fluid Pressure Boundary

SDC HX Channel Head shell side Fluid Pressure Boundary

Cont. Spray Pump HX shell, LPSI 

Pump HX shell Fluid Pressure Boundary

SIRWT HX Tubes Fluid Pressure Boundary

Cont. Spray, LPSI Pump coils Fluid Pressure Boundary

PCP Seal Cooler Coils, Cont. 

Spray Pump coils, LPSI pump 

Coils, SDC HX Tubes

Fluid Pressure Boundary

Heat Transfer

SDC HX Tubes

Fluid Pressure Boundary

Heat Transfer

PCP Seal Cooler Coils, SIRWT HX 

Tubes

Fluid Pressure Boundary

Heat Transfer

PCP Seal Cooler Coils Fluid Pressure Boundary
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SIRWT HX Tubes

Fluid Pressure Boundary

Heat Transfer

Cont. Spray Pump Coils, SDC HX 

Tubes

Fluid Pressure Boundary

Heat Transfer

SIRWT HX Tubes, Cont. Spray 

Pump coils, LPSI Pump coils, SDC 

HX Tubes

Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Containment Spray System 

Fasteners Fluid Pressure Boundary

Containment Spray Pump Bolting Fluid Pressure Boundary

Containment Spray System Valves 

Bolting Fluid Pressure Boundary

Containment Spray System Valves 

Header Bolting Fluid Pressure Boundary

HPSI, LPSI Pumps Bolting Fluid Pressure Boundary

SIRWT HX Bolting Fluid Pressure Boundary

SIRWT Bolting Fluid Pressure Boundary

HPSI Check Valves, SCDC from 

PCS MOVs Fluid Pressure Boundary

HPSI Check Valves Fluid Pressure Boundary

Hot Leg Injection Check Valves Fluid Pressure Boundary

HPSI Check Valves Loops 1A, 2A Fluid Pressure Boundary

Table 2.3.2-1 Engineered Safeguards System

Component Group Intended Function
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2.3.3 Auxiliary Systems

The following systems are addressed in this section:

• Chemical Addition System (Section 2.3.3.17)

• Chemical Volume and Control System (Section 2.3.3.1)

• Circulating Water System (Section 2.3.3.2)

• Component Cooling Water System (Section 2.3.3.3)

• Compressed Air System (Section 2.3.3.4)

• Containment Air Recirculation and Cooling System (Section 2.3.3.5)

• Domestic Water System (Section 2.3.3.16)

• Emergency Power System (Section 2.3.3.6)

• Fire Protection System (Section 2.3.3.7)

• Fuel Oil System (Section 2.3.3.8)

• Heating, Ventilation, and Air Conditioning System (Section 2.3.3.9)

• Miscellaneous Gas System (Section 2.3.3.10)

• Radwaste System (Section 2.3.3.11)

• Service Water System (Section 2.3.3.12)

• Shield Cooling System (Section 2.3.3.13)

• Spent Fuel Pool Cooling System (Section 2.3.3.14)

• Waste Gas System (Section 2.3.3.15)

2.3.3.1 Chemical and Volume Control System

System Description

The Chemical and Volume Control (CVC) System design basis is to: maintain 

the required volume of water in the Primary Coolant System (PCS) over the 

range of full to zero reactor power, maintain the chemistry and purity of the 

primary coolant, maintain the desired boric acid concentration in the PCS, and 

pressure test the PCS.

Letdown coolant from the cold leg of the PCS passes through the tube side of 

the regenerative heat exchanger and is partially cooled. The cooled fluid is then 

partially depressurized as it passes through the letdown stop valves and 

orifices. The temperature and pressure of the letdown coolant are finally 

reduced to the operating requirements of the purification system by the letdown 

heat exchanger and back pressure valve, respectively. The coolant then passes 
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through an ion exchanger and a filter and is sprayed into the volume control 

tank and pumped back to the PCS by way of the shell side of the regenerative 

heat exchanger. The regenerative heat exchanger transfers heat from the 

letdown coolant to the charging coolant before the charging coolant is returned 

to the PCS.

The boric acid concentration and chemistry of the primary coolant are 

maintained by the CVC system. A concentrated boric acid solution is prepared 

in a batching tank and is stored in two concentrated boric acid storage tanks. 

Two pumps are provided to transfer concentrated boric acid to a blender where 

the boric acid is mixed with primary makeup water in a predetermined ratio. The 

solution is added to the PCS by the charging pumps.

Chemicals are introduced to the PCS by means of a metering pump which 

pumps the chemical solution from a chemical addition tank and introduces it to 

the charging pumps suction header.

Depleted zinc ions are introduced to the PCS via the zinc addition system for 

reduction of dose to personnel through the removal of radioactive cobalt ions 

from the inner wall of PCS piping.

The PCS may be pressure tested for leaks by means of the variable speed 

charging pump. The system is also provided with connections for installing a 

hydrostatic test pump.

The CVC system is not credited in the Chapter 14 accident analyses with any 

mitigating actions. However, the system responds to safety injection actuation 

signal and the charging pumps inject concentrated boric acid into the primary 

coolant system.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Chemical and Volume Control System are non-safety related and their failure 

could affect the capability of safety related SSCs to perform their safety 

function, they are considered to be in-scope in accordance with 10 CFR 

54.4(a)(2). In addition, some SSCs are considered in-scope due to 

Environmental Qualification, Fire Protection, and Station Blackout in 

accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Chemical and Volume Control 

System are described as follows: 1) The PCS letdown through the regenerative 

heat exchanger (tube side), the letdown orifices, the letdown heat exchanger, 

Containment penetration #36, to the purification ion exchangers, 2) From the 

purification ion exchangers to the purification filters, 3) From the purification 

filters to the volume control tank (VCT), 4) From the primary coolant pumps 

controlled bleedoff, through Containment penetration #44 to the Containment 
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isolation valves, 5) From the VCT to the charging pumps, Containment 

penetration #45, the regenerative heat exchanger (shell side), and to the PCS, 

6) From the concentrated boric acid tanks to the concentrated boric acid 

pumps, the boric acid filters and to the suction of the charging pumps, and 7) 

From the safety injection and refueling water tank to the suction of the charging 

pumps. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

CVC non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment.

CVC non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Auxiliary Building and Containment.

The portions of the Chemical and Volume Control system containing 

components subject to an AMR include accumulators, coolers, filters, heat 

exchangers, fasteners, level glasses, pipe and fittings, pumps, flow elements, 

and valves. The NSAS components added into scope by the 10 CFR 54.4 

scoping boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Chemical and Volume 

Control System, or specific components contained in the system, is provided in 

the summary below.

System Function: CBA-01 Cri 1 Cri 2 Cri 3

Provide concentrated boric acid from the SIRW 

Tank to the suction of the charging pumps.

FP EQ PTS AT SB

X

Comment: Provides boration during a design basis accident.
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System Function: CBA-02 Cri 1 Cri 2 Cri 3

Maintain temperature of the boration flow paths. FP EQ PTS AT SB

Comment: Not in scope of License Renewal due to the concentrated boric acid flow 

path has been down-graded from Safety-Related to Non-Safety Related in 

the Palisades Technical Specifications and the Inservice Inspection 

Program.

System Function: CVC-01 Cri 1 Cri 2 Cri 3

Provide borated makeup water to the primary 

coolant system from the volume control tank, 

Concentrated Boric Acid storage tank, SIRW tank.

FP EQ PTS AT SB

Comment: This is a normal operating system function that does not meet 10 CFR 

54.4 Criteria 1, 2, or 3 and is not in boundary of License Renewal. Safety 

functions of CVC System have been eliminated from Chapter 14 analyses 

with the issuance of FSAR revision 21. The letdown portion of the system 

is isolation on Containment Isolation and performs no safety functions. 

System Function: CVC-02 Cri 1 Cri 2 Cri 3

Provide backup PCS pressure control via 

pressurizer sprays from CVC.

FP EQ PTS AT SB

Comment: Auxiliary spray capability is provided from the CVCS charging pumps 

when no PCP is operating.

During shutdown, the charging subsystem provides auxiliary spray flow to 

the pressurizer to cooldown the pressurizer if normal pressurizer spray via 

the primary coolant pumps is not available.

This system function is a normal operating system function and does not 

meet 10 CFR 54.4 Criteria 1 intended functions. However system 

components are required by NSAS (Criterion 2) and Appendix R (Criterion 

3), are addressed in System Functions CVC-NSAS and CVC-FP, 

respectively, and are in the boundary of License Renewal.

System Function: CVC-03 Cri 1 Cri 2 Cri 3

Manually or Automatically close PCP bleedoff and 

letdown containment isolation valves on CHP and 

CHR. Also ensure manual isolation valves can 

perform containment isolation.

FP EQ PTS AT SB

X

Comment: This function is associated with the valves and pipe required to ensure 

containment isolation in the CVC system. Components associated with the 

processing of electrical signals to initiate automatic isolation upon CHP 

and CHR are dispositioned under the electrical CIS system. The 

penetrations are dispositioned within the Containment Structure 

evaluation.
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System Function: CVC-04 Cri 1 Cri 2 Cri 3

Maintain PCS chemistry within specification. FP EQ PTS AT SB

Comment: The chemical control and purification functions ensure that during normal 

operation an average operating activity of 1.0 uc/cc, excluding gases, is 

maintained in the primary coolant.

This system function is not in boundary of License Renewal. The system 

components that are required by NSAS (Criterion 2) and Appendix R 

(Criterion 3) requirements are addressed in System Function CVC-NSAS 

and CVC-FP, respectively, and are in the boundary of License Renewal.

System Function: CVC-05 Cri 1 Cri 2 Cri 3

Provide an alternate charging PCS injection path 

through the high pressure injection piping.

FP EQ PTS AT SB

X

Comment: Generic Letter 88-17, recommended expeditious action No 6, required that 

there be at least two available or operable means of adding inventory to 

the PCS that are in addition to pumps that are a part of the normal decay 

heat removal systems.

System Function: CVC-06 Cri 1 Cri 2 Cri 3

Provide process radiation monitoring of the PCS 

for indication of failed fuel.

FP EQ PTS AT SB

Comment: This function is not in the boundary of License Renewal.

Currently, the installed monitor RIA-0202A is not being used and is slated 

for removal. PCS radioactivity level is being measured by batch sampling.

System Function: CVC-EQ Cri 1 Cri 2 Cri 3

The system contains -components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The CVC system contain components that are required for 10 CFR 50.49 

requirements.

System Function: CVC-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The CVC system contains components that are required for Appendix R 

safe shutdown.
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Technical and Administrative Information

FSAR Reference

Additional Chemical and Volume Control System details are provided in Section 

9.10 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Chemical and Volume Control System 

are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-1 along with each Component Group’s intended 

function(s).

System Function: CVC-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The CVC system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components. 

System Function: CVC-SBO Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: The CVC system contains components required to operate (valves) during 

an SBO to reduce the primary coolant system's inventory losses.

LR-M-201, Sheet 1

LR-M-201, Sheet 2

LR-M-202, Sheet 1

LR-M-202, Sheet 1A

LR-M-202, Sheet 1B

LR-M-204, Sheet 1A

LR-M-204, Sheet 1B

LR-M-209, Sheet 1

LR-M-209, Sheet 3

LR-M-212 Sheet 3

LR-M-222, Sheet 1A

LR-M-650, Sheet 1A

Table 2.3.3-1 Chemical and Volume Control System

Component Group Intended Function

Boric Acid Storage Tanks Fluid Pressure Boundary
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Oil Cooler Shell Fluid Pressure Boundary

Oil Cooler Tubes Fluid Pressure Boundary

Letdown Heat Exchanger Shell Fluid Pressure Boundary

Letdown Heat Exchanger Channel 

Head, Tubes, Tube Sheet Fluid Pressure Boundary

Letdown Heat Exchanger Tubes, 

Tube Sheet Fluid Pressure Boundary

Letdown Heat Exchanger Tubes Fluid Pressure Boundary

Letdown Heat Exchanger Channel 

Head, Tubes, Tube Sheet Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Pipe - CVC Cooler Fluid Pressure Boundary

Nozzle - CVC Spray Fluid Pressure Boundary

Tubing - CVC Oil Fluid Pressure Boundary

Pipe and Pressure Test Fittings Fluid Pressure Boundary

Flow Elements Fluid Pressure Boundary

Regenerative Heat Exchanger 

Tubes, Tube Sheet Fluid Pressure Boundary

Regenerative Heat Exchanger 

Channel Head, Shell, Tubes, Tube 

Sheet

Fluid Pressure Boundary

Control Valves Fluid Pressure Boundary

Letdown Stop Valve CV-2001 Fluid Pressure Boundary

Check, Control, Manual & Relief 

valves; Instrument Assemblies Fluid Pressure Boundary

Table 2.3.3-1 Chemical and Volume Control System

Component Group Intended Function
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2.3.3.2 Circulating Water System

System Description

The Circulating Water System (CWS) is a closed cycle system using two 

mechanical draft cooling towers. Each loop supplies one-half of the main 

condenser with cooling water by gravity flow from the two 18-cell, induced draft 

cross-flow cooling towers. The cooling towers are erected to the south of the 

Plant over concrete basins. Two half-capacity vertical wet pit cooling tower 

pumps receive heated circulating water from the condenser pump suction 

makeup basin. The cooling tower pumps return the circulating water to the 

cooling tower distribution headers through two 96-inch pipes. Improved cooling 

efficiency and reduced system scaling are obtained by injection of dilution water 

pump discharge into the condenser inlet.

The description above results in some non-safety related SSCs in this system, 

whose failure could affect the capability of a safety related SSC to perform its 

safety function, as being considered in-scope in accordance with 10 CFR 

54.4(a)(2).

The boundaries of the in-scope portions of the Circulating Water System are 

described as follows: 1) the dilution pumps and discharge piping located in the 

intake structure pump house, 2) the portion of the piping from A Cooling Tower 

to MO-5301 (West Water Box Inlet Valve) with splits to MO-5326A (Basin 'A' 

Cooling Tower Blowdown Line Isolation located outside and south of intake 

structure pump house) and MO-5315 (P-40A/B Discharge To E-30A 

Makeup/Fill located outside and northeast of intake structure pump house), and 

3) the portion of the piping from B Cooling Tower to MO-5302 (East Water Box 

Inlet Valve) with splits to MO-5326B (Basin 'B' Cooling Tower Blowdown Line 

Isolation located outside and south of intake structure pump house) and 

MO-5316 (P-40A/B Discharge To E-30B Makeup/Fill located outside and 

southeast of intake structure pump house).

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The in-scope boundaries have been expanded in accordance with 

current NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded 

scoping boundary includes:

CWS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include piping, fittings, and valves. The components are 

located in the Turbine Building and Screen House.
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The portions of the Circulating Water System containing components subject to 

an AMR include fasteners, pipe and fittings, pumps and valves. The NSAS 

components added into scope by the 10 CFR 54.4(a)(2) scope expansion are 

subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Circulating Water 

System, or specific components contained in the system, is provided in the 

summary below.

FSAR Reference

Additional Circulating Water System details are provided in Section 10.2 of the 

FSAR.

System Function: CWS-01 Cri 1 Cri 2 Cri 3

Circulate cooling water through the condenser 

tubes and cooling towers to remove heat from the 

secondary system and to provide condenser 

vacuum.

FP EQ PTS AT SB

Comment: The removal of heat from the main condenser is the main function of the 

Circulating Water System. The Circulation Water System is not safety 

related.

System Function: CWS-02 Cri 1 Cri 2 Cri 3

Circulate cooling air through the cooling tower to 

remove circulating water heat via evaporation.

FP EQ PTS AT SB

Comment: This function relates to the fans that are used to circulate air through the 

cooling towers.

System Function: CWS-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to flooding.

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

flooding.

A failure of the segment of CSW system pipe from E-30A to MO-5301 and 

E-30B to MO-5302 that runs through the screen house as well as the 36 

inch piping from P-40A and P-40B to the edge of the screen house could 

cause the loss of safety related equipment.
Page 2-90 

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Scoping Boundary Drawings

The scoping boundary drawings for the Circulating Water System are listed 

below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-2 along with each Component Group’s intended 

function(s).

2.3.3.3 Component Cooling Water System

System Description

The Component Cooling Water System (CCS) is designed to cool components 

carrying radioactive and potentially radioactive fluids. It provides a monitored 

intermediate barrier between these fluids and the service water system which 

transfers the heat to the outside environment. Thus, the probability of leakage 

of contaminated fluid into the lake is greatly reduced.

System components are rated for the maximum heat removal requirements that 

occur during normal, shutdown or accident operation as applicable. The parts of 

the system located inside containment are isolated in the event of a 

containment high-pressure signal (CHP). The component cooling water to the 

radwaste evaporators and spent fuel cooling system are isolated on safety 

injection actuation signal (SIAS). 

The system is a closed loop consisting of three motor-driven circulating pumps, 

two heat exchangers, a surge tank, associated valves, piping, instrumentation 

LR-M-653, Sheet 1 LR-M-653, Sheet 3

Table 2.3.3-2 Circulating Water System

Component Group Intended Function

Fasteners Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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and controls. The system is continuously monitored by a process monitor which 

detects radioactivity which may have leaked into the system from the fluids 

being cooled.

The Component Cooling Water System uses demineralized water to which an 

inhibitor is added for corrosion control. Makeup to the system is automatically 

supplied from the primary system makeup storage tank.

Heat is transferred from the system to plant service water by means of two 

component cooling heat exchangers. Service water from the critical service 

water header is provided to the tube side of the heat exchangers and the 

rejected heat from the system is discharged by service water into the cooling 

tower pump makeup basin.

Four main supply lines are provided to the various areas of the Plant as follows:

1. To Shutdown Cooling Heat Exchangers

2. To Engineered Safeguards Pumps

3. To Spent Fuel Pool Heat Exchangers and Radwaste Equipment

4. To Services Inside the Containment

Two full capacity valves installed in parallel are provided in the line supplying 

component cooling water to the Shutdown Cooling heat exchangers.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Component Cooling Water System are non-safety related and their failure could 

affect the capability of safety related SSCs to perform their safety function, they 

are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In 

addition, some SSCs are considered in-scope due to Environmental 

Qualification and Fire Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Component Cooling Water 

System are described as follows: 1) The pressure boundary from the Primary 

Makeup supply valve and bypass to the Component Cooling Expansion tank 

and the suction header to the CCS Pumps. 2) From the CCS pumps suction 

header, through the CCS pumps, the CCS discharge header, through the CCS 

heat exchangers to the CCS main supply header, 3) From the CCS main supply 

header to: a. Shutdown Cooling Heat Exchangers, b. the Engineered 

Safeguards Pumps, c. the Spent fuel Pool Heat Exchangers, d. through 

Containment penetration #14 to the Letdown Heat Exchanger, shield cooling 

heat exchanger and the Primary Coolant Pumps internal heat exchangers 

located inside Containment, and 4) the CCS return headers to the CCS pumps 

suction header and surge tank. 
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The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

CCS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment Building.

CCS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include an accumulator, fasteners (to maintain the pressure 

boundary), pipe, fittings and valves. The components are located in the 

Auxiliary Building and Containment Building.

The portions of the Component Cooling System containing components subject 

to an AMR include accumulators, flow switches, heat exchangers, coolers, 

fasteners, pipe and fittings, pumps and valves. The NSAS components added 

into scope by the 10 CFR 54.4(a)(2) scoping boundary expansion are subject to 

AMR.

System Function Listing

A comprehensive listing of functions associated with the Component Cooling 

Water System, or specific components contained in the system, is provided in 

the summary below.

System Function: CCS-01 Cri 1 Cri 2 Cri 3

Circulate cooling water through essential loads 

and heat exchangers during normal and shutdown 

operations.

FP EQ PTS AT SB

X

Comment: The CCS system provides sufficient heat removal for each of the 

components supported by the system in order to maintain operability and 

function of each component serviced during normal and emergency 

modes of operation. This function includes the Component Cooling Surge 

tank, Pumps, Heat Exchangers and piping to and from the cooled 

components.
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System Function: CCS-02 Cri 1 Cri 2 Cri 3

Automatically isolate the CCS supply and return 

lines from containment on CHP for containment 

isolation.

FP EQ PTS AT SB

X

Comment: The automatic activation by the Containment High Pressure (CHP) signal 

is required by Containment Pressure And Temperature Analysis, FSAR 

14.18.

This function is associated with the valves and pipe required to ensure 

containment isolation in the CCS system. Components associated with the 

processing of electrical signals to initiate automatic isolation upon CHP 

and CHR are dispositioned under the electrical Containment Isolation 

system. The penetrations are dispositioned within the Containment 

Structure evaluation.

System Function: CCS-03 Cri 1 Cri 2 Cri 3

Start idle CCS pumps and reposition valves to 

circulate water through essential loads/heat 

exchangers and isolate non-essential loads/heat 

exchangers upon receipt of an ESF actuation 

signal.

FP EQ PTS AT SB

X

Comment: The CCW system is automatically activated by the Safety Injection 

Actuation Signal (SIAS), Recirculation Actuation Signal (RAS), and 

Containment High Pressure (CHP) signal under certain accident 

conditions. The CHP signal is covered in function CCS-02.

This function includes all CCS SSCs required to start the pumps, 

reposition the valves and isolate the system. However the sequencers and 

the air system components to the solenoid valves are not included.

The FSAR Design Basis Accidents that affect CCS are: Increase In Steam 

Flow (Excess Load), FSAR 14.10, Loss Of Normal Feedwater, FSAR 

14.13, Steam Line Rupture Incident, FSAR 14.14, Steam Generator Tube 

Rupture With A Loss Of Offsite Power, FSAR 14.15, Large Break LOCA 

(LBLOCA), FSAR 14.17, Containment Pressure And Temperature 

Analysis, FSAR 14.18.

System Function: CCS-04 Cri 1 Cri 2 Cri 3

Provide cooling to non-essential loads for normal 

operations.

FP EQ PTS AT SB

Comment: This function does not meet Criterion 1, 2, or 3 and is not in boundary.

System Function: CCS-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: This function is developed to ensure the equipment subject to a harsh 

environment during an accident, will be able to perform its function. 
Page 2-94 

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FSAR Reference

Additional Component Cooling Water System details are provided in Section 

9.3, Section 14.10, Section 14.13, Section 14.14, Section 14.15, Section 14.17, 

and Section 14.18 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Component Cooling Water System are 

listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-3 along with each Component Group’s intended 

function(s).

System Function: CCS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: This function includes the equipment required to ensure the requirements 

of the 10CFR50.48 fire protection program are functional.

This function also includes the 10CFR50 Appendix R equipment required 

for a post fire safe shutdown.

System Function: CCS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10 CFR 54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: Selected components were determined to be in boundary for NSAS.

LR-M-202, Sheet 1B

LR-M-204, Sheet 1

LR-M-208, Sheet 1A

LR-M-209, Sheet 1

LR-M-209, Sheet 2

LR-M-209, Sheet 3

LR-M-212, Sheet 3

LR-M-212, Sheet 4

LR-M-214, Sheet 4

LR-M-214, Sheet 5

LR-M-219, Sheet 1B

LR-M-221, Sheet 1

LR-M-221, Sheet 2

LR-M-223, Sheet 1B

LR-M-224, Sheet 1

LR-M-655, Sheet 1

Table 2.3.3-3 Component Cooling Water System

Component Group Intended Function

Accumulators Fluid Pressure Boundary
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2.3.3.4 Compressed Air System

System Description

The Compressed Air Systems (CAS) consist of the Instrument Air System, the 

High Pressure Air System, various backup systems, and the Feedwater Purity 

Air system.

The Instrument Air System is a non-safety related system that is required for 

normal plant operation. The system is designed to provide a reliable supply of 

dry, oil-free air for instruments and controls, and for service air requirements. 

The design of the system is based on an estimated instrument air consumption 

rate of 80 scfm for the Nuclear Steam Supply System and 115 scfm for the 

Bistable/Switch

(In-line Flow Indicator)

Fluid Pressure Boundary

Component Cooling Heat 

Exchanger Fluid Pressure Boundary

Cooler Fluid Pressure Boundary

Heat Exchanger

Fluid Pressure Boundary

Heat Transfer

Fasteners Fluid Pressure Boundary

Primary Coolant Pump Motor Oil 

Cooler Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Waste Gas Compressor Cooler Fluid Pressure Boundary

Table 2.3.3-3 Component Cooling Water System

Component Group Intended Function
Page 2-96 

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remainder of the Plant. Portions of the systems are called out in the Fire 

Protection Plan for use in mitigating the results of fires in the plant.

Three air cooled, oil free compressors are provided for the system, each with 

an in-line air receiver tank. Two have after-coolers served by critical service 

water, with the third compressor after-cooler served by non-critical service 

water. The air receivers are connected to a common discharge air header. The 

common air header branches into two separate air headers, one to the 

instrument air dryer and filter assembly, and one to the Service Air System. The 

instrument air headers are divided into branch lines supplying the Turbine 

Building, Containment Building, Intake Structure, and Auxiliary Building.

The High Pressure Air System consists of three oil-lubricated air compressors, 

each with its own dryer and air receiver. One of these High Pressure Air 

Compressors resides in the Turbine Building and is non-safety related, while 

the other two are located in the East and West Safeguards Rooms. The 

compressors in the East and West Safeguards Rooms supply air to 

safety-related air receivers which supply air to valves located in the two 

Safeguards Rooms. The non-safety related Turbine Building system can supply 

either the East or West Safeguards Systems in any plant mode. Moisture is 

removed from the high pressure air by dryers that are in series with the 

compressors’ air-cooled aftercoolers. Any remaining moisture is removed by 

periodic blowdown of the air receivers and the low point drains. The safety 

related portion of the High Pressure Air System in the East and West 

Safeguards Rooms extends from the air receivers to the control valves serviced 

and is isolated from the non-safety related portion by check valves.

Backup systems consist of bottled nitrogen stations, bottled air station, bulk 

nitrogen, local accumulators, and manual valve actuators.

The Feedwater Purity system is not a safety-related system. When manually 

aligned the system is capable of supplying air to the Instrument and Service air 

systems.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Compressed Air System are non-safety related and their failure could affect the 

capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification and 

Fire Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Compressed Air System are 

described as: 1) the piping and valves from instrument air compressors, 

through aftercoolers, through air receivers, through air filters, to various control 
Page 2-97 

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valves located in the turbine building, auxiliary building and Containment; and 

2) the piping and valves from the high pressure air compressors through their 

aftercoolers, through air dryer, through air receivers, to various high pressure 

air operated valves, and to the instrument air header.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The scoping boundaries have been expanded in accordance with 

current NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded 

scoping boundary includes:

CAS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building, Containment Building and Turbine Building.

CAS non-safety related components contain compressed air. They are located 

in an area that also contains a safety related component. The components 

types include fasteners (to maintain the pressure boundary), piping, fittings and 

valves. The components are located in the Auxiliary Building, Containment 

Building and Turbine Building.

The portions of the Compressed Air System containing components subject to 

an AMR include accumulators, dryers, filters, heat exchangers, fasteners, pipe 

and fittings, steam traps, and valves. The NSAS components added into scope 

by the 10 CFR 54.4(a)(2) scoping boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Compressed Air 

System, or specific components contained in the system, is provided in the 

summary below.

System Function: CAS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: EQ components are located in the Compressed Air System.
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System Function: CAS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: Appendix R components are supplied air from both the Instrument Air 

subsystem or the High Pressure Air subsystem.

System Function: CAS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: Compressed air components are non-safety related. They are attached to 

and located above safety related components. 

System Function: FPA-01 Cri 1 Cri 2 Cri 3

The Feedwater Purity Air subsystem provides a 

backup source of instrument/service air.

FP EQ PTS AT SB

Comment: Feedwater Purity air is not a safety related system. When manually 

aligned, the system is capable of supplying air to the Instrument and 

Service Air System. Feedwater Purity air is not required for normal 

operation and is, therefore, not in-scope for license renewal.

System Function: HPA-01 Cri 1 Cri 2 Cri 3

The High Pressure Air subsystem provides high 

pressure air to assure operability of cylinder 

operated Engineered Safeguards, Main 

Feedwater, and Condensate valves necessary for 

accident conditions. Provides air to the Main 

Steam Isolation Valves.

FP EQ PTS AT SB

X

Comment: The HPA subsystem is safety related and, therefore, in-scope for CAS 

license renewal.

System Function: IAS-01 Cri 1 Cri 2 Cri 3

The Instrument and Service Air subsystem 

provides instrument air to components to avoid 

plant trips and to mitigate consequences of an 

accident.

FP EQ PTS AT SB

Comment: Except for IAS-03, below, the Instrument and Service air subsystem is not 

safety related. It does supply air to Appendix R components as identified in 

function CAS-FP above. The balance of the system is not in-scope for 

license renewal.
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FSAR Reference

Additional Compressed Air System details are provided in Section 9.5 of the 

FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Compressed Air System are listed 

below:

System Function: IAS-02 Cri 1 Cri 2 Cri 3

The Instrument and Service Air subsystem 

provides service air to the cooling tower pump 

basin level transmitter.

FP EQ PTS AT SB

Comment: This system function does not meet any license renewal criterion.

System Function: IAS-03 Cri 1 Cri 2 Cri 3

Manually isolate the Instrument Air subsystem to 

containment to ensure containment isolation.

FP EQ PTS AT SB

X

Comment: Components accomplishing this system function are safety related. 

Additionally, valve MV-CA10190, located in the Control Room, isolates 

Instrument air to the Control Room and is safety related for seismic 

considerations. Therefore, this valve is in-scope for License Renewal.

System Function: IAS-04 Cri 1 Cri 2 Cri 3

Automatically isolate the Service Air subsystem in 

the event of low air header pressure.

FP EQ PTS AT SB

Comment: Components accomplishing this system function do not meet a license 

renewal criterion.

LR-M-201, Sheet 1

LR-M-201, Sheet 2

LR-M-202, Sheet 1

LR-M-202, Sheet 1A

LR-M-202, Sheet 1B

LR-M-203, Sheet 1

LR-M-203, Sheet 2

LR-M-204, Sheet 1

LR-M-204, Sheet 1A

LR-M-204, Sheet 1B

LR-M-205, Sheet 1

LR-M-205, Sheet 2

LR-M-207, Sheet 1

LR-M-207, Sheet 1A

LR-M-207, Sheet 2

LR-M-208, Sheet 1A

LR-M-208, Sheet 1B

LR-M-209, Sheet 1

LR-M-209, Sheet 2

LR-M-209, Sheet 3

LR-M-210, Sheet 1A

LR-M-210, Sheet 1B

LR-M-210, Sheet 2

LR-M-211, Sheet 1

LR-M-211, Sheet 2

LR-M-211, Sheet 3

LR-M-212, Sheet 1

LR-M-212, Sheet 1A

LR-M-212, Sheet 2

LR-M-212, Sheet 3

LR-M-212, Sheet 4

LR-M-212, Sheet 5

LR-M-213

LR-M-215, Sheet 1

LR-M-216, Sheet 2

LR-M-218, Sheet 2

LR-M-218, Sheet 5

LR-M-218, Sheet 6

LR-M-218, Sheet 6A

LR-M-219, Sheet 1B

LR-M-220, Sheet 1

LR-M-221, Sheet 1

LR-M-222, Sheet 2

LR-M-225, Sheet 1

LR-M-225, Sheet 1A

LR-M-225, Sheet 2

LR-M-226, Sheet 1

LR-M-650, Sheet 1B

LR-M-651, Sheet 1B

LR-M-657, Sheet 1
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Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-4 along with each Component Group’s intended 

function(s).

2.3.3.5 Containment Air Recirculation and Cooling System

System Description

The Containment Air Recirculation and Cooling System (CRS) includes four air 

handling and cooling units located entirely within the Containment Building. 

Plant service water from the critical service water is circulated through the air 

cooling units. 

Air is drawn through the coils by two matched vaneaxial fans with direct 

connected motors. One fan motor is rated for normal operating conditions and 

Table 2.3.3-4 Compressed Air System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Air Dryers Fluid Pressure Boundary

Blowers Fans Compressors 

Vacuum Fluid Pressure Boundary

Filters/Strainers

Fluid Pressure Boundary

Filtration

Heat Exchangers Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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the second fan motor is rated for post-DBE conditions. The fan motors rated for 

the post-DBE condition are fed from the emergency power buses.

Four units are normally in operation with two fans in each unit operating. The 

coolers are automatically changed to the emergency mode by a safety injection 

actuation signal. This signal will trip the normal rated fan motor in each unit.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). In addition, some SSCs are 

considered in-scope due to Environmental Qualification and Fire Protection in 

accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Containment Air Recirculation 

and Cooling System (CRS) are described as follows: ducting from the 

Containment atmosphere, through filters, through the Containment Air Cooler 

(CAC) units (including drip pans), and returning to the Containment 

atmosphere. The boundary of the CRS also includes the cooling water side 

(critical service water) of the CAC cooling coils. 

The portions of the Containment Air Recirculation and Cooling System 

containing components subject to an AMR include fans, filters, heat exchanger, 

drip pans, pipe and fittings, flow elements, valves, dampers and fasteners.

System Function Listing

A comprehensive listing of functions associated with the Containment Air 

Recirculation and Cooling System, or specific components contained in the 

system, is provided in the summary below.

System Function: CRS-01 Cri 1 Cri 2 Cri 3

Remove heat and vapor from the containment 

atmosphere during normal plant operation.

FP EQ PTS AT SB

Comment: This is a normal plant operation function and does not meet the criteria of 

10 CFR 54.4. Therefore, this function is not in boundary of license 

renewal.
Page 2-102 

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FSAR Reference

Additional Containment Air Recirculation and Cooling System details are 

provided in Section 6.3 and Section 14.18 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Containment Air Recirculation and 

Cooling System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-5 along with each Component Group’s intended 

function(s).

System Function: CRS-02 Cri 1 Cri 2 Cri 3

In the event of a DBE, limit the containment 

building pressure rise and reduce the leakage of 

airborne radioactivity by providing a means of 

cooling the containment atmosphere.

FP EQ PTS AT SB

X

Comment: A LOCA is initiated by the rupture of the primary coolant system piping. 

The primary coolant will flash to steam and escape through the break. As 

the steam is released to the Containment building, the pressure and 

temperature of the Containment atmosphere quickly increases. The 

structures in Containment will absorb energy and condense steam, 

counteracting the initial pressure and temperature increase. The 

Containment Air Coolers and Containment Spray System, which are 

activated by the pressure rise, then act to reduce the pressure and 

temperature and remove energy released from decay heat.

System Function: CRS-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: The CRS system contains components that are required per 10 CFR 

50.49.

System Function: CRS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The Containment Air Coolers contain components that are required for 

“Appendix R” safe shutdown.

LR-M-208, Sheet 1B LR-M-218, Sheet 2
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2.3.3.6 Emergency Power System

System Description

The Emergency Power System (EPS) has four major subsystems: 1) 

Emergency Diesel Generator, 2) 125 Volt Vital DC, 3) 120 Volt Preferred AC 

System and 4) Emergency Lighting. The emergency power sources are 

designed to furnish onsite power to reliably shut down the Plant and maintain it 

in a safe shutdown condition under all conditions, including DBE, upon loss of 

normal and standby power. The emergency power sources are part of the 

engineered safeguards electrical system and are identified as Class 1E 

systems.

Table 2.3.3-5 Containment Air Recirculation and Cooling System

Component Group Intended Function

Containment Air Cooler Coils

Fluid Pressure Boundary

Heat Transfer

Containment Air Cooler Filter

Filtration

Fluid Pressure Boundary

Containment Air Cooler Flow 

Element

Flow Measurement

Fluid Pressure Boundary

Containment Air Cooler Housing Fluid Pressure Boundary

Containment Air Cooler 

Recirculation Fans Fluid Pressure Boundary

Dampers Fluid Pressure Boundary

Drip Pans Fluid Pressure Boundary

Duct Pressure Boundary

Fasteners Structure Functional Support

Manual and Instrumentation Valves Fluid Pressure Boundary
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The Diesel Fire Pump engines have also been included in the EPS system for 

convenience to permit fire pump diesels to be evaluated in conjunction with the 

diesel generator diesel engines.

The Emergency Diesel Generator subsystem consists of two independent, 

physically separate, diesel-engine driven generators of equal size. Support 

systems associated with each diesel generator include a fuel oil system, air 

starting system, lube oil system, jacket water system, crankcase exhauster, two 

starting circuits and a load sequencer. Supply of electric power for these 

support subsystems is obtained from the generator they are supporting. Each 

unit is installed in a separate room in the seismic Class 1 Auxiliary Building with 

the exception of the Fuel Oil Storage Tank, Fuel Oil Transfer Pumps, and the 

engine combustion air intake and exhaust. The load sequencers are located 

separate from one another in the main control room.

The 125-Volt Vital DC Power subsystem consists of two independent and 

redundant safety related Class 1E DC power sources. Each DC source 

consists of one 125 V battery, one battery charger in-service and one battery 

charger in-standby, and the associated control equipment, distribution panels, 

switchgear, instrumentation, fuse panels and interconnecting cabling. On loss 

of normal and standby ac power, the batteries will supply power to required 

preferred ac and dc loads until one of the diesel generators has started and can 

supply power for the chargers. Assuming that neither diesel emergency 

generator is available, the batteries have ample capacity to supply required dc 

loads and preferred ac loads during a complete loss of ac power for at least four 

hours.

The 120-Volt Preferred AC subsystem is part of the Engineered Safeguards 

Electrical System, and provides a Class 1E service. The inverters are the 

normal source of power for the four Preferred AC buses. The function of each 

inverter is to convert the 125-Volt Vital DC power from the batteries and provide 

continuous uninterruptible Preferred AC power for the instrumentation required 

to shut down the reactor and maintain it in a safe condition after an anticipated 

operational occurrence or a postulated DBE. The Preferred AC System buses 

supply power to the four Reactor Protection System channels and other 

Engineered Safety Features (ESF) controls and instrumentation.

The Emergency Lighting subsystem is composed of three subsystems: 1) 

Emergency AC Lighting (The portion of the normal lighting system which is 

supplied by the Alternating Current portion of the Class 1E Engineered 

Safeguards Electrical System), 2) Emergency DC Lighting (Supplied by the 

125-VOLT Vital DC battery), and 3) Emergency Lighting Units (Supplied by 

internal battery packs which are continuously maintained in the charged 
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condition when normal lighting power is available). These fixed battery pack 

lights are provided for access/egress and at the location of all manual actions 

required to achieve and maintain hot shutdown per 10 CFR 50, Appendix R. 

Emergency lighting inside containment is provided for personnel safety and to 

assist in safe handling of fuel during refueling outages.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Emergency Power System are non-safety related and their failure could affect 

the capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Fire Protection and Station 

Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Emergency Power System are 

described as follows: 1) Emergency Diesel Generators and components 

associated with the various support systems, including starting air, lube oil, fuel 

oil, intake and exhaust, and the jacket water system; 2) diesel fire pump 

engines, including auxiliary subsystems of cooling water, fuel oil, lube oil, intake 

air and exhaust air; 3) 125 Volt Vital DC subsystem, including two station 

batteries (including racks and output terminals), two redundant divisions 

consisting of battery chargers, bus, and distribution panels; 4) 120 Volt 

Preferred AC subsystem, including two divisions consisting of inverters, input 

breakers, instrument AC bypass regulator, distribution panels, and feeder 

breakers connected to instrument and control loads. 5) Emergency AC lighting, 

including lighting loads, branch circuit breakers and interconnecting cabling; a 

portion of emergency DC lighting, including one supply breaker; and 

self-contained emergency lighting units.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

EPS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

component types include piping and fittings. The components are located in the 

Auxiliary Building.

The portions of the Emergency Power System containing components subject 

to an AMR include accumulators, fans, coolers, filters, heat exchangers, 

instrument valve assemblies, heaters, fasteners, mufflers, pipe and fittings, 
Page 2-106 

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pumps, traps, tubing, valves and oil pans. The NSAS components brought into 

scope by the 10 CFR 54.4(a)(2) boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Emergency Power 

System, or specific components contained in the system, is provided in the 

summary below.

System Function: EDC-01 Cri 1 Cri 2 Cri 3

The 125-Volt Vital DC Power subsystem supplies 

DC power to safety related equipment and 

controls.

FP EQ PTS AT SB

X

Comment: The 125-Volt Vital DC Power subsystem consists of two independent and 

redundant safety related Class 1E DC power sources. On loss of normal 

and standby ac power, the batteries will supply power to preferred ac and 

dc loads until one of the diesel generators has started and can supply 

power for the chargers. Power to these loads is required for safe shutdown 

of the reactor. This EPS system function is within the boundary of License 

Renewal.

System Function: EDC-02 Cri 1 Cri 2 Cri 3

The 125-Volt Vital DC Power subsystem provides 

DC power to inverters supplying preferred AC 

busses/loads.

FP EQ PTS AT SB

X

Comment: The 125-Volt Vital DC Power subsystem supplies power to the inverters 

which are the normal source of power for the Preferred AC buses. The 

function of the inverter is to provide continuous AC electrical power to the 

Preferred AC buses, even in the event of an interruption to the normal AC 

power distribution system. The inverters are required to be operable to 

ensure that redundant sources of Preferred AC power for instrumentation 

and control are available to support engineered safeguards equipment in 

the event of an accident or transient and for power operation, plant 

heatups and cooldowns, and shutdown operation. Power to these loads is 

required for safe shutdown of the reactor. This EPS system function is 

within the boundary of License Renewal.
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System Function: EDG-01 Cri 1 Cri 2 Cri 3

The Emergency Diesel Generators are able to be 

locally started and controlled to provide minimum 

safeguards equipment loads.

FP EQ PTS AT SB

X

Comment: The Emergency Diesel Generators' control circuits, in addition to the 

“automatic” functions, are arranged for manual start-stop at the diesel and 

in the control room. The governor and voltage regulator also have local 

controls in the diesel generator room. Procedures direct the use of this 

system feature which provides an alternative start and control of the EDG. 

This EPS system function increases the availability of the EDG which is 

used to place the plant in a safe shutdown condition. This EPS system 

function is within the boundary of License Renewal.
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System Function: EDG-02 Cri 1 Cri 2 Cri 3

The Emergency Diesel Generators are able to 

auto start and provide minimum safeguards 

equipment electric loads.

FP EQ PTS AT SB

X

Comment: The emergency generators are designed to provide a dependable onsite 

power source capable of starting and supplying the essential loads to 

safely shut down the Plant and maintain it in a safe shutdown condition 

under all conditions. The reliability of this onsite power is provided by its 

duplication wherein each emergency generator supplies redundant loads 

and each is capable of providing power to the minimum necessary 

safeguards equipment.

The two DGs each supply a separate 2400 V bus. They provide backup 

power in the event of loss of off-site power, or loss of power to the 

associated 2400 V bus. If either 2400 V bus, 1C or 1D, experiences a 

sustained undervoltage, the associated DG is started, the affected bus is 

separated from its offsite power sources, loads are stripped from that bus 

and its supported buses, the DGs are connected to the bus, and ECCS or 

shutdown loads are started by an automatic load sequencer. The EDG is 

required for safe shutdown of the plant. This EPS system function is within 

the boundary of License Renewal.

The following system support auto start of the diesels:

The Lube Oil System provides lubrication for engine bearings, vibration 

damper, turbocharger, and internal crankcase components during engine 

operation. A prelube pump circulates the lube oil when the diesel is in the 

standby condition. The Lube Oil System maintains the engine at an 

elevated “Standby” temperature of approximately 120 deg. F for fast 

starting when shutdown. The lube oil components for this diesel generator 

support system are safety-related and are required to maintain the diesel 

in standby readiness and operable. This EPS system function is within the 

boundary of License Renewal.

Each diesel engine has its own self-contained jacket cooling system for 

use during operation and preheat heating system when in standby. The 

jacket water system removes heat from the engine cylinders, block, heads, 

turbocharger, and aftercooler during operation. The jacket water 

components for this diesel generator support system are safety-related 

and are required to maintain operability. This EPS system function is within 

the boundary of License Renewal.

System Function: EDG-03 Cri 1 Cri 2 Cri 3

Supply compressed air to the diesel engines for 

cranking.

FP EQ PTS AT SB

X

Comment: The starting air system for each diesel engine consists of an air 

compressor with diverse drives, two air storage tanks, two air start motors, 

and associated piping and valves. This auxiliary system is required to start 

the diesel and support operation of the EDG which is needed for safe 

shutdown of the plant. This EPS system function is within the boundary of 

License Renewal.
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System Function: EDG-04 Cri 1 Cri 2 Cri 3

Supply fuel oil from the diesel generator day 

tanks/belly tanks to the diesel engine.

FP EQ PTS AT SB

X

Comment: The Fuel Oil System provides storage of an adequate fuel supply, 

transfers fuel to the diesel engine, and delivers the correct amount of fuel 

to the engine cylinder. This auxiliary system is required to operate the 

EDG which is needed for safe shutdown of the plant. This EPS system 

function is within the boundary of License Renewal.

System Function: EDG-05 Cri 1 Cri 2 Cri 3

Provide indication/alarms of critical diesel 

generator operating parameters.

FP EQ PTS AT SB

X

Comment: Each emergency generating system is equipped with a local alarm station 

and local instrumentation to allow supervision and monitoring of the 

system during different modes of operation and testing. The system 

provides sufficient alarms and indications to alert or inform the operator of 

system conditions, including those which are abnormal, adverse or 

potentially adverse to proper system operation. The alarms are 

safety-related and needed to support operation of the diesel generator. 

This EPS system function is within the boundary of License Renewal.

System Function: ELU-01 Cri 1 Cri 2 Cri 3

The Emergency Lighting subsystem provides 

emergency AC lighting during normal, off normal 

and emergency conditions.

FP EQ PTS AT SB

Comment: During normal operation, the plant is served by the normal AC lighting 

system and the emergency AC lighting system (which is part of the normal 

AC lighting system). The Emergency AC Lighting subsystem is supplied 

by the Alternating Current portion of the Class 1E Engineered Safeguards 

Electrical System. The AC lighting system is non-Class 1E and can be 

isolated from Class 1E components by breaker. This EPS system function 

is not within the boundary of License Renewal.

System Function: ELU-02 Cri 1 Cri 2 Cri 3

The Emergency Lighting subsystem provides 

emergency DC lighting during off normal and 

emergency conditions.

FP EQ PTS AT SB

Comment: The Emergency DC Lighting subsystem is supplied by the Direct Current 

portion of the Class 1E Engineered Safeguards Electrical System. The DC 

lighting system is non-Class 1E and can be isolated from Class 1E 

components by breaker. equipment and actions necessary for safe 

shutdown of the reactor. This EPS system function is not within the 

boundary of License Renewal.
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System Function: ELU-03 Cri 1 Cri 2 Cri 3

Emergency Lighting subsystem provides 

emergency fixed battery pack lighting (ELUs) 

during off normal and emergency conditions.

FP EQ PTS AT SB

Comment: See EPS-FP and EPS-SB for the functions of the ELUs in scope of license 

renewal.

This function addresses general emergency lighting functions for those 

ELUs that are not in the boundary of License Renewal.

System Function: EPS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: Emergency Diesels, Emergency Lighting, Preferred AC and 125-Volt DC 

are all systems required for safe-shutdown by 10 CFR 50, Appendix R. 

Also, a portable air operated pump is used to transfer fuel oil from tank 

T-926 to the diesel generator day tanks to support Appendix R safe 

shutdown. The air is supplied from the starting air receivers and the 

receivers are replenished using the backup gasoline engine to drive the 

starting air compressors.

The diesel fire pump engines and auxiliaries are also addressed within the 

EPS system.

System Function: EPS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10 CFR 54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The EPS contains non-safety related components containing liquids 

located in an area that also contains safety related components.

System Function: EPS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: The Emergency Lighting Units at Palisades are considered equipment for 

coping with a Station Blackout.
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FSAR Reference

Additional Emergency Power System details are provided in Section 8.3.5, 

Section 8.3, Section 8.4, Section 7.2.8, Section 8.4.1 and Section 8.9 of the 

FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Emergency Power System are listed 

below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-6 along with each Component Group’s intended 

function(s).

System Function: PAC-01 Cri 1 Cri 2 Cri 3

120-Volt Preferred AC Power subsystem provides 

AC power to safety related instrumentation and 

controls during normal and emergency conditions.

FP EQ PTS AT SB

X

Comment: The 120 Volt Preferred AC buses are normally powered from the inverters. 

The function of the inverter is to convert 125 Volt DC to AC and provide 

continuous AC electrical power to the Preferred AC buses, even in the 

event of an interruption to the normal AC power distribution system. The 

inverters are required to be operable to ensure that redundant sources of 

Preferred AC power for instrumentation and control are available to 

support engineered safeguards equipment in the event of an accident or 

transient and for power operation, plant heatups and cooldowns, and 

shutdown operation. Power to these loads is required for safe shutdown of 

the plant. This EPS system function is within the boundary of License 

Renewal.

LR-E-13, Sheet 1

LR-E-13, Sheet 2

LR-M-208, Sheet 1A

LR-M-214, Sheet 1

LR-M-216, Sheet 1

LR-WD950, Sheet 1

LR-WD950, Sheet 4

LR-WD950, Sheet 21

LR-WD950, Sheet 21A

Table 2.3.3-6 Emergency Power System

Component Group Intended Function

Accumulators Fluid Pressure Boundary
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2.3.3.7 Fire Protection System

System Description

The Fire Protection System (FPS) includes the diverse design and operational 

features intended to prevent and mitigate the effects of fires. Building structures 

have been designed and arranged to prevent the spread of fire and to ensure 

integrity of redundant safe shutdown systems and areas. Fire suppression is 

Blowers Fans Compressor Vacuum Fluid Pressure Boundary

Cooler

Fluid Pressure Boundary

Heat Transfer

Fasteners Fluid Pressure Boundary

Filters/Strainers

Filtration

Fluid Pressure Boundary

Heat Exchangers

Fluid Pressure Boundary

Heat Transfer

Heaters, Electric Fluid Pressure Boundary

Misc Mechanical

(Mufflers, oil pans)

Fluid Pressure Boundary

Motors Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Table 2.3.3-6 Emergency Power System

Component Group Intended Function
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provided by fixed water spray systems, such as sprinkler systems and deluge 

systems, fire hose reels and cabinets, portable fire extinguishers, fire barriers 

and fire detection systems. These fire suppression provisions are found 

throughout the Plant site.

Fire hoses from fire hydrants and a standpipe system provide protection in 

accordance with the guidance of NFPA 14, 20 and 24. The fire hydrant piping 

system is designed, installed and tested in accordance with the guidance of 

NFPA 24-1965, Outside Protection. The pumping supply system and fire pumps 

are designed and installed in accordance with NFPA 20-1959, Installation of 

Centrifugal Fire Pumps. The standpipe system is designed, installed and tested 

as a Class II system in accordance with the guidance of NFPA 14-1963, 

Installation of Standpipe and Hose Systems.

Fixed water spray systems, such as wet pipe fusible link sprinkler systems, dry 

pipe fusible link sprinkler systems, and fixed fog deluge spray systems are 

designed, installed and tested in accordance with the guidance of 

NFPA13-1968, Installation of Sprinkler Systems, and NFPA 15-1966, Water 

Spray Fixed Systems for Fire Protection. Indication of individual systems in 

various areas is provided by an annunciator panel in the main control room.

Fixed fog deluge systems protect the main, start-up and station auxiliary 

transformers. Each of these deluge systems are automatically actuated and 

annunciated by a general alarm in the main control room. A manual operated 

fixed fog deluge system protects the charcoal filters used to maintain control 

room habitability.

Fire detection is provided in the form of smoke and ultraviolet detectors. These 

detectors were located and installed in accordance with the guidance of 

NFPA72E-1974. The fire detectors are located in selected plant areas. Alarms 

from any of these detector zones will be indicated on the annunciator panel 

located in the main control room and in Switchgear Room1D.

Other equipment required by Appendix R is included in the scope of License 

Renewal, and is addressed in the various systems where the equipment 

resides. The Appendix R equipment included in the Fire Protection System 

includes the Alternate Shutdown Panels EC-150, -150A (panels and power 

supply - individual instruments belong to their respective systems). Appendix R 

FPS equipment also includes components associated with providing backup 

supply to auxiliary feedwater and critical service water. The primary coolant 

pump oil collection system function, which is required by 10CFR50 Appendix R, 

is included in the Fire Protection System for evaluation.
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Portable fire extinguishers are provided at convenient and accessible locations. 

The extinguishing media are pressurized water, CO2 or dry chemical as 

appropriate for the service requirements of the area.

Water for the fire suppression system is supplied by one of three full-capacity 

fire pumps. Each fire pump is capable of providing water to the largest system 

demand plus fire hose streams in the area of demand. One fire pump is 

electrically driven; the other two are diesel engine-driven. Any fire pump will 

start automatically and can be manually started from the pump control panel. 

The diesel engine-driven fire pumps can also be manually started from the 

control room.

A jockey pump with local controls is provided to maintain the fire suppression 

system full and pressurized. The building structure has been designed and 

arranged to prevent the spread of fire and to ensure integrity of redundant safe 

shutdown systems and areas. 

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

System are non-safety related and their failure could affect the capability of 

safety related SSCs to perform their safety function, they are considered to be 

in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are 

considered in-scope due to Fire Protection in accordance with 10 CFR 

54.4(a)(3).

The boundaries of the in-scope portions of the Fire Protection System are 

described as follows: 1)Two diesel driven fire pumps, one motor driven fire 

pump, and all supporting components attached to the pumps and drivers. (The 

diesel driven fire pumps diesel engines are evaluated in the Emergency Power 

System), 2) Jockey pump and motor, 3) Discharge from three fire pumps and 

jockey pump to the fire main loop, 4) Fire main loop encircling the plant that 

includes fire hydrants FH-1 through FH-7, 5) Five legs that tap off the fire main 

loop to supply various sprinkler systems, deluge systems and hose stations 

within the auxiliary building, turbine building, intake structure, and hydrant 

stations, 6) Transformer deluge systems, 7) Backup supplies from the FPS to 

Auxiliary Feedwater, and Critical Service Water, 8) Fire dampers, 9) Primary 

Coolant Pump lubricating oil collection tanks, enclosures, drip pans and piping.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:
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FPS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Turbine Building.

FPS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Auxiliary Building and Turbine Building.

The portions of the Fire Protection System containing components subject to an 

AMR include accumulators, filter, strainers, sprinkler heads, fasteners, drip 

pans, oil enclosures, pipe and fittings, pumps and valves. The NSAS 

components brought into scope by the 10 CFR 54.4(a)(2) boundary expansion 

are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Fire Protection 

System, or specific components contained in the system, is provided in the 

summary below.

System Function: ASP-01 Cri 1 Cri 2 Cri 3

The Alternate Shutdown Panel provides alternate 

controls and indication during an Appendix R fire 

or when Control Room habitability is a concern.

FP EQ PTS AT SB

X X

Comment: The alternate hot shutdown panels include EC-150 and EC-150A (panels 

and power supplies only - individual instruments belong to their respective 

systems)

The most critical individual functions provided are S/G pressure/level 

indication and auxiliary feedwater pump controls.

System Function: FPS-01 Cri 1 Cri 2 Cri 3

Provide an alternate source of feedwater inventory 

for the auxiliary feedwater pumps.

FP EQ PTS AT SB

X

Comment: This function for this system does NOT include the portion of piping tying 

into the AFW pump suction that is ASME III class 3

System Function: FPS-02 Cri 1 Cri 2 Cri 3

Provide an alternate source of critical service 

water inventory. (Can only supplement total supply 

required.)

FP EQ PTS AT SB

X

Comment: FPS can provide partial backup supply to Service Water as noted in FSAR 

Section 9.1.2.1
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FSAR Reference

Additional Fire Protection System details are provided in Section 9.6 and Table 

9-10 of the FSAR.

System Function: FPS-03 Cri 1 Cri 2 Cri 3

Fire suppression and Fire Barriers FP EQ PTS AT SB

X

Comment: This function includes fire suppression equipment, including fixed water 

sprinkler and deluge systems, portable fire extinguishers, 

hoses/reels/cabinets, fire barriers/penetration seals.

System Function: FPS-04 Cri 1 Cri 2 Cri 3

Provide alternate source of inventory to the spent 

fuel 

FP EQ PTS AT SB

Comment: This is an auxiliary function of the FPS. Fuel pool normal makeup water is 

supplied from the Safety Injection and Refueling Water (SIRW) tank. A 

secondary backup supply of water is available from the fire system. This 

could be utilized to replenish the fuel pool inventory in the event of 

considerable loss of pool water. Therefore, this backup function is not 

considered within the scope of license renewal.

System Function: FPS-05 Cri 1 Cri 2 Cri 3

Fire detection, control and annunciation FP EQ PTS AT SB

X

Comment: Includes detectors cabling, and fire detector control panels.

System Function: FPS-FP Cri 1 Cri 2 Cri 3

This system contains components required by the 

Current Licensing Basis for fire protection

FP EQ PTS AT SB

X

Comment: The FP system contains components required for appendix R safe 

shutdown. This function also includes the primary coolant pump oil 

collection system.

System Function: FPS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

flooding, seismic II/I failures, spray impingement.
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Technical and Administrative Information

Scoping Boundary Drawings

The scoping boundary drawings for the Fire Protection System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-7 along with each Component Group’s intended 

function(s).

2.3.3.8 Fuel Oil System

System Description

The Fuel Oil System (FOS) is designed to provide storage of an adequate 

volume of fuel oil for accident conditions, to transfer fuel to the diesel engines or 

boilers at an adequate rate, and to stop delivery to the unit storage tank when 

LR-M-207, Sheet 2

LR-M-213

LR-M-214, Sheet 4

LR-M-214, Sheet 5

LR-M-216, Sheet 1

LR-M-216, Sheet 2

LR-M-216, Sheet 3

LR-M-218, Sheet 6

LR-M-221, Sheet 2

Table 2.3.3-7 Fire Protection System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Sprinkler Heads

Fluid Pressure Boundary

Spray Pattern

Valves & Dampers Fluid Pressure Boundary
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filled. The primary loads on the fuel oil system are the two Emergency Diesel 

engines and the two Fire Pump engines.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some of the SSCs in the 

system are non-safety related and their failure could affect the capability of 

safety related SSCs to perform their safety function, they are considered to be 

in scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are 

considered in-scope due to Fire Protection in accordance with 10 CFR 

54.4(a)(3).

The boundaries of the in-scope portions of the Fuel Oil System are described 

as follows: 1) The tank, piping, valves and components from the fuel oil storage 

tank (T-10A), through the diesel oil transfer pumps, and to the emergency 

diesel generator day tank isolation valve, 2) The piping and valves from the fuel 

oil storage tank (T-10A), through the diesel oil transfer pumps, through the 

diesel fire pump tanks, and to the fire pump diesel drivers, and 3) The tank, 

piping, valves and components from fuel oil tank (T-926), through the fuel oil 

transfer pump to manual valve MV-FO119. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

FOS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the turbine building and feedwater purity building.

FOS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include accumulator, fasteners (to maintain the pressure 

boundary), piping and fittings. The components are located in the turbine 

building and feedwater purity building.

The portions of the Fire Protection System containing components subject to an 

AMR include accumulators, filters, level glasses, fasteners, pipe and fittings, 

pumps and valves. The NSAS components added into scope by the 10 CFR 

54.4(a)(2) scope expansion are subject to AMR.
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System Function Listing

A comprehensive listing of functions associated with the Fuel Oil System is 

provided in the summary below.

System Function: FOS-01 Cri 1 Cri 2 Cri 3

Store a sufficient supply of fuel oil in storage tank 

T-10A, as defined in the Tech Specs and provide it 

to the Diesel Generator day tanks (T-25A and 

T-25B).

FP EQ PTS AT SB

X

Comment: The fuel oil system supplies fuel oil to the emergency diesel generators.

System Function: FOS-02 Cri 1 Cri 2 Cri 3

Provide fuel oil to the Fire Protection System 

diesel pump day tanks (T-24 and T-40).

FP EQ PTS AT SB

Comment: The FOS provides a fuel oil makeup source to the diesel fire pump day 

tanks. This makeup capability is not a license renewal intended function. 

The equipment to supply fuel from the diesel fire pump day tanks to the 

diesel fire pump engines has a Fire Protection intended function which is 

addressed in System Function FOS-FP. 

System Function: FOS-03 Cri 1 Cri 2 Cri 3

Provide fuel oil to the Service Building Heating 

Boiler (M-950), Feedwater Purity Heating Boiler 

(M-901), Plant Heating Boiler (M-8), and the 

Radwaste Evaporator Heating Boiler (M-61).

FP EQ PTS AT SB

Comment: This intended function of the Fuel Oil System does not perform an license 

renewal intended function per 10 CFR 54.4 and is not in the boundary of 

license renewal.

System Function: FOS-04 Cri 1 Cri 2 Cri 3

The system contains an alternate pumping system 

to supply fuel oil to the day tanks (T-25A/B) from 

T-926 for Appendix R safe shutdown.

FP EQ PTS AT SB

Comment: The system consists of an portable air driven diaphragm pump and rubber 

hose installed between T-926 and tanks T-25A/B per SOP-22, Attachment 

5. Refer to System Function FOS-FP.

System Function: FOS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The fuel oil system contains components that are required for “Appendix 

R” safe shutdown. This includes components required to supply fuel to the 

diesel fire pump engines from the day tanks.
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FSAR Reference

Additional System details are provided in Section 8.4 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Fuel Oil System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-8 along with each Component Group’s intended 

function(s). 

System Function: FOS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The FOS system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components

LR-M-214, Sheet 1

LR-M-215, Sheet 1

LR-M-216, Sheet 1

LR-M-655, Sheet 1

LR-M-907 

Table 2.3.3-8 Fuel Oil System 

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Indicators/Recorders

(level glasses)

Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary
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2.3.3.9 Heating, Ventilation, and Air Conditioning System

System Description

The Heating, Ventilation, and Air Conditioning System (VAS) provides air flow 

to spaces in the Plant. Various supply and exhaust fan combinations provide 

ventilation air for breathing, heated air to prevent equipment freezing and for 

personnel comfort in cold weather, and cooled air to selected locations to 

remove heat from lights, equipment, etc. This system is a collection of 

independent ventilation subsystems, with the major ones being: 1) Control 

Room Heating, Ventilation and Air Conditioning (HVAC), 2) Containment Purge, 

3) Engineered Safeguards Room HVAC, 4) Emergency Diesel Generator Room 

Fans, 5) Electrical Equipment Room HVAC, including Battery Room, 6) Fuel 

Handling Area Ventilation. 

The Control Room HVAC subsystem provides conditioned air to the Control 

Room, the Technical Support Center (TSC), the Viewing Gallery and the 

Mechanical Equipment Room (MER). The subsystem has separate and 

redundant air handling units, air filtering units, condensing units, steam 

humidifiers, and continuous air monitors (CAMs). There are two normal outside 

air intakes, one associated with each of the air handling units. A single common 

remote emergency outside air intake serves both of the air filtering units. The 

Control Room HVAC subsystem also includes a smoke purge exhaust fan with 

duct and a toilet exhaust fan with duct.

The Containment Purge subsystem supplies air to the Air Room area of the 

Containment Building and provides an exhaust line that connects the 

Containment Building to the Main Exhaust Fans. The Containment Purge 

Pipe & Fittings

Fire Barrier

Flow Restriction

Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Table 2.3.3-8 Fuel Oil System 

Component Group Intended Function
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subsystem is mostly located in the Auxiliary Building, with only the air outlet and 

return suction connection are located in the Containment Building.

The Engineered Safeguard Rooms HVAC subsystem normally supplies 

ventilation air to the East and West Engineered Safeguard Rooms via the 

Radwaste Area HVAC subsystem. The ductwork to these rooms is 

automatically isolated if airborne radiation in the exhaust ductwork exceeds 

preset levels. Each room has one cooling coil (cooled by critical service water) 

with two fans that recirculate room air to remove the heating load in these 

rooms.

The Emergency Diesel Generator Room Fans provide ventilation air to remove 

heat generated by the diesel generators. Each room is supplied with air from 

the common plenum by separate intake fans. The exhaust air from each room 

exits through louvered discharge ducts in the diesel generator muffler 

enclosure. The fans are powered by the particular emergency diesel generator 

for which they provide cooling. Each room also includes a unit heater, which 

uses plant heating steam.

The Electrical Equipment, Switchgear, & Cable Spreading Room HVAC 

subsystem (includes Battery Rooms) draws outside air through a filter and 

heating coil and distributes the air to these spaces, which contain mainly 

electrical equipment. Air is circulated back to the supply fan suction or 

exhausted to atmosphere from these areas by a recirculation fan, depending on 

supply air temperature. The electrical equipment room part of the subsystem 

includes a cooling coil whose heat sink is non-critical service water. The North 

Electrical Penetration Room receives minimal ventilation from the 1D 

Switchgear room via the cable way to the penetration room, it has no forced 

ventilation. The South Electrical Penetration Room has a roof-mounted 

ventilator controlled by a wall-mounted thermostat. There is no significant heat 

source in either Electrical Penetration Room.

The Fuel Handling Area Ventilation subsystem provides the capability of 

filtering potential airborne radioactive particulates from the area of the spent 

fuel pool following a fuel handling accident or a fuel cask drop accident. During 

plant evolutions when the possibility for a fuel handling accident or fuel cask 

drop accident exist, the Fuel Handling Area Ventilation subsystem is configured 

such that all fans are stopped except one exhaust fan that is aligned to the 

emergency filter bank.

The Penetration and Fan Room HVAC subsystem was installed in conjunction 

with modifications to protect essential structures, systems and components 

from the effects of high energy line breaks. The system includes a supply filter 

and fan, and an exhaust filter and fan. It also ran new ductwork for the supply 
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and return systems down to the Feedwater Penetration Room, and provided 

branch connections for the Main Steam Penetration Room and Fan Room 

elevations.

Steam for the various heating coils that are part of the above-described 

systems is provided by extraction steam from the low pressure turbine that is 

reduced to nominally 15 psig. When the main turbine is not operating, heating 

steam is supplied by two auxiliary heating boilers. The piping system 

associated with the steam source from the low pressure turbine is evaluated in 

HED system. The piping system associated with the heating boilers and the 

steam distribution system is evaluated in this system.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Heating, Ventilation, and Air Conditioning System are non-safety related and 

their failure could affect the capability of safety related SSCs to perform their 

safety function, they are considered to be in-scope in accordance with 10 CFR 

54.4(a)(2). In addition, some SSCs are considered in-scope due to 

Environmental Qualification, Fire Protection, and Station Blackout in 

accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the HVAC systems include the 

components and ducting of each subsystem as follows: 1) Control Room HVAC 

system, including the flow paths of Emergency mode operation and part of the 

Normal mode operation, 2) Fuel Handling Area HVAC System, including the 

original Fuel Pool HVAC System and the Fuel Pool HVAC System addition, 3) 

Engineered Safeguards Room (East and West) HVAC System, 4) Electrical 

Equipment, Switchgear, Cable Spreading & Battery Rooms HVAC System, 5) 

Emergency Diesel Generator Room HVAC System, 6) Containment Air Room 

Purge System, 7) Control Rod Drive Mechanism Ventilation system (Seismic), 

and 8) a portion of the Plant Heating Steam piping. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded to incorporate additional 

non-safety related components in accordance with current NRC guidance for 

implementation of 10 CFR 54.4(a)(2). The expanded scoping boundary 

includes:

VAS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 
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piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment.

VAS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include blower, ductwork, pipe, fittings, fasteners (to 

maintain the pressure boundary), filters, heaters, steam traps, and valves. The 

components are located in the Auxiliary Building and Turbine Building.

The portions of the Heating, Ventilation and Air Conditioning System containing 

components subject to an AMR include fans, duct, filters, heat exchangers, 

flexible connections, mufflers, fasteners, seals, pipe and fittings, traps, valves, 

and dampers. The NSAS components brought into scope by the boundary 

expansion for 10 CFR 54(a)(2) are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Heating, Ventilation, 

and Air Conditioning System, or specific components contained in the system, 

is provided in the summary below.

System Function: CPG-01 Cri 1 Cri 2 Cri 3

CONTAINMENT PURGE: Automatically isolate the 

containment isolation valves for the Containment 

Purge subsystem on CHP or CHR.

FP EQ PTS AT SB

X

Comment: Maintaining the containment Operable limits the leakage of fission product 

radioactivity from the containment to the environment. This function is 

associated with the valves and pipe required to ensure containment 

isolation in the Containment Purge subsystem. Components associated 

with the processing of electrical signals to initiate automatic isolation upon 

CHP and CHR are dispositioned under the Containment Isolation and 

Penetration (CIS) system. The penetrations are dispositioned within the 

Containment Structure evaluation.

System Function: CPG-02 Cri 1 Cri 2 Cri 3

CONTAINMENT PURGE: Circulate air through 

charcoal filters to remove iodine from the 

containment atmosphere prior to containment 

entry for outages.

FP EQ PTS AT SB

Comment: As indicated in FSAR 9.8.2.4.15, this function is in service only during cold 

shutdown condition. The function of containment purge is not 

safety-related. The associated piping and components are involved in the 

safety-related function of Containment Isolation, which is covered in 

System Function CPG-01 above. 
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System Function: CRV-01 Cri 1 Cri 2 Cri 3

CONTROL ROOM HVAC: Maintain ambient 

temperature in the control room at acceptable 

levels.

FP EQ PTS AT SB

X

Comment: The Control Room HVAC subsystem provides temperature control for the 

control room during normal and emergency conditions. This subsystem is 

capable of removing sensible and latent heat loads from the control room, 

considering equipment heat loads and personnel occupancy 

requirements, to ensure equipment Operability. The normal operating 

mode is also required to be operable to support Appendix R Safe 

Shutdown.

System Function: CRV-02 Cri 1 Cri 2 Cri 3

CONTROL ROOM HVAC: Maintain acceptable air 

quality in the control room.

FP EQ PTS AT SB

X

Comment: The emergency mode operation with charcoal filtration and positive 

pressurization are credited in the radiological analysis in FSAR Section 

14.24. The filtration provides a protected environment from which 

operators can control the plant following an uncontrolled release of 

radioactivity. Pressurization of the Control Room, including Technical 

Support Center, Viewing Gallery, and Mechanical Equipment Room 

(MER), prevents infiltration of unfiltered air from the surrounding areas.

System Function: CRV-03 Cri 1 Cri 2 Cri 3

CONTROL ROOM HVAC: Provide actuation and 

control signals for control room HVAC.

FP EQ PTS AT SB

X

Comment: The control room ventilation emergency mode of operation is actuated 

either by a containment high radiation signal or a containment high 

pressure signal, or manually from the control room. During emergency 

mode operation, the air handling units and the charcoal filter units of both 

trains are actuated automatically.

System Function: DGV-01 Cri 1 Cri 2 Cri 3

EMERGENCY DIESEL GENERATOR ROOM 

FANS: Maintain temperatures in the Emergency 

Diesel Generator Rooms.

FP EQ PTS AT SB

X

Comment: As indicated in FSAR Section 9.8.5.2.7, the reliable operation of these 

ventilation systems is considered essential to Plant safety. Analysis has 

demonstrated that room temperatures will exceed the design temperature 

in a matter of minutes without cooling. Note the unit heaters and the 

associated equipment are not required for this safety-related function 

since they are not essential for diesel generator operability.
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System Function: ESV-01 Cri 1 Cri 2 Cri 3

ENGINEERED SAFEGUARDS ROOM HVAC: 

Maintain temperature in the engineered 

safeguards equipment rooms.

FP EQ PTS AT SB

X

Comment: FSAR 9.8.2.4.13 states that the room coolers and associated fans are 

required to be operable to support operability of the required equipment to 

support the accident analysis.

System Function: SCV-01 Cri 1 Cri 2 Cri 3

ELECTRICAL EQUIPMENT, SWITCHGEAR, & 

CABLE SPREADING ROOM HVAC: Maintain 

ambient temperatures in the Cable Spreading, 

Switchgear and Battery Rooms at acceptable 

levels to ensure operability of essential equipment 

within the rooms.

FP EQ PTS AT SB

X

Comment: FSAR 9.8.2.4.21 and 9.8.5.2.6 indicate that the cable spreading room, 

switchgear rooms and battery rooms are considered essential because 

they house the safe shutdown equipment which are considered important 

to safety. However, the ventilation system that service these areas are not 

safety grade. Ventilation testing showed that upon loss of normal 

ventilation, the operator has up to six hours to take corrective measures. 

Based on Appendix R safe shutdown analysis, this ventilation system is 

considered safe shutdown equipment.

System Function: SCV-02 Cri 1 Cri 2 Cri 3

ELECTRICAL EQUIPMENT, SWITCHGEAR, & 

CABLE SPREADING ROOM HVAC: Remove 

hydrogen gas from Battery rooms to prevent 

explosive atmosphere.

FP EQ PTS AT SB

X

Comment: Battery Room exhaust fans V-15A, V-15B and the exhaust ducting are not 

safety-related. The amount of time it takes for the battery room 

atmosphere to build up to 2% hydrogen, when the batteries are being 

equalized and ventilation is lost, is 1.8 hours. Based on Appendix R safe 

shutdown Logic Diagram, the Battery Room exhaust fans V-15A and 

V-15B are safe shutdown equipment.

System Function: VAS-01 Cri 1 Cri 2 Cri 3

FUEL HANDLING AREA HVAC: Circulate air 

through HEPA and charcoal filters to remove 

contamination and iodine from the fuel handling 

area atmosphere during fuel handling.

FP EQ PTS AT SB

X

Comment: As indicated in Tech Spec Bases 3.7.12, filtration of the fuel handling area 

atmosphere following a fuel cask drop on irradiated fuel assemblies with 

<90 days decay is required to maintain the offsite doses within the 

guidelines of 10 CFR 100.
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System Function: VAS-02 Cri 1 Cri 2 Cri 3

RADWASTE AREA VENTILATION SYSTEM: 

Maintain ambient temperatures in the Auxiliary 

Building at acceptable levels.

FP EQ PTS AT SB

Comment: This function of temperature control in the Radwaste Area Ventilation 

System is to support normal plant operation only. Also, in the transient 

analyses of radiological events in the Auxiliary Building as described in 

FSAR 14.20, 14.21, and 14.23, it is assumed the radionuclides are 

uncontrolled and released directly into the environment. 

System Function: VAS-03 Cri 1 Cri 2 Cri 3

AFW PUMP ROOM HVAC: Maintain ambient 

temperatures in the AFW pump room at 

acceptable levels.

FP EQ PTS AT SB

Comment: This function is applicable to AFW pumps P-8A and P-8B only, and is not a 

license renewal intended function. AFW pump P-8C is located in the 

Engineered Safeguards Room, which is covered by System Function 

ESV-01. As described in FSAR 9.8.5.2.4, tests were performed to verify 

the room can safely withstand a loss of ventilation units for a long period of 

time, at least 24 hours. The simple measure of opening a door would 

provide adequate ventilation for an indefinite period. 

System Function: VAS-04 Cri 1 Cri 2 Cri 3

CONTAINMENT HIGH PRESSURE 

MONITORING: Provide containment pressure 

inputs to the Reactor Protective System for 

containment high pressure and to Engineered 

Safety Features Actuation for safety injection 

initiation.

FP EQ PTS AT SB

X

Comment: The Containment High Pressure trip provides a reactor trip in the event of 

a Loss of Coolant Accident (LOCA) or Main Steam Line Break (MSLB). 

The Containment High Pressure trip shares sensors with the Containment 

High Pressure sensing logic for Safety Injection (SIS), Containment 

Isolation, and Containment Spray. As indicated in Tech Spec B3.3.3, the 

SIS ensures acceptable consequences during Loss of Coolant Accident 

(LOCA) events, including steam generator tube rupture, and Main Steam 

Line Breaks (MSLBs) or Feedwater Line Breaks (FWLBs) (inside 

containment).
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System Function: VAS-05 Cri 1 Cri 2 Cri 3

CONTAINMENT TEMPERATURE AND 

PRESSURE MONITORING: Provide containment 

temperature and pressure indication.

FP EQ PTS AT SB

X

Comment: The containment average air temperature and containment pressure are 

limited during normal operation to preserve the initial conditions assumed 

in the accident analyses for a Loss of Coolant Accident (LOCA) or Main 

Steam Line Break (MSLB). The containment temperature and pressure 

indications are required for proper monitoring of these parameters to 

ensure that initial conditions assumed in the analysis of containment 

response to a DBE are not violated.

System Function: VAS-06 Cri 1 Cri 2 Cri 3

INTAKE STRUCTURE VENTILATION SYSTEM: 

Maintain ambient temperatures in the intake 

structure at acceptable levels.

FP EQ PTS AT SB

X

Comment: Although service water pumps are located in the intake structure and 

considered important to safety, as described in FSAR 9.8.5.2.8, the room 

is not airtight allowing some limited convection to take place, and doors 

opening to outside are available providing sufficient air flow even with 

multiple fan failures. Screen House Roof fans are Seismic Class 2, which 

meets license renewal scoping Criterion 2.

System Function: VAS-07 Cri 1 Cri 2 Cri 3

CRDM VENTILATION: Provide forced air cooling 

to Control Rod Drive Mechanisms.

FP EQ PTS AT SB

Comment: This function is to support normal operation only. It is not required 

following a reactor trip since the drive motors and clutches are 

de-energized.

System Function: VAS-08 Cri 1 Cri 2 Cri 3

PENETRATION AND FAN ROOM HVAC: Maintain 

ambient temperatures in the Penetration (Main 

Steam and Feedwater) and Fan Rooms.

FP EQ PTS AT SB

Comment: As discussed in FSAR 9.8.5.2.9, this function is not considered essential 

because the essential equipment in this area is qualified to survive a main 

steam line break within this area.

System Function: VAS-09 Cri 1 Cri 2 Cri 3

PENETRATION SLEEVE VENTILATION: Provides 

forced-air cooling in the air gap between the 

insulated pipe and the penetration sleeve of Main 

Steam and Feedwater penetrations.

FP EQ PTS AT SB

Comment: Based on the analysis cited in FSAR 5.8.6.4, it was determined that no 

cooling is necessary for these high temperature penetrations with 

insulation. A temperature switch is mounted in each penetration to provide 

alarm indication “Steam/Feedwater Penetration High Temp” in the Control 

Room if any of these penetrations reaches alarming point.
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System Function: VAS-10 Cri 1 Cri 2 Cri 3

CONTAINMENT ISOLATION: Maintain 

containment integrity at penetrations associated 

with the Heating, Ventilating and Air Conditioning 

System, including containment purge lines, 

various instrument lines, and heating steam 

supply/return lines.

FP EQ PTS AT SB

X

Comment: Maintaining the containment integrity limits the leakage of fission product 

radioactivity from the containment to the environment. The function is 

associated with the valves and pipe required to ensure containment 

isolation. Components associated with the processing of electrical signals 

to initiate automatic isolation upon CHP and CHR are dispositioned under 

the Containment Isolation and Penetration (CIS) system. The penetrations 

are dispositioned within the Containment Structure evaluation.

System Function: VAS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: Includes components associated with Engineered Safeguards Room 

Coolers, containment pressure switches, containment purge isolation 

controls, etc.

System Function: VAS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: HVAC systems associated with Control Room, Engineered Safeguards 

Rooms, Cable Spreading Room, Switchgear Room, Battery Room, and 

EDG Rooms are required to support the design function of Safe Shutdown 

equipment.

System Function: VAS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The VAS system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components.
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FSAR Reference

Additional Heating, Ventilation, and Air Conditioning System details are 

provided in Section 5.8, Section 6.5, Section 7.2, Section 7.4, Section 9.6, 

Section 9.8, Section 14.11, Section 14.19, Section 14.20, Section 14.21, 

Section 14.23, and Section 14.24 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Heating, Ventilation, and Air 

Conditioning System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-9 along with each Component Group’s intended 

function(s).

System Function: VAS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: The components involved in SBO 4-hour coping are Containment 

pressure and temperature indicators and associated components.

HVAC would not be required for Control Room, Containment, AFW, cable 

spreading room, battery and switchgear rooms during the SBO coping 

period.

LR-M-208, Sheet 1

LR-M-208, Sheet 1A

LR-M-208, Sheet 1B

LR-M-212, Sheet 3

LR-M212, Sheet 5

LR-M-215, Sheet 1

LR-M-215, Sheet 1A

LR-M-218, Sheet 1

LR-M-218, Sheet 2

LR-M-218, Sheet 4

LR-M-218, Sheet 5

LR-M-218, Sheet 6

LR-M-218, Sheet 6A

LR-M-218, Sheet 7

LR-M-223, Sheet 2

LR-M-650, Sheet 2

LR-M-658, Sheet 1

Table 2.3.3-9 Heating, Ventilation, and Air Conditioning System

Component Group Intended Function

Blowers Fans Compressor Vacuum Fluid Pressure Boundary
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2.3.3.10 Miscellaneous Gas System

System Description

The Miscellaneous Gas System (MGS) is a collection of all the compressed 

bottles and liquid storage of gases used in various plant process and 

Ductwork

Filtration

Fluid Pressure Boundary

Filters/Strainers

Filtration

Fluid Pressure Boundary

Heat Exchangers

Fluid Pressure Boundary

Heat Transfer

Heaters, Electric Fluid Pressure Boundary

Muffler (CRHVAC refrig. 

condensing units) Fluid Pressure Boundary

Elastomers in Flex. Connections 

and Seals inside/outside of 

Containment

Fluid Pressure Boundary

CRHVAC Duct Silencer Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Dampers Fluid Pressure Boundary

Pipe & Fittings

Fluid Pressure Boundary

Containment Isolation

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Table 2.3.3-9 Heating, Ventilation, and Air Conditioning System

Component Group Intended Function
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equipment. The stored gases are nitrogen (liquid and gaseous), hydrogen, 

carbon dioxide (liquid), propane, helium, argon, acetylene, and air bottles (Air 

bottles are included in the Compressed Air System scoping/screening.). Each 

system has headers to attach the gaseous source, pressure regulators, 

monitoring gauges, valving and piping. The Appendix R evaluations identified 

the need for a backup to the air supply to air operated valves. This evaluation 

resulted in numerous nitrogen supply stations being strategically located 

throughout the plant.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Miscellaneous Gas System are non-safety related and their failure could affect 

the capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification, Fire 

Protection, and Station Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Miscellaneous Gas System are 

described as follows: 1) The bulk nitrogen storage and the nitrogen gas supply 

bottles and stations that supply backup nitrogen to air-operated valves required 

to operate in order to support license renewal criteria, including Containment 

Isolation, 2) The backup high pressure air supply, 3) The Containment 

hydrogen monitoring system, and 4) The piping and valves from the 

compressed nitrogen bottles to the spent fuel pool gate, to various tank 

isolation valves, and to various control valves, including the nitrogen outboard 

Containment isolation valve CV-1358.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

MGS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building, Auxiliary Building and Containment.

MGS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include piping, fittings, fasteners (to maintain the pressure 
Page 2-133 

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boundary), and valves. The components are located in the Turbine Building, 

Auxiliary Building and Containment.

The portions of the Miscellaneous Gas System containing components subject 

to an AMR include accumulators, controllers, filters, heat exchangers, 

fasteners, manifold, monitor, pipe & fittings, pumps, valves, tanks and sample 

point. The NSAS components brought into scope by the 10 CFR 54.4(a)(2) 

boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Miscellaneous Gas 

System is provided in the summary below.

System Function: HYM-01 Cri 1 Cri 2 Cri 3

HYDROGEN MONITORING: Provide continuous 

hydrogen monitoring of the containment 

atmosphere during post accident conditions.

FP EQ PTS AT SB

X

Comment: Safety related panels EC-11A, EC-161, EC-162, EC-163, and EC-164 

contain MGS components.

System Function: HYM-02 Cri 1 Cri 2 Cri 3

HYDROGEN MONITORING: Automatically isolate 

the MGS (H2 monitor) containment isolation 

valves on Containment High Pressure and 

Containment High Radiation, and ensure the 

manual containment isolation valves can perform 

containment isolation.

FP EQ PTS AT SB

X

Comment: Containment isolation solenoid valves are safety related.

System Function: MGS-01 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen cover gas to the Safety Injection Tanks 

(SITs) for driving head to ensure SIT injection on 

low Primary Coolant System pressure.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-02 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the AFW pumps discharge 

valves.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.
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System Function: MGS-03 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the steam driven AFW pump 

steam inlet valves.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-04 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the SWS supply and return 

valves to and from containment.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-05 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the HPSI subcooling valves 

from CSS.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-06 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the instrument air containment 

isolation valves.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-07 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the containment spray valves.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-08 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the SIRW tank recirculation 

valves.

FP EQ PTS AT SB

X

Comment: Required for a safety related function.

System Function: MGS-09 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

nitrogen backup to the atmospheric steam dump 

valves.

FP EQ PTS AT SB

X

Comment: MGS also supplies motive pressure for selected AFW valves and steam to 

AFW. Also, see MGS-FP below.

System Function: MGS-10 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

carbon dioxide purge of main generator.

FP EQ PTS AT SB

Comment: This system function does not meet any license renewal criterion.
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System Function: MGS-11 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide air 

backup to HPSI pump P-66B discharge valve to 

Train 2.

FP EQ PTS AT SB

X

Comment: Normally isolated, seismically safety related valve.

System Function: MGS-12 Cri 1 Cri 2 Cri 3

MISCELLANEOUS GAS SYSTEM: Provide 

containment isolation boundary for North and 

South containment electrical penetrations.

FP EQ PTS AT SB

Comment: Provides an inert atmosphere to minimize the potential for corrosion by 

providing a dry nitrogen blanket to prevent condensed moisture buildup in 

the penetration canisters. Does not support a license renewal criterion.

System Function: MGS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: Provides backup pressure source for valve operations should an Appendix 

R fire occur. Also, see MGS-09 above.

System Function: MGS-SBO Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: Backup nitrogen is provided to the atmospheric steam dump valves and 

Bottled Nitrogen Gas Backup Stations 1 and 2 provide motive pressure for 

AFW valve operation to support recovery from an SBO event.

System Function: MSG-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: EQ components are present in the hydrogen analyzer portion of the MGS 

system.

System Function: MSG-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The MGS contains non-safety related components that are attached to 

safety related components and are located over safety related equipment.
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FSAR Reference

Additional Miscellaneous Gas System details are provided in Section 5.8, 

Section 6.1, Section 6.7, Section 7.4, Section 8.5, and Section 9.9 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Miscellaneous Gas System are listed 

below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-10 along with each Component Group’s intended 

function(s). 

LR-M-201, Sheet 2

LR-M-202, Sheet 1A

LR-M-203, Sheet 1

LR-M-205, Sheet 2

LR-M-206, Sheet 1

LR-M-206, Sheet 1A

LR-M-206, Sheet 1B

LR-M-208, Sheet 1B

LR-M-210, Sheet 1

LR-M-210, Sheet 1A

LR-M-210, Sheet 2

LR-M-211, Sheet 1

LR-M-211, Sheet 2

LR-M-211, Sheet 3

LR-M-212, Sheet 3

LR-M-219, Sheet 2

LR-M-222, Sheet 1

LR-M-222, Sheet 2

LR-M-222, Sheet 3

LR-M-224, Sheet 1

LR-M-224, Sheet 2

LR-M-650, Sheet 1

Table 2.3.3-10 Miscellaneous Gas System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Misc Mechanical

(fasteners, manifold, monitor)

Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Tanks Fluid Pressure Boundary
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2.3.3.11 Radwaste System

System Description

The Radwaste System (RWS) contains two major subsystems: 1) Liquid 

Radwaste and 2) Solid Radwaste. The systems are designed and operated to 

achieve a near-zero discharge to the environment.

The Liquid Radioactive Waste System is divided into three sections: (a) the 

clean waste section which processes high-activity, high-purity (low solids) liquid 

waste, (b) the dirty waste section which processes low-activity, low-purity (high 

solids) liquid waste and (c) the laundry waste.

The Solid Waste Management System is designed to collect, process, package 

and store for future offsite disposal low-level liquid and solid wastes, evaporator 

concentrates, spent ion-exchange resins and assorted solid wastes. Solid 

wastes are, as applicable, stored on site, shipped to contractors for 

incineration, immobilized by the addition of additives, and (resins) dewatered 

and compacted. There are two onsite storage/processing facilities.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Radwaste System are non-safety related and their failure could affect the 

capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification in 

accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Radwaste System are described 

as follows: 1) The piping, valve and strainer located downstream of manual 

valve MV-CRW175 to the Safety Injection and Refueling Water tank, 2 Manual 

valve MV-CRW819, 3) Containment isolation components to and from Clean 

Waste Receiver Tanks for Containment penetrations, 4) Containment isolation 

components to and from Primary System Drain Tank for Containment 

penetrations, 5) Containment isolation components associated with 

containment sump level instrumentation for Containment penetrations, 6) Flood 

control for the engineered safeguards rooms, emergency diesel generator 

rooms, auxiliary feedwater room, including floor/equipment drains and pipes, 

sump pits, sump pumps, and discharge piping to route flood water out of the 

rooms, and 7) The utility water storage tank.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 
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Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

RWS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building, Auxiliary Building and Containment Building.

RWS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building, Auxiliary Building and 

Containment Building.

The portions of the Radwaste System containing components subject to an 

AMR include accumulators, filters, strainers, heat exchangers, fasteners, pipe 

and fittings, pumps, and valves. The NSAS components brought into scope by 

the 10 CFR 54.4(a)(2) scoping boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Radwaste System, or 

specific components contained in the system, is provided in the summary 

below.

System Function: LRW-01 Cri 1 Cri 2 Cri 3

LIQUID RADIOACTIVE WASTE: Provide for 

collection, monitoring, filtering, processing, 

storage, reuse, and controlled release of liquid 

radioactive waste (LRW).

FP EQ PTS AT SB

Comment: The radioactive waste treatment system was designed so that discharge 

of radioactivity to the environment is in accordance with the requirements 

of 10CFR20 and Appendix I to 10CFR50. However, release of liquid 

radwaste is not required for safe plant shutdown, does not support any 

safety related equipment, and is not related to any of the five regulated 

events. 

The following tasks of the LRW system are not required for safe plant 

shutdown, do not support any safety related equipment, and are not 

related to any of the five regulated events: storage of water discharged 

from Steam Generators following a Steam Generator Tube Rupture event; 

collection, monitoring and processing of dirty liquid radwaste into 

concentrate for disposal by the solid radwaste system and into distillate 

utility water for reuse; collection, filtering and monitoring of laundry waste; 

collection, monitoring and processing of clean LRW.

Therefore, this function is not within the scope of license renewal.
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System Function: LRW-02 Cri 1 Cri 2 Cri 3

LIQUID RADIOACTIVE WASTE: Automatically 

isolate the LRW containment isolation valves on 

CHP and CHR. Also ensure manual containment 

isolation valves can perform containment isolation.

FP EQ PTS AT SB

X

Comment: This function is associated with the valves and pipe required to ensure 

containment isolation in the LRW system. Components associated with 

the processing of electrical signals to initiate automatic isolation upon CHP 

and CHR are dispositioned under the Containment Isolation and 

Penetration (CIS) system. The penetrations are dispositioned within the 

Containment Structure evaluation.

System Function: LRW-03 Cri 1 Cri 2 Cri 3

LIQUID RADIOACTIVE WASTE: Override 

automatic operation of engineered safeguards 

sump pumps on a high sump level on receipt of a 

CHR signal.

FP EQ PTS AT SB

Comment: See ESF-04 in ESS System. This is not an intended function of Liquid 

Radwaste.

System Function: LRW-04 Cri 1 Cri 2 Cri 3

Store water discharged from the Steam 

Generators, when responding to a Steam 

Generator Tube Rupture, in the miscellaneous 

waste holdup tanks.

FP EQ PTS AT SB

Comment: Storage of water discharged from the Steam Generators following a Steam 

Generator Tube Rupture event is not required for safe plant shutdown, 

does not support any safety related equipment, and is not related to any of 

the five regulated events. Therefore, this function is not within the scope of 

license renewal.

System Function: LRW-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current design basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The RWS system contains components that are required per 10 CFR 

50.49.

System Function: LRW-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

spray, flooding and seismic II/I considerations. Specifically, this includes a 

function to route flood-water out of the Engineered Safeguards rooms, 

Emergency Diesel Generator rooms, and Auxiliary Feedwater pump room 

to the sump via floor and equipment drains, and/or sump pumps.
Page 2-140 

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Technical and Administrative Information

FSAR Reference

Additional Radwaste System details are provided in Section 1.4.8, Section 6.7, 

Section 7.3, Section 11.2, and Section 11.4 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Radwaste System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-11 along with each Component Group’s intended 

function(s).

System Function: SRW-01 Cri 1 Cri 2 Cri 3

SOLID RADIOACTIVE WASTE: Collect, process, 

package and store dirty radwaste evaporator 

concentrates, spent ion-exchange resins and 

assorted solid wastes.

FP EQ PTS AT SB

Comment: Collection, processing, packaging and storage of dirty liquid radwaste 

concentrates, spent ion-exchanger resins and assorted solid wastes is not 

required for safe plant shutdown, does not support any safety related 

equipment, and is not related to any of the five regulated events. 

Therefore, this function is not within the scope of license renewal.

LR-M-201, Sheet 1

LR-M-201, Sheet 2

LR-M-202, Sheet 1

LR-M-202, Sheet 1A

LR-M-202, Sheet 1B

LR-M-203, Sheet 1

LR-M-204, Sheet 1

LR-M-204, Sheet 1A

LR-M-204, Sheet 1B

LR-M-209, Sheet 3

LR-M-210, Sheet 1

LR-M-210, Sheet 1A

LR-M-210, Sheet 1B

LR-M-210, Sheet 1C

LR-M-210, Sheet 2

LR-M-211, Sheet 1

LR-M-211, Sheet 2

LR-M-211, Sheet 3

LR-M-218, Sheet 6A

LR-M-219, Sheet 1A

LR-M-219, Sheet 2

LR-M-221, Sheet 2

LR-M-223, Sheet 1

LR-M-223, Sheet 1B

LR-M-224, Sheet 1

LR-M-227, Sheet 1

LR-M-650, Sheet 1

LR-M-650, Sheet 1A

LR-M-650, Sheet 1B

LR-M-651, Sheet 1A

LR-M-651, Sheet 1B

LR-M-652, Sheet 1

LR-M-654

LR-M-655, Sheet 2

LR-M-657, Sheet 1
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2.3.3.12 Service Water System

System Description

The Service Water System (SWS) supplies Lake Michigan water as the cooling 

medium (Ultimate Heat Sink) for removal of waste heat from the nuclear and 

steam plant auxiliary systems during normal, shutdown, or emergency 

conditions. 

Three half-capacity electric motor-driven pumps draw screened and 

intermittently chlorinated Lake Michigan water from the Intake Structure. Each 

service water pump discharges through a simplex strainer into a common 

header. The common header has a full-capacity takeoff at each end, which 

supplies critical plant systems. A third takeoff at one end of the common header 

supplies the noncritical auxiliary systems. 

Table 2.3.3-11 Radwaste System

Component Group Intended Function

Accumulators

Flood Protection

Fluid Pressure Boundary

Demineralizer Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe & Fittings

Flood Protection

Fluid Pressure Boundary

Pumps

Flood Protection

Fluid Pressure Boundary

Valves & Dampers

Flood Protection

Fluid Pressure Boundary
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The two critical service water (CSW) lines run underground by different paths 

from the Intake Structure to the Auxiliary Building. Each line supplies cooling 

water to one set of the redundant components including emergency diesel 

generator lube oil and jacket water coolers, a control room air-conditioning unit, 

an air compressor after-cooler and an engineered safeguards room cooler. In 

addition, Train A supplies cooling water to the component cooling water heat 

exchangers while Train B supplies cooling water to the containment air coolers.

The noncritical service water (NSW) header is isolated on a Safety Injection 

Signal, thus ensuring that all available service water is routed to the critical 

systems.

The Service Water System, also includes the Ultimate Heat Sink (UHS) 

subsystem. Basically, UHS subsystem of SWS consists of the components that 

take water from Lake Michigan to the suction of the SWS system (intake crib, 

intake structure, and connecting pipe), take the water from the SWS system 

and discharges it to the lake (discharge structure), and transfer water from the 

discharge structure to the intake structure (P-5 and associated components) for 

the purpose of deicing or supplying alternate SWS supply water should the 

intake crib collapse. 

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Service Water System are non-safety related and their failure could affect the 

capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification and 

Fire Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Service Water System are 

described as follows: (1) The piping systems from the intake structure, including 

the nominal 3000-feet long piping from the intake crib to the intake structure, 

through the service water pumps, through critical headers A & B, and return to 

the discharge structure, (2) the non-safety related warm water recirculation 

pump and its discharge piping and valves, (3) the non-safety related screen 

wash pump and its discharge piping and valves, including the spray nozzles 

and screens, (4) a section of the non-critical header located downstream of the 

non-critical service water isolation valve for flood protection, (5) piping and 

components used to provide makeup water to the spent fuel pool, (6) piping 

and components used to provide alternate water to the Auxiliary Feedwater 

System, (7) piping and components used to provide alternate water to the 

Engineered Safeguards pumps seal cooling, and (8) the piping and 

components that provide cooling to the Compressed Air System aftercoolers 
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Technical and Administrative Information

credited for Appendix R. It is noted that the de-icing function of the warm water 

recirculating pump and the trash removal function of the traveling screens and 

screen wash pump are conservatively included in scope to ensure the 

safety-related SWS functions are maintained.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

SWS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the screen house, turbine building, and Containment

SWS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the turbine building and auxiliary building.

The portions of the Service Water System containing components subject to an 

AMR include accumulator, heat exchanger, filters, strainers, spray nozzles, flex 

connections, instrument valve assemblies, fasteners, pipe and fittings, pumps, 

and valves. The NSAS components brought into scope by the 10 CFR 

54.4(a)(2) boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Service Water System, 

or specific components contained in the system, is provided in the summary 

below.

System Function: CSW-01 Cri 1 Cri 2 Cri 3

Circulate cooling water through safety related 

loads and heat exchangers.

FP EQ PTS AT SB

X

Comment: In boundary of License Renewal to supply cooling water to safety related 

components.
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System Function: CSW-02 Cri 1 Cri 2 Cri 3

Upon receipt of ESF actuation signals, start idle 

SWS pumps and reposition valves to circulate 

water through essential loads/heat exchangers 

and isolate non-essential loads/heat exchangers.

FP EQ PTS AT SB

X

Comment: In boundary of License Renewal due to being a response to an Safety 

Injection actuation signal.

System Function: CSW-03 Cri 1 Cri 2 Cri 3

Supply alternate water supply to the Auxiliary 

Feedwater System.

FP EQ PTS AT SB

X

Comment: In boundary of License Renewal due to supply a backup water source to 

Auxiliary Feedwater Pump P-8C.

System Function: CSW-04 Cri 1 Cri 2 Cri 3

Provide alternate cooling to the Engineered 

Safeguards System pumps.

FP EQ PTS AT SB

X

Comment: In boundary of License Renewal due to providing a alternate seal cooling 

water source to Engineered Safeguards pumps.

System Function: CSW-05 Cri 1 Cri 2 Cri 3

Isolate the service water system to and from 

containment.

FP EQ PTS AT SB

X

Comment: This function is associated with the valves and pipe required to ensure 

containment isolation in the Critical Service Water system. Components 

associated with the processing of electrical signals to initiate automatic 

isolation upon CHP and CHR are dispositioned under the Containment 

Isolation and Penetration (CIS) system. The penetrations are 

dispositioned within the Containment Structure evaluation.

System Function: CSW-06 Cri 1 Cri 2 Cri 3

Provide isolation of non-critical service water from 

critical service water.

FP EQ PTS AT SB

X

Comment: In boundary of License Renewal due to isolating the Non-critical Service 

Water header.

System Function: NSW-01 Cri 1 Cri 2 Cri 3

Circulate cooling water through non-essential 

loads and heat exchangers during normal 

operations.

FP EQ PTS AT SB

Comment: This system function is not in boundary of License Renewal due to not 

performing any Criterion 1, 2 or 3 functions per 10 CFR 54.
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Palisades Nuclear Plant

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System Function: NSW-02 Cri 1 Cri 2 Cri 3

Circulate cooling water through non-essential 

loads and heat exchangers during emergency 

operating conditions following restoration of 

Noncritical Service Water following an Safety 

Injection Actuation Signal.

FP EQ PTS AT SB

Comment: This system function is not required for safe shutdown of the plant. The 

function can be used at the discretion of plant operators. Therefore, this 

system function is not in the boundary of License Renewal.

System Function: SWS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The SWS system contains components that are required for 10 CFR 50.49 

requirements.

System Function: SWS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The SWS system contains components that are required for Appendix R 

safe shutdown.

System Function: SWS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The SWS system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components.

System Function: UHS-01 Cri 1 Cri 2 Cri 3

Maintain adequate level in the intake structure. FP EQ PTS AT SB

X

Comment: The UHS performs two principal safety functions: 1) dissipation of decay 

heat after reactor shutdown and during cool down and 2) dissipation of 

decay heat after an accident. Additionally, the UHS provides cooling water 

for critical equipment needed to cool down the plant and maintain it in a 

shutdown mode. Also, the screen wash system is in-scope of license 

renewal to provide trash removal from intake water.
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FSAR Reference

Additional Service Water System details are provided in Section 9.1 of the 

FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Service Water System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-12 along with each Component Group’s intended 

function(s).

System Function: UHS-02 Cri 1 Cri 2 Cri 3

Provide an emergency backup water supply to the 

intake structure via the warm water recirculation 

pump P-5.

FP EQ PTS AT SB

Comment: Per FSAR 9.1.2.1, in the event that water is not available to the intake 

structure, makeup water may be supplied via the warm water recirculation 

pump P-5, if it is available. The warm water recirculation pump's capability 

to provide water to the intake structure is an original design feature 

installed to mitigate circulation water system icing (see function UHS-03), 

and is not intended or required to provide a safety-related capability. Thus 

the SWS backup supply water function is not in-scope of license renewal.

System Function: UHS-03 Cri 1 Cri 2 Cri 3

Provides warm water flow (P-5) to prevent ice 

build-up on the trash racks and screens.

FP EQ PTS AT SB

X

Comment: The warm water recirculation pump (P-5) was designed to provide an 

adequate flow to the intake structure to prevent ice build-up.

LR-M-207, Sheet 1A

LR-M-207, Sheet 2

LR-M-208, Sheet 1

LR-M-208, Sheet 1A

LR-M-208, Sheet 1B

LR-M-209, Sheet 2

LR-M-209, Sheet 3

LR-M-212, Sheet 1

LR-M-213

LR-M-214, Sheet 1

LR-M-218, Sheet 1

LR-M-218, Sheet 4

LR-M-226, Sheet 1A

LR-M-653, Sheet 3

LR-M-658, Sheet 1

LR-C-24

LR-C-25
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2.3.3.13 Shield Cooling System

System Description

The reactor Shield Cooling System (SCS) is designed to remove heat from the 

biological shield surrounding the reactor vessel thereby limiting the thermal 

stresses in the structural concrete. It is not a safety-related system.

The system is designed to maintain structural concrete temperature below 165 

degrees F. The system assures the concrete in the reactor cavity does not 

overheat and develop excessive thermal stress. The Shield Cooling System is 

a closed loop system consisting of two full-capacity sets of cooling coils, two 

full-capacity pumps, a heat exchanger, a surge tank, associated piping, valves, 

instrumentation and controls.

Each set of shield cooling coils is composed of individual cooling coils 

embedded in the concrete shield. The distance between the inner surface of the 

concrete and the centerline of the cooling coils is three inches. The closed loop 

Table 2.3.3-12 Service Water System

Component Group Intended Function

Accumulator Fluid Pressure Boundary

Fasteners in Containment Fluid Pressure Boundary

Fasteners Not in Containment Fluid Pressure Boundary

Filters/Strainers

Filtration

Fluid Pressure Boundary

Heat Exchanger Fluid Pressure Boundary

Pipe & Fittings

Flow Restriction

Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Traveling Screen Spray Nozzles Spray Pattern

Valves & Dampers Fluid Pressure Boundary
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system transfers heat to the Component Cooling Water System by means of 

the shield cooling heat exchanger. Demineralized water with a corrosion 

inhibitor is used in the shield cooling loop.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the Shield 

Cooling System are non-safety related and their failure could affect the 

capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification in 

accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Shield Cooling System are 

described as follows: (1) The makeup water piping and valves from 

Containment isolation check valve CK-CD401, through control valve CV-0939 

and to the Containment penetration, and 2) components that are safety related 

due to being seismic. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

SCS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Containment Building and Auxiliary Building.

SCS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include an accumulator, filters, fasteners (to maintain the 

pressure boundary), piping, fittings and valves. The components are located in 

the Containment Building and Auxiliary Building.

The portions of the Shield Cooling System containing components subject to an 

AMR include accumulators, filters, fasteners, pipe and fittings, and valves. The 

NSAS components brought into scope by the 10 CFR 54.4(a)(2) boundary 

expansion are subject to AMR.
Page 2-149 

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System Function Listing

A comprehensive listing of functions associated with the Shield Cooling System 

is provided in the summary below.

FSAR Reference

Additional Shield Cooling System details are provided in Section 9.2 of the 

FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Shield Cooling System are listed 

below:

System Function: SCS-01 Cri 1 Cri 2 Cri 3

SHIELD COOLING SYSTEM: Remove heat from 

the biological shield surrounding the reactor 

vessel.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: SCS-02 Cri 1 Cri 2 Cri 3

SHIELD COOLING SYSTEM: Automatically 

isolate the containment isolation valve for the 

shield cooling surge tank fill line on CHP or CHR.

FP EQ PTS AT SB

X

Comment: The only portion of SCS that performs a safety related function is the 

containment isolation function for the surge tank fill line.

System Function: SCS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The SCS contains equipment in compliance with the EQ requirements of 

10CFR50.49.

System Function: SCS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

spray, flooding and seismic II/I considerations. 

LR-M-221, Sheet 1
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Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-13 along with each Component Group’s intended 

function(s). 

2.3.3.14 Spent Fuel Pool Cooling System

System Description

The Spent Fuel Pool Cooling (SFP) System removes decay heat from spent 

fuel stored in the spent fuel pool. The System is a closed loop system 

consisting of two pumps, a heat exchange unit consisting of two heat 

exchangers in series, a bypass filter, a bypass demineralizer, a booster pump, 

piping, valves and instrumentation.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the Spent 

Fuel Pool Cooling System are non-safety related and their failure could affect 

the capability of safety related SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2).

The boundaries of the in-scope portions of the Spent Fuel Pool Cooling system 

are described as follows: 1) The SFP cooling loop from the spent fuel pool, 

through the fuel pool cooling pumps, the spent fuel pool heat exchangers (tube 

side), the fuel pool recirculation booster pump, the fuel pool demineralizer, and 

return to the spent fuel pool; 2) the fuel transfer tube isolation valve; and 3) the 

temporary Fire Protection System connection for makeup water to the spent 

fuel pool. 

Table 2.3.3-13 Shield Cooling System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
Page 2-151 

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The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The scoping boundaries have been expanded in accordance with 

current NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded 

scoping boundary includes:

SFP non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment Building.

SFP non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include accumulators, filters, fasteners (to maintain the 

pressure boundary), pipe, fittings and valves. The components are located in 

the Auxiliary Building and Containment Building.

The portions of the Spent Fuel Pool Cooling System containing components 

subject to an AMR include accumulators, demineralizers, filters, fasteners, pipe 

& fittings, pumps, heat exchangers and valves. The NSAS components added 

into scope by the 10 CFR 54.4(a)(2) scope expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Spent Fuel Pool 

Cooling System, or specific components contained in the system, is provided in 

the summary below.

System Function: SFP-01 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Remove decay 

heat from fuel stored in the spent fuel pool and 

cool the reactor cavity water during spent fuel 

transfer.

FP EQ PTS AT SB

X

Comment: The spent fuel pool cooling system is in boundary of License Renewal for 

removing decay heat from the fuel stored in the spent fuel pool (normal 

operation), thereby preventing boiling of the spent fuel pool and 

uncovering the spent fuel bundles, which could result in exceeding the 10 

CFR 100 limits.

Cooling the reactor cavity during refueling operation does not meet the 

requirements of 10 CFR 54.4.
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System Function: SFP-02 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Provide alternate 

shutdown cooling.

FP EQ PTS AT SB

Comment: This function provides an alternate means of cooling the reactor core with 

SFP cross-tied to the refueling cavity if Shutdown Cooling is lost. This 

option is described in an off normal procedure to provide an alternate 

method to mitigate the event of Loss of Shutdown Cooling. However, this 

function is not described in FSAR and is not credited in design basis 

transients.

System Function: SFP-03 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Maintain SFP 

boron concentration at or greater than required 

concentrations.

FP EQ PTS AT SB

X

Comment: This system function provides reactivity control. The components 

associated with the addition of boron to the SFP are not in-scope of 

license renewal. 

System Function: SFP-04 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Able to isolate 

the SFP system to containment to ensure 

containment isolation.

FP EQ PTS AT SB

X

Comment: This function is associated with the valves and pipe required to ensure 

containment isolation in the SFP system. Components associated with the 

processing of electrical signals to initiate automatic isolation upon CHP 

and CHR are dispositioned under the Containment Isolation and 

Penetration (CIS) system. The penetrations are dispositioned within the 

Containment Structure evaluation.

System Function: SFP-05 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Maintain clarity 

and purity of the water in the SFP.

FP EQ PTS AT SB

Comment: This system function does not meet the requirements of 10 CFR 54.4. This 

is a normal operation function.

System Function: SFP-06 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Maintain clarity 

and purity of the water in the SIRW tank.

FP EQ PTS AT SB

Comment: This system function is not in the boundary of License Renewal due to not 

meeting the requirements of 10 CFR 54.4. This is a refueling operation 

function.
Page 2-153 

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FSAR Reference

Additional Spent Fuel Pool Cooling System details are provided in Section 9.4 

of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Spent Fuel Pool Cooling System are 

listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-14 along with each Component Group’s intended 

function(s).

System Function: SFP-07 Cri 1 Cri 2 Cri 3

SPENT FUEL POOL COOLING: Fill and drain the 

reactor cavity for refueling using Safety Injection 

and Refueling Water tank water transported via the 

SFP system.

FP EQ PTS AT SB

Comment: This system function is not in the boundary of License Renewal due to not 

meeting the requirements of 10 CFR 54.4. This is a refueling operation 

function.

System Function: SFP-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components from 

spraying by the postulated failure of the SFP system. 

LR-M-218, Sheet 2 LR-M-221, Sheet 2

Table 2.3.3-14 Spent Fuel Pool Cooling System

Component Group Intended Function

Accumulator Fluid Pressure Boundary

Demineralizers Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary
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2.3.3.15 Waste Gas System

System Description

The Waste Gas System (WGS) stores gaseous isotopes for a time period, 

which will permit sufficient radioactive decay, prior to their discharge to the 

environment. The Waste Gas System is divided into two sections: (a) the gas 

collection header which collects low-activity gases from liquids which have 

been previously degassed and/or vented in other waste handling steps, and (b) 

the gas processing section which collects gases from potentially high-activity 

sources. The Waste Gas system also contains components to provide 

Containment isolation.

The Hydrogen Recombiners are a subsystem to the WGS. The recombiner 

units are natural convection, thermal reactor type, hydrogen/oxygen 

recombiners. The subsystem consists of two 100% recombiner units, each 

containing an electric heater bank, power supply panel, and control panel. The 

recombiner units are located inside the containment building and the power 

supplies and control panels are in the Cable Spreading Room. These units rely 

on the Containment Air Coolers to mix the air for optimal performance.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the Waste 

Gas System are non-safety related and their failure could affect the capability of 

Filters/Strainers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

SFP Heat Exchanger Shell and 

Channel Head Fluid Pressure Boundary

SFP Heat Exchanger Tube and 

Tubesheet

Fluid Pressure Boundary

Heat Transfer

Valves & Dampers Fluid Pressure Boundary

Table 2.3.3-14 Spent Fuel Pool Cooling System

Component Group Intended Function
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safety related SSCs to perform their safety function, they are considered to be 

in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are 

considered in-scope due to Environmental Qualification in accordance with 10 

CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Waste Gas System are 

described as follows: 1) The piping and valves for Containment isolation 

located between Containment penetration #46 to control valve CV-1102, 2) the 

piping and valves for Containment isolation located between Containment 

penetration #52 to CV-1104, 2) the hydrogen recombiner units, and 3) 

numerous seismic components.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

WGS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Auxiliary Building and Containment Building.

WGS non-safety related components contain condensate and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Auxiliary Building and Containment Building.

The portions of the Waste Gas System containing components subject to an 

AMR include accumulators, fasteners, filters, pipe & fittings, and valves. The 

NSAS components brought into scope by the 10 CFR 54.4(a)(2) boundary 

expansion are subject to AMR.
Page 2-156 

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System Function Listing

A comprehensive listing of functions associated with the Waste Gas System is 

provided in the summary below.

System Function: HYR-01 Cri 1 Cri 2 Cri 3

HYDROGEN RECOMBINERS: Provide hydrogen 

recombiners to control hydrogen concentration in 

the containment atmosphere following an event 

affecting the reactor core with releases into 

containment.

FP EQ PTS AT SB

X

Comment: The hydrogen recombiners are safety related and EQ.

System Function: WGS-01 Cri 1 Cri 2 Cri 3

WASTE GAS SYSTEM: Collect and store high 

activity gases and allow a controlled discharge to 

the atmosphere.

FP EQ PTS AT SB

Comment: A release of the stored high activity gases would not result in exceeding 10 

CFR 100 limits.Therefore, this system function does not support a license 

renewal criterion.

System Function: WGS-02 Cri 1 Cri 2 Cri 3

WASTE GAS SYSTEM: Collect and filter gases 

with low activity levels and dilute and vent them to 

the atmosphere via a monitored vent path.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: WGS-03 Cri 1 Cri 2 Cri 3

WASTE GAS SYSTEM: Automatically isolate the 

WGS containment isolation valves on CHP and 

CHR. Also ensure manual containment isolation 

valves can perform containment isolation.

FP EQ PTS AT SB

X

Comment: Containment isolation valves and piping are safety related.

System Function: WGS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment: The hydrogen recombiners are managed by the Environmental 

Qualification Program.
Page 2-157 

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FSAR Reference

Additional Waste Gas System details are provided in Section 6.6 and Section 

11.3 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Waste Gas System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-15 along with each Component Group’s intended 

function(s). 

System Function: WGS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The WGS System contains non-safety related components that are 

attached to safety related components and is located above safety related 

components.

LR-M-201, Sheet 2

LR-M-202, Sheet 1A

LR-M-202, Sheet 1B

LR-M-203, Sheet 1

LR-M-209, Sheet 3

LR-M-210, Sheet 1

LR-M-210, Sheet 1A

LR-M-210, Sheet 1C

LR-M-210, Sheet 2

LR-M-211, Sheet 1

LR-M-211, Sheet 2

LR-M-211, Sheet 3

LR-M-218, Sheet 2

LR-M-218, Sheet 4

LR-M-219, Sheet 2A

LR-M-223, Sheet 1A

LR-M-650, Sheet 1

LR-M-650, Sheet 1A

LR-M-650, Sheet 1B

LR-M-651, Sheet 1

LR-M-651, Sheet 1A

LR-M-651, Sheet 1B

LR-M-655, Sheet 2

LR-M-657, Sheet 1

Table 2.3.3-15 Waste Gas System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary
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2.3.3.16 Domestic Water System

System Description

The Domestic Water System is a source of general purpose filtered well and/or 

city water to buildings of the plant. The major components are: a storage tank, 

level control system, accumulator, water heaters, pumps, piping, valves, and 

instrumentation. The accumulator is pressurized from the plant instrument air 

system. The system is non-safety related.

The Domestic Water System (DWS) has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) due to spatial considerations.

The boundaries of in-scope portions of the Domestic Water System are 

described as follows: 1) The well/city water line as it enters the Turbine building 

and exists the Turbine building going to the Domestic Water Storage Tank, 2) 

the DWS supply and return lines to and from the permanganate filter (T-36), 

including the filter, 3) the DWS supply lines to the potassium permanganate and 

sodium hydroxide tanks through the metering pumps, including the tanks and 

pumps, and return to the DWS supply line to T-36, 4) the DWS supply line to the 

permanganate filter (T-36), 5) the DWS supply line from the Domestic Water 

Storage Tank as it enters the Turbine building, through the Domestic Water 

Pumps to the Hydro Pneumatic Accumulator, 6) the DWS supply through the 

Service Building Domestic Water Pumps to the discharge line as it exist the 

turbine building, 7) the DWS supply to the Domestic Water Tank Heat 

Exchanger, including the heat exchanger, to the Domestic Water Storage Tank 

upstream of MV-DW106A, 8) the DWS lines located in Area 4, elevation 625', 8) 

the DWS lines located Area 2, elevation 611' going to and from the emergency 

shower, and 10) the DWS lines located in Area 9, elevation 590' going to and 

from the decontamination sink.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

Filters/Strainers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary

Table 2.3.3-15 Waste Gas System

Component Group Intended Function
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components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

DWS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components types include accumulators, pumps, fasteners (to maintain 

pressure boundary), heat exchanger, piping, fittings, and valves. The 

components are located in the turbine building and auxiliary building.

The portions of the Domestic Water System containing components subject to 

an AMR include accumulators, heat exchanger, pump casings, fasteners, 

piping and fittings, and valves. The NSAS components brought into scope by 

the 10 CFR 54.4(a)(2) boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Domestic Water 

System is provided in the summary below.

FSAR Reference

None.

Scoping Boundary Drawings

The scoping boundary drawings for the Domestic Water System are listed 

below:

System Function: DWS-01 Cri 1 Cri 2 Cri 3

Pump, chemically treat, store and distribute 

potable water to plant facilities.

FP EQ PTS AT SB

Comment: This function is not in scope of LR because it does not meet any of the 

three LR Criteria.

System Function: DWS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The DWS System is a non-safety related system with pressurized raw 

water and is in areas that also contain safety related components.

LR-M-215, Sheet 1A LR-M-220, Sheet 2
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Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-16 along with each Component Group’s intended 

function(s). 

2.3.3.17 Chemical Addition System

System Description

Provide chemical addition to; Primary Coolant, Main Feedwater, Condensate, 

Circulating Water, and Service Water Systems. These additions are to reduce 

radiation levels, preserve piping integrity, maintain heat transfer, and prevent 

biological growths.

The Chemical Addition System (CHM) has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) due to spatial considerations.

The boundaries of in-scope portions of the Chemical Addition System are 

described as follows: 1) Chemical Addition Tanks T-15, T-16, T-19A, T-19B, and 

T-19C, 2) the piping and valves from T-15, T-16, and T-19A through the 

Chemical Addition Pumps, P-15A/G, to the exhaust hood spray header, the 

feedwater headers, the condensate pump discharge header, the condensate 

effluent header, the feedwater pump suction header, and the steam generator 

blowdown header. 3) Chemical Addition Tank, T-35, and the piping and valves 

to MV-FW238/737, 4) the Anti-foam Injection Tank and the piping and valves 

downstream of the Anti-foam Injection Pump (P-101), including the pump, to 

Table 2.3.3-16 Domestic Water System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe and Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves Fluid Pressure Boundary
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the radwaste evaporators M-59A/B, to the miscellaneous waste tanks 

T-92A/B/C, and to the clean waste holdup tank T-85, 5) the Caustic Injection 

Tank and the piping and valves downstream of the Caustic Injection Pumps 

(P-100A/B), including the pumps, to the radwaste evaporators M-59A/B, to the 

miscellaneous waste tanks T-92A/B/C, to the clean waste holdup tank T-85, 

and to the evaporator concentrator tanks T-94/95, and 6) the piping, pumps 

(P-47A/B) and valves located between basket strainers BS-5393/4 and valves 

MV-CHM115/116, including the valves.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

CHM non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building and Auxiliary Building.

CHM non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building and Auxiliary Building.

The portions of the Chemical Addition System containing components subject 

to an AMR include accumulators, pump, fasteners, piping and fittings, and 

valves. The NSAS components brought into scope by the 10 CFR 54.4(a)(2) 

boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Chemical Addition 

System is provided in the summary below.

System Function: CHM-01 Cri 1 Cri 2 Cri 3

Provide a method to control chemistry in the 

Primary Coolant System via the Chemical and 

Volume Control System.

FP EQ PTS AT SB

Comment: This function is not in scope of LR because it does not meet any of the 

three LR Criteria.
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FSAR Reference

None.

Scoping Boundary Drawings

The scoping boundary drawings for the Chemical Addition System are listed 

below:

System Function: CHM-02 Cri 1 Cri 2 Cri 3

Provide a method to control Main Feedwater and 

Condensate Systems chemistry for steam 

generator reliability and heat transfer performance.

FP EQ PTS AT SB

Comment: This function is not in scope of LR because it does not meet any of the 

three LR Criteria.

System Function: CHM-03 Cri 1 Cri 2 Cri 3

Provide a method to control Circulating Water 

System chemistry for condenser tube heat transfer 

and integrity.

FP EQ PTS AT SB

Comment: This function is not in scope of LR because it does not meet any of the 

three LR Criteria.

System Function: CHM-04 Cri 1 Cri 2 Cri 3

Provide a method to control Service Water System 

chemistry to minimize biological growth to ensure 

piping and valve integrity.

FP EQ PTS AT SB

Comment: This function is not in scope of LR because it does not meet any of the 

three LR Criteria.

System Function: CHM-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The CHM system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components. 

LR-M-205, Sheet 1B

LR-M-207, Sheet 1A

LR-M-207, Sheet 1B

LR-M-220, Sheet 1

LR-M-220, Sheet 2

LR-M-226, Sheet 1

LR-M-227, Sheet 1

LR-M-650, Sheet 1

LR-M-650, Sheet 1A

LR-M-651, Sheet 1

LR-M-651, Sheet 1A

LR-M-653, Sheet 1

LR-M-655, Sheet 2
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Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.3-17 along with each Component Group’s intended 

function(s). 

Table 2.3.3-17 Chemical Addition System

Component Group Intended Function

Accumulator Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Pipe and Fittings Fluid Pressure Boundary

Pump Fluid Pressure Boundary

Valves and Dampers Fluid Pressure Boundary
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2.3.4 Steam and Power Conversion Systems

The following systems are addressed in this section:

• Condensate and Condenser System (Section 2.3.4.1)

• Demineralized Makeup Water System (Section 2.3.4.2)

• Feedwater System (Section 2.3.4.3)

• Heater Extraction and Drain System (Section 2.3.4.4)

• Main Air Ejection and Gland Seal System (Section 2.3.4.5)

• Main Steam System (Section 2.3.4.6)

• Turbine Generator System (Section 2.3.4.7)

2.3.4.1 Condensate and Condenser System

System Description

Within the Condensate and Condenser System (CDS), the main condenser 

condenses the steam from the main turbine and main feed pump driver 

exhausts, as well as the flashed steam from the feedwater heater drains, and 

provides the design vacuum which establishes the steam-water cycle efficiency. 

Noncondensible gases are removed from the main condenser by air ejectors or 

vacuum pump which are evaluated in Air Ejector System (AES). The 

condensate system provides the means for transferring the deaerated 

condensate from the condenser hotwell through the heat transfer surfaces of 

the air ejector condensers, the gland steam condenser, and the low pressure 

feedwater heaters to the suction of the main feed water pumps.

Also included in this system are the condensate storage tank (CST) and the 

associated piping system for makeup to and reject of the condenser hot well. 

The CST and the primary makeup (PMW) tank, which is covered in the 

demineralized make-up water system, provide a passive flow of water, by 

gravity, to the Auxiliary Feedwater (AFW) System. Piping from the CST to the 

AFW pump suctions is included in the Feedwater system. The combined CST 

and PMW tank contain a sufficient amount of cooling water to remove decay 

heat following a reactor trip to allow for cool down of the Primary Coolant 

System to Shutdown Cooling entry conditions.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Condensate and Condenser System are non-safety related and their failure 

could affect the capability of SR SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 
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some SSCs are considered in-scope due to Fire Protection and Station 

Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Condensate and Condenser 

System are described as follows: 1) The piping and valves from the condensate 

storage tank (CST), including the tank, through the condensate transfer pump, 

through the CST heat exchanger and return to the CST. 2) The condenser 

makeup line piping and valves from the CST to makeup and reject valves, 

including portions of the auxiliary feedwater pump recirculation lines, 3) some 

segments of CDS piping from feedwater heaters E-2A/B, through the 

downstream feedwater heaters (E-3A/B, E-4A/B, and E-5A/B) to the suction of 

the main feedwater pumps. In addition, the non-safety related condenser 

makeup and reject piping in the Auxiliary Feedwater pump room are in scope. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

CDS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building. 

CDS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building.

The portions of the Condensate and Condenser System containing 

components subject to an AMR include accumulators, heaters, strainers, pipe 

and fittings, fasteners, heat exchangers, pumps, and valves. The NSAS 

components brought into scope by the 10 CFR 54.4(a)(2) boundary expansion 

are subject to AMR.
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System Function Listing

A comprehensive listing of functions associated with the Condensate and 

Condenser System is provided in the summary below.

System Function: CDS-01 Cri 1 Cri 2 Cri 3

Provide a continuous supply of water from the 

condenser hotwell to the suction of the main 

feedwater pumps.

FP EQ PTS AT SB

Comment: Condensate supply to the main feedwater pumps is to support normal 

operation only. However, failure of some segments of condensate supply 

pipes in the pathway may cause damage to some safety related 

components, such as AFW pumps, controls of AFW turbine steam supply 

valve, and controls of FW regulator valves. The effect of the failure on the 

adjacent safety related components is addressed in Function CDS-NSAS. 

System Function: CDS-02 Cri 1 Cri 2 Cri 3

Ensure adequate condensate inventory is 

available for the Auxiliary Feedwater System.

FP EQ PTS AT SB

X

Comment: The CDS provides a safety grade source of water to the steam generators 

to make up for steaming required for removing decay heat and cooling 

down the plant following all events discussed in the FSAR, Chapters 5 and 

14. To satisfy accident analysis assumptions, the condensate inventory 

must contain sufficient cooling water to allow for cool down of the Primary 

Coolant System to Shutdown Cooling entry conditions.

System Function: CDS-03 Cri 1 Cri 2 Cri 3

Ensure ability to manually isolate the hotwell 

makeup valves to conserve condensate inventory 

for Auxiliary Feedwater during an accident.

FP EQ PTS AT SB

X

Comment: The Auxiliary Feedwater pumps operate with a continuous recirculation to 

the CST. The minimum flow recirculation is returned to the CST through 

the header of condenser hotwell reject and makeup. The associated 

manual makeup and reject isolation valves are relied on to minimize the 

losses and ensure the CST will maintain adequate inventory for its safety 

function of CDS-02.

System Function: CDS-04 Cri 1 Cri 2 Cri 3

Provide ability to feed the steam generators from 

the condenser hotwell via the condensate pumps 

during a Loss of Feedwater accident.

FP EQ PTS AT SB

Comment: As described in FSAR 9.7.4, the condensate pumps may be used to pump 

water through the normal feedwater train to the steam generators in the 

event of a failure of the auxiliary feedwater piping system. The failure of 

the Auxiliary Feedwater system is not postulated in the analysis of a Loss 

of Feedwater accident, and is outside the design basis of this plant. 
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FSAR Reference

Additional Condensate and Condenser System details are provided in Section 

9.7 and Section10.2 of the FSAR.

System Function: CDS-05 Cri 1 Cri 2 Cri 3

Steam discharged from the low-pressure turbine is 

condensed and deaerated in the main condenser.

FP EQ PTS AT SB

Comment: This function of the main condenser provides the design vacuum to 

establish the steam-water cycle efficiency, which is to support normal 

operation only.

System Function: CDS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The components of CDS involved in Appendix R Safe Shutdown Analysis 

include CST (normal source of AFW supply), control switches and 

breakers (breakers are addressed in Station Power System) of 

Condensate Pumps (secured for FW isolation without closing block 

valves), etc. 

System Function: CDS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The CDS system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components.

System Function: CDS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: As described in FSAR 10.2.3.1, the minimum required condensate storage 

tank (CST) inventory will ensure that sufficient inventory is available to 

cope with a Station Blackout for 4 hours.
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Scoping Boundary Drawings

The scoping boundary drawings for the Condensate and Condenser System 

are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-1 along with each Component Group’s intended 

function(s). 

LR-M-206, Sheet 1

LR-M-206, Sheet 1B

LR-M-207, Sheet 1A

LR-M-207, Sheet 1B

LR-M-207, Sheet 1C

LR-M-207, Sheet 1D

LR-M-207, Sheet 2

LR-M-212, Sheet 2

LR-M-215, Sheet 1A

LR-M-220, Sheet 1

LR-M-225, Sheet 2

Table 2.3.4-1 Condensate and Condenser System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

CST Heater Shell Fluid Pressure Boundary

CST Heater Tubes Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

FW Heater Shell and Channel 

Head Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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2.3.4.2 Demineralized Makeup Water System

System Description

The Demineralized Makeup Water (DMW) System is the source of high quality 

filtered and demineralized water throughout the plant. The major components of 

this system are pumps, storage tanks, a reverse osmosis system, filters, tank 

heating heat exchangers, extensive piping, valves, and instrumentation.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Demineralized Makeup Water System are non-safety related and their failure 

could affect the capability of SR SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Fire Protection and Station 

Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Demineralized Makeup Water 

System are described as follows:1) Primary System Makeup Storage Tank 

T-81, 2) Primary System Makeup Storage Tank T-90, 3) piping and components 

comprising the pressure boundary between tank T-81 to the Condensate 

Storage Tank, 4) piping located downstream of T-81 to valves MV-PMU100 and 

MV-PMU109, 5) piping header HC-11-3” located between headers HCD-92-1” 

and HCD-7-2”, and 6) piping header HB-26-1” located in Diesel Generator 1-1 

and 1-2 rooms. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

DMW non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building and Auxiliary Building.

DMW non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building and Auxiliary Building.

The portions of the Demineralized Makeup Water System containing 

components subject to an AMR include accumulators, heat exchanger, filters, 

pipe & fittings, fasteners, pumps, valves, and conductivity element. The NSAS 
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components added into scope by the 10 CFR 54.4(a)2 scoping boundary 

expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Demineralized 

Makeup Water System is provided in the summary below.

System Function: DMW-01 Cri 1 Cri 2 Cri 3

Provide condensate/feedwater supply from tank 

T-81 via pump feed or gravity feed.

FP EQ PTS AT SB

X

Comment: Gravity feed from Primary Makeup Water (PMW) Tank to Condensate 

Storage Tank is in-scope of License Renewal, but supply via pump feed is 

not in-scope of License Renewal because the feed pumps are not safety 

related. Technical Specification 3.7.6 requires that a minimum of 100,000 

gallons be maintained in the Condensate Storage Tank and PMW Tank, 

combined. 

System Function: DMW-02 Cri 1 Cri 2 Cri 3

Provide alternate supply of condensate/feedwater 

supply from tank T-939 via pump feed.

FP EQ PTS AT SB

Comment: Tank and feed pump are not safety related. This function is not in-scope of 

License Renewal.

System Function: DMW-03 Cri 1 Cri 2 Cri 3

Provide primary makeup water to the emergency 

diesel generator jacket water surge tanks.

FP EQ PTS AT SB

Comment: The emergency diesel generator jacket water surge tanks have sufficient 

capacity for duration of accident without addition of makeup water. This 

function is not in scope of license renewal.

System Function: DMW-04 Cri 1 Cri 2 Cri 3

Provide primary makeup water to the component 

cooling water system surge tank.

FP EQ PTS AT SB

Comment: The component cooling water surge tank has sufficient capacity for 

duration of accident without addition of makeup water. This function is not 

in scope of license renewal.

System Function: DMW-05 Cri 1 Cri 2 Cri 3

Provide demineralized water to the shield cooling 

system surge tank.

FP EQ PTS AT SB

Comment: The shield cooling system, including surge tank, is not safety related and 

is not required for design basis accidents, per FSAR 9.2.
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FSAR Reference

Additional Demineralized Makeup Water System details are provided in Section 

9.2 and Section 9.7 of the FSAR.

System Function: DMW-06 Cri 1 Cri 2 Cri 3

Provide demineralized water for miscellaneous 

plant uses.

FP EQ PTS AT SB

Comment: Not required for design basis accidents. 

System Function: DMW-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: In scope of license renewal for Appendix R.

System Function: DMW-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The DMW system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components. 

System Function: DMW-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: in-scope of License Renewal based on TS 3.7.6, which requires that a 

minimum of 100,000 gallons be maintained in the Condensate Storage 

Tank and Primary Makeup Water Tank, combined. 
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Scoping Boundary Drawings

The scoping boundary drawings for the Demineralized Makeup Water System 

are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-2 along with each Component Group’s intended 

function(s). 

LR-M-201, Sheet 2

LR-M-202, Sheet 1A

LR-M-209, Sheet 3

LR-M-210, Sheet 1B

LR-M-210, Sheet 2

LR-M-212, Sheet 2

LR-M-214, Sheet 1

LR-M-215, Sheet 1

LR-M-215, Sheet 1A

LR-M-219, Sheet 1A

LR-M-219, Sheet 1B

LR-M-219, Sheet 2

LR-M-220, Sheet 1

LR-M-220, Sheet 2

LR-M-221, Sheet 1

LR-M-227, Sheet 1

LR-M-650, Sheet 1

LR-M-650, Sheet 1B

LR-M-651, Sheet 1B

LR-M-652, Sheet 1

LR-M-653, Sheet 4

LR-M-654

LR-M-655, Sheet 1

LR-M-657, Sheet 1

Table 2.3.4-2 Demineralized Makeup Water System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe and Fittings Fluid Pressure boundary

Pumps Fluid Pressure Boundary

Transmitter/Element Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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2.3.4.3 Feedwater System

System Description

The Feedwater System (FWS) consists of Main Feedwater (MFW) and 

Auxiliary Feedwater (AFW) Systems. The MFW System provides a reliable 

source of water to the Steam Generators during normal operations. This water 

is preheated in the feedwater heaters to increase overall thermal efficiency. 

Flow rate is manually and/or automatically controlled to maintain Steam 

Generator level. Condensate from two parallel streams of low pressure 

Feedwater Heaters and from the discharge of two Heater Drain Pumps is 

supplied to the suction of the two variable speed, turbine driven Feedwater 

Pumps. These pumps deliver the feedwater through parallel high pressure 

feedwater heaters to the Steam Generators.

The AFW System supplies water to the secondary side of the steam generators 

for reactor decay heat removal when normal feedwater sources are unavailable 

during accident conditions. AFW is also designed to provide a supply of 

feedwater to the steam generators during start-up operations and to remove 

primary system sensible and decay heat during initial stages of shutdown 

operations.

AFW can provide feedwater to any combination of steam generators from any 

one or combination of three pumps; two are motor-driven, and the third is 

steam-driven. Steam can be supplied to the steam-driven pump from the steam 

generator E-50A. The pumps can take suction from the Condensate Storage 

Tank, which is the normal source, or from the Service Water System (P-8C) or 

the Fire Protection System (P-8A/B) if the Condensate Storage Tank is not 

available. The steam driven pump provides an independent and diversely 

powered means of providing feedwater to the steam generators. In the event of 

automatic initiation, the AFW system is designed to automatically start the AFW 

pumps and direct flow to the steam generators via the flow path to the AFW 

nozzles.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the 

Feedwater System are non-safety related and their failure could affect the 

capability of SR SSCs to perform their safety function, they are considered to 

be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are 

considered in-scope due to ATWS, Environmental Qualification, Fire Protection, 

and Station Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Feedwater System are 

described as follows: 1) The piping, valves, and components from the S/G Feed 
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Pumps, including the pumps, through feedwater heaters to the Steam 

Generators, 2) The piping, valves, and components from the Condensate 

Storage Tank (T-2) through the AFW pumps to the Steam Generators, and 3) 

the steam-driven pump turbine and the piping, valves and components for its 

steam supply from S/G E-50A. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

FWS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building, Auxiliary Building and Yard.

FWS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building and Auxiliary Building.

The portions of the Feedwater System containing components subject to an 

AMR include accumulator, strainers, heat exchangers, flow indicators, pipe & 

fittings, fasteners, filters, pumps, steam traps, turbines and valves. The NSAS 

components added into scope by the 10 CFR 54.4(a)(2) scoping boundary 

expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Feedwater System, or 

specific components contained in the system, is provided in the summary 

below.

System Function: AFW-01 Cri 1 Cri 2 Cri 3

Provide water to the steam generator (S/G) 

secondary side.

FP EQ PTS AT SB

X

Comment: Components of AFW are Safety-Related; FSAR 9.7 includes the detail 

description of the design basis function of AFW. Also, Safety Analyses in 

FSAR 14.13, 14.14, 14.15, and 14.18 credit the AFW system for the 

mitigation of the transients.
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System Function: AFW-02 Cri 1 Cri 2 Cri 3

Provide Auxiliary Feedwater Actuation Signals 

(AFAS) and flow control signals to AFW.

FP EQ PTS AT SB

X

Comment: AFW Control components are safety-related; FSAR 7.4.3 details the 

design basis functions of AFW Controls.

System Function: AFW-03 Cri 1 Cri 2 Cri 3

Able to manually isolate AFW to containment to 

ensure containment integrity.

FP EQ PTS AT SB

X

Comment: FSAR 7.4.3 and 9.7.2.3 indicate that in the event of a main steam line 

break inside containment, the AFW flow toward the affected steam 

generator must be terminated. The Emergency Operating Procedures 

direct operators to isolate the affected steam generator using the flow 

control valves.

System Function: AFW-04 Cri 1 Cri 2 Cri 3

Provide level instrumentation for steam generator 

level inputs to Auxiliary Feedwater Actuation and 

the Reactor Protective System for low steam 

generator level trips.

FP EQ PTS AT SB

X

Comment: FSAR Table 5.2-5, I&C Component Classification, FSAR 7.4.3, AFW 

Controls, and FSAR 7.2.3.7, Reactor Protective System (Low Steam 

Generator Water Level) indicate the safety function of the level 

instrumentation for steam generators.

System Function: AFW-05 Cri 1 Cri 2 Cri 3

Provide decay heat removal via steaming the 

steam generators through steam-driven AFW 

pump P-8B.

FP EQ PTS AT SB

Comment: Steaming of the Steam Generators via steam-driven AFW pump is an 

ancillary function that pump can perform that is a backup to the normal 

steaming paths via the turbine bypass valve, the Atmospheric Dump 

Valves, and the PCS code safeties. This function is included in the 

Emergency Operating Procedures to provide the operators a means to 

minimize challenges to the code safeties. Therefore, this is neither a 

safety related function nor a regulated event function.

System Function: AFW-06 Cri 1 Cri 2 Cri 3

Isolate steam supply to AFW pump turbine. FP EQ PTS AT SB

X

Comment: FSAR 14.15, Steam Generator Tube Rupture, states that one of the 

operator actions assumed in the analysis is to isolate the affected steam 

generator when the hot leg is 525 deg F or less.
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System Function: AFW-07 Cri 1 Cri 2 Cri 3

Provides AFW pump trips on low suction pressure, 

overcurrent, or load shed.

FP EQ PTS AT SB

Comment: This function is for equipment protection.

System Function: AFW-08 Cri 1 Cri 2 Cri 3

Provide means of containment isolation for Class 

C-1 penetrations.

FP EQ PTS AT SB

X

Comment: Because the steam supply lines to the steam driven AFW pump turbine 

branch off the main steam lines upstream of the main steam isolation 

valves, control valve CV-0522B is considered a containment isolation 

valve. 

The AFW piping to the steam generators is routed through Containment 

Penetrations. In each situation, a single check valve is the means of 

containment isolation, similar to the main feedwater isolation. FSAR 

5.1.6.9 provides justification of using single check valve for containment 

isolation for MFW and AFW systems.

This function is associated with the valves and pipe required to ensure 

containment isolation in the AFW system. Components and commodities 

(e.g., Cables and supports) associated with the processing of electrical 

signals to initiate automatic isolation upon CHP and CHR are 

dispositioned under the Containment Isolation and Penetration (CIS) 

system. The penetrations are dispositioned within the Containment 

Structure evaluation.

System Function: FWS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: FSAR 7.4.3 indicates an auto start of the turbine driven AFW pump on loss 

of DC control power was added as an independent actuation signal to 

meet the ATWS requirements.

System Function: FWS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment:
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System Function: FWS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: FSAR 9.6.8 summarizes the plant specific safe shutdown analysis. FSAR 

7.7.4 describes that the Auxiliary Hot Shutdown Panels have been 

provided as a centralized location for controlling safe shutdown of the 

plant for the alternate shutdown accomplished from outside the control 

room.(3) Technical Specification Table 3.3.8-1, Alternate Shutdown 

System Instrumentation and Controls, includes AFW control and indication 

of turbine driven pump.

System Function: FWS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The FWS system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components. 

System Function: FWS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: AFW is involved in the mitigation of Station Blackout events

System Function: MFW-01 Cri 1 Cri 2 Cri 3

Provide water to the steam generators to maintain 

water level above trip setpoint.

FP EQ PTS AT SB

Comment: This system function is to support Normal Operation, not credited in 

mitigation of design basis transients. However, piping failure of some 

segments will affect safety related components. The system function 

associated with Criterion 2 is covered in FWS-NSAS.
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System Function: MFW-02 Cri 1 Cri 2 Cri 3

Automatically isolate the MFW regulation and 

MFW regulation bypass valves on CHP or the 

respective Steam Generator low pressure signal.

FP EQ PTS AT SB

X

Comment: FSAR Table 14.14-4 (Steam Line Break Sequence Of Events) and FSAR 

7.5.1.3 indicate that in the event of low steam generator pressure < 500 

psia or containment high pressure (CHP), the main feedwater regulating 

and regulating bypass valves are closed to prevent excessive flow into the 

steam generators. This ensures containment pressure is not exceeded 

during a main steam line break inside containment. FSAR 10.2.3.3 

indicates this feature also prevent the possibility of a condensate pump 

supplying water to a depressurized steam generator causing overcooling 

of the Primary Coolant System.

System Function: MFW-03 Cri 1 Cri 2 Cri 3

Provide hot start capability of the MFW pumps 

during a loss of all feedwater event.

FP EQ PTS AT SB

Comment: Emergency Operating Procedures provide the direction to implement this 

function to recover the MFW pumps. But the recovery of MFW pumps 

following a transient is not credited in any safety analysis.

System Function: MFW-04 Cri 1 Cri 2 Cri 3

Provide pressure instrumentation for steam 

generator pressure inputs for Main Steam Isolation 

and to the Reactor Protective System for low 

Steam Generator pressure trips.

FP EQ PTS AT SB

X

Comment: Bases of Technical Specification 3.3.3 indicates this signal ensures 

acceptable consequence in the event of Main Steam Line Break by 

isolating the affected steam generator. The input to Reactor Protective 

System is described in the Bases of Technical Specification 3.3.1.

System Function: MFW-05 Cri 1 Cri 2 Cri 3

Isolate Steam Generators on high level override at 

85% level.

FP EQ PTS AT SB

Comment: Provides equipment protection only and no credit is taken in the safety 

analysis per FSAR 7.5.2.3. The associated level transmitters are in scope 

as safe shutdown equipment shown on Fire Protection drawings, but only 

for pressure boundary in support of functions MFW-01 and AFW-01.

System Function: MFW-06 Cri 1 Cri 2 Cri 3

Manually isolate the Main Feed Water System with 

the main feed water block valves.

FP EQ PTS AT SB

Comment: This is an operator action directed by Emergency Operating Procedures 

and no credit is taken in the accident analysis. This is redundant to closure 

of the MFW regulating valves and the MFW regulating bypass valves.
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FSAR Reference

Additional Feedwater System details are provided in Section 14.13, Section 

14.14, Section 14.15, Section 14.18, Section 5.2, Section 7.4, Section 9.7, 

Section 7.2, Section 5.1, Section 7.7, Section 9.6, Section 10.2, and Section 

7.5 of the FSAR.

System Function: MFW-07 Cri 1 Cri 2 Cri 3

Provide Steam Generator level and pressure 

indication.

FP EQ PTS AT SB

X

Comment: The Bases of Technical Specification 3.3.7 indicates that the Steam 

Generator level indication is used during a tube rupture event to determine 

which Steam Generator has the ruptured tube. It is also used to determine 

when to initiate once through cooling on low water level. The Bases also 

indicates Steam Generator pressure is a Type A, Category 1 variable used 

in accident identification, including Loss of Coolant, and Steam Line 

Break. Redundant monitoring capability is provided by two channels of 

instrumentation for each Steam Generator. FSAR Table 5.2-5 (I&C 

Component Classification) includes Wide Range Steam Generator Levels, 

which are Safety Class 1E.

System Function: MFW-08 Cri 1 Cri 2 Cri 3

Manually align the Main Feed Water System 

valves to support low pressure feed with the 

condensate pumps.

FP EQ PTS AT SB

Comment: This is an operator action driven by Emergency Operating Procedures and 

no credit is taken in the accident analysis.

System Function: MFW-09 Cri 1 Cri 2 Cri 3

Provide means of containment isolation for Class 

C-1 penetrations.

FP EQ PTS AT SB

X

Comment: The MFW piping is routed through Containment Penetrations. In each 

situation, a single check valve is the means of containment isolation. 

FSAR 5.1.6.9 provides justification of using single check valve for 

containment isolation for MFW and AFW systems. This function is 

associated with the valves and pipe required to ensure containment 

isolation in the MFW system. Components associated with the processing 

of electrical signals to initiate automatic isolation upon CHP and CHR are 

dispositioned under the Containment Isolation and Penetration (CIS) 

system. The penetrations are dispositioned within the Containment 

Structure evaluation.
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Scoping Boundary Drawings

The scoping boundary drawings for the Feedwater System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-3 along with each Component Group’s intended 

function(s).

LR-M-201, Sheet 2

LR-M-205, Sheet 2

LR-M-205, Sheet 2A

LR-M-206, Sheet 1

LR-M-207, Sheet 1

LR-M-207, Sheet 1A

LR-M-207, Sheet 1C

LR-M-207, Sheet 2

LR-M-212, Sheet 2

LR-M-212, Sheet 3

LR-M-214, Sheet 3

LR-M-220, Sheet 1

LR-M-220, Sheet 2

LR-M-225, Sheet 2

Table 2.3.4-3 Feedwater System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Indicators/Recorders Fluid Pressure Boundary

Pipe & Fittings

Flow Restriction

Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Turbines Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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2.3.4.4 Heater Extraction and Drain System

System Description

In the Heater Extraction and Drain (HED) System, extraction steam is supplied 

to the feedwater heaters from the high pressure (HP) and low pressure (LP) 

turbines as required by the plant thermal cycle. During normal operation, 

feedwater heating stages 1 through 4 are supplied by the LP turbines extraction 

steam, and heating stage 5 is supplied from the HP turbine exhaust crossunder 

to the moisture separator reheater. Feedwater heating stage 6, high pressure, 

is supplied by HP turbine extraction and the reheater drain tanks. All feedwater 

heaters with sufficient energy to overspeed the turbine have extraction 

nonreturn valves or turbine reheat stop and intercept valves to stop reverse 

steam flow following a turbine trip.

The HED System collects drains from various heaters and returns them to the 

secondary water cycle. Feedwater heater 6 drains cascade to heater 5 and 

then to the moisture separator drain tank which supplies the heater drain 

pumps. Feedwater heaters 4, 3, 2, and 1 are also arranged in a cascaded drain 

system, but ultimately discharge to the main condenser. The system design is 

to inject the higher temperature drains to the shell side of the feedwater heaters 

closer to the steam generators. This allows the feedwater to be progressively 

heated until it is just a few degrees below main steam temperature when the 

feedwater is injected into the steam generators. This also increases the thermal 

efficiency of the steam/water cycle.

Since the failure of some non-safety related SSCs in the Heater Extraction and 

Drain System could affect the capability of SR SSCs to perform their safety 

function, they are considered to be in-scope in accordance with 10 CFR 

54.4(a)(2). In addition, some SSCs are considered in-scope due to Fire 

Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Heater Extraction and Drain 

System are described as follows: 1) The piping, valves and components from 

extraction steam supply lines downstream of the HP turbine Bleeder Trip Valves 

to feedwater heaters E-6A/B, 2) A portion of the HP turbine exhaust crossunder 

piping to feedwater heaters E-5A/B, 3) The piping, valves and components from 

the heater drains from heaters E-6A/B, cascade to heater E-5A/B, and then to 

the moisture separator drain tank (T-5), 4) The piping, valves and components 

from T-5 through the heater drain pumps, and the discharge headers to flow 

element FE-0786 and 5) Part of the extraction steam lines to the plant heating 

system located upstream of the plant heating steam trap ST-0672 and pipe 

header HB-27-8” through CV-0668 to pipe header JB-11-2”.
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The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

HED non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Turbine Building.

HED non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building.

The portions of the Heater Extraction and Drain System containing components 

subject to an AMR include accumulator, heat exchangers, pipe & fittings, 

fasteners, pumps, flow elements, steam traps, and valves. The NSAS 

components added into scope by the 10 CFR 54.4(a)(2) scoping boundary 

expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Heater Extraction and 

Drain System is provided in the summary below.

System Function: HED-01 Cri 1 Cri 2 Cri 3

Utilize extraction steam to preheat condensate 

and feedwater and provide a warm water suction 

supply to the MFW pumps via the heater drain 

pumps.

FP EQ PTS AT SB

Comment: This function is to support normal plant operation only. No safety functions 

are involved and this function is not in scope for license renewal. Some 

segments of the associated piping systems have potential to impact 

design function of the surrounding safety-related equipment upon 

postulated pipe failures. The evaluation of this failure is covered by 

System Function HED-NSAS.
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FSAR Reference

Additional Heater Extraction and Drain System details are provided in Section 

7.5 and Section 9.8 of the FSAR.

System Function: HED-02 Cri 1 Cri 2 Cri 3

Close bleeder trip valves to prevent turbine 

overspeed via reverse steam flow from the heaters 

to the turbine following a turbine trip.

FP EQ PTS AT SB

Comment: As described in FSAR 7.5.3.6, the steam required to produce turbine 

overspeed has to come from either the main steam system or from water 

flashing in feedwater heaters and moisture separators after a turbine trip. 

All feedwater heaters with sufficient energy to overspeed the turbine have 

extraction nonreturn valves. However, this system function does not 

support a license renewal criterion.

System Function: HED-03 Cri 1 Cri 2 Cri 3

The HVAC system normally uses extraction steam, 

from the low-pressure turbine, as source of plant 

heating Steam.

FP EQ PTS AT SB

Comment: This function is to support normal plant operation only. No safety functions 

are involved. Some segments of the associated piping systems have 

potential to impact design function of the surrounding safety-related 

equipment upon postulated pipe failures. The evaluation of this failure is 

covered by System Function HED-NSAS.

System Function: HED-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: The main feedwater, condensate and heater drain pumps must be off to 

provide feedwater isolation to the steam generators. Ensuring that these 

pumps are off will accomplish the feedwater isolation function to the steam 

generators.

System Function: HED-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The HED system contains non-safety related components that are 

attached to safety related components and non-safety related components 

containing liquids located in an area that also contains safety related 

components. 
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Scoping Boundary Drawings

The scoping boundary drawings for the Heater Extraction and Drain System are 

listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-4 along with each Component Group’s intended 

function(s). 

2.3.4.5 Main Air Ejection and Gland Seal System

System Description

In the Main Air Ejection and Gland Seal (AES) System, noncondensible gases 

are removed from the main condenser during operation by the steam jet air 

ejectors, and during start-up by the condenser vacuum pump, hogging air 

ejector and the steam jet air ejectors. The condenser vacuum pump is used to 

LR-M-206, Sheet 1

LR-M-206, Sheet 1A

LR-M-206, Sheet 1B

LR-M-206, Sheet 2

LR-M-207, Sheet 1C

LR-M-215, Sheet 1A

Table 2.3.4-4 Heater Extraction and Drain System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Transmitter/Element Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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establish a partial condenser vacuum during start-up, and to allow testing of the 

main condenser for leakage while the plant is shut down. 

The gland seal system provides steam seal on main turbine shaft to prevent air 

inleakage and maintain condenser vacuum. Steam supplies for sealing the 

main turbines pass through pressure reducing stations off the main steam 

supply line. The gland seal exhaust is condensed through the gland seal 

condenser and returned to steam-condensate cycle at the condenser hotwell.

Since the failure of some non-safety related SSCs in the Main Air Ejection and 

Gland Seal System could affect the capability of SR SSCs to perform their 

safety function, they are considered to be in-scope in accordance with 10 CFR 

54.4(a)(2). In addition, some SSCs are considered in-scope due to Fire 

Protection in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Main air Ejection and gland Seal 

System can be described as follows: 1) The piping, valves and components 

from Main Steam piping, through the Hogging Air Ejector, the muffler, and to 

outside the turbine building; and 2) The piping, valves and components from 

Main Steam piping, through the Steam Jet Air Ejectors, to the after-condenser. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries were expanded in accordance with current NRC 

guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

AES non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Turbine Building.

The portions of the Main Air Ejection and Gland Seal System containing 

components subject to an AMR include fans, strainers, heat exchangers, filters, 

piping & fittings, fasteners, steam trap, and valves. The NSAS components 

added into scope by the 10 CFR 54.4(a)(2) scoping boundary expansion are 

subject to AMR.
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System Function Listing

A comprehensive listing of functions associated with the Main Air Ejection and 

Gland Seal System is provided in the summary below.

System Function: AES-01 Cri 1 Cri 2 Cri 3

Provide condenser vacuum via steam jet air 

ejectors.

FP EQ PTS AT SB

Comment: Maintaining condenser vacuum by removing noncondensible gases from 

the condenser supports plant start-up and normal operation. This function 

does not meet any of the LR criteria.

System Function: AES-02 Cri 1 Cri 2 Cri 3

Provide decay heat removal via steaming of the 

steam generators through the hogging air ejector.

FP EQ PTS AT SB

Comment: Hot standby/hot shutdown decay heat removal can be accomplished by 

releasing steam to the atmosphere using the Atmospheric Dump Valves or 

the hogging air ejector. This is a normal operating function and is not in 

scope for license renewal. However, as described in FSAR 9.6.8.3, this 

same method and systems/components are used to accomplish pressure 

reduction and cooldown in Appendix R safe shutdown analysis. See 

AES-FP for the fire-protection-related function.

System Function: AES-03 Cri 1 Cri 2 Cri 3

Provide steam seal on main turbine shaft to 

maintain condenser vacuum.

FP EQ PTS AT SB

Comment: This system function of maintaining condenser vacuum is to support plant 

start-up and normal operation only. No LR criteria are involved in this 

system function.

System Function: AES-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for fire protection.

FP EQ PTS AT SB

X

Comment: The AES system contains components that are required for Appendix R 

safe shutdown.

System Function: AES-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The AES system contains non-safety related components containing 

liquids located in an area that also contains safety related components. 
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FSAR Reference

Additional Main Air Ejection and Gland Seal System details are provided in 

Section 10.2 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Main Air Ejection and Gland Seal 

System are listed below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-5 along with each Component Group’s intended 

function(s). 

2.3.4.6 Main Steam System

System Description

In the Main Steam System (MSS), steam generated in the steam generators 

passes through two 36-inch headers and main steam isolation valves (MSIVs) 

to the turbine stop valves. Each main steam header is provided with 12 

spring-loaded safety valves (MSSVs) and 2 atmospheric dump valves (ADVs) 

LR-M-205, Sheet 1

LR-M-206, Sheet 1B

LR-M-206, Sheet 1C

LR-M-207, Sheet 1B

Table 2.3.4-5 Main Air Ejection and Gland Seal System

Component Group Intended Function

Blowers Fans Compressor Vacuum Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
Page 2-188 

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upstream of the MSIVs. In addition, there is a steam bypass to condenser 

downstream of the MSIVs. The main steam line also supplies steam for the 

steam jet air ejectors, the heating steam for the reheaters, the steam supply to 

the steam generator feed pump turbine drivers, and steam supply to the 

turbine-driven auxiliary feed pump turbine driver which is connected upstream 

of an MSIV.

The MSIVs are provided to isolate the steam generators to (1) prevent the 

uncontrolled release of radioactivity in the unlikely event of a steam generator 

tube failure, (2) lessen a rapid uncontrolled cool down of the Primary Coolant 

System in the event of a main steam line break by limiting the blowdown from a 

single steam generator, and (3) limit the steam discharge to the containment 

from the affected steam generator in the event of the rupture of one main steam 

line inside containment. The design basis of the ADVs is to prevent lifting of the 

MSSVs following a turbine and reactor trip, and to provide the capability to cool 

the plant to Shutdown Cooling (SDC) System entry conditions when condenser 

vacuum is lost. The turbine bypass to the main condenser provides for removal 

of reactor decay heat following normal reactor shutdown. Overpressure 

protection for the shell side of the steam generators and the main steam line 

piping up to the inlet of the turbine stop valve is provided by the MSSVs. The 

MSSVs also provide protection against overpressurizing the Primary Coolant 

Pressure Boundary by providing a heat sink for the removal of energy from the 

Primary Coolant System if the preferred heat sink, provided by the condenser 

and Circulating Water System, is not available. 

A subsystem of Main Steam is Steam Generator Blowdown. The steam 

generator blowdown subsystem is designed to process steam generator 

blowdown water. A minimum continuous blowdown is normally maintained for 

effective steam generator chemistry control. Other functions of the subsystem 

include the capability to clean up the condenser hotwell prior to start up by 

recirculating the water through the blowdown demineralizers, and the capability 

to recirculate steam generator secondary side water, for treatment purposes, 

during cold shutdown conditions. 

The steam generator blowdown subsystem consists of flash tank, blowdown 

tank, two blowdown pumps, blowdown heat exchanger, blowdown filter, 

blowdown demineralizers, piping, valves and instrumentation. The subsystem 

is continuously monitored by a process monitor to detect radioactivity which 

may have leaked into the steam generator from the primary system.

The description above results in some SSCs in this system being considered 

in-scope in accordance with 10 CFR 54.4(a)(1). Since some SSCs in the Main 

Steam System are non-safety related and their failure could affect the capability 
Page 2-189 

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of SR SSCs to perform their safety function, they are considered to be in-scope 

in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are considered 

in-scope due to ATWS, Environmental Qualification, Fire Protection, and 

Station Blackout in accordance with 10 CFR 54.4(a)(3).

The boundaries of the in-scope portions of the Main Steam System are 

described as follows: 1) The piping, valves and components from each S/G 

E-50A/B, through flow elements FE-0702/0704, through Containment 

penetrations 2 and 3 (including steam generator blowdown system to the flash 

tank, the main steam safety valves (MSSVs), and atmospheric dump valves 

(ADVs)), through the Main Steam Isolation Valves (MSIVs) to the main steam 

stop valves; 2) The piping, valves and components to the driving turbines of 

auxiliary feedwater pump and main feedwater pumps, and some segments of 

the main turbine crossunder piping and connections to the moisture separators 

and reheaters (MSRs); 3) The piping, valves, and components supplying steam 

through the steam jet air ejectors (SJAE) to the after-condenser; and 4) The 

piping, valves and components supplying steam through the hogging air ejector 

and silencer to outside the turbine building. 

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

MSS non-safety related piping and components that are directly attached to 

safety related piping and components out to the first seismic anchor or 

equivalent anchor. Where base mounted components are credited as an 

anchor, they are also included in scope. Pipe supports for the newly added 

piping and components are also in scope. The new piping components are 

located in the Containment Building, Auxiliary Building and the Turbine 

Building.

MSS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

components are located in the Containment Building, Auxiliary Building and 

Turbine Building.

The portions of the Main Steam System containing components subject to an 

AMR include accumulators, strainers, filters, heat exchangers, pumps, level 

glasses, piping & fittings, fasteners, ejectors, steam traps and valves. The 

NSAS components added into scope by the 10 CFR 54.4(a)(2) scoping 

boundary expansion are subject to AMR.
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System Function Listing

A comprehensive listing of functions associated with the Main Steam System, 

or specific components contained in the system, is provided in the summary 

below.

System Function: BLD-01 Cri 1 Cri 2 Cri 3

Provide ability to sample each steam generator for 

activity and lithium as directed by the EOP.

FP EQ PTS AT SB

Comment: This function is not within the scope of license renewal. Steam Generator 

sampling for activity and lithium is one of several potential methods 

available for diagnosis of Steam Generator Tube Rupture (SGTR) to 

determine the most affected steam generator for isolation. This system 

function may be not available with loss of service water to the sample 

coolers. Other diagnosis information included in Emergency Operating 

Procedures includes Steam Generator level, Pressurizer pressure, 

Pressurizer level.

System Function: BLD-02 Cri 1 Cri 2 Cri 3

Automatically close the containment isolation 

valves and blowdown system valves on 

Containment High Pressure or Containment High 

Radiation.

FP EQ PTS AT SB

X

Comment: This function is associated with the valves and pipe required to ensure 

containment isolation in the blowdown subsystem. Components 

associated with the processing of electrical signals to initiate automatic 

isolation upon CHP and CHR are dispositioned under the Containment 

Isolation and Penetration (CIS) system. The penetrations are 

dispositioned within the Containment Structure evaluation.

System Function: MSS-01 Cri 1 Cri 2 Cri 3

Pathway for steam which provides motive force to 

the main turbine.

FP EQ PTS AT SB

Comment: Steam supply to the Main Turbine is to support normal operation only, and 

is outside the scope of license renewal. However, failure of some 

segments of steam pipes in the pathway may cause damage to some 

safety related components, such as Component Cooling Water pumps. 

The effects of failure of non-safety segments on the safety related 

components are addressed in System Function MSS-NSAS.
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System Function: MSS-02 Cri 1 Cri 2 Cri 3

Pathway for steam which provides motive force to 

the main feedwater pump turbines.

FP EQ PTS AT SB

Comment: Steam supply to the feedwater pump turbines is to support normal 

operation only, and is outside the scope of license renewal. However, 

failure of some segments of steam pipes in the pathway may cause 

damage to some safety related components. The effects of failure of 

non-safety segments on the safety related components are addressed in 

System Function MSS-NSAS.

System Function: MSS-03 Cri 1 Cri 2 Cri 3

Pathway for steam which provides motive force to 

the auxiliary feedwater pump turbine.

FP EQ PTS AT SB

X

Comment:

System Function: MSS-04 Cri 1 Cri 2 Cri 3

Provide a steaming path via the atmospheric 

steam dump valves during a plant transient or 

plant cooldown.

FP EQ PTS AT SB

Comment: Although ADVs are assumed to be used to cool down the plant to 

Shutdown Cooling entry condition, it is not a safety-related requirement to 

take the plant to cold shutdown. Palisades is licensed as a “Hot Shutdown” 

plant) following a transient. Thus this function of the ADVs does not meet 

Criterion #1. However, these ADVs are credited to meet the requirements 

of Station Blackout events, and are credited for Appendix R safe 

shutdown. The equivalent Criterion 3 functions are captured under 

function MSS-SB and MSS-FP.

System Function: MSS-05 Cri 1 Cri 2 Cri 3

Provide a steaming path via the turbine bypass 

valve during a plant transient or plant cooldown.

FP EQ PTS AT SB

Comment: Although the turbine bypass valve can be used by the operator to cool 

down the plant to Shutdown Cooling entry conditions if the condenser, as 

the preferred heat sink, is available, this function is not credited for 

mitigation of plant transients. 

System Function: MSS-06 Cri 1 Cri 2 Cri 3

Close both MSIVs on receipt of a low Steam 

Generator pressure signal.

FP EQ PTS AT SB

X

Comment: Main steam isolation will occur on containment high pressure or steam 

generator low pressure (see FSAR Section 7.2.3.8) based on containment 

pressurization considerations for a steam line break. A low steam 

generator secondary pressure signal is provided to protect against 

excessively high steam flow caused by a steam line break.
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System Function: MSS-07 Cri 1 Cri 2 Cri 3

Close the MSIVs upon receipt of Containment 

High Pressure.

FP EQ PTS AT SB

X

Comment: Containment high-pressure (CHP) signal will initiate closure of the main 

steam isolation valves to reduce the inventory blowdown from the intact 

steam generator in the case of a main steam line break, reducing the peak 

containment pressure and temperature as required in the accident 

analysis.

System Function: MSS-08 Cri 1 Cri 2 Cri 3

Prevent release of contents of the secondary side 

of the steam generator(s) in the event of a tube 

leak/rupture.

FP EQ PTS AT SB

X

Comment: In the event of a steam generator tube rupture, closure of the MSIVs 

isolates the affected steam generator from the intact steam generator and 

minimizes radiological releases.

System Function: MSS-09 Cri 1 Cri 2 Cri 3

Provide passive overpressure protection of the 

Main Steam System.

FP EQ PTS AT SB

X

Comment: The Main Steam Safety Valves (MSSVs) provide overpressure protection 

for the secondary system. The MSSVs also provide protection against 

overpressurizing the Primary Coolant pressure boundary by providing a 

heat sink for the removal of energy from the Primary Coolant System. 

System Function: MSS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: The design for compliance with the ATWS rule includes an independent 

and diverse turbine trip. This function only includes the closure of main 

turbine stop valves to support ATWS. The actuation of associated relays is 

covered in Turbine Generator System function TGS-AT.

System Function: MSS-EQ Cri 1 Cri 2 Cri 3

The system contains components required by the 

current licensing basis for Environmental 

Qualification.

FP EQ PTS AT SB

X

Comment:
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FSAR Reference

Additional Main Steam System details are provided in Section 5.6, Section 7.3, 

Section 7.2, Section 7.5, and Section 9.6, Section 10.2, and Section 14.15 of 

the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Main Steam System are listed below:

System Function: MSS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: Some components of MSS are involved in the mitigation of this Regulated 

Event. Also, FSAR 9.6.8.3 indicates that for post fire safe shutdown, the 

systems and equipment which may be utilized for decay heat removal 

while maintaining the plant at hot standby or hot shutdown include the 

main steam system, the atmospheric steam dump valves, the hogging air 

ejector, and the main steam safety valves.

System Function: MSS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: Some Main Steam components are non-safety related. They are attached 

to and located above safety related components. The MSS contains steam 

in an area that also contains safety related components. 

System Function: MSS-SB Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: As described in FSAR 10.2.1, the atmospheric steam dump valves have a 

back up nitrogen supply to allow steam generator pressure control during 

station blackout.

LR-M-201, Sheet 1

LR-M-205, Sheet 1

LR-M-205, Sheet 1A

LR-M-205, Sheet 1B

LR-M-205, Sheet 2

LR-M-205, Sheet 2A

LR-M-206, Sheet 1

LR-M-206, Sheet 1B

LR-M-207, Sheet 1

LR-M-210, Sheet 1

LR-M-212, Sheet 3

LR-M-222, Sheet 1

LR-M-223, Sheet 1B

LR-M-226, Sheet 1

LR-M-226, Sheet 1A

LR-M-651, Sheet 1
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Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-6 along with each Component Group’s intended 

function(s).

2.3.4.7 Turbine Generator System

System Description

The Turbine Generator System (TGS) consists of the main turbines, main 

electrical generator and various supporting subsystems. The turbine is an 

1,800 r/min tandem compound, 3 cylinder, quadruple flow, indoor unit. 

Saturated steam is supplied to the turbine throttle from the steam generators 

through four stop valves and four governing control valves. The steam flows 

through a double-flow, high-pressure turbine and four combination moisture 

Table 2.3.4-6 Main Steam System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Ejectors Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Indicators/Recorders

(Level glasses)

Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Traps (Steam) Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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separator-reheaters in parallel, and two double-flow, low-pressure turbines that 

exhaust to the main condenser.

Turbine control is accomplished with a rapid response electrohydraulic control 

system. In the event of turbine trip initiated from a solenoid trip, overspeed, low 

bearing oil pressure, low condenser vacuum, thrust bearing failure or a manual 

trip, a signal is supplied from the turbine auto-stop oil system to the Reactor 

Protective System to trip the reactor.

The turbine lubricating oil system supplies oil for lubricating the bearings. A 

bypass stream of turbine lubricating oil flows continuously through coalescing 

filters to remove water and other impurities.

The generator is a hydrogen inner cooled unit connected directly to the turbine. 

It is rated for 955 MVA and has the capability to accept the gross output of the 

turbine at rated steam conditions. The generator is made up of a housing, 

stator, exciter, rotor and shaft with sleeve bearings and ventilation blower. 

Generator operation is supported by a hydrogen gas system, a seal oil system 

and a signal system.

The turbine generator controls are the means by which the turbine generator is 

made to meet the electrical load demand placed upon it. The controls consist of 

the following five parts: 1) Operators Interface Panel, 2) Digital Controller & 

Engineers Console, 3) Steam valve servo actuator assemblies, 4) 

High-pressure fluid supply, and 5) Emergency trip. The electronic controller 

performs basic digital computations on reference signals and turbine feed-back 

signals and generates an output to the steam valve actuators. Manual inputs 

and manual functions, plus valve contingencies are also built-in capabilities. 

Since the failure of some non-safety related SSCs in the Turbine Generator 

System could affect the capability of SR SSCs to perform their safety function, 

they are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In 

addition, some SSCs are considered in-scope due to ATWS in accordance with 

10 CFR 54.4(a)(3).

The boundaries of in-scope portions of the Turbine Generator and Crane 

System are described as follows: 1) The HP turbine steam inlet drains to the 

condenser, 2) portions of the HP turbine glands seals and gland seals exhaust 

located below elevation 625', 3) portions of the LR turbine gland seals and 

gland seals exhaust located below elevation 625', 4) Hydrogen Side Seal Oil 

Cooler (E-16A), 5) Air Side Seal Oil Cooler (E16B), 6) portions of the bearing oil 

supply piping, the high pressure seal oil backup piping, the low pressure seal oil 

backup piping and the bearing/control oil return piping located below elevation 

625', 7) the Electro-Hydraulic Control System piping, valves, and components 
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located below elevation 625', and 8) the Main Generator Seal Oil System 

piping, valves and components located below elevation 625'.

The original system scoping boundaries for license renewal included, where 

applicable, non-safety related components that could affect safety-related 

components. The boundaries have been expanded in accordance with current 

NRC guidance for implementation of 10 CFR 54.4(a)(2). The expanded scoping 

boundary includes:

TGS non-safety related components containing steam and/or fluids that are 

located in an area that also contains a safety related component. The 

component types include accumulators, heat exchangers, fasteners (to 

maintain the pressure boundary), filters, piping, fittings, pumps, and valves. The 

components are located in the Turbine Building.

The NSAS components added into scope by the 10 CFR 54.4(a)(2) scoping 

boundary expansion are subject to AMR.

System Function Listing

A comprehensive listing of functions associated with the Turbine Generator 

System is provided in the summary below.

System Function: DEH-01 Cri 1 Cri 2 Cri 3

Provide control and monitoring of the turbine 

governor and stop valves which controls turbine 

speed and generator load.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: DEH-02 Cri 1 Cri 2 Cri 3

Provide turbine protective trips. FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: EHC-01 Cri 1 Cri 2 Cri 3

Provide high pressure fluid which acts as a motive 

force to the main turbine steam admission valves 

and repositions the valves in response to 

electronic commands.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.
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System Function: EHC-02 Cri 1 Cri 2 Cri 3

Provide direct turbine protective trips and provide 

a reactor trip signal to the RPS.

FP EQ PTS AT SB

Comment: This system function provides an immediate reactor trip upon a turbine 

trip. The trip is not taken credit for in FSAR Section 14.12. Additionally, 

FSAR Section 7.2.3.6 states: “The loss of load reactor trip is an 

anticipatory trip which is not required to protect the reactor since the 

primary trip is high primary system pressure.” Therefore, this system 

function does not support a license renewal criterion.

System Function: TGS-01 Cri 1 Cri 2 Cri 3

Provide motive force to the main generator. FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-02 Cri 1 Cri 2 Cri 3

Provide control and monitoring of the main 

generator excitation.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-03 Cri 1 Cri 2 Cri 3

Provide lubrication and seal oil between the main 

generator shaft and seal.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-04 Cri 1 Cri 2 Cri 3

Provide isophase bus cooling. FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-05 Cri 1 Cri 2 Cri 3

Provide gland sealing steam to the main turbine. FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-06 Cri 1 Cri 2 Cri 3

Provide a 10 second time delay on tripping the 

main generator output breaker following a turbine 

trip occurring simultaneously with a loss of offsite 

power.

FP EQ PTS AT SB

Comment: This system function adds additional main coolant pump coastdown time 

to facilitate core heat removal following a turbine trip. FSAR Section 4.4.1 

states: “The most severe electrical failure analyzed, however, is the loss of 

offsite power and no turbine coastdown. The results are within core design 

limits and are presented in Section 14.7." Therefore, this system function 

does not support a license renewal criterion.
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System Function: TGS-07 Cri 1 Cri 2 Cri 3

Close the turbine stop valves and the governor 

valves on demand.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion. The 

turbine stop and governor valves are included in the Main Steam System 

(MSS).

System Function: TGS-08 Cri 1 Cri 2 Cri 3

Circulate cooled hydrogen through the main 

generator.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-09 Cri 1 Cri 2 Cri 3

Provide electrical connection between main 

generator and main transformer.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-10 Cri 1 Cri 2 Cri 3

Produce electrical power for transmission to the 

power grid.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-11 Cri 1 Cri 2 Cri 3

Generate, transfer and regulate the field strength 

that creates and controls the Main Generator's 

power output.

FP EQ PTS AT SB

Comment: This system function does not support a license renewal criterion.

System Function: TGS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: Turbine trip signal is an input to ATWS. The signal circuitry is in TGS. The 

turbine stop valves are in the Main Steam System (MSS).

System Function: TGS-NSAS Cri 1 Cri 2 Cri 3

This system has components in scope of license 

renewal in accordance with 10CFR54.4(a)(2) 

requirements for non-safety affecting safety 

(NSAS).

FP EQ PTS AT SB

X

Comment: The TGS has non-safety related components containing liquids located in 

an area that also contains safety related components. 
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FSAR Reference

Additional Turbine Generator System details are provided in Section 7.5, 

Section 7.2, Section 14.12, Section 14.7, Section 4.4, and Section 8.4 of the 

FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Turbine Generator System are listed 

below:

Components Subject to an AMR

The component groups for this system that require aging management review 

are addressed in Table 2.3.4-7 along with each Component Group’s intended 

function(s). 

LR-M-205, Sheet 1

LR-M-205, Sheet 1A

LR-M-205, Sheet 1B

LR-M-206, Sheet 1B

LR-M-208, Sheet 1

LR-M-214 Sheet 2A

LR-M-214, Sheet 2B

Table 2.3.4-7 Turbine Generator System

Component Group Intended Function

Accumulators Fluid Pressure Boundary

Fasteners Fluid Pressure Boundary

Filters/Strainers Fluid Pressure Boundary

Heat Exchangers Fluid Pressure Boundary

Pipe & Fittings Fluid Pressure Boundary

Pumps Fluid Pressure Boundary

Valves & Dampers Fluid Pressure Boundary
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2.4 Scoping and Screening Results: Containments, Structures, and Component 

Supports

The following structures and structural commodities are addressed in this section:

• Auxiliary Building (Section 2.4.1)

• Component Supports (Section 2.4.2)

• Containment (Section 2.4.3)

• Containment Interior Structures (Section 2.4.4)

• Discharge Structure (Section 2.4.5)

• Feedwater Purity Building (Section 2.4.6)

• Intake Structure (Section 2.4.7)

• Miscellaneous Structural and Bulk Commodities (Section 2.4.8)

• Switchyard and Yard Structures (Section 2.4.9)

• Turbine Building (Section 2.4.10)

2.4.1 Auxiliary Building

Description

The Auxiliary Building, with the exception of the administration area and the access 

control area, is a Class 1 structure. The following facilities, systems and equipment are 

among those located in the auxiliary building:

• Control room

• Emergency diesel generators and related auxiliaries

• New and spent fuel handling, storage and shipment facilities

• Radwaste, chemical and volume control equipment

• Safety Injection System (majority)

• Component Cooling System (majority)

• Containment Spray System (majority)

The reinforced concrete enclosure containing the engineered safeguards equipment is 

located below grade. It is partitioned into two rooms so that one room is operable in the 

event a pipe rupture floods the other room. The partition wall is designed to withstand 

hydrostatic loading over its full height. This building also houses the access control area, 

which controls access to and exit from the various radiation controlled zones.
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The new and spent fuel pools are located adjacent to the three-story concrete enclosure, 

which houses the control room, switchgear and the emergency diesel generators. To 

ensure that the spent fuel pool and tilt pits have a high degree of leak tightness, the walls 

and floors of these cavities are lined with stainless steel plates. Monitoring trenches have 

been provided behind the liner plates to detect any leakage that might occur. 

The main steam and main feedwater lines pass through the southwest corner of the 

auxiliary building. In this region, pipe whip restraints are provided on the turbine building 

side of the main steam and main feedwater isolation valves. These structural steel frames 

are anchored to various auxiliary building concrete walls and slabs. In addition, the jet 

forces resulting from a failure in either one of these lines were considered in the design of 

the walls and slabs that separate these lines from the switchgear and cable spreading 

rooms and from the containment ventilation isolation valves. 

At elevation 590' there are electrical manholes in the 2.4kV Switchgear Room associated 

with safety related Bus 1-C, used for routing cables to various plant areas. Duct banks 

(reinforced concrete encasing rigid steel conduit) run from these manholes, connecting to 

another manhole just outside of the Auxiliary Building. 

Auxiliary Building Radwaste Addition

During 1972 a 124’ x 38’ x 106’-high addition (approximate maximum dimensions) was 

added to the north side of the auxiliary building. This Class 1 structure houses additional 

gaseous, liquid and solid radwaste equipment. The building is constructed on a mat 

foundation. The reinforced concrete slabs and walls were designed as two-way slabs and 

bearing walls.

Auxiliary Building TSC/EER/HVAC Addition

During 1983 a reinforced concrete addition was appended to the north side of the 

auxiliary building for a technical support center (TSC), an electrical equipment room 

(EER) and a heating, ventilating and air conditioning (HVAC) area. The TSC was 

constructed pursuant to NUREG-0696, the HVAC area as a result of the control room 

habitability requirements of NUREG-0737, and the EER area as a result of loads placed 

on the electrical system by the addition of the TSC and HVAC areas. The L-shaped 

structure was added to the roofs of the existing waste gas decay tank/baler room 

(elevation 607’ - 6”) and the diesel generator exhaust muffler enclosure (elevation 629’ - 

2”. 

The portions of the Auxiliary Building that are in-boundary and contain components 

subject to an AMR include the original Auxiliary Building (except administrative areas), 

the Auxiliary Building Radwaste Addition and the Auxiliary Building TSC/EER/HVAC 
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Addition. These structures shelter or support ATWS, EQ, FP (Appendix R), SBO, Safety 

Related and/or NSAS components.

System Function Listing

A comprehensive listing of functions associated with the Auxiliary Building, or specific 

components contained in the structure, is provided in the summary below.

Code S0200-AT Cri 1 Cri 2 Cri 3

Provides shelter or support to ATWS related 

components.

FP EQ PTS AT SB

X

Comment: Most ATWS components are located in the Control Room and Cable 

Spreading Room.

Code S0200-EQ Cri 1 Cri 2 Cri 3

Provides shelter or support to EQ related 

components.

FP EQ PTS AT SB

X

Comment: Many EQ components are in the Class 1 portion of the Auxiliary Building.

Code S0200,B-FP Cri 1 Cri 2 Cri 3

Provides rated fire barrier to confine or retard a fire 

from spreading to or from adjacent areas of the 

plant.

FP EQ PTS AT SB

X

Comment: Auxiliary Building contains Appendix R fire barriers.

Code S0200-SB Cri 1 Cri 2 Cri 3

Provides shelter or support to SBO related 

components

FP EQ PTS AT SB

X

Comment: Several systems required to perform during SBO are in the Class 1 portion 

of the Auxiliary Building.

Code S0200-SR Cri 1 Cri 2 Cri 3

Provides shelter/protection to safety related 

component.

FP EQ PTS AT SB

X

Comment: Most areas of the Auxiliary Building are Consumers Design Class 1 

(Category 1).
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FSAR Reference

Additional Auxiliary Building details are described in Section 5.9 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Auxiliary Building are listed below:

Components/Commodities Subject to an AMR

The component groups for the Auxiliary Building that require aging management review 

are addressed in Table 2.4.1-1 along with each component group’s intended function(s).

Code S0200B-NSAS Cri 1 Cri 2 Cri 3

Provides storage/handling of spent fuel 

assemblies and provides structural support of 

safety related components

FP EQ PTS AT SB

X

Comment: The Access Control area of the Auxiliary Building is Consumers Design 

Class 3. However, concrete walls below the roof slab of Access Control 

Area supports the Load Distribution System (LDS) that is used to transport 

spent fuel assemblies. They are in-scope of 10CFR 54.4. These walls are 

part of the Auxiliary Building framing system which supports safety related 

components. 

Code Architectural (BLA)-FP2 Cri 1 Cri 2 Cri 3

Provides access to remote shutdown panels & 

components in the event of a fire

FP EQ PTS AT SB

X

Comment: Provides access for the operator from the Control Room to Redundant 

Safety Injection Panel EC-33 in Auxiliary Building and Hot Shutdown 

Panels EC-150 & EC-150A in Turbine Building for alternate shutdown 

station. Other Auxiliary Building platforms, stairs, and similar commodities 

that are necessary to provide access to the operators that affects safety 

operations are in-scope.

LR-C3
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Table 2.4.1-1 Auxiliary Building

Component Group Intended Function

Building Framing - Carbon Steel, 

Protected

(column, hanger, beam, truss, 

decking, floor grating or plate, 

catwalk, threaded fastener, 

concrete expansion bolt, column 

base plate, weld, etc.)

HELB Shielding

Pipe Whip Restraint

Shelter/ Protection

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Building Framing - Concrete, 

Below Grade

(wall footing, foundation slab, 

grout, reinforcement, duct banks, 

cable pits, tunnels, etc.)

Flood Protection

Structural Support for Safety 

Related

Building Framing - Concrete, 

Exposed

(foundations, concrete & masonry 

wall, beam, roof slab, grout, 

reinforcements, concrete around 

expansion & grouted anchors)

Flood Protection

Missile Barrier

Radiation Shielding

Shelter/ Protection

Structural Support for Safety 

Related
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Building Framing - Concrete, 

Protected

(foundations, concrete & masonry 

wall, column, pedestal, beam, floor 

slab, grout, reinforcements, 

concrete around expansion & 

grouted anchors, cable pits, 

tunnels, etc.)

Direct Flow

Fire Barrier

HELB Shielding

Missile Barrier

Pipe Whip Restraint

Radiation Shielding

Shelter/ Protection

Structural Support for Safety 

Related

Flood Barrier - Carbon Steel, 

Exposed

(water tight doors)

Flood Protection

Structural Support for Safety 

Related

Flood Barrier - Carbon Steel, 

Protected

(water tight doors and gate)

Flood Protection

Structural Support for Safety 

Related

Fuel Related component - Carbon 

Steel, Protected

(anchor bolts for SFP gates, liners, 

transfer tube appurtenances)

Structural Support for Safety 

Related

Fuel Related Component - 

Stainless, Protected

(anchor bolts for SFP gates, liners, 

transfer tube appurtenances)

Structural Support for Safety 

Related

Table 2.4.1-1 Auxiliary Building

Component Group Intended Function
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Fuel Related Component - 

Stainless, Borated

(liner plates, gates, transfer tube 

expansion bellows)

Expansion / Separation

Fluid Pressure Boundary

Structural Support for Safety 

Related

HELB/MELB Component - Carbon 

Steel, Protected

(doors, scuttle, blowout panels, 

floor drains & screens, guard pipes, 

louvers, whip restraints, bellows, 

spray shields, etc.)

Direct Flow

Flood Protection

HELB Shielding

Pipe Whip Restraint

HELB/MELB Component - 

Concrete, Protected

(curbs & pipe whip restraint grout, 

concrete at locations of expansion 

& grouted anchors)

Direct Flow

Flood Protection

HELB Shielding

Pipe Whip Restraint

HVAC Component - Stainless, 

Protected

(control room vestibule doors)

Fluid Pressure boundary

Structure Functional Support

HVAC Component - Carbon Steel, 

Protected

(Control Room vestibule door)

Fluid Pressure Boundary

Structural Support for Safety 

Related

HVAC Component - Concrete, 

Protected

(Control Room vestibules, concrete 

& masonry walls, floors, ceilings)

Fluid Pressure Boundary

Structural Support for Safety 

Related

HVAC Component - Galvanized, 

Protected

(damper & louver frames)

Fire Barrier

Structural Support for Safety 

Related

Table 2.4.1-1 Auxiliary Building

Component Group Intended Function
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2.4.2 Component Supports

Description

This commodity group includes ASME and non-ASME pipe supports, ASME Class 1 

equipment supports, as well as general mechanical and electrical component supports 

(e.g., HVAC, cable trays, conduits, etc.). These assets consist primarily of steel and 

concrete assets included under GALL Section IIIB for supports and GALL Section VII A1 

and A2 for new fuel and spent fuel storage, respectively. They are grouped together 

based on their similar “support” function, material, environments, and expected aging 

management programs. This commodity group includes the following categories of 

support components:

Missile Shield - Carbon Steel, 

Protected

(steel doors and structural steel 

missile barrier)

Missile Barrier

Structural Support for Safety 

Related

Operator Access Component - 

Carbon Steel, Protected

(stairs, floors, platforms, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Operator Access Component - 

Concrete, Protected

(stairs, floors, platforms, concrete 

at locations of expansion & grouted 

anchors)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Operator Access Component - 

Galvanized, Protected

(stairs, walkways, removable 

platform, welds, bolted 

connections)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Table 2.4.1-1 Auxiliary Building

Component Group Intended Function
Page 2-208 

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ASME CLASS 1 PIPING & MECHANICAL COMPONENT SUPPORTS

This support commodity includes as applicable, but is not limited to, 

support/hanger/frame/rack/housing/skid composed of prefab or rolled steel 

shapes, rods, clamps, fasteners (screws, bolts, clips, concrete expansion bolts, 

inserts, anchor bolts) and welds. ASME Class 1 Components include Reactor 

Vessel, Steam Generators, Primary Coolant Pumps, Pressurizer, and 

Regenerative Heat Exchanger. Also included are stainless steel pipe support 

lug, rolled plates, shapes, and Incore Instrumentation (ICI) Support Stand 

Assemblies; Reactor Head Vent pipe supports; Lubrite bearing plates; building 

concrete at locations of expansion and grouted anchors; and grout pads for 

support base plates. (GALL IIIB1)

ASME CLASS 2 & 3 PIPING & MECHANICAL COMPONENT SUPPORTS

This support commodity includes as applicable, but is not limited to, 

support/hanger/frame/rack/housing/skid composed of prefab or rolled steel 

shapes, fasteners (screws, bolts, clips, concrete expansion bolts, inserts, 

anchor bolts) and welds. Also included are manholes, Lubrite or Fluorogold 

bearing plates, building concrete at locations of expansion and grouted 

anchors, and grout pads for support base plates. (GALL IIIB1)

NON-ASME PIPING & MECHANICAL COMPONENT SUPPORTS

This support commodity includes as applicable, but is not limited to: 

support/hanger/tray/frame/rack composed of prefab or rolled steel shapes, 

rods, clamps, fasteners (screws, bolts, clips, concrete expansion bolts, inserts, 

anchor bolts) and welds. Commodity includes support and anchorage of HVAC 

Ducts, TubeTrack, instrument tubing, manhole covers, building concrete at 

locations of expansion and grouted anchors, and grout pads for support base 

plates. This includes supports for Emergency Diesel Generator (EDG), HVAC 

System Components, and other miscellaneous mechanical equipment. (GALL 

IIIB2 & B4)

ELECTRICAL COMPONENT SUPPORTS

This support commodity includes, as applicable, electrical component supports; 

anchorage of cable trays, conduit, racks, panels, cabinets, and enclosures for 

electrical equipment and instrumentation; support/hanger/tray/frame/rack 

composed of prefab or rolled steel shapes, fasteners (screws, bolts, clips, 

concrete expansion bolts, inserts, anchor bolts) and welds; manholes, cabinets, 

panels, and boxes; building concrete at locations of expansion and grouted 

anchors; and grout pads for support base plates. (GALL IIIB2 & B3)
Page 2-209 

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NEW FUEL STORAGE RACK

This commodity is the aluminum New Fuel Storage Rack in the Auxiliary 

Building in the new fuel storage pit. (GALL VIIA1)

SPENT FUEL STORAGE RACK-AUXILIARY BUILDING

This commodity is the stainless steel spent fuel racks. It also includes the boron 

carbide neutron absorber material credited in the spent fuel pool criticality 

analysis. Note that Boraflex is not credited in the criticality analysis. 

Supports/anchorage for the racks are included.(GALL VIIA2)

The portions of the Component Supports commodity containing components subject to 

an AMR include ASME and non-ASME pipe supports, ASME Class 1 equipment supports 

(including new fuel and spent fuel storage), as well as general mechanical and electrical 

component supports (e.g., HVAC, cable trays, conduits, etc.).

System Function Listing

A comprehensive listing of functions associated with Component Supports is provided in 

the summary below.

Code ELECTRICAL SUPPORT (BLE) -AT Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Electrical 

ATWS related commodities

FP EQ PTS AT SB

X

Comment: ATWS components are located in the Control Room (Auxiliary Bldg.), 

Cable Spreading Room (Auxiliary Bldg.), and Containment Bldg. 

Code ELECTRICAL SUPPORT (BLE) -EQ Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Electrical EQ 

related commodities

FP EQ PTS AT SB

X

Comment: Electrical components that are within the scope of EQ Program are 

basically identified within different Mechanical & Electrical Plant Systems. 

Civil/Structural supports for these components are within the scope of 

10CFR 54. Various Civil/Structural devices protect and ensure the 

environmental conditions for electrical components evaluated in the EQ 

Program. 

Code ELECTRICAL SUPPORT (BLE) -FP Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Electrical Fire 

Protection related commodities.

FP EQ PTS AT SB

X

Comment: Electrical components supporting Fire Protection System are identified in 

Mechanical system FPS, Fire Protection. Supports for these components 

are within the scope of 10CFR54. Civil/Structural supports for Fire 

Protection System electrical components include, but are not limited to 

alarms and detectors
Page 2-210 

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Code ELECTRICAL SUPPORT (BLE) 

-NSAS

Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for non-safety 

related Electrical commodities affecting safety 

related commodities.

FP EQ PTS AT SB

X

Comment: This Civil/Structural group of supports are non-safety; however, they 

include components designed seismically to assure that the non-safety 

related electrical components being supported will not fall on other safety 

related components and prevent them from functioning as intended. They 

also include supports for non-safety related equipment credited with 

maintaining the functions of safety related equipment and whose failure 

could affect safety related components; such as, the Warm Water Recirc 

Pump that mitigates Service Water System icing. Anchorages and 

supports of non-safety related ancillary items (dollies, gas bottles, etc.), 

located such that during an earthquake, they might be dislodged and 

impact and damage safety related equipment during an earthquake are 

within the scope the 10CFR 54.

Code ELECTRICAL SUPPORT (BLE) -SB Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Electrical 

SBO related commodities.

FP EQ PTS AT SB

X

Comment: Provides support to Station Blackout components.

Code ELECTRICAL SUPPORT (BLE) -SR Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for safety related 

Electrical commodities.

FP EQ PTS AT SB

X

Comment: Supports for safety related Class 1E equipment are safety related 

Civil/Structural supports.

Code MECHANICAL SUPPORT (BLM) -EQ Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Mechanical 

EQ related commodities.

FP EQ PTS AT SB

X

Comment: Mechanical components that are within the scope of EQ Program are 

identified within different Mechanical & Electrical Plant Systems. 

Civil/Structural supports for these components are within the scope of 

10CFR 54. Examples of these commodities are: flooding curbs, pipe whip 

restraints, jet impingement and spray shields.

Code MECHANICAL SUPPORT (BLM) -FP Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for Mechanical 

Fire Protection System

FP EQ PTS AT SB

X

Comment: Mechanical components for the Fire Protection System are identified in 

Mechanical system FPS, Fire Protection. Supports for these components 

are within the scope of 10CFR 54. Also includes components credited in 

the appendix R safe shutdown analysis.
Page 2-211 

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FSAR Reference

None.

Scoping Boundary Drawings

None.

Components/Commodities Subject to an AMR

The component groups for Component Supports that require aging management review 

are addressed in Table 2.4.2-1 along with each component group’s intended function(s).

Code MECHANICAL SUPPORT (BLM) 

-NSAS

Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for non-safety 

related Mechanical commodities affecting safety 

related commodities.

FP EQ PTS AT SB

X

Comment: This Civil/Structural group of supports are non-safety; however, they are 

in-scope of 10CFR54.4 to assure that the non-safety related mechanical 

components being supported will not fall on other safety related 

components and prevent them from functioning as intended.

Code MECHANICAL SUPPORT (BLM) -SR Cri 1 Cri 2 Cri 3

Provides Civil/Structural supports for safety related 

Mechanical commodities and fuel storage.

FP EQ PTS AT SB

X

Comment: Supports for safety related Mechanical commodities meet Criterion 1 of 

10CFR54.4 and are therefore, in-scope for License Renewal as a safety 

related Civil/Structural support commodity.

Table 2.4.2-1 Component Supports

Component Group Intended Function

ASME 1 Support - Containment - Carbon Steel, 

Protected

Structural Support for Safety 

Related

ASME 1 Support - Containment - Concrete, Protected Structural Support for Safety 

Related

ASME 1 Support - Containment - Sliding Material, 

Cont Cavity

Expansion/Separation

Structural Support for Safety 

Related
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ASME 1 Support - Containment - Sliding Material, 

Protected

Expansion/Separation

Structural Support for Safety 

Related

ASME 2 & 3 Support - Turbine (Water Treatment 

Area) - Carbon Steel, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME 2 & 3 Support - Turbine (Water Treatment 

Area) - Concrete, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 1 Tubing Support - Auxiliary Bldg, 

Carbon Steel, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Auxiliary Bldg, Cast Iron, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Auxiliary Bldg, Concrete, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Auxiliary Bldg, Galvanized, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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ASME Class 2 & 3 Piping & Mechanical Component 

Support - Auxiliary Bldg, Sliding Material, Protected

Expansion/Separation

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Carbon Steel, Cont 

Cavity

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Carbon Steel, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Concrete, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Galvanized, Cont Cavity

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Galvanized, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Sliding Material, 

Protected

Expansion/Separation

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Containment Bldg, Stainless, Borated

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Intake Structure Bldg, Carbon Steel, 

Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Intake Structure Bldg, Concrete, Protected

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Intake Structure Bldg, Galvanized, 

Protected

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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ASME Class 2 & 3 Piping & Mechanical Component 

Support - Turbine Bldg, Carbon Steel, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Turbine Bldg, Concrete, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Turbine Bldg, Galvanized, Protected

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Turbine Bldg, Sliding, Protected

Expansion/Separation

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Yard, Aluminum, Exposed

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Yard, Carbon Steel, Below Grade

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Yard, Carbon Steel, Exposed

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

ASME Class 2 & 3 Piping & Mechanical Component 

Support - Yard, Concrete, Exposed

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Elec Component Support - Auxiliary Bldg, Carbon 

Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Auxiliary Bldg, Carbon 

Steel, Raw Water

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Auxiliary Bldg, Concrete, 

Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Auxiliary Bldg, Concrete, 

Raw Water

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Auxiliary Bldg, 

Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
Page 2-216 

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Elec Component Support - Auxiliary Bldg, 

Galvanized, Raw Water

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Containment Bldg, 

Carbon Steel, Containment Cavity

Structural Support for Safety 

Related

Elec Component Support - Containment Bldg, 

Carbon Steel, Protected

Structural Support for Safety 

Related

Elec Component Support - Containment Bldg, 

Concrete, Protected

Structural Support for Safety 

Related

Elec Component Support - Containment Bldg, 

Galvanized, Containment Cavity

Structural Support for Safety 

Related

Elec Component Support - Containment Bldg, 

Galvanized, Protected

Structural Support for Safety 

Related

Elec Component Support - Discharge Structure, 

Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Elec Component Support - Discharge Structure, 

Galvanized, Protected

Structural Support for Non-Safety 

Related

Elec Component Support - Intake Structure Bldg, 

Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Elec Component Support - Intake Structure Bldg, 

Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Intake Structure Bldg, 

Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Elec Component Support - Switch Yard Relay House 

Group Bldg, Carbon Steel, Protected

Structural Support for Regulated 

Events

Elec Component Support - Switch Yard Relay House 

Group Bldg, Concrete, Protected

Structural Support for Regulated 

Events

Elec Component Support - Switch Yard Relay House 

Group Bldg, Galvanized, Protected

Structural Support for Regulated 

Events

Elec Component Support - Turbine Bldg, Carbon 

Steel, Protected

Structural Support for Regulated 

Events

Elec Component Support - Turbine Bldg, Concrete, 

Protected

Structural Support for Regulated 

Events

Elec Component Support - Turbine Bldg, Galvanized, 

Protected

Structural Support for Regulated 

Events

Elec Component Support - Yard, Carbon Steel, 

Exposed

Structural Support for Regulated 

Events

Elec Component Support - Yard, Concrete, Exposed Structural Support for Regulated 

Events

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Elec Component Support - Yard, Galvanized, 

Exposed

Structural Support for Regulated 

Events

Elec Component Support - Yard, Galvanized, Raw 

Water

Structural Support for Regulated 

Events

High Strength Bolting - Containment Building, Carbon 

Steel, Protected

Structural Support for Safety 

Related

Non-ASME Component Support - Auxiliary Bldg, 

Aluminum, Protected

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Auxiliary Bldg, Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Auxiliary Bldg, Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Auxiliary Bldg, Stainless, Borated

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Boiler Building, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Non-ASME Piping & Mechanical Component Support 

- Boiler Building, Concrete, Protected

Structural Support for Non-Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Aluminum, Protected

Structural Support for Non-Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Carbon Steel, Containment 

Cavity

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Galvanized, Containment Cavity

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Containment Bldg, Stainless, Borated

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Discharge Structure, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Non-ASME Piping & Mechanical Component Support 

- Discharge Structure, Cast Iron, Protected

Structural Support for Non-Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Discharge Structure, Concrete, Protected

Structural Support for Non-Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Discharge Structure, Galvanized, Protected

Structural Support for Non-Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Feedwater Purity Bldg, Carbon Steel, Protected

Structural Support for Regulated 

Events

Non-ASME Piping & Mechanical Component Support 

- Feedwater Purity Bldg, Concrete, Protected

Structural Support for Regulated 

Events

Non-ASME Piping & Mechanical Component Support 

- Intake Structure Bldg, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Intake Structure Bldg, Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Intake Structure Bldg, Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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Non-ASME Piping & Mechanical Component Support 

- Turbine Bldg, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Turbine Bldg, Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Turbine Bldg, Galvanized, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Water Treatment Bldg, Carbon Steel, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Non-ASME Piping & Mechanical Component Support 

- Water Treatment Bldg, Concrete, Protected

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Non-ASME Piping & Mechanical Component Support 

- Yard, Carbon Steel, Exposed

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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2.4.3 Containment

Description

The Containment structure consists of a post tensioned, reinforced concrete cylinder and 

dome connected to and supported by a massive, reinforced concrete foundation slab. 

The containment structure is a Class 1 structure. The majority of the interior surface of the 

containment pressure boundary structure is lined with 1/4” thick welded, steel plate to 

ensure a high degree of leak tightness. Numerous mechanical and electrical systems 

penetrate the containment wall through steel penetrations that are welded to the 

containment liner plate. None of the mechanical or electrical penetrations require 

expansion joints.

Personnel and equipment access to the structure is provided by a personnel air lock with 

two 3’ - 6” x 6’ - 8” doors, an escape air lock with two 30” diameter doors, and an 

Non-ASME Piping & Mechanical Component Support 

- Yard, Concrete, Exposed

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Non-ASME Piping & Mechanical Component Support 

- Yard, Galvanized, Exposed

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Spent Fuel Storage Rack - Auxiliary Building, Boron 

Carbide, Borated Water Radiation Shielding

Spent Fuel Storage Rack - Auxiliary Building, 

Stainless Steel, Borated Water

Structural Support for Safety 

Related

Table 2.4.2-1 Component Supports

Component Group Intended Function
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equipment hatch with a single door that provides total access to the 12’ diameter 

passageway. 

Principal dimensions are as follows:

Inside Diameter - 116’

Inside Height (Including Dome) - 189’

Vertical Wall Thickness - 3-1/2’

Dome Thickness - 3’

Foundation Slab Thickness - 8-1/2’ to 13-1/2’

Internal Free Volume - 1,640,000 ft3

Upon completion of initial testing of the containment, the tendon anchorages at the ring 

girder and the buttresses were enclosed by corrugated aluminum siding, chosen to 

coordinate the architectural appearance of the containment with the balance of the Plant. 

This siding is removable to permit access to the tendons for the surveillance program. No 

siding was provided for tendons that terminate within adjacent buildings or within the 

access gallery under the containment wall.

Primary Containment Concrete

The Palisades concrete structures and concrete are designed in accordance with ACI 

318-63 & 71, and constructed using ingredients conforming to ACI and ASTM standards. 

Palisades’ specifications require all concrete to contain an air-entraining agent in 

sufficient quantity to maintain specified percentages based on nominal maximum size 

aggregate. For severe weather exposures, the air content of Primary Containment 

concrete varies from 3 to 5 percent. Containment replacement concrete for steam 

generator replacement access had 3 to 7 percent air entrainment specified.

Primary Containment Liner

The original and steam generator replacement used 1/4” thick, ASTM A-442, Grade 55, 

liner plate, welded to a gridwork of structural steel angles embedded in the concrete. The 

anchoring system is designed to prevent significant distortion of the liner plate during 

accident conditions and to ensure that the liner maintains its leak tight integrity. The liner 

plate has been coated on the inside with 4 1/2 mils of inorganic zinc paint for corrosion 

protection. There is no paint on the side in contact with the concrete. 

The personnel air lock, the emergency air lock, and the equipment hatch contain double 

seals that can be pressurized from outside the containment building. This feature allows 

periodic local leak rate testing to be conducted during both operation and shutdown. The 
Page 2-224 

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electrical penetration canisters also can be pressurized from outside the containment. 

The piping and ventilation penetrations are of the rigid welded type and are solidly 

anchored to the containment wall, thus precluding any requirement for expansion 

bellows. 

The deformations of the containment structure during normal Plant operation, or during 

accident conditions, are relatively minor due to the low strain behavior of the shell. The 

largest deformations occur during or shortly after the post-tensioning operation. This low 

strain behavior together with the inherent strength of the structure permits the shell to be 

used as an anchor point for all piping that passes through it. This behavior eliminates the 

need for expansion bellows and significantly reduces the likelihood of leaks developing at 

these containment penetrations.

The transfer tube and flange are also 304 SS, and the transfer tube flange gaskets are 

neoprene, testable, double “O”-ring (short lived, since they are replaced every refueling 

outage).

Primary Containment Prestressing System

The post tensioning system consists of:

• Three groups of 55 dome tendons oriented at 120 degrees to each other for a total of 

165 tendons anchored at the vertical face of the dome ring girder.

• 178 vertical tendons anchored at the top surface of the ring girder and at the bottom of 

the base slab.

• Six groups of hoop tendons enclosing 120 degrees of arc for a total of 502 tendons 

anchored at the 6 vertical buttresses. 

After fabrication, the tendon was shop dipped in a petrolatum corrosion protection 

material, bagged, and shipped. After installation, the tendon sheathing and caps were 

filled with corrosion preventative grease. (Reference FSAR 5.8.2)

The boundary of the in-scope portions of the Containment Building are described as: the 

entire containment building is in scope.

The portions of the Containment containing components subject to an AMR include the 

Primary Containment Concrete, the Primary Containment Liner, the Primary Containment 

Pre-stressing System and the Primary Containment Foundation.
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System Function Listing

A comprehensive listing of functions associated with the Containment, or specific 

components contained in the structure, is provided in the summary below.

Code S0100-AT Cri 1 Cri 2 Cri 3

Provides shelter or support to ATWS related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to ATWS related 

components of Electrical and Instrumentation & Control systems.

Code S0100-EQ Cri 1 Cri 2 Cri 3

Provides shelter or support to EQ related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to safety related 

components of Electrical and Instrumentation & Control systems, Class 

1E.

Code S0100-FP Cri 1 Cri 2 Cri 3

Provides rated fire barrier to confine or retard a fire 

from spreading to or from adjacent areas of the 

plant.

FP EQ PTS AT SB

X

Comment: Containment exterior wall is an Appendix R fire barrier.

Code S0100-NSAS Cri 1 Cri 2 Cri 3

Provides structural or functional support to 

non-safety components that support safety related 

components.

FP EQ PTS AT SB

X

Comment: Provides structural support to non-safety related components that are 

directly attached to or located in proximity to safety related components 

such that their support failure could cause failure of the SR component.

Code S0100-SB Cri 1 Cri 2 Cri 3

Provides shelter or support to SBO related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to SBO related 

components of Electrical and Instrumentation & Control systems.

Code S0100-SR1 Cri 1 Cri 2 Cri 3

Provides essentially leak tight barrier to prevent 

uncontrolled release of radioactivity

FP EQ PTS AT SB

X

Comment: Containment Building is a Consumers Design Class 1 (seismic category 1) 

structure.
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FSAR Reference

Additional Containment details are provided in Section 2.3.4, Section 5.8.2, Section 5.8.7 

and Section 5.8.9 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Containment are listed below:

Components/Commodities Subject to an AMR

The component groups for the Containment that require aging management review are 

addressed in Table 2.4.3-1 along with each component group’s intended function(s).

Code S0100-SR2 Cri 1 Cri 2 Cri 3

Provides shelter/protection and functional support 

to safety related component

FP EQ PTS AT SB

X

Comment: Containment Building is a Consumers Design Class 1 (seismic category 1) 

structure.

LR-C3

Table 2.4.3-1 Containment 

Component Group Intended Function

Containment Shell & Base Slab - 

Containment Bldg - Carbon Steel, 

Protected

(air locks, equipment hatch, liner 

plate, penetrations)

Heat Sink

Pressure Boundary/ Fission 

Product Retention

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Containment Shell & Base Slab - 

Containment Bldg - Concrete, 

Below Grade

(base mat, foundation, wall, 

embedded steel, etc.)

Pressure Boundary/ Fission 

Product Retention

Radiation Shielding

Shelter/Protection

Structural Support for Safety 

Related
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Containment Shell & Base Slab - 

Containment Bldg - Concrete, 

Exposed

(dome, wall, base mat, embedded 

steel, etc.)

Pressure Boundary/ Fission 

Product Retention

Heat Sink

Missile Barrier

Radiation Shielding

Shelter/ Protection

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Containment Shell & Base Slab - 

Containment Bldg - Elastomer, 

Protected

(seals, gaskets, moisture barriers)

Pressure Boundary/ Fission 

Product Retention

Shelter/ Protection

Containment Shell & Base Slab - 

Containment Bldg - Stainless Steel, 

Protected

(fuel transfer tube, closure flange)

Heat Sink

Pressure Boundary/ Fission 

Product Retention

Containment Shell Prestressing 

system - Containment Bldg - 

Carbon steel, Exposed

(includes tendons and anchorage 

components)

Pressure Boundary/ Fission 

Product Retention

Structural Support for Safety 

Related

Table 2.4.3-1 Containment 

Component Group Intended Function
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2.4.4 Containment Interior Structures

Description

The containment interior concrete structures, which consist of all structural elements 

within the containment shell, are Class 1 structures. The principal interior concrete 

structures are:

• The primary shield wall, which forms the reactor cavity

• Two steam generator compartments

• A refueling pool which is located between the steam generator compartments and 

above the reactor cavity

• An enclosed sump under the reactor cavity

• Major equipment supports including the steam generator pedestals

The primary shield wall (bioshield) is essentially a circular cylinder, lined with 1⁄4” steel 

plate, with concrete ranging in thickness from 7' to 8', with the inner 10” thickness acting 

as a sacrificial shield. The sacrificial shield is not reinforced, except for two horizontal 

“bands/hoops” of reinforcing steel and is considered non-structural, non-load bearing 

concrete. The primary shield wall cooling coils are located within the sacrificial concrete to 

provide temperature control of a maximum of 165oF for the outer 6' to 7' thick, reinforced 

concrete. Openings in the shield wall for the primary coolant pipes are lined with 1⁄4” steel 

plate, with the space between the opening and the piping filled with non-structural 

concrete block for shielding. The primary shield wall supports the roof slab of the sump.

The steam generator compartment walls form the secondary shield walls around the 

primary coolant loops. The primary functions of these walls are:

• To provide biological shielding,

• To provide missile barriers, and

• To provide barriers to resist the jet impingement loads, and associated compartment 

pressurization, resulting from the rupture of any one primary coolant pipe.

These compartment walls span horizontally between vertical beams, which, in turn, are 

restrained by the floor systems at elevations 607’ - 0” and 649’ - 0”, and by structural steel 

tie struts at intermediate levels.

Pipe whip restraints are provided for the primary coolant pump suction, main steam, 

feedwater, and other high-pressure piping. Pipe whip barriers are also provided. For 

example, a reinforced concrete slab is provided above the top head of the pressurizer to 

protect it from a ruptured main steam line.
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The boundaries of the in-scope portions of the Containment Interior Structures are 

described as follows: all containment interior structures are in scope.

The portions of the Containment Interior Structures containing components subject to an 

AMR include the primary shield wall, the steam generator compartments, the refueling 

pool, the Containment sump and major equipment supports including the steam 

generator pedestals.

System Function Listing

A comprehensive listing of functions associated with the Containment Interior Structures, 

or specific components contained in the structures, is provided in the summary below.

Code S0100-AT Cri 1 Cri 2 Cri 3

Provides shelter or support to ATWS related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to ATWS related 

components of Electrical and Instrumentation & Control systems.

Code S0100-EQ Cri 1 Cri 2 Cri 3

Provides shelter or support to EQ related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to safety related 

components of Electrical and Instrumentation & Control systems, Class 

1E.

Code S0100-NSAS Cri 1 Cri 2 Cri 3

Provides structural or functional support to 

non-safety components that support safety related 

components.

FP EQ PTS AT SB

X

Comment: Provides structural support to non-safety related components that are 

directly attached to or located in proximity to safety related components 

such that their support failure could cause failure of the SR component.

Code S0100-SB Cri 1 Cri 2 Cri 3

Provides shelter or support to SBO related 

components.

FP EQ PTS AT SB

X

Comment: Containment building provides supporting function to SBO related 

components of Electrical and Instrumentation & Control systems.

Code S0100-SR2 Cri 1 Cri 2 Cri 3

Provides shelter/protection and functional support 

to safety related component.

FP EQ PTS AT SB

X

Comment: Containment Building is a Consumers Design Class 1 (seismic category 1) 

structure.
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FSAR Reference

Additional Containment Interior Structures details are provided in Section 5.9.2, and 

Section 9.2 of the FSAR.

Scoping Boundary Drawings

None.

Components/Commodities Subject to an AMR

The component groups for the Containment Interior Structures that require aging 

management review are addressed in Table 2.4.4-1 along with each component group’s 

intended function(s).

Table 2.4.4-1 Containment Interior Structures

Component Group Intended Function

Building Framing - Carbon Steel, Protected

(column, beam, truss, platform, floor grating or 

plate, catwalk, bracing, threaded fastener, 

concrete expansion bolt, column base plate, 

welds, etc.)

Heat Sink

HELB Shielding

Pipe Whip Restraint

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Support for Non-Safety Related

Building Framing - Concrete, Containment Cavity

(reactor shield walls including reinforcements, 

inserts, grouted anchors)

Heat Sink

HELB Shielding

Missile Barrier

Radiation Shielding

Structural Support for Safety 

Related
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Building Framing - Concrete, Protected

(concrete & masonry wall, column, pedestal, 

beam, slab, grout, reinforcements, concrete 

around expansion & grouted anchors, etc.)

Direct Flow

Heat Sink

HELB Shielding

Pipe Whip Restraint

Radiation Shielding

Structural Support for Regulated 

Events

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Fuel Related Component - Stainless, Protected

(refueling cavity liner, containment sump liner 

and screen, transfer tube) 

Structural Support for Safety 

Related

HELB/MELB Component - Carbon Steel, 

Protected 

(steel curbs, pipe whip restraints, spray shields, 

etc.)

HELB Shielding

Pipe Whip Restraint

Structural Support for Safety 

Related

HELB/MELB Component - Concrete, Protected

(curbs, sump, pipe whip restraint, grout, concrete 

at locations of expansion & grouted anchors, 

etc.)

Direct Flow

Flood Protection

Heat Sink

HELB Shielding

Pipe Whip Restraint

HVAC Component - Carbon Steel, Protected 

(damper & louver mounting frames)

Structural Support for Safety 

Related

Table 2.4.4-1 Containment Interior Structures

Component Group Intended Function
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2.4.5 Discharge Structure

Description

The Discharge Structure is a non-safety related, concrete structure with retaining walls 

that includes the Mixing Basin and Make-up Basin.

The safety related and non-safety related Service Water System (SWS) piping combine 

into a common 24" discharge header. This discharge header runs underground, splits into 

two 24" headers, and discharges into the Discharge Structure through the north and 

south concrete walls.

The Discharge Structure can also be used as a backup source of service water supply. In 

the event that water is not available to the intake structure due to a collapse of the intake 

crib or a similar type failure, approximately 17,000 gpm flow to the intake structure may 

be supplied from the mixing basin or makeup basin via the warm water recirculation pump 

P-5, if it is available. The warm water recirculation pump’s capability to provide water to 

the intake structure is an original design feature installed to mitigate circulating water 

system icing, and is not intended or required to provide a safety-related Service Water 

System makeup capability.

Due to similarities in materials and environment, the Intake Crib is included with the 

Discharge Structure scoping. The Intake Crib is a non-safety related structure that 

functionally supports the Ultimate Heat Sink function of maintaining adequate level in the 

Intake Structure.

The portions of the Discharge Structure containing components subject to an AMR 

include the Discharge Structure concrete walls (through which the Service Water 

HVAC Component - Galvanized, Protected

(damper & louver mounting frames)

Structural Support for Safety 

Related

Missile Shield - Concrete, Containment Cavity

(removable missile shield above reactor vessel)

Heat Sink

Missile Barrier

Table 2.4.4-1 Containment Interior Structures

Component Group Intended Function
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discharge pipes pass), the Warm Water Recirculating Pump pump house, and the sluice 

gates. The Intake Crib is included to provide a section source to the Service Water 

Pumps.

System Function Listing’

A comprehensive listing of functions associated with the Discharge Structure, or specific 

components contained in the structures, is provided in the summary below.

FSAR Reference

None.

Scoping Boundary Drawings

The scoping boundary drawings for the Discharge Structure are listed below:

Components/Commodities Subject to an AMR

The component groups for the Discharge Structure that require aging management 

review are addressed in Table 2.4.5-1 along with each component group’s intended 

function(s).

Code S1200-NSAS-1 Cri 1 Cri 2 Cri 3

Provides structural and/or functional support to 

safety related components

FP EQ PTS AT SB

X

Comment: Service water discharges to the Discharge Structure. The structural 

integrity of the Discharge Structure concrete walls is necessary to ensure 

the non-safety related SWS system discharge piping is not constricted or 

plugged so that it maintains required flow through the system. The Intake 

Crib must functionally pass flow to ensure a supply of lake water to the 

suction of the Service Water Pumps in the Intake Structure.

Code S1200-NSAS Cri 1 Cri 2 Cri 3

Provides warm water to the Intake Structure for 

de-icing to maintain operability of the Service 

Water System.

FP EQ PTS AT SB

X

Comment: The non-safety related Warm Water Recirculation Pump, located in a shed 

atop the Discharge Structure, pumps warm water from the Discharge 

Structure to a location upstream of the traveling screens in the Intake 

Structure to de-ice the screens. This is performed on an as-needed basis 

to maintain lake water flow to the safety related Service Water Pumps 

during icing conditions.

LR-C-3
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2.4.6 Feedwater Purity Building

Description

The Feedwater Purity Building (condensate and makeup demineralizer building) was 

constructed during the feedwater purity modification. It houses the raw water filtration 

system, the reverse osmosis pretreatment system, the makeup demineralizer system, 

various components of the condensate demineralizer system, regeneration chemicals 

handling system, feedwater purity service and instrument air, chemical storage and a 

boiler room.

Because of a concern for steam generator contamination from resin leakage and sodium 

release, the condensate demineralizer system has been rendered inoperable and retired 

in place; however, the Water Purity Building is “in-scope” based on Fire Protection 

Table 2.4.5-1 Discharge Structure

Component Group Intended Function

Building Framing - Cast Iron, Raw Water 

(sluice gates)

Structural Support for Non-Safety 

Related

Building Framing - Discharge/Intake Crib - Carbon 

Steel, Raw Water

(sluice gate, column, bracket, beam, bracing, 

threaded fastener, connector, weld, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Concrete, Below Grade

(wall, footing, foundation, slab, grout, 

reinforcement, trenches, cable pits, tunnels, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Concrete, Exposed 

(foundations, masonry & concrete wall, floor/roof 

slab, grout, reinforcements, steel shapes, 

concrete around expansion & grouted anchors)

Structural Support for Non-Safety 

Related

Building Framing - Concrete, Raw Water 

(wall, footing, foundation, slab, grout, 

reinforcements)

Structural Support for Non-Safety 

Related
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requirements to achieve safe shutdown. The Feed Water Purity Boiler Room in the south 

end of the building houses a diesel fuel oil transfer pump and piping, and this is the only 

area in this structure that is in-scope for License Renewal.

System Function Listing

A comprehensive listing of functions associated with the Feedwater Purity Building, or 

specific components contained in the structures, is provided in the summary below.

FSAR Reference

None.

Scoping Boundary Drawings

The scoping boundary drawings for the Feedwater Purity Building are listed below:

Components/Commodities Subject to an AMR

The component groups for the Feedwater Purity Building that require aging management 

review are addressed in Table 2.4.6-1 along with each component group’s intended 

function(s).

Code S0800-FP Cri 1 Cri 2 Cri 3

Provides structural and/or functional support to 

Fire Protection related components

FP EQ PTS AT SB

X

Comment: Appendix R Safe Shutdown Analysis credits portions of the Fuel Oil 

transfer piping between Fuel Oil Tank & the EDG Day Tanks in the event of 

a fire that renders the normal FO transfer pumps inoperable. The credited 

piping is located in the FWP Building.

LR-C-3

Table 2.4.6-1 Feedwater Purity Building

Component Group Intended Function

Building Framing - Carbon Steel, Protected

(column, beam, bracing, threaded fastener, concrete 

expansion bolt, column base plate, welds, etc.)

Structural Support for Regulated 

Events
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2.4.7 Intake Structure

Description

The portion of the Intake Structure above elevation 590 feet was designed to CP Co 

Design Class l standards. Major items of equipment housed in the area include the three 

safety-related service water pumps, two dilution pumps, two diesel engine-driven fire 

pumps, and two 480V MCCs providing electrical power to miscellaneous non- safety 

related equipment, including a motor-driven fire pump.

The pump room east wall adjacent to the turbine building has a three-hour fire rating with 

a single three-hour fire door installed. All other walls and access have outdoor exposure 

with a small section common with the diesel engine-driven fire pump day tank room. Fire 

ratings are in excess of three hours.

The portions of the Intake Structure containing components subject to AMR include the 

Design Class 1 portion (above elevation 590 feet), Design Class 3 walls and slab (below 

elevation 588 feet), including the triangular portion, sluice gates, trash racks, and the 

North and South chambers.

Building Framing - Concrete, Below Grade

(pedestal, footing, foundation, slab, grout, 

reinforcement, trenches, cable pits, etc.)

Structural Support for Regulated 

Events

Building Framing - Concrete, Exposed

(foundations, masonry/concrete wall, grout, 

reinforcement, concrete around expansion & grouted 

anchors, etc.)

Structural Support for Regulated 

Events

Building Framing - Concrete, Protected

(foundations, masonry/concrete wall, column, pedestal, 

beam, slab, grout, reinforcement, concrete around 

expansion & grouted anchors, etc.)

Structural Support for Regulated 

Events

Table 2.4.6-1 Feedwater Purity Building

Component Group Intended Function
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System Function Listing

A comprehensive listing of functions associated with the Intake Structure, or specific 

components contained in the structures, is provided in the summary below.

Code S0400-FP Cri 1 Cri 2 Cri 3

Provides structural and/or functional support to 

Fire Protection related component

FP EQ PTS AT SB

X

Comment: Portions of Intake Structure (Building) is a Consumers Design Class 3 

(Non-Category 1) structure that support the Fire Protection function are 

in-scope of 10CFR 54.4. Structure contains Appendix R fire barriers.

Code S0400-NSAS Cri 1 Cri 2 Cri 3

Provides structural and/or functional support to 

safety related component

FP EQ PTS AT SB

X

Comment: Walls and slab below El 588' that are not part of the triangular portion 

(Class 1) are Consumers Design Class 3 portion of the structure. 

However, the Class 3 walls and slab are connected to the triangular 

portion and support the Class 1 slab and walls above El 588' that are 

in-scope of 10CFR 54.4. Failure of these Class 3 (non-safety related) 

walls or slab will affect the structural integrity of the Class 1 structures, 

which protect and support the safety related service water pumps, 

strainers, and associated piping and supports.

Code S0400A-FP Cri 1 Cri 2 Cri 3

Provides structural support to the fire pumps and 

rated fire barriers to confine or retard a fire from 

spreading to or from adjacent areas of the plant

FP EQ PTS AT SB

X

Comment: Structure contains Appendix R fire barriers and fire protection pumps.

Code S0400A-SR Cri 1 Cri 2 Cri 3

Provides shelter/protection to safety related 

components

FP EQ PTS AT SB

X

Comment: Provides structural support to safety related components. Safety related 

components include the Service Water Pumps, Fuel Oil (FO) Transfer 

Pumps. The walls that protect the FO pumps from flooding are included in 

this structure.

Code S0400B-FP Cri 1 Cri 2 Cri 3

Provides source of water for fire protection Pumps. FP EQ PTS AT SB

X

Comment: The north and south chambers provide water into the triangular concrete 

reservoir through the north and south sluice gates. The triangular portion 

provides water supply suction for the safety related Service Water and Fire 

Water system pumps. See FWS system for Fire Protection Functions 

supported by this structure.
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FSAR Reference

None.

Scoping Boundary Drawings

The scoping boundary drawings for the Intake Structure are listed below:

Components/Commodities Subject to an AMR

The component groups for the Intake Structure that require aging management review 

are addressed in Table 2.4.7-1 along with each component group’s intended function(s).

Code S0400B-SR Cri 1 Cri 2 Cri 3

Provides source of cooling water for service water 

pumps P-7A, P-7B & P-7C.

FP EQ PTS AT SB

X

Comment: The north and south chambers provide water into the triangular concrete 

reservoir through the north and south sluice gates. The triangular portion 

provides water supply suction for the safety related Service Water and Fire 

Water system pumps. See SWS system for Service Water Functions 

supported by this structure. For structural stability of the whole Intake 

Structure the adjacent walls, slabs below & above the “triangular” portion 

are considered in-scope.

LR-C-3

Table 2.4.7-1 Intake Structure

Component Group Intended Function

Building Framing - Carbon Steel, Raw Water

(gates, guides, and trash racks)

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Building Framing - Cast Iron, Raw Water 

(Sluice Gates)

Structural Support for Regulated 

Events

Structural Support for Safety 

Related
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Building Framing - Galvanized, Raw Water

(fasteners and anchor bolts)

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Building Framing - Concrete, Below Grade

(wall, foundation, slab, grout, reinforcement, trenches, 

cable pits, tunnels, etc.)

Shelter / Protection

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Building Framing - Concrete, Exposed 

(wall, beam, floor slab, roof slab, grout, 

reinforcements, grouted anchors, etc.)

Fire Barrier

Flood Protection

Missile Barrier

Shelter/ Protection

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Building Framing - Concrete, Protected 

(wall, beam, floor slab, grout, reinforcements, grouted 

anchors, etc.)

Direct Flow

Flood Protection

Shelter/ Protection

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Table 2.4.7-1 Intake Structure

Component Group Intended Function
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2.4.8 Miscellaneous Structural and Bulk Commodities

Description

This group includes miscellaneous component types (assets) of various materials that 

were identified as requiring aging management review, but which did not fit into the other 

structural commodity groups. Assets in this group include: 

• Building crane bridges, trolleys, girders, and rails

• Elastomers for watertight door seals/gaskets, Emergency Diesel Generator vibration 

isolator elements, flood seals, seismic/expansion gap filler, waterstop, spray shield 

gasket, etc. 

• Fire Protection related commodities (seals, fire wrap, fire doors, concrete and concrete 

block fire barrier floors, ceilings and walls, etc.) 

• Architectural commodities (e.g., roofing systems, siding, control room ceiling, etc.)

• Soil and rip rap related to Water Control Structures - Intake Crib

Building Framing - Concrete, Raw Water 

(wall, column, beam, footing, foundation slab, floor 

slab, grout, reinforcements, etc.)

Structural Support for Regulated 

Events

Structural Support for Safety 

Related

Flood Barrier - Concrete, Protected

(concrete interior wall in southeast corner)

Flood Protection

HELB/MELB Component - Carbon Steel, Protected 

(steel curbs, floor drains, shields, etc.)

Direct Flow

Flood Protection

Structural Support for Safety 

Related

HELB/MELB Component - Concrete, Protected

(concrete/masonry walls, curbs, etc.)

Direct Flow

Flood Protection

Table 2.4.7-1 Intake Structure

Component Group Intended Function
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• Insulation between the main steam and feedwater piping and containment concrete at 

the piping penetration.

For the most part, these assets consist of component types that are included under GALL 

Section IIIA6.4-a and under various portions of GALL Section VII, as well as non-GALL 

items.

System Function Listing

A comprehensive listing of functions associated with the Miscellaneous Structural and 

Bulk Commodities is provided in the summary below.

Code Architectural (BLA)-FP1 Cri 1 Cri 2 Cri 3

Provides shelter and support to Fire Protection 

components.

FP EQ PTS AT SB

X

Comment: Roofing over the Intake Structure protects the three fire pumps.

Code Architectural (BLA)-NSAS1 Cri 1 Cri 2 Cri 3

Provides support of non-safety related Operator 

Habitability components whose failure could affect 

safety related components. 

FP EQ PTS AT SB

X

Comment: Architectural commodities provide ceiling framing to support lighting 

fixtures in the Control Room. 

Code Architectural (BLA)-NSAS2 Cri 1 Cri 2 Cri 3

Provides shelter to safety-related component and 

personnel.

FP EQ PTS AT SB

X

Comment: The roofing of the Auxiliary, Intake Structure, Discharge Structure (over 

warm water recirc pump), Water Treatment Building, and Safeguard Bus 

Building; and the metal siding of the Auxiliary Building & Safeguard Bus 

Building are non-safety related commodities. However, leaky roofing (e.g., 

Control Room roof) or siding (metal) may prevent satisfactory 

accomplishment of safety related functions of Mechanical & Electrical 

safety related components. Therefore, the design function of architectural 

roofing & siding of the Auxiliary, Intake Structure, Discharge Structure, 

Water Treatment building, and Safeguard Bus buildings, as applicable, is 

in-scope of 10CFR 54.4. The roofing of the Containment Building is not 

in-scope because of the liner plate. The Turbine Building and Feedwater 

Purity Building roofing & metal siding; and Boiler Building roofing do not 

affect any safety related components due to leaky roof or siding.
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Code Architectural (BLA)-SB Cri 1 Cri 2 Cri 3

Provides shelter and support to SBO related 

components.

FP EQ PTS AT SB

X

Comment: The roofing of the Switchyard Relay House Building, Switchgear 1F & 1G 

Building (incoming breakers need to open to isolate the 1F & 1G loads 

from SBO required loads) and Safeguards Bus Building protects SBO 

related components. Rain dripping from leaky roof may prevent 

satisfactory accomplishment of SBO related components function.

Code Consumables (BLB)-EQ Cri 1 Cri 2 Cri 3

Provides seal. FP EQ PTS AT SB

X

Comment: Consumables are used for protection of safety related electrical 

components from internal flooding (e.g., gasket or water seal used in 

internal flooding curbs).

Code Consumables (BLB)-NSAS Cri 1 Cri 2 Cri 3

Provides seal to prevent transmission of undesired 

fluid or/and debris between two adjacent areas

FP EQ PTS AT SB

X

Comment: Some non-safety related Civil/Structural consumables perform supporting 

or protection functions for safety related components: 1) HVAC air seal 

(e.g., weatherstripping of Control Room doors to minimize air in-leakage) 

& duct seals. Control Room doors weatherstrippings are safety related, 

see commodity group BLO. 2) Thermal expansion / seismic separation 

joint filler between safety related building to safety or non-safety related 

building (e.g., between Containment and Auxiliary Building / Turbine 

Building). Aging of filler may allow hard material intrusion into the joint and 

prevent free movement of structures. 3) Water leak seal at flood 

doors/hatches, interior & exterior concrete wall penetrations, roofing, 

internal flood preventive curbs, etc. 4) Containment Personnel Air Lock, 

Escape Air Lock and Equipment Hatch seals are safety related and are 

addressed in commodity group BLS.

Code Cranes (BLC)-NSAS Cri 1 Cri 2 Cri 3

Provides handling for plant modification and 

maintenance activities

FP EQ PTS AT SB

X

Comment: Some Cranes & Rigging commodities do not perform any safety related 

functions. However, depending on the load path and mode of operations, 

they may affect other safety related components due to potential 

accidental load drop. Cranes included in this function are Containment 

Building Boom Crane, Containment Jib Crane Hatch Area. Therefore 

BLC-NSAS function of Cranes & Rigging commodities is in-scope of 

10CFR 54.4.
Page 2-243 

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FSAR Reference

None.

Scoping Boundary Drawings

None.

Components/Commodities Subject to an AMR

The component groups for the Miscellaneous Structural and Bulk Commodities that 

require aging management review are addressed in Table 2.4.8-1 along with each 

component group’s intended function(s).

Code Cranes (BLC)-SR Cri 1 Cri 2 Cri 3

Provides handling of fuel assemblies, and lift and 

transport of loads in the Containment and Spent 

Fuel Pool areas without dropping.

FP EQ PTS AT SB

X

Comment: Some Cranes & Rigging commodities perform safety related functions, 

such as handling of fuel assemblies in the Containment and Spent Fuel 

Pool of the Auxiliary Building. The handling equipment (Refueling 

Machine, Spent Fuel Handling Machine {SFHM}, New Fuel Inspection 

Elevator, SFHM Auxiliary Hoist, Tilt Machines, Transfer Carriage, and 

Spent Fuel Handling Machine Auxiliary Hoist) provide for retrieval, 

reorientation and transport of fuel and poisons (control rods) in and 

between the Spent Fuel Pool and the reactor cavity. Some cranes in this 

group handle Dry Fuel cask, sealed canister and transfer cask; Reactor 

Vessel components (e.g., Upper Guide Structure, Reactor Vessel Head, 

etc.); and other heavy material inside the Containment Building.

Code Soil (BLY)-NSAS Cri 1 Cri 2 Cri 3

Provides foundation, missile shield, and natural 

slopes stability.

FP EQ PTS AT SB

X

Comment: Provides soil stability for Intake Crib structure. The Intake Crib steel 

structure is surrounded by a sloped ring of stone riprap with sand fill inside 

the crib around the intake pipe elbow. The sand fill is covered and 

protected by three layers of concrete sack riprap. The riprap and sand for 

the Intake Crib provides a supporting function to deliver water to the safety 

related Service Water pumps.

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities

Component Group Intended Function

Built-Up Roofing - Auxiliary Bldg - Tarred, Exposed Shelter/ Protection
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Built-Up Roofing - Discharge Structure - Tarred, 

Exposed

Structural Support for Non-Safety 

Related

Built-Up Roofing - Intake Structure Bldg - Tarred, 

Exposed Shelter/ Protection

Built-Up Roofing - Switch Yard Relay House Bldg - 

Tarred, Exposed

Structural Support for Regulated 

Events

Built-Up Roofing - Water Treatment Bldg - Tarred, 

Exposed

Structural Support for Non-Safety 

Related

Crane - Auxiliary Bldg - Carbon Steel, Protected Structural Support for Safety 

Related

Crane - Containment Bldg - Carbon Steel, Protected Structural Support for Safety 

Related

Crane Lift Device - Containment Bldg - Carbon Steel, 

Protected

Structural Support for Non-Safety 

Related

Crane Support - Auxiliary Bldg - Carbon Steel, 

Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Crane Support - Containment Bldg - Carbon Steel, 

Protected

Structural Support for Non-Safety 

Related

Structural Support for Safety 

Related

Fire Barrier - Auxiliary Bldg - Carbon Steel, Protected Fire Barrier

Fire Barrier - Auxiliary Bldg - Concrete, Exposed Fire Barrier

Fire Barrier - Auxiliary Bldg - Concrete, Protected Fire Barrier

Fire Barrier - Auxiliary Bldg - Fire Stop, Protected Fire Barrier

Fire Barrier - Auxiliary Bldg - Fire Wrap, Protected Fire Barrier

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities

Component Group Intended Function
Page 2-245 

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Fire Barrier - Containment Bldg - Carbon Steel, 

Protected Fire Barrier

Fire Barrier - Containment Bldg - Concrete, Exposed Fire Barrier

Fire Barrier - Intake Structure Bldg - Carbon Steel, 

Protected Fire Barrier

Fire Barrier - Intake Structure Bldg - Concrete, 

Exposed Fire Barrier

Fire Barrier - Intake Structure Bldg - Fire Stop, 

Protected Fire Barrier

Fire Barrier - Intake Structure Bldg - Fire Wrap, 

Protected Fire Barrier

Fire Barrier - Turbine Bldg - Carbon Steel, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Concrete, Exposed Fire Barrier

Fire Barrier - Turbine Bldg - Concrete, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Fire Stop, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Fire Wrap, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Water Treatment Bldg - 

Concrete, Exposed Fire Barrier

Fire Barrier - Turbine Bldg - Water Treatment Bldg - 

Concrete, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Water Treatment Bldg - 

Fire Stop, Protected Fire Barrier

Fire Barrier - Turbine Bldg - Water Treatment Bldg - 

Fire Wrap, Protected Fire Barrier

Flood Barrier - Auxiliary Bldg - Elastomer, Protected Flood Protection

Flood Barrier - Turbine Building - Elastomer, Protected Flood Protection

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities

Component Group Intended Function
Page 2-246 

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HELB/MELB Civil/ Structural Component - Auxiliary 

Bldg - Elastomer, Protected

Direct Flow

Flood Protection

HELB/MELB Civil/ Structural Component - Intake 

Structure Bldg - Elastomer, Protected

Direct Flow

Flood Protection

Mechanical General Component Support - 

Containment Bldg - Elastomer, Protected

Structural Support for Safety 

Related

Riprap - Yard - Soil, Submerged Structural Support for Non-Safety 

Related

Roof Flashing - Auxiliary Bldg - Galvanized, Exposed Shelter / Protection

Roof Flashing - Intake Structure Bldg - Galvanized, 

Exposed Shelter / Protection

Roof Flashing - Switchyard Relay House - 

Galvanized, Exposed

Structural Support for Regulated 

Events

Seal, Gasket or Filler - Auxiliary Bldg - Elastomer, 

Exposed Shelter/ Protection

Seal, Gasket or Filler - Auxiliary Bldg - Elastomer, 

Protected

Direct Flow

Expansion / Separation

Flood Protection

Shelter/ Protection

Seal, Gasket or Filler - Containment Bldg - Elastomer, 

Protected

Expansion / Separation

Flood Protection

Shelter/ Protection

Seal, Gasket or Filler - Discharge Structure - 

Elastomer, Exposed

Structural Support for Non-Safety 

Related

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities

Component Group Intended Function
Page 2-247 

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2.4.9 Switchyard and Yard Structures

Description

Switchyard Relay House Group

The Switch Yard Relay House group includes 1) the Switch Yard Relay House, 2) the 

Switchgear 1F & 1G Building, and 3) the Safeguards Bus Building. These buildings are 

Consumers Design Class 3 structures.

Switch Yard Foundations

This group includes reinforced concrete foundations for the Switch Yard Relay House, 

Safeguards Building, and Bus 1F/1G Building. It also includes foundations for startup and 

safeguards transformers; foundation and framing for the high voltage towers between the 

plant and switchyard, foundation and framing for the overhead lines from the plant to 

switchyard disconnect 24R2 (including the subject disconnect and takeoff towers); and 

foundation and framing for the underground line transitioning to the overhead bus, 

safeguards transformer, and disconnect 24 F1. Transformer foundations are reinforced 

concrete, slab on grade. Take-off towers have substantial, reinforced concrete spread 

footings, well below grade, and piers extending to 6" above grade. The switchgear 

Seal, Gasket or Filler - Discharge Structure - 

Elastomer, Protected

Structural Support for Non-Safety 

Related

Seal, Gasket or Filler - Intake Structure Bldg - 

Elastomer, Exposed Shelter/ Protection

Seal, Gasket or Filler - Switchyard Relay House/ 

Switchgear/ Safeguard Bldg - Elastomer, Exposed

Shelter/ Protection

Structural Support for Regulated 

Events

Seal, Gasket or Filler - Turbine Bldg - Elastomer, 

Exposed

Structural Support for Non-Safety 

Related

Seal, Gasket or Filler - Turbine Bldg - Elastomer, 

Protected

Flood Protection

Shelter/ Protection

Table 2.4.8-1 Miscellaneous Structural and Bulk Commodities

Component Group Intended Function
Page 2-248 

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housing and bus supports also are on spread footings with piers extending through 

backfill to above grade. These structures are in-scope based on SBO coping 

requirements. 

Also included are cable trench commodities, consisting of precast reinforced concrete 

“Trenwa” underground utility trench system comprised of trench walls and cover, which 

are set on a bed of gravel, precast reinforced concrete cable pits/manholes, and 

underground, reinforced concrete duct bank, rigid steel or PVC conduit encased in 

concrete. 

Tank Foundations

This includes reinforced concrete foundations for Primary Makeup Storage Tank, Safety 

Injection and Refueling (SIRW) Tank, Condensate Storage Tank including valve pit, 

Demineralized Water Storage Tank, Primary System Makeup Storage Tank, Utility Water 

Storage Tank, Diesel Generator Oil Storage Tank, and Fuel Oil Storage Tank.

The foundations for primary makeup storage tank, condensate storage tank including 

valve pit, demineralized water storage tank, primary system makeup storage tank, and 

utility water storage tank are reinforced concrete rings, with backfill compacted to 95% to 

support the tank bottoms. The SIRW Tank is supported on a concrete pad on top of the 

reinforced concrete roof of the Auxiliary Building. The Class 1 diesel generator fuel oil 

tank is housed in a below-grade vault, constructed of reinforced concrete (2' thick floor 

and walls, with an 18" thick roof) for missile protection. The fuel oil tank is credited in the 

Fire Protection Program.

The portions of the Switchyard and Yard Structures containing components subject to an 

AMR include the Switch Yard Relay House, Safeguards Bus Building, and bus 1F/1G 

building; foundations for startup and safeguards transformers; high voltage towers 

between plant and switchyard; foundation and framing for the overhead lines from the 

plant to switchyard disconnect 24R2 (including the subject disconnect and takeoff 

towers); foundation and framing for the underground line transitioning to the overhead 

bus, safeguards transformer and disconnect 24F1; cable trench commodities (including 

manholes, duct bank, conduit, etc.), and tank foundations.
Page 2-249 

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System Function Listing

A comprehensive listing of functions associated with the Switchyard and Yard Structures, 

or specific components contained in the structure, is provided in the summary below.

FSAR Reference

None

Scoping Boundary Drawings

The scoping boundary drawings for the Switchyard and Yard Structures are listed below:

Components/Commodities Subject to an AMR

The component groups for the Switchyard and Yard Structures that require aging 

management review are addressed in Table 2.4.9-1 along with each component group’s 

intended function(s).

Code S1100-SB Cri 1 Cri 2 Cri 3

Provides shelter to SBO related components FP EQ PTS AT SB

X

Comment: The Switchyard Relay House, Switchgear 1F & 1G Building, and 

Safeguards Bus Building provide shelter and support to Station Blackout 

components. Transformer foundations and foundations and framing for 

overhead and buried lines from plant to switchyard (including disconnects) 

provide functional support to SBO components.

LR-C-3 LR-C2

Table 2.4.9-1 Switchyard and Yard Structures

Component Group Intended Function

Building Framing - Safeguard Bus/Switchgear - 

Carbon Steel, Protected 

(floor beam, panels, welds, threaded fasteners, 

concrete expansion bolt, etc.)

Structural Support for Regulated Events

Building Framing - switchyard - concrete, Below 

Grade

(grade beam, footing, trenches, slab, grout, 

reinforcement, trenches, cable pits, tunnels, etc.)

Structural Support for Regulated Events
Page 2-250 

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2.4.10 Turbine Building

Description

The turbine building houses the turbine generator, condenser, feedwater heaters, 

condensate and feed water pumps, turbine auxiliaries and certain of the switchgear 

assemblies. The north end of the turbine building provides additional shop, laboratory and 

office space.

Building Framing - Switchyard - Concrete, Exposed

(masonry/concrete wall, grout, reinforcements, 

foundations, concrete around expansion & grouted 

anchors, bus supports, etc.)

Structural Support for Regulated Events

Building Framing - Switchyard - Concrete, 

Protected

(masonry roof bearing walls, reinforcements, 

concrete around expansion & grouted anchors, 

etc.)

Structural Support for Regulated Events

Metal Roofing & Siding - Switchgear & Safeguard 

Bus - Carbon Steel, Exposed

(flashing)

Structural Support for Regulated Events

Missile Shield - Yard - Concrete, Exposed 

(Tank vault roof, pavement over buried piping)

Missile Barrier

Tank Foundations - Building & Yard - Concrete, 

Below Grade

(concrete foundation)

Structural Support for Regulated Events

Structure Functional Support

Tank Foundations - Building & Yard - Concrete, 

Exposed

(concrete foundation)

Structural Support for Regulated Events

Structural Support for Safety Related

Table 2.4.9-1 Switchyard and Yard Structures

Component Group Intended Function
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The following areas of the turbine building were designed to CP Co Design Class l 

standards: 

• Portion of the turbine building basement forming the Auxiliary Feedwater Pump Room.

• Portion of the turbine building known as the South Electrical Penetration Room.

The remainder of the turbine building is CP Co Design Class 3. Areas include the 

following:

• Control Room Door Enclosure

• Other tornado missile enclosures

• Containment Escape Hatch Enclosure

• Boiler Buildings

• Water Treatment Building

The Turbine Building foundation is a series of concrete spread footings and piers for each 

steel building column or heavy equipment location with an interlocking grade beam 

arrangement. A grade slab fill is then provided to complete the Turbine Building floor. The 

Turbine Pedestal has its own concrete base mat, piers, and top deck that are 

independent of the remaining Turbine Building substructure.

The Turbine Building has a steel frame superstructure with siding and a concrete curb 

wall at the foundation line. In addition, the Turbine Building has concrete and masonry 

wall construction in the areas adjoining the Auxiliary and Containment Buildings. The 

floors within the Turbine Building are framed steel supporting formed concrete slabs, 

concrete metal decking slabs, and grating. The turbine building also contains fire barrier 

concrete commodities credited in Fire Protection requirements for achieving safe 

shutdown.

Boiler Buildings portions of the Turbine Building

The Boiler Building and Boiler Building Addition are Consumers Design Class 3 

structures. They house the Evaporator Heating Boiler and Heating Boiler. The Boiler 

Buildings support and protect diesel fuel oil components and associated piping.

Water Treatment Area Portion of the Turbine Building

The Water Treatment Area, like the Turbine Building, has a steel frame superstructure 

with siding and a concrete curb wall at the foundation line. The foundation and floor slab 

are reinforced concrete. The Water Treatment Area is “in-scope” for NSAS and SBO due 

to the Condensate Storage Tank valves located within. 
Page 2-252 

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The portions of the Turbine Building containing components subject to an AMR include 

the Turbine Building framing (steel & concrete), the Water Treatment Building framing 

(steel & concrete), flood barriers, HELB components (steel and concrete), HVAC 

components (steel and concrete), missile shield and operators access components (steel 

and concrete).

System Function Listing

A comprehensive listing of functions associated with the Turbine Building, or specific 

components contained in the structure, is provided in the summary below.

Code S0500-FP Cri 1 Cri 2 Cri 3

Provides structural and/or functional support to 

Fire Protection related component.

FP EQ PTS AT SB

X

Comment: Turbine Building contains Appendix R Fire Barriers and Fire Protection 

related equipment or components.

Code S0500-NSAS Cri 1 Cri 2 Cri 3

Provides structural or functional support to safety 

related components

FP EQ PTS AT SB

X

Comment: Shelters or protects the Main Feed Regulator and Regulator Bypass 

valves that have a safety related closed function, and the turbine driven 

AFW pump steam supply valve and associated piping. Also contains whip 

restraints and seismic supports for the Main Steam and Feedwater lines.

Code S0500A,B-SB Cri 1 Cri 2 Cri 3

Provides shelter or support to SBO related 

components

FP EQ PTS AT SB

X

Comment: Class 3 portion of the Turbine Building shelters AFW Pump P-8B steam 

supply & nitrogen supply to Atmospheric Steam Dump Valves. AFW Pump 

Room contains AFW Pump which is required during SBO.

Code S0500A,B-FP Cri 1 Cri 2 Cri 3

Provides rated fire barrier to confine or retard a fire 

from spreading to or from adjacent areas of the 

plant

FP EQ PTS AT SB

X

Comment: The Turbine Building AFW Pump Room is Fire Zone Area 24. The Turbine 

Building South Electrical Penetration Room is Fire Zone Area 26. These 

rooms contain fire detection and/or suppression equipment.

Code S0500A,B-SR Cri 1 Cri 2 Cri 3

Provides shelter/protection to safety related 

component.

FP EQ PTS AT SB

X

Comment: The Turbine Building Electrical Penetration Room and AFW Pump Rooms 

are Consumers Design Class 1 (Category 1) structures.
Page 2-253 

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FSAR Reference

None

Code S0500C,D,E-NSAS Cri 1 Cri 2 Cri 3

Provides missile barrier. FP EQ PTS AT SB

X

Comment: The concrete, steel and masonry enclosures provide tornado missile 

protection for selected safety related Class 1 equipment, including Control 

Room Door 52 and Containment Escape Lock.

Code S0600-NSAS Cri 1 Cri 2 Cri 3

Provides shelter, protection, and structural support 

of non-safety related components whose failure 

could affect the function of safety related 

components.

FP EQ PTS AT SB

X

Comment: Boiler Rooms contain Diesel Fuel Oil components and associated piping 

that are non-safety related, but are attached to safety related fuel oil 

piping. Thus, shelter, protection and support of the FOS piping is an 

in-scope function.

Code S0700-NSAS Cri 1 Cri 2 Cri 3

Provides shelter to safety related component or 

personnel

FP EQ PTS AT SB

X

Comment: Turbine Bldg Water Treatment Area is Consumers Design Class 3 

structure that is a non-safety related structure. The building provides 

shelter and support to safety related components and their associated 

piping.

Code S0700-SB Cri 1 Cri 2 Cri 3

Provides shelter or support to SBO related 

components.

FP EQ PTS AT SB

X

Comment: Gravity feed of condensate to AFW suction are required to support SBO. 

Associated valves in this flow path and located in the Turbine Bldg Water 

Treatment Area.

Code Architectural (BLA)-FP2 Cri 1 Cri 2 Cri 3

Provides access to remote shutdown panels & 

components in the event of a fire

FP EQ PTS AT SB

X

Comment: Provides access for the operator from the Control Room to Redundant 

Safety Injection Panel EC-33 in Auxiliary Building and Hot Shutdown 

Panels EC-150 & EC-150A in Turbine Building for alternate shutdown 

station. Other Auxiliary Building platforms, stairs, and similar commodities 

that are necessary to provide access to the operators that affects safety 

operations are in-scope.
Page 2-254 

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Scoping Boundary Drawings

The scoping boundary drawings for the Turbine Building are listed below:

Components/Commodities Subject to an AMR

The component groups for the Turbine Building that require aging management review 

are addressed in Table 2.4.10-1 along with each component group’s intended function(s).

LR-C-3

Table 2.4.10-1 Turbine Building

Component Group Intended Function

Building Framing - Boiler Buildings Area - Carbon 

Steel, Protected

(column, hanger, beam, truss, decking, platform, floor 

grating or plate, catwalk, threaded fastener, concrete 

expansion bolt, column base plate, welds, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Boiler Buildings Area - Concrete, 

Below Grade

(wall, pedestal, grade beam, footing, foundation, slab, 

grout, reinforcement, cable pits, tunnels, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Boiler Buildings Area - Concrete, 

Exposed

(masonry/concrete wall, grout, reinforcements, 

concrete around expansion & grouted anchors, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Boiler Buildings Area - Concrete, 

Protected

(foundations, concrete & masonry wall, column, 

beam, floor.roof slab, grout, reinforcements, concrete 

around expansion & grouted anchors, etc.)

Structural Support for Non-Safety 

Related

Building Framing - Water Treatment Area - Concrete, 

Protected

(concrete/ masonry wall, beam, floor slab, grout, 

reinforcements, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events
Page 2-255 

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Building Framing - Carbon Steel, Protected 

(column, beam, truss, decking, platform, floor grating 

or plate, catwalk, bracing, threaded fastener, concrete 

expansion bolt, column base plate, welds, etc.)

Flood Protection

HELB Shielding

Pipe Whip Restraint

Shelter/ Protection

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety Related

Building Framing - Concrete, Below Grade

(wall, pedestal, grade beam, footing, foundation, slab, 

grout, reinforcement, cable pits, tunnels, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety Related

Building Framing - Concrete, Exposed

(foundations, masonry/concrete wall, grout, 

reinforcements, concrete around expansion & grouted 

anchors, etc.)

Flood Protection

Shelter/ Protection

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety Related

Table 2.4.10-1 Turbine Building

Component Group Intended Function
Page 2-256 

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Building Framing - Concrete, Protected 

(foundations, concrete & masonry wall, column, 

beam, floor/roof slab, grout, reinforcements, concrete 

around expansion & grouted anchors, etc.)

Flood Protection

HELB Shielding

Missile Barrier

Shelter/ Protection

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Structural Support for Safety Related

Building Framing - Water Treatment Area - Carbon 

Steel, Protected

(column, beam, bracing, threaded fastener, weld, etc.)

Structural Support for Regulated 

Events

Building Framing - Water Treatment Area - Concrete, 

Below Grade

(wall, pedestal, grade beam, footing, foundation, slab, 

grout, reinforcement, trenches, cable pits, tunnels, 

etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Building Framing - Water Treatment Area - Concrete, 

Exposed 

(foundations, wall, grout, reinforcements, concrete 

around expansion & grouted anchors, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Building Framing - Water Treatment Area - Concrete, 

Protected

(foundations, concrete/masonry wall, beam, floor slab, 

grout, reinforcements, concrete around expansion & 

grouted anchors, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Flood Barrier - Carbon Steel, Protected 

(flood doors, hatch, standpipe)

Flood Protection

Structural Support for Safety Related

Table 2.4.10-1 Turbine Building

Component Group Intended Function
Page 2-257 

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HELB/MELB Component - Carbon Steel, Protected

(curbs, floor drains, pipe whip restraints, spray 

shields, etc.)

Flood Protection

HELB Shielding

Pipe Whip Restraint

Structural Support for Safety Related

HELB/MELB Component - Concrete, Protected

(concrete/masonry wall, whip restraint grout, concrete 

around expansion & grouted anchors)

Flood Protection

HELB Shielding

Pipe Whip Restraint

HVAC Component - Carbon Steel, Protected

(Control Room vestibule door)

Fluid Pressure Boundary

Structural Support for Non-Safety 

Related

HVAC Component - Concrete, Protected

(Control Room vestibules, concrete & masonry walls, 

floors, ceilings)

Fluid Pressure Boundary

Structural Support for Non-Safety 

Related

Missile Shield - Concrete, Exposed

(concrete and/or masonry walls protecting CCW room 

door and Containment escape hatch)

Missile Barrier

Missile Shield - Concrete, Protected

(concrete.masonry walls, floor & roof protecting 

Control Room Door)

Missile Barrier

Operator Access Component - Carbon Steel, 

Protected

(stairs, floors, platforms)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Table 2.4.10-1 Turbine Building

Component Group Intended Function
Page 2-258 

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Operator Access Component - Concrete, Protected 

(stairs, floors, platforms, concrete at locations of 

expansion & grouted anchors, etc.)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Operator Access Component - Galvanized, Protected 

(stairs, floors, platforms)

Structural Support for Non-Safety 

Related

Structural Support for Regulated 

Events

Table 2.4.10-1 Turbine Building

Component Group Intended Function
Page 2-259 

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2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

The following commodity groups and systems are addressed in this section:

• Commodity Group Descriptions (Section 2.5.1)

• Cables and Terminations Commodity (Section 2.5.2)

• Containment Isolation and Penetration System (Section 2.5.3)

• Control Rod Drive System (Section 2.5.4)

• Neutron Monitoring System (Section 2.5.5)

• Radiation Monitoring System (Section 2.5.6)

• Reactor Protective System (Section 2.5.7)

• Station Power System (Section 2.5.8

• Switchyard System (Section 2.5.9

During the Scoping Process, evaluation boundaries were established for each system or 

commodity group based on the system functions. The Screening Process identified the 

long-lived, passive, components from the in-scope systems and commodity groups that 

would be subject to an aging management review. For convenience, because of similarities 

across systems in materials, environments, and aging management strategies, the various 

system components that required aging management review were assigned to commodity 

groups. Aging management reviews were then performed on the electrical components as 

commodities, regardless of system association. This approach is consistent with the 

approach taken by most applicants for license renewal.

The electrical commodity groupings identified at Palisades are:

• Electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

• Electrical cables and connections used in instrumentation circuits not subject to 10 CFR

50.49 EQ requirements that are sensitive to reduction in conductor IR (Nuclear

Instrumentation & Radiation Monitoring Systems)

• Electrical Portions of the Non-EQ Electrical and I&C Penetration Assemblies (Cables and

Connections)

• Fuse Holders (ISG-5)

• Non-Segregated Phase Bus and Connections

• High-Voltage Transmission Conductors (ISG-2)

• High-Voltage Switchyard Bus and Connections (ISG-2)

• Inaccessible Medium-Voltage (2kV to 15kV) Cables and Connections not subject to 10

CFR 50.49 requirements
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• High-Voltage Insulators (ISG-2)

Section 2.5.1 describes the commodity groups that were used to evaluate all in-scope 

electrical and I&C components subject to aging management review. 

Sections 2.5.2 through 2.5 8 provide descriptions of the electrical and I&C systems that 

were determined to be in-scope. Components within those electrical systems which were 

determined to require aging management review were addressed as part of the defined 

commodities. This system organization is not retained in later sections of this application.

2.5.1 Commodity Group Descriptions

Commodity: Electrical cables and connections not subject to 10 CFR 50.49 EQ 

requirements

Commodity: Electrical cables and connections used in instrumentation circuits not 

subject to 10 CFR 50.49 EQ requirements that are sensitive to reduction in conductor 

IR (Nuclear Instrumentation & Radiation Monitoring Systems)

The two commodity groups listed above include the same types of cables and components. 

They differ primarily in the programs selected to manage aging of those components. The 

determination of which cables and components are assigned to each commodity is self 

explanatory based on the commodity titles. 

The component types which comprise these two commodity groups are described below:

Insulated Cables

Insulated cables encompass all in-scope cable types used in the plant. The cable 

insulation material used at Palisades is SR, EPR, XLP, XLPE, EPDM, PVC, BR, 

PE, polymide, and teflon. Cable insulation material groups are assessed on the 

basis of material similarity and their respective material aging characteristics. The 

insulated cable materials subject to aging are metal and insulation. The metals 

used are copper and tinned copper. The insulation materials are various 

elastomers and thermoplastics. The insulated cable conductor metal is protected 

from the environments that induce aging effects, as long as the cable insulation 

maintains its integrity (material properties). Therefore, the metal conductor portion 

of insulated electrical cables does not experience aging effects requiring aging 

management. 

Electrical Connections - Splices

Palisades utilizes Raychem WCSF-N heat shrink tubing for all of its field splices. 

Raychem heat-shrinkable tubing consists of a proprietary material stated by 

Raychem to be made of a “modified polyolefin” similar to the properties of XLPE 
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and XLPO. Since this material and its cable applications (P, C & I) are similar to 

the XLPE insulated cables, the cable splices are bounded by the XLPE cable 

insulation review. 

Electrical Connections - Terminations (Terminal Blocks and Fuse Blocks)

Terminal blocks and fuse blocks, that are part of an active component, were 

excluded from further aging management review.

Terminal blocks used at Palisades, that are not part of an active component, were 

identified to be Buchanan (Model NQB), States (ZWM and NT Types), Cinch 

Jones (140 Series), and Westinghouse (542-245). The Palisades J-Box Drawings 

were reviewed to capture the prominent terminal block brands and models used at 

Palisades. All terminal blocks identified and reviewed, potentially in-scope of LR, 

had phenolic insulation material.

Electrical Connections - Connectors

Electrical connectors are used to connect the cable conductors to other cables or 

electrical devices. The three main types of connectors are compression, fusion, 

and plug-in (mated) connectors. A brief description of each is provided below:

Compression Connectors: Fittings (e.g. ring lugs or barrels) that are bolted, 

physically crimped or mechanically swaged to connect cable conductors.

Fusion Connectors: Cable connections made by welding, brazing or soldering 

where permanence of the conductor connection is desired.

Plug-in (Mated) Connectors: Connectors with one or more electrical contacts that 

plug or screw into a mating receptacle; useful where ease and frequency of 

separation of an electrical connection is desired, for ease of mating specific types 

of equipment, and where multiple simultaneous electrical disconnections / 

reconnections need to be made.

Insulated plug-in (mated) connectors were the main focus of the connector aging 

review. 

Detailed drawings and vendor information may not be available to identify all 

insulating materials used in non-EQ connectors. Therefore, the identification of 

insulation materials on all potentially in-scope plug-in connectors at Palisades 

(both EQ and non-EQ) began with a review of other previous AMRs with 

references to NUREG/CR-6412. This review provided a listing of the 

predominantly-used connector insulation materials in the nuclear industry: EPDM, 

EPR, Kapton, and XLPE. The plant EQ Master Equipment List and the EQ File 

Reports were then used to validate completeness of the generic list, and identify 
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any additional connector insulation materials used at Palisades. The EQ files 

identified additional materials, which were added to the generic materials list. This 

combined list of electrical connector insulation materials provides reasonable 

assurance that it is a bounding list of connector insulation materials installed at 

Palisades. 

Commodity: Electrical Portions of the Non-EQ Electrical and I&C Penetration 

Assemblies (Cables and Connections) 

There are thirty-seven (37) active Electrical Containment Penetrations (Canisters) at 

Palisades. Twenty-two (22) of the electrical penetrations fall within the EQ Program, and 

fifteen (15) are non-EQ. 

Palisades uses two types of Electrical Containment Penetrations (Canisters) manufactured 

by two vendors: thirty-five (35) penetrations were manufactured by Viking Industries, and 

two (2) by Conax. The two manufactured by Conax are both EQ electrical penetrations. 

Fifteen (15) of the thirty-five (35) electrical penetrations manufactured by Viking Industries 

are non-EQ electrical penetrations.

The non-electrical portions of the Viking Industries electrical penetration assemblies, that 

support the LR pressure boundary or structural function, are addressed in the civil/structural 

area. The electrical portions of the electrical penetration assemblies that electrically support 

the License Renewal functions are the internal cable insulation materials and the connector 

insulation materials. 

The internal cables used in the Viking Electrical Penetrations are:

• Coaxial Cable (PE)

• Rockbestos Firewall Cable (SR)

• Anaconda Cable (EPR)

• Ceramic Bushings

• Fiberglass

The cable insulation materials are included in the non-EQ insulated cable review.

Commodity: Fuse Holders (ISG-5)

This commodity includes all fuse blocks used at Palisades that are not part of an active 

component or larger active assembly. Those identified are all located inside junction boxes 

in a controlled environment and are not subject to any aging mechanism, including cycling 

more than once an refueling outage.
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Commodity: Non-Segregated Phase Bus and Connections

The non-segregated phase bus, supporting the SBO restoration path for Palisades, is 

in-scope. The structural hardware and enclosure housing components are addressed in the 

civil/structural area, if applicable.

The Unibus Inc. metal-enclosed bus contains the following vital electrical components that 

provide the primary electrical conductivity and insulation functions:

• Copper Bus

• Glass-Reinforced Polyester Blocks (track-resistant)

• Porcelain Bus Sleeve, or Ceramic and Fiberglass

• Bus mounting boots (Material unknown)

The non-segregated bus is provided with uniform heating and temperature control to 

prevent condensation. The contact surfaces of all electrical joints [connections] are either 

silver or tin-plated. Per design, no electrical joint compounds are used or required. Per 

design, no retorquing of properly installed conductor connecting hardware is required on a 

routine basis. Flexible ground continuity connections are provided at bus expansion joints. 

The Unibus, Inc. metal enclosed bus system has been designed to eliminate components or 

consumables that might require periodic or routine replacement. 

Recent concern among the industry, as discussed in ISG-17, has focused upon the 

non-segregated bus enclosure seals and loose connections from thermal cycling. Palisades 

has conservatively included the non-segregated bus duct into its aging management 

program due to moisture level concerns resulting from potential seal leakage and loose 

connections from thermal cycling. 

Commodity: High-Voltage Transmission Conductors (ISG-2)

The switchyard is not included in the plant equipment defined in the CLB for mitigation of the 

SBO event. ISG-2, however, indicates that certain equipment which provides offsite power 

for restoration from a Station Blackout is to be included in the scope of license renewal. 

Therefore, to be consistent with the NRC guidance in ISG-2, Palisades has included 

in-scope, selected equipment associated with the switchyard and the two qualified offsite 

power circuits that can provide offsite power to the safety related Buses 1C and 1D following 

an SBO event. The equipment brought in to scope is addressed as a commodity consisting 

of the following component types.

• All in-scope 345 kV station transmission cables are “Bluebird” 2,156 MCM, 84/19 ACSR

(aluminum conductor steel reinforced) and are constructed of the following materials:

(a) Aluminum
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(b) Steel

• The transmission conductor between the switchyard bus and transformers or tie breakers

is within scope.

Commodity: High-Voltage Switchyard Bus and Connections (ISG-2)

The 345 kV switchyard bus is 5" and 3 1⁄2” aluminum alloy 6061-T6, Schedule 40 seamless 

pipe. The aluminum bus bolted connection hardware is aluminum or stainless steel. 

Commodity: Insulation for Inaccessible Medium-Voltage (2kV to 15kV) Cables and 

Connections

Medium-voltage cables, including those in the SBO restoration path for Palisades, are 

in-scope and were included with the non-EQ insulated cable commodity for review. 

Insulation materials are various elastomers and polymers.

Commodity: High-Voltage Insulators (ISG-2)

The Palisades high-voltage cable insulators are 5-3/4” x 10", 25,000 lbs. M&E Strength, 

ASA 52-5 suspension insulators with a porcelain electrical insulation material, Portland 

cement, on a steel post. The Switchyard Bus post insulators are made of porcelain and 

cement. Porcelain and cement do not experience aging effects from the bounding site 

radiation and temperature levels. The internal metal posts of the HV Cable Insulators are 

reviewed for potential wear from the effects of vibration. It was determined that no significant 

aging effects are induced by temperature or radiation on the high-voltage insulator 

materials.
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Table 2.5-1 Electrical Commodity Groups

Commodity Group Intended Function

Electrical cables and connections 

not subject to 10 CFR 50.49 EQ 

Requirements

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

Electrical cables and connections 

used in instrumentation circuits not 

subject to 10 CFR 50.49 EQ 

Requirements that are sensitive to 

reduction in conductor IR.

(ISG-15)

(Nuclear Instrumentation and 

Radiation Monitoring Systems)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

Electrical Portion of the Non-EQ 

Electrical and I&C Penetration 

Assemblies

(Cables & Connections) 

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

Fuse Holders

(ISG-5)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals.

Non-Segregated Phase Bus and 

Connections

(ISG-17)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

High-Voltage Transmission 

Conductors

(ISG-2)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

High-Voltage Switchyard Bus and 

Connections

(ISG-2)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals
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2.5.2 Cables and Terminations Commodity 

Description

The license renewal system Cables and Terminations (CBL) Commodity includes the 

cables and terminations in each Palisades system that includes components requiring 

electrical power or control. The purpose of establishing CBL is to treat all plant non-EQ 

cables and terminations as a commodity group.

Some SSCs in this system are considered in-scope in accordance with 10 CFR 

54.4(a)(1). Since some SSCs in the Cables and Terminations Commodity are non-safety 

related, and their failure could affect the capability of SR SSCs to perform their safety 

function, they are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In 

addition, some SSCs are considered in-scope due to ATWS, Environmental Qualification, 

Fire Protection, and Station Blackout in accordance with 10 CFR 54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Cables and Terminations 

Commodity, or specific components contained in the commodity, is provided in the 

summary below.

Inaccessible medium-voltage (2kV 

to 15kV) cables and connections 

not subject to 10 CFR 50.49 EQ 

Requirements

(ISG-18)

Provide electrical connections to 

specified sections of an electrical 

circuit to deliver voltage, current, or 

signals

High-Voltage Insulators

(ISG-2)

Insulate and support an electrical 

conductor

System Function: CBL-01 Cri 1 Cri 2 Cri 3

The CBL system includes safety related 

components.

FP EQ PTS AT SB

X

Comment: The system includes 1E components.

Table 2.5-1 Electrical Commodity Groups

Commodity Group Intended Function
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FSAR Reference

None.

Scoping Boundary Drawings

None.

System Function: CBL-ATWS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current design basis 

for Anticipated Transient Without Scram.

FP EQ PTS AT SB

X

Comment: An example of a component with this system function is cabling used for 

ATWS detection.

System Function: CBL-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current design basis 

for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: EQ components are in the scope of license renewal but do not require an 

AMR since they are periodically replaced.

System Function: CBL-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current design basis 

for Fire Protection.

FP EQ PTS AT SB

X

Comment: Examples of components with this system function are fire detector 

cabling and fire alarm cabling.

System Function: CBL-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

orientation.

FP EQ PTS AT SB

X

Comment: An example of a component with this system function is a non-safety 

related cable next to a safety related cable in a cable tray.

System Function: CBL-SBO Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current design basis 

for Station Blackout (Loss of all AC power).

FP EQ PTS AT SB

X

Comment: An example of a component with this system function is DC (direct current) 

cabling.
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Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups defined in Table 2.5-1.

2.5.3 Containment Isolation and Penetration System 

System Description

The Containment Isolation and Penetration System (CIS) is designed to minimize the 

release of radioactivity from the containment building to the atmosphere in the event of an 

accident resulting in containment building high atmospheric pressure or radioactivity. All 

containment building penetrations are considered as potential sources of airborne 

radioactive leakage of the atmosphere in the event of a DBA or leakage of radioactive 

waste. Isolation valves are provided in all process systems penetrating the containment 

which serve to isolate the containment building atmosphere when required. The type and 

quantity of isolation valves for each pipe penetration are determined by the process 

system operational and physical characteristics in relation to the containment building 

atmosphere. 

Included in the CIS is the Safety Injection System control circuits which are designed to 

automatically initiate the necessary engineered safeguards equipment upon a safety 

injection actuation signal (SIAS or SIS Signal - terms are used interchangeably) with or 

without offsite power available. 

The Normal Shutdown and Design Basis Accident Sequencer is designed to sequentially 

load the safe shutdown equipment onto the emergency buses and/or diesel generators. 

Sequencing of loads ensures that the appropriate equipment is energized when needed 

while preventing excessive step loads from being on the diesel generator which could 

result in the loss of the generator.

The CIS also includes some components from the Plant Data Logger that provide an 

isolation function or have a seismic function only.

For license renewal purposes, the Containment Isolation and Penetration System is an 

electrical system. The components are active and not subject to an AMR. The mechanical 

portion of the system, (e.g., piping and valves) are addressed in their respective 

mechanical systems. The seals and penetrations are addressed in the civil / structural 

system.

The license renewal boundary of the CIS is described as follows: 1) from the containment 

pressure transmitters to the containment isolation relays that send signals to the process 

system containment isolation valves 2) from the containment isolation high radiation 
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monitors to the containment isolation high radiation relays that send signals to the 

process system containment isolation valves and 3) the Normal Shutdown and Design 

Basis Accident Sequencers; 4) the SIS subsystem from the containment pressure 

transmitters to the safety injection relays that send signals to the process system 

safeguard equipment and containment isolation valves, and from the pressurizer low-low 

pressure transmitters to the safety injection relays that send signals to the process 

system; 5) the DTA subsystem, including the Multiplexer Input Modules for the Critical 

Function Monitor System (CFMS).

The description above results in some SSCs in this system being considered in-scope in 

accordance with 10 CFR 54.4(a)(1). Since some SSCs in the Containment Isolation and 

Penetration System are non-safety related and their failure could affect the capability of 

SR SSCs to perform their safety function, they are considered to be in-scope in 

accordance with 10 CFR 54.4(a)(2).

System Function Listing

A comprehensive listing of functions associated with the Containment Isolation and 

Penetration System, or specific components contained in the system, is provided in the 

summary following.

System Function: CIS-01 Cri 1 Cri 2 Cri 3

Process a signal on Containment High Radiation 

(CHR).

FP EQ PTS AT SB

X

Comment: Coincident two-out-of-four high-radiation signals from the auxiliary relays 

will trigger an alarm in the main control room, close all containment 

isolation valves not required for engineering safeguards except the 

component cooling line valves, and will isolate the control room ventilation 

system. High radiation detected by the refueling accident high-radiation 

monitors will also close all containment isolation valves not required for 

engineered safeguards when enabled by the respective refueling monitor 

key switches.

System Function: CIS-02 Cri 1 Cri 2 Cri 3

Process a signal on Containment High Pressure 

(CHP).

FP EQ PTS AT SB

X

Comment: Coincident two-out-of-four high-containment pressure signals will trigger 

an alarm in the main control room, close all containment isolation valves 

not required for engineered safeguards, and will isolate the control room 

ventilation system.
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System Function: CIS-03 Cri 1 Cri 2 Cri 3

Provide containment operability in order to 

minimize the release of radioactive material to the 

environment.

FP EQ PTS AT SB

X

Comment: The containment isolation and penetration system is an electrical system 

for license renewal purposes. Components such as the personnel airlock, 

escape airlock, containment penetrations, and containment isolation 

valves are addressed in their individual system.

System Function: CIS-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

interactions.

FP EQ PTS AT SB

X

Comment: in-scope of License Renewal to protect safety related components.

System Function: DTA-07 Cri 1 Cri 2 Cri 3

The Critical Functions Monitoring subsystem 

provides Safety Parameter Display System 

(SPDS) functions required by NUREG 0696 and 

NUTREG 0737 Supplement 1.

FP EQ PTS AT SB

X

Comment: The Critical Functions Monitoring node of the Data Logger contains 

equipment that is credited with a safety related function to isolate safety 

related 1E circuits from Non-1E circuits.

System Function: SEQ-01 Cri 1 Cri 2 Cri 3

Automatically sequence the connected Normal 

Shut Down (NSD) loads to bus 1C and/or bus 1D 

upon automatic closing of the associated diesel 

generator breaker with no SIS signal present.

FP EQ PTS AT SB

X

Comment: The sequencers are emergency generator support systems that are 

required to safely shutdown the plant after a loss of offsite power.

System Function: SEQ-02 Cri 1 Cri 2 Cri 3

Automatically sequence the connected Design 

Basis Accident (DBA) loads to bus 1C and/or bus 

1D upon automatic closing of the associated diesel 

generator breaker with an SIS signal present.

FP EQ PTS AT SB

X

Comment: The sequencers are emergency generator support components that are 

required to safely shutdown the plant after a loss of offsite power. The 

design basis LOCA is assumed to be coincident with a loss of offsite 

power.
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FSAR Reference

Additional Containment Isolation and Penetration System details are provided in Section 

7.3 and Section 8.4 of the FSAR.

Scoping Boundary Drawings

Components Subject to an AMR

There are no assets for this system that require aging management review.

2.5.4 Control Rod Drive System

System Description

The Control Rod Drive (CRD) System is designed to provide for gravity insertion of 

control rods on reactor scram and positive controlled insertion or withdrawal of control 

rods to provide definite shutdown margin, for short-term reactivity control and for control 

of axial xenon shifting. The major components are control rod drive mechanisms, and 

primary and secondary rod position indication. The control rod drive mechanism housing 

functions to provide a pressure boundary between primary coolant pressure and 

atmosphere are addressed by the Reactor Vessel System. For license renewal purposes, 

this system includes electrical functions only. Mechanical functions of the Control rod 

Drives are addressed with the Reactor Vessel (RVG) license renewal system.

The power to the CRD is supplied from the Control Rod Drive Power Supply subsystem. 

The CRD Power Supply subsystem provides both control power and motive power for the 

Control Rod Drive motors. The CRD System contains no electrical components which are 

required to remain operable during and after an accident to enable the operator to bring 

System Function: SIS-01 Cri 1 Cri 2 Cri 3

Process a signal on Containment High Pressure. 

(CHP).

FP EQ PTS AT SB

X

Comment: Two-out-of-four containment high-pressure signals initiate the SIS signal 

which, in turn, actuates two safety injection control circuits, each of which 

is supplied by a separate preferred ac source.

System Function: SIS-02 Cri 1 Cri 2 Cri 3

Process a signal on Pressurizer Low-Low 

Pressure.

FP EQ PTS AT SB

X

Comment: Two-out-of-four pressurizer low-low pressure signals initiate the SIS signal 

which, in turn, actuates two safety injection control circuits, each of which 

is supplied by a separate preferred ac source.

None
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the plant to safe shutdown conditions. A loss of power from the CRD Power Supply 

System does not affect the position of the control rods. Power for the clutches, which 

(when energized) engage the control rods with the drives, is supplied from an 

independent source (Preferred AC) which is discussed under the Reactor Protective 

System. A loss of clutch power automatically causes a reactor safe shutdown, since the 

control rods drop into the reactor core by gravity when the clutches are de energized for 

any reason.

The license renewal boundary (electrical) of the CRD System begins at the load side of 

MCC breakers, step-down Transformers X45 and X46, manual bus transfer switch, the 

CRD Power Supply bus, and associated cables. 

The description above results in some SSCs in this system being considered in-scope in 

accordance with 10 CFR 54.4(a)(1). In addition, some SSCs are considered in-scope due 

to ATWS, Environmental Qualification, and Station Blackout in accordance with 10 CFR 

54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Control Rod Drive System is 

provided in the summary below.

System Function: CRD-01 Cri 1 Cri 2 Cri 3

Provide instantaneous negative reactivity to the 

core on demand via gravity insertion of control 

rods on reactor scram.

FP EQ PTS AT SB

X

Comment: The Control Rod Drive System, in response to a Reactor Protection 

System trip signal, shuts down the reactor and maintains it in a safe 

shutdown condition. CRD is used to mitigate the consequences of 

numerous accidents and transients as described in FSAR Chapter 14. 

During a LOCA, high containment pressure provides the signal to 

shutdown the reactor and protect containment integrity.
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System Function: CRD-02 Cri 1 Cri 2 Cri 3

Provide positive controlled insertion or withdrawal 

of control rods on receipt of a signal from the CRD 

control system.

FP EQ PTS AT SB

Comment: The ability to drive control rods is not required to shutdown the reactor and 

maintain it in a safe shutdown condition. In the event of an unsafe 

condition, the reactor trips and the rods are gravity inserted, i.e., they are 

not driven in by the control rod drive mechanism. As a contingency action 

to the reactor trip and a failure of all rods to fully insert, the control rods are 

selected and manually driven in per the Emergency Operating 

Procedures. Based on the above, this is a normal operating system 

function and is not required for safe shutdown. Therefore, this CRD 

system function is not within the boundary of License Renewal.

System Function: CRD-03 Cri 1 Cri 2 Cri 3

Provide control position indication and position 

related alarms.

FP EQ PTS AT SB

Comment: Rod position indication is required to allow verification that the rods are 

positioned and aligned as assumed in the safety analysis. If no rod 

position indication exists for one or more control rods, continued operation 

is not allowed because the safety analysis assumptions of rod position 

cannot be ensured.

This is a normal operating system function and is not required for safe 

shutdown. Therefore, this CRD system function is not within the License 

Renewal boundary.

System Function: CRD-04 Cri 1 Cri 2 Cri 3

Maintain PCS pressure boundary. FP EQ PTS AT SB

Comment: The pressure housings of the Control Rod Drive Mechanisms, including 

seals, are an extension of the reactor vessel and provide a primary coolant 

pressure boundary. This CRD system function is not within the electrical 

CRD license renewal system. The equipment which performs this function 

is in scope for License Renewal but will be evaluated in RVG, Reactor 

Vessel. See RVG System Function RVG-01.
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System Function: CRD-05 Cri 1 Cri 2 Cri 3

Provide manual control of shutdown, regulating 

and part length control rods in either individual, 

group or group sequential modes.

FP EQ PTS AT SB

Comment: In the event of an unsafe condition, the reactor trips and the rods are 

gravity inserted, i.e., they are not driven in by the control rod drive 

mechanism. Following a reactor trip and a failure of all rods to fully insert, 

emergency boration is used to complete the reactor shutdown. As part of 

the reactivity control functional recovery and in parallel action with 

emergency boration, the control rods are selected and manually driven in 

per the Emergency Operating Procedures. This can only be performed if 

the non-Class 1E Control Rod Drive Power Supply is available. This 

availability and ability to drive control rod is not relied upon to shut down 

the reactor and maintain it in a safe shutdown condition. 

Therefore, this CRD system function is not within the License Renewal 

boundary.

System Function: CRD-06 Cri 1 Cri 2 Cri 3

Provide a rundown signal to the shutdown and 

regulating rods on a reactor trip.

FP EQ PTS AT SB

Comment: The rundown feature of the Control Rod Drive System is a non-safety 

related regulating control. This is a backup action to the insertion of the 

regulating and shutdown control rods by gravity action on the receipt of a 

reactor trip signal. The reactor trip initiates rundown of the shutdown and 

regulating control rods through relays connected in parallel with the CRDM 

clutches. The rundown feature of the CRD system is not required for safe 

shutdown of the plant. Therefore, this CRD system function is not within 

the License Renewal boundary.

System Function: CRD-07 Cri 1 Cri 2 Cri 3

Provide interlocks to prohibit regulating group rod 

withdrawal under conditions that would put the 

reactor in an undesirable condition.

FP EQ PTS AT SB

X

Comment: Interlocks to prohibit regulating group withdrawal are provided to prevent 

the reactor from reaching undesirable conditions. Operation outside of the 

limitations imposed by these control rod interlocks is not allowed and a 

reactor shutdown is required to enforce this. The limits on shutdown, 

regulating, and part-length rod alignments ensure that the assumptions in 

the safety analysis will remain valid. The requirements on operability 

ensure that upon reactor trip, the full-length control rods will be available 

and will be inserted to provide enough negative reactivity to shut down the 

reactor. The operability requirements also ensure that the control rod 

banks maintain the correct alignment and that each full-length control rod 

is capable of being moved by its CRDM. The operability requirement for 

the part-length rods is that they are fully withdrawn. By maintaining rod 

alignments consistent with the safety analysis a safe shutdown of the 

reactor is ensured.

This CRD system function is within the boundary of License Renewal.
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FSAR Reference

Additional Control Rod Drive System details are provided in Section 7.2, Section 7.5, 

Section 7.6.2.3, Section 4, Section 4.7, Section 8.1.5, Section 8.4, and Appendix 7C of 

the FSAR.

Scoping Boundary Drawings

None.

Components Subject to an AMR

There are no assets for this system that require aging management review. 

System Function: CRD-AT Cri 1 Cri 2 Cri 3

Provide instantaneous negative reactivity to the 

core on demand via gravity insertion of control 

rods during an Anticipated Transient Without 

Scram.

FP EQ PTS AT SB

X

Comment: The Control Rod Drive System, in response to a diverse and independent 

ATWS trip signal, interrupts power to the CRDM clutches which release to 

allow the control rods and connecting CRDM components to drop by 

gravity into the core. This action shuts down the reactor and maintains it in 

a safe shutdown condition. This CRD system function is within the 

boundary of License Renewal.

System Function: CRD-EQ Cri 1 Cri 2 Cri 3

SYSTEM Provide Full In or Not Full In analog 

position for any of 45 Control Rods.

FP EQ PTS AT SB

X

Comment: Full In or Not Full In Control Rod position indication is required for post 

accident monitoring. This indication is needed to verify safe shutdown of 

the reactor.

System Function: CRD-SB Cri 1 Cri 2 Cri 3

Provide instantaneous negative reactivity to the 

core on demand via gravity insertion of control 

rods during a Station Blackout.

FP EQ PTS AT SB

X

Comment: The Control Rod Drive System, in response to a loss of all AC power 

(Station Blackout), receives an RPS low flow trip signal that deenergizes 

the CRDM clutches which release to allow the control rods and connecting 

CRDM components to drop by gravity into the core. This action shuts 

down the reactor and maintains it in a safe shutdown condition. This CRD 

system function is within the boundary of License Renewal.
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2.5.5 Neutron Monitoring System

Description

The Nuclear Monitoring System (NMS) instrumentation consists of excore and incore flux 

monitoring chambers. Eight channels of excore instrumentation monitor the neutron flux 

and six of the eight channels provide reactor protection signals during start-up and power 

operation. Two of the channels follow the neutron flux through the start-up range. The 

incore monitors consist of rhodium neutron detectors and a thermocouple. The incore 

monitoring system provides information on neutron flux and temperatures in the core.

The License Renewal Boundary for the Neutron Monitoring System extends from the 

neutron detector wells embedded in the Reactor Shield Wall which contains the 

source/wide range and power range neutron detector assemblies, through the signal 

cables from the detectors which are routed through Containment electrical penetrations to 

the Control Room and the remote shutdown panel. The system provides safety-related 

inputs to the Reactor Protective System (RPS).

Some SSCs in this system are considered in-scope in accordance with 10 CFR 

54.4(a)(1). Since some SSCs in the Neutron Monitoring System are non-safety related 

and their failure could affect the capability of SR SSCs to perform their safety function, 

they are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to Environmental Qualification and Fire 

Protection in accordance with 10 CFR 54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Neutron Monitoring System, or 

specific components contained in the system, is provided in the summary that follows.

System Function: NMS-01 Cri 1 Cri 2 Cri 3

Provide accurate, self-powered neutron flux 

detection within the reactor core and provide the 

core power profile signals to the Plant Process 

Computer (PPC) for reporting and alarms.

FP EQ PTS AT SB

Comment: This function of the neutron monitoring system does not perform a license 

renewal intended function per 10CFR54.4 and is not within the scope of 

the license renewal rule.
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System Function: NMS-02 Cri 1 Cri 2 Cri 3

Provide instantaneous multiple channel detection 

of neutron flux in the reactor core continuously 

from the source range through 200% of full power.

FP EQ PTS AT SB

Comment: This normal operating function is not in scope. The similar Appendix R 

function is addressed as function NMS-FP.

System Function: NMS-03 Cri 1 Cri 2 Cri 3

Provide an instantaneous reactor power input 

signal to Thermal Margin Monitor from power 

range nuclear instrumentation for thermal 

margin/low pressure trips.

FP EQ PTS AT SB

X

Comment: This function of the Neutron Monitoring System (NMS) is a nuclear safety 

function. The NMS provides a safety-related signal to the Reactor 

Protection System (RPS).

System Function: NMS-04 Cri 1 Cri 2 Cri 3

Provide an instantaneous reactor power input 

signal to RPS from source/wide range Nuclear 

Instrumentation for high rate of power change 

trips.

FP EQ PTS AT SB

X

Comment: This function of the Neutron Monitoring System (NMS) is a nuclear safety 

function. The NMS provides a safety-related signal to the Reactor 

Protection System (RPS).

System Function: NMS-05 Cri 1 Cri 2 Cri 3

Provide an instantaneous reactor power input 

signal to Thermal Margin Monitor from power 

range Nuclear Instrumentation for variable high 

power trips.

FP EQ PTS AT SB

X

Comment: This function of the Neutron Monitoring System (NMS) is a nuclear safety 

function. The NMS provides a safety-related signal to the Reactor 

Protection System (RPS).

System Function: NMS-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: The Neutron Monitoring System contains components that are required to 

be environmentally qualified in accordance with 10CFR50.49.

System Function: NMS-FP Cri 1 Cri 2 Cri 3

Provide instantaneous multiple channel detection 

of neutron flux in the reactor core continuously 

from the source range through 200% of full power.

FP EQ PTS AT SB

X

Comment: The system contains structures and/or components required by the current 

licensing basis for fire protection.
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FSAR Reference

Additional Neutron Monitoring System details are provided in Section 7.6, Section 7.2, 

and Table 5.2-5 of the FSAR.

Scoping Boundary Drawings

None

Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups described in Table 2.5-1.

2.5.6 Radiation Monitoring System

System Description

The Radiation Monitoring System (RIA) consists of monitors, instrumentation and alarms 

that warn plant personnel of increasing radiation levels in various areas of the plant. The 

alarm and/or control functions of these monitors allow action, either automatic or manual, 

to be taken to correct excessive radiation levels or control discharges of radioactive 

material to the environment. The major elements of this system are area monitors, 

process monitors and continuous air monitors. Thirty-seven area monitors are 

strategically locations throughout the plant. They provide both indication and warning of 

radiation levels in both normally radioactive and non-radioactive areas. Instrument ranges 

and sensitivities are chosen to enable monitoring within the requirements of 10 CFR 20. 

The process radiation and effluent radiological monitoring and sampling system is 

designed to assure that ionizing radiation levels are indicated and alarmed so that action, 

either automatic or manual, can be taken to prevent radioactive releases from exceeding 

the limits of 10 CFR 20. Continuous air monitors are used in areas of potential airborne 

radioactivity or air samples are taken with a portable sampler and analyzed for airborne 

radioactivity. Continuous air monitors are set to alarm when the airborne radioactivity 

reaches the applicable derived air concentrations. 

System Function: NMS-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

interactions.

FP EQ PTS AT SB

X

Comment: The system contains some non-safety related components that are 

seismically supported to in order to preclude spatial interaction with other 

safety-related components (specifically, the Audible Count Rate Speaker).
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For license renewal purposes, this system is an electrical system only. The pressure 

boundary components associated with the Radiation Monitoring System are included with 

the systems which they monitor. 

The license renewal boundaries of the Radiation Monitoring System are described as 

follows: The boundaries are as follows: 1) The Containment radiation monitors, 2) area 

radiation elements in the Containment, the auxiliary building, the radwaste building, 

control building, turbine building, and support building, 3) plant system radiation elements 

for the radwaste ventilation, the engineered safeguards rooms ventilation, the 

Containment building gas, the waste gas surge tank outlet, the radwaste discharge, the 

gaseous effluent, the main steam line, and the service water discharge.

Some SSCs in this system are in-scope in accordance with 10 CFR 54.4(a)(1). Since 

some SSCs in the Radiation Monitoring System are non-safety related and their failure 

could affect the capability of SR SSCs to perform their safety function, they are 

considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs 

are considered in-scope due to Environmental Qualification in accordance with 10 CFR 

54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Radiation Monitoring System, or 

specific components contained in the system, is provided in the summary following.

System Function: RIA-01 Cri 1 Cri 2 Cri 3

Monitor condenser off-gas radiation for 

identification of a primary-to-secondary steam 

generator tube leak.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-0631.
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System Function: RIA-02 Cri 1 Cri 2 Cri 3

Automatically align the component cooling surge 

tank vent to the gas collection header on high 

radiation.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-0915. However, 

this component was transferred to the Component Cooling System due to 

a pressure boundary function for that system.

System Function: RIA-03 Cri 1 Cri 2 Cri 3

Monitor the waste gas discharge, and 

automatically close the waste gas decay tank 

discharge valve when the release rate exceeds 

pre-determined limits.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-1113.

System Function: RIA-04 Cri 1 Cri 2 Cri 3

Automatically isolate the liquid radwaste 

discharge.

FP EQ PTS AT SB

X

Comment: Monitor RE-1049 is Q-listed as safety related. Therefore, RE-1049 is in 

boundary of License Renewal.

System Function: RIA-05 Cri 1 Cri 2 Cri 3

Automatically isolate the engineered safeguards 

ventilation on high radiation.

FP EQ PTS AT SB

Comment: Monitor RE-1810 and 1811 initiate the electrical signal to perform this 

function. They are Q-listed for seismic and, therefore, RE-1810 and 1811 

are in boundary of License Renewal under System Function RIA-NSAS.
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System Function: RIA-06 Cri 1 Cri 2 Cri 3

Monitor the main steam safety and dump valve 

discharge.

FP EQ PTS AT SB

Comment: Monitor RE-2323 and RE-2324 perform this function. RE-2323 and -2324 

are Q-Listed for seismic and, therefore, in boundary of License Renewal 

under RIA-NSAS.

System Function: RIA-07 Cri 1 Cri 2 Cri 3

Monitor particulates in the main plant stack. FP EQ PTS AT SB

Comment: Monitor RE-2325 is Q-listed for Technical specifications only. RE-2325 

supports no license renewal criterion and, therefore, is not in the boundary 

of license renewal.

System Function: RIA-08 Cri 1 Cri 2 Cri 3

Monitor for normal range and high range noble 

gases in the main plant stack.

FP EQ PTS AT SB

Comment: Monitors RE-2326 and -2327 are Q-listed for Tech. Spec. only. RE-2326 

and -2327 support no LR criterion and, therefore, are not in the boundary 

of License Renewal.

System Function: RIA-09 Cri 1 Cri 2 Cri 3

Monitor radiation levels in containment and 

provide high radiation signals to CHR.

FP EQ PTS AT SB

X

Comment: Monitors RE-1805, 1806, 1807, 1808, 2316, and 2317 perform this 

function. RE-1805, 1806, 1807, and 1808 are Q-listed as safety related. 

Therefore, RE-1805, 1806, 1807, and 1808 are in boundary of LR for this 

system function. RE-2316, and 2317 Q-listed as seismic only, therefore, 

they are in the boundary of License Renewal under RIA-NSAS.

System Function: RIA-10 Cri 1 Cri 2 Cri 3

Monitor the CVC letdown line for fuel degradation 

via the failed fuel monitor.

FP EQ PTS AT SB

Comment: Monitor RE-0202 is retired in place. Therefore, RE-0202A is not in the 

boundary of License Renewal other than for function RIA-NSAS.
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System Function: RIA-11 Cri 1 Cri 2 Cri 3

Automatically isolate the surface and bottom 

steam generator blowdown isolation valves on 

receipt of a high radiation signal.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-0707.

System Function: RIA-12 Cri 1 Cri 2 Cri 3

Monitor for containment gamma radiation. FP EQ PTS AT SB

X

Comment: Monitors RE-2321 and RE-2322 are Q-listed as safety related. Therefore, 

RE-2321 and RE-2322 are in the boundary of License Renewal.

System Function: RIA-13 Cri 1 Cri 2 Cri 3

Monitor for criticality in the Spent Fuel Pool. FP EQ PTS AT SB

Comment: Monitors RE-2313 and RE-5709 perform this function and are Q-listed as 

seismic only. Therefore, RE-2313 and RE-5709 are in the boundary of 

License Renewal under RIA-NSAS.

System Function: RIA-14 Cri 1 Cri 2 Cri 3

Automatically isolate Fuel Handling Area HVAC on 

high radiation.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-5712.
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System Function: RIA-15 Cri 1 Cri 2 Cri 3

Automatically isolate Penetration/Fan Room HVAC 

on high radiation.

FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. In particular, it does not meet Criterion 1 because it is not 

required to ensure the integrity of the reactor coolant pressure boundary, 

does not affect the capability to shut down the reactor and maintain it in a 

safe shutdown condition, and does not mitigate the consequences of 

accidents that could result in potential offsite exposure comparable to the 

10CFR100 guidelines. It does not meet Criterion 2 because its failure 

could not prevent satisfactory accomplishment of any of the functions of 

Criterion 1. The monitor that supports this function is RE-5710.

System Function: RIA-16 Cri 1 Cri 2 Cri 3

Monitor radiation in the Auxiliary Building areas 

adjacent to piping which could be a source of loss 

of PCS coolant.

FP EQ PTS AT SB

Comment: Monitors RE-2300, -2301 and -2302. perform this function and are Q-listed 

as seismic only. Therefore, RE-2300, RE-2301 and RE-2302 are in the 

boundary of License Renewal under RIA-NSAS.

System Function: RIA-17 Cri 1 Cri 2 Cri 3

Provide Continuous Air Monitoring (CAM) of the 

control room viewing gallery, and alarm on high 

radiation to provide for manual switching of control 

room HVAC to emergency mode.

FP EQ PTS AT SB

Comment: Monitors RE-1818A and RE-1818B are Q-listed for seismic only. 

Therefore, RE-1818A and RE-1818B are in the boundary of License 

Renewal under RIA-NSAS.

System Function: RIA-18 Cri 1 Cri 2 Cri 3

Monitor for noble gases in Containment Building. FP EQ PTS AT SB

Comment: This function is not in-scope of LR because it does not meet any of the 

three LR Criteria. The monitor that supports this function is RE-1817.

System Function: RIA-19 Cri 1 Cri 2 Cri 3

Monitors for radiation in other areas of the plant 

that do not perform a 10 CFR 54, Criteria 1, 2, or 3 

function.

FP EQ PTS AT SB

Comment: This function covers the radiation monitors in the plant that are not 

covered in the other functions for this system. This function is not in-scope 

of LR because it does not meet any of the three LR Criteria. The monitors 

that support this function are RE-1323, 1809, 1815, 2300, 2301, 2302, 

2304, 2305, 2306, 2307, 2308, 2309, 2320, 2328, 5211, 5705, 5707, 5708, 

5711, 5713, and 5714.
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FSAR Reference

Additional Radiation Monitoring System details are provided in Section 6.7, Section 7.4.5, 

Section 9.8, Section 10.2, Section 11.5, Section 11.6, Appendix 7C, Table 5.2-5, Section 

14.15, and Section14.19 of the FSAR.

Scoping Boundary Drawings

System Function: RIA-20 Cri 1 Cri 2 Cri 3

Monitors for radiation in other areas of the plant 

that perform a 10 CFR 54, Criteria 1 function.

FP EQ PTS AT SB

X

Comment: Monitors RE-0833, 2300, 2301, 2302, 2303, 2304, 2305, 2306, 2307, 

2308, 2309, 2310, 2311, 2312, 2314, 2315, 2323, 2324, 2326, 2327, 5701, 

5702, 5703, 5704, 5706, and 5710 perform this function and are required 

to be operable. Therefore, these REs are in boundary of License Renewal. 

RE-2303 is Q-listed for seismic only and is in License Renewal boundary 

under RIA-NSAS.

System Function: RIA-EQ Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Environmental Qualification.

FP EQ PTS AT SB

X

Comment: This function is in-scope of License Renewal. The monitors that support 

this function are RE/RIA-1805, -1806, -1807, -1808, -2321 and -2322.

System Function: RIA-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

interactions.

FP EQ PTS AT SB

X

Comment: The following Radiation Detection Elements are in-scope of License 

Renewal with a Q-list of seismic only: RE-0202, 1810, 1818A, 1818B, and 

5709.

LR-M-202-1 LR-M-207-1

LR-M-208-1A LR-M-210-1C

LR-M-218-2 LR-M-218-4

LR-M-218-6 LR-M-223-1

LR-M-223-1A LR-M-223-1B

LR-M-223-2 LR-M-223-3

LR-M-654
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Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups listed in Table 2.5-1.

2.5.7 Reactor Protective System

Description

The Reactor Protective System (RPS) is a Class 1E system comprised of the sensor 

instrumentation, amplifiers, trip units, logic circuits, actuator circuits and other equipment 

as required to monitor selected nuclear steam supply system conditions is designed to 

reliably effect a rapid reactor shutdown (scram) if any one or combination of conditions 

deviates from a preselected operating range. The system functions to protect the reactor 

core.

The RPS is housed in four cabinets in the control room. The major components are: the 

bistable trip units and Auxiliary trip units; coincidence logic matrices; clutch power trip 

circuits; clutch power supplies; and clutch coil relays.

Components of the RPS in boundary for license renewal include 1E electrical 

components (circuit breakers, indicators, integrators, switches, transformers, isolation 

devices, relays, etc.) that were screened as active. Therefore, no aging management is 

required.

Some SSCs in this system are considered in-scope in accordance with 10 CFR 

54.4(a)(1). Since some SSCs in the Reactor Protective System are non-safety related 

and their failure could affect the capability of SR SSCs to perform their safety function, 

they are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, 

some SSCs are considered in-scope due to ATWS in accordance with 10 CFR 54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Reactor Protective System, or 

specific components contained in the system, is provided in the summary below.

System Function: RPS-01 Cri 1 Cri 2 Cri 3

Provide automatic and manual trips via RPS clutch 

coils.

FP EQ PTS AT SB

X

Comment: RPS is a 1E electrical system.
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FSAR Reference

Additional Reactor Protective System details are provided in Section 7.2 and Section 7.6 

of the FSAR.

Scoping Boundary Drawings

None.

Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups listed in Table 2.5-1.

System Function: RPS-02 Cri 1 Cri 2 Cri 3

Provide automatic and manual trips via RPS 

breakers.

FP EQ PTS AT SB

X

Comment: RPS is a 1E electrical system.

System Function: RPS-03 Cri 1 Cri 2 Cri 3

Provide manual and automatic bypass of RPS 

reactor trips for testing (at power and shutdown) 

and for the equipment protection trips.

FP EQ PTS AT SB

Comment: This function does not support a license renewal criterion.

System Function: RPS-04 Cri 1 Cri 2 Cri 3

Provide trip signals and setpoints and provide 

annunciated alarms to warn of unacceptable DNB 

margins.

FP EQ PTS AT SB

X

Comment: RPS is a 1E electrical system.

System Function: RPS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: ATWS components include Matrix Relays, ATWS1 Relays, etc.

System Function: RPS-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

interactions.

FP EQ PTS AT SB

X

Comment:
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2.5.8 Station Power System

Description

The Station Power System consists of the transformers, switchgear and other 

components necessary to transform 345KV Power to three voltage levels used by the 

internal plant equipment. SPS includes four 4,160 volt buses, four 2,400 volt buses, and 

several 480 volt load centers and 480 volt motor control centers. The subsystems are 

4,160 volt, 2,400 volt, and 480 volt.

The 4,160 volt subsystem is designed to reliably function and supply power during 

normal, abnormal and accident conditions to the 4,160 volt station auxiliaries. The normal 

power source for the 4,160 volt station auxiliaries is the site turbine generator which 

supplies the reactor plant primary coolant pumps and condensate pumps via 21 KV - 

4,160 volt Station Power Transformer 1-1. Also, the cooling towers and associated 

equipment loads are supplied via the 345 kV - 4,160 volt Station Power Transformer 1-3. 

When the turbine generator is out of service, offsite power is supplied to the primary 

coolant pumps and condensate pumps via 345 kV - 4,160 volt Start-Up Transformers 1-1 

and 1-3. The 4,160 volt subsystem provides no safety function and is non-Class 1E. 

The 2,400 volt subsystem is a three-phase, ungrounded power distribution system 

intended to provide a safe, reliable and efficient means of supplying power to the plant 

auxiliary loads during startup, normal, off-normal, emergency and shutdown conditions. 

2,400 volt reactor and turbine plant loads, including the engineered safeguards electric 

subsystem, are normally supplied from either the offsite power source 345 kV - 2,400 volt 

Safeguard Transformer 1-1 or the offsite power source 345 KV - 2,400 volt Start-Up 

Transformer 1-2. To ensure adequate voltage levels on the engineered safeguards 

buses, load shedding and sequencing is utilized to shed all loads and reestablish the 

Class 1E loads on Buses 1C and 1D when the emergency diesel generators are called on 

to supply power.

The 480 volt subsystem distributes power to the safety and non-safety related process 

loads and to non-process equipment during normal, abnormal and emergency conditions. 

Certain 480 volt load center buses receive power from load center transformers 

energized from the 2,400 volt buses. Other 480 volt load center buses receive power from 

load center transformers energized from 4,160 volt Buses 1A, 1F and 1G. The 480 volt 

motor control centers are connected to the 480 volt load center buses.

The boundaries of the in-scope portions of the Station Power System can be described as 

follows: 1) Startup Transformers, 2) Safeguards Transformer and Safeguards Bus, and 3) 

2400 volt AC buses 1C and 1D, 4) 480 volt distribution system supplied from buses 1C 

and 1D, and 5) Preferred AC buses.
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Some SSCs in this system are considered in-scope in accordance with 10 CFR 

54.4(a)(1). Since some SSCs in the Station Power System are non-safety related and 

their failure could affect the capability of SR SSCs to perform their safety function, they 

are considered to be in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some 

SSCs are considered in-scope due to Fire Protection and Station Blackout in accordance 

with 10 CFR 54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Station Power System, or 

specific components contained in the system, is provided in the following summary.

System Function: HAC-01 Cri 1 Cri 2 Cri 3

Start and load 4,160 volt power to the associated 

auxiliary loads under all modes of operation.

FP EQ PTS AT SB

Comment: The 4,160 volt subsystem provides no safety function and is non-Class 

1E. This system function does not support a license renewal criterion.

System Function: HAC-02 Cri 1 Cri 2 Cri 3

Provide transfer (automatically or manually) of the 

4,160 volt loads to the available offsite power 

source (while all auxiliaries continue to run) upon 

turbine generator or reactor trips.

FP EQ PTS AT SB

Comment: The 4,160 volt subsystem provides no safety function and is non-Class 

1E. This system function does not support a license renewal criterion.

System Function: HAC-03 Cri 1 Cri 2 Cri 3

Provide the control room with electrical parameter 

indications and annunciation of important 

functional/parameter changes in the 4160 volt 

subsystem.

FP EQ PTS AT SB

Comment: The 4,160 volt subsystem provides no safety function and is non-Class 

1E. This system function does not support a license renewal criterion.

System Function: HAC-04 Cri 1 Cri 2 Cri 3

Raise the output voltage produced by the main 

generator from 22KV to 345KV for distribution to 

the power grid.

FP EQ PTS AT SB

Comment: This system function is not a function of 4,160 volt subsystem. This 

function is supported by the Turbine Generator System (TGS-09, TGS-10) 

and the Switchyard System (SWY-02).
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System Function: LAC-01 Cri 1 Cri 2 Cri 3

Start and load 480 volt AC power to the associated 

auxiliary loads under all modes of operation.

FP EQ PTS AT SB

X

Comment: The 480 volt system involves both safety and non-safety related 

equipment. Most of the nuclear transient analyses in FSAR Chapter 14 

assumes at least some portion of the 480 volt system associated with 

safeguards equipment is operable. This SPS system function is within the 

boundary of License Renewal.

System Function: LAC-02 Cri 1 Cri 2 Cri 3

Provide AC power to safety related instruments 

and components which are supplied by instrument 

AC panel EY-01.

FP EQ PTS AT SB

Comment: This system function is not a function of 480 volt power. This function is 

supported by the Emergency Power System (EPS-01, PAC-01, EDC-02).

System Function: LAC-03 Cri 1 Cri 2 Cri 3

Provide the instrument AC panel EY-01 as a 

backup to any single preferred AC panel via the 

bypass regulator.

FP EQ PTS AT SB

Comment: This system function is not a function of 480 volt power. This function is 

supported by the Emergency Power System (EPS-01).

System Function: LAC-04 Cri 1 Cri 2 Cri 3

Supply power to Data Logger system components 

from 125 volt non-vital DC or 125 volt AC.

FP EQ PTS AT SB

Comment: Per FSAR Tables 5.2-4 and 5.2-5, the Plant Process Computer and 

associated DC/AC power supplies are non-Safety Class 1E. This system 

function does not support a license renewal criterion.

System Function: MAC-01 Cri 1 Cri 2 Cri 3

Start and load 2,400 volt AC power to the 

associated auxiliary loads under all modes of 

operation.

FP EQ PTS AT SB

X

Comment: The 2,400 volt system is designed to reliably function and supply power 

during normal, abnormal and accident conditions. Two of the four 2,400 

volt buses are an integral part of the plant engineered safeguards 

electrical system and are identified as Class 1E components.
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System Function: MAC-02 Cri 1 Cri 2 Cri 3

Provide automatic and manual transfer of the 

2,400 volt loads to the redundant offsite power 

source, while attached loads continue to run on 

loss of the normal offsite power source.

FP EQ PTS AT SB

X

Comment: If power is lost to the safeguards transformer, the 2,400 volt loads will 

automatically transfer to startup transformer 1-2. Startup Transformer 1-2 

can supply both safety related and non-safety related 2,400 volt loads. 

These safety related loads are required for safe shutdown of the reactor.

System Function: MAC-03 Cri 1 Cri 2 Cri 3

Provide the control room with electrical parameter 

indications and annunciation of important 

functional/parameter changes for 2400 volt AC.

FP EQ PTS AT SB

X

Comment: 2,400 volt buses, 1C and 1D, supply power to engineered safeguard loads 

and are part of the engineered safeguards electrical system. Although 

annunciators are not safety related and required for safe shutdown of the 

reactor, meters and other indicators are necessary for personnel in the 

Control Room to monitor this safeguards electrical system.

System Function: MAC-04 Cri 1 Cri 2 Cri 3

Provide automatic voltage protection of buses 1C 

and 1D from loss or degradation of offsite power 

by tripping the respective incoming bus breakers, 

starting both EDGs, and initiating bus load shed.

FP EQ PTS AT SB

X

Comment: Two of the 2,400 volt buses, 1C and 1D, supply power to engineered 

safeguard loads and are part of the engineered safeguards electrical 

system. If either 2,400 volt bus, 1C or 1D, experiences a sustained 

undervoltage, the associated EDG is started, the affected bus is separated 

from its offsite power sources, major loads are stripped from that bus and 

its supported buses, the EDGs are connected to the bus, and ECCS or 

shutdown loads are started by an automatic load sequencer. These safety 

related loads are required for safe shutdown of the reactor.

System Function: MAC-05 Cri 1 Cri 2 Cri 3

Provide load shed of bus 1E and selected 

nonessential loads on receipt of a Safety Injection 

Actuation Signal.

FP EQ PTS AT SB

X

Comment: The load shedding function is required to support post-accident operation 

of the SPS system and supply of essential power to safety related loads. 

This SPS system function is within the boundary of License Renewal.

System Function: SPS-AT Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Anticipated Transients Without Scram.

FP EQ PTS AT SB

X

Comment: The SPS provides power to the ATWS Control circuitry.
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FSAR Reference

Additional Station Power System details are provided in Section 5, Section 8.1, Section 

8.3, and Section 8.6 of the FSAR.

Scoping Boundary Drawings

The scoping boundary drawings for the Station Power System are listed below:

Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups listed in Table 2.5-1.

2.5.9 Switchyard System

Description

The Switchyard System (SWY) operates at 345 KV and is arranged to give maximum 

availability of the power system grid. The equipment is selected to have the capability of 

System Function: SPS-FP Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components required by the current licensing 

basis for Fire Protection.

FP EQ PTS AT SB

X

Comment: Safeguard busses 1C and 1D and associated load centers, MCCs, and 

inverters and breakers are required for Appendix R safe shutdown of the 

reactor.

System Function: SPS-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

interactions.

FP EQ PTS AT SB

X

Comment: In-scope of License Renewal to protect safety related components.

System Function: SPS-SBO Cri 1 Cri 2 Cri 3

The system constrains structures and/or 

components required by the current licensing 

basis for Station Blackout (Loss of All AC Power).

FP EQ PTS AT SB

X

Comment: The normal supplies from the safeguards transformer in the switchyard to 

safeguard buses 1C and 1D have been included as part of the plant 

equipment required (for License Renewal) for mitigation of the SBO event. 

The inverter breakers supply power to equipment required for safe 

shutdown of the reactor.

LR-WD950-A
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isolating system and substation faults with a minimum effect on stability of the power 

system grid.

The switchyard is designed in a breaker-and-one-half arrangement with two main buses 

(Buses F and R) and connections for the generator main power transformer, the Plant 

safeguard transformer, the Plant start-up transformers, and six outgoing lines. Two of the 

outgoing lines are connected to the American Electric Power system and the remaining 

lines are connected to the Consumers Energy Company system and the Michigan Power 

Pool. Each line has sufficient capacity to carry the entire output of the main turbine 

generator. A line also goes to the independent generator near the plant site.

The license renewal boundaries of the Switchyard license renewal system are described 

as follows: Switchyard components that provide power from 345KV bus F through the 

motor operated disconnect to the Safeguards Transformer, and from 345KV bus R 

through the motor operated disconnect to the Startup Transformers.

Since some SSCs in the Switchyard are non-safety related and their failure could affect 

the capability of SR SSCs to perform their safety function, they are considered to be 

in-scope in accordance with 10 CFR 54.4(a)(2). In addition, some SSCs are considered 

in-scope due to Station Blackout in accordance with 10 CFR 54.4(a)(3).

System Function Listing

A comprehensive listing of functions associated with the Switchyard, or specific 

components contained in the system, is provided in the following summary.

System Function: SWY-01 Cri 1 Cri 2 Cri 3

Provide offsite power to and from the front bus and 

the rear bus.

FP EQ PTS AT SB

Comment: The 345 KV Switchyard System provides no safety function and is 

non-Class 1E. All 345 KV Switchyard components are non-Class 1E. The 

345 KV Switchyard is not taken credit for in any FSAR Chapter 14 event. 

This system function does not support a license renewal criterion.

System Function: SWY-02 Cri 1 Cri 2 Cri 3

Provide 345 kV connection between the 

switchyard and the high side of plant transformers.

FP EQ PTS AT SB

Comment: The 345 KV Switchyard System provides no safety function and is 

non-Class 1E. All 345 KV Switchyard components are non-Class 1E. The 

345 KV Switchyard is not taken credit for in any FSAR Chapter 14 event. 

This system function does not support a license renewal criterion.
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FSAR Reference

Additional Switchyard details are provided in Section 8.2 of the FSAR.

System Function: SWY-03 Cri 1 Cri 2 Cri 3

Provide reliable 240 volt AC power for air 

compressor operation for the switchyard ACB 

breakers.

FP EQ PTS AT SB

Comment: The 345 KV Switchyard System provides no safety function and is 

non-Class 1E. All 345 KV Switchyard components are non-Class 1E. The 

345 KV Switchyard is not taken credit for in any FSAR Chapter 14 event. 

This system function does not support a license renewal criterion.

System Function: SWY-04 Cri 1 Cri 2 Cri 3

Provide reliable DC power for switchyard breaker 

control.

FP EQ PTS AT SB

Comment: The 345 KV Switchyard System provides no safety function and is 

non-Class 1E. All 345 KV Switchyard components are non-Class 1E. The 

345 KV Switchyard is not taken credit for in any FSAR Chapter 14 event. 

This system function does not support a license renewal criterion.

System Function: SWY-05 Cri 1 Cri 2 Cri 3

Provide for reliable operation of switchyard relays 

and breakers.

FP EQ PTS AT SB

Comment: The 345 KV Switchyard System provides no safety function and is 

non-Class 1E. All 345 KV Switchyard components are non-Class 1E. The 

345 KV Switchyard is not taken credit for in any FSAR Chapter 14 event. 

This system function does not support a license renewal criterion.

System Function: SWY-NSAS Cri 1 Cri 2 Cri 3

The system contains structures and/or 

components whose failure could cause failure of 

safety related components due to spatial 

orientation.

FP EQ PTS AT SB

X

Comment: Switchyard-related instruments are located on control room panel.

System Function: SWY-SBO Cri 1 Cri 2 Cri 3

Provide power to the plant during recovery from a 

station blackout event.

FP EQ PTS AT SB

X

Comment: The system contains structures and/or components relied on for recovery 

of offsite power following a Station Blackout (Loss of all AC power). The 

345 KV Switchyard System provides no safety function and is non-Class 

1E.
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Scoping Boundary Drawings

The scoping boundary drawings for the Switchyard are listed below:

Components Subject to an AMR

The components in this system that require aging management review are addressed as 

part of the commodity groups listed in Table 2.5-1.

LR-WD950-A

LR-WD-1421-31
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3.0 Aging Management Review Results

For those structures and components that are subject to aging management review, 10 CFR 

54.21(a)(3) of the license renewal rule requires a demonstration that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the current 

licensing basis for the period of extended operation.

This section describes the results of the aging management reviews for those structures and 

components that were identified in Section 2.0, Scoping and Screening Methodology for Identifying 

Structures and Components Subject to Aging Management Review.

3.0.1 Aging Management Review Results Display Method

This section provides the results of the aging management review for those structures and 

components identified in Section 2.0 as being subject to aging management review. 

Descriptions of the internal and external service environments which were used in the aging 

management review to determine aging effects requiring management are included in Table 

3.0-1, Service Environments. The environments used in the aging management reviews are 

listed in the Environment column. 

Most of the Aging Management Review (AMR) results information in Section 3 is presented 

in the following two tables:

• Table 3.x.1 - where '3' indicates the LRA section number, 'x' indicates the subsection 

number from NUREG-1801, Volume 1, and '1' indicates that this is the first table type in 

Section 3. For example, in the Reactor Coolant System subsection, this table would be 

number 3.1.1, in the Engineered Safety Features subsection, this table would be 3.2.1, 

and so on. For ease of discussion, this table will hereafter be referred to in this Section as 

“Table 1." 

• Table 3.x.2-y - where '3' indicates the LRA section number, 'x' indicates the subsection 

number from NUREG-1801, Volume 1, and '2' indicates that this is the second table type 

in Section 3; and 'y' indicates the system table number. For example, for the Reactor 

Vessel, within the Reactor Coolant System subsection, this table would be 3.1.2-1 and for 

the Reactor Vessel Internals, it would be table 3.1.2-2. For the Containment Spray 

System, within the Engineered Safety Features subsection, this table would be 3.2.2-1. 

For the next system within the ESF subsection, it would be table 3.2.2-2. For ease of 

discussion, this table will hereafter be referred to in this section as “Table 2."

Table Description

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” contains the staff's 

generic evaluation of the existing plant programs. It documents the technical basis for 
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determining where existing programs are adequate without modification, and where existing 

programs should be augmented for the extended period of operation. The evaluation results 

documented in the report indicate that many of the existing programs are adequate to 

manage the aging effects for particular structures or components, within the scope of 

license renewal, without change. The report also contains recommendations on specific 

areas for which existing programs should be augmented for license renewal. In order to take 

full advantage of NUREG-1801, a comparison between the AMR results and the tables of 

NUREG-1801 has been made. The results of that comparison are provided in the two 

tables.

Table 1 (Figure 3.0-1)

The purpose of Table 1 is to provide a summary comparison of how the facility aligns with 

the corresponding tables of NUREG-1801, Volume 1. The table is essentially the same as 

Tables 1 through 6 provided in NUREG-1801, Volume 1, except that the “Type” column 

has been replaced by an “Item Number” column and the “Item Number in GALL” column 

has been replaced by a “Discussion” column. 

The “Item Number” column provides the reviewer with a means to cross-reference from 

Table 2 to Table 1. 

The “Discussion” column is used by the applicant to provide clarifying/amplifying 

information. The following are examples of information that might be contained within this 

column:

• “Further Evaluation Recommended” information or reference to where that information 

is located (including a hyperlink if possible)

• The name of a plant specific program being used (and a hyperlink to the program if 

possible)

• Exceptions to the NUREG-1801 assumptions

• A discussion of how the line item is consistent with the corresponding line item in 

NUREG-1801, Volume 1, when that may not be intuitively obvious

• A discussion of how the line item is different than the corresponding line item in 

NUREG-1801, Volume 1, when it may appear to be consistent (e.g., when there is 

exception taken to an aging management program that is listed in NUREG-1801, 

Volume 1)

The format of Table 1 provides the reviewer with a means of aligning a specific Table 1 

row with the corresponding NUREG-1801, Volume 1 table row, thereby allowing for the 

ease of checking consistency.
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Table 2 (Figure 3.0-2)

Table 2 provides the detailed results of the aging management reviews for those 

components identified in LRA Section 2 as being subject to aging management review. 

There will be a Table 2 for each of the sub-systems within a “system” grouping. For 

example, the Engineered Safety Features System Group contains tables specific to 

Engineered Safeguards system and Reactor Cavity Flood System. 

Table 2 consists of the following nine columns:

• Component Type

• Intended Function

• Material

• Environment

• Aging Effect Requiring Management

• Aging Management Programs

• NUREG-1801 Volume 2 Item

• Table 1 Item 

• Notes

Component Type

The first column identifies all of the component types from Section 2 of the LRA that are 

subject to aging management review. They are typically listed in alphabetical order.

Intended Function

The second column contains the license renewal intended functions (including 

abbreviations where applicable) for the listed component types. Definitions and 

abbreviations of intended functions are contained within the Intended Functions table of 

LRA Section 2.

Material

The third column lists the particular materials of construction for the component type. 

Environment

The fourth column lists the environment to which the component types are exposed. 

Internal and external service environments are indicated and a list of these environments 

is provided in Table 3.0-1, Service Environments.
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Aging Effect Requiring Management

As part of the aging management review process, the applicant determines any aging 

effects requiring management for the material and environment combination in order to 

maintain the intended function of the component type. These aging effects requiring 

management are listed in column five.

Aging Management Programs 

The aging management programs used to manage the aging effects requiring 

management are listed in column six of Table 2.

In many cases, a particular Palisades Aging Management Program will implement more 

than one program defined in the GALL. To assist with NRC reviews, and to simplify the 

correlation with the associated table in GALL Volume 2, the Programs column will 

typically contain the GALL program number, and then, in parentheses, the title of the 

Palisades AMP that contains the GALL program. 

NUREG-1801 Vol. 2 Item

Each combination of component type, material, environment, aging effect requiring 

management, and aging management program that is listed in Table 2, is compared to 

NUREG-1801, Volume 2, with consideration given to the standard notes, to identify 

consistencies. When they are identified, they are documented by noting the appropriate 

NUREG-1801, Volume 2 item number in column seven of Table 2. If there is no 

corresponding item number in NUREG-1801, Volume 2, this row in column seven is left 

blank. That way, a reviewer can readily identify where there is correspondence between 

the plant specific tables and the NUREG-1801, Volume 2 tables. 

Table 1 Item

Each combination of component, material, environment, aging effect requiring 

management, and aging management program that has an identified NUREG-1801 

Volume 2 item number must also have a Table 3.x.1 line item reference number. The 

corresponding line item from Table 1 (Figure 3.0-1) is listed in column eight of Table 2. If 

there is no corresponding item in NUREG-1801, Volume 1, this row in column eight is left 

blank. That way, the information from the two tables can be correlated.

Notes

In order to realize the full benefit of NUREG-1801, each applicant needs to identify how 

the information in Table 2 aligns with the information in NUREG-1801, Volume 2. This is 

accomplished through a series of notes. All note references with letters are standard 

notes that will be the same from application to application throughout the industry. Any 
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Technical and Administrative Information

notes the plant requires, which are in addition to the standard notes, will be identified by a 

number and deemed plant specific.

Table Usage

Table 1 

The reviewer evaluates each row in Table 1 (Figure 3.0-1) by moving from left to right 

across the table. Since the Component, Aging Effect/Mechanism, Aging Management 

Programs and Further Evaluation Recommended information is taken directly from 

NUREG-1801, Volume 1, no further analysis of those columns is required. The 

information intended to help the reviewer the most in this table is contained within the 

Discussion column. Here the reviewer will be given information necessary to determine, 

in summary, how the applicant's evaluations and programs align with NUREG-1801, 

Volume 1. This may be in the form of descriptive information within the Discussion column 

or the reviewer may be referred to other locations within the LRA for further information 

(including hyperlinks where possible/practical).

Table 2

The Table 2 (Figure 3.0-2) contains all of the Aging Management Review information for 

each system, structure, or commodity, whether or not it aligns with NUREG-1801. For a 

given row within the table, the reviewer is able to see the intended function, material, 

environment, aging effect requiring management and aging management program 

combination for a particular component type within that system, structure, or commodity. 

In addition, if there is a correlation between the combination in Table 2 and a combination 

in NUREG-1801, Volume 2, this will be identified by a referenced item number in column 

seven, NUREG-1801, Volume 2 Item. The reviewer can refer to the item number in 

NUREG-1801, Volume 2, if desired, to verify the correlation. If the column is blank, the 

applicant was unable to locate an appropriately corresponding combination in 

NUREG-1801, Volume 2.

As the reviewer continues across the table from left to right, within a given row, the next 

column is labeled Table 1 Item. If there is a reference number in this column, the reviewer 

is able to use that reference number to locate the corresponding row in Table 1 and see 

how the aging management program for this particular combination aligns with 

NUREG-1801. Program details may be found in Appendix B. There may be a hyperlink 

directly to the corresponding row in Table 1 as well.

Table 2 provides the reviewer with a means to navigate from the components subject to 

Aging Management Review (AMR) in LRA Section 2, all the way through the evaluation of 

the programs that will be used to manage the effects of aging of those components.

A listing of the abbreviations used in this section is provided in Section 1.5.
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Table 3.0-1 Service Environments

Category Description

Air/Gas The air/gas environment includes dry, filtered instrument air, nitrogen, and 

other vendor-supplied gases that may be used for analysis or calibration. Air 

conditions may include humidity, condensation, and contaminants.

Atmosphere/ 

Weather

The atmosphere/weather conditions that may affect aging of systems, 

structures, or components (SSC) include temperature, precipitation, and 

ultraviolet radiation. The December 1977 through November 1978 recorded 

Palisades atmosphere/weather environment is bounded by temperatures of 

-2.9°F to 88.3°F. The US Weather Bureau has reports of extremes for areas 

near Palisades of -25°F and 95°F. Periodic wetting and ultraviolet radiation 

must be considered for SSC exposed to atmosphere/weather.

The atmosphere/weather environment includes atmospheric air outside 

covered structures and includes moist laden air, precipitation, and wind. 

Borated Water 

Leakage

Systems, structures, and components may be located in the vicinity of primary 

systems containing boric acid solution that could leak, creating a boric acid 

leakage environment, and leading to boric acid corrosion. Borated water 

systems and the boric acid leakage may exist within the Auxiliary Building, the 

Auxiliary Building Addition, and the Containment.

The borated water leakage is an external environment that includes all plant 

areas that contain borated water systems that leak on nearby components or 

structures.
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Containment Air Temperature - The Containment air environment, outside the reactor cavity, is 

bounded during normal operation by temperatures of 50°F to 144°F. 

Summertime temperatures inside the Pressurizer Shed typically approach 

140°F, and around the PCS hot and cold leg piping they approach 130°F. 

Even the cooler areas in containment, down on the 590' elevation have typical 

summer temperatures up to around 110°F. EQ Design Basis temperatures 

approach 136°F for 590' - 610' elevations and 144°F for 611' - 670' elevations. 

Thermal hot spots may exist within the Containment and should be specified 

in individual aging management review reports. 

For electrical commodities the average temperature for elevations 611' - 702' 

is 123 °F and for elevations 590' - 610' it is 96.2 °F.

Relative Humidity - Normal relative humidity is approximately 50% but for 

aging management is assumed at 100%. 

Radiation - Plant radiation doses outside the reactor cavity are not of concern 

for aging management. Materials can be affected by cumulative radiation 

exposure. For concrete, neutron fluence above 1019 n/cm2 (>1 Mev) or 

gamma dose >1010 rads is required to cause degradation. For metals, 

neutron fluence above 1017 n/cm2 (>1 Mev) is required to cause degradation.

For electrical commodities in containment the 60 year bounding value for 

radiation is 3X107 rads.

Electrical 

Environment 

Evaluation 

Parameters

Each of the three significant stressors for insulated cables and connections 

could lead to a loss of material properties of the insulating material of cables 

and connections when exposed to environment more severe than their 

respective 60-year service-limiting values for temperature and radiation.

Bounding electrical stressor conditions have been defined for temperature, 

radiation and moisture.

Oil This category encompasses lubricating oil, diesel fuel oil, or hydraulic oil. 

Palisades Systems having this internal environment include, but not limited to, 

the Emergency Diesel Generator (EDG) Fuel Oil System, and the EDG Lube 

Oil System. 

Table 3.0-1 Service Environments

Category Description
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Plant Indoor Air Plant indoor air includes all heated, ventilated, or air conditioned plant areas 

sheltered from outside conditions. 

Temperature - A temperature range of 50°F to 120°F and relative humidity of 

up to100% bound plant indoor air conditions. 

For example, in the Component Cooling Water room el. 607', the average 

temperature is 110 °F, and for Component Cooling Water room el. 625', the 

average temperature is 120 °F. All other areas are less than or equal to an 

average temperature of 104 °F.

Relative Humidity - Normal relative humidity is approximately 50% but for 

aging management is assumed at 100%. 

Radiation - Plant radiation doses outside the Containment are not of concern 

for aging management. For commodities outside containment the 60 year 

bounding radiation dose is <7.5X107 rads. 

Raw Water Raw water is defined as water that enters the plant from Lake Michigan, 

pond, or rain/ground water source that has not been demineralized or 

chemically treated to any significant extent. In general, the water is rough 

filtered to remove large particles. Biocides may be added to control 

micro-organisms or macro-organisms. Another designation of raw water is 

water that leaks from any system. The Raw Water category at Palisades 

constitutes the lake water used for the main condensers, intake cooling 

water, and fire protection. 

Soil (Buried) Portions of systems, structures, and components (SSC) such as foundations, 

buried piping, buried tanks, buried valves, buried cable, etc. may be exposed 

to soil/earth. These SSCs are exposed to soil/earth, fill, and ground 

water/runoff.

Depending on the particular site groundwater table levels, buried components 

may also be exposed to the chemicals in the groundwater. The groundwater 

chemistry, which may be acidic or contain chlorides and sulfates, plays a 

major role in the determination of the degradation of below grade 

components. 

Examples of buried components are buried fuel oil tanks, the exterior surface 

of a foundation or basemat, those portions of a building's exterior walls below 

grade, buried concrete such as duct banks or concrete trenches. If the buried 

component is exposed to flowing groundwater or other aqueous liquids, then 

component surfaces exposed to raw water environment were considered. 

Table 3.0-1 Service Environments

Category Description
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Submerged 

(Structural) 

Components and piping that are exposed to raw water can be submerged in 

water or exposed to flowing water. The types of water may be raw water (lake 

or pond water), groundwater, or even treated water (e.g., wet cooling towers). 

The chemicals in the water source may be acidic or contain chlorides and 

sulfates and play a major role in the determination of the degradation of 

concrete. Examples of concrete exposed to raw water are the submerged 

potion of a water control structure (intake or pump structure) exterior and 

interior walls, intake system, and mechanical wet cooling towers. 

Treated Water 

and/or Steam

Demineralized water or chemically purified water that is the source for 

water that may require further processing, such as for the primary or 

secondary coolant system. Treated water can be de-aerated, can include 

corrosion inhibitors, biocides, or boric acid, or can include a combination of 

treatments. Steam generated from treated water is included in this 

environment category. 

Table 3.0-1 Service Environments

Category Description
Page 3-10 

Figure 3.0-1 Table 1 - 

Application for Renewed Operating Licenses

Table 3.x.1, Summary of Aging Management Evaluations in Chapter _____ of NUREG-1801 for ____________

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.x.1-013.x.1-023.x.1-033.x.1-043.x.1-053.x.1-06
Page 3-11 

Figure 3.0-2 Table 2 - 

Application for Renewed Operating Licenses

Table 3.x.2-y, Section 3 Title - Plant Specific System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
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3.1 Aging Management of Reactor Coolant System

3.1.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.3.1, Reactor Vessel, Internals, and Reactor Coolant System, as being 

subject to aging management review. The systems, or portions of systems, which are 

addressed in this section, are described in the indicated sections.

• Primary Coolant System (Section 2.3.1.1)

• Reactor Vessel (Section 2.3.1.2)

• Reactor Vessel Internals (Section 2.3.1.3)

• Replacement Steam Generators (Section 2.3.1.4)

Table 3.1.1, Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for 

Reactor Coolant System, provides the summary of the programs evaluated in NUREG-1801 

for the Reactor Coolant System component groups that are relied on for license renewal. 

This table uses the format described in Figure 3.0-1 above. Note that this table only includes 

those component groups that are applicable to a PWR.

3.1.2 Results

The following tables summarize the results of the aging management review for systems in 

the Reactor Vessel, Reactor Internals, and Reactor Coolant System group: 

Table 3.1.2-1, Reactor Coolant System - Primary Coolant System - Summary of Aging 

Management Evaluation

Table 3.1.2-2, Reactor Coolant System - Reactor Vessel - Summary of Aging Management 

Evaluation

Table 3.1.2-3, Reactor Coolant System - Reactor Vessel Internals - Summary of Aging 

Management Evaluation

Table 3.1.2-4, Reactor Coolant System - Replacement Steam Generators - Summary of 

Aging Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the potential aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for each of the 

above systems in the following subsections of Section 3.1.2.1, Materials, Environment, 

Aging Effects Requiring Management and Aging Management Programs:

Section 3.1.2.1.1, Primary Coolant System
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Section 3.1.2.1.2, Reactor Vessel

Section 3.1.2.1.3, Reactor Vessel Internals

Section 3.1.2.1.4, Replacement Steam Generators

3.1.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.1.2.1.1 Primary Coolant System

Materials

The materials of construction for the Primary Coolant System are:

• Alloy 600

• Carbon Steel

• Cast Austenitic SS

• Low Alloy Steel

• Stainless Steel

• Epoxy Coated Carbon Steel

Environment

The Primary Coolant System is exposed to the following environments:

• Containment Air (Ext)

• Plant Indoor Air (Ext)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Primary Coolant System, 

require management:

• Cracking 

• Loss of Material

• Loss of Preload

• Reduction of Fracture Toughness 
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Primary Coolant System:

• Alloy 600 Program

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.1.2.1.2 Reactor Vessel

Materials

The materials of construction for the Reactor Vessel are:

• Carbon Steel

• Nickel-Based Alloys

• Stainless Steel

Environment

The Reactor Vessel components are exposed to the following environments:

• Containment Air (Ext)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Reactor Vessel, require 

management:

• Crack Initiation and Growth

• Cracking 

• Loss of Material

• Reduction in Fracture Toughness 

• Loss of Preload
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Reactor Vessel components:

• Alloy 600 Program

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Reactor Vessel Integrity Surveillance Program

• Reactor Vessel Internals Inspection Program

• Water Chemistry Program

3.1.2.1.3 Reactor Vessel Internals

Materials

The materials of construction for the Reactor Vessel Internals are:

• Stainless Steel

Environment

The Reactor Vessel Internals components are exposed to the following 

environments:

• Treated Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Reactor Vessel Internals, 

require management:

• Changes in Dimensions 

• Cracking

• Loss of Material 

• Loss of Preload

• Reduction in Fracture Toughness

Aging Management Programs

The following aging management programs manage the aging effects for the 

Reactor Vessel Internals components:

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program
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• Reactor Vessel Internals Inspection Program

• Water Chemistry Program

3.1.2.1.4 Replacement Steam Generators

Materials

The materials of construction for the Replacement Steam Generators are:

• Alloy 600/690

• Carbon Steel

• Carbon Steel w/SS Cladding

• Low-Alloy Steel

• Nickel Based Alloy

• Stainless Steel

Environment

The Replacement Steam Generators components are exposed to the following 

environments:

• Containment Air (Ext)

• Treated Water (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Replacement Steam 

Generators, require management:

• Cracking

• Crack Initiation and Growth

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Replacement Steam Generators components:

• Alloy 600 Program

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Bolting Integrity Program
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• Boric Acid Corrosion Program

• Flow Accelerated Corrosion Program

• Steam Generator Tube Integrity Program

• Water Chemistry Program

3.1.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 Volume 1 Tables provide the basis for identifying those programs 

that warrant further evaluation in the license renewal application. For the Reactor 

Vessel, Internals, and Reactor Coolant System group, those programs are 

addressed in the following sections.

3.1.2.2.1 Cumulative Fatigue Damage

NUREG-1800 states that cracking due to fatigue is an aging effect applicable 

to primary coolant system items subject to aging management review. Fatigue 

evaluations are TLAAs since they are based on design transients (cyclic 

loadings) defined for the life of the plant. 

Fatigue evaluations were performed in the design of the Palisades Class 1 

Primary Coolant System components in accordance with the requirements 

specified in applicable design codes. Fatigue is a TLAA as defined in 10 CFR 

54.3. TLAAs are required to be evaluated in accordance with 10 CFR 

54.21(c). The evaluation of this TLAA is addressed separately in Section 4.3.

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion (PWR/BWR)

3.1.2.2.2.1 Loss of Material due to Pitting and Crevice Corrosion in Steam 

Generator Shell Assembly

NUREG-1800 states that Loss of material due to pitting and crevice 

corrosion could occur in the steam generator shell assembly. The existing 

program relies on control of chemistry to mitigate corrosion and ISI to detect 

loss of material. The extent and schedule of the existing steam generator 

inspections are designed to ensure that flaws cannot attain a depth 

sufficient to threaten the integrity of the welds. However, according to NRC 

Information Notice (IN) 90-04, if general corrosion pitting of the shell exists, 

the program may not be sufficient to detect pitting and corrosion. 

NUREG-1801 recommends augmented inspection to manage this aging 

effect.
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NUREG-1801 refers to NRC Information Notice (IN) 90-04 and 

recommends augmented inspection to manage pitting and crevice 

corrosion. IN 90-04 states that if general corrosion pitting of the steam 

generator shell is known to exist the requirements of ASME Section XI may 

not be sufficient to differentiate isolated cracks for inherent geometric 

conditions. 

The concerns of IN 90-04 are not applicable to Palisades since the steam 

generators were replaced in 1990 and pitting corrosion of the steam 

generator shell is not known to currently exist. Therefore, Palisades credits 

the water chemistry control program and the inservice inspection program 

for managing loss of material due to pitting and crevice corrosion on the 

internal surfaces of the steam generator shell, and recommends using the 

Steam Generator Tube Integrity Program to manage pitting and crevice 

corrosion. The Steam Generator Tube Integrity Program incorporates the 

guidance of NEI 97-06 “Steam Generator Program Guidelines” (January 

2001) to verify the integrity of the secondary-side internal surfaces of the 

steam generators. The Program manages the aging effects of accessible 

SG secondary side internal components through a balance of mitigation, 

inspection, evaluation, repair, and leakage monitoring measures.

Therefore, a combination of the Water Chemistry Program , ASME Section 

XI IWB, IWC, IWD, IWF Inservice Inspection Program , and the Steam 

Generator Tube Integrity Program are used to manage this aging effect. 

3.1.2.2.2.2 Loss of Material due to Pitting and Crevice Corrosion

Applicable to BWR Only 

3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement 

BWR/PWR)

3.1.2.2.3.1 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement - 

TLAA Evaluation

NUREG-1800 states that certain aspects of neutron irradiation 

embrittlement are TLAAs as defined in 10 CFR 54.3. TLAAs are required to 

be evaluated in accordance with 10 CFR 54.21(c)(1).

Neutron irradiation embrittlement is a TLAA to be evaluated for the period of 

license renewal for ferritic materials that have a neutron fluence of greater 

than 1.0E17 n/cm2 (E >1 MeV) at the end of the license renewal term. The 

beltline region, as described in Section 3.1.2.1.1, was verified to be the 
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limiting region in evaluating loss of fracture toughness due to neutron 

irradiation embrittlement. This TLAA is discussed in Section 4.2

3.1.2.2.3.2 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement - 

Reactor Vessel Materials Surveillance Program

NUREG-1800 states that loss of fracture toughness in reactor vessel 

beltline shell and weld materials due to neutron irradiation embrittlement 

has been identified as an aging effect requiring management during the 

period of extended operation. A reactor vessel materials surveillance 

program monitors neutron irradiation embrittlement of the reactor vessel. 

Reactor vessel surveillance programs are plant specific, depending on 

matters such as the composition of limiting materials, availability of 

surveillance capsules, and projected fluence levels. In accordance with 10 

CFR Part 50, Appendix H, an applicant is required to submit its proposed 

withdrawal schedule for approval prior to implementation. 

At Palisades, loss of fracture toughness in reactor vessel beltline materials 

due to neutron irradiation embrittlement is an aging effect requiring 

management during the period of extended operation. The limiting beltline 

materials in the Palisades reactor vessel are the plates and welds as 

indicated in Table 3.1.2-2 and Section 4.2. See Section 4.2 for additional 

information.

Reactor vessel upper shell and nozzles are not subject to significant 

neutron irradiation exposure because of their physical distance from the 

reactor core. For beltline materials, the Reactor Vessel Integrity 

Surveillance Program, in conjunction with TLAA analyses, effectively 

manages loss of fracture toughness. The Palisades Reactor Vessel 

Integrity Surveillance Program provides adequate material property and 

neutron dosimetry data to predict fracture toughness in beltline materials at 

the end of the period of extended operation.

3.1.2.2.3.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement

NUREG-1800 states that loss of fracture toughness due to neutron 

irradiation embrittlement and void swelling could occur in Westinghouse 

and B&W baffle/former bolts. NUREG-1801 recommends further evaluation 

to ensure that this aging effect is adequately managed. 

This issue is not applicable. Palisades is a Combustion Engineering PWR 

and does not have a baffle/former bolt configuration.
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3.1.2.2.4 Crack Initiation and Growth due to Thermal and Mechanical Loading or 

Stress Corrosion Cracking (BWR/PWR)

3.1.2.2.4.1 Crack Initiation and Growth due to Thermal and Mechanical Loading 

or Stress Corrosion Cracking of Small-Bore Piping <4” NPS

NUREG-1800 states that crack initiation and growth due to thermal and 

mechanical loading or SCC (including intergranular stress corrosion 

cracking (IGSCC) could occur in small-bore reactor coolant system and 

connected system piping less than NPS 4”. The existing program relies on 

ASME Section XI ISI and on control of water chemistry to mitigate SCC. 

NUREG-1801 recommends that a plant-specific destructive examination or 

a nondestructive examination (NDE) that permits inspection of the inside 

surfaces of the piping be conducted to ensure that cracking has not 

occurred and the component intended function will be maintained during the 

extended period. The AMPs should be augmented by verifying that service 

induced weld cracking is not occurring in the small-bore piping less than 

NPS 4, including pipe, fittings, and branch connections. 

At Palisades, crack initiation and growth due to SCC was identified as an 

aging effect/mechanism requiring management in small-bore (<NPS 4) 

primary coolant system piping and branch lines. Aging management of 

service-induced cracking will be accomplished by a combination of the 

Water Chemistry Program and the ASME Section XI, Subsections IWB, 

IWC, and IWD Inservice Inspection Program. Inspections of a sample of 

small bore PCS piping will be performed.

The proposed combination of the Water Chemistry Program , and the 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program , 

provide an effective means of managing service-induced cracking in 

small-bore primary coolant system piping and connected branch lines 

during the period of extended operation.

3.1.2.2.4.2 Crack Initiation and Growth due to Thermal and Mechanical Loading 

or Stress Corrosion Cracking (BWR Only)

Applicable to BWR Only

3.1.2.2.4.3 Crack Initiation and Growth due to Thermal and Mechanical Loading 

or Stress Corrosion Cracking (BWR Only)

Applicable to BWR Only
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3.1.2.2.5 Crack Growth due to Cyclic Loading

NUREG-1800 states that crack growth due cyclic loading could occur in 

reactor vessel shell and reactor coolant system piping and fittings. Growth of 

intergranular separations (underclad cracks) in low-alloy or carbon steel heat 

affected zone under austenitic stainless steel cladding is a time-limited aging 

analysis (TLAA) to be evaluated for the period of extended operation for all the 

SA 508-Cl 2 forgings where the cladding was deposited with a high heat input 

welding process.

The Palisades reactor vessel items fabricated from SA-508 Class 2 material 

include the primary nozzles, reactor vessel flange, and the closure head 

flange. NUREG-1801 identifies this aging effect as applicable to reactor vessel 

items fabricated from SA-508, Class 2 materials exposed to a neutron fluence 

> 1.0E17 n/cm2. The fluence at the end of the period of extended operation at 

the bottom of the nozzle to shell welds (highest fluence received by an SA-508 

Class 2 Palisades item) has been determined to be 6 orders of magnitude less 

than 1.0E19 n/cm2, approximately 1.0E13 n/cm2. In addition, controls on the 

cladding chemical composition and processes during fabrication of the 

Palisades reactor vessel reduced the potential for cracking of the vessel 

cladding. There have been no cases of underclad cracking in any clad 

Combustion Engineering reactor vessel subcomponents. Therefore, this aging 

effect does not require management for the period of extended operation for 

Palisades.

3.1.2.2.6 Changes in Dimension due to Void Swelling

NUREG-1800 states that changes in dimension due to void swelling could 

occur in reactor internal components. NUREG-1801 recommends further 

evaluation to ensure that this aging effect is adequately managed. The reactor 

vessel internals receive a visual inspection (VT-3) according to Category 

B-N-3 of Subsection IXB, ASME Section XI. This inspection is not sufficient to 

detect the effects of changes in dimension due to void swelling. GALL 

recommends that a plant specific aging management program should be 

evaluated. The applicant provides a plant specific AMP or participates in 

industry programs to investigate aging effects and determine appropriate 

AMP. Otherwise, the applicant provides the basis for concluding that void 

swelling is not an issue for the component. The applicant should either provide 

the basis for concluding that void swelling is not an issue for the component or 

provide a program to manage the effects of changes in dimension due to void 

swelling and the loss of ductility associated with swelling.
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Industry activities are underway to determine whether changes in dimension 

due to void swelling is an aging effect requiring management for license 

renewal. Palisades continues to participate in industry investigations of aging 

effects applicable to reactor vessel internals, as well as initiatives to develop 

and qualify methods for detection and management. Palisades will incorporate 

applicable results of industry initiatives related to void swelling in the Reactor 

Vessel Internals Inspection Program . 

3.1.2.2.7 Crack Initiation and Growth due to Stress Corrosion Cracking or Primary 

Water Stress Corrosion Cracking (PWR)

3.1.2.2.7.1 Crack Initiation and Growth due to Stress Corrosion Cracking or 

Primary Water Stress Corrosion Cracking (PWR Components)

NUREG-1800 states that crack initiation and growth due to SCC and 

primary water stress corrosion cracking (PWSCC) could occur in PWR core 

support pads (or core guide lugs), instrument tubes (bottom head 

penetrations), pressurizer spray heads, and nozzles for the steam 

generator instruments and drains. NUREG-1801 recommends further 

evaluation to ensure that these aging effects are adequately managed. 

NUREG-1801 recommends that a plant specific aging management 

program be evaluated because existing programs may not be capable of 

mitigating or detecting crack initiation and growth due to SCC.

At Palisades, this grouping includes the surge nozzle thermal sleeve, safety 

injection nozzle thermal sleeve, charging inlet nozzle thermal sleeve, RTD 

nozzles, pressure measurement nozzle, sampling nozzle, and partial nozzle 

replacement. Reactor vessel items included in this grouping are the lower 

shell and bottom head cladding, surveillance capsule holders, core 

stabilizing lugs, core stop and support lugs, and the flow baffle and skirt., 

the reactor head O-ring, leakoff tubing and valves. Steam generator items 

included in this grouping are the tube plate cladding, channel head divider 

plate, and primary nozzle closure rings. Refer to item 3.1.1-44 of Table 3.1.1 

for primary side steam generator items. EPRI Material Reliability Program 

(MRP) in conjunction with the PWR owners groups is developing a strategic 

plan to manage and mitigate cracking of nickel based alloy items. The 

guidance developed by the MRP will be used to identify critical locations for 

inspection and to augment existing ISI inspections at Palisades, as 

appropriate. The results of the strategic plan will be incorporated into the 
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Alloy 600 Program and, as applicable, the Water Chemistry Program and 

the ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program . 

3.1.2.2.7.2 Crack Initiation and Growth due to Stress Corrosion Cracking or 

Primary Water Stress Corrosion Cracking (CASS Components)

NUREG-1800 states that crack initiation and growth due to SCC could 

occur in PWR cast austenitic stainless steel (CASS) reactor coolant system 

piping and fittings and pressurizer surge line nozzle. NUREG-1801 

recommends further evaluation of piping that does not meet either the 

reactor water chemistry guidelines of TR-105714 or material guidelines of 

NUREG-0313.

At Palisades, the Primary Coolant Pump casing and the valve bodies of 

PORV isolation valves are fabricated of cast austenitic stainless steel 

(CASS). The Palisades Water Chemistry Program and the ASME Section 

XI IWB, IWC, IWD, IWF Inservice Inspection Program are used to manage 

this aging effect. The Water Chemistry Program meets the EPRI reactor 

water chemistry guideline TR-105714. As discussed in the respective 

sections of Appendix B, each of these programs provides reasonable 

assurance that the aging effect will be managed such that the SSCs within 

the scope of each program will continue to perform their intended functions 

consistent with the current licensing bases for the period of extended 

operation.

3.1.2.2.7.3 Crack Initiation and Growth due to Stress Corrosion Cracking or 

Primary Water Stress Corrosion Cracking (Ni Alloys)

NUREG-1800 states that crack initiation and growth due to PWSCC could 

occur in PWR pressurizer instrumentation penetrations and heater sheaths 

and sleeves made of Ni alloys. The existing program relies on ASME 

Section XI ISI and on control of water chemistry to mitigate PWSCC. 

However, the existing program should be augmented to manage the effects 

of SCC on the intended function of Ni-alloy components. NUREG-1801 

recommends that the applicant provide a plant-specific AMP or participate 

in industry programs to determine appropriate AMP for PWSCC of Inconel 

182 weld.

At Palisades, nickel based alloy material is identified for the pressurizer 

instrumentation nozzles, heater sheaths and sleeves, and thermal sleeves. 

Palisades pressurizer components included in this grouping are the 

instrument nozzles, electric heaters (penetration nozzles and plugs, original 
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heater sheath, heater sleeve, and end plugs). The programs credited for the 

management of PWSCC of these nickel based alloy items are the Alloy 600 

Program and Water Chemistry Program , supplemented by the ASME 

Section XI IWB, IWC, IWD, IWF Inservice Inspection Program . As 

described in Section 3.1.2.2.7.1, above, the Alloy 600 Program includes 

participation in industry programs to identify critical locations for inspection 

and augment existing ISI inspections at Palisades where appropriate. 

3.1.2.2.8 Crack Initiation and Growth due to Stress Corrosion Cracking or 

Irradiation-Assisted Stress Corrosion Cracking

NUREG-1800 states that crack initiation and growth due to SCC or IASCC 

could occur in baffle / former bolts in Westinghouse and B&W reactors. 

Historically the VT-3 visual examinations have not identified baffle/former bolt 

cracking because cracking occurs at the juncture of the bolt head and shank, 

which is not accessible for visual inspection. However, recent UT 

examinations of the baffle/former bolts at several plants have identified 

cracking. The industry is currently addressing the issue of baffle bolt cracking 

in the PWR Materials Reliability Project, Issues Task Group (ITG) activities to 

determine, develop, and implement the necessary steps and plans to manage 

the applicable aging effects on a plant-specific basis. NUREG-1801 

recommends further evaluation to ensure that these aging effects are 

adequately managed. 

The Palisades reactor vessel internals do not include baffle / former bolts. The 

discussion in this paragraph of NUREG-1800 is not applicable to Palisades.

3.1.2.2.9 Loss of Preload due to Stress Relaxation

NUREG-1800 states that loss of preload due to stress relaxation could occur 

in baffle/former bolts in Westinghouse and B&W reactors. Visual inspection 

(VT-3) should be augmented to detect relevant conditions of stress relaxation 

because only the heads of the baffle/former bolts are visible, and a plant 

specific aging management program is thus required. NUREG-1801 

recommends a plant specific aging management program to ensure that these 

aging effects are adequately managed. Acceptance criteria are described in 

Branch Technical Position RLSB-1 (Appendix A.1 of the standard review plan).

The Palisades reactor vessel internals do not include baffle / former bolts. The 

discussion in this paragraph of NUREG-1800 is not applicable to Palisades.
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3.1.2.2.10 Loss of Section Thickness due to Erosion

NUREG-1800 states that loss of section thickness due to erosion could occur 

in steam generator feedwater impingement plates and supports. 

NUREG-1801 recommends further evaluation of a plant-specific aging 

management program to ensure that this aging effect is adequately managed.

The Palisades steam generators do not include impingement plates. 

Therefore, the discussion in this paragraph is not applicable.

3.1.2.2.11 Crack Initiation and Growth due to PWSCC, ODSCC, or Intergranular 

Attack or Loss of Material due to Wastage and Pitting Corrosion or Loss 

of Section Thickness due to Fretting and Wear or Denting due to 

Corrosion of Carbon Steel Tube Support Plate

NUREG-1800 states that crack initiation and growth due to PWSCC, ODSCC, 

or intergranular attack (IGA) or loss of material due to wastage and pitting 

corrosion or deformation due to corrosion could occur in alloy 600 

components of the steam generator tubes, repair sleeves and plugs. All PWR 

licensees have committed voluntarily to a SG degradation management 

program described in NEI 97-06. NUREG-1801 recommends that an AMP 

based on the recommendations of staff-approved NEI 97-06 guidelines, or 

other alternate regulatory basis for SG degradation management, should be 

developed to ensure that this aging effect is adequately managed.

At Palisades, crack initiation and growth due to PWSCC, SCC, or 

intergranular attack (IGA) or loss of material due to wastage and pitting 

corrosion or deformation due to corrosion could occur in nickel based alloy 

components of the steam generator tube plugs. To manage these aging 

effects, Palisades credits the Steam Generator Tube Integrity Program 

supplemented by the Water Chemistry Program and the ASME Section XI 

IWB, IWC, IWD, IWF Inservice Inspection Program. The steam generator tube 

integrity program assessment of tube integrity and plugging or repair criteria of 

flawed tubes is in accordance with the plant technical specifications and NEI 

97-06 guidelines. For general and pitting corrosion, the acceptance criteria are 

in accordance with NEI 97-06 guidelines.

New, replacement recirculating steam generators were Installed at Palisades 

in 1990. These new steam generators incorporate many enhancements In 

design and materials of construction to minimize aging effects. However, 

cracking due to PWSCC and IGA/IGSCC and loss of material due to pitting 

and wear could occur in the Palisades steam generator tubes and plugs.
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The Water Chemistry Program conforms to the guidelines in EPRI TR-105714 

and TR-102134. The Water Chemistry Program mitigates aging effects such 

as cracking due to PWSCC and IGA/IGSCC and loss of material due to pitting 

and wear, by controlling the environment to which the steam generator tubes 

and plugs are exposed. These aging effects are minimized by controlling the 

chemical species that cause the underlying mechanisms that result in these 

aging effects. The program provides assurance that an elevated level of 

contaminants and oxygen does not exist in either the primary or secondary 

sides of the steam generators, and thus minimizes the occurrences of these 

aging effects. The Water Chemistry Program has been in effect since initial 

plant operation and has been effective at maintaining the desired primary and 

secondary water chemistry and detecting abnormal conditions, which have 

been corrected in an expedient manner. Therefore, the Water Chemistry 

Program effectively mitigates cracking due to PWSCC and IGA/IGSCC and 

loss of material due to pitting and wear in the steam generator tubes and 

plugs. Verification of the effectiveness of the program will be performed to 

ensure that these aging effects are not occurring.

The Steam Generator Tube Integrity Program is used to manage these aging 

effects for the steam generator tubes and plugs in order to confirm the 

effectiveness of the Water Chemistry Program. The Steam Generator Tube 

Integrity Program was developed to meet the guidelines of NEI 97-06 “Steam 

Generator Program Guidelines” (January 2001). The program manages these 

aging effects through a balance of prevention, inspection, evaluation, repair, 

and leakage monitoring measures. Eddy Current Testing is used to detect 

steam generator tube flaws and degradation. Steam generator tubes not 

meeting the Technical Specification limits for continued operation are removed 

from service by installation of tube plugs. Tube plugs installed in the steam 

generators are fabricated from heat-treated Alloy 690 material. Although these 

plugs have a high resistance to PWSCC, they are routinely inspected as a part 

of the program. A tube integrity assessment is performed following each 

steam generator tube inspection to ensure that the performance criteria have 

been met for the previous operating period and will continue to be met for the 

next period.

Therefore, a combination of the Water Chemistry Program and the Steam 

Generator Tube Integrity Program are used to manage these aging effects.
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3.1.2.2.12 Loss of Section Thickness due to Flow-accelerated Corrosion

NUREG-1800 states that loss of section thickness due to flow-accelerated 

corrosion could occur in tube support lattice bars made of carbon steel. 

NUREG-1801 recommends that a plant-specific aging management program 

be evaluated and, on the basis of the guidelines of NRC Generic Letter 97-06, 

an inspection program for steam generator internals be developed to ensure 

that this aging effect is adequately managed.

The Palisades steam generators do not include carbon steel tube support 

lattice bars. Therefore, loss of section thickness of these bars is not an 

applicable aging effect for Palisades.

3.1.2.2.13 Ligament Cracking due to Corrosion

NUREG-1800 states that ligament cracking due to corrosion could occur in 

carbon steel components in the steam generator tube support plate. All PWR 

licensees have committed voluntarily to a SG degradation management 

program described in NEI 97-06. NUREG-1801 recommends that an AMP 

based on the recommendations of staff-approved NEI 97-06 guidelines, or 

other alternate regulatory basis for SG degradation management, be 

developed to ensure that this aging effect is adequately managed.

The Palisades steam generators have stainless steel eggcrate tube lattice 

support rings. Therefore, ligament cracking due to corrosion is not an 

applicable aging effect for Palisades. New, replacement recirculating steam 

generators were installed at Palisades in 1990. These new steam generators 

incorporate many enhancements in design and materials of construction, to 

minimize aging effects. 

The Water Chemistry Program conforms to the guidelines In EPRI 

TR-105714, and TR-102134. The Water Chemistry Program mitigates aging 

effects such as cracking due to SCC, by controlling the environment to which 

the steam generator stainless steel tube support plates are exposed. This 

aging effect is minimized by controlling the chemical species that cause the 

underlying mechanisms that result in the aging effect. The program provides 

assurance that an elevated level of contaminants and oxygen does not exist in 

either the primary or secondary sides of the steam generators, and thus 

minimizes the occurrences of this aging effect. The Water Chemistry Program 

has been in effect since initial plant operation and has been effective at 

maintaining the desired primary and secondary water chemistry and detecting 

abnormal conditions, which have been corrected in an expedient manner. 
Page 3-28 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Therefore, the Water Chemistry Program effectively mitigates cracking due to 

SCC in the steam generator stainless steel tube support plates. Verification of 

the effectiveness of the program will be performed to ensure that this aging 

effect is not occurring.

The Steam Generator Tube Integrity Program is used to manage this aging 

effect for the steam generator stainless steel tube support plates in order to 

confirm the effectiveness of the Water Chemistry Program. The Steam 

Generator Tube Integrity Program was developed to meet the guidelines of 

NEI 97-06 “Steam Generator Program Guidelines” (January 2001). The 

program manages this aging effect through a balance of prevention, 

inspection, evaluation, repair, and leakage monitoring measures. Periodic 

visual inspections of accessible areas are performed to verify the integrity of 

secondary-side components, including the steam generator stainless steel 

tube support plates.

Therefore, a combination of the Water Chemistry Program and the Steam 

Generator Tube Integrity Program are used to manage this aging effect.

3.1.2.2.14 Loss of Material due to Flow-accelerated Corrosion

NUREG-1800 states that loss of material due to flow-accelerated corrosion 

could occur in feedwater inlet ring and supports. As noted in Combustion 

Engineering (CE) Information Notice (IN) 90-04 and NRC IN 91-19 and LER 

50-362/90-05-01, this form of degradation has been detected only in certain 

CE System 80 steam generators. NUREG-1801 recommends further 

evaluation to ensure that this aging effect is adequately managed. 

NUREG-1801 recommends that a plant-specific aging management program 

be evaluated because existing programs may not be capable of mitigating or 

detecting loss of material due to flow-accelerated corrosion.

The discussion in this paragraph of NUREG-1800 is applicable to CE System 

80 steam generators only, whereas Palisades has Combustion Engineering 

Model 2530 steam generators. 

3.1.2.2.15 Quality Assurance for Aging Management of Non-Safety Related 

Components

Quality Assurance Program applicability to non-safety-related components is 

addressed in Appendix B, Section 1.2.
Page 3-29 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

3.1.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Reactor Vessel, Internals, and Reactor Coolant System components. The section 

of the LRA that contains the TLAA review results is indicated in parenthesis.

• Reactor Vessel Neutron Embrittlement (Section 4.2)

• Metal Fatigue (Section 4.3)

• Alloy 600 Nozzle and Safe End Life Assessment Analyses (Section 4.7.2)

• ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld 

Category B-L-1 Inspection Interval from 10 Years to 40 Years (Section 4.7.3)

3.1.3 Conclusion

The Reactor Vessel, Internals, and Reactor Coolant System piping, fittings, and 

components that are subject to aging management review have been identified in 

accordance with the requirements of 10 CFR 54.4. The aging management programs 

selected to manage aging effects for the Reactor Vessel, Internals, and Reactor Coolant 

System components are identified Section 3.1.2.1.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.

Therefore, based on the conclusions provided in Appendix B, the effects of aging associated 

with the Reactor Vessel, Internals, and Reactor Coolant System components will be 

adequately managed so that there is reasonable assurance that the intended function(s) will 

be maintained consistent with the current licensing basis during the period of extended 

operation.
Page 3-30 

Table 3.1.1 Summary of Aging Management Evaluations in

Application for Renewed Operating Licenses

 Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.1.1-01 Reactor coolant pressure 

boundary components

Cumulative fatigue damage

TLAA, evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.1.2.2.1)

Further evaluation is documented in Section 3.1.2.2.1.The aging mechanism fatigue is potentially applicable to many component types in the Reactor Coolant System Supergroup, but only selected components or locations require explicit analysis as TLAAs and/or warrant aging management. The Palisades approach to identifying and managing the relevant locations and components is addressed in Section 4.3 and in Appendix B, Fatigue Monitoring Program. Therefore, cumulative fatigue damage is not identified as an aging effect in Tables 3.1.2-1 through 3.1.2-4.below.

3.1.1-02 Steam generator shell 

assembly

Loss of material due to pitting and crevice corrosion

Inservice inspection; water chemistry

Yes, detection of aging effects is to be further evaluated (see [SRP] subsection 3.1.2.2.2.1)

Further evaluation documented in Section 3.1.2.2.2.1.

3.1.1-03 BWR only3.1.1-04 Pressure vessel ferritic 

materials that have a neutron fluence greater than 1017

n/cm2 (E>1 MeV)

Loss of fracture toughness due to neutron irradiation embrittlement

TLAA, evaluated in accordance with Appendix G of 10 CFR 50 and RG 1.99

Yes, TLAA (see [SRP] subsection 3.1.2.2.3.1)

Further evaluation documented in Section 3.1.2.2.3.1.

3.1.1-05 Reactor vessel beltline shell 

and welds

Loss of fracture toughness due to neutron irradiation embrittlement

Reactor vessel surveillance

Yes, plant specific (see [SRP] subsection 3.1.2.2.3.2)

Further evaluation documented in Section 3.1.2.2.3.2.
Page 3-31 

Application for Renewed Operating Licenses

3.1.1-06 Westinghouse and B&W 

baffle/former bolts

Loss of fracture toughness due to neutron irradiation embrittlement and void swelling

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.3.3)

Further evaluation documented in Section 3.1.2.2.3.3.

3.1.1-07 Small-bore reactor coolant 

system and connected systems piping 

Crack initiation and growth due to SCC, intergranular SCC, and thermal and mechanical loading

Inservice inspection; water chemistry; one-time inspection

Yes, parameters monitored/ inspected and detection of aging effects are to be further evaluated (see [SRP] subsection 3.1.2.2.4.1)

Further evaluation documented in Section 3.1.2.2.4.1.

3.1.1-08 BWR only3.1.1-09 BWR only3.1.1-10 Vessel shell Crack growth due to 

cyclic loading

TLAA Yes, TLAA (see 

[SRP] subsection 3.1.2.2.5)

Further evaluation documented in Section 3.1.2.2.5.

3.1.1-11 Reactor internals Changes in dimension 

due to void swelling

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.6)

Further evaluation documented in Section 3.1.2.2.6.

3.1.1-12 PWR core support pads, 

instrument tubes (bottom head penetrations), pressurizer spray heads, and nozzles for the steam generator instruments and drains

Crack initiation and growth due to SCC and/or primary water stress corrosion cracking (PWSCC)

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.7.1)

Further evaluation documented in Section 3.1.2.2.7.1.

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-32 

Application for Renewed Operating Licenses

3.1.1-13 Cast austenitic stainless steel 

(CASS) reactor coolant system piping

Crack initiation and growth due to SCC

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.7.2)

Further evaluation documented in Section 3.1.2.2.7.2.

3.1.1-14 Pressurizer instrumentation 

penetrations and heater sheaths and sleeves made of Ni-alloys

Crack initiation and growth due to PWSCC

Inservice inspection; water chemistry

Yes, AMP for PWSCC of Inconel 182 weld is to be evaluated (see [SRP] subsection 3.1.2.2.7.3)

Further evaluation documented in Section 3.1.2.2.7.3.

3.1.1-15 Westinghouse and B&W baffle 

former bolts

Crack initiation and growth due to SCC and IASCC

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.8)

Further evaluation documented in Section 3.1.2.2.8.

3.1.1-16 Westinghouse and B&W baffle 

former bolts

Loss of preload due to stress relaxation

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.9)

Further evaluation documented in Section 3.1.2.2.9.

3.1.1-17 Steam generator feedwater 

impingement plate and support

Loss of section thickness due to erosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.10)

Further evaluation documented in Section 3.1.2.2.10.

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-33 

Application for Renewed Operating Licenses

3.1.1-18 (Alloy 600) Steam generator 

tubes, repair sleeves, and plugs

Crack initiation and growth due to PWSCC, outside diameter stress corrosion cracking (ODSCC), and/or intergranular attack (IGA) or loss of material due to wastage and pitting corrosion, and fretting and wear: or deformation due to corrosion at tube support plate intersections

Steam generator tubing integrity; water chemistry

Yes, effectiveness of a proposed AMP is to be evaluated (see [SRP] subsection 3.1.2.2.11)

Further evaluation documented in Section 3.1.2.2.11.

3.1.1-19 Tube support lattice bars 

made of carbon steel

Loss of section thickness due to FAC

Plant specific Yes, plant specific 

(see [SRP] subsection 3.1.2.2.12)

Further evaluation documented in Section 3.1.2.2.12

3.1.1-20 Carbon steel tube support 

plate

Ligament cracking due to corrosion

Plant specific Yes, effectiveness 

of a proposed AMP is to be evaluated (see [SRP] subsection 3.1.2.2.13)

Further evaluation documented in Section 3.1.2.2.13.

3.1.1-21 Steam generator feedwater 

inlet ring and supports

Loss of material due to flow accelerated corrosion

Combustion Engineering (CE) steam generator feedwater ring inspection

Yes, plant specific Further evaluation documented in Section 

3.1.2.2.14.

3.1.1-22 Reactor vessel closure studs 

and stud assembly

Crack initiation and growth due to SCC and/or IGSCC

Reactor head closure studs

No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-34 

Application for Renewed Operating Licenses

3.1.1-23 CASS pump casing and valve 

body

Loss of fracture toughness due to thermal aging embrittlement

Inservice inspection No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

3.1.1-24 CASS piping Loss of fracture 

toughness due to thermal aging embrittlement

Thermal aging embrittlement of CASS

No Palisades does not have CASS piping in the 

Primary Coolant System

3.1.1-25 BWR piping and fittings; 

steam generator components

Wall thinning due to flow-accelerated corrosion

Flow-accelerated corrosion

No See [Section B2.1.11] Flow Accelerated 

Corrosion Program for aging management program

3.1.1-26 Reactor coolant pressure 

boundary (RCPB) valve closure bolting, manway and holding bolting, and closure bolting in high pressure and high temperature systems

Loss of material due to wear; loss of preload due to stress relaxation; crack initiation and growth due to cyclic loading and/or SCC

Bolting integrity No Bolting integrity is managed under the Bolting 

Integrity Program. See [Section B2.1.3]

3.1.1-27 BWR only3.1.1-28 BWR only3.1.1-29 BWR only3.1.1-30 BWR only3.1.1-31 BWR only3.1.1-32 BWR only3.1.1-33 BWR only3.1.1-34 BWR only

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-35 

Application for Renewed Operating Licenses

3.1.1-35 CRD nozzle Crack initiation and 

growth due to PWSCC

Ni-alloy nozzles and penetrations; water chemistry

No See [Section B2.1.1] Alloy 600 Program and 

[Section B2.1.21] Water Chemistry Program for aging management programs

3.1.1-36 Reactor vessel nozzles safe 

ends and CRD housing; reactor coolant system components (except CASS and bolting)

Crack initiation and growth due to cyclic loading, and/or SCC, and PWSCC

Inservice inspection; water chemistry

No See [Section B2.1.1] Alloy 600 Program, 

[Section B2.1.21] Water Chemistry Program, and [Section B2.1.2] ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program for aging management programs

3.1.1-37 Reactor vessel internals 

CASS components

Loss of fracture toughness due to thermal aging, neutron irradiation embrittlement, and void swelling

Thermal aging and neutron irradiation embrittlement

No Palisades does not have CASS reactor vessel 

internals

3.1.1-38 External surfaces of carbon 

steel components in reactor coolant system pressure boundary

Loss of material due to boric acid corrosion

Boric acid corrosion No See [Section B2.1.4] Boric Acid Corrosion 

Program for aging management program

3.1.1-39 Steam generator secondary 

manways and handholds (CS)

Loss of material due to erosion

Inservice inspection No This NUREG 1801 grouping which addresses 

erosion concerns in once-through steam generators is not applicable to Palisades

3.1.1-40 Reactor internals, reactor 

vessel closure studs, and core support pads

Loss of material due to wear

Inservice inspection No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

3.1.1-41 Pressurizer integral support Crack initiation and 

growth due to cyclic loading

Inservice inspection No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-36 

Application for Renewed Operating Licenses

3.1.1-42 Upper and lower internals 

assembly (Westinghouse)

Loss of preload due to stress relaxation

Inservice inspection; loose part and/or neutron noise monitoring

No Not applicable to Palisades. Palisades is a CE 

unit.

3.1.1-43 Reactor vessel internals in 

fuel zone region (except Westinghouse and Babcock & Wilcox [B&W] baffle bolts)

Loss of fracture toughness due to neutron irradiation embrittlement, and void swelling

PWR vessel internals; water chemistry

No See [Section B2.1.17] Reactor Vessel Internals 

Program for aging management program

3.1.1-44 Steam generator upper and 

lower heads; tubesheets; primary nozzles and safe ends

Crack initiation and growth due to SCC, PWSCC and IASCC

Inservice inspection; water chemistry

No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program and [Section B2.1.21] Water Chemistry Program for aging management programs

3.1.1-45 Vessel internals (except 

Westinghouse and B&W baffle former bolts)

Crack initiation and growth due to SCC and IASCC

PWR vessel internals; water chemistry

No See [Section B2.1.17] Reactor Vessel Internals 

Program and [Section B2.1.21] Water Chemistry Program for aging management programs

3.1.1-46 Reactor internals (B&W 

screws and bolts)

Loss of preload due to stress relaxation

Inservice inspection; loose part monitoring

No Not applicable to Palisades. Palisades is a CE 

unit.

3.1.1-47 Reactor vessel closure studs 

and stud assembly

Loss of material due to wear

Reactor head closure studs

No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

3.1.1-48 Reactor internals 

(Westinghouse upper and lower internal assemblies; CE bolts and tie rods)

Loss of preload due to stress relaxation

Inservice inspection; loose part monitoring

No See [Section B2.1.2] ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program for aging management program

Table 3.1.1 Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Coolant System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-37 

Table 3.1.2-1 Reactor Coolant System - Primary Coolan

Application for Renewed Operating Licenses

t System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Alloy 600 Cladding

Shelter / Protection

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.D1.1-i 3.1.1-44 C

Water Chemistry Program IV.D1.1-i 3.1.1-44 C

Alloy 600 Safe Ends

Fluid Pressure Boundary

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.C2.2-f 3.1.1-36 A, 123

IV.C2.5-h 3.1.1-36 A

Water Chemistry Program IV.C2.2-f 3.1.1-36 A, 123

IV.C2.5-h 3.1.1-36 A

Alloy 600 Thermal Sleeves

Shelter / Protection

Alloy 600 Treated Water 

(Ext)

Cracking Alloy 600 Program IV.C2.5-k 3.1.1-14 C, 124

Water Chemistry Program IV.C2.5-k 3.1.1-14 C, 124

Bolting and Fasteners

Fluid Pressure Boundary

Low Alloy Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program IV.C2.4-g 3.1.1-27 101, ALoss of Material Bolting Integrity Program F

Boric Acid Corrosion Program

IV.C2.1-d 3.1.1-39 CIV.C2.2-d 3.1.1-39 C

Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program IV.C2.4-g 3.1.1-27 ALoss of Material Bolting Integrity Program F

Boric Acid Corrosion Program

IV.C2.1-d 3.1.1-39 CIV.C2.2-d 3.1.1-39 C

Carbon Steel Nozzles

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.2-d 3.1.1-38 C
Page 3-38 

Application for Renewed Operating Licenses

Carbon Steel Pipe (30” and 42”)

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.1-d 3.1.1-38 A

Flow Element(PCP Controlled Bleed)

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.2-f 3.1.1-36 C

Water Chemistry Program IV.C2.2-f 3.1.1-36 C

Non-CASS Valves in PCS and Connected Systems

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.2-f 3.1.1-36 C

Water Chemistry Program IV.C2.2-f 3.1.1-36 C

IV.C2.2-f 3.1.1-36 C

PCS Spray and Drain Nozzles

Fluid Pressure Boundary

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.C2.5-k 3.1.1-14 C

IV.C2.5-s 3.1.1-14 C

Water Chemistry Program IV.C2.5-k 3.1.1-14 C

IV.C2.5-s 3.1.1-14 C

PORV Isolation, Quench Tank Spray Manual Valves

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.4-b 3.1.1-36 A

Water Chemistry Program IV.C2.4-b 3.1.1-36 A

PORV Isolation Valves

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Reduction of Fracture Toughness 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

IV.C2.4-c 3.1.1-23 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-39 

Application for Renewed Operating Licenses

Pressurizer Alloy 600 Instrument Penetrations

Fluid Pressure Boundary

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.C2.5-k 3.1.1-14 A

Water Chemistry Program IV.C2.5-k 3.1.1-14 A

Pressurizer Heater Sleeves

Fluid Pressure Boundary

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.C2.5-s 3.1.1-14 A

Water Chemistry Program IV.C2.5-s 3.1.1-14 A

Pressurizer Heaters

Fluid Pressure Boundary

Alloy 600 Treated Water 

(Int)

Cracking Alloy 600 Program IV.C2.5-s 3.1.1-14 A

Water Chemistry Program IV.C2.5-s 3.1.1-14 A

Pressurizer Integral Support Weld

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.5-v 3.1.1-41 A

Loss of Material Boric Acid Corrosion 

Program

IV.C2.5-u 3.1.1-38 A

Pressurizer Manway and Flange Bolting

Fluid Pressure Boundary

Low Alloy Steel Containment Air 

(Ext), Borated Water or Steam Leakage

Loss of Material Boric Acid Corrosion 

Program

IV.C2.5-o 3.1.1-38 A

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.5-o 3.1.1-38 A

Loss of Preload Bolting Integrity Program IV.C2.5-p 3.1.1-26 101, A

Pressurizer Manway and Flanges

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext), Borated Water or Steam Leakage

Loss of Material Boric Acid Corrosion 

Program

IV.C2.5-o 3.1.1-38 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-40 

Application for Renewed Operating Licenses

Pressurizer Quench Tank

Fluid Pressure Boundary

Epoxy Coated Carbon Steel

Containment Air (Ext)

Loss of Material System Monitoring 

Program

IV.C2.6-b 3.1.1-38 E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

F

Pressurizer Quench Tank Shell and Heads

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.6-b 3.1.1-38 A

Pressurizer Spray Head

Spray Pattern Alloy 600 Treated Water 

(Int)

Cracking One-Time Inspection 

Program

IV.C2.5-j 3.1.1-12 A

Water Chemistry Program IV.C2.5-j 3.1.1-12 A

Primary Coolant Pump Casing

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.3-b 3.1.1-36 A

Water Chemistry Program IV.C2.3-b 3.1.1-36 A

Reduction of Fracture Toughness 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

IV.C2.3-c 3.1.1-23 A

Primary Coolant Pump Closure Bolting

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program IV.C2.3-g 3.1.1-27 101, ALoss of Material Boric Acid Corrosion 

Program

IV.C2.3-f 3.1.1-39 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-41 

Application for Renewed Operating Licenses

Primary Coolant Sample Heat Exchanger Shell

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.2-d 3.1.1-38 A

System Monitoring Program

VII.I.1-b 3.1.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

V.D1.5-a 3.1.1-13 C

Reactor Head Vent

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-g 3.1.1-07 C

Water Chemistry Program IV.C2.1-g 3.1.1-07 C

Reactor Head Vent Orifice

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-g 3.1.1-07 A

Water Chemistry Program IV.C2.1-g 3.1.1-07 A

Sample Point(Quench Tank Liquid, Loop 2 Hot Leg, Pressurizer Surge Line)

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-g 3.1.1-07 CIV.C2.2-h 3.1.1-07 C

Water Chemistry Program IV.C2.1-g 3.1.1-07 C

IV.C2.2-h 3.1.1-07 C

Small Bore Stainless Steel Pipe(PCS and Connected Systems)

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-g 3.1.1-07 AIV.C2.2-h 3.1.1-07 A

Water Chemistry Program IV.C2.1-g 3.1.1-07 A

IV.C2.2-h 3.1.1-07 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-42 

Application for Renewed Operating Licenses

SS Cladding Shelter/ 

Protection

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-c 3.1.1-36 AIV.C2.5-c 3.1.1-36 AIV.C2.5-g 3.1.1-36 AIV.C2.5-h 3.1.1-36 AIV.C2.5-m 3.1.1-36 A

Water Chemistry Program IV.C2.1-c 3.1.1-36 A

IV.C2.5-c 3.1.1-36 AIV.C2.5-g 3.1.1-36 AIV.C2.5-h 3.1.1-36 AIV.C2.5-m 3.1.1-36 A

Stainless Steel Pipe(PCS and Connected Systems)

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.1-c 3.1.1-36 AIV.C2.2-f 3.1.1-36 A

Water Chemistry Program IV.C2.1-c 3.1.1-36 A

IV.C2.2-f 3.1.1-36 A

Stainless Steel Safe Ends(Pressurizer and Connected Systems)

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.2-f 3.1.1-36 AIV.C2.5-h 3.1.1-36 A

Water Chemistry Program IV.C2.2-f 3.1.1-36 A

IV.C2.5-h 3.1.1-36 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-43 

Application for Renewed Operating Licenses

Stainless Steel Thermal Sleeves

Shelter / Protection

Stainless Steel Treated Water 

(Ext)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.5-h 3.1.1-36 C

Water Chemistry Program IV.C2.5-h 3.1.1-36 C

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.5-h 3.1.1-36 C

Water Chemistry Program IV.C2.5-h 3.1.1-36 C

Stainless Steel Tubing

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.2-f 3.1.1-36 A

Water Chemistry Program IV.C2.2-f 3.1.1-36 A

Vessels, Pressure(Pressurizer)

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.C2.5-b 3.1.1-38 A

Table 3.1.2-1 Reactor Coolant System - Primary Coolant System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-44 

Table 3.1.2-2 Reactor Coolant System - Reactor Ve

Application for Renewed Operating Licenses

ssel - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

CRDM Upper Pressure Housing & Flange

Pressure Boundary/ Fission Product Retention

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.2-b 3.1.1-36 A

Water Chemistry Program IV.A2.2-b 3.1.1-36 A

CRDM/Incore Instrument Bolting

Pressure Boundary/ Fission Product Retention

Stainless Steel Containment Air 

(Ext)

Loss of Material Bolting Integrity Program IV.A2.2-f 3.1.1-26 ALoss of Preload Bolting Integrity Program IV.A2.2-g 3.1.1-26 101, ACracking Bolting Integrity Program IV.A2.2-e 3.1.1-26 A

Incore Instrument Closure Flanges

Pressure Boundary/ Fission Product Retention

Stainless Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.2-f 3.1.1-26 C

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.2-b 3.1.1-36 C

Water Chemistry Program IV.A2.2-b 3.1.1-36 C

Internal SS Cladding

Pressure Boundary/ Fission Product Retention

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.4-b 3.1.1-36 C

Water Chemistry Program IV.A2.4-b 3.1.1-36 C

Reactor Vessel Column Support

Component Structural Support

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.8-b 3.1.1-38 119, 

122, A

Reactor Vessel Bottom Head

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C
Page 3-45 

Application for Renewed Operating Licenses

Reactor Vessel Closure Head

Component Structural SupportPressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.5-f 3.1.1-40 C

Boric Acid Corrosion Program

IV.A2.1-a 3.1.1-38 A

Reactor Vessel Closure Head Lifting Lugs

Component Structural Support

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.1-a 3.1.1-38 C

Reactor Vessel Core Stabilizer Lugs

Structure Functional Support

Nickel-Based Alloys

Treated Water (Ext)

Cracking Water Chemistry Program IV.A2.6-a 3.1.1-12 A

Reactor Vessel Internals Inspection Program

IV.A2.6-a 3.1.1-12 A

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

110, H

Reactor Vessel CRDM Nozzles

Structure Functional SupportPressure Boundary/ Fission Product Retention

Nickel-Based Alloys

Treated Water (Int)

Cracking Alloy 600 Program IV.A2.2-a 3.1.1-35 A

Water Chemistry Program IV.A2.2-a 3.1.1-35 A

Reactor Vessel Flow Skirt

Reduce Flow Inequalities

Nickel-Based Alloys

Treated Water (Ext)

Cracking Water Chemistry Program IV.A2.6-a 3.1.1-12 E

Reactor Vessel Internals Inspection Program

IV.A2.6-a 3.1.1-12 A

Table 3.1.2-2 Reactor Coolant System - Reactor Vessel - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-46 

Application for Renewed Operating Licenses

Reactor Vessel Head O-ring Leakage Monitor Tube

Pressure Boundary/ Fission Product Retention

Nickel-Based Alloys

Treated Water (Int)

Cracking Alloy 600 Program IV.A2.1-f 3.1.1-12 123, A

Reactor Vessel Head Vent Nozzle

Pressure Boundary/ Fission Product Retention

Nickel-Based Alloys

Treated Water (Int)

Cracking Alloy 600 Program IV.A2.7-b 3.1.1-35 A

Water Chemistry Program IV.A2.7-b 3.1.1-35 A

Reactor Vessel Incore Instrument Nozzles

Pressure Boundary/ Fission Product Retention

Nickel-Based Alloys

Treated Water (Int)

Cracking Alloy 600 Program IV.A2.7-b 3.1.1-35 121, A

Water Chemistry Program IV.A2.7-b 3.1.1-35 A

Reactor Vessel Intermediate Shell

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C

Reduction in Fracture Toughness 

Reactor Vessel Integrity Surveillance Program

IV.A2.5-c 3.1.1-05 109, A

Reactor Vessel Lower Shell

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C

Reduction in Fracture Toughness 

Reactor Vessel Integrity Surveillance Program

IV.A2.5-c 3.1.1-05 109, A

Reactor Vessel Nozzle Safe Ends

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C

Table 3.1.2-2 Reactor Coolant System - Reactor Vessel - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-47 

Application for Renewed Operating Licenses

Reactor Vessel Primary Coolant Nozzles

Pressure Boundary/ Fission Product RetentionStructure Functional Support

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C

Reactor Vessel Seal Ledge Ring

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.A2.5-e 3.1.1-38 C

Reactor Vessel Stop Lugs

Prevent Core Displacement

Nickel-Based Alloys

Treated Water (Ext)

Cracking Water Chemistry Program IV.A2.6-a 3.1.1-12 A

Reactor Vessel Internals Inspection Program

IV.A2.6-a 3.1.1-12 A

Reactor Vessel Studs, Nuts, Washers

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Crack Initiation and Growth

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

IV.A2.1-c 3.1.1-22 A

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.1-d 3.1.1-47 C

Boric Acid Corrosion Program

IV.A2.1-a 3.1.1-38 A

Reactor Vessel Surveillance Capsule Holder

Structure Functional Support

Nickel-Based Alloys

Treated Water (Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.A2.6-a 3.1.1-12 A

Water Chemistry Program IV.A2.6-a 3.1.1-12 C

Table 3.1.2-2 Reactor Coolant System - Reactor Vessel - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-48 

Application for Renewed Operating Licenses

Reactor Vessel Upper Shell

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.5-f 3.1.1-40 A

Boric Acid Corrosion Program

IV.A2.5-e 3.1.1-38 A

Reactor Vessel Upper Shell Flange

Pressure Boundary/ Fission Product Retention

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.5-f 3.1.1-40 A

Boric Acid Corrosion Program

IV.A2.5-e 3.1.1-38 A

Under Head CRDM Support

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.A2.2-b 3.1.1-36 C

Water Chemistry Program IV.A2.2-b 3.1.1-36 C

Table 3.1.2-2 Reactor Coolant System - Reactor Vessel - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-49 

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel 

Application for Renewed Operating Licenses

Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes

Control Rod Shroud Assembly = IV.B3.2 - CEA Shroud AssembliesControl Rod Shroud

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.2-c 3.1.1-11 A, 113

Control Rod Shroud, Shroud Top Support, Shroud Support Lug

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.2-a 3.1.1-45 A

Water Chemistry Program IV.B3.2-a 3.1.1-45 A

Control Rod Support Lug, Fuel Guide Pin, Fuel Guide Pin Nuts

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.2-c 3.1.1-11 A, 113

Fuel Guide Pin, Fuel Guide Pin Nuts

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.2-b 3.1.1-45 A

Water Chemistry Program IV.B3.2-b 3.1.1-45 A

Fuel Guide Pin, Fuel Guide Pin Nuts, Fuel Plate Cap Screw

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Loss of Preload ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

V.B3.2-g 3.1.1-48 101, A

Core Shroud Assembly = IV.B3.4 - Core Shroud Assembly
Page 3-50 

Application for Renewed Operating Licenses

Anchor Block, Centering Plate, Core Shroud Plate

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.4-b 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.4-a 3.1.1-45 A

Water Chemistry Program IV.B3.4-a 3.1.1-45 A

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.4-c 3.1.1-43 A, 113

Anchor Screw & Pin, Centering Screw & Pin, Positioning Screw, Shroud Bolt & Pin

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.4-e 3.1.1-45 A

Water Chemistry Program IV.B3.4-e 3.1.1-45 A

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.4-f 3.1.1-11 A, 113

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.4-g 3.1.1-43 A, 113

Loss of Preload ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.4-h 3.1.1-48 101, A

Core Support Barrel Assembly = IV.B3.3 - Core Support Barrel AssemblyCore Support Barrel

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.3-a 3.1.1-45 A

Water Chemistry Program IV.B3.3-a 3.1.1-45 A

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-51 

Application for Renewed Operating Licenses

Core Support Barrel Integral Upper Flange

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.3-a 3.1.1-45 A

Water Chemistry Program IV.B3.3-a 3.1.1-45 A, 113

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.3-b 3.1.1-11 A, 113

Incore Instrument Guide Tube (This group of components is not addressed in GALL IV.B3)Guide Tube Plug Screw

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Loss of Preload ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.2-g 3.1.1-48 E, 103

Instrument Guide Tube, Guide Tube Bracket

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 C

Instrument Guide Tube, Guide Tube Bracket, Guide Tube Plugs, Guide Tube Plug Screw, Guide Tube Support

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.1-b 3.1.1-11 C, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.1-a 3.1.1-45 C

Water Chemistry Program IV.B3.1-a 3.1.1-45 C

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 C

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.3-a 3.1.1-45 C, 113

Lower Internal Assembly (Integral with Core Barrel Assembly) = IV.B3.5 - Lower Internal Assembly

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-52 

Application for Renewed Operating Licenses

Core Support Barrel Cap Screws

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.5-c 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.5-b 3.1.1-45 A

Water Chemistry Program IV.B3.5-b 3.1.1-45 A

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.5-d 3.1.1-11 A

Core Support Barrel Snubber Lug

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.5-c 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.5-a 3.1.1-45 A

Water Chemistry Program IV.B3.5-a 3.1.1-45 A

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.5-e 3.1.1-40 A

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.5-d 3.1.1-11 A

Core Support Column

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.5-c 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.5-a 3.1.1-45 A

Water Chemistry Program IV.B3.5-a 3.1.1-45 A

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-53 

Application for Renewed Operating Licenses

Core Support Column Support Beams and Tie Rods

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.5-c 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.5-a 3.1.1-45 A

Water Chemistry Program IV.B3.5-a 3.1.1-45 A

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.5-d 3.1.1-11 A

Core Support Plate

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.5-c 3.1.1-11 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.5-a 3.1.1-45 A

Water Chemistry Program IV.B3.5-a 3.1.1-45 A

Reduction in Fracture Toughness

Reactor Vessel Internals Inspection Program

IV.B3.5-d 3.1.1-11 A

Upper Guide Structure - Not in GALLInstrument Sleeve

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.1-b 3.1.1-11 C, 113

Reduction in Fracture Toughness 

Reactor Vessel Internals Inspection Program

IV.B3.2-e 3.1.1-43 F

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-54 

Application for Renewed Operating Licenses

Spacer Shim, Instrument Sleeve

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.1-a 3.1.1-45 C

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 C

Upper Internal Assembly = GALL IV.B3.1 - Upper Internal AssemblyBrace Grid Beam, Cross Brace Screw, Shroud Grid Ring

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.1-b 3.1.1-45 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.1-a 3.1.1-45 A

Water Chemistry Program IV.B3.1-a 3.1.1-45 A

Fuel Alignment Plate

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.1-b 3.1.1-45 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.1-a 3.1.1-45 A

Water Chemistry Program IV.B3.1-a 3.1.1-45 A

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 A

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-55 

Application for Renewed Operating Licenses

Fuel Plate Align Lug, Fuel Plate Cap Screw, Fuel Plate Guide Pin

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Changes in Dimensions

Reactor Vessel Internals Inspection Program

IV.B3.1-b 3.1.1-45 A, 113

Cracking Reactor Vessel Internals 

Inspection Program

IV.B3.1-a 3.1.1-45 A

Water Chemistry Program IV.B3.1-a 3.1.1-45 A

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 A

Holddown Ring Plunger, Holddown Ring Strap, Holddown Ring

Structure Functional Support

Stainless Steel Treated Water 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.B3.1-c 3.1.1-40 A

Table 3.1.2-3 Reactor Coolant System - Reactor Vessel Internals - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-56 

Table 3.1.2-4 Reactor Coolant System - Replacement Steam 

Application for Renewed Operating Licenses

Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes

Alloy 690 Tube Plugs

Fluid Pressure Boundary

Alloy 690 Treated Water 

(Ext)

Cracking Steam Generator Tube 

Integrity Program

IV.D1.2-i 3.1.1-18 A

Water Chemistry Program IV.D1.2-i 3.1.1-18 A

Treated Water (Int)

Cracking Steam Generator Tube 

Integrity Program

IV.D1.2-i 3.1.1-18 A

Water Chemistry Program IV.D1.2-i 3.1.1-18 A

Handhole Cover Fluid 

Pressure Boundary

Low-Alloy Steel

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 C

Water Chemistry Program IV.D1.1-c 3.1.1-02 C

Tube Bundle Support Assembly

Structural Support for Safety Related

Stainless Steel

Treated Water (Ext)

Cracking Water Chemistry Program F

Steam Generator Tube Integrity Program

118, F

Carbon Steel Treated Water 

(Ext)

Loss of Material Water Chemistry Program IV.D1.2-k 3.1.1-20 A

Steam Generator Tube Integrity Program

IV.D1.2-k 3.1.1-20 118, A

Tube Bundle Wrapper

Direct Flow Low Alloy 

Steel

Treated Water (Int)

Loss of Material Water Chemistry Program F
Page 3-57 

Application for Renewed Operating Licenses

Lower Head Fluid 

Pressure Boundary

Carbon Steel w/SS cladding

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 A

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-i 3.1.1-44 C

Water Chemistry Program IV.D1.1-i 3.1.1-44 C

Primary Manway Cover

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-k 3.1.1-38 A

Manway Cover Diaphragm

Fluid Pressure Boundary

Stainless Steel

Treated Water (Int)

Cracking Water Chemistry Program IV.D1.1-i 3.1.1-44 E

Nozzle Safe Ends Fluid 

Pressure Boundary

Carbon Steel w/ SS Cladding

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-i 3.1.1-44 A

Water Chemistry Program IV.D1.1-i 3.1.1-44 A

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Primary Divider Plate

Fluid Pressure Boundary

Stainless Steel

Treated Water (Ext)

Cracking Water Chemistry Program IV.D1.1-i 3.1.1-44 C

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-58 

Application for Renewed Operating Licenses

Primary Inlet and Outlet Nozzles

Fluid Pressure Boundary

Carbon Steel w/SS cladding

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-i 3.1.1-44 A

Water Chemistry Program IV.D1.1-i 3.1.1-44 A

Feedwater Inlet Nozzles and Thermal Sleeves

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 C

Water Chemistry Program IV.D1.1-c 3.1.1-02 CFlow Accelerated Corrosion Program

IV.D1.1-d 3.1.1-25 117, A

Steam Outlet Nozzle and Flow Limiter, Blowdown Nozzle

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Loss of Material Water Chemistry Program IV.D1.1-c 3.1.1-02 E

Flow Accelerated Corrosion Program

IV.D1.1-d 3.1.1-25 117, A

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-59 

Application for Renewed Operating Licenses

Secondary Side 2” Inspection Port Cover

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-k 3.1.1-38 C

Treated Water (Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 A

Water Chemistry Program IV.D1.1-c 3.1.1-02 A

Wide and Narrow Range Water level Nozzles, Sampling and Instrument Nozzles

Fluid Pressure Boundary

Low Alloy Steel

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Loss of Material Water Chemistry Program IV.D1.1-c 3.1.1-02 CCracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 E

Water Chemistry Program IV.D1.1-c 3.1.1-02 E

Shells (Lower, Upper, Transition)

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 A

Treated Water (Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 A

Water Chemistry Program IV.D1.1-c 3.1.1-02 ASteam Generator Tube Integrity Program

IV.D1.1-c 3.1.1-02 B

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-60 

Application for Renewed Operating Licenses

Tubesheet Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 114, C

Treated Water (Int) (Secondary)

Loss of Material Steam Generator Tube 

Integrity Program

IV.D1.1-c 3.1.1-02 C

Water Chemistry Program IV.D1.1-c 3.1.1-02 C

Nickel Based Alloy

Treated Water (Int) (Primary)

Cracking Steam Generator Tube 

Integrity Program

IV.D1.2-a 3.1.1-18 C

Water Chemistry Program IV.D1.2-a 3.1.1-18 C

Upper Head Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-g 3.1.1-38 C

Treated Water (Int)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.D1.1-c 3.1.1-02 A

Loss of Material Water Chemistry Program IV.D1.1-c 3.1.1-02 A

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-61 

Application for Renewed Operating Licenses

U-Tubes Fluid 

Pressure BoundaryHeat Transfer

Alloy 600 Treated Water 

(Ext)

Cracking Steam Generator Tube 

Integrity Program

IV.D1.2-b 3.1.1-18 AIV.D1.2-c 3.1.1-18 A

Water Chemistry Program IV.D1.2-b 3.1.1-18 A

IV.D1.2-c 3.1.1-18 A

Loss of Material Water Chemistry Program IV.D1.2-e 3.1.1-18 A

Steam Generator Tube Integrity Program

IV.D1.2-e 3.1.1-18 A

Treated Water (Int)

Cracking Steam Generator Tube 

Integrity Program

IV.D1.2-a 3.1.1-18 A

Water Chemistry Program IV.D1.2-a 3.1.1-18 A

Manway Fasteners Fluid 

Pressure Boundary

Carbon Steel / Low Alloy Steel

Containment Air (Ext)

Crack Initiation and Growth 

Bolting Integrity Program IV.D1.1-l 3.1.1-26 A

Loss of Material Boric Acid Corrosion 

Program

IV.D1.1-k 3.1.1-38 A

Loss of Preload Bolting Integrity Program IV.D1.1-f 3.1.1-26 101, A

Table 3.1.2-4 Reactor Coolant System - Replacement Steam Generators - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-62 

Palisades Nuclear Plant

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Notes for Tables 3.1.2-1 through 3.1.2-4

A Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP has exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP has exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different AMP is 

credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific notes:

101 Loss of preload is included here in response to recent NRC RAIs on non-primary system, 

high temperature bolting that may experience loss of preload. The Palisades Bolting 

Integrity Program manages potential bolting AERMs and event driven degradation. GALL 

reconciliation is based on Loss of Material.

102 Not used

103 Palisades will not credit Loose Parts Monitoring for managing Loss of Preload.

104 Not used

105 Not used

106 Not used

107 SCC not applicable since temperature is less than 500F.

108 Not Used
Page 3-63 

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109 Cladding addressed separately, therefore, environment does not match NUREG-1801, IV 

A2.5-c. The low alloy steel plate at the lower and intermediate shells is monitored at 

(1/4)Thickness and (3/4)Thickness for neutron fluence.

110 Plant-specific OE identified this aging effect/mechanism.

111 Fuel alignment pins are integral with fuel assemblies and fit into holes in fuel alignment 

plate. No CASS or nickel alloys.

112 The material and environment combination is in NUREG-1801 but neither the plant 

component, nor a reasonable substitute exists.

113 NMC will participate with the nuclear industry to determine if void swelling is an aging 

effect/mechanism requiring management, and help develop a program if needed.

114 Denting and corrosion of tube support plate

115 Loss of section thickness due to flow accelerated corrosion

116 Ligament cracking / Corrosion

117 The flow-accelerated corrosion program will be supplemented by the water chemistry 

control program for the management of loss of material of this component.

118 Focus of the credited steam generator integrity program is on maintaining the integrity of the 

steam generator tubes which additionally serves to supplement the water chemistry control 

program for management of cracking and loss of material of pertinent secondary side 

components, including internal supports.

119 Reactor Vessel column support is evaluated in civil/structural aging management review. 

Only evaluated Boric Acid Corrosion to match GALL item.

120 Safety Injection nozzles connect to the primary coolant piping not the reactor vessel so 

GALL items IV.A2.3-a and IV.A2.3-b are N/A.

121 There are no instrument tubes in bottom head so GALL item IV.A2.7-a is N/A

122 There is no skirt support so GALL item IV.A2.8-a is N/A.

123 Based on EPRI Mechanical Tools, Alloy 600 and Stainless Steel have similar properties with 

respect to Cracking / SCC.

124 All Alloy 600 Thermal Sleeves were evaluated under this item.
Page 3-64 

Palisades Nuclear Plant

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Technical and Administrative Information

3.2 Aging Management of Engineered Safety Features

3.2.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.3.2, Engineered Safety Features, as being subject to aging 

management review. The systems, or portions of systems, which are addressed in this 

section, are described in the indicated section.

• Engineering Safeguards System (Section 2.3.2.1)

Table 3.2.1, Summary of Aging Management Evaluations in Chapter V of NUREG-1801 for 

Engineered Safety Features, provides the summary of the programs evaluated in 

NUREG-1801 for the Engineered Safety Features component groups that are utilized in 

license renewal. 

This table uses the format described in Figure 3.0-1 above. Note that this table only includes 

those component groups that are applicable to a PWR.

3.2.2 Results

The following table summarizes the results of the aging management review for systems in 

the Engineered Safety Features system group. 

Table 3.2.2-1, Engineered Safety Features - Engineering Safeguards System - Summary of 

Aging Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the potential aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for the above 

system in the following subsection of Section 3.2.2.1, Materials, Environment, Aging Effects 

Requiring Management and Aging Management Programs:

Section 3.2.2.1.1, Engineering Safeguards System

3.2.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.2.2.1.1 Engineering Safeguards System

Materials

The materials of construction for the Engineering Safeguards System are:

• Aluminum

• Carbon Steel

• Carbon Steel w/SS clad lining
Page 3-65 

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• Cast Austenitic SS

• Cast Iron

• Stainless Steel

Environment

The Engineering Safeguards System components are exposed to the following 

environments:

• Air (Int)

• Atmosphere / Weather (Ext)

• Containment Air (Ext)

• Gas (Int)

• Plant Indoor Air (Ext)

• Steam (Ext)

• Steam (Int)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Engineering Safeguards 

System, require management:

• Cracking 

• Heat Transfer Degradation

• Loss of Material 

• Loss of Preload

• Reduction of Fracture Toughness 

Aging Management Programs

The following aging management programs manage the aging effects for the 

Engineering Safeguards System components:

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program
Page 3-66 

Palisades Nuclear Plant

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Technical and Administrative Information

• System Monitoring Program

• Water Chemistry Program

• One-Time Inspection Program

3.2.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 Volume 1 Tables provide the basis for identifying those programs 

that warrant further evaluation by the reviewer in the license renewal application. 

For the Engineered Safety Features, those programs are addressed in the 

following sections.

3.2.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is 

addressed separately in Section 4.3.

3.2.2.2.2 Loss of Material Due to General Corrosion

3.2.2.2.2.1 Loss of Material Due to General Corrosion (BWR Only)

Applicable to BWR Only

3.2.2.2.2.2 Loss of Material Due to General Corrosion (PWR Components)

NUREG-1800 states that loss of material due to general corrosion could occur 

in the PWR containment spray system header and spray nozzle components, 

containment isolation valves and associated piping, and the external surfaces 

of PWR carbon steel components. NUREG-1801 recommends further 

evaluation on a plant specific basis to ensure that the aging effect is adequately 

managed. 

This aging effect of carbon steel in air does not apply to stainless steel 

components in Containment Spray and Emergency Core Cooling systems. The 

external surface of carbon steel and cast iron components in the Containment 

Spray and Emergency Core Cooling systems are susceptible to general 

corrosion in an air environment. The System Monitoring Program is credited 

with managing this aging effect.

Containment isolation components are addressed with their individual systems. 

Programs credited for aging management are identified in the 3.x.2 table for the 

system containing the penetration. 
Page 3-67 

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Technical and Administrative Information

The aging effect/mechanism for containment isolation in aqueous systems is 

managed by the Water Chemistry Program and supplemented by the One-Time 

Inspection Program.

The aging effect/mechanism for containment isolation components in gaseous 

systems, the containment sump level instrumentation, and radwaste systems is 

managed by the One-Time Inspection Program. 

All containment isolation valves and associated piping are currently tested on a 

set frequency by the Containment Leakage Testing Program. The testing will be 

continued in the extended period of operation. 

3.2.2.2.3 Local Loss of Material due to Pitting and Crevice Corrosion

3.2.2.2.3.1 Local Loss of Material due to Pitting and Crevice Corrosion (BWR 

Only)

Applicable to BWR Only

3.2.2.2.3.2 Local Loss of Material due to Pitting and Crevice Corrosion (PWR 

Components)

NUREG-1800 states that local loss of material from pitting and crevice 

corrosion could occur in the PWR containment spray components, 

containment isolation valves and associated piping, and the buried portion 

of the refueling water tank external surface. NUREG-1801 recommends 

further evaluation to ensure that the aging effect is adequately managed. 

The Palisades Containment Spray and Emergency Core Cooling system 

components are stainless steel, susceptible to pitting and crevice corrosion 

and are managed by the Water Chemistry Program supplemented by the 

One-Time Inspection Program. Loss of material due to pitting and crevice 

corrosion is a potential aging effect/mechanism that require management, 

even though the component has O2<100 ppb supporting the effectiveness 

of the existing water chemistry program. 

Containment isolation valve bodies and connecting piping are addressed 

with their individual systems. Programs credited for aging management are 

identified in the 3.x.2 table for the system containing the penetration. 

The stainless steel containment isolation components are exposed to 

borated water, susceptible to pitting and crevice corrosion, and managed by 

the Water Chemistry Program supplemented by the One-Time Inspection 

Program. All containment isolation valves and associated piping are 
Page 3-68 

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currently tested on a set frequency by the Containment Leakage Testing 

Program. The testing will be continued in the extended period of operation. 

The SIRW tank bottom is not buried. It is located on the Auxiliary Building 

Roof. The bottom edge is sealed around its circumference from exposure to 

the weather. Supply piping enters and exits the bottom of the tank through 

the roof of the Auxiliary Building. This arrangement exposes the bottom 

surface of the tank to a plant indoor air environment. Loss of material due to 

crevice and pitting is not a potential aging effect/mechanism for aluminum in 

air. 

3.2.2.2.4 Local Loss of Material due to Microbiologically Influenced Corrosion

NUREG-1800 states that local loss of material due to microbiologically 

influenced corrosion (MIC) could occur in BWR and PWR containment 

isolation valves and associated piping in systems that are not addressed in 

other chapters of NUREG-1801.

Loss of material due to MIC is considered a potential aging effect/mechanism 

that requires management, even though the component has no potential 

source of MIC contamination in treated water. The treated water environment 

is effectively controlled by the existing water chemistry program. 

Containment isolation valve bodies and connecting piping are addressed with 

their individual systems. Programs credited for aging management are 

identified in the 3.x.2 table for the system containing the penetration. All 

containment isolation valves and associated piping are currently tested on a 

set frequency by the Containment Leakage Testing Program. The testing will 

be continued in the extended period of operation. 

The Water Chemistry Program is credited for managing this aging 

effect/mechanism on containment isolation valves and associated piping in 

aqueous systems. This is supplemented by the One-Time Inspection Program 

to determine if the aging effect/mechanism exists, and, if it exists, how rapidly 

it is progressing. 

The high temperature (>210oF) of the Main Steam, Main Feedwater and 

Steam Generator Blowdown containment isolation components make them 

not susceptible to MIC.

The One-Time Inspection Program is credited for managing this aging 

effect/mechanism in gaseous systems, the containment sump level 

instrumentation, and radwaste systems containment isolation components. 
Page 3-69 

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Technical and Administrative Information

3.2.2.2.5 Changes in Properties due to Elastomer Degradation

Applicable to BWR Only

3.2.2.2.6 Local Loss of Material due to Erosion

NUREG-1800 states that local loss of material due to erosion could occur in 

the high pressure safety injection pump miniflow orifice. This aging 

mechanism and effect will apply only to pumps that are normally used as 

charging pumps in the chemical and volume control systems (PWRs).

The high pressure safety injection pumps are not used for normal charging at 

Palisades. Loss of material due to erosion of miniflow orifices is not applicable 

to Palisades.

3.2.2.2.7 Buildup of Deposits due to Corrosion

Applicable to BWR Only

3.2.2.2.8 Quality Assurance for Aging Management of Non-Safety Related 

Components

See Section 3.1.2.2.15

3.2.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Engineered Safety Features system components. The section of the LRA that 

contains the TLAA review results is indicated in parenthesis.

• Metal Fatigue (Section 4.3)

3.2.3 Conclusion

The Engineered Safety Features piping, fittings, and components that are subject to aging 

management review have been identified in accordance with the requirements of 10 CFR 

54.4. The aging management programs selected to manage aging effects for the 

Engineered Safety Features components are identified in the summaries in Section 3.2.2.1.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.

Therefore, based on the demonstrations provided in Appendix B, the effects of aging 

associated with the Engineered Safety Features components will be adequately managed 

so that there is reasonable assurance that the intended function(s) will be maintained 

consistent with the current licensing basis during the period of extended operation.
Page 3-70 

Table 3.2.1 Summary of Aging Management

Application for Renewed Operating Licenses

 Evaluations in Chapter V of NUREG-1801 for Engineered Safety Features 

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.2.1-01 Piping, fittings, and valves in 

emergency core cooling system

Cumulative fatigue damage 

TLAA, evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.2.2.2.1)

Further evaluation is documented in Section 3.2.2.2.1.The aging mechanism fatigue is potentially applicable to many component types in the Engineered Safety Features Supergroup, but only selected components or locations require explicit analysis as TLAAs and/or warrant aging management. The Palisades approach to identifying and managing the relevant locations and components for fatigue damage is addressed in Section 4.3 and in Appendix B, Fatigue Monitoring Program. Therefore, cumulative fatigue damage is not identified as an aging effect in Table 3.2.2-1 below.

3.2.1-02 BWR only3.2.1-03 Components in containment 

spray (PWR only), standby gas treatment (BWR only), containment isolation, and emergency core cooling systems

Loss of material due to general corrosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.2.2.2.2.2)

Further evaluation is documented in Section 3.2.2.2.2.2.

3.2.1-04 BWR only3.2.1-05 Components in containment 

spray (PWR only), standby gas treatment (BWR only), containment isolation, and emergency core cooling systems

Loss of material due to pitting and crevice corrosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.2.2.2.3.2)

Further evaluation is documented in Section 3.2.2.2.3.2.

3.2.1-06 Containment isolation valves 

and associated piping

Loss of material due to microbiologically influenced corrosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.2.2.2.4)

Further evaluation is documented in Section 3.2.2.2.4.
Page 3-71 

Application for Renewed Operating Licenses

3.2.1-07 BWR only3.2.1-08 High pressure safety injection 

(charging) pump miniflow orifice

Loss of material due to erosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.2.2.2.6)

Further evaluation is documented in Section 3.2.2.2.6.

3.2.1-09 BWR only3.2.1-10 External surface of carbon 

steel components

Loss of material due to general corrosion

Plant specific Yes, plant specific Further evaluation is documented in Section 

3.2.2.2.2.2

3.2.1-11 Piping and fittings of CASS in 

emergency core cooling system

Loss of fracture toughness due to thermal aging embrittlement

Thermal aging embrittlement of CASS

No There are no CASS piping and fittings in ESF 

systems. ESF CASS valves are managed as described in [Section B2.1.2] ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

3.2.1-12 Components serviced by 

open-cycle cooling system

Local loss of material due to corrosion and/or buildup of deposit due to biofouling

Open-cycle cooling water system

No The components in the ESF system are not 

cooled by an open cycle cooling water system. Therefore, this line item is not applicable to Palisades.

3.2.1-13 Components serviced by 

closed-cycle cooling system

Loss of material due to general, pitting, and crevice corrosion

Closed-cycle cooling water system

No A closed cycle cooling system cools the ESF 

system components. See [Section B2.1.6] Closed Cycle Cooling Water Program and [Section B2.1.21] Water Chemistry Program for the aging management programs

3.2.1-14 BWR only

Table 3.2.1 Summary of Aging Management Evaluations in Chapter V of NUREG-1801 for Engineered Safety Features 

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-72 

Application for Renewed Operating Licenses

3.2.1-15 Pumps, valves, piping, and 

fittings in containment spray and emergency core cooling systems

Crack initiation and growth due to SCC

Water chemistry No The line items in NUREG-1801 Volume 2 that 

refer to this row number specify a temperature less than 93°C (200°F). The aging management reviews consider a threshold for SCC of 140°F. Environments for the systems are either less than 120°F such that cracking is not an aging effect requiring management or at 582°F PCS temperature, which is outside the range of the NUREG 1801 listed environment. The items from the following tables referring to this row number have a temperature between 120°F and 582°F. The Water Chemistry Program [Section B2.1.21] is credited with managing stress corrosion cracking for stainless steel in borated water at temperatures above the 140°F threshold for SCC.

3.2.1-16 BWR only3.2.1-17 Carbon steel components Loss of material due 

to boric acid corrosion

Boric acid corrosion No See [Section B2.1.4] Boric Acid Corrosion 

Program for the aging management program

3.2.1-18 Closure bolting in high 

pressure or high temperature systems

Loss of material due to general corrosion, loss of preload due to stress relaxation, and crack initiation and growth due to cyclic loading or SCC

Bolting integrity No Aging effects are managed by the Bolting 

integrity Program [Section B2.1.3].

Table 3.2.1 Summary of Aging Management Evaluations in Chapter V of NUREG-1801 for Engineered Safety Features 

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-73 

Table 3.2.2-1 Engineered Safety Features - Engineering Sa

Application for Renewed Operating Licenses

feguards System - Summary of Aging Management Evaluation 

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

SIRW Tank Fluid Pressure 

Boundary

Aluminum Treated Water (Int) Cracking Water Chemistry Program V.D1.8-a 3.2.1-15 F, 210

One-Time Inspection Program

V.D1.8-a 3.2.1-15 F, 210

Safety Injection Tank

Fluid Pressure Boundary

Carbon Steel w/SS clad lining

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.7-a 3.2.1-17 A

System Monitoring Program V.E1-b 3.2.1-10 A

SDC HX Shell Fluid Pressure 

Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.5-b 3.2.1-17 A

Treated Water (Int) Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B

SIRWT HX Shell Fluid Pressure 

Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.6-d 3.2.1-17 A

Steam (Int) Loss of Material Water Chemistry Program G, 211

One-Time Inspection Program

G, 211

SDC, SIRWT HX Shell

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring Program V.E1-b 3.2.1-10 A

SDC HX Channel Head

Fluid Pressure Boundary

Carbon Steel w/SS clad lining

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.5-b 3.2.1-17 A

System Monitoring Program V.E1-b 3.2.1-10 A

SDC HX Tube Sheet shell side

Fluid Pressure Boundary

Carbon Steel w/SS clad lining

Treated Water (Ext)

Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B

SDC HX Channel Head shell side

Fluid Pressure Boundary

Carbon Steel w/SS clad lining

Treated Water (Int) Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B
Page 3-74 

Cont. Spray Pump HX shell, LPSI Pump HX shell

Application for Renewed Operating Licenses

Fluid Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.E1-a 3.2.1-17 A

System Monitoring Program V.E1-b 3.2.1-10 A

Treated Water (Int) Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 H, 212

One-Time Inspection Program

V.D1.5-a 3.2.1-13 H, 212

SIRWT HX Tubes Fluid Pressure 

Boundary

Stainless Steel Steam (Ext) Cracking 

Heat Transfer Degradation Loss of Material 

Water Chemistry Program V.D1.6-a 3.2.1-13 G, 211One-Time Inspection Program

V.D1.6-a 3.2.1-13 G, 211

Cont. Spray, LPSI Pump coils

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Ext)

Cracking Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 H

PCP Seal Cooler Coils, Cont. Spray Pump coils, LPSI pump Coils, SDC HX Tubes

Fluid Pressure BoundaryHeat Transfer

Stainless Steel Treated Water 

(Ext)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

V.D1.5-a 3.2.1-13 H

Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B

SDC HX Tubes Fluid Pressure 

BoundaryHeat Transfer

Stainless Steel Treated Water 

(Ext)

Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B

PCP Seal Cooler Coils, SIRWT HX Tubes

Fluid Pressure BoundaryHeat Transfer

Stainless Steel Treated Water (Int) Cracking Water Chemistry Program V.D1.5-a 3.2.1-13 H

Table 3.2.2-1 Engineered Safety Features - Engineering Safeguards System - Summary of Aging Management Evaluation 

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-75 

PCP Seal Cooler Coils

Application for Renewed Operating Licenses

Fluid Pressure Boundary

Stainless Steel Treated Water (Int) Cracking Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 H

Loss of Material Closed Cycle Cooling Water 

Program

V.D1.5-a 3.2.1-13 B

SIRWT HX Tubes Fluid Pressure 

BoundaryHeat Transfer

Stainless Steel Treated Water (Int) Cracking One-Time Inspection 

Program

V.D1.6-a 3.2.1-13 G

Cont. Spray Pump Coils, SDC HX Tubes

Fluid Pressure BoundaryHeat Transfer

Stainless Steel Treated Water (Int) Heat Transfer 

Degradation

Water Chemistry Program V.D1.5-a 3.2.1-13 H

Loss of Material Water Chemistry Program V.D1.5-a 3.2.1-13 A, 204

SIRWT HX Tubes, Cont. Spray Pump coils, LPSI Pump coils, SDC HX Tubes

Fluid Pressure Boundary

Stainless Steel Treated Water (Int) Heat Transfer 

Degradation

One-Time Inspection Program

V.D1.5-a 3.2.1-13 H

Loss of Material One-Time Inspection 

Program

V.D1.6-a 3.2.1-13 G

Fasteners Fluid Pressure 

Boundary

Carbon Steel Plant Indoor Air 

(Ext)Containment Air (Ext)

Loss of Preload Bolting Integrity Program 206, FLoss of Material Bolting Integrity Program V.E.2-a 3.2.1-18 A

Stainless Steel Plant Indoor Air 

(Ext)Containment Air (Ext)

Loss of Preload Bolting Integrity Program 206, F

Table 3.2.2-1 Engineered Safety Features - Engineering Safeguards System - Summary of Aging Management Evaluation 

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-76 

Containment Spray System Fasteners

Application for Renewed Operating Licenses

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

V.A.1-b 3.2.1-17 A

Containment Spray Pump Bolting

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.A.3-b 3.2.1-17 A

Containment Spray System Valves Bolting

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

V.A.4-b 3.2.1-17 A

Containment Spray System Valves Header Bolting

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.A.5-b 3.2.1-15 A

HPSI, LPSI Pumps Bolting

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.2-b 3.2.1-17 A

SIRWT HX Bolting

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.6-d 3.2.1-17 A

SIRWT Bolting Fluid Pressure 

Boundary

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material Boric Acid Corrosion 

Program

V.D1.8-b 3.2.1-17 A

HPSI Check Valves, SDC from PCS MOVs

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int) Cracking Water Chemistry Program G, 207

One-Time Inspection Program

G, 207

Reduction of Fracture Toughness

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

V.D1.1-b 3.2.1-11 E, 209

Table 3.2.2-1 Engineered Safety Features - Engineering Safeguards System - Summary of Aging Management Evaluation 

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-77 

HPSI Check Valves

Application for Renewed Operating Licenses

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int) Loss of Material Water Chemistry Program G, 207

One-Time Inspection Program

G, 207

Hot Leg Injection Check Valves

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int) Cracking Water Chemistry Program G, 207

One-Time Inspection Program

G, 207

HPSI Check Valves Loops 1A, 2A

Fluid Pressure Boundary

Stainless Steel Treated Water (Int) Loss of Material Water Chemistry Program G, 207

One-Time Inspection Program

G, 207

Table 3.2.2-1 Engineered Safety Features - Engineering Safeguards System - Summary of Aging Management Evaluation 

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
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Notes for Table 3.2.2-1

A Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP has exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP has exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different AMP is 

credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific notes:

201 Not used

202 Not used

203 Not used

204 GALL addresses crevice and pitting corrosion; Palisades included crevice, pitting and MIC.

205 GALL has crevice and pitting corrosion. Palisades included also general corrosion

206 Loss of preload is included here in response to recent NRC RAIs on non-primary system, 

high temperature bolting that may experience loss of preload. The Palisades Bolting 

Integrity Program manages potential bolting AERMs and event driven degradation. GALL 

reconciliation is based on Loss of Material.

207 The GALL assumes a temperature for valves in this system to be less than 93 degrees C 

(<200 degrees F) whereas these valves have the potential to be >93 degrees C (>200 

degrees F)
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208 GALL has crevice and pitting corrosion. Palisades has included crevice, pitting, fretting, and 

MIC.

209 GALL credits XI.M12 Thermal Aging of CASS. Palisades credits ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

210 GALL evaluates RWT as stainless steel only. Palisades SIRW Tank is aluminum.

211 GALL evaluates open or closed cooling water only. Palisades has steam environment.

212 GALL addresses pitting and crevice corrosion. Palisades includes general corrosion and 

selective leaching.
Page 3-80 

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Technical and Administrative Information

3.3 Aging Management of Auxiliary Systems

3.3.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.3.3, Auxiliary Systems, as being subject to aging management review. 

The systems, or portions of systems, which are addressed in this section, are described in 

the indicated sections.

• Chemical Addition System (Section 2.3.3.17)

• Chemical Volume and Control System (Section 2.3.3.1)

• Circulating Water System (Section 2.3.3.2)

• Component Cooling Water System (Section 2.3.3.3)

• Compressed Air System (Section 2.3.3.4)

• Containment Air Recirculation and Cooling System (Section 2.3.3.5)

• Domestic Water System (Section 2.3.3.16)

• Emergency Power System (Section 2.3.3.6)

• Fire Protection System (Section 2.3.3.7)

• Fuel Oil System (Section 2.3.3.8)

• Heating, Ventilation, and Air Conditioning System (Section 2.3.3.9)

• Miscellaneous Gas System (Section 2.3.3.10)

• Radwaste System (Section 2.3.3.11)

• Service Water System (Section 2.3.3.12)

• Shield Cooling System (Section 2.3.3.13)

• Spent Fuel Pool Cooling System (Section 2.3.3.14)

• Waste Gas System (Section 2.3.3.15)

Table 3.3.1, Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for 

Auxiliary Systems, provides the summary of the programs evaluated in NUREG-1801 for 

the Auxiliary Systems component groups that are relied on for license renewal. 

This table uses the format described in Figure 3.0-1 above. Note that this table only includes 

those component groups that are applicable to a PWR.
Page 3-81 

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3.3.2 Results

The following tables summarize the results of the aging management review for systems in 

the Auxiliary Systems group: 

Table 3.3.2-1, Auxiliary Systems - Chemical and Volume Control System - Summary of 

Aging Management Evaluation

Table 3.3.2-2, Auxiliary Systems - Circulating Water System - Summary of Aging 

Management Evaluation

Table 3.3.2-3, Auxiliary Systems - Component Cooling Water System - Summary of Aging 

Management Evaluation

Table 3.3.2-4, Auxiliary Systems - Compressed Air System - Summary of Aging 

Management Evaluation

Table 3.3.2-5, Auxiliary Systems - Containment Air Recirculation and Cooling System - 

Summary of Aging Management Evaluation

Table 3.3.2-6, Auxiliary Systems - Emergency Power System - Summary of Aging 

Management Evaluation

Table 3.3.2-7, Auxiliary Systems - Fire Protection System - Summary of Aging Management 

Evaluation

Table 3.3.2-8, Auxiliary Systems - Fuel Oil System - Summary of Aging Management 

Evaluation

Table 3.3.2-9, Auxiliary Systems - Heating, Ventilation, and Air Conditioning System - 

Summary of Aging Management Evaluation

Table 3.3.2-10, Auxiliary Systems - Miscellaneous Gas - Summary of Aging Management 

Evaluation

Table 3.3.2-11, Auxiliary Systems - Radwaste System - Summary of Aging Management 

Evaluation

Table 3.3.2-12, Auxiliary Systems - Service Water System - Summary of Aging 

Management Evaluation

Table 3.3.2-13, Auxiliary Systems - Shield Cooling System - Summary of Aging 

Management Evaluation

Table 3.3.2-14, Auxiliary Systems - Spent Fuel Pool Cooling System - Summary of Aging 

Management Evaluation

Table 3.3.2-15, Auxiliary Systems - Waste Gas System - Summary of Aging Management 

Evaluation
Page 3-82 

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Table 3.3.2-16, Auxiliary Systems - Domestic Water System - Summary of Aging 

Management Evaluation

Table 3.3.2-17, Auxiliary Systems - Chemical Addition System - Summary of Aging 

Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for each of the 

above systems in the following subsections of Section 3.3.2.1, Materials, Environment, 

Aging Effects Requiring Management and Aging Management Programs:

Section 3.3.2.1.1, Chemical and Volume Control System

Section 3.3.2.1.2, Circulating Water System

Section 3.3.2.1.3, Component Cooling Water System

Section 3.3.2.1.4, Compressed Air System

Section 3.3.2.1.5, Containment Air Recirculation and Cooling System

Section 3.3.2.1.6, Emergency Power System

Section 3.3.2.1.7, Fire Protection System

Section 3.3.2.1.8, Fuel Oil System

Section 3.3.2.1.9, Heating, Ventilation, and Air Conditioning System

Section 3.3.2.1.10, Miscellaneous Gas System

Section 3.3.2.1.11, Radwaste System

Section 3.3.2.1.12, Service Water System

Section 3.3.2.1.13, Shield Cooling System

Section 3.3.2.1.14, Spent Fuel Pool Cooling System

Section 3.3.2.1.15, Waste Gas System

Section 3.3.2.1.16, Domestic Water System

Section 3.3.2.1.17, Chemical Addition System
Page 3-83 

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3.3.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.3.2.1.1 Chemical and Volume Control System

Materials

The materials of construction for the Chemical and Volume Control System 

components are:

• Brass

• Carbon Steel

• Cast Austenitic SS

• Copper Nickel

• Low-Alloy Steel

• Stainless Steel

Environment

The Chemical and Volume Control System components are exposed to the 

following environments:

• Air (Ext)

• Air (Int)

• Containment Air (Ext)

• Gas (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Chemical and Volume Control 

System, require management:

• Cracking 

• Loss of Material

• Loss of Preload

• Reduction of Fracture Toughness 
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Chemical and Volume Control System components:

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Boric Acid Corrosion Program

• Bolting Integrity Program

• Closed Cycle Cooling Water Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.3.2.1.2 Circulating Water System

Materials

The materials of construction for the Circulating Water System components are:

• Carbon Steel

• Cast Iron

• Low-Alloy Steel

Environment

The Circulating Water System components are exposed to the following 

environments:

• Plant Indoor Air (Ext)

• Raw Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Circulating Water System, 

require management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Circulating Water System components:

• Bolting Integrity Program
Page 3-85 

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• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.3 Component Cooling Water System

Materials

The materials of construction for the Component Cooling Water System 

components are:

• Aluminum Bronze

• Brass

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Copper Nickel

• Nickel-Based Alloys

• Stainless Steel

Environment

The Component Cooling Water System components are exposed to the 

following environments:

• Air (Int)

• Containment Air (Ext)

• Gas (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

• Raw Water (Int)

• Treated Water (Ext)

• Treated Water (Int)
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Aging Effects Requiring Management

The following aging effects, associated with the Component Cooling Water 

System, require management:

• Buildup of Deposit 

• Cracking

• Heat Transfer Degradation 

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Component Cooling Water System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

• Water Chemistry Program

3.3.2.1.4 Compressed Air System

Materials

The materials of construction for the Compressed Air System components are:

• Aluminum

• Brass

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Galvanized

• Stainless Steel
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Environment

The Compressed Air System components are exposed to the following 

environments:

• Air (Ext)

• Air (Int)

• Containment Air (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

• Raw Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Compressed Air System, 

require management:

• Cracking 

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Compressed Air System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.5 Containment Air Recirculation and Cooling System

Materials

The materials of construction for the Containment Air Recirculation and Cooling 

System components are:

• Carbon Steel

• Copper Alloys
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• Galvanized

• Low-Alloy Steel

• Stainless Steel

Environment

The Containment Air Recirculation and Cooling System components are 

exposed to the following environments:

• Air (Ext)

• Air (Int)

• Containment Air (Ext)

• Raw Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Containment Air Recirculation 

and Cooling System, require management:

• Buildup of Deposit 

• Heat Transfer Degradation

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Containment Air Recirculation and Cooling System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.6 Emergency Power System

Materials

The materials of construction for the Emergency Power System components 

are:

• Brass
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• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Galvanized

• Low-Alloy Steel

• Stainless Steel

Environment

The Emergency Power System components are exposed to the following 

environments:

• Air (Ext)

• Air (Int)

• Atmosphere/ Weather (Ext)

• Oil (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Int)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Emergency Power System, 

require management:

• Buildup of Deposit

• Cracking

• Heat Transfer Degradation

• Loss of Material

• Loss of Preload
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Emergency Power System components:

• Bolting Integrity Program

• Closed Cycle Cooling Water Program

• Diesel Fuel Monitoring and Storage Program

• Fire Protection Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.7 Fire Protection System

Materials

The materials of construction for the Fire Protection System components are:

• Bare Copper

• Brass

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Stainless Steel

Environment

The Fire Protection System components are exposed to the following 

environments:

• Air (Ext)

• Air (Int)

• Atmosphere/Weather (Ext)

• Containment Air (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)
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• Raw Water (Int)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Fire Protection System, require 

management:

• Buildup of Deposit 

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Fire Protection System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Fire Protection Program

• One-Time Inspection Program

• System Monitoring Program

3.3.2.1.8 Fuel Oil System

Materials

The materials of construction for the Fuel Oil System are:

• Brass

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Low-Alloy Steel

• Stainless Steel

Environment

The Fuel Oil System components are exposed to the following environments:

• Air (Int)
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• Atmosphere/Weather (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Fuel Oil System, require 

management:

• Cracking 

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Fuel Oil System components:

• Bolting Integrity Program

• Buried Services Corrosion Monitoring Program

• Diesel Fuel Monitoring and Storage Program

• Fire Protection Program

• One-Time Inspection Program

• System Monitoring Program

3.3.2.1.9 Heating, Ventilation, and Air Conditioning System

Materials

The materials of construction for the Heating, Ventilation, and Air Conditioning 

System components are:

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Elastomers

• Galvanized
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• Low-Alloy Steel

• Stainless Steel

Environment

The Heating, Ventilation, and Air Conditioning System components are 

exposed to the following environments:

• Air (Ext)

• Air (Int)

• Containment Air (Ext)

• Gas (Ext)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Int)

• Steam (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Heating, Ventilation, and Air 

Conditioning System, require management:

• Buildup of Deposit 

• Change in Material Properties

• Cracking 

• Heat Transfer Degradation

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Heating, Ventilation, and Air Conditioning System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program
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3.3.2.1.10Miscellaneous Gas System

Materials

The materials of construction for the Miscellaneous Gas System are:

• Brass

• Bronze

• Carbon Steel

• Copper Alloys

• Galvanized

• Low-Alloy Steel

• Stainless Steel

Environment

The Miscellaneous Gas System components are exposed to the following 

environments:

• Air (Int)

• Atmosphere/Weather (Ext)

• Containment Air (Ext)

• Plant Indoor Air (Ext)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Miscellaneous Gas System, 

require management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Miscellaneous Gas System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Buried Services Corrosion Monitoring Program
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• One-Time Inspection Program

• System Monitoring Program

3.3.2.1.11Radwaste System

Materials

The materials of construction for the Radwaste System components are:

• Bronze

• Carbon Steel

• Cast Austenitic SS

• Cast Iron

• Copper Alloys

• Stainless Steel

Environment

The Radwaste System components are exposed to the following environments:

• Air (Int)

• Atmosphere/Weather (Ext)

• Containment Air (Ext)

• Gas (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

• Raw Water (Int)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Radwaste System, require 

management:

• Loss of Material

• Loss of Preload
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Radwaste System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program

• One-Time Inspection Program

• System Monitoring Program

3.3.2.1.12Service Water System

Materials

The materials of construction for the Service Water System components are:

• Aluminum Bronze

• Brass

• Bronze

• Carbon Steel

• Cast Iron

• Copper Alloys

• Low-Alloy Steel

• Rubber

• Stainless Steel

Environment

The Service Water System components are exposed to the following 

environments:

• Air (Int)

• Containment Air (Ext)

• Soil (Ext)

• Gas (Int)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Ext)
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• Raw Water (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Service Water System, require 

management:

• Buildup of Deposit 

• Cracking (of rubber)

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Service Water System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Buried Services Corrosion Monitoring Program

• One-Time Inspection Program

• Open Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.13Shield Cooling System

Materials

The materials of construction for the Shield Cooling System are:

• Carbon Steel

Environment

The Shield Cooling System components are exposed to the following 

environments:

• Containment Air (Ext)

• Plant Indoor Air (Ext)

• Treated Water (Int)
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Aging Effects Requiring Management

The following aging effects, associated with the Shield Cooling System, require 

management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Shield Cooling System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program

• System Monitoring Program

3.3.2.1.14Spent Fuel Pool Cooling System

Materials

The materials of construction for the Spent Fuel Pool Cooling System 

components are:

• Carbon Steel

• Stainless Steel

Environment

The Spent Fuel Pool Cooling System components are exposed to the following 

environments:

• Plant Indoor Air (Ext)

• Treated Water (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Spent Fuel Pool Cooling 

System, require management:

• Heat Transfer Degradation

• Loss of Material 

• Loss of Preload
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Spent Fuel Pool Cooling System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Closed Cycle Cooling Water Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.3.2.1.15Waste Gas System

Materials

The materials of construction for the Waste Gas System are:

• Carbon Steel

• Low-Alloy Steel

Environment

The Waste Gas System components are exposed to the following 

environments:

• Containment Air (Ext)

• Gas (Int)

• Plant Indoor Air (Ext)

• Raw Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Waste Gas System, require 

management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Waste Gas System components:

• Bolting Integrity Program
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• Boric Acid Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

3.3.2.1.16Domestic Water System

Materials

The materials of construction for the Domestic Water System are:

• Carbon Steel

• Cast Iron

• Copper Alloy

• Low Alloy Steel

• Stainless Steel

Environment

The Domestic Water System components are exposed to the following 

environments:

• Air (Int)

• Plant Indoor Air (Ext)

• Raw Water (Int)

• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Domestic Water System, 

require management:

• Loss of Material

Aging Management Programs

The following aging management programs manage the aging effects for the 

Domestic Water System components:

• Bolting Integrity Program

• One-Time Inspection Program

• System Monitoring Program
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3.3.2.1.17Chemical Addition System

Materials

The materials of construction for the Chemical Addition System are:

• Carbon Steel

• Stainless Steel

Environment

The Chemical Addition System components are exposed to the following 

environments:

• Air (Int)

• Plant Indoor Air (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Chemical Addition System, 

require management:

• Loss of Material

Aging Management Programs

The following aging management programs manage the aging effects for the 

Chemical Addition System components:

• One-Time Inspection Program

• System Monitoring Program

3.3.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 Volume 1 Tables provide the basis for identifying those programs 

that warrant further evaluation by the reviewer in the license renewal application. 

For the Auxiliary Systems, those programs are addressed in the following 

sections.

3.3.2.2.1 Loss of Material due to General, Pitting, and Crevice Corrosion

Paragraph 1 of this NUREG-1800 item states that loss of material due to 

general, pitting, and crevice corrosion could occur in the channel head and 

access cover, tubes, and tubesheets of the heat exchanger in the spent fuel 

pool cooling and cleanup. The water chemistry program relies on monitoring 
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and control of reactor water chemistry based on EPRI guidelines of 

TR-105714 for primary water chemistry in PWRs, and TR-102134 for 

secondary water chemistry in PWRs to manage the effects of loss of material 

from general, pitting or crevice corrosion. However, high concentrations of 

impurities at crevices and locations of stagnant flow conditions could cause 

general, pitting, or crevice corrosion. Therefore, verification of the 

effectiveness of the chemistry control program should be performed to ensure 

that corrosion is not occurring. NUREG-1801 recommends further evaluation 

of programs to manage loss of material from general, pitting, and crevice 

corrosion to verify the effectiveness of the water chemistry program.A 

one-time inspection of select components at susceptible locations is an 

acceptable method to ensure that corrosion is not occurring and the 

component’s intended function will be maintained during the period of 

extended operation.

Paragraph 2 states that loss of material due to pitting and crevice corrosion 

could occur in the filter housing, valve bodies, and nozzles of the ion 

exchanger in the spent fuel pool cooling and cleanup system (PWR). The 

water chemistry program relies on monitoring and control of reactor water 

chemistry based on EPRI guidelines of TR-105714 (Ref. 4) for primary water 

chemistry in PWRs, and TR-102134 (Ref. 5) for secondary water chemistry in 

PWRs to manage the effects of loss of material from pitting or crevice 

corrosion. However, high concentrations of impurities at crevices and 

locations of stagnant flow conditions could cause pitting, or crevice corrosion. 

Therefore, verification of the effectiveness of the chemistry control program 

should be performed to ensure that corrosion is not occurring. NUREG-1801 

recommends further evaluation of programs to manage loss of material from 

pitting and crevice corrosion to verify the effectiveness of the water chemistry 

program. A one-time inspection of select components at susceptible locations 

is an acceptable method to ensure that corrosion is not occurring and that the 

component’s intended function will be maintained during the period of 

extended operation.

The materials of the spent fuel pool cooling components evaluated in 

NUREG-1801 are carbon steels with elastomer linings, which differ from the 

stainless steel Spent Fuel Pool (SFP) Cooling System components of 

Palisades. This aging effect is not applicable to the Palisades spent Fuel Pool 

Cooling System.
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3.3.2.2.2 Hardening and Cracking or Loss of Strength due to Elastomer 

Degradation or Loss of Material due to Wear

NUREG-1800 states that hardening and cracking due to elastomer 

degradation could occur in elastomer linings of the filter, valve, and ion 

exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR). 

Hardening and loss of strength due to elastomer degradation could occur in 

the collars and seals of the duct and in the elastomer seals of the filters in the 

control room area, auxiliary and radwaste area, and primary containment 

heating ventilation systems and in the collars and seals of the duct in the 

diesel generator building ventilation system. Loss of material due to wear 

could occur in the collars and seals of the duct in the ventilation systems. 

NUREG-1801 recommends further evaluation to ensure that these aging 

effects are adequately managed.

This paragraph of NUREG 1800 describes the potential for degradation of 

elastomers in collars and seals in spent fuel cooling systems and ventilation 

systems. The materials of the spent fuel pool cooling components subject to 

aging management review have no elastomers. For the ventilation systems, 

elastomers are evaluated for cracking and changes of material properties due 

to thermal and radiation exposure. The System Monitoring Program manages 

degradation of elastomers at the seals and flexible connections. Elastomers 

are used in other systems. For those systems, management of elastomer 

degradation is provided by the System Monitoring Program.

3.3.2.2.3 Cumulative Fatigue Damage

NUREG-1800 states that fatigue of Reactor Pressure Boundary components is 

a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in 

accordance with 10 CFR 54.21(c). The evaluation of this TLAA is addressed 

separately in Section 4.3.

3.3.2.2.4 Crack Initiation and Growth due to Cracking or Stress Corrosion 

Cracking

NUREG-1800 states that crack initiation and growth due to SCC could occur 

due to cracking in the high-pressure pump in the chemical and volume control 

system (PWR). NUREG-1801 recommends further evaluation to ensure that 

these aging effects are managed adequately.

This paragraph of NUREG -1800, which discusses cracking in the 

high-pressure pump is not applicable to Palisades because the pump 
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temperature is <140°F, which is below the temperature threshold required to 

support cracking.

3.3.2.2.5 Loss of Material due to General, Microbiologically Influenced, Pitting, 

and Crevice Corrosion

NUREG-1800 states that loss of material due to general, pitting, and crevice 

corrosion could occur in the piping and filter housing and supports in the 

control room area, the auxiliary and radwaste area, the primary containment 

heating and ventilation systems, in the piping of the diesel generator building 

ventilation system, in the aboveground piping and fittings, valves, and pumps 

in the diesel fuel oil system and in the diesel engine starting air, combustion air 

intake, and combustion air exhaust subsystems in the emergency diesel 

generator system. Loss of material due to general, pitting, crevice, and 

microbiologically influenced corrosion (MIC) could occur in the duct fittings, 

access doors, and closure bolts, equipment frames and housing of the duct, 

due to pitting and crevice corrosion could occur in the heating/cooling coils of 

the air handler heating/cooling, and due to general corrosion could occur on 

the external surfaces of all carbon steel structures and components, including 

bolting exposed to operating temperatures less than 212°F in the ventilation 

systems. NUREG-1801 recommends further evaluation to ensure that these 

aging effects are adequately managed.

This paragraph of NUREG -1800 discusses the loss of material from corrosion 

that could occur on internal and external surfaces of components exposed to 

plant indoor air and atmosphere and weather. Specifically included are the 

ventilation systems, diesel fuel oil, emergency diesel starting air, and 

combustion air intake and exhaust systems, and the external carbon steel 

surfaces of auxiliary systems.

For the internal environments of applicable Auxiliary Systems, the Open Cycle 

Cooling Water Program, Diesel Fuel Monitoring and Storage Program, 

One-Time Inspection Program (including tank internal inspection), and Fire 

Protection Program are credited for managing the aging effect of loss of 

material.

For the external surfaces of all carbon steel components in Auxiliary Systems, 

the System Monitoring Program is credited for managing the aging effect of 

loss of material. The Open Cycle Cooling Water Program and the Fire 

Protection Program are credited to augment the System Monitoring Program 

for managing external aging effects in Service Water and Fire Protection 
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System, respectively. Closure bolting is managed by the Bolting Integrity 

Program.

As discussed in the respective program sections of Appendix B, each of these 

programs provides reasonable assurance that aging effects will be managed 

such that SSCs within the scope of each program will continue to perform their 

intended functions consistent with the current licensing bases for the period of 

extended operation.

3.3.2.2.6 Loss of Material due to General, Galvanic, Pitting, and Crevice Corrosion

NUREG-1800 states that loss of material due to general, galvanic, pitting, and 

crevice corrosion could occur in tanks, piping, valve bodies, and tubing in the 

reactor coolant pump oil collection system in fire protection. The fire protection 

program relies on a combination of visual and volumetric examinations in 

accordance with the guidelines of 10 CFR Part 50 Appendix R and Branch 

Technical Position 9.5-1 to manage loss of material from corrosion. However, 

corrosion may occur at locations where water from wash downs may 

accumulate. Therefore, verification of the effectiveness of the program should 

be performed to ensure that corrosion is not occurring. NUREG-1801 

recommends further evaluation of programs to manage loss of material due to 

general, galvanic, pitting, and crevice corrosion to verify the effectiveness of 

the program. A one-time inspection of the bottom half of the interior surface of 

the tank of the reactor coolant pump oil collection system is an acceptable 

method to ensure that corrosion is not occurring and that the component’s 

intended function will be maintained during the period of extended operation.

The Palisades Fire Protection Program has a separate oil collection system 

for each Primary Coolant Pump (PCP). NUREG-1801 assumes that the 

reactor coolant pump oil collection tanks and piping is constructed from 

carbon steel, copper and stainless steel alloys. However, the Palisades Plant 

oil collection tank, drip pans and oil lift pump enclosures are stainless steel. 

Annealed copper tubing is used to connect these components and direct the 

path of any oil leakage from the PCP motor. These materials are located 

inside containment. They are normally exposed to a Containment Air internal 

and external environment. Any oil that is collected will be lubricating oil without 

any water entrainment. Loss of material due to general and galvanic corrosion 

is not applicable to this oil collection system. If water condensed from air or 

spray from some water source were to enter the system then crevice and 

pitting corrosion could be an aging effect. A One-Time Inspection of the tank 
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and piping is credited to ensure that loss of material due to crevice and pitting 

corrosion are not occurring. 

3.3.2.2.7 Loss of Material due to General, Pitting, Crevice, and Microbiologically 

Influenced Corrosion and Biofouling

NUREG-1800 states that loss of material due to general, pitting, and crevice 

corrosion, MIC, and biofouling could occur in the internal surface of tanks in 

the diesel fuel oil system and due to general, pitting, and crevice corrosion and 

MIC in the tanks of the diesel fuel oil system in the emergency diesel 

generator system. The existing aging management program relies on the fuel 

oil chemistry program for monitoring and control of fuel oil contamination in 

accordance with the guidelines of ASTM Standards D4057, D1796, D2709 

and D2276 to manage loss of material due to corrosion or biofouling. 

Corrosion or biofouling may occur at locations where contaminants 

accumulate. Verification of the effectiveness of the chemistry control program 

should be performed to ensure that corrosion is not occurring. NUREG-1801 

recommends further evaluation of programs to manage corrosion/biofouling to 

verify the effectiveness of the program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

The Diesel Fuel Monitoring and Storage Program manages components in 

the Fuel Oil System associated with the Emergency Diesel Generators and 

Diesel Fire Pumps, including storage tanks, day tanks, piping, valve bodies, 

and other passive components rely on the Diesel Fuel Monitoring and Storage 

Program to minimize potential for degradation and loss of intended function. 

The program manages the conditions that would cause general, pitting and 

microbiological influenced corrosion (MIC) of the diesel fuel tank internal 

surfaces. 

The One-Time Inspection Program provides reasonable assurance that aging 

effects will be managed such that SSCs within the scope of this program will 

continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.

3.3.2.2.8 Quality Assurance for Aging Management of Non-Safety Related 

Components

Quality Assurance Program applicability to non-safety-related components is 

addressed in Appendix B, Section 1.2.
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3.3.2.2.9 Crack Initiation and Growth due to Stress Corrosion Cracking and Cyclic 

Loading

NUREG-1800 states that crack initiation and growth due to SCC and cyclic 

loading could occur in the channel head and access cover, tube sheet, tubes, 

shell and access cover, and closure bolting of the regenerative heat 

exchanger and in the channel head and access cover, tube sheet, and tubes 

of the letdown heat exchanger in the chemical and volume control system 

(PWR). The water chemistry program relies on monitoring and control of water 

chemistry based on the guidelines of TR-105714 for primary water chemistry 

in PWRs to manage the effects of crack initiation and growth due to SCC and 

cyclic loading. Verification of the effectiveness of the chemistry control 

program should be performed to ensure that crack initiation and growth are 

not occurring. NUREG-1801 recommends further evaluation to manage crack 

initiation and growth from SCC and cyclic loading for these systems to verify 

the effectiveness of the water chemistry program. A one-time inspection of 

select components and susceptible locations is an acceptable method to 

ensure that crack initiation and growth are not occurring and that the 

components’ intended function will be maintained during extended operations.

The Water Chemistry Program is credited for managing aging effects such as 

loss-of-material due to general, pitting and crevice corrosion, MIC, cracking 

due to SCC, and fouling due to corrosion product buildup in stagnant and low 

flow regions, by controlling the environment to which internal surfaces of 

systems and components are exposed. The aging effects are minimized by 

controlling the chemical species that cause the underlying mechanisms that 

result in these aging effects. The program provides assurance that an 

elevated level of contaminants and oxygen does not exist in the systems and 

components covered by the program, thus minimizing the occurrences of 

aging effects, and maintaining components ability to perform their intended 

functions. The program is based on the guidelines in EPRI TR-105714, Rev. 5 

and TR-102134, Rev. 5. 

The One-Time Inspection Program is credited by the Water Chemistry 

Program and its corresponding GALL Report section XI.M2 for managing the 

effects of aging in stagnant or low-flow areas of components. The Water 

Chemistry Control Program may be credited for managing aging effects for 

components where the water flow is low or stagnant conditions exist. However 

water chemistry sampling points may not be indicative of conditions in 

stagnant or low-flow locations. Therefore, confirmatory inspections are 
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appropriate. Accordingly, to ensure that significant degradation is not 

occurring and to ensure that the component will continue to perform its 

intended function during the period of extended operation, a one-time 

inspection of selected components will be performed.

3.3.2.2.10Reduction of Neutron-Absorbing Capacity and Loss of Material due to 

General Corrosion

NUREG-1800 states that reduction of neutron-absorbing capacity and loss of 

material due to general corrosion could occur in the neutron-absorbing sheets 

of the spent fuel storage rack in the spent fuel storage. NUREG-1801 

recommends further evaluation to ensure that these aging effects are 

adequately managed.

Palisades FSAR Section 9.11.3.2, “Modified Spent Fuel Storage,” provides a 

discussion of the spent fuel storage racks in the Palisades spent fuel pool. It 

describes two regions, as follows: “Region 1 contains racks in the spent fuel 

pool having a 10.25-inch center-to-center spacing and a single rack in the 

North Tilt Pit having 11.25-inch x 10.69-inch center-to-center spacing. Region 

2 contains racks in both the spent fuel pool and North Tilt Pit having 9.17-inch 

center-to-center spacing. Because of the larger center-to-center spacing, and 

the poison (B10) concentration of Region 1 cells, Region I (NUS) spent fuel 

storage racks can accommodate fuel assemblies having a maximum planar 

average U-235 enrichment of 4.95 weight percent. This assures the fuel 

enrichment limit assumed in the spent fuel analyses will not be exceeded.

“The Region 2 racks contain a neutron absorbing material, boraflex, 

manufactured by the Brand Industrial Services, Inc., and fabricated to the 

Nuclear Criteria of 10 CFR 50, Appendix B. Boraflex is a silicone-based 

polymer containing fine particles of boron carbide in a homogeneous matrix. 

The boraflex used in the Region 2 racks contains a minimum B10 areal density 

of 0.006 gm/cm2. Since the long-term stability of boraflex has not yet been 

resolved, the Region 2 criticality calculations were revised to eliminate any 

credit taken for criticality control due to the presence of Boraflex.”

FSAR Section 9.11.3.4, “Prevention of Criticality During Transfer and 

Storage,” further clarifies that: “The Region 2 racks are designed for a 9.17 

inch center-to-center spacing with boraflex sheets used as a neutron 

absorbing material to compensate for the closer spacing. As discussed earlier 

the most recent criticality calculation for Region 2 did not take credit for 

boraflex. The omission of boraflex from the calculation is compensated for by 
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taking credit for the presence of soluble boron in the spent fuel pool water and 

the radioactive decay time of the spent fuel being stored.

“The precedent of crediting soluble boron to provide criticality control aside 

from normal reactor operations has already been established. Soluble boron 

credit was used in the “Westinghouse Spent Fuel Rack Criticality Analysis 

Methodology” described in WCAP-14416-NP-A. That methodology was 

accepted for use by an NRC Safety Evaluation dated October 25, 1996. 

Additional guidance outlining the requirements for use of soluble boron has 

been issued by the NRC and documented in 'Guidance on the Regulatory 

Requirements for Criticality Analysis of Fuel Storage at Light-Water Reactor 

Power Plants,' Laurence I. Kopp, U.S. Nuclear Regulatory Commission, Office 

of Nuclear Reactor Regulation, Reactor Systems Branch, February 1998."

This section of the FSAR continues to discuss that: “In order to maintain a 

k-effective less than or equal to 0.95 for the tilt machine and fuel elevator, 850 

ppm boron is required. This is maintained by meeting normal requirements 

outlined in Technical Specification LCO 3.7.15 and associated procedures. 

Credit is taken for boron to maintain k-effective less than or equal to 0.95 with 

a margin of 870 ppm being available due to the Technical Specification 

requirement of 1720 ppm.”

Thus, Boraflex in Region 2 of the Spent Fuel Pool is not credited in the Spent 

Fuel Pool criticality analysis since the required boron is ensured by the 

Technical Specifications requirements. Accordingly, it is not included in-scope 

of License Renewal and no age managing of it is required.

For Region 1, FSAR Section 9.11.3.4, “Prevention of Criticality During 

Transfer and Storage,” states that B4C (boron carbide) is credited in criticality 

calculations:

“The Region 1 racks in the main pool are designed for a 10-1/4-inch 

center-to-center spacing with B4C plates around each assembly. Borated 

water surrounds the spent fuel storage racks in the same concentration and to 

a level common to the refueling cavity and pool. The center-to-center distance 

of the Region 1 storage racks is such that a keff of less than 0.95 is maintained 

even in the event that unborated water was used to fill the storage areas.”

The B4C plates in the Region 1 racks are sheathed between stainless plates, 

unlike Boral that has the boron carbide sandwiched between aluminum alloy. 

There has been some industry experience with blistering and swelling of Boral 

as a result of a chemical reaction between the boron carbide and aluminum 
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alloy. This has not been observed with stainless cladding. In addition, per NRC 

memorandum entitled “Resolution of Spent Fuel Storage Pool Action Plan 

Issue” dated July 26, 1996, section 3.3.1 states “...degradation in neutron 

absorption performance has not been observed in materials other than 

Boraflex. Some neutron absorbing panels have been observed to swell due to 

gas accumulation within the cladding material, but this effect has not degraded 

neutron absorption performance.” Thus, reduction in neutron-absorbing 

capacity and loss of material due to general corrosion is not an aging effect 

requiring management for boron carbide (B4C). The stainless steel sheathing 

for the boron carbide will be age managed for loss of material due to pitting or 

crevice corrosion cracking via the water chemistry program, consistent with 

NUREG-1801 item VIIA2.1c.

In conclusion, the Palisades Spent Fuel Storage Racks contain B4C (Boron 

Carbide) and Boraflex neutron absorbing material. Due to industry concerns 

on degradation of boraflex, soluble boron is maintained at 1720 ppm per 

Technical Specification LCO 3.7.15 to maintain k-effective less than or equal 

to 0.95. Criticality calculations take credit for the soluble boron in the spent 

fuel pool water and conclude that boraflex material does not need to be 

credited.

For the storage racks containing boron carbide, no credit is taken for soluble 

boron. There is no industry experience that boron carbide sheathed in 

stainless steel has experienced loss of material due to corrosion. With regards 

to reduction of neutron absorbing capability due to corrosion, NRC 

memorandum entitled “Resolution of Spent Fuel Storage Pool Action Plan 

Issue” dated July 26, 1996, section 3.3.1 states “...degradation in neutron 

absorption performance has not been observed in materials other than 

Boraflex.” 

Therefore, no plant specific aging management program is required to 

manage reduction of neutron-absorbing capacity and loss of material due to 

general corrosion, as addressed in NUREG-1801 Item VIIA2.1-b, in VIIA2, 

Spent Fuel Storage. The stainless steel sheathing for the boron carbide will be 

age managed for loss of material due to pitting or crevice corrosion cracking 

via the Water Chemistry Program, consistent with NUREG-1801 item 

VIIA2.1c. Boraflex, as discussed in NUREG-1801 item VIIA2.1a is not 

in-scope of license renewal since it performs no intended function.
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3.3.2.2.11Loss of Material due to General, Pitting, Crevice, and Microbiologically 

Influenced Corrosion

NUREG-1800 states that loss of material due to general, pitting, and crevice 

corrosion and MIC could occur in the underground piping and fittings in the 

open-cycle cooling water system (service water system) and in the diesel fuel 

oil system. The buried piping and tanks inspection program relies on industry 

practice, frequency of pipe excavation, and operating experience to manage 

the effects of loss of material from general, pitting, and crevice corrosion and 

MIC. The effectiveness of the buried piping and tanks inspection program 

should be verified to evaluate an applicant’s inspection frequency and 

operating experience with buried components, ensuring that loss of material is 

not occurring.

The Buried Services Corrosion Monitoring Program manages aging effects on 

the external surfaces of carbon steel, low-alloy steel, and stainless steel 

components (e.g. tanks, piping) that are buried in soil or sand. This program 

includes (a) visual inspections of external surfaces of buried components for 

evidence of coating damage and substrate degradation to manage the effects 

of aging, (b) visual inspection of the external surfaces of buried stainless steel 

components for evidence of crevice corrosion, pitting, and MIC. The 

periodicity of these inspections for carbon, low-alloy, and stainless steel will be 

based on opportunities for inspection such as scheduled maintenance work.

3.3.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Auxiliary Systems components. The section of the LRA that contains the TLAA 

review results is indicated in parenthesis.

• Fatigue (Section 4.3, Metal Fatigue)

3.3.3 Conclusion

The Auxiliary System piping, fittings, and components that are subject to aging 

management review have been identified in accordance with the requirements of 10 CFR 

54.4. The aging management programs selected to manage aging effects for the Auxiliary 

Systems components are identified in the summaries in Section 3.3.2.1 above.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.
Page 3-112 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Therefore, based on the demonstrations provided in Appendix B, the effects of aging 

associated with the Auxiliary System components will be adequately managed so that there 

is reasonable assurance that the intended function(s) will be maintained consistent with the 

current licensing basis during the period of extended operation.
Page 3-113 

Table 3.3.1 Summary of Aging Management Evaluations 

Application for Renewed Operating Licenses

in Chapter VII of NUREG-1801 for Auxiliary Systems

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.3.1-01 Components in spent fuel pool 

cooling and cleanup

Loss of material due to general, pitting, and crevice corrosion

Water chemistry and one-time inspection

Yes, detection of aging effects is to be further evaluated (see [SRP] subsections 3.3.2.2.1.1 and 3.3.2.2.1.2)

Further evaluation documented in Section 3.3.2.2.1 Paragraph 1 and Paragraph 2.

3.3.1-02 Linings in spent fuel pool 

cooling and cleanup system; seals and collars in ventilation systems 

Hardening, cracking and loss of strength due to elastomer degradation; loss of material due to wear

Plant specific Yes, plant specific 

(see [SRP] subsection 3.3.2.2.2)

Further evaluation documented in Section 3.3.2.2.2.

3.3.1-03 Components in load handling, 

chemical and volume control system (PWR), and reactor water cleanup and shutdown cooling systems (older BWR) 

Cumulative fatigue damage

TLAA, evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.3.2.2.3)

Further evaluation documented in Section 3.3.2.2.3.The aging mechanism fatigue is potentially applicable to many component types in the Auxiliary Systems Supergroup, but only selected components or locations require explicit analysis as TLAAs and/or warrant aging management. The Palisades approach to identifying and managing the relevant locations and components for fatigue damage is addressed in Section 4.3 and in Appendix B, Fatigue Monitoring Program. Therefore, cumulative fatigue damage is not identified as an aging effect in Tables 3.3.2-1 through 3.3.2-15.below.

3.3.1-04 Heat exchangers in reactor 

water cleanup system (BWR); high pressure pumps in chemical and volume control system (PWR)

Crack initiation and growth due to SCC or cracking

Plant specific Yes, plant specific 

(see [SRP] subsection 3.3.2.2.4)

Further evaluation documented in Section 3.3.2.2.4.
Page 3-114 

Application for Renewed Operating Licenses

3.3.1-05 Components in ventilation 

systems, diesel fuel oil system, and emergency diesel generator systems; external surfaces of carbon steel components 

Loss of material due to general, pitting, and crevice corrosion, and MIC

Plant specific Yes, plant specific 

(see [SRP] subsection 3.3.2.2.5)

Further evaluation documented in Section 3.3.2.2.5.

3.3.1-06 Components in reactor coolant 

pump oil collect system of fire protection 

Loss of material due to galvanic, general, pitting, and crevice corrosion

One-time inspection

Yes, detection of aging effects is to be further evaluated (see [SRP] subsection 3.3.2.2.6)

Further evaluation documented in Section 3.3.2.2.6.

3.3.1-07 Diesel fuel oil tanks in diesel 

fuel oil system and emergency diesel generator system

Loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling

Fuel oil chemistry and one-time inspection

Yes, detection of aging effects is to be further evaluated (see [SRP] subsection 3.3.2.2.7)

Further evaluation documented in Section 3.3.2.2.7.

3.3.1-08 BWR only3.3.1-09 Heat exchangers in chemical 

and volume control system 

Crack initiation and growth due to SCC and cyclic loading

Water chemistry and a plant-specific verification program

Yes, plant specific (see [SRP] subsection 3.3.2.2.9)

Further evaluation documented in Section 3.3.2.2.9.

3.3.1-10 Neutron absorbing sheets in 

spent fuel storage racks 

Reduction of neutron absorbing capacity and loss of material due to general corrosion (Boral, boron steel)

Plant specific Yes, plant specific 

(see [SRP] subsection 3.3.2.2.10)

Further evaluation documented in Section 3.3.2.2.10.

3.3.1-11 New fuel rack assembly Loss of material due 

to general, pitting, and crevice corrosion

Structures monitoring

No See [Section B2.1.4] Boric Acid Corrosion 

Program for aging management program.

Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary Systems

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-115 

Application for Renewed Operating Licenses

3.3.1-12 Neutron absorbing sheets in 

spent fuel storage racks

Reduction of neutron absorbing capacity due to Boraflex degradation

Boraflex monitoring No Not applicable

3.3.1-13 Spent fuel storage racks and 

valves in spent fuel pool cooling and cleanup

Crack initiation and growth due to stress corrosion cracking

Water chemistry No See [Section B2.1.21] Water Chemistry 

Program for aging management program.

3.3.1-14 Closure bolting and external 

surfaces of carbon steel and low-alloy steel components 

Loss of material due to boric acid corrosion

Boric acid corrosion No See [Section B2.1.4] Boric Acid Corrosion 

Program for aging management program.

3.3.1-15 Components in or serviced by 

closed-cycle cooling water system

Loss of material due to general, pitting, and crevice corrosion, and MIC

Closed-cycle cooling water system

No See [Section B2.1.6] Closed Cycle Cooling 

Water Program, [Section B2.1.13] One Time Inspection Program, and [Section B2.1.21] Water Chemistry Program for aging management program.

3.3.1-16 Cranes including bridge and 

trolleys and rail system in load handling system

Loss of material due to general corrosion and wear

Overhead heavy load and light load handling systems

No See [Section B2.1.15] Overhead Load 

Handling System Inspection Program for aging management program.

3.3.1-17 Components in or serviced by 

open-cycle cooling water systems

Loss of material due to general, pitting, crevice, and galvanic corrosion, MIC, and biofouling; buildup of deposit due to biofouling

Open-cycle cooling water system

No See [Section B2.1.6] Closed Cycle Cooling 

Water Program, [Section B2.1.13] One Time Inspection Program, and [Section B2.1.14] Open Cycle Cooling Water Program for aging management program.

Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary Systems

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-116 

Application for Renewed Operating Licenses

3.3.1-18 Buried piping and fittings Loss of material due 

to general, pitting, and crevice corrosion, and MIC

Buried piping and tanks surveillanceor Buried piping and tanks inspection

NoYes, detection of aging effects and operating experience are to be further evaluated (see [SRP] subsection 3.3.2.2.11)

Further evaluation documented in Section 3.3.2.2.11.

3.3.1-19 Components in compressed 

air system

Loss of material due to general and pitting corrosion

Compressed air monitoring

No See [Section B2.1.13] One Time Inspection 

Program for aging management program.

3.3.1-20 Components (doors and 

barrier penetration seals) and concrete structures in fire protection

Loss of material due to wear; hardening and shrinkage due to weathering

Fire protection No See [Section B2.1.10] Fire Protection Program 

for aging management program.

3.3.1-21 Components in water-based 

fire protection 

Loss of material due to general, pitting, crevice, and galvanic corrosion, MIC, and biofouling

Fire water system No See [Section B2.1.10] Fire Protection Program 

and [Section B2.1.13] One Time Inspection Program for aging management programs.

3.3.1-22 Components in diesel fire 

system

Loss of material due to galvanic, general, pitting, and crevice corrosion

Fire protection and fuel oil chemistry

No See [Section B2.1.10] Fire Protection Program 

and [Section B2.1.9] Diesel Fuel Monitoring and Storage Program for aging management programs.

3.3.1-23 Tanks in diesel fuel oil system Loss of material due 

to general, pitting, and crevice corrosion

Above ground carbon steel tanks

No See [Section B2.1.9] Diesel Fuel Monitoring 

and Storage Program, [Section B2.1.13] One Time Inspection Program, and [Section B2.1.20] System Monitoring Program for aging management program.

Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary Systems

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-117 

Application for Renewed Operating Licenses

3.3.1-24 Closure bolting Loss of material due 

to general corrosion; crack initiation and growth due to cyclic loading and SCC

Bolting integrity No See [Section B2.1.4] Boric Acid Corrosion 

Program, [Section B2.1.13] One Time Inspection Program, and [Section B2.1.20] System Monitoring Program for aging management programs.

3.3.1-25 BWR only3.3.1-26 BWR only3.3.1-27 BWR only3.3.1-28 BWR only3.3.1-29 Components (aluminum 

bronze, brass, cast iron, cast steel) in open-cycle and closed-cycle cooling water systems, and ultimate heat sink 

Loss of material due to selective leaching

Selective leaching of materials

No See [Section B2.1.13] One Time Inspection 

Program for aging management program.

3.3.1-30 Fire barriers, walls, ceilings 

and floors in fire protection

Concrete cracking and spalling due to freeze-thaw, aggressive chemical attack, and reaction with aggregates; loss of material due to corrosion of embedded steel

Fire protection and structures monitoring

No See [Section B2.1.10] Fire Protection Program 

and [Section B2.1.19] Structural Monitoring Program for aging management programs.

Table 3.3.1 Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for Auxiliary Systems

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-118 

Table 3.3.2-1 Auxiliary Systems - Chemical and Volume C

Application for Renewed Operating Licenses

ontrol System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Boric Acid Storage Tanks

Fluid Pressure Boundary

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

G

Oil Cooler Shell Fluid 

Pressure Boundary

Brass Oil (Int) Loss of Material One-Time Inspection 

Program

J

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Oil Cooler Tubes Fluid 

Pressure Boundary

Copper Nickel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

J

Letdown Heat Exchanger Shell

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.E1.8-c 3.3.1-15 B

Letdown Heat Exchanger Channel Head, Tubes, Tube Sheet

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Ext)

Cracking Closed Cycle Cooling 

Water Program

VII.E1.8-b 3.3.1-09 B

Letdown Heat Exchanger Tubes, Tube Sheet

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Ext)

Loss of Material Closed Cycle Cooling 

Water Program

H

Letdown Heat Exchanger Tubes

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Ext)

Loss of Material One-Time Inspection 

Program

H
Page 3-119 

Application for Renewed Operating Licenses

Letdown Heat Exchanger Channel Head, Tubes, Tube Sheet

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

VII.E1.8-b 3.3.1-09 A

Water Chemistry Program VII.E1.8-b 3.3.1-09 A

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, ALoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 A

Boric Acid Corrosion Program

VII.E1.1-b 3.3.1-14 AVII.E1.2-a 3.3.1-14 AVII.E1.5-b 3.3.1-14 AVII.E1.6-a 3.3.1-14 AVII.E1.7-b 3.3.1-14 AVII.E1.8-d 3.3.1-14 AVII.E1.10-a 3.3.1-14 A

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Containment Air (Ext)

Loss of Preload Bolting Integrity Program 324, F

Table 3.3.2-1 Auxiliary Systems - Chemical and Volume Control System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-120 

Application for Renewed Operating Licenses

Pipe - CVC Cooler

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.1-a 3.3.1-15 366, B

Nozzle - CVC Spray

Fluid Pressure Boundary

Stainless Steel Gas (Ext) Loss of Material One-Time Inspection 

Program

G

Tubing - CVC Oil Fluid 

Pressure Boundary

Stainless Steel Oil (Int) Loss of Material One-Time Inspection 

Program

G

Pipe and Pressure Test Fittings

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

IV.C2.2-f 3.1.1-36 AIV.C2.2-h 3.1.1-07 A

One-Time Inspection Program

IV.C2.2-h 3.1.1-07 B

Water Chemistry Program IV.C2.2-f 3.1.1-36 A

IV.C2.2-h 3.1.1-07 A

Flow Elements Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

IV.C2.2-h 3.1.1-07 367, H

Regenerative Heat Exchanger Tubes, Tube Sheet

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Ext)

Cracking Water Chemistry Program VII.E1.7-c 3.3.1-09 A

One-Time Inspection Program

VII.E1.7-c 3.3.1-09 B

Table 3.3.2-1 Auxiliary Systems - Chemical and Volume Control System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-121 

Application for Renewed Operating Licenses

Regenerative Heat Exchanger Channel Head, Shell, Tubes, Tube Sheet

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

VII.E1.7-c 3.3.1-09 A

Water Chemistry Program VII.E1.7-c 3.3.1-09 A

Control Valves Fluid 

Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

VII.E1.7-c 3.3.1-09 C

One-Time Inspection Program

VII.E1.7-c 3.3.1-09 D

Water Chemistry Program VII.E1.7-c 3.3.1-09 C

Letdown Stop Valve CV-2001

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Reduction of Fracture Toughness 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

H

Check, Control, Manual & Relief valves; Instrument Assemblies

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

VII.E1.5-a 3.3.1-04 C

One-Time Inspection Program

VII.E1.5-a 3.3.1-04 D

Water Chemistry Program VII.E1.5-a 3.3.1-04 C

Table 3.3.2-1 Auxiliary Systems - Chemical and Volume Control System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-122 

Table 3.3.2-2 Auxiliary Systems - Circulating Water 

Application for Renewed Operating Licenses

System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 ALoss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, A

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A

Pumps Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.5-a 3.3.1-17 A

Valves & Dampers

Fluid Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.5-a 3.3.1-17 A

One-Time Inspection Program

VII.C1.5-a 3.3.1-17 B, 301
Page 3-123 

Table 3.3.2-3 Auxiliary Systems- Component Cooling Wate

Application for Renewed Operating Licenses

r System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material Closed Cycle Cooling 

Water Program

319, G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.4-a 3.3.1-15 B

Bistable/Switch(In-line Flow Indicator)

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 D

Component Cooling Heat Exchanger

Fluid Pressure Boundary

Aluminum Bronze

Raw Water (Ext) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 315, C

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 A

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 380, A
Page 3-124 

Application for Renewed Operating Licenses

Component Cooling Heat Exchanger

Fluid Pressure Boundary

Carbon Steel Raw Water (Int) Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 E

Open Cycle Cooling Water Program

VII.C1.3-a 3.3.1-17 A

Treated Water (Ext)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 E

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 E

Fluid Pressure BoundaryHeat Transfer

Copper Alloys Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 A

Heat Transfer Degradation

Closed Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 315, E

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 313, 

315, 316, A

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 313, 

315, E

Open Cycle Cooling Water Program

VII.C1.3-a 3.3.1-17 313, 

315, A

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, 

313, 315, B

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-125 

Application for Renewed Operating Licenses

Component Cooling Heat Exchanger

Fluid Pressure BoundaryHeat Transfer

Copper Alloys Treated Water 

(Ext)

Heat Transfer Degradation

Closed Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 313, 

315, 316, E

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 313, 

315, 323, E

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, 

313, B

Cooler Fluid 

Pressure Boundary

Nickel-Based Alloys

Treated Water (Ext)

Loss of Material Closed Cycle Cooling 

Water Program

308, J

One-Time Inspection Program

308, J

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

308, J

Water Chemistry Program 308, J

Stainless Steel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 D

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-126 

Application for Renewed Operating Licenses

Heat Exchanger Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.4-a 3.3.1-15 C

Copper Alloys Treated Water 

(Ext)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.4-a 3.3.1-15 323, C

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C2.3-a 3.3.1-15 301, C

Treated Water (Int)

Cracking Closed Cycle Cooling 

Water Program

J

Fasteners Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, CLoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, CLoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Stainless Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program 324, F

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-127 

Application for Renewed Operating Licenses

Primary Coolant Pump Motor Oil Cooler

Fluid Pressure Boundary

Brass Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 325, E

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 325, D

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 D

Copper Nickel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 325, E

Pipe & Fittings Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 D

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.1-a 3.3.1-15 B

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-128 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Copper Alloys Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

317, F

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 325, E

Pumps Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.3-a 3.3.1-15 B

Valves & Dampers

Fluid Pressure Boundary

Bronze Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

317, F

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 325, E

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 B

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-129 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Cast Iron Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 390, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C2.3-a 3.3.1-29 D

Waste Gas Compressor Cooler

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 318, 

320, D

Stainless Steel Gas (Int) Cracking Closed Cycle Cooling 

Water Program

308, J

Loss of Material Closed Cycle Cooling 

Water Program

308, J

Treated Water (Ext)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 323, D

Table 3.3.2-3 Auxiliary Systems- Component Cooling Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-130 

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Application for Renewed Operating Licenses

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.3-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Air Dryers Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.6-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Blowers, Fans, Compressors, Vacuum

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.6-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A
Page 3-131 

Application for Renewed Operating Licenses

Filters/Strainers Fluid 

Pressure BoundaryFiltration

Aluminum Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Brass Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Bronze Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.5-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.5-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.D.5-a 3.3.1-19 A

System Monitoring Program

VII.I.1-b 3.3.1-05 335, A

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-132 

Application for Renewed Operating Licenses

Filters/Strainers Fluid 

Pressure BoundaryFiltration

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.5-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

F

Oil (Int) Loss of Material One-Time Inspection 

Program

F

Heat Exchangers

Fluid Pressure Boundary

Bronze Air (Int) Loss of Material Open Cycle Cooling Water 

Program

F

Raw Water (Ext) Loss of Material Open Cycle Cooling Water 

Program

F

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material Open Cycle Cooling Water 

Program

F

Copper Alloys Air (Int) Loss of Material One-Time Inspection 

Program

F

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-133 

Application for Renewed Operating Licenses

Fasteners Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program 324, FLoss of Material Bolting Integrity Program VII.I.1-b 3.3.1-05 E

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Copper Alloys Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Loss of Preload Bolting Integrity Program 324, F

Pipe & Fittings Fluid 

Pressure Boundary

Brass Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.1-a 3.3.1-19 E

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Copper Alloys Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-134 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Copper Alloys Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

F

Pumps Fluid 

Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 335, A

Traps (Steam) Fluid 

Pressure Boundary

Aluminum Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.2-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 335, A

Valves & Dampers

Fluid Pressure Boundary

Brass Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-135 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Brass Oil Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Bronze Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.2-a 3.3.1-19 E

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.2-a 3.3.1-19 E

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 335, A

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-136 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Copper Alloys Containment Air 

(Ext)Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

F

Table 3.3.2-4 Auxiliary Systems - Compressed Air System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-137 

Table 3.3.2-5 Auxiliary Systems- Containment Air Recirculat

Application for Renewed Operating Licenses

ion and Cooling System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Containment Air Cooler Coils

Fluid Pressure Boundary

Copper Alloys Air (Ext) Heat Transfer 

Degradation 

System Monitoring Program

VII.F3.2-a 3.3.1-05 387, H

Loss of Material One-Time Inspection 

Program

VII.F3.2-a 3.3.1-05 B

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 325, C

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 316, 

325, C

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 325, 

394, C

Heat Transfer Copper Alloys Air (Ext) Heat Transfer 

Degradation 

System Monitoring Program

VII.F3.2-a 3.3.1-05 387, H

Loss of Material One-Time Inspection 

Program

VII.F3.2-a 3.3.1-05 B

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 325, C

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 316, 

325, C

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 325, 

394, C
Page 3-138 

Application for Renewed Operating Licenses

Containment Air Cooler Filter

Filtration Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.4-a 3.3.1-05 308, B

Fluid Pressure Boundary

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.4-a 3.3.1-05 308, B

Containment Air Cooler Flow Element

Flow Measurement

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.4-a 3.3.1-05 308, E

Fluid Pressure Boundary

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.4-a 3.3.1-05 308, E

Containment Air Cooler Housing

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.1-a 3.3.1-05 391, B

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Containment Air Cooler Recirculation Fans

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.1-a 3.3.1-05 391, B

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-5 Auxiliary Systems- Containment Air Recirculation and Cooling System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-139 

Application for Renewed Operating Licenses

Dampers Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.1-a 3.3.1-05 391, B

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Drip Pans Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.F3.1-a 3.3.1-05 B

Duct Pressure 

Boundary

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.1-a 3.3.1-05 B

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 386, A

Fasteners Fluid 

Pressure BoundaryStructure Functional Support

Stainless Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Low-Alloy Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, ALoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, D

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Table 3.3.2-5 Auxiliary Systems- Containment Air Recirculation and Cooling System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-140 

Manual and 

Application for Renewed Operating Licenses

Instrumentation Valves

Fluid Pressure Boundary

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F3.4-a 3.3.1-05 308, E

Table 3.3.2-5 Auxiliary Systems- Containment Air Recirculation and Cooling System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-141 

Table 3.3.2-6 Auxiliary Systems- Emergency Power Sy

Application for Renewed Operating Licenses

stem - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VIII.H.2-a 3.4.1-08 AVII.H2.2-a 3.3.1-05 B

Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 B

One-Time Inspection Program

VII.H2.5-a 3.3.1-07 B

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.H2.1-a 3.3.1-15 D

Blowers Fans Compressor Vacuum

Fluid Pressure Boundary

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 399, A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A
Page 3-142 

Application for Renewed Operating Licenses

Cooler Fluid 

Pressure Boundary

Carbon Steel Oil (Ext) Heat Transfer 

Degradation 

One-Time Inspection Program

J

Loss of Material One-Time Inspection 

Program

VII.H2.5-a 3.3.1-07 D

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.H2.5-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

J

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 A

Heat Transfer Carbon Steel Oil (Ext) Heat Transfer 

Degradation 

One-Time Inspection Program

J

Loss of Material One-Time Inspection 

Program

VII.H2.5-a 3.3.1-07 D

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

J

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 A

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-143 

Application for Renewed Operating Licenses

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, ALoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 A

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Filters/Strainers Filtration Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 386, A

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

F

Fluid Pressure Boundary

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 D

One-Time Inspection Program

VII.H2.5-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 386, A

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

F

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.4-a 3.3.1-05 A

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-144 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

F

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-a 3.3.1-17 H

Loss of Material Open Cycle Cooling Water 

Program

VIII.D1.3-a 3.4.1-02 C

Treated Water (Int)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

VII.H2.1-a 3.3.1-15 H

Loss of Material Closed Cycle Cooling 

Water Program

VII.H2.1-a 3.3.1-15 B

Copper Alloys Air (Ext) Loss of Material One-Time Inspection 

Program

F

Oil (Ext) Heat Transfer 

Degradation 

One-Time Inspection Program

VII.G.7-b 3.3.1-06 H

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.7-b 3.3.1-06 301, H

Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 D

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 A

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-a 3.3.1-17 396, AVII.C1.3-b 3.3.1-17 396, A

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-145 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure Boundary

Copper Alloys Raw Water (Int) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 396, A

Treated Water (Ext)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

VII.H2.1-a 3.3.1-15 H

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Heat Transfer Copper Alloys Air (Ext) Loss of Material One-Time Inspection 

Program

F

Oil (Ext) Heat Transfer 

Degradation 

One-Time Inspection Program

VII.G.7-b 3.3.1-06 H

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.7-b 3.3.1-06 301, H

Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 D

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 A

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-a 3.3.1-17 396, AVII.C1.3-b 3.3.1-17 396, A

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-146 

Application for Renewed Operating Licenses

Heat Exchangers

Heat Transfer Copper Alloys Raw Water (Int) Loss of Material - 

Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 396, A

Treated Water (Ext)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

VII.H2.1-a 3.3.1-15 H

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C1.3-a 3.3.1-17 B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, B

Heaters, Electric Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.H2.1-b 3.3.1-17 380, C

Loss of Material Open Cycle Cooling Water 

Program

VII.H2.1-b 3.3.1-17 C

Stainless Steel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 D

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-147 

Muffler Fluid 

Application for Renewed Operating Licenses

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Instrument Valve Assemblies & Tubing

Fluid Pressure Boundary

Bronze Air (Int) Cracking One-Time Inspection 

Program

J

Loss of Material One-Time Inspection 

Program

J

Loss of Material - Selective Leaching

One-Time Inspection Program

J

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 D

One-Time Inspection Program

VII.G.7-b 3.3.1-06 DVII.H2.5-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Stainless Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

F

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-148 

Motors Fluid 

Application for Renewed Operating Licenses

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.4-a 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.2-a 3.3.1-05 AVII.H2.3-a 3.3.1-05 AVII.H2.4-a 3.3.1-05 A

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

VII.H1.1-a 3.3.1-05 A

Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 D

One-Time Inspection Program

VII.H2.5-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.H2.1-a 3.3.1-15 B

Copper Alloys Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-149 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Copper Alloys Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

F

Pumps Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.G.8-a 3.3.1-22 B

Fire Protection Program VII.G.8-a 3.3.1-22 B

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Cast Iron Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 399, D

One-Time Inspection Program

J

Loss of Material - Selective Leaching

One-Time Inspection Program

J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 399, A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.3-a 3.3.1-15 B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C2.3-a 3.3.1-29 301, B

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-150 

Application for Renewed Operating Licenses

Traps (Steam) Fluid 

Pressure Boundary

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.2-a 3.3.1-05 399, A

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.H2.2-a 3.3.1-05 399, H

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.2-b 3.3.1-24 399, A

Valves & Dampers

Fluid Pressure Boundary

Brass Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Loss of Material - Selective Leaching

One-Time Inspection Program

F

Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Loss of Material Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Bronze Air (Int) Cracking One-Time Inspection 

Program

F

Loss of Material One-Time Inspection 

Program

F

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-151 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Bronze Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Loss of Material Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

F

Carbon Steel Air (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

G

One-Time Inspection Program

VII.H2.2-a 3.3.1-05 BVIII.H2.2-a 3.4.1-05 A

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

VII.H1.2-a 3.3.1-05 A

Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H2.5-a 3.3.1-07 D

One-Time Inspection Program

VII.H2.5-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-152 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.H2.1-a 3.3.1-15 D

Copper Alloys Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

F

Fire Protection Program F

Loss of Material Diesel Fuel Monitoring and 

Storage Program

F

Fire Protection Program F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

F

Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

F

One-Time Inspection Program

F

Table 3.3.2-6 Auxiliary Systems- Emergency Power System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-153 

Table 3.3.2-7 Auxiliary Systems- Fire Protection Sy

Application for Renewed Operating Licenses

stem - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Stainless Steel Oil (Int) Loss of Material One-Time Inspection 

Program

371, 372, F

Fasteners Fluid 

Pressure Boundary

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 347, A

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, I

Raw Water (Ext) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 348, D

Loss of Preload Bolting Integrity Program 324, J

Soil (Ext) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 336, 

349, D

Loss of Preload Bolting Integrity Program 324, J

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F
Page 3-154 

Application for Renewed Operating Licenses

Filters/Strainers Filtration Carbon Steel Raw Water (Ext) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 B

Raw Water (Int) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 B

Fluid Pressure Boundary

Bronze Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 370, B

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

335, G

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 338, 

378, 379, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-b 3.3.1-21 338, H

Pipe & Fittings Fluid 

Pressure Boundary

Bare Copper Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 D

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 D

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 385, A

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-a 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-a 3.3.1-21 B

Soil (Ext) Loss of Material Fire Protection Program VII.G.6-a 3.3.1-21 334, 

350, B

Table 3.3.2-7 Auxiliary Systems- Fire Protection System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-155 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Cast Iron Raw Water (Ext) Loss of Material Fire Protection Program VII.G.6-a 3.3.1-21 351, 

352, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-a 3.3.1-21 352, H

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-a 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-a 3.3.1-21 351, 

352, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-a 3.3.1-21 352, H

Copper Alloys Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

353, F

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 373, 

374, B

Stainless Steel Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-a 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-a 3.3.1-21 B

Pumps Fluid 

Pressure Boundary

Carbon Steel Air (Ext) Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 339, B

Table 3.3.2-7 Auxiliary Systems- Fire Protection System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-156 

Application for Renewed Operating Licenses

Pumps Fluid 

Pressure Boundary

Cast Iron Air (Ext) Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Ext) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 340, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-b 3.3.1-21 340, H

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 340, BLoss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-b 3.3.1-21 340, H

Sprinkler Heads Fluid 

Pressure BoundarySpray Pattern

Brass Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

346, F

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 376, 

377, H

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 375, B

Valves & Dampers

Fluid Pressure Boundary

Brass Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

F

System Monitoring Program

357, 383, F

Raw Water (Int) Buildup of Deposit Fire Protection Program F

Loss of Material Fire Protection Program 341, F

Table 3.3.2-7 Auxiliary Systems- Fire Protection System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-157 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 342, B

Cast Iron Air (Int) Loss of Material Fire Protection Program G

Atmosphere/ Weather (Ext)

Loss of Material Fire Protection Program F

System Monitoring Program

337, F

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

System Monitoring Program

384, F

Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 B

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 343, 

344, B

One-Time Inspection Program

VII.G.6-b 3.3.1-21 344, H

Soil (Ext) Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 358, 

359, B

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.G.6-b 3.3.1-21 359, 

384, H

Stainless Steel Raw Water (Int) Buildup of Deposit Fire Protection Program VII.G.6-b 3.3.1-21 H

Loss of Material Fire Protection Program VII.G.6-b 3.3.1-21 346, B

Table 3.3.2-7 Auxiliary Systems- Fire Protection System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-158 

Table 3.3.2-8 Auxiliary Systems - Fuel Oil System

Application for Renewed Operating Licenses

 - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

319, G

Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 305, B

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.H1.4-a 3.3.1-23 310, A

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 ALoss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, A

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 D

One-Time Inspection Program

VII.H1.4-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Indicators/ Recorders

Fluid Pressure Boundary

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 D

One-Time Inspection Program

VII.H1.4-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 C

Pipe & Fittings Fire Barrier Carbon Steel Air (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

307, 319, G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.H1.1-b 3.3.1-18 A
Page 3-159 

Application for Renewed Operating Licenses

Pipe & Fittings Flow 

Restriction

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 D

One-Time Inspection Program

VII.H1.4-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.H1.1-b 3.3.1-18 A

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

307, 319, G

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

VII.H1.1-a 3.3.1-05 A

Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 D

Fire Protection Program VII.G.8-a 3.3.1-22 BOne-Time Inspection Program

VII.H1.4-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.H1.1-b 3.3.1-18 A

Raw Water (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

VII.H1.1-b 3.3.1-18 A

Copper Alloys Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Table 3.3.2-8 Auxiliary Systems - Fuel Oil System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-160 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Copper Alloys Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Stainless Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

317, F

Fire Protection Program 317, FOne-Time Inspection Program

317, F

Pumps Fluid 

Pressure Boundary

Cast Iron Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-b 3.3.1-23 D

One-Time Inspection Program

VII.H1.4-b 3.3.1-23 D

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.H1.4-b 3.3.1-23 301, D

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.H1.4-b 3.3.1-23 A

Valves & Dampers

Fluid Pressure Boundary

Brass Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Loss of Material Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Table 3.3.2-8 Auxiliary Systems - Fuel Oil System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-161 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Bronze Oil (Int) Cracking Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Loss of Material Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Carbon Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

VII.H1.4-a 3.3.1-07 D

Fire Protection Program VII.G.8-a 3.3.1-22 DOne-Time Inspection Program

VII.H1.4-a 3.3.1-07 D

Plant Indoor Air (Ext)

Loss of Material Fire Protection Program VII.I.1-b 3.3.1-05 B

System Monitoring Program

VII.H1.1-b 3.3.1-18 A

Stainless Steel Oil (Int) Loss of Material Diesel Fuel Monitoring and 

Storage Program

317, F

One-Time Inspection Program

317, F

Table 3.3.2-8 Auxiliary Systems - Fuel Oil System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-162 

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and 

Application for Renewed Operating Licenses

Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Blowers Fans Compressor Vacuum

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, BVII.F2.1-a 3.3.1-05 391, BVII.F4.1-a 3.3.1-05 391, B

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, B

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 386, A

Ductwork Filtration

Fluid Pressure Boundary

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 386, BVII.F2.1-a 3.3.1-05 386, BVII.F4.1-a 3.3.1-05 386, B

Filters/Strainers Filtration

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.4-a 3.3.1-05 BVII.F2.4-a 3.3.1-05 B

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 392, D
Page 3-163 

Application for Renewed Operating Licenses

Filters/Strainers Filtration

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F2.4-a 3.3.1-05 386, B

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 386, A

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 380, A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 C

Steam (Int) Loss of Material One-Time Inspection 

Program

393, G

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-164 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure BoundaryHeat Transfer

Copper Alloys Air (Ext) Heat Transfer 

Degradation 

One-Time Inspection Program

VII.F1.2-a 3.3.1-05 387, HVII.F2.2-a 3.3.1-05 387, H

Loss of Material One-Time Inspection 

Program

VII.F1.2-a 3.3.1-05 323, BVII.F2.2-a 3.3.1-05 323, B

Gas (Ext) Loss of Material One-Time Inspection 

Program

323, 388, G

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 C

Heat Transfer Degradation 

Open Cycle Cooling Water Program

VII.C1.3-b 3.3.1-17 316, 

387, C

Loss of Material - Erosion

One-Time Inspection Program

VII.C1.3-a 3.3.1-17 394, H

Loss of Material - Selective Leaching

One-Time Inspection Program

VII.C1.3-a 3.3.1-29 301, D

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.3-a 3.3.1-17 394, C

Fluid Pressure Boundary

Copper Alloys Steam (Int) Loss of Material One-Time Inspection 

Program

393, G

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-165 

Application for Renewed Operating Licenses

Heaters, Electric Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, BVII.F2.1-a 3.3.1-05 391, B

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, B

Muffler (CRHVAC Refrig. condensing units)

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Elastomers in Flex. Connections and Seals inside/outside of Containment

Fluid Pressure Boundary

Elastomers Air (Int) Change in Mat. 

Properties 

One-Time Inspection Program

VII.F1.1-b 3.3.1-02 389, BVII.F1.4-b 3.3.1-02 389, BVII.F2.1-b 3.3.1-02 389, BVII.F2.4-b 3.3.1-02 389, BVII.F3.1-b 3.3.1-02 389, BVII.F3.4-b 3.3.1-02 389, BVII.F4.1-b 3.3.1-02 389, B

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-166 

Application for Renewed Operating Licenses

Elastomers in Flex. Connections and Seals inside/outside of Containment

Fluid Pressure Boundary

Elastomers Air (Int) Cracking One-Time Inspection 

Program

VII.F1.1-b 3.3.1-02 389, BVII.F1.4-b 3.3.1-02 389, BVII.F2.1-b 3.3.1-02 389, BVII.F2.4-b 3.3.1-02 389, BVII.F3.1-b 3.3.1-02 389, BVII.F3.4-b 3.3.1-02 389, BVII.F4.1-b 3.3.1-02 389, B

Containment Air (Ext)

Change in Mat. Properties 

System Monitoring Program

VII.F3.1-b 3.3.1-02 389, AVII.F3.4-b 3.3.1-02 389, A

Cracking System Monitoring 

Program

VII.F3.1-b 3.3.1-02 389, AVII.F3.4-b 3.3.1-02 389, A

Plant Indoor Air (Ext)

Change in Mat. Properties 

System Monitoring Program

VII.F1.1-b 3.3.1-02 389, AVII.F1.4-b 3.3.1-02 389, AVII.F2.1-b 3.3.1-02 389, AVII.F2.4-b 3.3.1-02 389, A

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-167 

Application for Renewed Operating Licenses

Elastomers in Flex. Connections and Seals inside/outside of Containment

Fluid Pressure Boundary

Elastomers Plant Indoor Air 

(Ext)

Cracking System Monitoring 

Program

VII.F1.1-b 3.3.1-02 389, AVII.F1.4-b 3.3.1-02 389, AVII.F2.1-b 3.3.1-02 389, AVII.F2.4-b 3.3.1-02 389, A

CRHVAC Duct Silencer

Fluid Pressure Boundary

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 D

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

HVAC Dampers Fluid 

Pressure Boundary

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, BVII.F2.1-a 3.3.1-05 391, BVII.F4.1-a 3.3.1-05 391, B

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-168 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 DVII.F2.1-a 3.3.1-05 DVII.F4.1-a 3.3.1-05 D

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

395, G

Steam (Int) Loss of Material One-Time Inspection 

Program

393, G

Copper Alloys Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.2-a 3.3.1-05 DVII.F2.2-a 3.3.1-05 DVII.F4.2-a 3.3.1-05 D

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

317, F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

308, F

Containment Isolation

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.C.1-a 3.3.1-05 A

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-169 

Application for Renewed Operating Licenses

Traps (Steam) Fluid 

Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 390, A

Steam (Int) Loss of Material One-Time Inspection 

Program

390, 393, G

Raw Water (Int) Loss of Material One-Time Inspection 

Program

390, 393, G

Valves & Dampers

Fluid Pressure Boundary

Bronze Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.2-a 3.3.1-05 DVII.F2.2-a 3.3.1-05 DVII.F4.2-a 3.3.1-05 D

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

317, F

Steam (Int) Loss of Material One-Time Inspection 

Program

393, G

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 DVII.F2.1-a 3.3.1-05 DVII.F4.1-a 3.3.1-05 D

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-170 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

395, G

Steam Loss of Material One-Time Inspection 

Program

G

System Monitoring Program

G

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.F1.1-a 3.3.1-05 391, BVII.F2.1-a 3.3.1-05 391, BVII.F4.1-a 3.3.1-05 391, B

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 386, A

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

308, F

Raw Water (Int) Loss of Material One-Time Inspection 

Program

308, F

Table 3.3.2-9 Auxiliary Systems- Heating, Ventilation, and Air Conditioning System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-171 

Table 3.3.2-10 Auxiliary Systems - Miscellaneous Gas 

Application for Renewed Operating Licenses

System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Filters/Strainers Fluid 

Pressure Boundary

Galvanized Air (Int) Loss of Material One-Time Inspection 

Program

VII.D.5-a 3.3.1-19 E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Misc. Mechanical (fasteners, manifold, monitor)

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program VII.D.3-a 3.3.1-19 324, ELoss of Material Bolting Integrity Program VII.D.1-a 3.3.1-19 E

VII.D.2-a 3.3.1-19 EVII.D.3-a 3.3.1-19 EVII.D.5-a 3.3.1-19 EVII.D.6-a 3.3.1-19 E

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Copper Alloys Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program 324, FLoss of Material Bolting Integrity Program F
Page 3-172 

Misc. Mechanical 

Application for Renewed Operating Licenses

(fasteners, manifold, monitor)

Fluid Pressure Boundary

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

VII.C1.1-b 3.3.1-18 A

Copper Alloys Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Tanks Fluid 

Pressure Boundary

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-10 Auxiliary Systems - Miscellaneous Gas System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-173 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Brass Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Bronze Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

F

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Containment Air (Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Low-Alloy Steel Containment Air 

(Ext)Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-10 Auxiliary Systems - Miscellaneous Gas System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-174 

Table 3.3.2-11 Auxiliary Systems- Radwaste Syst

Application for Renewed Operating Licenses

em - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

331, J

Atmosphere / Weather (Ext)

Loss of Material System Monitoring 

Program

VII.H1.4-b 3.3.1-23 331, E

Flood ProtectionFluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C3.1-a 3.3.1-29 331, E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Demineralizer Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Filters/Strainers Fluid 

Pressure Boundary

Stainless Steel Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.6-a 3.3.1-17 331, E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E
Page 3-175 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure Boundary

Bronze Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

308, F

Treated Water (Ext)

Loss of Material One-Time Inspection 

Program

VII.F2.2-a 3.3.1-05 331, 

368, 381, E

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

331, 368, J

One-Time Inspection Program

VII.F2.2-a 3.3.1-05 331, 

368, 381, E

Carbon Steel Air (Ext) Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-03 A

Steam (Int) Loss of Material One-Time Inspection 

Program

331, J

Copper Alloys Treated Water 

(Ext)

Loss of Material One-Time Inspection 

Program

VII.F2.2-a 3.3.1-05 331, 

381, E

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

331, 368, J

One-Time Inspection Program

VII.F2.2-a 3.3.1-05 331, 

381, E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Fasteners Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 A

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Table 3.3.2-11 Auxiliary Systems- Radwaste System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-176 

Application for Renewed Operating Licenses

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 B

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, A

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Pipe & Fittings Flood 

ProtectionFluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Fluid Pressure Boundary

Carbon Steel Gas (Int) Loss of Material One-Time Inspection 

Program

331, 381, G

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C3.1-a 3.3.1-29 331, E

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 399, A

System Monitoring Program

VII.I.1-b 3.3.1-05 399, A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

331, 381, F

Table 3.3.2-11 Auxiliary Systems- Radwaste System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-177 

Application for Renewed Operating Licenses

Pumps Flood 

ProtectionFluid Pressure Boundary

Bronze Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

331, G

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.F2.2-a 3.3.1-05 331, 

381, E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Ext) Loss of Material One-Time Inspection 

Program

331, I

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.5-a 3.3.1-17 331, E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Valves & Dampers

Flood ProtectionFluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381,E 

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

VII.F2.1-a 3.3.1-05 331, E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 399, A

System Monitoring Program

VII.I.1-b 3.3.1-05 399, A

Table 3.3.2-11 Auxiliary Systems- Radwaste System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-178 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.F2.1-a 3.3.1-05 331, 

369, E

Gas (Int) Loss of Material One-Time Inspection 

Program

VII.F2.1-a 3.3.1-05 331, E

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 331, E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 331, 

381, E

Table 3.3.2-11 Auxiliary Systems- Radwaste System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-179 

Table 3.3.2-12 Auxiliary Systems- Service Water Sy

Application for Renewed Operating Licenses

stem - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulator Fluid 

Pressure Boundary

Stainless Steel Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Fasteners in Containment

Fluid Pressure Boundary

Low-Alloy Steel Containment Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 A

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Loss of Preload Bolting Integrity Program 324, F

Fasteners Not in Containment

Fluid Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.1-b 3.3.1-05 A, 300

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Loss of Preload Bolting Integrity Program 324, F

Filters/Strainers Filtration Stainless Steel Raw Water (Ext) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.6-a 3.3.1-17 A

Fluid Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.6-a 3.3.1-17 A, 399

Loss of Material One-Time Inspection 

Program

VII.C1.5-a 3.3.1-17 D, 301

Open Cycle Cooling Water Program

VII.C1.6-a 3.3.1-17 A, 399

Stainless Steel Raw Water (Ext) Loss of Material Open Cycle Cooling Water 

Program

VII.C1.6-a 3.3.1-17 A
Page 3-180 

Application for Renewed Operating Licenses

Flex Connections & Instrument Valve Assemblies

Fluid Pressure Boundary

Stainless Steel Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.4-a 3.3.1-17 C

Heat Exchanger Fluid 

Pressure Boundary

Carbon Steel Air/Gas (Int) Loss of Material One-Time Inspection 

Program

G

Oil (Int) Loss of Material One-Time Inspection 

Program

G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.I.3-a 3.3.1-17 E

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-181 

Application for Renewed Operating Licenses

Pipe & Fittings Flow 

Restriction

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 AVII.C1.2-a 3.3.1-17 AVII.C3.1-a 3.3.1-29 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A, 302VII.C3.1-a 3.3.1-29 A, 302

Fluid Pressure Boundary

Bronze Raw Water (Int Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 C

One-Time Inspection Program

VII.C1.1-a 3.3.1-17 D

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

VII.C1.1-b 3.3.1-18 A

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-182 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 AVII.C1.2-a 3.3.1-17 AVII.C3.1-a 3.3.1-29 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A, 302VII.C3.1-a 3.3.1-29 A, 302

Loss of Material - Erosion

Open Cycle Cooling Water Program

VII.C1.1-a 3.3.1-17 A, 302VII.C3.1-a 3.3.1-29 A, 302

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A, 399

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A

Loss of Material One-Time Inspection 

Program

VII.C1.6-a 3.3.1-17 B, 399

Open Cycle Cooling Water Program

VII.C1.6-a 3.3.1-17 A, 399

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-183 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Copper Alloys Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A

Stainless Steel Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A, 302

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 A

Loss of Material - Erosion

Open Cycle Cooling Water Program

VII.C1.1-a 3.3.1-17 A, 

Rubber Plant Indoor Air 

(Ext)

Cracking System Monitoring 

Program

F

Pumps Fluid 

Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A, 399

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.5-a 3.3.1-17 A, 399VII.C3.3-a 3.3.1-17 A, 399

Loss of Material One-Time Inspection 

Program

VII.C1.5-a 3.3.1-29 C, 301VII.C3.3-a 3.3.1-17 C, 301

Open Cycle Cooling Water Program

VII.C1.5-a 3.3.1-17 A

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-184 

Application for Renewed Operating Licenses

Traveling Screen spray Nozzles

Spray Pattern Aluminum 

Bronze

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.3-b 3.3.1-17 C

Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-29 D, 301

Open Cycle Cooling Water Program

VII.C1.1-a 3.3.1-17 C, 302

Valves & Dampers

Fluid Pressure Boundary

Brass Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Bronze Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-185 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.1-a 3.3.1-17 CVII.C3.2-a 3.3.1-29 C

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A, 302VII.C3.2-a 3.3.1-29 A, 302

Cast Iron Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A, 399

System Monitoring Program

VII.I.1-b 3.3.1-05 A, 399

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A, 399

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A, 399

Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A, 399

Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 B, 301, 

399

Open Cycle Cooling Water Program

VII.C1.2-a 3.3.1-17 A, 302, 

399

Loss of Material - Erosion

Open Cycle Cooling Water Program

VII.C1.2-a 3.3.1-17 A, 302, 

399

Copper Alloys Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-186 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Stainless Steel Raw Water (Int) Buildup of Deposit Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Loss of Material Open Cycle Cooling Water 

Program

VII.C1.2-a 3.3.1-17 A

Table 3.3.2-12 Auxiliary Systems- Service Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-187 

Table 3.3.2-13 Auxiliary Systems - Shield Cooling 

Application for Renewed Operating Licenses

System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 C

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.4-a 3.3.1-15 327, B

Fasteners Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, FLoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Plant Indoor Air (Ext)

Loss of Preload Bolting Integrity Program 324, FLoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.4-a 3.3.1-15 327, D
Page 3-188 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.1-a 3.3.1-15 327, B

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 327, B

Table 3.3.2-13 Auxiliary Systems - Shield Cooling System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-189 

CTable 3.3.2-14 Auxiliary Systems- Spent Fuel Pool Cool

Application for Renewed Operating Licenses

ing System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 329, E

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

Demineralizers Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 329, E

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

Filters/Strainers Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 329, E

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, CLoss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 324, C

Boric Acid Corrosion Program

VII.A3.1-a 3.3.1-14 AVII.A3.2-c 3.3.1-14 AVII.A3.3-c 3.3.1-14 AVII.A3.4-b 3.3.1-14 AVII.A3.5-b 3.3.1-14 AVII.A3.6-a 3.3.1-14 A

Stainless Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program 324, F

Containment Air (Ext)

Loss of Preload Bolting Integrity Program 324, F
Page 3-190 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 329, E

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

Pumps Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 329, E

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

SFP Heat Exchanger Shell and Channel Head

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.A3.4-b 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.A3.4-a 3.3.1-15 320, B

SFP Heat Exchanger Shell and Channel Head

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 318, 

322, 329, D

Water Chemistry Program VII.C2.2-a 3.3.1-15 329, E

SFP Heat Exchanger Tube and Tubesheet

Fluid Pressure Boundary

Carbon Steel Treated Water 

(Ext)

Loss of Material Closed Cycle Cooling 

Water Program

VII.A3.4-a 3.3.1-15 328, D

Table 3.3.2-14 Auxiliary Systems- Spent Fuel Pool Cooling System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-191 

Application for Renewed Operating Licenses

SFP Heat Exchanger Tube and Tubesheet

Fluid Pressure BoundaryHeat Transfer

Stainless Steel Treated Water 

(Ext)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

328, J

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 323, 

328, D

Treated Water (Int)

Heat Transfer Degradation 

Closed Cycle Cooling Water Program

328, J

Water Chemistry Program 328, J

Loss of Material Closed Cycle Cooling 

Water Program

VII.C2.2-a 3.3.1-15 323, 

328, D

Water Chemistry Program VII.C2.2-a 3.3.1-15 E

Valves & Dampers

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 E

Water Chemistry Program VII.C2.2-a 3.3.1-15 E

Table 3.3.2-14 Auxiliary Systems- Spent Fuel Pool Cooling System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-192 

Table 3.3.2-15 Auxiliary Systems - Waste Gas Syst

Application for Renewed Operating Licenses

em - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulator Fluid 

Pressure Boundary

Carbon Steel Gas (Int) Loss of Material One-Time Inspection 

Program

332, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C3.1-a 3.3.1-29 332, E

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Containment Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 A

Boric Acid Corrosion Program

VII.I.1-a 3.3.1-14 A

Plant Indoor Air (Ext)

Loss of Material Bolting Integrity Program VII.I.2-a 3.3.1-24 ALoss of Preload Bolting Integrity Program VII.I.2-a 3.3.1-24 324, A

Filter/Strainer Fluid 

Pressure Boundary

Carbon Steel Gas (Int) Loss of Material One-Time Inspection 

Program

332, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A
Page 3-193 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Gas (Int) Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C3.1-a 3.3.1-29 332, E

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Gas (Int) Loss of Material One-Time Inspection 

Program

332, G

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.I.1-a 3.3.1-14 A

System Monitoring Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 332, E

Table 3.3.2-15 Auxiliary Systems - Waste Gas System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-194 

Table 3.3.2-16 Auxiliary Systems - Domestic Water 

Application for Renewed Operating Licenses

System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulator Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Cast Iron Air (Int) Loss of Material One-Time Inspection 

Program

J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

J

Stainless Steel Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Fasteners Fluid 

Pressure Boundary

Low-Alloy Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VII.I.1-b 3.3.1-05 A

Heat Exchanger Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

J

Steam (Int) Loss of Material One-Time Inspection 

Program

J
Page 3-195 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Copper Alloy Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Pumps Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.5-a 3.3.1-17 E

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 E

Copper Alloy Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 E

Table 3.3.2-16 Auxiliary Systems - Domestic Water System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-196 

Table 3.3.2-17 Auxiliary Systems - Chemical Addition 

Application for Renewed Operating Licenses

System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulator Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2-4a 3.3.1-15 E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 E

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2-4A 3.3.1-15 E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 E

Pumps Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2-4A 3.3.1-15 E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 E
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Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VII.I.1-b 3.3.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2-4a 3.3.1-15 E

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-15 E

Table 3.3.2-17 Auxiliary Systems - Chemical Addition System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
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Notes for Tables 3.3.2-1 through 3.3.2-17

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. 

AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. 

AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, 

and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, and 

aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different AMP is 

credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific notes:

300 Plant Indoor Air includes Indoor Uncontrolled Air and Condensation

301 The One-Time Inspection Program at Palisades includes the Selective Leaching of 

Materials Program of NUREG-1801.

302 Erosion has been identified through OE review as a plant-specific aging mechanism.

303 Not used

304 Not used

305 The Diesel Fuel Monitoring and Storage Program includes internal inspection.

306 Biofouling in fuel oil systems only occurs at fuel oil storage tanks, during initial fuel oil 

delivery. Therefore, biofouling is not a potential aging mechanism for this component.

307 These AERMs are to be inspected during fuel oil tank internal inspections.

308 This component/material group is not included in GALL for this system.
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309 Not used

310 The System Monitoring Program at Palisades includes the requirements (for external tank 

inspections) of the Above ground Carbon Steel Tanks Program of NUREG-1801.

311 Not used

312 Not used

313 For CCW heat exchanger, the tubes are Admiralty Brass and tubesheets are Carbon Steels 

with Aluminum Bronze overlay for raw water side.

314 Not used

315 For the purpose of this GALL item, the material of CCW HX tubes (copper-nickel and 

aluminum brass in GALL) is considered to be equivalent to Admiralty Brass or Aluminum 

Bronze.

316 For the purpose of this GALL item, the aging effect of Buildup of deposit/Biofouling is 

considered to be equivalent to Heat Transfer Degradation/Fouling.

317 Copper alloys for this component type is not addressed in GALL.

318 Use GALL line item of Valves in VII.C2 for this evaluation.

319 Air space of the tank internal is not addressed in GALL.

320 For carbon steels in treated water, Galvanic Corrosion and/or MIC are conservatively 

included as aging mechanisms for Loss of Material.

321 Not used

322 For stainless steels or copper alloys, MIC is conservatively included as aging mechanisms 

for Loss of Material.

323 Fretting is included as a potential external aging effect for stainless steel or copper alloys 

tubes of heat exchangers.

324 Loss of preload is included here in response to recent NRC RAIs on non-primary system, 

high temperature bolting that may experience loss of preload. The Palisades Bolting 

Integrity Program manages potential bolting AERMs and event driven degradation. GALL 

reconciliation is based on Loss of Material.

325 Use copper alloys of this GALL line of CCW heat exchanger tube for this evaluation.

326 Not used

327 Shield Cooling System (SCS) is considered to be in the category of Closed-Cycle Cooling 

that is addressed in NUREG-1801(GALL), Chapter VII.C2.
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328 The tubes and tubesheets of SFP heat exchangers are not evaluated in 

NUREG-1801(GALL) VII.A3.

329 The material of this SFP component addressed in NUREG-1801 (GALL) is carbon steel 

instead of stainless steel.

330 This component does not have temperatures > 140°F. Therefore, cracking due to stress 

corrosion cracking is not a potential aging mechanism.

331 The Radwaste System is not addressed in NUREG-1801.

332 The Waste Gas System is not addressed in NUREG-1801.

333 Not used

334 This component is buried in soil and exposed to Raw water.

335 Cast Iron is not a material in VII.I.1-b.

336 Component is bolting in Soil. Soil Environment is assumed to be raw water.

337 Material is cast iron. It does not match VII.I.1-b.

338 Component matches GALL. Palisades also identifies Selective Leaching.

339 Palisades matches GALL except Palisades does not identify galvanic corrosion for the 

Jockey Pump.

340 Palisades matches GALL except Palisades identifies Selective Leaching as an additional 

AERM for Fire Pumps.

341 GALL does not identify Brass as a material in Section VII.G.6-b.

342 Palisades matches GALL except Palisades does not have galvanic corrosion in carbon steel 

valves.

343 Palisades matches GALL except Palisades does not have galvanic corrosion in cast iron 

valves.

344 PAL matches GALL except (see Note 343). In addition, PAL Identifies Selective Leaching of 

cast iron valves.

345 Not used

346 Brass is not a material in GALL Section VII.I.1-a. But the Palisades Boric Acid Corrosion 

Program is credited.

347 Palisades matches GALL for general corrosion. PAL also identifies crevice & pitting.

348 Submerged bolting is not identified in GALL Section VII.G.6-b. PAL identifies general, 

crevice, pitting& MIC.
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349 Buried bolting is not identified in GALL Section VII.G.6-b. PAL identifies general, crevice, 

pitting & MIC.

350 Palisades matches GALL for general, crevice, pitting, MIC. However Palisades does not 

have galvanic or biofouling.

351 Palisades matches GALL for general, crevice, pitting & MIC. However, Palisades does not 

identify galvanic or biofouling.

352 GALL does not identify Selective Leaching of cast iron. Palisades identifies Selective 

Leaching of cast iron.

353 GALL does not identify brass in Section VII.I.1-a. Palisades identifies BAW of brass in 

borated water.

354 Not used

355 Not used

356 Not used

357 GALL does not identify brass as a material in Section VII.I.1-b.

358 GALL matches Palisades for general, crevice, pitting and MIC. Palisades does not have 

galvanic or biofouling on buried pipe.

359 Palisades identifies Selective leaching of cast iron. GALL does not identify selective 

leaching.

360 Not used

361 Not used

362 Not used

363 Not used

364 Not used

365 Not used

366 The carbon steel piping is managed for MIC using the Closed Cycle Cooling Water 

Program.

367 Piping, pumps, flow elements, valves and restricting orifices are managed for crevice 

corrosion and pitting corrosion using the ASME Section XI, IWB, IWC, IWD, IWF Inservice 

Inspection Program; the Water Chemistry Program; and/or, the One-Time Inspection 

Program.

368 The system is Component Cooling Water and all AERMs are managed using the Closed 

Cycle Cooling Water Program and/or the One-Time Inspection Program.
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369 Boric acid has the potential to get into floor drains; therefore, boric acid wastage is a 

potential internal aging mechanism that is managed by the One-Time Inspection Program.

370 This component is not connected to material higher in the Galvanic Series.

371 General & Galvanic Corrosion are not applicable to this Stainless Steel Tank.

372 GALL identified crevice, general, galvanic & pitting corrosion. Palisades identified crevice & 

pitting corrosion. See note 371.

373 General corrosion is not applicable to copper tubing.

374 GALL & Palisades identified crevice, pitting & galvanic corrosion in oil with water 

environment.

375 This component is a Palisades wet pipe sprinkler head made from brass. GALL identifies 

bronze not brass.

376 This component is a Palisades wet pipe sprinkler head made from brass. GALL identifies 

bronze not Brass.

377 PAL identifies corrosion product buildup due to bio-fouling. GALL identifies loss of material 

due to bio-fouling.

378 Flow in this component is zero; therefore, Loss of Material due to erosion is not applicable.

379 This component is not connected to a material higher in the Galvanic Series.

380 Palisades identifies corrosion product buildup due to bio-fouling. GALL identifies Loss of 

material due to bio-fouling.

381 For Radwaste, “Treated Water” is not controlled by Water Chemistry, and can be considered 

as “Warm, Moist Air” for GALL reconciliation.

382 Not used

383 This valve (MV-FP168) is installed on the Jockey Pump Discharge Piping. It is subject to 

sweating.

384 In addition to general corrosion, valves are subject to sweating. They are on the Jockey 

Pump discharge piping.

385 GALL identifies general corrosion. Palisades identifies general, crevice, pitting & galvanic 

for Jockey Pump pipe.

386 Galvanized steels are considered equivalent to carbon steels in terms of AERM evaluations, 

except for external environment of indoor air where General Corrosion is not an applicable 

aging mechanism for galvanized steels.
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387 Heat Transfer Degradation is not evaluated in GALL VII.F1 through VII.F4 for HVAC 

heating/cooling coils.

388 The AERM evaluation in the environment of Freon is not included in GALL.

389 The aging effect of Hardening and Loss of Strength/Elastomer Degradation evaluated in 

GALL is considered to be equivalent to Cracking/Thermal Exposure and Change of Material 

Properties/Thermal Exposure.

390 Cast Irons are considered equivalent to carbon steels in terms of AERM evaluations, except 

for Selective Leaching which is only applicable for Cast Irons.

391 This line evaluates AERM of the equipment frames and/or housing, which is addressed in 

GALL lines of DUCT, VII.F1.1-a, VII.F2.1-a, VII.F3.1-a or VII.F4.1-a.

392 The AERM in the environment of Oil is not addressed in GALL for HVAC components. Use 

GALL line of Fire Protection in VII.G.7 for this evaluation.

393 The AERM in the environment of Steam is not addressed in GALL Chapter VII components.

394 Erosion is conservatively included as an applicable aging effect for heat exchanger tubes in 

service water and steam environments.

395 The AERM in the environment of HVAC condensation as raw water is not addressed in 

GALL Chapter VII components.

396 This is a raw water heat exchanger. Fouling is an AERM needing management. Standard 

note H applies to this roll up line item.

397 Not used

398 Not used

399 At Palisades, cast iron aging mechanisms are evaluated as carbon steel except for selective 

leaching.
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3.4 Aging Management of Steam and Power Conversion System

3.4.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.3.4, Steam and Power Conversion Systems, as being subject to aging 

management review. The systems, or portions of systems, which are addressed in this 

section, are described in the indicated sections.

• Condensate and Condenser System (Section 2.3.4.1)

• Demineralized Makeup Water System (Section 2.3.4.2)

• Feedwater System (Section 2.3.4.3)

• Heater Extraction and Drain System (Section 2.3.4.4)

• Main Air Ejection and Gland Seal System (Section 2.3.4.5)

• Main Steam System (Section 2.3.4.6)

• Turbine Generator and Crane System (Section 2.3.4.7)

Table 3.4.1, Summary of Aging Management Evaluations in Chapter VII of NUREG-1801 for 

Steam and Power Conversion Systems, provides the summary of the programs evaluated in 

NUREG-1801 for the Steam and Power Conversion Systems component groups that are 

relied on for license renewal. 

This table uses the format described in Figure 3.0-1 above. Note that this table only includes 

those component groups that are applicable to a PWR.

3.4.2 Results

The following tables summarize the results of the aging management review for systems in 

the Steam and Power Conversion Systems group: 

Table 3.4.2-1, Steam and Power Conversion Systems - Condensate and Condenser System 

- Summary of Aging Management Evaluation

Table 3.4.2-2, Steam and Power Conversion Systems - Demineralized Makeup Water 

System - Summary of Aging Management Evaluation

Table 3.4.2-3, Steam and Power Conversion Systems - Feedwater System - Summary of 

Aging Management Evaluation

Table 3.4.2-4, Steam and Power Conversion Systems - Heater Extraction and Drain System 

- Summary of Aging Management Evaluation

Table 3.4.2-5, Steam and Power Conversion Systems - Main Air Ejection and Gland Seal 

System - Summary of Aging Management Evaluation
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Table 3.4.2-6, Steam and Power Conversion Systems - Main Steam System - Summary of 

Aging Management Evaluation

Table 3.4.2-7, Steam and Power Conversion Systems - Turbine Generator and Crane 

System - Summary of Aging Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for each of the 

above systems in the following subsections of Section 3.4.2.1, Materials, Environment, 

Aging Effects Requiring Management and Aging Management Programs:

Section 3.4.2.1.1, Condensate and Condenser System

Section 3.4.2.1.2, Demineralized Makeup Water System

Section 3.4.2.1.3, Feedwater System

Section 3.4.2.1.4, Heater Extraction and Drain System

Section 3.4.2.1.5, Main Air Ejection and Gland Seal System

Section 3.4.2.1.6, Main Steam System

Section 3.4.2.1.7, Turbine Generator and Crane System

3.4.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.4.2.1.1 Condensate and Condenser System

Materials

The materials of construction for the Condensate and Condenser System 

components are:

• Carbon Steel

• Cast Iron

• Stainless Steel

Environment

The Condensate and Condenser System components are exposed to the 

following environments:

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Soil (Ext)
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• Steam (Int)

• Steam (Ext)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Condensate and Condenser 

System, require management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Condensate and Condenser System components:

• Bolting Integrity Program

• Buried Services Corrosion Monitoring Program

• Flow Accelerated Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.2 Demineralized Makeup Water System

Materials

The materials of construction for the Demineralized Makeup Water System 

components are:

• Carbon Steel

• Cast Austenitic SS

• Stainless Steel

Environment

The Demineralized Makeup Water System components are exposed to the 

following environments:

• Air (Int)

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)
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• Soil (Ext)

• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Demineralized Makeup Water 

System, require management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Demineralized Makeup Water System components:

• Bolting Integrity Program

• Buried Services Corrosion Monitoring Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.3 Feedwater System

Materials

The materials of construction for the Feedwater System components are:

• Carbon Steel

• Cast Austenitic SS

• Cast Iron

• Stainless Steel

Environment

The Feedwater System components are exposed to the following 

environments:

• Atmosphere/Weather (Ext)

• Air (Int)

• Containment Air (Ext)

• Oil (Int)
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• Plant Indoor Air (Ext)

• Raw Water (Int)

• Soil (Ext)

• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Feedwater System, require 

management:

• Cracking 

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Feedwater System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Buried Services Corrosion Monitoring Program

• Flow Accelerated Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.4 Heater Extraction and Drain System

Materials

The materials of construction for the Heater Extraction and Drain System 

components are:

• Carbon Steel

• Cast Iron

• Stainless Steel
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Environment

The Heater Extraction and Drain System components are exposed to the 

following environments:

• Plant Indoor Air (Ext)

• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Heater Extraction and Drain 

System, require management:

• Cracking 

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Heater Extraction and Drain System components:

• Bolting Integrity Program

• Flow Accelerated Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.5 Main Air Ejection and Gland Seal System

Materials

The materials of construction for the Main Air Ejection and Gland Seal System 

components are:

• Carbon Steel

• Cast Iron

Environment

The Main Air Ejection and Gland Seal System components are exposed to the 

following environments:

• Air (Int)
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• Plant Indoor Air (Ext)

• Raw Water (Int)

• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Main Air Ejection and Gland 

Seal System, require management:

• Loss of Material 

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Main Air Ejection and Gland Seal System components:

• Bolting Integrity Program

• Flow Accelerated Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.6 Main Steam System

Materials

The materials of construction for the Main Steam System components are:

• Carbon Steel

• Copper Alloys

• Stainless Steel

Environment

The Main Steam System components are exposed to the following 

environments:

• Containment Air (Ext)

• Plant Indoor Air (Ext)

• Steam (Int)

• Treated Water (Int)
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Aging Effects Requiring Management

The following aging effects, associated with the Main Steam System, require 

management:

• Cracking

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Main Steam System components:

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Flow Accelerated Corrosion Program

• One-Time Inspection Program

• System Monitoring Program

• Water Chemistry Program

3.4.2.1.7 Turbine Generator System

Materials

The materials of construction for the Turbine Generator and Crane System 

components are:

• Carbon Steel

• Cast Iron

• Stainless Steel

Environment

The Turbine Generator and Crane System components are exposed to the 

following environments:

• Air/Gas (Int)

• Oil (Int)

• Plant Indoor Air (Ext)

• Raw Water (Int)
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• Steam (Int)

• Treated Water (Int)

Aging Effects Requiring Management

The following aging effects, associated with the Turbine Generator and Crane 

System, require management:

• Loss of Material

• Loss of Preload

Aging Management Programs

The following aging management programs manage the aging effects for the 

Turbine Generator and Crane System components:

• One-Time Inspection Program

• System Monitoring Program

• Bolting Integrity Program

3.4.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 provides the basis for identifying those programs that warrant 

further evaluation by the reviewer in the license renewal application. For the 

Steam and Power Conversion Systems, those programs are addressed in the 

following sections.

3.4.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be 

evaluated in accordance with 10 CFR 54.21(c). The evaluation of this TLAA is 

addressed in Section 4.3.

3.4.2.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion

NUREG-1800 states that the management of loss of material due to general, 

pitting, and crevice corrosion should be evaluated further for carbon steel 

piping and fittings, valve bodies and bonnets, pump casings, pump suction 

and discharge lines, tanks, tubesheets, channel heads, and shells except for 

main steam system components and for loss of material due to pitting and 

crevice corrosion for stainless steel tanks and heat exchanger/cooler tubes. 

The water chemistry program relies on monitoring and control of water 

chemistry based on the EPRI guidelines of TR-102134 for secondary water 
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chemistry in PWRs to manage the effects of loss of material due to general, 

pitting, or crevice corrosion. However, corrosion may occur at locations of 

stagnant flow conditions. Therefore, the effectiveness of the chemistry control 

program should be verified to ensure that corrosion is not occurring. 

NUREG-1801 recommends further evaluation of programs to manage loss of 

material due to general, pitting, and crevice corrosion to verify the 

effectiveness of the water chemistry program. A one-time inspection of select 

components and susceptible locations is an acceptable method to ensure that 

corrosion is not occurring and that the component’s intended function will be 

maintained during the period of extended operation.

At Palisades, under the One-Time Inspection Program, a representative 

sample of the component population will be chosen for inspection. The focus, 

when practical, will be placed on bounding or lead components. Factors that 

will be considered when choosing components for inspection are time in 

service, severity of operating conditions, and operating experience. The 

examination techniques will be visual, volumetric, or other appropriately 

established NDE methods that are capable of management of the aging effect 

loss of material due to galvanic and general corrosion, MIC, pitting and crevice 

corrosion, and selective leaching.

3.4.2.2.3 Loss of Material due to General, Pitting, and Crevice Corrosion, 

Microbiologically Influenced Corrosion, and Biofouling

NUREG-1800 states that loss of material due to general corrosion, pitting and 

crevice corrosion, microbiologically influenced corrosion (MIC), and biofouling 

could occur in carbon steel piping and fittings for untreated water from the 

backup water supply in the PWR auxiliary feedwater system. NUREG-1801 

recommends further evaluation to ensure that these aging effects are 

adequately managed.

At Palisades, the portion of the lines from the Service Water System (SWS) to 

the auxiliary feedwater system is addressed as part of the SWS system (item 

3.3.1-17 of Table 3.3.1 of NUREG-1800). The aging effect of loss of material is 

managed by Open Cycle Cooling Water Program. The program is consistent 

with the NUREG-1801, Section XI.M20, “Open-Cycle Cooling Water System”, 

and aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions.

The portion of the lines from the fire protection water lines to the auxiliary 

feedwater system is addressed as part of the Fire Protection system (item 
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3.3.1-21 of Table 3.3.1 of NUREG-1800). The aging effect of loss of material is 

managed by the Fire Protection Program . The program is consistent with, but 

includes exceptions to, NUREG-1801, Section XI.M27, “Fire Water System.”

3.4.2.2.4 General Corrosion

NUREG-1800 states that loss of material due to general corrosion could occur 

on the external surfaces of all carbon steel structures and components, 

including closure boltings, exposed to operating temperature less than 212°F. 

NUREG-1801 recommends further evaluation to ensure that this aging effect is 

adequately managed.

At Palisades, the external aging effect of general corrosion is managed by the 

System Monitoring Program . The external surfaces of various component 

types (e.g., pump casings, valve bodies, piping, etc.) are visually inspected for 

leakage and evidence of material degradation, such as loss of material due to 

corrosion. The external aging effect of general corrosion of closure boltings is 

managed by the Bolting Integrity Program. 

The attributes of System Monitoring Program are consistent with the criteria 

described in the Branch Technical Position RLSB-1 which is included in 

Appendix A of NUREG-1800, and this aging effect will be managed such that 

the subject SSCs will continue to perform their intended functions.

The Bolting Integrity Program is consistent with the NRC GALL Report, Section 

XI.M18, “Bolting Integrity.” 

3.4.2.2.5 Loss of Material due to General, Pitting, Crevice, and Microbiologically 

Influenced Corrosion

3.4.2.2.5.1 Loss of Material due to General, Pitting, Crevice, and Microbiologically 

Influenced Corrosion in AFW Pump Bearing Oil Cooler

NUREG-1800 states that loss of material due to general corrosion (carbon 

steel only), pitting and crevice corrosion, and MIC could occur in stainless 

steel and carbon steel shells, tubes, and tubesheets within the bearing oil 

coolers (for steam turbine pumps) in the PWR auxiliary feedwater system. 

NUREG-1801 recommends further evaluation to ensure that these aging 

effects are adequately managed.

This paragraph of NUREG -1800 is not applicable to Palisades. The bearing 

oil coolers for the AFW pump turbine, addressed in NUREG-1801 VIII.G.5-a 

through VIII.G.5-d, are not applicable for Palisades.
Page 3-215 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

3.4.2.2.5.2 Loss of Material due to General, Pitting, Crevice, and Microbiologically 

Influenced Corrosion in Underground Condensate Piping, Tanks, and 

Fittings

NUREG-1800 states that loss of material due to general corrosion, pitting 

and crevice corrosion, and MIC could occur in underground piping and 

fittings and emergency condensate storage tank in the auxiliary feedwater 

system and the underground condensate storage tank in the condensate 

system. The buried piping and tanks inspection program relies on industry 

practice, frequency of pipe excavation, and operating experience to 

manage the effects of loss of material from general corrosion, pitting and 

crevice corrosion, and MIC. The effectiveness of the buried piping and 

tanks inspection program should be verified to evaluate an applicant's 

inspection frequency and operating experience with buried components, 

ensuring that loss of material is not occurring.

Palisades does not have buried storage tanks. Loss of material in buried 

carbon steel and stainless steel piping is managed by the Buried Services 

Corrosion Monitoring Program . The program is consistent with 

NUREG-1801, Section XI.M34, “Buried Piping and Tanks Inspection,” and 

the Buried Services Corrosion Program will be effective in maintaining the 

intended functions of these underground piping systems.

3.4.2.2.6 Quality Assurance for Aging Management of Non-Safety Related 

Components

Quality Assurance Program applicability to non-safety-related components is 

addressed in Appendix B, Section 1.2.

3.4.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Steam and Power Conversion Systems components. The section of the LRA that 

contains the TLAA review results is indicated in parenthesis.

• Fatigue (Section 4.3, Metal Fatigue)

3.4.3 Conclusion

The Steam and Power Conversion Systems piping, fittings, and components that are 

subject to aging management review have been identified in accordance with the 

requirements of 10 CFR 54.4. The aging management programs selected to manage aging 
Page 3-216 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

effects for the Steam and Power Conversion Systems components are identified in the 

summaries in Section 3.4.2.1 above.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.

Therefore, based on the demonstrations provided in Appendix B, the effects of aging 

associated with the Steam and Power Conversion Systems components will be adequately 

managed so that there is reasonable assurance that the intended function(s) will be 

maintained consistent with the current licensing basis during the period of extended 

operation.
Page 3-217 

Table 3.4.1 Summary of Aging Management Evaluations in 

Application for Renewed Operating Licenses

Chapter VIII of NUREG-1801 for Steam and Power Conversion 

System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.4.1-01 Piping and fittings in main 

feedwater line, steam line and AFW piping (PWR only)

Cumulative fatigue damage

TLAA, evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.4.2.2.1)

Further evaluation documented in Section 3.4.2.2.1.The aging mechanism fatigue is potentially applicable to many component types in the Steam and Power Conversion Supergroup, but only selected components or locations require explicit analysis as TLAAs and/or warrant aging management. The Palisades approach to identifying and managing the relevant locations and components for fatigue damage is addressed in Section 4.3 and in Appendix B, Fatigue Monitoring Program. Therefore, cumulative fatigue damage is not identified as an aging effect in Tables 3.4.2-1 through 3.4.2-7 below. 

3.4.1-02 Piping and fittings, valve 

bodies and bonnets, pump casings, tanks, tubes, tubesheets, channel head and shell (except main steam system) 

Loss of material due to general (carbon steel only), pitting, and crevice corrosion

Water chemistry and one-time inspection

Yes, detection of aging effects is to be further evaluated (see [SRP] subsection 3.4.2.2.2)

Further evaluation documented in Section 3.4.2.2.2.

3.4.1-03 Auxiliary feedwater (AFW) 

piping 

Loss of material due to general, pitting, and crevice corrosion, MIC, and biofouling

Plant specific Yes, plant specific 

(see [SRP] subsection 3.4.2.2.3)

Further evaluation documented in Section 3.4.2.2.3.

3.4.1-04 Oil coolers in AFW system 

(lubricating oil side possibly contaminated with water)

Loss of material due to general (carbon steel only), pitting, and crevice corrosion and MIC

Plant specific Yes, plant specific 

(see [SRP] subsection 3.4.2.2.5.1)

Further evaluation documented in Section 3.4.2.2.5.
Page 3-218 

Application for Renewed Operating Licenses

3.4.1-05 External surface of carbon 

steel components 

Loss of material due to general corrosion

Plant specific Yes, plant specific 

(see [SRP] subsection 3.4.2.2.4)

Further evaluation documented in Section 3.4.2.2.4.

3.4.1-06 Carbon steel piping and valve 

bodies 

Wall thinning due to flow-accelerated corrosion

Flow-accelerated corrosion

No See [Section B2.1.11] Flow Accelerated 

Corrosion Program for Aging Management Program for Main Steam and Main Feedwater systems.

3.4.1-07 Carbon steel piping and valve 

bodies in main steam system

Loss of material due to pitting and crevice corrosion

Water chemistry No See [Section B2.1.13] One Time Inspection 

Program and [Section B2.1.21] Water Chemistry Program for aging management programs

3.4.1-08 Closure bolting in 

high-pressure or hightemperature systems 

Loss of material due to general corrosion; crack initiation and growth due to cyclic loading and/or SCC

Bolting integrity No See [Section B2.1.3] Bolting Integrity Program 

and [Section B2.1.20] System Monitoring Program for aging management programs

3.4.1-09 Heat exchangers and coolers/ 

condensers serviced by open-cycle cooling water

Loss of material due to general (carbon steel only), pitting, and crevice corrosion, MIC, and biofouling; buildup of deposit due to biofouling

Open-cycle cooling water system

No Heat exchangers were divided into 

subcomponents as indicated in [Section 2.1.2.2]

3.4.1-10 Heat exchangers and coolers/ 

condensers serviced by closed-cycle cooling water

Loss of material due to general (carbon steel only), pitting, and crevice corrosion

Closed-cycle cooling water system

No Heat exchangers were divided into 

subcomponents as indicated in [Section 2.1.2.2]

Table 3.4.1 Summary of Aging Management Evaluations in Chapter VIII of NUREG-1801 for Steam and Power Conversion 

System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-219 

Application for Renewed Operating Licenses

3.4.1-11 External surface of above 

ground condensate storage tank

Loss of material due to general (carbon steel only), pitting, and crevice corrosion

Above ground carbon steel tanks

No See [Section B2.1.13] One Time Inspection 

Program and [Section B2.1.20] System Monitoring Program for aging management programs

3.4.1-12 External surface of buried 

condensate storage tank and AFW piping 

Loss of material due to general, pitting, and crevice corrosion and MIC

Buried piping and tanks surveillanceor

No Not credited for Aging Management

Buried piping and tanks inspection

Yes, detection of aging effects and operating experience are to be further evaluated (see [SRP] subsection 3.4.2.2.5.2)

Further evaluation documented in Section 3.4.2.2.5.2.

3.4.1-13 External surface of carbon 

steel components 

Loss of material due to boric acid corrosion

Boric acid corrosion No See [Section B2.1.4] Boric Acid Corrosion 

Program for Aging Management Program

Table 3.4.1 Summary of Aging Management Evaluations in Chapter VIII of NUREG-1801 for Steam and Power Conversion 

System

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-220 

Table 3.4.2-1 Steam and Power Conversion System - Condensat

Application for Renewed Operating Licenses

e and Condenser System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material One-Time Inspection 

Program

VIII.E.5-c 3.4.1-11 418, 

420, B

System Monitoring Program

VIII.E.5-c 3.4.1-11 418, 

420, A

Treated Water (Int)

Loss of Material Water Chemistry Program VIII.E.5-a 3.4.1-02 411, A

One-Time Inspection Program

VIII.E.5-a 3.4.1-02 411, B

CST Heater Shell

Fluid Pressure Boundary

Carbon Steel Steam (Int) Loss of Material Water Chemistry Program VIII.A.2-b 3.4.1-02 413, C

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 413, D

CST Heater Tubes

Fluid Pressure Boundary

Carbon Steel Steam (Ext) Loss of Material Water Chemistry Program VIII.A.2-b 3.4.1-02 413, C

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 413, D

Loss of Material - Fretting

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 413, D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.2-b 3.4.1-02 411, 

413, D

Water Chemistry Program VIII.E.2-b 3.4.1-02 411, 

413, C

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, CLoss of Material Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C
Page 3-221 

Application for Renewed Operating Licenses

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.2-b 3.4.1-02 411, D

Water Chemistry Program VIII.E.2-b 3.4.1-02 411, C

FW Heater Shell and Channel Head

Fluid Pressure Boundary

Carbon Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.2-b 3.4.1-02 411, 

413, D

Water Chemistry Program VIII.E.2-b 3.4.1-02 411, 

413, C

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material One-Time Inspection 

Program

VIII.A.1-b 3.4.1-02 D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.4-a 3.4.1-02 A

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H1-b 3.4.1-05 A

Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

VIII.G1-e 3.4.1-12 408, C

Table 3.4.2-1 Steam and Power Conversion System - Condensate and Condenser System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-222 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Treated Water 

(Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.E.1-a 3.4.1-06 423, A

One-Time Inspection Program

VIII.E.1-b 3.4.1-02 411, B

Water Chemistry Program VIII.E.1-b 3.4.1-02 411, A

Stainless Steel Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

407, F

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 405, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 405, 

419, C

Pumps Fluid 

Pressure Boundary

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 422, A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.3-a 3.4.1-02 411, 

422, B

Water Chemistry Program VIII.E.3-a 3.4.1-02 411, 

422, A

Loss of Material - Selective Leaching

One-Time Inspection Program

412, 422, F

Table 3.4.2-1 Steam and Power Conversion System - Condensate and Condenser System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-223 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material Water Chemistry Program VIII.E.2-b 3.4.1-02 411, A

One-Time Inspection Program

VIII.E.2-b 3.4.1-02 411, B

Flow Accelerated Corrosion Program

VIII.E.2-a 3.4.1-06 423, A

Table 3.4.2-1 Steam and Power Conversion System - Condensate and Condenser System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-224 

Table 3.4.2-2 Steam and Power Conversion System - Deminerali

Application for Renewed Operating Licenses

zed Makeup Water System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 416, E

Atmosphere/ Weather (Ext)

Loss of Material One-Time Inspection 

Program

VIII.G.4-c 3.4.1-11 417, 

418, 420, D

System Monitoring Program

VIII.G.4-c 3.4.1-11 417, 

418, 420, C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material Water Chemistry Program VIII.G.4-a 3.4.1-02 411, 

417, C

One-Time Inspection Program

VIII.G.4-a 3.4.1-02 411, 

417, D

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, CLoss of Material Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Filters Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, E
Page 3-225 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material One-Time Inspection 

Program

VIII.C.1-a 3.4.1-02 E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.1-b 3.4.1-02 E

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.1-b 3.4.1-02 411, 

417, D

Water Chemistry Program VIII.E.1-b 3.4.1-02 411, 

417, C

Stainless Steel Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

407, F

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 417, 

419, C

Pumps Fluid 

Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, E

Table 3.4.2-2 Steam and Power Conversion System - Demineralized Makeup Water System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-226 

Application for Renewed Operating Licenses

Transmitter/ Element

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 417, 

419, C

Valves & Dampers

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 417, 

419, C

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 417, 

419, C

Table 3.4.2-2 Steam and Power Conversion System - Demineralized Makeup Water System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-227 

Table 3.4.2-3 Steam and Power Conversion System - Feedwa

Application for Renewed Operating Licenses

ter System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air/Gas (Int) Loss of Material One-Time Inspection 

Program

VII.H2.3-a 3.3.1-05 409, E

Oil (Int) Loss of Material One-Time Inspection 

Program

VIII.G.5-d 3.3.1-06 C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VIII.G.5-d 3.3.1-06 C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.1-c 3.4.1-02 408, 

411, D

Water Chemistry Program VIII.D1.1-c 3.4.1-02 408, 

411, C

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VIII.G.5-b 3.4.1-03 411, 

421, E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.1-c 3.4.1-02 408, 

411, D

Water Chemistry Program VIII.D1.1-c 3.4.1-02 408, 

411, C
Page 3-228 

Application for Renewed Operating Licenses

Indicators/ Recorders

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.1-c 3.4.1-02 408, 

411, D

Water Chemistry Program VIII.D1.1-c 3.4.1-02 408, 

411, C

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(ExtContainment Air (Ext))

Loss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, CLoss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Pipe & Fittings Flow 

Restriction

Carbon Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.1-c 3.4.1-02 411, BVIII.D1.3-a 3.4.1-02 411, BVIII.G.1-c 3.4.1-02 411, BVIII.G.2-a 3.4.1-02 411, B

Water Chemistry Program VIII.D1.1-c 3.4.1-02 411, A

VIII.D1.3-a 3.4.1-02 411, AVIII.G.1-c 3.4.1-02 411, AVIII.G.2-a 3.4.1-02 411, A

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-229 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

System Monitoring Program

VIII.H.1-b 3.4.1-05 A

Oil (Int) Loss of Material One-Time Inspection 

Program

VIII.G.5-d C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Boric Acid Corrosion Program

VIII.H.1-a 3.4.1-13 A

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.D1.1-a 3.4.1-06 AVIII.D1.3-b 3.4.1-06 AVIII.G.1-a 3.4.1-06 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.1-c 3.4.1-02 411, BVIII.D1.3-a 3.4.1-02 411, BVIII.G.1-c 3.4.1-02 411, BVIII.G.2-a 3.4.1-02 411, B

Water Chemistry Program VIII.D1.1-c 3.4.1-02 411, A

VIII.D1.3-a 3.4.1-02 411, AVIII.G.1-c 3.4.1-02 411, AVIII.G.2-a 3.4.1-02 411, A

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-230 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

409, J

Atmosphere/ Weather (Ext)

Loss of Material System Monitoring 

Program

G

Oil (Int) Loss of Material One-Time Inspection 

Program

F

Soil (Ext) Loss of Material Buried Services Corrosion 

Monitoring Program

407, F

Treated Water (Int)

Cracking Water Chemistry Program 410, F

One-Time Inspection Program

410, F

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 405, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 405, 

419, C

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-231 

Application for Renewed Operating Licenses

Pumps Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VIII.G.5-d 3.3.1-06 C

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.D1.3-b 3.4.1-06 A

One-Time Inspection Program

VIII.D1.3-a 3.4.1-02 411, BVIII.G.2-a 3.4.1-02 411, B

Water Chemistry Program VIII.D1.3-a 3.4.1-02 411, A

VIII.G.2-a 3.4.1-02 411, A

Stainless Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 405, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 405, 

419, C

Traps (Steam) Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

409, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Turbines Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

409, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-232 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

409, G

Containment Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Boric Acid Corrosion Program

VIII.H.1-a 3.4.1-13 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VIII.G.1-d 3.4.1-03 411, 

421, D

Steam (Int) Loss of Material Water Chemistry Program VIII.A.2-b 3.4.1-02 A

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 411, B

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.D1.2-a 3.4.1-06 A

One-Time Inspection Program

VIII.D1.2-b 3.4.1-02 411, BVIII.G.3-a 3.4.1-02 411, B

Water Chemistry Program VIII.D1.2-b 3.4.1-02 411, A

VIII.G.3-a 3.4.1-02 411, A

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-233 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Cast Austenitic SS

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 405, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 405, 

419, C

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 422, A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.G.3-a 3.4.1-02 411, 

422, B

Water Chemistry Program VIII.G.3-a 3.4.1-02 411, 

422, A

Loss of Material - Selective Leaching

One-Time Inspection Program

412, 422, F

Stainless Steel Air (Int) Loss of Material One-Time Inspection 

Program

409, F

Steam (Int) Cracking Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Loss of Material Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-234 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking Water Chemistry Program F

One-Time Inspection Program

F

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 405, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 405, 

419, C

Table 3.4.2-3 Steam and Power Conversion System - Feedwater System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-235 

Table 3.4.2-4 Steam and Power Conversion System - Heater Extr

Application for Renewed Operating Licenses

action and Drain System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-08 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.1-a 3.4.1-02 E

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, CLoss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-08 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.1-a 3.4.1-02 E

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.C.1-a 3.4.1-06 423, A

Water Chemistry Program VIII.C.1-b 3.4.1-02 AOne-Time Inspection Program

VIII.C.1-b 3.4.1-02 411, B

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.E.1-a 3.4.1-06 414, 

423, C

One-Time Inspection Program

VIII.E.1-b 3.4.1-02 411, 

414, D

Water Chemistry Program VIII.E.1-b 3.4.1-02 411, 

414, C
Page 3-236 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Stainless Steel Steam (Int) Cracking Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Loss of Material Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Pumps Fluid 

Pressure Boundary

Carbon Steel Treated Water 

(Int)

Loss of Material One-Time Inspection 

Program

VIII.E.3-a 3.4.1-02 411, 

414, D

Water Chemistry Program VIII.E.3-a 3.4.1-02 411, 

414, C

Transmitter/ Element

Fluid Pressure Boundary

Stainless Steel Treated Water 

(Int)

Cracking Water Chemistry Program 410, F

One-Time Inspection Program

410, F

Loss of Material Water Chemistry Program F

One-Time Inspection Program

F

Traps (Steam) Fluid 

Pressure Boundary

Carbon Steel Steam (Int) Loss of Material Water Chemistry Program VIII.C.2-b 3.4.1-02 C

One-Time Inspection Program

VIII.C.2-b 3.4.1-02 D

Table 3.4.2-4 Steam and Power Conversion System - Heater Extraction and Drain System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-237 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.C.2-a 3.4.1-06 423, A

Water Chemistry Program VIII.C.2-b 3.4.1-02 AOne-Time Inspection Program

VIII.C.2-b 3.4.1-02 B

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.E.2-a 3.4.1-06 414, 

423, C

One-Time Inspection Program

VIII.E.2-b 3.4.1-02 411, 

414, D

Water Chemistry Program VIII.E.2-b 3.4.1-02 411, 

414, C

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material None Required VIII.H.1-b 3.4.1-05 401, 

422, I

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.C.2-a 3.4.1-06 422, 

423, A

Water Chemistry Program VIII.C.2-b 3.4.1-02 422, AOne-Time Inspection Program

VIII.C.2-b 3.4.1-02 422, B

Loss of Material - Selective Leaching

One-Time Inspection Program

412, 422, F

Table 3.4.2-4 Steam and Power Conversion System - Heater Extraction and Drain System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-238 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Stainless Steel Steam (Int) Cracking Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Loss of Material Water Chemistry Program 404, F

One-Time Inspection Program

404, F

Table 3.4.2-4 Steam and Power Conversion System - Heater Extraction and Drain System - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-239 

Table 3.4.2-5 Steam and Power Conversion System - Main Air Ejection and Gland Seal

Application for Renewed Operating Licenses

System - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Blowers Fans Compressor Vacuum

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

415, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material Water Chemistry Program VIII.A.1-b 3.4.1-02 415, C

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 415, D

Cast Iron Steam (Int) Loss of Material Water Chemistry Program VIII.A.1-b 3.4.1-02 415, 

422, C

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 415, 

422, D

Loss of Material - Selective Leaching

One-Time Inspection Program

412, 415, J

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

415, J

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.1-a 3.4.1-06 415, C

Water Chemistry Program VIII.A.1-b 3.4.1-02 415, COne-Time Inspection Program

VIII.A.1-b 3.4.1-02 415, D
Page 3-240 

Application for Renewed Operating Licenses

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material Water Chemistry Program VIII.A.1-b 3.4.1-02 415, C

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 415, D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.2-b 3.4.1-02 411, 

415, D

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, CLoss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

416, G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material Water Chemistry Program VIII.A.1-b 3.4.1-02 415, C

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 415, D

Table 3.4.2-5 Steam and Power Conversion System - Main Air Ejection and Gland Seal System - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-241 

Application for Renewed Operating Licenses

Traps (Steam) Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 E

Steam (Int) Loss of Material Water Chemistry Program VIII.A.2-b 3.4.1-02 415, C

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 415, D

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Air (Int) Loss of Material One-Time Inspection 

Program

416, G

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.2-a 3.4.1-06 415, C

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 415, D

Water Chemistry Program VIII.A.2-b 3.4.1-02 415, C

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.D1.2-b 3.4.1-02 411, 

415, D

Water Chemistry Program VIII.D1.2-b 3.4.1-02 411, 

415, C

Table 3.4.2-5 Steam and Power Conversion System - Main Air Ejection and Gland Seal System - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-242 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Cast Iron Steam (Int) Loss of Material Water Chemistry Program VIII.A.2-b 3.4.1-02 415, 

422, C

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 411, 

415, 422, D412, 422, F

Loss of Material - Selective Leaching

One-Time Inspection Program

Table 3.4.2-5 Steam and Power Conversion System - Main Air Ejection and Gland Seal System - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-243 

Table 3.4.2-6 Steam and Power Conversion System - Main St

Application for Renewed Operating Licenses

eam System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 C

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.1-a 3.4.1-06 403, 

423, C

Water Chemistry Program VIII.A.1-b 3.4.1-02 403, COne-Time Inspection Program

VIII.A.1-b 3.4.1-02 403, D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.F.1-b 3.4.1-02 E

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 401, A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.2-a 3.4.1-06 403, 

423, C

Water Chemistry Program VIII.A.2-b 3.4.1-02 403, COne-Time Inspection Program

VIII.A.2-b 3.4.1-02 403, D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E5-a 3.4.1-02 E

Indicators/ Recorders

Fluid Pressure Boundary

Stainless Steel Steam (Int) Cracking Water Chemistry Program 403, 

404, J

Loss of Material Water Chemistry Program 403, 

404, J
Page 3-244 

Application for Renewed Operating Licenses

Ejectors Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 401, A

Steam (Int) Loss of Material Water Chemistry Program VIII.A.1-b 3.4.1-02 403, C

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 403, D

Fasteners Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 401, A

Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Loss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Steam (Int) Loss of Material One-Time Inspection 

Program

VIII.B1.1-a 3.4.1-07 E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.F.1-b 3.4.1-02 E

Table 3.4.2-6 Steam and Power Conversion System - Main Steam System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-245 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.1-a 3.4.1-06 423, AVIII.B1.1-c 3.4.1-06 423, A

Water Chemistry Program VIII.A.1-b 3.4.1-02 424, A

VIII.B1.1-a 3.4.1-07 424, A

One-Time Inspection Program

VIII.A.1-b 3.4.1-02 B

Treated Water (Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.F.1-a 3.4.1-06 423, A

One-Time Inspection Program

VIII.F.1-b 3.4.1-02 411, B

Water Chemistry Program VIII.F.1-b 3.4.1-02 411, A

Copper Alloys Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

402, F

Stainless Steel Steam (Int) Cracking Water Chemistry Program 404, G

Steam (Int) Loss of Material Water Chemistry Program 404, G

Pumps Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-13 A

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-a 3.4.1-02 E

Table 3.4.2-6 Steam and Power Conversion System - Main Steam System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-246 

Application for Renewed Operating Licenses

Traps (Steam) Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.2-a 3.4.1-06 403, 

423, C

Water Chemistry Program VIII.A.2-b 3.4.1-02 403, COne-Time Inspection Program

VIII.A.2-b 3.4.1-02 403, D

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.F.1-b 3.4.1-02 E

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Plant Indoor Air (Ext)

Loss of Material Boric Acid Corrosion 

Program

VIII.H.1-a 3.4.1-13 A

Steam (Int) Loss of Material Flow Accelerated 

Corrosion Program

VIII.A.2-a 3.4.1-06 423, AVIII.B1.2-b 3.4.1-06 423, A

Water Chemistry Program VIII.A.2-b 3.4.1-02 424, A

VIII.B1.2-a 3.4.1-07 424, A

One-Time Inspection Program

VIII.A.2-b 3.4.1-02 B

Table 3.4.2-6 Steam and Power Conversion System - Main Steam System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-247 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Treated Water 

(Int)

Loss of Material Flow Accelerated 

Corrosion Program

VIII.F.2-a 3.4.1-06 423, A

One-Time Inspection Program

VIII.F.2-b 3.4.1-02 411, B

Water Chemistry Program VIII.F.2-b 3.4.1-02 411, A

Stainless Steel Steam (Int) Cracking Water Chemistry Program 404, F

Loss of Material Water Chemistry Program 404, F

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VIII.E.5-b 3.4.1-02 417, 

419, D

Water Chemistry Program VIII.E.5-b 3.4.1-02 417, 

419, C

Table 3.4.2-6 Steam and Power Conversion System - Main Steam System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-248 

Table 3.4.2-7 Steam and Power Conversion System - Turbine Ge

Application for Renewed Operating Licenses

nerator System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Accumulators Fluid 

Pressure Boundary

Carbon Steel Air/Gas (Int) Loss of Material One-Time Inspection 

Program

VII.H.2.3-a 3.3.1-05 E

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-a 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Stainless Steel Oil (Int) Loss of Material One-Time Inspection 

Program

G

Fasteners Fluid 

Pressure Boundary

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Loss of Preload Bolting Integrity Program VIII.H.2-a 3.4.1-08 406, C

Filters/Strainers Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-a 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Heat Exchangers

Fluid Pressure Boundary

Carbon Steel Air/Gas (Int) Loss of Material One-Time Inspection 

Program

VII.H.2.3-a 3.3.1-05 E

Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-a 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.3-a 3.3.1-17 E
Page 3-249 

Application for Renewed Operating Licenses

Pipe & Fittings Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.1-a 3.3.1-17 E

Steam (Int) Loss of Material One-Time Inspection 

Program

VIII.B1.1-c 3.3.1-17 E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2.1-a 3.3.1-17 E

Stainless Steel Oil (Int) Loss of Material One-Time Inspection 

Program

G

Pumps Fluid 

Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-a 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Cast Iron Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-a 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Table 3.4.2-7 Steam and Power Conversion System - Turbine Generator System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-250 

Application for Renewed Operating Licenses

Valves & Dampers

Fluid Pressure Boundary

Carbon Steel Oil (Int) Loss of Material One-Time Inspection 

Program

VII.G.7-b 3.3.1-06 E

Plant Indoor Air (Ext)

Loss of Material System Monitoring 

Program

VIII.H.1-b 3.4.1-05 A

Raw Water (Int) Loss of Material One-Time Inspection 

Program

VII.C1.2-a 3.3.1-17 E

Steam (Int) Loss of Material One-Time Inspection 

Program

VIII.B1.2-b 3.3.1-17 E

Treated Water (Int)

Loss of Material One-Time Inspection 

Program

VII.C2.2-a 3.3.1-17 E

Table 3.4.2-7 Steam and Power Conversion System - Turbine Generator System - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
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Notes for Tables 3.4.2-1 through 3.4.2-7

A Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP has exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP has exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different AMP is 

credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific notes:

401 The external surface temperature of this component is < 212°F.

402 Copper alloys are not addressed in S&PC Supergroup of GALL.

403 These components are not addressed in MSS subgroup (VIII.A, VIII.B1, and VIII.F) of 

GALL.

404 The combination of Stainless Steels and environment of Steam is not evaluated in S&PC 

Supergroup of GALL.

405 Use GALL line of Condensate Storage Tank in VIII.E for this evaluation.

406 Loss of preload is included here in response to recent NRC RAIs on non-primary system, 

high temperature bolting that may experience loss of preload. The Palisades Bolting 

Integrity Program manages potential bolting AERMs and event driven degradation. GALL 

reconciliation is based on Loss of Material.

407 Buried stainless steel piping are not addressed in S&PC Supergroup of GALL.
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408 Use the GALL line of FWS or AFW piping for this evaluation.

409 These components associated with AFW turbine are normally exposed to air in standby with 

steam supply isolated.

410 Aging effect of cracking for internal environment is not evaluated in S&PC Supergroup of 

GALL.

411 For carbon steels, Galvanic Corrosion and/or MIC are conservatively included as aging 

mechanisms for Loss of Material.

412 Selective Leaching is not addressed in S&PC Supergroup of GALL.

413 Use GALL VIII.A for evaluation of steam environment and VIII.E.2 for condensate 

environment.

414 The environment of Treated Water is not addressed in GALL VIII.C. Use GALL line of 

Condensate System for this evaluation.

415 Internal environment of components associated with condenser vacuum. Air Ejectors are 

not addressed in S&PC Supergroup of GALL.

416 The internal environment of Air is not addressed in S&PC Supergroup of GALL.

417 Demineralized Make-Up Water (DMW) is not addressed in GALL. Use GALL line of 

Condensate System or Feedwater System for this evaluation.

418 Palisades does not maintain a separate Above ground Carbon Steel Tanks Program (GALL 

XI.M29). It is implemented by System Monitoring Program (inspection) and One-Time 

Inspection Program (tank bottom thickness).

419 For stainless steels in treated water < 212°F, MIC is conservatively included as an aging 

mechanism for Loss of Material.

420 For carbon steels outside the plant buildings, Crevice and Pitting corrosion are considered 

to be applicable aging mechanisms.

421 The AFW isolation valves of backup supplies from Fire Protection Water and Service Water 

are normally closed. It is not covered by Fire Protection Water program or Service Water 

Program. The One-Time Inspection Program will determine whether further actions are 

required.

422 Cast Irons are considered to be equivalent to Carbon Steels in evaluation of the aging 

effects of Loss of Material, except Selective Leaching.

423 As described in Plant OE database, erosion had occurred to some components that also are 

susceptible to FAC aging effect. Thus it is conservatively assumed this aging effect is 
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applicable to the components susceptible to FAC. This aging effect is covered by the Flow 

Accelerated Corrosion Program.

424 General Corrosion is not evaluated for carbon steel main steam piping and valves in GALL 

VIII.B1.1-a and VIII.B1.2-a.
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3.5 Aging Management of Containments, Structures, and Component Supports

3.5.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.4, Containments, Structures, and Component Supports, as being 

subject to aging management review. The systems, or portions of systems, which are 

addressed in this section, are described in the indicated sections.

• Auxiliary Building (Section 2.4.1)

• Component Supports (Section 2.4.2)

• Containment (Section 2.4.3)

• Containment Interior Structures (Section 2.4.4)

• Discharge Structure (Section 2.4.5)

• Feedwater Purity Building (Section 2.4.6)

• Intake Structure (Section 2.4.7)

• Miscellaneous Structural and Bulk Commodities (Section 2.4.8)

• Switchyard and Yard Structures (Section 2.4.9)

• Turbine Building (Section 2.4.10)

Table 3.5.1, Summary of Aging Management Evaluations in Chapters II and III of 

NUREG-1801 for Structures and Component Supports, provides the summary of the 

programs evaluated in NUREG-1801 for the Structures and Component Supports 

component groups that are relied on for license renewal. 

This table uses the format described in Figure 3.0-1 above. Note that this table only includes 

those component groups that are applicable to a PWR.

3.5.2 Results

The following tables summarize the results of the aging management review for systems in 

the Containments, Structures, and Component Supports group: 

Table 3.5.2-1, Structures and Component Supports - Auxiliary Building - Summary of Aging 

Management Evaluation

Table 3.5.2-2, Structures and Component Supports - Component Supports - Summary of 

Aging Management Evaluation

Table 3.5.2-3, Structures and Component Supports - Containment - Summary of Aging 

Management Evaluation
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Table 3.5.2-4, Structures and Component Supports - Containment Interior Structures - 

Summary of Aging Management Evaluation

Table 3.5.2-5, Structures and Component Supports - Discharge Structure - Summary of 

Aging Management Evaluation

Table 3.5.2-6, Structures and Component Supports - Feedwater Purity Building - Summary 

of Aging Management Evaluation

Table 3.5.2-7, Structures and Component Supports - Intake Structure - Summary of Aging 

Management Evaluation

Table 3.5.2-8, Structures and Component Supports - Miscellaneous Structural and Bulk 

Commodities - Summary of Aging Management Evaluation

Table 3.5.2-9, Structures and Component Supports - Switchyard and Yard Structures - 

Summary of Aging Management Evaluation

Table 3.5.2-10, Structures and Component Supports - Turbine Building - Summary of Aging 

Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the potential aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for each of the 

above systems in the following subsections of Section 3.5.2.1, Materials, Environment, 

Aging Effects Requiring Management and Aging Management Programs:

Section 3.5.2.1.1, Auxiliary Building

Section 3.5.2.1.2, Component Supports

Section 3.5.2.1.3, Containment

Section 3.5.2.1.4, Containment Interior Structures

Section 3.5.2.1.5, Discharge Structure

Section 3.5.2.1.6, Feedwater Purity Building

Section 3.5.2.1.7, Intake Structure

Section 3.5.2.1.8, Miscellaneous Structural and Bulk Commodities

Section 3.5.2.1.9, Switchyard and Yard Structures

Section 3.5.2.1.10, Turbine Building
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3.5.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.5.2.1.1 Auxiliary Building

Materials

The materials of construction for the Auxiliary Building components are:

• Carbon Steel

• Concrete

• Galvanized

• Stainless Steel

Environment

The Auxiliary Building components are exposed to the following environments:

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Soil (Ext)

• Treated Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Auxiliary Building, require 

management:

• Change in Material Properties

• Cracking

• Cracking and Expansion 

• Cracking, Loss of Bond/Material

• Loss of Leak Tightness

• Loss of Material 

• Loss of Strength 

• Reduction in Concrete Anchor Capacity

Aging Management Programs

The following aging management programs manage the aging effects for the 

Auxiliary Building components:

• Boric Acid Corrosion Program
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• Structural Monitoring Program

• Water Chemistry Program

3.5.2.1.2 Component Supports

Materials

The materials of construction for the Component Supports components are:

• Aluminum

• Boron Carbide

• Bronze

• Carbon Steel

• Cast Iron

• Concrete

• Galvanized

• Stainless Steel

Environment

The Component Supports components are exposed to the following 

environments:

• Atmosphere/Weather (Ext)

• Containment Air (Ext)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

• Treated Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Component Supports, require 

management:

• Cracking

• Loss of Material

• Reduction in Conc Anchor Capacity
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Component Supports components:

• ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Structural Monitoring Program

• Water Chemistry Program

3.5.2.1.3 Containment 

Materials

The materials of construction for the Containment components are:

• Carbon Steel

• Concrete

• Elastomers

• Stainless Steel

Environment

The Containment components are exposed to the following environments:

• Atmosphere/Weather (Ext)

• Containment Air (Ext)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Containment, require 

management:

• Change in Material Properties 

• Cracking

• Cracking and Expansion 

• Cracking, Loss of Bond/Material

• Loss of Leak Tightness 

• Loss of Material
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Containment components:

• Boric Acid Corrosion Program

• Containment Inservice Inspection Program

• Containment Leakage Testing Program

• Structural Monitoring Program

3.5.2.1.4 Containment Interior Structures

Materials

The materials of construction for the Containment Interior Structures 

components are:

• Carbon Steel

• Concrete

• Stainless Steel

• Galvanized 

Environment

The Containment Interior Structures components are exposed to the following 

environments:

• Containment Air (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Containment Interior 

Structures, require management:

• Change in Material Properties 

• Cracking 

• Cracking and Expansion 

• Cracking, Loss of Bond/Material 

• Loss of Material 

• Reduction in Conc Anchor Capacity
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Containment Interior Structures components:

• Boric Acid Corrosion Program

• Structural Monitoring Program

• Water Chemistry Program

3.5.2.1.5 Discharge Structure

Materials

The materials of construction for the Discharge Structure components are:

• Carbon Steel

• Cast Iron

• Concrete

Environment

The Discharge Structure components are exposed to the following 

environments:

• Atmosphere/ Weather (Ext)

• Soil (Ext)

• Raw Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Discharge Structure, require 

management:

• Change in Material Properties 

• Cracking 

• Cracking and Expansion 

• Cracking, Loss of Bond/Material 

• Loss of Material 

• Reduction in Concrete Anchor Capacity
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Discharge Structure components:

• Structural Monitoring Program

3.5.2.1.6 Feedwater Purity Building

Materials

The materials of construction for the Feedwater Purity Building components 

are:

• Carbon Steel

• Concrete

Environment

The Feedwater Purity Building components are exposed to the following 

environments:

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Feedwater Purity Building, 

require management:

• Change in Material Properties

• Cracking

• Cracking and Expansion 

• Cracking, Loss of Bond/Material

• Loss of Material

• Loss of Strength

• Reduction in Concrete Anchor Capacity

Aging Management Programs

The following aging management programs manage the aging effects for the 

Feedwater Purity Building components:

• Structural Monitoring Program
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3.5.2.1.7 Intake Structure

Materials

The materials of construction for the Intake Structure components are:

• Carbon Steel

• Cast Iron

• Concrete

• Galvanized

Environment

The Intake Structure components are exposed to the following environments:

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Intake Structure, require 

management:

• Change in Material Properties

• Cracking 

• Cracking and Expansion 

• Cracking, Loss of Bond/Material 

• Loss of Material 

• Loss of Strength 

• Reduction in Concrete Anchor Capacity

Aging Management Programs

The following aging management programs manage the aging effects for the 

Intake Structure components:

• Structural Monitoring Program
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3.5.2.1.8 Miscellaneous Structural and Bulk Commodities

Materials

The materials of construction for the Miscellaneous Structural and Bulk 

Commodities components are:

• Built-up Roofing

• Carbon Steel

• Concrete

• Elastomers

• Fire Stops [Sealant/Maranite]

• Fire Wraps [Mineral-Wool Batts]

• Galvanized

• Soil

Environment

The Miscellaneous Structural and Bulk Commodities components are exposed 

to the following environments:

• Containment Air (Ext)

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Raw Water (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Miscellaneous Structural and 

Bulk Commodities, require management:

• Change in Material Properties 

• Cracking 

• Cracking and Expansion 

• Cracking/Delamination

• Cracking, Loss of Bond/Material

• Loss of Form 

• Loss of Leak Tightness

• Loss of Material 
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• Loss of Material/Form

• Separation

Aging Management Programs

The following aging management programs manage the aging effects for the 

Miscellaneous Structural and Bulk Commodities components:

• Fire Protection Program

• Overhead Load Handling Systems Inspection Program

• Structural Monitoring Program

• Containment Inservice Inspection Program

3.5.2.1.9 Switchyard and Yard Structures

Materials

The materials of construction for the Switchyard and Yard Structures 

components are:

• Carbon Steel

• Concrete

• Galvanized

Environment

The Switchyard and Yard Structures components are exposed to the following 

environments:

• Atmosphere/Weather (Ext)

• Plant Indoor Air (Ext)

• Soil (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Switchyard and Yard 

Structures, require management:

• Change in Material Properties

• Cracking

• Cracking and Expansion 

• Cracking, Loss of Bond/Matl 

• Loss of Material 
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• Loss of Strength

• Reduction in Concrete Anchor Capacity

Aging Management Programs

The following aging management programs manage the aging effects for the 

Switchyard and Yard Structures components:

• Structural Monitoring Program

3.5.2.1.10Turbine Building

Materials

The materials of construction for the Turbine Building components are:

• Bronze

• Carbon Steel

• Concrete

• Galvanized

Environment

The Turbine Building components are exposed to the following environments:

• Atmosphere/ Weather (Ext)

• Soil (Ext)

• Plant Indoor Air (Ext)

Aging Effects Requiring Management

The following aging effects, associated with the Turbine Building, require 

management:

• Change in Material Properties 

• Cracking 

• Cracking and Expansion 

• Cracking, Loss of Bond/Matl 

• Loss of Leak Tightness 

• Loss of Material 

• Loss of Strength 

• Reduction in Concrete Anchor Capacity
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Aging Management Programs

The following aging management programs manage the aging effects for the 

Turbine Building components:

• Structural Monitoring Program

3.5.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 Volume 1 Tables provide the basis for identifying those programs 

that warrant further evaluation by the reviewer in the license renewal application. 

For the Containments, Structures, and Component Supports, those programs are 

addressed in the following sections.

3.5.2.2.1 PWR Containment

3.5.2.2.1.1 Aging of Inaccessible Concrete Areas

NUREG 1800 states that cracking, spalling, and increases in porosity and 

permeability due to leaching of calcium hydroxide and aggressive chemical 

attack; and cracking, spalling, loss of bond, and loss of material due to 

corrosion of embedded steel; could occur in inaccessible areas of PWR 

concrete and steel containments. NUREG-1801 recommends further 

evaluation of plant-specific programs to manage the aging effects for 

inaccessible areas if specific criteria defined in NUREG-1801 cannot be 

satisfied.

Loss of Material (Spalling, Scaling) and Cracking due to Freeze - Thaw 

(GALL IIA1.1-a) 

Accessible Areas: In accordance with NUREG-1801 as revised by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Containment Inservice Inspection Program to manage 

Loss of Material (spalling, scaling) and cracking due to Freeze - thaw.

Inaccessible Areas: Palisades is located in an area with severe weathering 

conditions as noted on Figure 1 of ASTM C33-99. Freeze-thaw is not 

considered an aging mechanism for concrete components below the frost 

line (depth of 42 inches, per Michigan Building Code).

Discussion: The Palisades concrete structures and concrete are designed 

in accordance with ACI 318-63 & 71, and constructed using ingredients 

conforming to ACI and ASTM standards. Palisades specifications require all 

concrete to contain an air-entraining agent in sufficient quantity to maintain 
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specified percentages based on nominal maximum size aggregate. For 

severe weather exposures, the air content identified varies from 3 to 5 

percent. Containment replacement concrete for steam generator 

replacement access had 3 to 7 percent air entrainment specified. 

Water/cement ratios for concrete mixes range from 0.44 for the 5000 psi 

concrete and 0.45 to 0.46 for the 4000 psi concrete mix designs used in the 

primary containment construction (FSAR Section 5.8.7.1), and 0.33 for 

5000 psi concrete used for closing the opening in the shell for steam 

generator replacement (FSAR Section 5.8.9.3.1.4). 

Review of Operating Experience and Maintenance Rule Structures 

Monitoring results confirmation that freeze-thaw degradation of Palisades’ 

concrete has not occurred. 

As described in NUREG-1557 “Summary of Technical Information and 

Agreements from Nuclear Management and Resources Council [NUMARC] 

Industry Reports Addressing License Renewal,” freeze-thaw does not 

cause loss of material from reinforced concrete in foundations, and in above 

and below grade exterior concrete, for plants located in a geographic region 

of negligible weathering conditions (weathering index <100 day-inch/yr). 

Similarly, freeze-thaw damage is not significant for reinforced concrete in 

foundations, and in above and below grade exterior concrete, for plants 

located in areas in which weathering conditions are considered severe 

(weathering index >500 day-inch/yr) or moderate (100-500 day-inch/yr), 

provided that the concrete mix design meets the air content (entrained air 

3-6%) and water-to-cement ratio (0.35-0.45) specified in ACI 318-63 or ACI 

349-85. Palisades water-cement ratios range between 0.33 and 0.46, and 

ACI 201.2R-77 Section 1.4.2 recommends a not to exceed water-cement 

ratio of 0.50 for other than “thin” structures. In addition, at Palisades, the 

ground tends to freeze and stay frozen through the winter, which means 

that below grade concrete is only exposed, essentially, to one freeze-thaw 

cycle in a typical year. Since damage to concrete from freeze-thaw is 

related to repeated cycles of freeze-thaw as noted in EPRI Structural Tools, 

Rev1, Section 5.3.1.1, and no evidence of freeze-thaw damage has been 

identified in exposed concrete which is subjected to repeated cycles, it is 

concluded that below grade concrete will not experience damage or 

degradation. 

Therefore, since these conditions for Palisades concrete are satisfied, 

aging management is not required for below grade concrete. 
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Increase in Porosity, Permeability, and Loss of Strength Due to 

Leaching (GALL IIA1.1-b)

Accessible Areas: In accordance with NUREG-1801 as revised by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Containment Inservice Inspection Program to manage 

increase in porosity and permeability, and loss of strength due to leaching of 

calcium hydroxide.

Inaccessible Areas (Containment Shell and Basemat Concrete): The 

Palisades concrete structures and concrete components are designed in 

accordance with ACI 318-63 and constructed using ingredients conforming 

to ACI and ASTM standards, which provide for good quality, dense, well 

cured, and low permeability concrete. Cracking is controlled through proper 

arrangement and distribution of reinforcing bars.

Concrete structures and concrete components are constructed of a dense, 

well-cured concrete with an amount of cement suitable for strength 

development, and achievement of a water-to-cement ratio (Palisades 

water/cement ratio 0.45), which is characteristic of concrete having low 

permeability. This is consistent with the recommendations and guidance 

provided by ACI 201.2R-77.

In addition, concrete components must be exposed to flowing water through 

the concrete component in order for leaching to be an issue. Ground water 

elevation is Elev.580', with primary containment basement floor at Elev. 

590'. In addition, the containment bottom/floor has a 1⁄4” thick, steel liner 

plate welded to embedments and covered with 18" concrete, further 

reducing the likelihood of water flowing through the floor.

Natural groundwater movement in this area is from the plant site to Lake 

Michigan. The rate of groundwater flow estimated during site exploration 

and discussed in the FSAR Section 2.2.1, is 650 feet per year (0.074 

feet/hr), which is not considered an aggressive flow rate. Groundwater 

elevation at the plant site is the same as Lake Michigan (elevation 

corresponds with lake water level).

 Leaching of Calcium Hydroxide is readily noticeable as white deposits that 

remain on the concrete surface after a solution of water-free lime from the 

concrete and carbon dioxide from the air is absorbed and dries. The 

Containment ISI Program inspects concrete surfaces for signs of leaching. 
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No significant signs of leaching have been documented during these 

inspection walkdowns.

In summary, the accessible concrete will be inspected in accordance with 

ASME Section Subsection IWL requirements. Inaccessible concrete is not 

subject to flowing water, and was constructed consistent with ACI 201.2R 

such that below grade aging management is not required. Therefore, the 

conditions identified in NUREG-1801 as revised by ISG-03 are satisfied, 

and aging management of increase in porosity and permeability, loss of 

strength due to leaching of calcium hydroxide for below grade inaccessible 

concrete is not required.

Increase in Porosity and Permeability, Cracking, Loss of Material 

(Spalling, Scaling) due to Aggressive Chemical Attack (GALL IIA1.1-c)

Inaccessible Areas: ISG-3 indicates that a plant-specific aging management 

program is required for below-grade exterior reinforced concrete (basemat, 

embedded walls) if the environment is aggressive (pH < 5.5, chlorides >500 

ppm, or sulfates > 1500 ppm). Examination of representative samples of 

below-grade concrete, when excavated for any reason, is to be included as 

part of a plant-specific program. Periodic monitoring of below-grade water 

chemistry (including consideration of potential seasonal variations) is an 

acceptable approach to demonstrate that the below-grade environment is 

aggressive or non-aggressive.

Design and construction of Palisades’ reinforced concrete provides for 

dense, well cured, and low permeability concrete that provides an 

acceptable degree of protection against exposure of below-grade exterior 

reinforced concrete to an aggressive environment. Cracking of concrete is 

controlled through proper arrangement and distribution of reinforcing bars. 

Continued or frequent cyclic exposure to the following aggressive 

environments is necessary for aggressive chemicals to cause a significant 

increase in porosity and permeability, cracking, loss of material (spalling, 

scaling):

Acidic solutions with pH < 5.5

Chloride solutions >500 ppm

Sulfate solutions >1500 ppm

Since aggressive chemicals are contained at plant sites, system leakage is 

possible that could cause the reinforced concrete to be exposed to 

chemicals beyond these limits. However, leaks are not expected to continue 
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for the extensive periods required for degradation, and repairs would be 

completed prior to loss of intended function. It is not likely that leaks inside 

the structure would get outside to cause an aggressive chemical attack on 

embedded concrete.

An aggressive environment may also occur when reinforced concrete is 

exposed to aggressive aqueous solutions such as groundwater or 

aggressive water flow. Palisades groundwater water sample 

measurements, summarized below, have confirmed that parameters are 

well below threshold limits that could cause concrete degradation i.e., (an 

aggressive environment does not exist). 

Palisades Groundwater Sampling results from 1966, 1996, and 2004:

Natural groundwater movement in this area is from the plant site to Lake 

Michigan. The rate of groundwater flow estimated during site exploration 

and discussed in the FSAR Section 2.2.1 Groundwater, is 650 feet per year 

(0.074'/hr), which is not considered an aggressive flow rate. Groundwater 

elevation at the plant site is the same as Lake Michigan (elevation 

corresponds with lake water level).

Lake Michigan water samples, listed below also confirm that an aggressive 

environment does not exist.

Chemistry/Year 1966

(20 locations)

1996 2004

pH Range 6.1 - 7.7

(> 5.5)

No reading 7.0

Chlorides - ppm Range 4.0 - 39

(<500)

23 139

Sulfates - ppm Range 9.47 - 33.17

(<1500)

15.2 11.5
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Samples from 1962 to1966 of Lake Michigan water at or near the site and 

1992 and 2004 site results: 

In addition, FSAR Chapter 2 - Table 2-12 - Analysis of Soil Samples shows 

that site soil pH (9 samples) ranged between 8.1 and 8.5, indicating that soil 

around and under site structures is also alkaline and does not present an 

aggressive environment for inaccessible concrete.

In summary, Palisades ground water sample measurements, taken over the 

course of many years and during varying seasons, confirm that parameters 

have remained consistent and are well below threshold limits that could 

cause concrete degradation (i.e., an aggressive environment does not 

exist). The rate of ground water flow is not considered an aggressive flow 

rate. Therefore, the conditions identified in NUREG-1801 as revised by 

ISG-03 are satisfied; and aging management of increased porosity and 

permeability, cracking, loss of material (spalling, scaling) due to aggressive 

chemical attack of below grade inaccessible concrete is not required.

In addition it is concluded that additional groundwater monitoring over the 

period of license extension is not necessary. Sampling to date has shown 

no variance in over 40 years and the chemical parameters are well below 

limits considered aggressive. It would require a significant environmental 

event to substantially affect the quality of groundwater in the vicinity of 

Palisades. A change in the environment due to a chemical release would be 

considered as an “abnormal event.” NUREG-1800, “Standard Review Plan 

for the Review of License Renewal Applications for Nuclear Power Plants,” 

states that aging effects from abnormal events need not be postulated 

specifically for license renewal.

Chemistry/Year 1962-1966 1992 2004

pH Range 7.6 to 8.2

(>5.5)

8.2 7.9

Chlorides - ppm Range 5.0 to 32.0

(<500)

11.5 12

Sulfates - ppm Range 16.0 to 28.0

(<1500)

29 24.4
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Expansion and Cracking due to Reaction with Aggregates (GALL 

IIA1.1-d)

Accessible Areas: In accordance with NUREG-1801, as revised by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Containment Inservice Inspection Program to manage 

expansion and cracking due to reaction with aggregates.

Inaccessible Areas: The aggregate used in the concrete of the Palisades 

components did not come from a region known to yield aggregates 

suspected of or known to cause aggregate reactions. Materials for concrete 

used in Palisades structures and components were specifically 

investigated, tested and examined in accordance with pertinent ASTM 

standards. All aggregates used at Palisades conform to the requirements of 

ASTM C33 “Standard Specification of Concrete Aggregates.” Appendix XI 

of ASTM C33 identifies methods for evaluating potential reactivity of 

aggregates including ASTM C295, ASTM C289, ASTM C227, and ASTM 

C342. Palisades aggregates were tested to assure compliance with ASTM 

C-33 (FSAR 5.8.7.2): Petrographic Analysis - ASTM C-295, Potential 

Reactivity (Chemical) - ASTM C-289, and Potential Reactivity (Mortar Bar) - 

ASTM C-227. Palisades aggregates were not tested to ASTM C-342, 

presumably because this method does not provide reliable results as noted 

in ACI 201.2R-77 Chapter 5, Section 5.3.3. Low alkali Portland Cement 

(ASTM C150 Type II) was used in the concrete mixes used in all Palisades 

concrete structures, which mitigates harmful expansion due to alkali 

aggregate reaction.

Therefore, the conditions identified in NUREG-1801 as revised by ISG-03 

are satisfied and aging management of expansion and cracking due to 

reaction with aggregates for below grade inaccessible concrete is not 

required.

Aggressive Groundwater Environment-Embedded Steel (GALL 

IIA1.1-e)

Inaccessible Areas: For the aging effects of cracking, loss of bond, loss of 

material (spalling, scaling) due to corrosion of embedded steel for concrete 

components, ISG-3 indicates that a plant-specific aging management 

program is required if the below-grade environment is aggressive (pH < 5.5, 

chlorides >500 ppm, or sulfates > 1500 ppm). Examination of 

representative samples of below-grade concrete, when excavated for any 
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reason, is to be included as part of a plant-specific program. Note: Periodic 

monitoring of below-grade water chemistry (including consideration of 

potential seasonal variations) is an acceptable approach to demonstrate 

that the below-grade environment is aggressive or non-aggressive.

The groundwater environment that exists at Palisades has been reviewed in 

detail in the discussion for GALL IIA1.1-c above, and will not be repeated 

here.

Palisades groundwater water sample measurements, taken over the course 

of many years and during varying seasons, confirm that parameters have 

remained consistent and are well below threshold limits that could cause 

concrete degradation or corrosion of embedded steel (i.e., an aggressive 

environment does not exist). The rate of groundwater flow is not considered 

an aggressive flow rate. The conditions identified in NUREG-1801 as 

revised by ISG-03 are satisfied; therefore, aging management of cracking, 

loss of bond, loss of material (spalling, scaling) due to corrosion of 

embedded steel for below grade inaccessible concrete is not required.

In addition it is concluded that additional groundwater monitoring over the 

period of license extension is not necessary. Sampling to date has shown 

no variance in over 40 years and the chemical parameters are well below 

limits considered aggressive. It would require a significant environmental 

event to substantially affect the quality of groundwater in the vicinity of 

Palisades. A change in the environment due to a chemical release would be 

considered as an “abnormal event.” NUREG-1800, “Standard Review Plan 

for the Review of License Renewal Applications for Nuclear Power Plants,” 

states that aging effects from abnormal events need not be postulated 

specifically for license renewal.

3.5.2.2.1.2 Cracking, Distortion, and Increase in Component Stress Level due to 

Settlement; Reduction of Foundation Strength due to Erosion of 

Porous Concrete Subfoundations, if not Covered by Structures 

Monitoring Program

NUREG 1800 states that cracking, distortion, and increase in component 

stress level due to settlement could occur in PWR concrete and steel 

containments. Also, reduction of foundation strength due to erosion of 

porous concrete subfoundations could occur in all types of PWR 

containments. Some plants may rely on a de-watering system to lower the 

site ground water level. If the plant’s CLB credits a de-watering system, 
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NUREG-1801 recommends verification of the continued functionality of the 

de-watering system during the period of extended operation. NUREG-1801 

recommends no further evaluation if this activity is included in the scope of 

the applicant’s structures monitoring program. 

Cracks; distortion; increase in component stress level Due to 

Settlement (GALL IIA1.1-f)

Concrete structures can be affected by differential settlement between 

supporting foundations, within the building, or between buildings. For 

buildings experiencing significant settlement, cracks on structural members 

may be visibly detected. Cracks, distortion, and an increase in component 

stress level due to settlement are not considered as aging effects requiring 

management for the Palisades Primary Containment Structure since it is 

founded on highly dense, compacted sand, that remained after removal of 

the sand dunes for site preparation. (FSAR Section 2.3.4, Engineering 

Geology). The Palisades Primary Containment Structure did not require a 

de-watering system to control settlement, since subsurface conditions of 

dense compact sand and compacted backfill do not require such a system. 

For concrete structures founded on dense soil or backfill, if in the past 20 

years of experience for a structure, the total differential settlement 

experienced are well within the permissible limits for this type of structure 

and no settlement has manifested itself via cracked walls or cracked 

foundations, then it can be concluded that cracking due to settlement is not 

significant, and would not be applicable for the structure during the period of 

extended operation. No settlement monitoring program for Palisades 

structures has been formally implemented. In support of NUREG 0820, 

Integrated Plant Safety Assessment, Systematic Evaluation Program, 

Palisades Plant,...Final Report October 1982, the NRC evaluation for topics 

II-4.D, Stability of Slopes and II-4.F, Settlement of Foundations and Buried 

Equipment, provided NRC staff conclusions on the site conditions. On the 

settlement issue, the NRC concluded that, “the settlement of foundations 

and buried equipment will not be a safety problem of concern.” 

Reduction in foundation strength, cracking, differential settlement due 

to erosion of porous concrete subfoundation (GALL IIA1.1-g)

The Palisades primary containment base mat rests directly on native soil 

(dense fine sand). There is no porous concrete sub-foundation below the 

base mat. Therefore, erosion of porous sub-foundation cement by ground 
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water, a matter addressed in Section II A1 of NUREG 1801, is not an issue 

at the Palisades Plant. Palisades does not have a porous concrete 

foundation and has no subsurface drainage system, as was identified at 

other facilities in NRC Information Notice 97-11. In addition, natural 

groundwater movement in this area is from the plant site to Lake Michigan. 

The rate of groundwater flow estimated during site exploration and 

discussed in the FSAR Section 2.2.1, is 650 feet per year (0.074'/hr), which 

is not considered an aggressive flow rate. 

3.5.2.2.1.3 Reduction of Strength and Modulus of Concrete Structures due to 

Elevated Temperature

NUREG 1800 states that reduction of strength and modulus of elasticity due 

to elevated temperatures could occur in PWR concrete and steel 

containments. NUREG-1801 recommends further evaluation if any portion 

of the concrete containment components exceeds specified temperature 

limits, i.e., general area temperature 66°C (150°F) and local area 

temperature 93°C (200°F).

Reduction of strength and modulus due to elevated temperature 

(>150°F general; >200°F local)-Containment Shell Operating 

Temperature Evaluation (GALL IIA1.1-h)

Subsection CC-3400 of ASME Section III, Division 2, specifies the concrete 

temperature limits for normal operation or any other long-term period. The 

temperatures shall not exceed 150°F except for local areas, such as around 

penetrations, which are not allowed to exceed 200°F. If significant 

equipment loads are supported by concrete at temperatures exceeding 

150°F, an evaluation of the ability to withstand the postulated design loads 

is to be made.

Appendix A of ACI 349-85 specifies that for normal operation or any other 

long term period the concrete temperature shall not exceed 150 oF except 

for local areas, which are allowed to have increased temperatures not to 

exceed 200 oF. The Palisades containment shell reinforced concrete 

structures have general area temperatures less than 150oF during normal 

operation. FSAR Table 9-13, shows a maximum ambient design basis 

temperature of 104°F.

Analyses have determined that, due to the increased ambient containment 

shell temperatures specified in the EEQ program, the maximum boundary 

temperature in the main steam penetration room near the main steam 
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penetration increased from, 104°F to 110°F, and the reactor containment 

temperature near the main steam penetration increased from 104°F to 

110°F. The analysis concluded the maximum temperature of the concrete at 

the main steam penetration increased from 143°F to <179°F, which is less 

than the limit imposed by ACI 349 of 200°F and provides adequate margin.

The main steam and feedwater penetrations through containment shown on 

FSAR Figure 5.8-2 are provided with 6" of insulation between the pipe and 

the concrete shell, and fills the conical steel penetration closure that is 

welded to the containment liner plate. FSAR Figure 5.8-18 shows plots of 

thermal gradients at the main steam penetration. It shows the 143°F 

gradient at the liner plate in the penetration opening, which, based on the 

above EEQ discussion, could be <179°F. Temperatures at this localized 

area are less than the 200°F that is allowed at localized areas.

This situation is judged to be acceptable since local temperature is less 

than 200°F, and reinforcing steel exists around the penetrations to distribute 

compressive stresses due to heating. (Reference FSAR Section 5.8.6.4.1) 

It is, therefore, concluded that the conditions identified in GALL IIA1.1-h are 

satisfied and aging management of reduction of strength and modulus due 

to elevated temperature for containment shell concrete components is not 

required.

3.5.2.2.1.4 Loss of Material due to Corrosion in Inaccessible Areas of Steel 

Containment Shell or Liner Plate

NUREG 1800 states that loss of material due to corrosion could occur in 

inaccessible areas of the steel containment shell or the steel liner plate for 

all types of PWR containments. NUREG-1801 recommends further 

evaluation of plant-specific programs to manage this aging effect for 

inaccessible areas if specific criteria defined in NUREG-1801 cannot be 

satisfied.

NUREG-1801, Item IIA2.1-a, states that loss of material due to corrosion is 

not significant if four conditions are satisfied. Each condition, and a 

Palisades discussion for that condition, is itemized below:

1. Concrete meeting the requirements of ACI 318 or 349 and the guidance 

of 201.2R was used for the containment concrete in contact with the 

embedded containment shell or liner.
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The Palisades containment structure was designed and constructed in 

accordance with ACI-318-63, ACI-301-72 (proposed) and the ASME 

Pressure Vessel Code, Sections III, VIII and IX, 1965. (Reference FSAR 

Section 5.1.6.2). Palisades’ concrete, meeting the requirements of ACI 318 

(and is consistent with the guidance of 201.2R-77), was used for the 

containment concrete in contact with the embedded containment shell or 

liner, as discussed in FSAR Section 5.8.2 and Section 5.8.7.1 These 

materials produced an excellent high strength, dense, sound concrete. 

2. The concrete is monitored to ensure that it is free of penetrating cracks 

that provide a path for water seepage to the surface of the containment 

shell or liner.

The containment exterior concrete is monitored by the Palisades 

Containment Inservice Inspection Program to ensure that it is free of 

penetrating cracks that might provide a path for water seepage to the 

surface of the containment shell or liner. The containment interior 18" 

reinforced concrete floor placed over the containment bottom steel liner is 

monitored by the Palisades Structural Monitoring Program to ensure that 

penetrating cracks are not occurring. 

3. The moisture barrier, at the junction where the shell or liner becomes 

embedded, is subject to aging management activities in accordance with 

IWE requirements.

The moisture barrier, at the junction where the shell or liner becomes 

embedded, is subject to aging management activities in accordance with 

Palisades Containment Inservice Inspection Program requirements.

4. Borated water spills and water ponding on the containment concrete floor 

are not common and when detected are cleaned up in a timely manner.

Borated water spills and water ponding on the containment concrete floor 

are not common, and when detected, are cleaned up in a timely manner, in 

accordance with the Palisades Boric Acid Corrosion Program.

It is, therefore, concluded that corrosion is not significant for inaccessible 

areas of the containment liner.

3.5.2.2.1.5 Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated 

Temperature

NUREG 1800 states that loss of prestress forces due to relaxation, 

shrinkage, creep, and elevated temperature for PWR prestressed concrete 
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containments is a TLAA as defined in 10 CFR 54.3. TLAAs are required to 

be evaluated in accordance with 10 CFR 54.21(c).

See Section 4.5 for a more detailed discussion of this issue.

The Containment Inservice Inspection Program includes the requirements 

for periodic containment tendon surveillance. The program predicts 

time-dependent lower limits of the lift-off force (predicted lower limits, PLL) 

for each tendon subgroup by regression analysis of individual tendon 

surveillance data. The PLL calculations are revised at each inspection, as 

required by the program.

The program maintains trend lines of the data for each tendon surveyed. 

The program inspects a sample of tendons from each group (dome, vertical, 

and hoop) in each inspection interval to confirm that the trend lines remain 

within the tolerances of the predicted lower limits, and therefore that tendon 

prestresses will remain above their respective minimum required values 

(MRV) for the succeeding inspection interval. The program provides 

appropriate actions if surveillance data indicate that a trend line may cross 

its MRV.

3.5.2.2.1.6 Cumulative Fatigue Damage

NUREG 1800 states that, if included in the current licensing basis, fatigue 

analyses of containment steel liner plates and steel containment shells 

(including welded joints) and penetrations (including penetration sleeves, 

dissimilar metal welds, and penetration bellows) for all types of PWR 

containments are TLAAs as defined in 10 CFR 54.3. TLAAs are required to 

be evaluated in accordance with 10 CFR 54.21(c).

See Section 4.6.1 and Section 4.6.2 for more detailed discussions of the 

fatigue in the containment liner and penetrations, respectively.

Liner

The Palisades containment design relies on the liner to maintain a leak-tight 

containment. However, There are no design conditions under which the 

liner plate is relied upon to assist the concrete in maintaining the integrity of 

the structure. Forces are transmitted between the liner plate and the 

concrete through the anchorage system and through direct contact 

(pressure). At times, forces may also be transmitted by bond and/or friction. 

These forces cause, or are caused by, liner plate strains. The liner plate is 
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designed to withstand the predicted strains. The effect of concrete cracking 

on the liner plate has also been considered.

The 1/4 inch liner plate will yield when subjected to the effects of concrete 

creep and shrinkage, prestressing forces and high temperature. Because 

the liner plate shares deformation compatibility with the containment shell 

along the continuous angle anchors and because the shell is very stiff, 

these loads do not lead to a severe condition in the liner plate. The most 

significant contributor to what (if calculated) would have been the fatigue 

usage factor is a single end-of-design-life strain cycle due to a design basis 

accident. 

The cyclical load events that contribute to fatigue in the containment liner 

during the licensed operating period result in only insignificant fatigue usage 

factors. No changes in operation are anticipated during the extended 

licensed operating period that would increase the frequency of the 

contributing events. The resulting fatigue usage factors in the containment 

liner will therefore remain insignificant for the 60-year extended licensed 

operating period.

Penetrations

FSAR Section 5.8.3 and Section 5.8.6.4 describe design of both the “large 

penetrations” (personnel air lock and equipment hatch) and the “small 

penetrations” (escape air lock, piping, ventilation, and electrical 

penetrations) to limiting strain criteria for a set of design loads, including 

thermal loads and design basis accident (DBA) loads.

Although the FSAR Section 5.8.6.4.1 description states (1) that “The 

allowable value of stress intensity Sa was determined from Figure N 415(a) 

of the referenced ASME Code article,” and (2) that “For all load 

combinations, the strains in the pipe penetrations did not exceed [those for 

which an equivalent Sa would exceed] the values given in the ASME B&PV 

Code, Figure N 415(a),” it appears that the only event for which the 

N-415(a) stress criterion was used was the end-of-life design basis event. 

3.5.2.2.1.7 Cracking due to Cyclic Loading and SCC

NUREG 1800 states that cracking of containment penetrations (including 

penetration sleeves, penetration bellows, and dissimilar metal welds) due to 

cyclic loading or SCC could occur in all types of PWR and BWR 

containments. Cracking could also occur in vent line bellows, vent headers 

and downcomers due to SCC for BWR containments. A visual VT-3 
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examination would not detect such cracks. NUREG-1801 recommends 

further evaluation of the inspection methods implemented to detect these 

aging effects.

See Section 4.6.1 and Section 4.6.2 for more detailed discussions of the 

fatigue in the containment liner and penetrations, respectively.

No expansion bellows are required in the Palisades containment design. All 

piping and ventilation penetrations are of the rigid welded type and are 

solidly anchored to the containment shell, thus precluding any requirement 

for expansion bellows. (Reference FSAR Section 5.8.6.2.2) Stress 

concentrations around openings in the liner plate were calculated using the 

theory of elasticity. These stress concentrations were then reduced by 

thickening the liner plate around each penetration in accordance with the 

ASME B&PV Code, Section III, 1965.

Anchor bolts are provided as part of each penetration assembly. When the 

penetration assembly has no significant external loads, the anchors 

maintain the strain compatibility between the liner plate and the concrete. 

When significant loads are present, the anchors control the inward 

displacement of the liner plate. The stress level in the anchor bolts from 

external loads is in accordance with the AISC Code. (Reference FSAR 

Section 5.8.6.4.1)

Therefore, no further evaluation is required since these GALL Items are not 

applicable to Palisades’ design.

3.5.2.2.2 Class 1 Structures

3.5.2.2.2.1 ‘Aging of Structures not Covered by Structures Monitoring Program

NUREG 1800 states that NUREG-1801 recommends further evaluation of 

certain structure/aging effect combinations if they are not covered by the 

structures monitoring program. This includes (1) scaling, cracking, and 

spalling due to repeated freeze-thaw for Groups 1-3, 5, 7-9 structures; (2) 

scaling, cracking, spalling and increase in porosity and permeability due to 

leaching of calcium hydroxide and aggressive chemical attack for Groups 

1-5, 7-9 structures; (3) expansion and cracking due to reaction with 

aggregates for Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of 

bond, and loss of material due to corrosion of embedded steel for Groups 

1-5, 7-9 structures; (5) cracks, distortion, and increase in component stress 

level due to settlement for Groups 1-3, 5, 7-9 structures; (6) reduction of 
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foundation strength due to erosion of porous concrete subfoundation for 

Groups 1-3, 5-9 structures; (7) loss of material due to corrosion of structural 

steel components for Groups 1-5, 7-8 structures; (8) loss of strength and 

modulus of concrete structures due to elevated temperatures for Groups 

1-5; and (9) crack initiation and growth due to SCC and loss of material due 

to crevice corrosion of stainless steel liner for Groups 7 and 8 structures. 

Further evaluation is necessary only for structure/aging effect combinations 

not covered by the structures monitoring program.

Loss of Material (Spalling, Scaling) and Cracking due to Freeze - Thaw 

- (GALL IIIA3.1-a, III.A6.1-a, IIIA8.1-a) 

Accessible Areas: In accordance with NUREG-1801 as clarified by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Palisades Structural Monitoring Program to manage Loss 

of Material (spalling, scaling) and cracking due to freeze - thaw.

Inaccessible Areas: Palisades is located in an area with severe weathering 

conditions as noted on Figure 1 of ASTM C33-99. Freeze-thaw is not 

considered an aging mechanism for concrete components below the frost 

line (depth of 42 inches in accordance with Michigan Building Code).

The Palisades concrete structures and concrete are designed in 

accordance with ACI 318-63 and -71, and constructed using ingredients 

conforming to ACI and ASTM standards. Palisades specifications require all 

concrete to contain an air-entraining agent in sufficient quantity to maintain 

specified percentages based on nominal maximum size aggregate. For 

severe weather exposures, the air content identified varies from 3 to 5 

percent. Water/cement ratios, for concrete mixes, range from 0.45 to 0.46 

for the 4000 psi concrete used in the primary containment internal concrete 

construction, and in other PAL structures. Water/cement ratio for 3000 psi 

concrete used in the original Auxiliary Building and other original structures 

as previously identified, is 0.47, slightly above the recommended range.

Review of Operating Experience and Maintenance Rule Structures 

Monitoring results provide confirmation that freeze-thaw degradation of 

Palisades concrete has not occurred. 

As described in NUREG-1557 “Summary of Technical Information and 

Agreements from Nuclear Management and Resources Council [NUMARC] 

Industry Reports Addressing License Renewal,” freeze-thaw does not 

cause loss of material from reinforced concrete in foundations, and in above 
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and below grade exterior concrete, for plants located in a geographic region 

of negligible weathering conditions (weathering index <100 day-inch/yr). 

Similarly, freeze-thaw damage is not significant for reinforced concrete in 

foundations, and in above and below grade exterior concrete, for plants 

located in areas in which weathering conditions are considered severe 

(weathering index >500 day-inch/yr) or moderate (100-500 day-inch/yr), 

provided that the concrete mix design meets the air content (entrained air 

3-6%) and water-to-cement ratio (0.35-0.45) specified in ACI 318-63 or ACI 

349-85. Palisades water-cement ratios range between 0.45 and 0.47 and 

ACI 201.2R-77 (Reference 7.22) Section 1.4.2 recommends a not to 

exceed water-cement ratio of 0.50 for other than “thin” structures. In 

addition, at Palisades, the ground tends to freeze and stay frozen through 

the winter, which means that below grade concrete only is exposed, 

essentially, to one freeze-thaw cycle in a typical year. Since damage to 

concrete from freeze-thaw is related to repeated cycles of freeze-thaw as 

noted in EPRI Structural Tools, Rev1, Section 5.3.1.1, and no evidence of 

freeze-thaw damage has been identified in exposed concrete which is 

subjected to repeated cycles, it is concluded that below grade concrete will 

not experience damage or degradation.

Therefore, since these conditions for Palisades concrete are essentially 

satisfied, aging management is not required for below grade concrete. 

Increase in Porosity, Permeability, and Loss of Strength Due to 

Leaching -(GALL IIIA3.1-b, III.A6.1-b, IIIA8.1-b)

Accessible Areas: In accordance with NUREG-1801 as clarified by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Palisades Structural Monitoring Program to manage 

increase in porosity and permeability, loss of strength due to leaching of 

calcium hydroxide.

Inaccessible Areas: The Palisades concrete structures and concrete 

components are designed in accordance with ACI 318-63 and constructed 

using ingredients conforming to ACI and ASTM standards, which provide 

for a good quality, dense, well cured, and low permeability concrete. 

Cracking is controlled through proper arrangement and distribution of 

reinforcing bars.

Concrete structures and concrete components are constructed of a dense, 

well-cured concrete with an amount of cement suitable for strength 
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development, and achievement of a water-to-cement ratio (Palisades 

water/cement ratio 0.45), which is characteristic of concrete having low 

permeability. This is consistent with the recommendations and guidance 

provided by ACI 201.2R-77.

In addition, concrete components must be exposed to flowing water through 

the concrete component for this to be a significant issue. Natural 

groundwater movement in this area is from the plant site to Lake Michigan. 

The rate of groundwater flow estimated during site exploration and shown in 

the FSAR, is 650 feet per year (0.074 feet/hr), which is not considered an 

aggressive flow rate. Groundwater elevation at the plant site is the same as 

Lake Michigan (elevation corresponds with lake water level).

Leaching of Calcium Hydroxide is readily noticeable as white deposits that 

remain on the concrete surface after a solution of water-free lime from the 

concrete and carbon dioxide from the air is absorbed and dries. The 

Palisades Structural Monitoring Program inspects concrete surfaces for 

signs of leaching. No significant signs of leaching have been documented 

during these inspection walkdowns.

Therefore, the conditions identified in NUREG-1801 as revised by ISG-03 

are satisfied and aging management of increase in porosity and 

permeability, loss of strength due to leaching of calcium hydroxide for below 

grade inaccessible concrete is not required.

Increase in Porosity and Permeability, cracking, loss of material 

(spalling, scaling) due to Aggressive Chemical Attack (GALL III.A3.1-f, 

III.A4, III.A6.1-e, III.A8.1-e)

Accessible Areas: In accordance with NUREG-1801 as revised by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Structures Monitoring Program to manage increase in 

porosity and permeability, cracking, loss of material (spalling, scaling) due 

to aggressive chemical attack. 

Inaccessible Areas: A plant-specific aging management program is required 

for below-grade exterior reinforced concrete (basemat, embedded walls) if 

the environment is aggressive (pH < 5.5, chlorides >500 ppm, or sulfates > 

1500 ppm). Examination of representative samples of below-grade 

concrete, when excavated for any reason, is to be included as part of a 

plant-specific program. Note: Periodic monitoring of below-grade water 

chemistry (including consideration of potential seasonal variations) is an 
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acceptable approach to demonstrate that the below-grade environment is 

aggressive or non-aggressive.

At Palisades, design and construction of reinforced concrete provides for 

dense, well cured, and low permeability concrete that provides acceptable 

degree of protection against exposure of below grade exterior reinforced 

concrete to an aggressive environment. Cracking of concrete is controlled 

through proper arrangement and distribution of reinforcing bars. Continued 

or frequent cyclic exposure to the following aggressive environments is 

necessary for aggressive chemicals to cause a significant increase in 

porosity and permeability, cracking, loss of material (spalling, scaling):

Acidic solutions with pH < 5.5

Chloride solutions >500 ppm

Sulfate solutions >1500 ppm

Since aggressive chemicals are contained at plant sites, system leakage is 

possible that could cause the embedded steel to be exposed to chemicals 

beyond these limits. However, leaks are not expected to continue for the 

extensive periods required for degradation, and repairs would be completed 

prior to loss of intended function. It is not likely that leaks inside the 

structure would get outside to cause an aggressive chemical attack on 

embedded concrete.

An aggressive environment may also occur where embedded steel is 

exposed to aggressive aqueous solutions such as groundwater or 

aggressive water flow. Palisades groundwater water sample 

measurements, summarized below, have confirmed that parameters are 

well below threshold limits that could cause concrete degradation or 

corrosion of embedded steel (i.e., an aggressive environment does not 

exist). 

Palisades Groundwater Sampling from 1966 (18 Sampling Locations 

results), 1996 South Monitoring Well, and 2004 Well #14 at Palisades:

Chemistry/Year 1966 (18 locations) 1996 2004

pH Range 6.1-7.7

(> 5.5)

No reading 7.0
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Natural groundwater movement in this area is from the plant site to Lake 

Michigan. The rate of groundwater flow estimated during site exploration 

and described in the FSAR Section 2.2.1 Groundwater, is 650 feet per year 

(0.074 feet/hr), which is not considered an aggressive flow rate. 

Groundwater elevation at the plant site is the same as Lake Michigan 

(elevation corresponds with lake water level).

Lake Michigan water samples also confirm an aggressive environment 

does not exist.

Samples from 1962 to1966 of Lake Michigan water at or near the site and 

1992 and 2004 site results:

In addition, FSAR Chapter 2 - Table 2-12 - Analysis of Soil Samples shows 

that site soil pH of 9 samples ranged between 8.1 and 8.5, indicating that 

soil around and under site structures is also alkaline and does not present 

an aggressive environment for inaccessible concrete.

Chlorides - ppm Range 4.0-39

(<500)

23 139

Sulfates - ppm Range 9.47-33.17

(<1500)

15.2 11.5

Chemistry/Year 1962-1966 1992 2004

pH Range 

7.6 - 8.2

(>5.5)

8.2 7.9

Chlorides - 

ppm

Range 

5.0 - 32.0

(<500)

11.5 12

Sulfates - 

ppm

Range 

20.0 to 

28.0

(<1500)

29 24.4

Chemistry/Year 1966 (18 locations) 1996 2004
Page 3-286 

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In summary, Palisades groundwater water sample measurements have 

confirmed that parameters are well below threshold limits that could cause 

concrete degradation (i.e., an aggressive environment does not exist). The 

rate of groundwater flow is not considered an aggressive flow rate. The 

conditions identified in NUREG-1801 as revised by ISG-03 are satisfied; 

therefore, aging management of increased porosity and permeability, 

cracking, and loss of material (spalling, scaling) due to aggressive chemical 

attack of below grade inaccessible concrete is not required.

It is also concluded that it is not necessary to monitor groundwater 

chemistry over the period of license extension, since it is not credible to 

postulate that some environmental event will occur in the future that would 

affect the quality of groundwater in the vicinity of Palisades. A change in the 

environment due to a chemical release would be considered as an 

“abnormal event.” NUREG-1800, “Standard Review Plan for the Review of 

License Renewal Applications for Nuclear Power Plants,” states that aging 

effects from abnormal events need not be postulated specifically for license 

renewal.

Expansion and cracking due to reaction with aggregates - (GALL, 

IIIA3.1-c, IIIA4.1-b, IIIA6.1-c, IIIA8.1-c)

Accessible Areas: In accordance with NUREG-1801 as clarified by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Structural Monitoring Program to manage expansion and 

cracking due to reaction with aggregates.

Inaccessible Areas: The aggregate used in the concrete of the Palisades 

components did not come from a region known to yield aggregates 

suspected of or known to cause aggregate reactions. Materials for concrete 

used in Palisades structures and components were specifically 

investigated, tested and examined in accordance with pertinent ASTM 

standards. All aggregates used at Palisades conform to the requirements of 

ASTM C33 “Standard Specification of Concrete Aggregates.” Appendix XI 

of ASTM C33 identifies methods for evaluating potential reactivity of 

aggregates including ASTM C295, ASTM C289, ASTM C227, and ASTM 

C342. Low alkali Portland Cement (ASTM C150 Type II) was used in the 

concrete mixes used in all PAL concrete structures, which mitigates harmful 

expansion due to alkali aggregate reaction. (FSAR Section 5.8.2)
Page 3-287 

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Therefore, the conditions identified in NUREG-1801 as revised by ISG-03 

are satisfied and aging management of expansion and cracking due to 

reaction with aggregates for below grade inaccessible concrete is not 

required.

Cracking, Spalling, Loss of Bond, and Loss of Material Due to 

Corrosion of Embedded steel for Groups 1-5, 7-9 Structures

Accessible Areas: In accordance with NUREG-1801 as revised by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Structures Monitoring Program to manage cracking, loss 

of bond, and loss of material (spalling, scaling) due to corrosion of 

embedded steel.

Inaccessible Areas: A plant-specific aging management program is required 

if the below-grade environment is aggressive (pH < 5.5, chlorides >500 

ppm, or sulfates > 1500 ppm). Examination of representative samples of 

below-grade concrete, when excavated for any reason, is to be included as 

part of a plant-specific program. Note: Periodic monitoring of below-grade 

water chemistry (including consideration of potential seasonal variations) is 

an acceptable approach to demonstrate that the below-grade environment 

is aggressive or non-aggressive.

At Palisades, design and construction of reinforced concrete provides for 

dense, well cured, and low permeability concrete that provides acceptable 

degree of protection against exposure of the embedded steel (including, but 

not limited to, reinforcing steel, unistrut, nelson studs, anchorages 

consisting of steel shapes/plate, tendon sheaths, conduit, and steel 

pipes/drains), to an aggressive environment. Cracking of concrete is 

controlled through proper arrangement and distribution of reinforcing bars. 

Continued or frequent cyclic exposure to the following aggressive 

environments is necessary for aggressive chemicals to cause significant 

corrosion of embedded steel:

Acidic solutions with pH < 5.5

Chloride solutions >500 ppm

Sulfate solutions >1500 ppm

Since aggressive chemicals are contained at plant sites, system leakage is 

possible that could cause the embedded steel to be exposed to chemicals 

beyond these limits. However, leaks are not expected to continue for the 
Page 3-288 

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extensive periods required for degradation, and repairs would be completed 

prior to loss of intended function.

An aggressive environment may also occur where embedded steel is 

exposed to aggressive aqueous solutions such as groundwater or 

aggressive water flow. PAL groundwater water sample measurements have 

confirmed that parameters are well below threshold limits that could cause 

concrete degradation or corrosion of embedded steel (an aggressive 

environment does not exist). 

Palisades Groundwater Sampling from 1966 (18 Sampling Locations 

results), 1996 South Monitoring Well, and 2004 Well #14 at Palisades:

Natural groundwater movement in this area is from the plant site to Lake 

Michigan. The rate of groundwater flow estimated during site exploration 

and described in the FSAR Section 2.2.1 Groundwater, is 650 feet per year 

(0.074 feet/hr), which is not considered an aggressive flow rate. 

Groundwater elevation at the plant site is the same as Lake Michigan 

(elevation corresponds with lake water level).

Lake Michigan water samples also confirm an aggressive environment 

does not exist.

Samples from 1962 to1966 of Lake Michigan water at or near the site and 

1992 and 2004 site results: 

Chemistry/Year 1966 1996 2004

pH Range 6.1-7.7

(> 5.5)

No reading 7.0

Chlorides - ppm Range 4.0-39

(<500)

23 139

Sulfates - ppm Range 

9.47-33.17

(<1500)

15.2 11.5
Page 3-289 

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In addition, FSAR Chapter 2 - Table 2-12 - Analysis of Soil Samples shows 

that site soil pH of 9 samples ranged between 8.1 and 8.5, indicating that 

soil around and under site structures is also alkaline and does not present 

an aggressive environment for inaccessible concrete.

In summary, Palisades groundwater water sample measurements have 

confirmed that parameters are well below threshold limits that could cause 

concrete degradation or corrosion of embedded steel (an aggressive 

environment does not exist). The rate of groundwater flow is not considered 

an aggressive flow rate. The conditions identified in NUREG-1801 as 

revised by ISG-03 are satisfied; therefore, aging management of cracking, 

loss of bond, and loss of material (spalling, scaling) due to corrosion of 

embedded steel for below grade inaccessible concrete is not required.

It is also concluded that it is not necessary to monitor groundwater 

chemistry over the period of license extension, since it is not credible to 

postulate that some environmental event will occur in the future that would 

affect the quality of groundwater in the vicinity of Palisades. A change in the 

environment due to a chemical release would be considered as an 

“abnormal event.” NUREG-1800, “Standard Review Plan for the Review of 

License Renewal Applications for Nuclear Power Plants,” states that aging 

effects from abnormal events need not be postulated specifically for license 

renewal.

Chemistry/Year 1962-1966 1992 2004

pH Range 

7.6 - 8.2

(>5.5)

8.2 7.9

Chlorides - 

ppm

Range 

5.0 - 32.0

(<500)

11.5 12

Sulfates - 

ppm

Range 

20.0 to 

28.0

(<1500)

29 24.4
Page 3-290 

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Cracks, distortion, and increase in component stress level due to 

settlement for Groups 1-3, 5, 7-9 structures

Cracks, distortion, and an increase in component stress level due to 

settlement are not considered as aging effects requiring management for 

Palisades structures founded highly dense, compacted sand and/or 

compacted engineered fill. Palisades Structures Monitoring Program 

inspections include monitoring of cracking associated aging effects, 

irrespective of aging mechanisms. 

Concrete structures can be affected by differential settlement between 

supporting foundations, within the building, or between buildings. For 

buildings experiencing significant settlement, cracks on structural members 

may be visibly detected. Cracks, distortion, and an increase in component 

stress level due to settlement are not considered as aging effects requiring 

management for Palisades structural concrete commodities since they are 

founded on highly dense, compacted sand, that remained after removal of 

the sand dunes for site preparation or compacted backfill. 

None of the Palisades concrete structures require a de-watering system to 

control settlement, since subsurface conditions of dense compact sand and 

compacted backfill do not require such a system. 

In summary, for concrete structures founded on dense soil or backfill, if in 

the past 20 years of experience for a structure, the total differential 

settlement experienced are well within the permissible limits for this type of 

structure and no settlement has manifested itself via cracked walls or 

cracked foundations, then it can be concluded that cracking due to 

settlement is not significant, and would not be applicable for the structure 

during the period of extended operation. No settlement monitoring program 

for PAL structures was formally implemented. 

NUREG 0820, Integrated Plant Safety Assessment, Systematic Evaluation 

Program, Palisades Plant,...Final Report October 1982, Letter (NRC) 

LS05-81-04-020 for Docket No. 50-255; RE: SEP TOPICS II-4.D, 

STABILITY OF SLOPES AND II-4.F, SETTLEMENT OF FOUNDATIONS 

AND BURIED EQUIPMENT, provides results of staff inspections and 

conclusions on the site conditions. On the settlement issue, it was 

concluded that, “the settlement of foundations and buried equipment will not 

be a safety problem of concern.” 
Page 3-291 

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In conclusion, monitoring of accessible concrete for cracks and distortions 

to settlement will be performed in accordance with the Palisades Structures 

Monitoring Program. Inspection of inaccessible concrete is not required.

Reduction of foundation strength due to erosion of porous concrete 

subfoundation for Groups 1-3, 5-9 structures

The Palisades concrete structures are on native soil (dense fine sand) 

and/or engineered fill. There are no porous concrete sub-foundations below 

the building foundations. Therefore, erosion of porous sub-foundation 

cement by ground water is not an issue at the Palisades Plant. Palisades 

does not have a porous concrete foundation and no subsurface drainage 

system, as was identified at other facilities in NRC Information Notice 97-11. 

In addition, natural groundwater movement in this area is from the plant site 

to Lake Michigan. The rate of groundwater flow estimated during site 

exploration and shown in the FSAR, is 650 feet per year (0.074 feet/hr), 

which is not considered an aggressive flow rate. 

Loss of material due to corrosion of structural steel components for 

Groups 1-5, 7-8 structures

Structural Steel Commodities potentially subject to loss of material due to 

corrosion (crevice, pitting, general, MIC) credit the Structural Monitoring 

Program for aging management. 

Loss of strength and modulus of concrete structures due to elevated 

temperatures for Groups 1-5

For any concrete elements that exceed specified temperature limits, further 

evaluations are warranted. Appendix A of ACI 349-85 specifies the concrete 

temperature limits for normal operation or any other long-term period. The 

temperatures shall not exceed 150°F except for local areas that are allowed 

to have increased temperatures not to exceed 200°F.

General Description Of Auxiliary Building Concrete And Temperatures 

(GALL IIIA3.1-j)

Group 3 structures include Auxiliary, Diesel Generator, Radwaste, and 

Turbine Buildings: Switchgear Room, AFW Pumphouse, Utility/Piping 

Tunnels. The Water Treatment and Water Purity Buildings are also included 

in this GALL Group.

The Palisades auxiliary building houses: 

• Control room 
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• Emergency diesel generators and related auxiliaries

• New and spent fuel handling, storage and shipment facilities

• Radwaste, chemical and volume control equipment

• Safety Injection System (majority)

• Component Cooling System (majority)

• Containment Spray System (majority) 

None of the areas in the auxiliary building(s) have normal operating 

temperatures greater than 150°F. The bounding temperature in the 

Component Cooling Room 338 is 120°F, with other areas at or less than 

104°F. The spent fuel pool normal operating temperature is 125°F (Ref. 

FSAR 5.9.3.3). 

Therefore, no further evaluation is required for the Auxiliary Building.

General Description Of Containment Internal Concrete And Temperatures 

(GALL IIIA4.1-c)

The principal interior concrete structures and their temperature exposure 

are:

• The primary shield wall, which forms the reactor cavity is exposed to the 

highest temperature, 200°F at the cavity liner (further evaluation applies)

• Two steam generator compartments/less than 150°F 

• A refueling pool which is located between the steam generator 

compartments and above the reactor cavity/less than 150°F

• An enclosed sump under the reactor cavity/less than 150°F

• Major equipment supports including the steam generator pedestals/less 

than 150°F

• The containment floor slab/ less than 150°F 

The primary shield wall (bioshield) is essentially a circular cylinder, lined 

with 1⁄4” steel plate, with concrete ranging in thickness from 7' to 8', with the 

inner 10" thickness acting as a sacrificial shield. The sacrificial shield is not 

reinforced, except for three horizontal “bands/hoops” of reinforcing steel 

and is considered non-structural, non-load bearing concrete as evidenced 

by the existence of the plywood construction form 10" in from the liner (ref 

dwg C-153). The primary shield wall cooling coils are in the sacrificial 

concrete, 3" in from the 1⁄4” liner plate, with cooling coils looping radially 

outward to provide temperature control of a maximum of 165oF for the outer 
Page 3-293 

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region of reinforced concrete. Openings in the shield wall for the primary 

coolant pipelines are lined with 1⁄4” steel plate, with the space between the 

opening and the piping filled with non-structural concrete block for shielding.

The Shield Cooling System is designed to remove heat from the biological 

shield surrounding the reactor vessel thereby limiting the thermal stresses 

in the structural concrete. The system is designed to maintain structural 

concrete temperature below 165°F. The system is to assure that the 

concrete in the reactor cavity does not overheat and develop excessive 

thermal stress. FSAR Figures 9-5 and 9-6 show the temperature gradient 

through the shield wall and the temperature 10" in (sacrificial concrete) is 

less than 180oF and drops to 140oF at 80".

This is judged to be acceptable due to the fact that reductions in excess of 

10% in the compressive strength, tensile strength, and the modulus of 

elasticity only begins to occur in the range of 180oF to 200oF (Reference 

EPRI TR-103842 - Class I Structures License Renewal Industry Report; 

Revision 1 - Section 4.1.6). This is further supported by the fact that 180oF 

is also the value that the original Bechtel Palisades Plant design criteria 

states the structural concrete is not to exceed (FSAR Section 9.0). The 

temperature in the structural/load bearing portion of the bioshield is less 

than 180oF per FSAR figures 9.5 and 9.6. In addition, concrete mixes are 

designed in accordance with ACI 613 with 15% more compressive strength 

than the required design strength. (Specification No. 5935-C-30 for 

Furnishing and Delivery of Concrete).

Therefore, the conditions identified in NUREG-1801 are satisfied and aging 

management of reduction of strength and modulus due to elevated 

temperature for containment interior concrete components is not required.

Crack initiation and growth due to SCC and loss of material due to 

crevice corrosion of stainless steel liner for Groups 7 and 8 

structures. 

To foster SCC, a temperature threshold of 140 degrees F or a continuous 

temperature environment of 200 degrees F is necessary. The maximum 

temperature in the Auxiliary Building or Containment Building for 

fuel-related components is 125 degrees F. The normal temperature for the 

Spent Fuel Pool is maintained below 125 degrees F, and maximum allowed 

temperature are not to exceed 140 degrees F. Therefore, the temperature 
Page 3-294 

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threshold to foster stress corrosion cracking / IGA is not present, and no 

aging management is required.

3.5.2.2.2.2 Aging Management of Inaccessible Areas

NUREG 1800 states that cracking, spalling, and increases in porosity and 

permeability due to aggressive chemical attack and cracking, spalling, loss 

of bond, and loss of material due to corrosion of embedded steel could 

occur in below-grade inaccessible concrete areas. NUREG-1801 

recommends further evaluation to manage these aging effects in 

inaccessible areas of Groups 1-3, 5, 7-9 structures, if specific criteria 

defined in NUREG-1801 cannot be satisfied.

Increase in Porosity and Permeability, Cracking, Loss of Material 

(Spalling, Scaling) due to Aggressive Chemical Attack (GALL IIIA3.1-f, 

IIIA4-N/A, III.A6.1-e, IIIA8.1-e)

Accessible Areas: In accordance with NUREG-1801 as clarified by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Structural Monitoring Program to manage Increase in 

porosity and permeability, cracking, loss of material (spalling, scaling) due 

to aggressive chemical attack.

Inaccessible Areas: NUREG-1801 states that a plant-specific aging 

management program is required for below-grade exterior reinforced 

concrete (basemat, embedded walls) if the environment is aggressive (pH < 

5.5, chlorides >500 ppm, or sulfates > 1500 ppm). Examination of 

representative samples of below-grade concrete, when excavated for any 

reason, is to be included as part of a plant-specific program. Note: Periodic 

monitoring of below-grade water chemistry (including consideration of 

potential seasonal variations) is an acceptable approach to demonstrate 

that the below-grade environment is aggressive or non-aggressive.

At Palisades, the design and construction of reinforced concrete provides 

for dense, well cured, and low permeability concrete that provides an 

acceptable degree of protection against exposure of below-grade exterior 

reinforced concrete to an aggressive environment. Cracking of concrete is 

controlled through proper arrangement and distribution of reinforcing bars. 

Continued or frequent cyclic exposure to the following aggressive 

environments is necessary for aggressive chemicals to cause a significant 
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increase in porosity and permeability, cracking, loss of material (spalling, 

scaling):

Acidic solutions with pH < 5.5

Chloride solutions >500 ppm

Sulfate solutions >1500 ppm

Since aggressive chemicals are contained at plant sites, system leakage is 

possible that could cause the reinforced concrete to be exposed to 

chemicals beyond these limits. However, leaks are not expected to continue 

for the extensive periods required for degradation, and repairs would be 

completed prior to loss of intended function. It is not likely that leaks inside 

the structure would get outside to cause an aggressive chemical attack on 

embedded concrete.

An aggressive environment may also occur when reinforced concrete is 

exposed to aggressive aqueous solutions such as groundwater or 

aggressive water flow. Palisades groundwater water sample 

measurements, summarized below, have confirmed that parameters are 

well below threshold limits that could cause concrete degradation or 

corrosion of embedded steel (i.e., an aggressive environment does not 

exist). 

Palisades Groundwater Sampling Results from 1966, 1996, and 2004:

Chemistry/Year 1966 

(18 Locations)

1996 2004

pH Range 6.1-7.7

(> 5.5)

No reading 7.0

Chlorides - ppm Range 4.0-39

(<500)

23 139

Sulfates - ppm Range 

9.47-33.17

(<1500)

15.2 11.5
Page 3-296 

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Natural groundwater movement in this area is from the plant site to Lake 

Michigan. The rate of groundwater flow estimated during site exploration 

and described in the FSAR Section 2.2.1 Groundwater, is 650 feet per year 

(0.074 feet/hr), which is not considered an aggressive flow rate. 

Groundwater elevation at the plant site is the same as Lake Michigan 

(elevation corresponds with lake water level).

Lake Michigan water samples, listed below also confirm an aggressive 

environment does not exist.

Lake Michigan Water Sampling Results from 1962 to 1966, 1992, 2004: 

In addition, FSAR Table 2-12 - Analysis of Soil Samples, shows that site soil 

pH of nine samples ranged between 8.1 and 8.5, indicating that soil around 

and under site structures is also alkaline and does not present an 

aggressive environment for inaccessible concrete.

It is, therefore, concluded that Palisades groundwater water sample 

measurements have confirmed that parameters are well below threshold 

limits that could cause concrete degradation (an aggressive environment 

does not exist). The rate of groundwater flow is not considered an 

aggressive flow rate. The conditions identified in NUREG-1801 as revised 

by ISG-03 are satisfied; therefore, aging management of increased porosity 

and permeability, cracking, and loss of material (spalling, scaling) due to 

aggressive chemical attack of below grade inaccessible concrete is not 

required.

Chemistry/Year 1962-1966 1992 2004

pH Range 7.6 - 8.2

(>5.5)

8.2 7.9

Chlorides - ppm Range 5.0 - 32.0

(<500)

11.5 12

Sulfates - ppm Range 20.0 to 

28.0

(<1500)

29 24.4
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It is also concluded that formal groundwater monitoring over the period of 

license extension is unnecessary, since it is not credible to postulate that 

some environmental event will occur in the future that would substantially 

affect the quality of groundwater in the vicinity of Palisades. A change in the 

environment due to a chemical release would be considered as an 

“abnormal event.” NUREG-1800, “Standard Review Plan for the Review of 

License Renewal Applications for Nuclear Power Plants,” states that aging 

effects from abnormal events need not be postulated specifically for license 

renewal.

Cracking, Loss of Bond, Loss of Material (Spalling, Scaling)/Corrosion 

of Embedded Steel (GALL IIIA3.1-e, IIIA4.1-d, III.A6.1-d, IIIA8.1-d)

Accessible Areas: In accordance with NUREG-1801 as clarified by ISG-03, 

accessible reinforced concrete structures and components will be 

monitored by the Structural Monitoring Program to manage cracking, loss of 

bond, loss of material (spalling, scaling)/corrosion of embedded steel.

Inaccessible Areas: NUREG-1801 states that a plant-specific aging 

management program is required if the below-grade environment is 

aggressive (pH < 5.5, chlorides >500 ppm, or sulfates > 1500 ppm). 

Examination of representative samples of below-grade concrete, when 

excavated for any reason, is to be included as part of a plant-specific 

program. Note: Periodic monitoring of below-grade water chemistry 

(including consideration of potential seasonal variations) is an acceptable 

approach to demonstrate that the below-grade environment is aggressive 

or non-aggressive.

The groundwater environment that exists at Palisades has been reviewed in 

detail in the discussion for GALL IIA1.1-c, and will not be repeated here.

It is concluded that Palisades groundwater water sample measurements 

confirm that chemistry parameters are well below threshold limits that could 

cause concrete degradation or corrosion of embedded steel (i.e., an 

aggressive environment does not exist). The rate of groundwater flow is not 

considered an aggressive flow rate. The conditions identified in 

NUREG-1801 as revised by ISG-03 are satisfied; therefore, aging 

management of cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel for below grade inaccessible 

concrete is not required.
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It is also concluded that formal groundwater monitoring over the period of 

license extension is unnecessary, since it is not credible to postulate that 

some environmental event will occur in the future that would affect the 

quality of groundwater in the vicinity of Palisades. A change in the 

environment due to a chemical release would be considered as an 

“abnormal event.” NUREG-1800, “Standard Review Plan for the Review of 

License Renewal Applications for Nuclear Power Plants,” states that aging 

effects from abnormal events need not be postulated specifically for license 

renewal.

3.5.2.2.3 Component Supports

3.5.2.2.3.1 Aging of Supports not Covered by Structures Monitoring Program

NUREG-1801 recommends further evaluation of certain component 

support/aging effect combinations if they are not covered by the structures 

monitoring program. This includes (1) reduction in concrete anchor capacity 

due to degradation of the surrounding concrete, for Groups B1-B5 supports; 

(2) loss of material due to environmental corrosion, for Groups B2-B5 

supports; and (3) reduction/loss of isolation function due to degradation of 

vibration isolation elements, for Group B4 supports. Further evaluation is 

necessary only for structure/aging effect combinations not covered by the 

structures monitoring program.

NUREG-1801 Items III.B1.1.4-a, III.B1.2.3-a, III.B2.2-a, III.B3.2-a, 

III.B4.3-a, and III.B5.2-a discuss Aging Effect/Mechanism: Reduction in 

Anchor Bolt Capacity due to Local Concrete Degradation / Service Induced 

Cracking. NUREG-1801 requires further evaluation of this aging effect and 

mechanism if the Structures Monitoring Program does not have this aging 

effect and mechanism in-scope. The Palisades Structural Monitoring 

Program includes Local Concrete Degradation / Service Induced Cracking 

in-scope. Therefore no further evaluation is required.

NUREG-1801 Items III.B2.1-a, III.B3.1-a, III.B4.1-a, and III.B5.1-a discuss 

Aging Effect/Mechanism: Loss of Material due to Environmental Corrosion 

(i.e., pitting corrosion, general corrosion, etc.). NUREG-1801 requires 

further evaluation of this aging effect and mechanism if the Structures 

Monitoring Program does not have this aging effect and mechanism 

in-scope. The Palisades Structural Monitoring Program includes Loss of 

Material due to Environmental Corrosion (i.e., pitting corrosion, general 

corrosion, etc.) in-scope. Therefore no further evaluation is required.
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NUREG-1801 Item III.B4.2-a discusses Vibration Isolation Elements and 

Aging Effect/Mechanism: Reduction or Loss of Isolation Function due 

Radiation Hardening, Temperature, Humidity, Sustained Vibratory Loading. 

The Palisades Structural Monitoring Program is credited with age managing 

vibration isolation elements for the Emergency Diesel Generator. Therefore 

no further evaluation is required.

3.5.2.2.3.2 Cumulative Fatigue Damage due to Cyclic Loading

NUREG-1800 states that fatigue of component support members, anchor 

bolts, and welds for Groups B1.1, B1.2, and B1.3 component supports is a 

TLAA as defined in 10 CFR 54.3 only if a CLB fatigue analysis exists. 

TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). 

NUREG-1801 Items III.B1.1.1-c, and III.B1.2.1-c discuss Aging 

Effect/Mechanism: Cumulative Fatigue Damage due to Fatigue for ASME 

Class 1, 2, and 3 Component Supports. A TLAA is required if, as part of the 

current CLB, a fatigue analysis is performed for these supports. Palisades 

does not perform fatigue analysis for ASME Class 1, 2, or 3 Component 

Supports (i.e. support members, welds, bolted connections, and support 

anchorage to building structure). Therefore this item is not a TLAA at 

Palisades.

Note that certain Class 1 components have fatigue analyses that include 

their integral supports. These are addressed in Section 4.3 of the LRA.

3.5.2.2.4 Quality Assurance for Aging Management of Non-Safety Related 

Components

Quality Assurance Program applicability to non-safety-related components is 

addressed in Appendix B, Section 1.2.

3.5.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Containments, Structures, and Component Supports components. The section of 

the LRA that contains the TLAA review results is indicated in parenthesis.

• Fatigue (Section 4.6, Containment Liner Plate and Penetrations Load Cycles)

• Fatigue (Section 4.7.1, Crane Load Cycles)

• Loss of Preload (Section 4.5, Concrete Containment Tendon Prestress 

Analysis)
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3.5.3 Conclusion

The Containments, Structures, and Component Supports components that are subject to 

aging management review have been identified in accordance with the requirements of 10 

CFR 54.4. The aging management programs selected to manage aging effects for the 

Containments, Structures, and Component Supports components are identified in the 

summaries in Section 3.5.2.1 above.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.

Therefore, based on the demonstrations provided in Appendix B, the effects of aging 

associated with the Containments, Structures, and Component Supports components will 

be adequately managed so that there is reasonable assurance that the intended function(s) 

will be maintained consistent with the current licensing basis during the period of extended 

operation.
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Table 3.5.1 Summary of Aging Management 

Application for Renewed Operating Licenses

Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion

Common Components of All Types of PWR and BWR Containment3.5.1-01 Penetration sleeves, 

penetration bellows, and dissimilar metal welds

Cumulative fatigue damage (CLB fatigue analysis exists)

TLAA evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.5.2.2.1.6)

Further evaluation documented in Section 3.5.2.2.1.6.The aging mechanism fatigue is potentially applicable to many component types in the Structures and Component Supports Supergroup, but only selected components or locations require explicit analysis as TLAAs and/or warrant aging management for fatigue. The Palisades evaluation of these components is discussed in Section 4.6. Therefore, cumulative fatigue damage is not identified as an aging effect in Tables 3.5.2-1 through 3.5.2-10.below.

3.5.1-02 Penetration sleeves, bellows, 

and dissimilar metal welds. 

Cracking due to cyclic loading, or crack initiation and growth due to SCC

Containment ISI and Containment leak rate test

Yes, detection of aging effects is to be evaluated (see [SRP] subsection 3.5.2.2.1.7)

Further evaluation documented in Section 3.5.2.2.1.7.

3.5.1-03 Penetration sleeves, 

penetration bellows, and dissimilar metal welds

Loss of material due to corrosion

Containment ISI and Containment leak rate test

No

3.5.1-04 Personnel airlock and 

equipment hatch

Loss of material due to corrosion

Containment ISI and Containment leak rate test

No

3.5.1-05 Personnel airlock and 

equipment hatch

Loss of leak tightness in closed position due to mechanical wear of locks, hinges and closure mechanism

Containment leak rate test and Plant Technical Specifications

No
Page 3-302 

Application for Renewed Operating Licenses

3.5.1-06 Seals, gaskets, and moisture 

barriers

Loss of sealant and leakage through containment due to deterioration of joint seals, gaskets, and moisture barriers

Containment ISI and Containment leak rate test

No

PWR Concrete (Reinforced and Prestressed) and Steel ContainmentBWR Concrete (Mark II and III) and Steel (Mark I, II, and III) Containment3.5.1-07 Concrete elements: 

foundation, walls, dome. 

Aging of accessible and inaccessible concrete areas due to leaching of calcium hydroxide, aggressive chemical attack, and corrosion of embedded steel

Containment ISI Yes, if aging 

mechanism is significant for inaccessible areas (see [SRP] subsection 3.5.2.2.1.1)

Further evaluation documented in Section 3.5.2.2.1.1.

3.5.1-08 Concrete elements: foundation Cracks, distortion, and 

increases in component stress level due to settlement

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.1.2)

Further evaluation documented in Section 3.5.2.2.1.2.

3.5.1-09 Concrete elements: foundation Reduction in 

foundation strength due to erosion of porous concrete subfoundation

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.1.2)

Further evaluation documented in Section 3.5.2.2.1.2.

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-303 

Application for Renewed Operating Licenses

3.5.1-10 Concrete elements: 

foundation, dome, and wall 

Reduction of strength and modulus due to elevated temperature

Plant specific Yes, for any 

portions of concrete containment that exceed specified temperature limits (see [SRP] subsection 3.5.2.2.1.3)

Further evaluation documented in Section 3.5.2.2.1.3.

3.5.1-11 Prestressed containment: 

tendons and anchorage components

Loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

TLAA evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.5.2.2.1.5)

Further evaluation documented in Section 3.5.2.2.1.5.

3.5.1-12 Steel elements: liner plate, 

containment shell 

Loss of material due to corrosion in accessible and inaccessible areas

Containment ISI and Containment leak rate test

Yes, if corrosion is significant for inaccessible areas (see [SRP] subsection 3.5.2.2.1.4)

Further evaluation documented in Section 3.5.2.2.1.4.

3.5.1-13 BWR only3.5.1-14 Steel elements: protected by 

coating

Loss of material due to corrosion in accessible areas only

Protective coating monitoring and maintenance

No

3.5.1-15 Prestressed containment: 

tendons and anchorage components

Loss of material due to corrosion of prestressing tendons and anchorage components

Containment ISI No

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-304 

Application for Renewed Operating Licenses

3.5.1-16 Concrete elements: 

foundation, dome, and wall 

Scaling, cracking, and spalling due to freeze-thaw; expansion and cracking due to reaction with aggregate

Containment ISI No

3.5.1-17 BWR only3.5.1-18 BWR only3.5.1-19 BWR onlyClass 1 Structures

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-305 

Application for Renewed Operating Licenses

3.5.1-20 All Groups except Group 6: 

accessible interior/exterior concrete & steel components 

All types of aging effects

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.2.1)ISG-3 has clarified this wording as follows:No, if within the scope of the applicant’s structures monitoring program and a plant-specific aging management program is required for inaccessible areas as stated (see subsection 3.5.2.2.2.1)

Further evaluation documented in Section 3.5.2.2.2.1.

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-306 

Application for Renewed Operating Licenses

3.5.1-21 Groups 1-3, 5, 7-9: 

inaccessible concrete components, such as exterior walls below grade and foundation 

Aging of inaccessible concrete areas due to aggressive chemical attack, and corrosion of embedded steel

Plant-specific Yes, if an 

aggressive below-grade environment exists (see [SRP] subsection 3.5.2.2.2.2)ISG-3 has clarified this wording as follows:Yes, a plant-specific aging management program is required for inaccessible areas as stated (see subsection 3.5.2.2.2.2)

Further evaluation documented in Section 3.5.2.2.2.2.

3.5.1-22 Group 6: all accessible/ 

inaccessible concrete, steel, and earthen components

All types of aging effects, including loss of material due to abrasion, cavitation, and corrosion

Inspection of Water-Control Structures or FERC/US Army Corps of Engineers dam inspections and maintenance

No

3.5.1-23 Group 5: liners Crack initiation and 

growth from SCC and loss of material due to crevice corrosion

Water Chemistry Program and Monitoring of spent fuel pool water level

No

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-307 

Application for Renewed Operating Licenses

3.5.1-24 Groups 1-3, 5, 6: all masonry 

block walls 

Cracking due to restraint, shrinkage, creep, and aggressive environment

Masonry Wall No

3.5.1-25 Groups 1-3, 5, 7-9: foundation Cracks, distortion, and 

increases in component stress level due to settlement

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.1.2)

Further evaluation documented in Section 3.5.2.2.1.2.

3.5.1-26 Groups 1-3, 5-9: foundation Reduction in 

foundation strength due to erosion of porous concrete subfoundation

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.1.2)

Further evaluation documented in Section 3.5.2.2.1.2.

3.5.1-27 Groups 1-5: concrete Reduction of strength 

and modulus due to elevated temperature

Plant-specific Yes, for any 

portions of concrete that exceed specified temperature limits (see [SRP] subsection 3.5.2.2.1.3)

Further evaluation documented in Section 3.5.2.2.1.3.

3.5.1-28 Groups 7, 8: liners Crack Initiation and 

growth due to SCC; Loss of material due to crevice corrosion

Plant-specific Yes

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-308 

Application for Renewed Operating Licenses

Component Supports3.5.1-29 All Groups: support members: 

anchor bolts, concrete surrounding anchor bolts, welds, grout pad, bolted connections, etc.

Aging of component supports

Structures Monitoring

No, if within the scope of the applicant’s structures monitoring program (see [SRP] subsection 3.5.2.2.3.1)

Further evaluation documented in Section 3.5.2.2.3.1.

3.5.1-30 Groups B1.1, B1.2, and B1.3: 

support members: anchor bolts, welds

Cumulative fatigue damage (CLB fatigue analysis exists)

TLAA evaluated in accordance with 10 CFR 54.21(c)

Yes, TLAA (see [SRP] subsection 3.5.2.2.3.2)

Further evaluation documented in Section 3.5.2.2.3.2.

3.5.1-31 All Groups: support members: 

anchor bolts, welds

Loss of material due to boric acid corrosion

Boric acid corrosion No

3.5.1-32 Groups B1.1, B1.2, and B1.3: 

support members: anchor bolts, welds, spring hangers, guides, stops, and vibration isolators 

Loss of material due to environmental corrosion; loss of mechanical function due to corrosion, distortion, dirt, overload, etc.

ISI No

3.5.1-33 Group B1.1: high strength 

low-alloy bolts

Crack initiation and growth due to SCC

Bolting integrity No

Table 3.5.1 Summary of Aging Management Evaluations in Chapters II and III of NUREG-1801 for Structures and Component 

Supports

Item 

Number Component

Aging 

Effect/Mechanism

Aging 

Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-309 

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building

Application for Renewed Operating Licenses

- Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Building Framing - Carbon Steel, Protected(column, hanger, beam, truss, decking, floor grating or plate, catwalk, threaded fastener, concrete expansion bolt, column base plate, weld, etc.)

HELB ShieldingPipe Whip RestraintShelter/ ProtectionStructural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.A3.2-a 3.5.1-20 580, 

584, H

III.B5.1-b 3.5.1-31 583, A

Structural Monitoring Program

III.A3.2-a 3.5.1-20 580, AIII.B5.1-a 3.5.1-31 A

Building Framing - Concrete, Below Grade(wall footing, foundation, slab, grout, reinforcement, duct banks, cable pits, tunnels, etc.)

Flood ProtectionStructural Support for Safety Related

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, ACracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking / Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A
Page 3-310 

Application for Renewed Operating Licenses

Building Framing - Concrete, Exposed(foundations, concrete & masonry wall, beam, roof slab, grout, reinforcements, concrete around expansion & grouted anchors)

Flood ProtectionMissile BarrierRadiation ShieldingShelter/ ProtectionStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-311 

Application for Renewed Operating Licenses

Building Framing - Concrete, Protected(foundations, concrete & masonry wall, column, pedestal, beam, floor slab, grout, reinforcements, concrete around expansion & grouted anchors, cable pits, tunnels, etc.)

Direct FlowFire BarrierHELB ShieldingMissile BarrierPipe Whip RestraintRadiation ShieldingShelter/ ProtectionStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program 

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program 

III.B5.2-a 3.5.1-29 A

Flood Barrier - Carbon Steel, Exposed(water tight doors)

Flood ProtectionStructural Support for Safety Related

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program 

III.A3.2-a 3.5.1-20 580, C

Flood Barrier - Carbon Steel, Protected(water tight doors and gate)

Flood ProtectionStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Leak Tightness

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 531, H

Loss of Material Boric Acid Corrosion 

Program 

III.B5.1-b 3.5.1-31 583, C

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 580, C

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-312 

Application for Renewed Operating Licenses

Fuel Related Component - Carbon Steel, Protected(anchor bolts for SFP gates, liners, transfer tube appurtenances

Structural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 578, 

579, F

Fuel Related Component - Stainless, Protected(anchor bolts for SFP gates, liners, transfer tube appurtenances

Structural Support for Safety Related

Stainless Steel Plant Indoor Air 

(Ext)

Cracking None Required III.A5.2-b 3.5.1-23 535, G

Fuel Related Component - Stainless, Borated(liner plates, gates, transfer tube expansion bellows)

Expansion / SeparationFluid Pressure BoundaryStructural Support for Safety Related

Stainless Steel Treated Water 

(Ext)

Cracking None Required III.A5.2-b 3.5.1-23 535, ELoss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 523, 

578, A

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-313 

Application for Renewed Operating Licenses

HELB/MELB Component - Carbon Steel, Protected(doors, scuttle, blowout panels, floor drains & screens, guard pipes, louvers, whip restraints, bellows, spray shields, etc.)

Direct FlowFlood ProtectionHELB ShieldingPipe Whip Restraint

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Leak Tightness

Structural Monitoring Program

III.A3.2-a 3.5.1-20 532, H

Loss of Material Boric Acid Corrosion 

Program 

III.B5.1-b 3.5.1-31 583, C

Structural Monitoring Program

III.A3.2-a 3.5.1-20 580, C

HELB/MELB Component - Concrete, Protected(curbs & pipe whip restraint grout, concrete at locations of expansion & grouted anchors)

Flood ProtectionHELB ShieldingPipe Whip RestraintDirect Flow

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program 

III.A3.3-a 3.5.1-24 A

Cracking and Expansion 

Structural Monitoring Program 

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program 

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program 

III.A3.1-f 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B5.2-a 3.5.1-29 A

HVAC Component - Stainless, Protected(Control Room vestibule door)

Fluid Pressure BoundaryStructural Support for Safety Related

Stainless Steel Plant Indoor Air 

(Ext)

Cracking None Required III.A3.2-a 588, F

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-314 

Application for Renewed Operating Licenses

HVAC Component - Carbon Steel, Protected(Control Room vestibule door)

Fluid Pressure BoundaryStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Leak Tightness

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 533, H

Loss of Material Boric Acid Corrosion 

Program 

III.B5.1-b 3.5.1-31 583, C

Structural Monitoring Program

III.A3.2-a 3.5.1-20 580, C

HVAC Component - Concrete, Protected(Control Room vestibules, concrete & masonry walls, floors, ceilings)

Fluid Pressure BoundaryStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program 

III.A3.3-a 3.5.1-24 A

Cracking and Expansion 

Structural Monitoring Program 

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program 

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program 

III.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program 

III.B5.2-a 3.5.1-29 A

HVAC Component - Galvanized, Protected(damper & louver frames)

Fire BarrierStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B5.1-b 3.5.1-31 581, 

583, C

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 581, C

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-315 

Missile Shield - 

Application for Renewed Operating Licenses

Carbon Steel, Protected(steel doors and structural steel missile barrier)

Missile BarrierStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B5.1-b 3.5.1-31 583, C

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 580, C

Operator Access Component - Carbon Steel, Protected(stairs, floors, platforms, welds, bolted connections, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B5.1-b 3.5.1-31 583, A

Structural Monitoring Program

III.A3.2-a 3.5.1-20 A

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-316 

Application for Renewed Operating Licenses

Operator Access Component - Concrete, Protected(stairs, floors, platforms, concrete at locations of expansion & grouted anchors, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program 

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program 

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program 

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program 

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program 

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program 

III.B5.2-a 3.5.1-29 A

Operator Access Component - Galvanized, Protected(stairs, walkways, removable platform, welds, bolted connections)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B5.1-b 3.5.1-31 581, 

583, C

Structural Monitoring Program 

III.A3.2-a 3.5.1-20 581, A

Table 3.5.2-1 Structures and Component Supports - Auxiliary Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-317 

Table 3.5.2-2 Structures and Com

Application for Renewed Operating Licenses

ponent Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

ASME 1 Support - Containment - Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.1.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.1.1-b 3.5.1-31 A

ASME 1 Support - Containment - Concrete, Protected

Structural Support for Safety Related

Concrete Containment Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.1.4-a 3.5.1-29 A

ASME 1 Support - Containment - Sliding Material, Cont Cavity

Expansion/ SeparationStructural Support for Safety Related

Bronze Containment Air 

(Ext)

Loss of Material None Required III.A4.2-b 3.5.1-20 515, I

ASME 1 Support - Containment - Sliding Material, Protected

Expansion/ SeparationStructural Support for Safety Related

Bronze Containment Air 

(Ext)

Loss of Mechanical Function

None Required III.B1.1.3-a 3.5.1-32 515, I

ASME Class 1 Tubing Support - Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.1.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.1.1-b 3.5.1-31 583, A
Page 3-318 

Application for Renewed Operating Licenses

ASME 2 & 3 Support - Turbine (Water Treatment Area) - Carbon Steel, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

ASME 2 & 3 Support - Turbine (Water Treatment Area) - Concrete, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.2.3-a 3.5.1-29 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 583, A

ASME Class 2 & 3 Piping & Mechanical Component Support - Auxiliary Bldg, Cast Iron, Protected

Structural Support for Safety Related

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 582, F

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 582, F

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-319 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Auxiliary Bldg, Concrete, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.2.3-a 3.5.1-29 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Auxiliary Bldg, Galvanized, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 581, A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 581, 

583, A

ASME Class 2 & 3 Piping & Mechanical Component Support - Auxiliary Bldg, Sliding Material, Protected

Expansion/ SeparationStructural Support for Safety Related

Bronze Plant Indoor Air 

(Ext)

Loss of Mechanical Function

None Required III.B1.2.2-a 3.5.1-32 515, I

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Carbon Steel, Cont Cavity

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

III.B1.2.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-320 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

III.B1.2.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Concrete, Protected

Structural Support for Safety Related

Concrete Containment Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B1.2.3-a 3.5.1-29 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Galvanized, Cont Cavity

Structural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 581, A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 581, A

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Galvanized, Protected

Structural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

Boric Acid Corrosion Program 

III.B1.2.1-b 3.5.1-31 581, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-321 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Sliding Material, Protected

Expansion/ SeparationStructural Support for Safety Related

Bronze Containment Air 

(Ext)

Loss of Mechanical Function

None Required III.B1.2.2-a 3.5.1-32 515, I

ASME Class 2 & 3 Piping & Mechanical Component Support - Containment Bldg, Stainless, Borated

Structural Support for Safety Related

Stainless Steel Treated Water 

(Ext)

Loss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 567, 

587, C

ASME Class 2 & 3 Piping & Mechanical Component Support - Intake Structure Bldg, Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Intake Structure Bldg, Concrete, Protected

Structural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.2.3-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-322 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Intake Structure Bldg, Galvanized, Protected

Structural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Turbine Bldg, Carbon Steel, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Turbine Bldg, Concrete, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.2.3-a 3.5.1-29 A

ASME Class 2 & 3 Piping & Mechanical Component Support - Turbine Bldg, Galvanized, Protected

Structural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 581, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-323 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Turbine Bldg, Sliding, Protected

Expansion/ SeparationStructural Support for Safety Related

Bronze Plant Indoor Air 

(Ext)

Loss of Mechanical Function

None Required III.B1.2.2-a 3.5.1-32 515, I

ASME Class 2 & 3 Piping & Mechanical Component Support - Yard, Aluminum, Exposed

Structural Support for Safety Related

Aluminum Atmosphere/ 

Weather (Ext)

Loss of Material Boric Acid Corrosion 

Program 

501, F

ASME Class 2 & 3 Piping & Mechanical Component Support - Yard, Carbon Steel, Below Grade

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 518, A

ASME Class 2 & 3 Piping & Mechanical Component Support - Yard, Carbon Steel, Exposed

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program 

III.B1.2.1-a 3.5.1-32 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-324 

Application for Renewed Operating Licenses

ASME Class 2 & 3 Piping & Mechanical Component Support - Yard, Concrete, Exposed

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B1.2.3-a 3.5.1-29 A

Elec Component Support - Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B2.1-b 3.5.1-31 583, AIII.B3.1-b 3.5.1-31 583, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Auxiliary Bldg, Carbon Steel, Raw Water

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Raw Water (Ext) Loss of Material Structural Monitoring 

Program 

III.B2.1-a 3.5.1-29 594, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-325 

Application for Renewed Operating Licenses

Elec Component Support - Auxiliary Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program 

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Elec Component Support - Auxiliary Bldg, Concrete, Raw Water

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Raw Water (Ext) Reduction in Conc 

Anchor Capacity

Structural Monitoring Program 

III.B2.2-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-326 

Application for Renewed Operating Licenses

Elec Component Support - Auxiliary Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B2.1-b 3.5.1-31 581, AIII.B3.1-b 3.5.1-31 581, A

Structural Monitoring Program 

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Auxiliary Bldg, Galvanized, Raw Water

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Raw Water (Ext) Loss of Material Structural Monitoring 

Program 

III.B2.1-a 3.5.1-29 581, 

594, A

Elec Component Support - Containment Bldg, Carbon Steel, Containment Cavity

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B2.1-b 3.5.1-31 AIII.B3.1-b 3.5.1-31 A

Structural Monitoring Program 

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-327 

Application for Renewed Operating Licenses

Elec Component Support - Containment Bldg, Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program 

III.B2.1-b 3.5.1-31 AIII.B3.1-b 3.5.1-31 A

Structural Monitoring Program 

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Containment Bldg, Concrete, Protected

Structural Support for Safety Related

Concrete Containment Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Elec Component Support - Containment Bldg, Galvanized, Containment Cavity

Structural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 581, AIII.B3.1-b 3.5.1-31 581, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Containment Bldg, Galvanized, Protected

Structural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 581, AIII.B3.1-b 3.5.1-31 581, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Discharge Structure, Carbon Steel, Protected

Structural Support for Non-Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-328 

Application for Renewed Operating Licenses

Elec Component Support - Discharge Structure, Galvanized, Protected

Structural Support for Non-Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Intake Structure Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Intake Structure Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-329 

Application for Renewed Operating Licenses

Elec Component Support - Intake Structure Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Switch Yard Relay House Group Bldg, Carbon Steel, Protected

Structural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Switch Yard Relay House Group Bldg, Concrete, Protected

Structural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Elec Component Support - Switch Yard Relay House Group Bldg, Galvanized, Protected

Structural Support for Regulated Events

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-330 

Application for Renewed Operating Licenses

Elec Component Support - Turbine Bldg, Carbon Steel, Protected

Structural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Turbine Bldg, Concrete, Protected

Structural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Elec Component Support - Turbine Bldg, Galvanized, Protected

Structural Support for Regulated Events

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Yard, Carbon Steel, Exposed

Structural Support for Regulated Events

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B3.1-a 3.5.1-29 A

Elec Component Support - Yard, Concrete, Exposed

Structural Support for Regulated Events

Concrete Atmosphere/ 

Weather (Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B3.2-a 3.5.1-29 A

Elec Component Support - Yard, Galvanized, Exposed

Structural Support for Regulated Events

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B3.1-a 3.5.1-29 581, A

Elec Component Support - Yard, Galvanized, Raw Water

Structural Support for Regulated Events

Galvanized Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.B3.1-a 3.5.1-29 581, 

594, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-331 

Application for Renewed Operating Licenses

High Strength Bolting - Containment Building, Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Cracking Bolting Integrity Program III.B1.1.2-a 3.5.1-33 ALoss of Material ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program

III.B1.1.1-a 3.5.1-32 AIII.B1.2.1-a 3.5.1-32 A

Boric Acid Corrosion Program

III.B1.1.1-b 3.5.1-31 AIII.B1.2.1-b 3.5.1-31 A

Non-ASME Component Support - Auxiliary Bldg, Aluminum, Protected

Structural Support for Safety Related

Aluminum Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

VII.A1.1-a 3.3.1-11 503, F

Non-ASME Piping & Mechanical Component Support - Auxiliary Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 583, AIII.B4.1-b 3.5.1-31 583, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-332 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Auxiliary Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Auxiliary Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 581, 

583, A

III.B4.1-b 3.5.1-31 581, 

583, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Non-ASME Piping & Mechanical Component Support - Auxiliary Bldg, Stainless, Borated

Structural Support for Safety Related

Stainless Steel Treated Water 

(Ext)

Loss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 578, C

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-333 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Boiler Building, Carbon Steel, Protected

Structural Support for Non-Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Boiler Building, Concrete, Protected

Structural Support for Non-Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Aluminum, Protected

Structural Support for Non-Safety Related

Aluminum Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

502, F

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Carbon Steel, Containment Cavity

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 AIII.B4.1-b 3.5.1-31 A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-334 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 AIII.B4.1-b 3.5.1-31 A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Concrete Containment Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Galvanized, Containment Cavity

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 581, AIII.B4.1-b 3.5.1-31 581, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-335 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B2.1-b 3.5.1-31 581, AIII.B4.1-b 3.5.1-31 581, A

Structural Monitoring Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Non-ASME Piping & Mechanical Component Support - Containment Bldg, Stainless, Borated

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Stainless Steel Treated Water 

(Ext)

Loss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 567, 

587, C

Non-ASME Piping & Mechanical Component Support - Discharge Structure, Carbon Steel, Protected

Structural Support for Non-Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-336 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Discharge Structure, Cast Iron, Protected

Structural Support for Non-Safety Related

Cast Iron Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 582, F

Non-ASME Piping & Mechanical Component Support - Discharge Structure, Concrete, Protected

Structural Support for Non-Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Discharge Structure, Galvanized, Protected

Structural Support for Non-Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Non-ASME Piping & Mechanical Component Support - Feedwater Purity Bldg, Carbon Steel, Protected

Structural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-337 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Feedwater Purity Bldg, Concrete, Protected

Structural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Intake Structure Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Intake Structure Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-338 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Intake Structure Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Non-ASME Piping & Mechanical Component Support - Turbine Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Turbine Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-339 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Turbine Bldg, Galvanized, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Non-ASME Piping & Mechanical Component Support - Water Treatment Bldg, Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Water Treatment Bldg, Concrete, Protected

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-340 

Application for Renewed Operating Licenses

Non-ASME Piping & Mechanical Component Support - Yard, Carbon Steel, Exposed

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 AIII.B4.1-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Yard, Concrete, Exposed

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B2.2-a 3.5.1-29 AIII.B4.3-a 3.5.1-29 A

Non-ASME Piping & Mechanical Component Support - Yard, Galvanized, Exposed

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.B2.1-a 3.5.1-29 581, AIII.B4.1-a 3.5.1-29 581, A

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-341 

Application for Renewed Operating Licenses

Spent Fuel Storage Rack - Auxiliary Building, Boron Carbide, Borated Water

Radiation Shielding

Boron Carbide Treated Water 

(Ext)

Loss of Material None Required VII.A2.1-b 3.3.1-10 595, F

Spent Fuel Storage Rack - Auxiliary Building, Stainless Steel, Borated Water

Structural Support for Safety Related

Stainless Steel Treated Water 

(Ext)

Loss of Material Water Chemistry Program VII.A2.1-c 3.3.1-13 H

Table 3.5.2-2 Structures and Component Supports - Component Supports - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-342 

Table 3.5.2-3 Structures and Component Supports - Cont

Application for Renewed Operating Licenses

ainment - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Containment Shell & Base Slab - Containment Bldg, Carbon Steel, Protected(air locks, equipment hatch, liner plate, penetrations)

Heat SinkPressure Boundary/ Fission Product RetentionStructural Support for Safety RelatedStructural Support for Regulated Events

Carbon Steel Containment Air 

(Ext)

Loss of Leak Tightness

Containment Leakage Testing Program

II.A3.2-b 3.5.1-05 538, A

Loss of Material Boric Acid Corrosion 

Program

II.A1.2-a 3.5.1-12 577, A

Containment Inservice Inspection Program

II.A1.2-a 3.5.1-12 AII.A3.1-a 3.5.1-03 AII.A3.2-a 3.5.1-04 A

Containment Leakage Testing Program

II.A1.2-a 3.5.1-12 AII.A3.1-a 3.5.1-03 AII.A3.2-a 3.5.1-04 A

Containment Shell & Base Slab - Containment Bldg, Concrete, Below Grade(base mat, foundation, wall, embedded steel, etc.)

Pressure Boundary/ Fission Product RetentionRadiation ShieldingStructural Support for Safety RelatedShelter/ Protection

Concrete Soil (Ext) Change in Material 

Properties

None Required II.A1.1-b 3.5.1-07 572, A

II.A1.1-c 3.5.1-07 573, A

Cracking None Required II.A1.1-f 3.5.1-08 547, ACracking and Expansion

None Required II.A1.1-d 3.5.1-16 574, A

Cracking, Loss of Bond/Matl

None Required II.A1.1-e 3.5.1-07 573, A

Loss of Material None Required II.A1.1-a 3.5.1-16 575, A

None Required II.A1.1-c 3.5.1-07 573, A
Page 3-343 

Application for Renewed Operating Licenses

Containment Shell & Base Slab - Containment Bldg, Concrete, Exposed(dome, wall, base mat, embedded steel, etc.)

Heat SinkMissile BarrierPressure Boundary/ Fission Product RetentionRadiation ShieldingShelter / ProtectionStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Containment Inservice Inspection Program

II.A1.1-b 3.5.1-07 AII.A1.1-c 3.5.1-07 A

Cracking Containment Inservice 

Inspection Program

II.A1.1-a 3.5.1-16 A

Structural Monitoring Program

II.A1.1-f 3.5.1-08 547, A

Cracking and Expansion

Containment Inservice Inspection Program

II.A1.1-d 3.5.1-16 A

Cracking, Loss of Bond/Matl

Containment Inservice Inspection Program

II.A1.1-e 3.5.1-07 A

Loss of Material Containment Inservice 

Inspection Program

II.A1.1-a 3.5.1-16 AII.A1.1-c 3.5.1-07 A

Containment Shell & Base Slab - Containment Bldg, Elastomer, Protected(seals, gaskets, moisture barriers)

Pressure Boundary/ Fission Product RetentionShelter/ Protection

Elastomers Containment Air 

(Ext)

Change in Material Properties

Containment Inservice Inspection Program

II.A3.3-a 3.5.1-06 A

Containment Leakage Testing Program

II.A3.3-a 3.5.1-06 A

Cracking Containment Inservice 

Inspection Program

II.A3.3-a 3.5.1-06 A

Containment Leakage Testing Program

II.A3.3-a 3.5.1-06 A

Table 3.5.2-3 Structures and Component Supports - Containment - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-344 

Application for Renewed Operating Licenses

Containment Shell & Base Slab - Containment Bldg, Stainless Steel, Protected(fuel transfer tube and closure flange)

Heat SinkPressure Boundary/ Fission Product Retention

Stainless Steel Containment Air 

(Ext)

Loss of Material Containment Inservice 

Inspection Program

II.A3.1-a 3.5.1-03 570, A

Containment Leakage Testing Program

II.A3.1-a 3.5.1-03 570, A

Containment Shell Prestressing System - Containment Bldg, Carbon Steel, Exposed(includes tendons and anchorage components)

Pressure Boundary/ Fission Product RetentionStructural Support for Safety Related

Carbon Steel Atmosphere/ 

Weather (Ext)

Loss of Material Containment Inservice 

Inspection Program

II.A1.3-a 3.5.1-15 A

Table 3.5.2-3 Structures and Component Supports - Containment - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-345 

Table 3.5.2-4 Structures and Component Supports - Containment Interior Structures

Application for Renewed Operating Licenses

- Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Building Framing - Carbon Steel, Protected(column, beam, truss, platform, floor grating or plate, catwalk, bracing, threaded fastener, concrete expansion bolt, column base plate, welds, etc.)

Heat SinkHELB ShieldingPipe Whip RestraintStructural Support for Regulated EventsStructural Support for Safety RelatedSupport for Non-Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.A4.2-a 3.5.1-20 580, 

585, H

III.B5.1-b 3.5.1-29 A

Structural Monitoring Program

III.A4.2-a 3.5.1-20 580, A

Building Framing - Concrete, Containment Cavity(reactor shield walls including reinforcements, inserts, grouted anchors)

Heat SinkHELB ShieldingMissile BarrierRadiation ShieldingStructural Support for Safety Related

Concrete Containment Air 

(Ext)

Cracking and Expansion

Structural Monitoring Program

III.A4.1-b 3.5.1-20 A

Cracking, Loss of Bond/Material

Structural Monitoring Program

III.A4.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A4.1-a 3.5.1-20 A

Change in Material Properties

None Required III.A4.1-c 3.5.1-27 576, A
Page 3-346 

Application for Renewed Operating Licenses

Building Framing - Concrete, Protected(concrete & masonry wall, column, pedestal, beam, slab, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Direct FlowHeat SinkHELB ShieldingPipe Whip RestraintRadiation ShieldingStructural Support for Regulated EventsStructural Support for Non-Safety RelatedStructural Support for Safety Related

Concrete Containment Air 

(Ext)

Cracking Structural Monitoring 

Program

559, H

Cracking and Expansion 

Structural Monitoring Program

III.A4.1-b 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A4.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A4.1-a 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Fuel Related Component - Stainless, Protected(refueling cavity sump, containment sump liner and screen, transfer tube) 

Structural Support for Safety Related

Stainless Steel Containment Air 

(Ext)

Cracking None Required III.A5.2-b 3.5.1-23 535, ELoss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 578, 

587, A

Structural Monitoring Program

III.A5.2-b 3.5.1-23 596, E

Table 3.5.2-4 Structures and Component Supports - Containment Interior Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-347 

Application for Renewed Operating Licenses

Fuel Related Component - Carbon Steel, Protected(anchor bolts for refueling cavity liner and transfer tube appurtenances)

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Water Chemistry Program III.A5.2-b 3.5.1-23 578, 

579, F 

HELB/MELB Component - Carbon Steel, Protected (steel curbs, pipe whip restraints, spray shields, etc.)

HELB ShieldingPipe Whip RestraintStructural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B5.1-b 3.5.1-31 C

Structural Monitoring Program

III.A4.2-a 3.5.1-20 580, C

HELB/MELB Component - Concrete, Protected(curbs, sump, pipe whip restraint grout, concrete at locations of expansion & grouted anchors, etc.)

Direct FlowFlood ProtectionHeat SinkHELB ShieldingPipe Whip Restraint

Concrete Containment Air 

(Ext)

Cracking Structural Monitoring 

Program

H

Cracking and Expansion 

Structural Monitoring Program

III.A4.1-b 3.5.1-20 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A4.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A4.1-a 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-4 Structures and Component Supports - Containment Interior Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-348 

Application for Renewed Operating Licenses

HVAC Component - Carbon Steel, Protected (damper & louver mounting frames)

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B5.1-b 3.5.1-31 C

Structural Monitoring Program

III.A4.2-a 3.5.1-20 580, C

HVAC Component - Galvanized, Protected(damper & louver mounting frames)

Structural Support for Safety Related

Galvanized Containment Air 

(Ext)

Loss of Material Boric Acid Corrosion 

Program

III.B5.1-b 3.5.1-31 C

Structural Monitoring Program

III.A4.2-a 3.5.1-20 580, C

Missile Shield - Concrete, Containment Cavity(removable missile shield above reactor vessel)

Heat SinkMissile Barrier

Concrete Containment Air 

(Ext)

Cracking and Expansion 

Structural Monitoring Program

III.A4.1-b 3.5.1-20 A

Cracking, Loss of Bond/Material

Structural Monitoring Program

III.A4.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A4.1-a 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-4 Structures and Component Supports - Containment Interior Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-349 

Table 3.5.2-5 Structures and Component Supports - Discharge Structure

Application for Renewed Operating Licenses

- Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes

Building Framing - Cast Iron, Raw Water (sluice gates)

Structural Support for Non-Safety Related

Cast Iron Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 580, 

582, A

Building Framing - Discharge/Intake Crib - Carbon Steel, Raw Water(sluice gate, column, bracket, beam, bracing, threaded fastener, connector, weld, etc.)

Structural Support for Non-Safety Related

Carbon Steel Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 580, A

Building Framing - Concrete, Below Grade(wall, footing, foundation, slab, grout, reinforcement, trenches, cable pits, tunnels, etc.)

Structural Support for Non-Safety Related

Concrete Soil (Ext) Loss of Material None Required III.A6.1-a 3.5.1-22 571, A

III.A6.1-e 3.5.1-22 544, A

Change in Material Properties

None Required III.A6.1-b 3.5.1-22 557, A

III.A6.1-e 3.5.1-22 544, A

Cracking and Expansion

None Required III.A6.1-c 3.5.1-22 543, A

Cracking, Loss of Bond/Matl

None Required III.A6.1-d 3.5.1-22 544, A

Cracking None Required III.A6.1-f 3.5.1-22 547, A
Page 3-350 

Application for Renewed Operating Licenses

Building Framing - Concrete, Exposed (foundations, masonry & concrete wall, floor/ roof slab, grout, reinforcements, steel shapes, concrete around expansion & grouted anchors)

Structural Support for Non-Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties 

Structural Monitoring Program

III.A6.1-b 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Cracking Structural Monitoring 

Program

III.A6.3-a 3.5.1-24 AIII.A6.1-a 3.5.1-22 AIII.A6.1-f 3.5.1-22 A

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A6.1-d 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-5 Structures and Component Supports - Discharge Structure - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-351 

Application for Renewed Operating Licenses

Building Framing - Concrete, Raw Water (wall, footing, foundation, slab, grout, reinforcements)

Structural Support for Non-Safety Related

Concrete Raw Water (Ext) Change in Material 

Properties 

Structural Monitoring Program

III.A6.1-b 3.5.1-22 557, AIII.A6.1-e 3.5.1-22 A

Cracking Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-f 3.5.1-22 A

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-e 3.5.1-22 AIII.A6.1-h 3.5.1-22 A

Table 3.5.2-5 Structures and Component Supports - Discharge Structure - Summary of Aging Management Evaluation

Component Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-352 

Table 3.5.2-6 Structures and Component Supports - Feedwater Purity Building

Application for Renewed Operating Licenses

- Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Building Framing - Carbon Steel, Protected(column, beam, bracing, threaded fastener, concrete expansion bolt, column base plate, welds, etc.)

Structural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, A

Building Framing - Concrete, Below Grade(pedestal, grade beam, footing, foundation, slab, grout, reinforcement, trenches, cable pits, etc.)

Structural Support for Regulated Events

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, A
Page 3-353 

Application for Renewed Operating Licenses

Building Framing - Concrete, Exposed(foundations, masonry/ concrete wall, grout, reinforcement, concrete around expansion & grouted anchors, etc.)

Structural Support for Regulated Events

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-6 Structures and Component Supports - Feedwater Purity Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-354 

Application for Renewed Operating Licenses

Building Framing - Concrete, Protected(foundations, masonry/ concrete wall, column, pedestal, beam, slab, grout, reinforcement, concrete around expansion & grouted anchors, etc.)

Structural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Material

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-6 Structures and Component Supports - Feedwater Purity Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-355 

Table 3.5.2-7 Structures and Component Supports - Intake

Application for Renewed Operating Licenses

 Structure - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Building Framing - Carbon Steel, Raw Water(gates, guides, and trash racks)

Structural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 580, A

Building Framing - Cast Iron, Raw Water (Sluice Gates)

Structural Support for Regulated EventsStructural Support for Safety Related

Cast Iron Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 580, 

582, A

Building Framing - Galvanized, Raw Water(fasteners and anchor bolts)

Structural Support for Regulated EventsStructural Support for Safety Related

Galvanized Raw Water (Ext) Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 581, A
Page 3-356 

Application for Renewed Operating Licenses

Building Framing - Concrete, Below Grade(wall, foundation, slab, grout, reinforcement, trenches, cable pits, tunnels, etc.)

Shelter / ProtectionStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Soil (Ext) Loss of Material None Required III.A6.1-a 3.5.1-22 571, A

III.A6.1-e 3.5.1-22 544, A

Change in Material Properties

None Required III.A6.1-b 3.5.1-22 557, A

III.A6.1-e 3.5.1-22 544, A

Cracking and Expansion

None Required III.A6.1-c 3.5.1-22 543, A

Cracking, Loss of Bond/Matl

None Required III.A6.1-d 3.5.1-22 544, A

Cracking None Required III.A6.1-f 3.5.1-22 547, A

Table 3.5.2-7 Structures and Component Supports - Intake Structure - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-357 

Application for Renewed Operating Licenses

Building Framing - Concrete, Exposed (wall, beam, floor slab, roof slab, grout, reinforcements, grouted anchors, etc.)

Fire BarrierFlood ProtectionMissile BarrierShelter/ ProtectionStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A6.1-b 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Cracking Structural Monitoring 

Program

III.A6.3-a 3.5.1-24 AIII.A6.1-a 3.5.1-22 AIII.A6.1-f 3.5.1-22 A

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A6.1-d 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Reduction in concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-7 Structures and Component Supports - Intake Structure - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-358 

Application for Renewed Operating Licenses

Building Framing - Concrete, Protected (wall, beam, floor slab, grout, reinforcements, grouted anchors, etc.)

Direct FlowFlood ProtectionShelter/ ProtectionStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A6.3-a 3.5.1-24 AIII.A6.1-f 3.5.1-22 A

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A6.1-d 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Loss of Strength Structural Monitoring 

Program

III.A6.1-b 3.5.1-22 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Building Framing - Concrete, Raw Water (wall, column, beam, footing, foundation slab, floor slab, grout, reinforcements, etc.)

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Raw Water (Ext) Change in Material 

Properties

Structural Monitoring Program

III.A6.1-b 3.5.1-22 AIII.A6.1-e 3.5.1-22 A

Cracking Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-f 3.5.1-22 A

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-a 3.5.1-22 AIII.A6.1-e 3.5.1-22 AIII.A6.1-h 3.5.1-22 A

Table 3.5.2-7 Structures and Component Supports - Intake Structure - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-359 

Application for Renewed Operating Licenses

Flood Barrier - Concrete, Protected(concrete interior wall in southeast corner)

Flood Protection

Concrete Plant Indoor Air 

(Ext)

Cracking and Expansion 

Structural Monitoring Program

III.A6.1-c 3.5.1-22 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program

III.A6.1-d 3.5.1-22 A

Loss of Material Structural Monitoring 

Program

III.A6.1-e 3.5.1-22 A

Loss of Strength Structural Monitoring 

Program

III.A6.1-b 3.5.1-22 A

HELB/MELB Component - Carbon Steel, Protected (steel curbs, floor drains, shields, etc.)

Direct FlowFlood ProtectionStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A6.2-a 3.5.1-22 580, C

HELB/MELB Component - Concrete, Protected(concrete / masonry wall, curbs, etc.)

Direct FlowFlood Protection

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A6.3-a 3.5.1-24 A

Cracking and Expansion 

Structural Monitoring Program (XI.S6)

III.A6.1-c 3.5.1-22 A

Cracking, Loss of Bond/Material 

Structural Monitoring Program (XI.S6)

III.A6.1-d 3.5.1-22 A

Loss of Material Structural Monitoring 

Program (XI.S6)

III.A6.1-e 3.5.1-22 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program (XI.S6)

III.B5.2-a 3.5.1-29 A

Table 3.5.2-7 Structures and Component Supports - Intake Structure - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-360 

Table 3.5.2-8 Structures and Component Supports - 

Application for Renewed Operating Licenses

Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Built-Up Roofing - Auxiliary Bldg - Tarred, Exposed

Shelter/ Protection

Built-up Roofing

Atmosphere/ Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Loss of Form Structural Monitoring 

Program

J

Loss of Material Structural Monitoring 

Program

J

Built-Up Roofing - Discharge Structure - Tarred, Exposed

Structural Support for Non-Safety Related

Built-up Roofing

Atmosphere/ Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Loss of Form Structural Monitoring 

Program

J

Loss of Material Structural Monitoring 

Program

J

Built-Up Roofing - Intake Structure Bldg - Tarred, Exposed

Shelter/ Protection

Built-up Roofing

Atmosphere/ Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Loss of Form Structural Monitoring 

Program

J

Loss of Material Structural Monitoring 

Program

J

Built-Up Roofing - Switch Yard Relay House Bldg - Tarred, Exposed

Structural Support for Regulated Events

Built-up Roofing

Atmosphere/ Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Loss of Form Structural Monitoring 

Program

J

Loss of Material Structural Monitoring 

Program

J
Page 3-361 

Application for Renewed Operating Licenses

Built-Up Roofing - Water Treatment Bldg - Tarred, Exposed

Structural Support for Non-Safety Related

Built-up Roofing

Atmosphere/ Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Loss of Form Structural Monitoring 

Program

J

Loss of Material Structural Monitoring 

Program

J

Crane - Auxiliary Bldg - Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Overhead Load Handling 

Systems Inspection Program

VII.B.1-b 3.3.1-16 BVII.B.2-a 3.3.1-16 B

Crane - Containment Bldg - Carbon Steel, Protected

Structural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Overhead Load Handling 

Systems Inspection Program

VII.B.1-b 3.3.1-16 BVII.B.2-a 3.3.1-16 B

Crane Lift Device - Containment Bldg - Carbon Steel, Protected

Structural Support for Non-Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Overhead Load Handling 

Systems Inspection Program

VII.B.1-b 3.3.1-16 D

Crane Support - Auxiliary Bldg - Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Overhead Load Handling 

Systems Inspection Program

VII.B.1-b 3.3.1-16 B

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-362 

Application for Renewed Operating Licenses

Crane Support - Containment Bldg - Carbon Steel, Protected

Structural Support for Non-Safety RelatedStructural Support for Safety Related

Carbon Steel Containment Air 

(Ext)

Loss of Material Overhead Load Handling 

Systems Inspection Program

VII.B.1-b 3.3.1-16 B

Fire Barrier - Auxiliary Bldg - Carbon Steel, Protected

Fire Barrier Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Fire Protection Program VII.G.3-d 3.3.1-20 591, B

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-363 

Application for Renewed Operating Licenses

Fire Barrier - Auxiliary Bldg - Concrete, Exposed

Fire Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Fire Protection Program VII.G.3-b 3.3.1-30 BStructural Monitoring Program

VII.G.3-b 3.3.1-30 A

Cracking Fire Protection Program VII.G.3-b 3.3.1-30 B

Structural Monitoring Program

VII.G.3-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.3-b 3.3.1-30 BStructural Monitoring Program

VII.G.3-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.3-c 3.3.1-30 BStructural Monitoring Program

VII.G.3-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.3-b 3.3.1-30 B

Structural Monitoring Program

VII.G.3-b 3.3.1-30 A

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-364 

Application for Renewed Operating Licenses

Fire Barrier - Auxiliary Bldg - Concrete, Protected

Fire Barrier Concrete Plant Indoor Air 

(Ext)

Cracking Fire Protection Program VII.G.3-b 3.3.1-30 B

Structural Monitoring Program

VII.G.3-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.3-b 3.3.1-30 BStructural Monitoring Program

VII.G.3-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.3-c 3.3.1-30 BStructural Monitoring Program

VII.G.3-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.3-b 3.3.1-30 H

Structural Monitoring Program

VII.G.3-b 3.3.1-30 H

Fire Barrier - Auxiliary Bldg - Fire Stop, Protected

Fire Barrier Fire Stops 

[Sealant / Maranite]

Plant Indoor Air (Ext)

Cracking / Delamination

Fire Protection Program VII.G.3-a 3.3.1-20 592, B

VII.G.4-a 3.3.1-20 592, B

Loss of Material Fire Protection Program VII.G.3-a 3.3.1-20 H

VII.G.4-a 3.3.1-20 H

Separation Fire Protection Program VII.G.3-a 3.3.1-20 592, B

VII.G.4-a 3.3.1-20 592, B

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-365 

Application for Renewed Operating Licenses

Fire Barrier - Auxiliary Bldg - Fire Wrap, Protected

Fire Barrier Fire Wraps 

[Mineral-Wool Batts]

Plant Indoor Air (Ext)

Cracking Fire Protection Program JLoss of Material Fire Protection Program J

Fire Barrier - Containment Bldg - Carbon Steel, Protected

Fire Barrier Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Fire Protection Program VII.G.5-c 3.3.1-20 B

Fire Barrier - Containment Bldg - Concrete, Exposed

Fire Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Containment Inservice Inspection Program

II.A1.1-b 3.5.1-07 AII.A1.1-c 3.5.1-07 A

Cracking Containment Inservice 

Inspection Program

II.A1.1-a 3.5.1-16 A

Structural Monitoring Program

II.A1.1-f 3.5.1-08 A

Cracking and Expansion 

Containment Inservice Inspection Program

II.A1.1-d 3.5.1-16 A

Cracking, Loss of Bond/Material

Containment Inservice Inspection Program

II.A1.1-e 3.5.1-07 A

Loss of Material Containment Inservice 

Inspection Program

II.A1.1-a 3.5.1-16 AII.A1.1-c 3.5.1-07 A

Fire Barrier - Intake Structure Bldg - Carbon Steel, Protected

Fire Barrier Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Fire Protection Program VII.G.1-d 3.3.1-20 591, B

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-366 

Application for Renewed Operating Licenses

Fire Barrier - Intake Structure Bldg - Concrete, Exposed

Fire Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Fire Protection Program VII.G.1-b 3.3.1-30 BStructural Monitoring Program

VII.G.1-b 3.3.1-30 A

Cracking Fire Protection Program VII.G.1-b 3.3.1-30 B

Structural Monitoring Program

VII.G.1-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.1-b 3.3.1-30 BStructural Monitoring Program

VII.G.1-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.1-c 3.3.1-30 BStructural Monitoring Program

VII.G.1-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.1-b 3.3.1-30 B

Structural Monitoring Program

VII.G.1-b 3.3.1-30 A

Fire Barrier - Intake Structure Bldg - Fire Stop, Protected

Fire Barrier Fire Stops 

[Sealant / Maranite]

Plant Indoor Air (Ext)

Cracking / Delamination

Fire Protection Program VII.G.1-a 3.3.1-20 592, B

Loss of Material Fire Protection Program VII.G.1-a 3.3.1-20 HSeparation Fire Protection Program VII.G.1-a 3.3.1-20 592, B

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-367 

Application for Renewed Operating Licenses

Fire Barrier - Intake Structure Bldg - Fire Wrap, Protected

Fire Barrier Fire Wraps 

[Mineral-Wool Batts]

Plant Indoor Air (Ext)

Cracking Fire Protection Program JLoss of Material Fire Protection Program J

Fire Barrier - Turbine Bldg - Carbon Steel, Protected

Fire Barrier Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Fire Protection Program VII.G.2-d 3.3.1-20 B

Fire Barrier - Turbine Bldg - Concrete, Exposed

Fire Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.2-c 3.3.1-30 BStructural Monitoring Program

VII.G.2-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-368 

Application for Renewed Operating Licenses

Fire Barrier - Turbine Bldg - Concrete, Protected

Fire Barrier Concrete Plant Indoor Air 

(Ext)

Cracking Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.2-c 3.3.1-30 BStructural Monitoring Program

VII.G.2-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Fire Barrier - Turbine Bldg - Fire Stop, Protected

Fire Barrier Fire Stops 

[Sealant / Maranite]

Plant Indoor Air (Ext)

Cracking / Delamination

Fire Protection Program VII.G.2-a 3.3.1-20 592, B

Loss of Material Fire Protection Program VII.G.2-a 3.3.1-20 HSeparation Fire Protection Program VII.G.2-a 3.3.1-20 592, B

Fire Barrier - Turbine Bldg - Fire Wrap, Protected

Fire Barrier Fire Wraps 

[Mineral-Wool Batts]

Plant Indoor Air (Ext)

Cracking Fire Protection Program JLoss of Material Fire Protection Program J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-369 

Application for Renewed Operating Licenses

Fire Barrier - Water Treatment Bldg - Concrete, Exposed

Fire Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.2-c 3.3.1-30 BStructural Monitoring Program

VII.G.2-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-370 

Application for Renewed Operating Licenses

Fire Barrier - Water Treatment Bldg - Concrete, Protected

Fire Barrier Concrete Plant Indoor Air 

(Ext)

Cracking Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking and Expansion 

Fire Protection Program VII.G.2-b 3.3.1-30 BStructural Monitoring Program

VII.G.2-b 3.3.1-30 A

Cracking, Loss of Bond/Material

Fire Protection Program VII.G.2-c 3.3.1-30 BStructural Monitoring Program

VII.G.2-c 3.3.1-30 A

Loss of Material Fire Protection Program VII.G.2-b 3.3.1-30 B

Structural Monitoring Program

VII.G.2-b 3.3.1-30 A

Fire Barrier - Water Treatment Bldg - Fire Stop, Protected

Fire Barrier Fire Stops 

[Sealant / Maranite]

Plant Indoor Air (Ext)

Cracking / Delamination

Fire Protection Program VII.G.2-a 3.3.1-20 592, B

Loss of Material Fire Protection Program VII.G.2-a 3.3.1-20 HSeparation Fire Protection Program VII.G.2-a 3.3.1-20 592, B

Fire Barrier - Water Treatment Bldg - Fire Wrap, Protected

Fire Barrier Fire Wraps 

[Mineral-Wool Batts]

Plant Indoor Air (Ext)

Cracking Fire Protection Program JLoss of Material Fire Protection Program J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-371 

Application for Renewed Operating Licenses

Flood Barrier - Auxiliary Bldg - Elastomer, Protected

Flood Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Flood Barrier - Turbine Building - Elastomer, Protected

Flood Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

HELB/MELB & EQ Civil/ Structural Component - Auxiliary Bldg - Elastomer, Protected

Direct FlowFlood Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

HELB/MELB & EQ Civil/ Structural Component - Intake Structure Bldg - Elastomer, Protected

Direct FlowFlood Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program 

J

Cracking Structural Monitoring 

Program

J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-372 

Mech General 

Application for Renewed Operating Licenses

Component Support - Containment Bldg - Elastomer, Protected

Structural Support for Safety Related

Elastomers Containment Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Riprap - Yard - Soil, Submerged

Structural Support for Non-Safety Related

Soil Raw Water (Ext) Loss of 

Material/Form 

Structural Monitoring Program

III.A6.4-a 3.5.1-22 A

Roof Flashing - Auxiliary Bldg - Galvanized, Exposed

Shelter/ Protection

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 A

Roof Flashing - Intake Structure Bldg - Galvanized, Exposed

Shelter/ Protection

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program 

III.A6.2-a 3.5.1-22 A

Roof Flashing - Switchyard Relay House - Galvanized, Exposed

Structural Support for Regulated Events

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program 

III.A3.2-a 3.5.1-20 A

Seal, Gasket or Filler - Auxiliary Bldg - Elastomer, Exposed

Shelter/ Protection

Elastomers Atmosphere/ 

Weather (Ext)

Cracking Structural Monitoring 

Program 

J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-373 

Application for Renewed Operating Licenses

Seal, Gasket or Filler - Auxiliary Bldg - Elastomer, Protected

Direct FlowExpansion / SeparationFlood ProtectionShelter/ Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

III.B4.2-a 3.5.1-29 593, A

Cracking Structural Monitoring 

Program

III.B4.2-a 3.5.1-29 593, A

Seal, Gasket or Filler - Containment Bldg - Elastomer, Protected

Expansion / SeparationFlood ProtectionShelter/ Protection

Elastomers Containment Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Seal, Gasket or Filler - Discharge Structure - Elastomer, Exposed

Structural Support for Non-Safety Related

Elastomers Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program 

J

Seal, Gasket or Filler - Discharge Structure - Elastomer, Protected

Structural Support for Non-Safety Related

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program 

J

Seal, Gasket or Filler - Intake Structure Bldg - Elastomer, Exposed

Shelter/ Protection

Elastomers Atmosphere/ 

Weather (Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program 

J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-374 

Application for Renewed Operating Licenses

Seal, Gasket or Filler - Switchyard Relay House/ Switchgear/ Safeguard Bldg - Elastomer, Exposed

Shelter / ProtectionStructural Support for Regulated Events

Elastomers Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Seal, Gasket or Filler - Turbine Bldg - Elastomer, Exposed

Structural Support for Non-Safety Related

Elastomers Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Seal, Gasket or Filler - Turbine Bldg - Elastomer, Protected

Flood ProtectionShelter/ Protection

Elastomers Plant Indoor Air 

(Ext)

Change in Material Properties 

Structural Monitoring Program

J

Cracking Structural Monitoring 

Program

J

Table 3.5.2-8 Structures and Component Supports - Miscellaneous Structural and Bulk Commodities - Summary of Aging 

Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-375 

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures

Application for Renewed Operating Licenses

- Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Building Framing - Safeguard Bus/Switchgear - Carbon Steel, Protected (floor beam, panels, welds, threaded fasteners, concrete expansion bolt, etc.)

Structural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, A

Building Framing - Switchyard - Concrete, Below Grade(grade beam, footing, foundation, slab, grout, reinforcement, trenches, cable pits, tunnels, etc.)

Structural Support for Regulated Events

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, A
Page 3-376 

Application for Renewed Operating Licenses

Building Framing - Switchyard - Concrete, Exposed(masonry/ concrete wall, grout, reinforcements, foundations, concrete around expansion & grouted anchors, bus supports, etc.)

Structural Support for Regulated Events

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 544, A

Cracking Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-377 

Application for Renewed Operating Licenses

Building Framing - Switchyard - Concrete, Protected(masonry roof bearing walls, reinforcements, concrete around expansion & grouted anchors, etc.)

Structural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.1-h 3.5.1-25 AIII.A3.3-a 3.5.1-24 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Metal Roofing & Siding - Switchgear & Safeguard Bus - Carbon Steel, Exposed(flashing)

Structural Support for Regulated Events

Galvanized Atmosphere/ 

Weather (Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 581, C

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-378 

Missile Shield - 

Application for Renewed Operating Licenses

Yard - Concrete, Exposed (Tank vault roof, pavement over buried piping)

Missile Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 A

Structural Monitoring Program

III.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-379 

Application for Renewed Operating Licenses

Tank Foundations - Building & Yard - Concrete, Below Grade(concrete foundation)

Structural Support for Regulated EventsStructure Functional Support

Concrete Soil (Ext) Loss of Material None Required III.A8.1-a 3.5.1-20 571, A

III.A8.1-e 3.5.1-21 544, A

Change in Material Properties

None Required III.A8.1-b 3.5.1-20 557, A

III.A8.1-e 3.5.1-21 544, A

Cracking and Expansion

None Required III.A8.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A8.1-d 3.5.1-21 544, A

Cracking None Required III.A8.1-f 3.5.1-25 547, A

Tank Foundations - Building & Yard - Concrete, Exposed(concrete foundation)

Structural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere / 

Weather

Cracking Structural Monitoring 

Program

III.A8.1-a 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A8.1-a 3.5.1-20 A

Change in Material Properties

Structural Monitoring Program

III.A8.1-b 3.5.1-20 A

Cracking and Expansion

Structural Monitoring Program

III.A8.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl

Structural Monitoring Program

III.A8.1-d 3.5.1-21 A

Table 3.5.2-9 Structures and Component Supports - Switchyard and Yard Structures - Summary of Aging Management 

Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-380 

Table 3.5.2-10 Structures and Component Supports - Turbine Building

Application for Renewed Operating Licenses

- Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes

Building Framing - Boiler Buildings Area - Carbon Steel, Protected(column, hanger, beam, truss, decking, platform, floor grating or plate, catwalk, threaded fastener, concrete expansion bolt, column base plate, welds, etc.)

Structural Support for Non-Safety Related

Carbon Steel Plant Indoor air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 A

Building Framing - Boiler Buildings Area - Concrete, Below Grade(wall, pedestal, grade beam, footing, foundation, slab, grout, reinforcement, cable pits, tunnels, etc.)

Structural Support for Non-Safety Related

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, A
Page 3-381 

Application for Renewed Operating Licenses

Building Framing - Boiler Buildings Area - Concrete, Exposed(foundations, masonry/ concrete wall, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Structural Support for Non-Safety Related

Concrete Atmosphere / 

Weather (Ext)

Cracking Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 AIII.A3.3-a 3.5.1-24 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking and Expansion

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-382 

Application for Renewed Operating Licenses

Building Framing - Boiler Buildings Area - Concrete, Protected(foundations, concrete & masonry wall, column, beam, floor/roof slab, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Structural Support for Non-Safety Related

Concrete Plant Indoor Air 

(Ext)

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Cracking and Expansion

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.1-h 3.5.1-25 AIII.A3.3-a 3.5.1-24 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-383 

Application for Renewed Operating Licenses

Building Framing - Carbon Steel, Protected(column, beam, truss, decking, platform, floor grating or plate, catwalk, bracing, threaded fastener, concrete expansion bolt, column base plate, welds, etc.)

Flood ProtectionHELB ShieldingPipe Whip RestraintShelter/ ProtectionStructural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-384 

Application for Renewed Operating Licenses

Building Framing - Concrete, Below Grade(wall, pedestal, grade beam, footing, foundation, slab, grout, reinforcement, cable pits, tunnels, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-385 

Application for Renewed Operating Licenses

Building Framing - Concrete, Exposed(foundations, masonry/ concrete wall, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Flood ProtectionShelter/ ProtectionStructural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-386 

Application for Renewed Operating Licenses

Building Framing - Concrete, Protected (foundations, concrete & masonry wall, column, beam, floor/roof slab, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Flood ProtectionHELB ShieldingMissile BarrierShelter/ ProtectionStructural Support for Non-Safety RelatedStructural Support for Regulated EventsStructural Support for Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Building Framing - Sliding Material, Protected(vertical supports with sliding surfaces)

Expansion / Separation

Bronze Plant Indoor Air 

(Ext)

Loss of Material None Required III.A4.2-b 3.5.1-20 586, I

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-387 

Application for Renewed Operating Licenses

Building Framing - Water Treatment Area - Carbon Steel, Protected(column, beam, bracing, threaded fastener, weld, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, A

Building Framing - Water Treatment Area - Concrete, Below Grade(wall, pedestal, grade beam, footing, foundation, slab, grout, reinforcement, trenches, cable pits, tunnels, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Concrete Soil (Ext) Loss of Material None Required III.A3.1-a 3.5.1-20 571, A

III.A3.1-g 3.5.1-21 544, A

Change in Material Properties

None Required III.A3.1-b 3.5.1-20 557, A

III.A3.1-g 3.5.1-21 544, A

Cracking and Expansion

None Required III.A3.1-c 3.5.1-20 543, A

Cracking, Loss of Bond/Matl

None Required III.A3.1-e 3.5.1-21 544, A

Cracking None Required III.A3.1-h 3.5.1-25 547, A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-388 

Application for Renewed Operating Licenses

Building Framing - Water Treatment Area - Concrete, Exposed (foundations, wall, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-389 

Application for Renewed Operating Licenses

Building Framing - Water Treatment Area - Concrete, Protected(foundations, concrete/ masonry wall, beam, floor slab, grout, reinforcements, concrete around expansion & grouted anchors, etc.)

Structural Support for Regulated EventsStructural Support for Non-Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Reduction in Concrete Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Flood Barrier - Carbon Steel, Protected (flood doors, hatch, standpipe)

Flood ProtectionStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Leak Tightness 

Structural Monitoring Program

III.A3.2-a 3.5.1-20 531, H

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, C

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-390 

Application for Renewed Operating Licenses

HELB/MELB Component - Carbon Steel, Protected(curbs, floor drains, pipe whip restraints, spray shields, etc.)

Flood ProtectionHELB ShieldingPipe Whip RestraintStructural Support for Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, C

HELB/MELB Component - Concrete, Protected(concrete/ masonry wall, whip restraint grout, concrete around expansion & grouted anchors, etc.)

Flood ProtectionHELB ShieldingPipe Whip Restraint

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

HVAC Component - Carbon Steel, Protected(Control Room vestibule door)

Fluid Pressure BoundaryStructural Support for Non-Safety Related

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Leak Tightness 

Structural Monitoring Program

III.A3.2-a 3.5.1-20 533, H

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 580, C

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-391 

Application for Renewed Operating Licenses

HVAC Component - Concrete, Protected(Control Room vestibules, concrete & masonry walls, floors, ceilings)

Fluid Pressure BoundaryStructural Support for Non-Safety Related

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-392 

Missile Shield - 

Application for Renewed Operating Licenses

concrete, Exposed(concrete and/or masonry walls protecting CCW room door and containment escape hatch

Missile Barrier Concrete Atmosphere/ 

Weather (Ext)

Change in Material Properties

Structural Monitoring Program

III.A3.1-b 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-a 3.5.1-20 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-a 3.5.1-20 AIII.A3.1-f 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Missile Shield - Concrete, Protected(concrete/ masonry walls, floor, & roof protecting Control Room Door)

Missile Barrier Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-393 

Application for Renewed Operating Licenses

Operator Access Component - Carbon Steel, Protected(stairs, floors, platforms)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Carbon Steel Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 A

Operator Access Component - Concrete, Protected (stairs, floors, platforms, concrete at locations of expansion & grouted anchors, etc.)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Concrete Plant Indoor Air 

(Ext)

Cracking Structural Monitoring 

Program

III.A3.3-a 3.5.1-24 AIII.A3.1-h 3.5.1-25 A

Cracking and Expansion 

Structural Monitoring Program

III.A3.1-c 3.5.1-20 A

Cracking, Loss of Bond/Matl 

Structural Monitoring Program

III.A3.1-d 3.5.1-20 A

Loss of Material Structural Monitoring 

Program

III.A3.1-f 3.5.1-20 A

Loss of Strength Structural Monitoring 

Program

III.A3.1-b 3.5.1-20 A

Reduction in Conc Anchor Capacity

Structural Monitoring Program

III.B5.2-a 3.5.1-29 A

Operator Access Component - Galvanized, Protected (stairs, floors, platforms)

Structural Support for Non-Safety RelatedStructural Support for Regulated Events

Galvanized Plant Indoor Air 

(Ext)

Loss of Material Structural Monitoring 

Program

III.A3.2-a 3.5.1-20 581, A

Table 3.5.2-10 Structures and Component Supports - Turbine Building - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 

Line Item

Table 1 

Item Notes
Page 3-394 

Palisades Nuclear Plant

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Notes for Tables 3.5.2-1 through 3.5.2-10

A Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging 

management program. AMP has exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, aging 

effect and AMP. AMP has exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different AMP is 

credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific notes:

501 Aging effect/mechanism is applicable for SIRW Tank supports on roof of Auxiliary Building.

502 Aging effect/mechanism is applicable for permanent radiation shield support beam inside 

Containment Building pressurizer shed.

503 Aging effect/mechanism is applicable for new fuel racks adjacent to Spent Fuel Pool.

504 Not Used.

505 Not Used.

506 Not Used.

507 Not Used.

508 Not Used.

509 Not Used.

510 Not Used.
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511 Not Used.

512 Not Used.

513 Not Used.

514 Not Used.

515 Lubrite does not require Aging Management.

516 Not Used.

517 Not Used.

518 Aging effect/mechanism is applicable to the condensate storage tank valve pit supports.

519 Not Used.

520 Not Used.

521 Not Used.

522 Not Used.

523 Spent Fuel Pool Liner is susceptible to Crevice and Pitting Corrosion. GALL Item III.A5.2-b 

mandates Water Chemistry Program to manage contaminants. 

524 Not Used.

525 Not Used.

526 Not Used.

527 Not Used.

528 Not Used.

529 Not Used.

530 Not Used.

531 Aging Effect is applicable to Floor Doors.

532 Aging Effect is applicable to HELB Doors.

533 Aging Effect is applicable to Control Room Vestibule Doors.

534 Not Used.

535 Aging Effect is not applicable for Fuel Pool Liner since temperature threshold to initiate SCC 

is not present.

536 Not Used.

537 Not Used.
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538 “Loss of Leak Tightness/Mechanical Wear” AERM is only applicable for Pressure Boundary 

Intended Function.

539 Not Used.

540 Not Used.

541 Not Used.

542 Not Used.

543 See further evaluation. Cracking and Expansion due to aggregate reaction is not applicable. 

Palisades concrete aggregates were tested for reactivity and accepted. Aggregate came 

from source known not to be reactive. Therefore, inspection of inaccessible (below grade) 

concrete is not required. The Structures Monitoring Program will monitor this aging 

effect/mechanism for accessible (exposed to weather or protected) concrete.

544 Aging effect is not applicable. Palisades does not have an aggressive environment. 

Reinforcing and embedment steel are in sound, dense concrete.

545 Not Used.

546 Not Used.

547 See Further Evaluation discussion. Cracking due to settlement does not apply. No 

de-watering system is relied upon. There is no history of settlement and NRC Systematic 

Evaluation Program Topic II-4.F evaluation supports this conclusion. (See FSAR Table 1-3). 

Therefore, inspection of inaccessible (below grade) concrete is not required. The Structures 

Monitoring Program will monitor this aging effect/mechanism for accessible (exposed to 

weather or protected) concrete.

548 Not Used.

549 Not Used.

550 Not Used.

551 Not Used.

552 Not Used.

553 Not Used.

554 Not Used.

555 Not Used.

556 Not Used.
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557 PAL concrete design and construction is consistent with ACI 201.2R-77 recommendations. 

Concrete is dense, well cured, low permeability and adequately reinforced to control 

cracking. Leaching aging effect does not apply.

558 Not Used.

559 GALL Group 4-Containment internal Structures does not have entry for Masonry Walls. PAL 

has masonry wall enclosure inside containment.

560 Not Used.

561 Not Used.

562 Not Used.

563 Not Used.

564 Not Used.

565 Not Used.

566 Not Used.

567 Aging Effect and Mechanism is applicable to supports immersed in Borated Water in the 

Refueling Cavity and Water Chemistry Program controls contaminants to minimize 

possibility for Aging Effect and Mechanism to occur.

568 Not Used.

569 Not Used

570 Stainless Steel transfer tube with dissimilar metal weld to carbon steel penetration.

571 See further evaluation. Cracking of inaccessible (below grade) concrete due to freeze/thaw 

is not an AERM. Palisades water-to-cement ratio (3 -5%) and air content in the concrete mix 

design are per applicable ACI standards and no freeze-thaw degradation has been 

identified. Therefore, inspection of inaccessible (below grade) concrete is not required. The 

Structures Monitoring Program will monitor this aging effect/mechanism for accessible 

concrete exposed to weather.

572 See Further Evaluation discussion. Palisades concrete design and construction is 

consistent with ACI 201.2R-77 recommendations. Concrete is dense, well cured, low 

permeability and adequately reinforced to control cracking. Leaching aging effect does not 

apply. Therefore, inspection of inaccessible (below grade) concrete is not required. ASME 

Section XI Subsection IWL will monitor this aging effect for accessible (exposed to weather 

or protected) concrete.

573 See Further Evaluation discussion. This aging effect/mechanism is not applicable. 

Palisades does not have an aggressive ground water environment based on a long history 
Page 3-398 

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of ground water sampling results. Reinforcing and embedment steel are in sound, dense 

concrete. Therefore, inspection of inaccessible (below grade) concrete is not required. 

ASME Section XI Subsection IWL will monitor this aging effect/mechanism for accessible 

(exposed to weather or protected) concrete.

574 See Further Evaluation discussion. Cracking and Expansion due to aggregate reaction is 

not applicable. Palisades concrete aggregates were tested for reactivity and accepted. 

Aggregate came from a source known not to be reactive. Therefore, inspection of 

inaccessible (below grade) concrete is not required. ASME Section XI Subsection IWL will 

monitor this aging effect/mechanism for accessible (exposed to weather or protected) 

concrete.

575 See Further Evaluation discussion. Cracking of inaccessible (below grade) concrete due to 

freeze/thaw is not an AERM. Palisades water-to-cement ratio (3 - 5%) and air content in the 

concrete mix design are per applicable ACI standards, and no freeze-thaw degradation has 

been identified. Therefore, inspection of inaccessible (below grade) concrete is not required. 

ASME Section XI Subsection IWL will monitor this aging effect/mechanism for accessible 

(exposed to weather or protected) concrete.

576 Temperatures for reactor cavity concrete are designed to be below 165 F which is above 

150 F. Further evaluation has been performed to justify acceptability.

577 See Further Evaluation discussion. For embedded containment liner, the four conditions are 

satisfied with regards to concrete quality, concrete inspections for cracks are performed via 

IWE (external), and borated water spills are infrequent and identified and cleaned up in 

accordance with the Boric Acid Corrosion Program.

578 Technical Specification 3.7.14.1 includes a surveillance requirement to verify minimum 

spent fuel pool level.

579 Carbon steel anchor bolts supporting the SFP and reactor cavity liner plates are protected 

from corrosive environments by the liner plates. However, since leakage of the liners could 

expose the anchor bolts to pool environment, the programs credited to age manage the liner 

plates are also credited for the anchor bolts.

580 Protective coatings not credited in managing effects of aging.

581 Galvanized material is treated the same as carbon steel. No credit is taken for the 

galvanized coating.

582 Cast iron is considered consistent with carbon steel and is evaluated the same, but with the 

additional aging effect/mechanism of loss of material due to selective leaching also 

evaluated.
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583 GALL III.B5.1-b environment is inside PWR containment. Palisades will also manage boric 

acid wastage in the Auxiliary Building since it contains boric acid systems as well.

584 GALL III.A3.2-a does not address the mechanism of Boric Acid Wastage. Boric acid 

wastage of structural steel in the Auxiliary Building will be managed by the Boric Acid 

Corrosion Program.

585 GALL III.A4.2-a does not address the mechanism of Boric Acid Wastage. Boric acid 

wastage of structural steel in the Containment Building will be managed by the Boric Acid 

Corrosion Program.

586 Lubrite sliding surface for structural steel in the turbine building is a material and 

environment combination not addressed in the GALL. However, it is similar to GALL line 

item IIIA4.2-b (lubrite sliding surface for RPV support shoes in the containment building) so 

it is being aligned to that GALL line item. Per EPRI Structural Tools Section 9.3.1, Lubrite 

has no aging effects requiring management (AERM). This is contrary to GALL IIIA4.2-b that 

identifies lock-up due to wear as an AERM. This specific application is as a sliding seismic 

joint that does not see wear.

587 The primary environment for refueling cavity liner and transfer tube is containment air. 

However, since the refueling cavity is submerged in borated water during refueling, it is 

evaluated using a more conservative treated water environment category. The water 

chemistry program and SFP level monitoring (during refueling) well age manage the liner for 

Loss of Material due to crevice and pitting corrosion, consistent with GALL.

588 Stainless steel control room vestibule doors do not have any aging effects requiring 

management.

589 Not Used.

590 Not Used.

591 This component group also includes steel fire barriers as well as fire doors.

592 Fire stop materials consist of various sealants, including silicone, maranite and ceramic fiber 

insulation. Aging effect terminology used in GALL is slightly different but overall 

deterioration is the same (e.g., cracking due to shrinkage, separation due to shrinkage, 

etc.).

593 Aging effect terminology used in GALL for the Emergency Diesel Generators vibration 

isolation elements is slightly different, but overall deterioration is the same (e.g., cracking 

and change in material properties due to thermal exposure, etc.). Other elements included 

in this component (thermal expansion / seismic separation joint filler, gap or crack seal, etc.) 

are not addressed in the GALL.
Page 3-400 

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594 Normal Environment is plant indoor air for manholes and valve pits. A raw water 

environment was conservatively evaluated to address potential ground water intrusion.

595 Palisades neutron absorbing material consists of boron carbide sheathed in stainless steel, 

unlike Boral which consists of boron carbide and aluminum alloy.

596 The primary environment for the Containment sump liner and screen is Containment air. 

However, since portions of the sump are periodically wetted, it is evaluated using a more 

conservative environment of treated water. The Structural Monitoring Program will age 

manage the Containment sump liner and screen for loss of material due to crevice and 

pitting corrosion.
Page 3-401 

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3.6 Aging Management of Electrical and Instrumentation and Controls

3.6.1 Introduction

This section provides the results of the aging management review for those components 

identified in Section 2.5, Electrical and Instrumentation and Controls, as being subject to 

aging management review. The commodities containing those components, which are 

addressed in this section, are described above in Commodity Group Descriptions (Section 

2.5.1)

Table 3.6.1, Summary of Aging Management Evaluations in Chapter VI of NUREG-1801 for 

Electrical Components, provides the summary of the programs evaluated in NUREG-1801 

for the Electrical Component groups that are relied on for license renewal. This table uses 

the format described in Figure 3.0-1. Note that this table only includes those component 

groups that are applicable to a PWR.

3.6.2 Results

The following table summarizes the results of the aging management review for electrical 

commodities in the Electrical Components group: 

Table 3.6.2-1, Electrical Components - Electrical Commodity Groups - Summary of Aging 

Management Evaluation

The materials that specific components are fabricated from, the environments to which 

components are exposed, the potential aging effects requiring management, and the aging 

management programs used to manage these aging effects are provided for each of the 

above commodities in the following subsections of Section 3.6.2.1, Materials, Environment, 

Aging Effects Requiring Management and Aging Management Programs:

Section 3.6.2.1.1, Commodity: Electrical cables and connections not subject to 10 CFR 

50.49 EQ requirements

Section 3.6.2.1.2, Commodity: Electrical cables and connections used in instrumentation 

circuits not subject to 10 CFR 50.49 EQ requirements that are sensitive to reduction in 

conductor IR (ISG-15) (Nuclear Instrumentation and Radiation Monitoring Systems)

Section 3.6.2.1.3, Commodity: Electrical Portion of the Non-EQ Electrical and I&C 

Penetration Assemblies (Cables and Connections) 

Section 3.6.2.1.4, Commodity: Fuse Holders (ISG-5)

Section 3.6.2.1.5, Commodity: Non-Segregated Phase Bus and Connections (ISG-17)

Section 3.6.2.1.6, Commodity: High-Voltage Transmission Conductors (ISG-2)

Section 3.6.2.1.7, Commodity: High-Voltage Switchyard Bus and Connections (ISG-2)
Page 3-402 

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Section 3.6.2.1.8, Commodity: Inaccessible medium-voltage (2kV to 15kV) cables and 

connections not subject to 10 CFR 50.49 EQ requirements (ISG-18)

Section 3.6.2.1.9, Commodity: High-Voltage Insulators (ISG-2)

3.6.2.1 Materials, Environment, Aging Effects Requiring Management and Aging 

Management Programs

3.6.2.1.1 Commodity: Electrical cables and connections not subject to 10 CFR 

50.49 EQ requirements

Materials

The materials of construction for this electrical cables and connections 

commodity are:

• Insulation materials - various organic polymers

• Connector Pins - Various Materials

Environment

The cables and connections of this commodity are exposed to the following 

environments:

• Adverse localized environment caused by heat, radiation, or moisture in the 

presence of oxygen

• Borated Water Leakage

Aging Effects Requiring Management

The following aging effects, associated with the cables and connections of this 

commodity, require management:

• Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric 

strength leading to reduced IR

• Electrical failure caused by thermal/ thermoxidative degradation of organics

• Radiation-induced oxidation

• Moisture intrusion

• Corrosion of connector contact surfaces caused by intrusion of borated water
Page 3-403 

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Aging Management Programs

The following aging management programs manage the aging effects for the 

cables and connections of this commodity:

• Non-EQ Electrical Commodities Condition Monitoring Program

• Boric Acid Corrosion Program 

3.6.2.1.2 Commodity: Electrical cables and connections used in instrumentation 

circuits not subject to 10 CFR 50.49 EQ requirements that are sensitive 

to reduction in conductor IR (ISG-15) (Nuclear Instrumentation and 

Radiation Monitoring Systems)

Materials

The materials of construction for this sensitive instrument cables and 

connections commodity are:

• Insulation materials - various organic polymers

Environment

The cables and connections of this commodity are exposed to the following 

environments:

• Adverse localized environment caused by heat, radiation, or moisture in the 

presence of oxygen

Aging Effects Requiring Management

The following aging effects, associated with this sensitive instrument cables 

and connections of this commodity, require management:

• Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric 

strength leading to reduced IR

• Electrical failure caused by thermal/ thermoxidative degradation of organics

• Radiation-induced oxidation

• Moisture intrusion

Aging Management Programs

The following aging management programs manage the aging effects for the 

sensitive instrument cables and connections of this commodity:

• Non-EQ Electrical Commodities Condition Monitoring Program
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3.6.2.1.3 Commodity: Electrical Portion of the Non-EQ Electrical and I&C 

Penetration Assemblies (Cables and Connections)

Materials

The materials of construction for the electrical portion of this non-EQ 

penetration assembly commodity are:

• Insulation materials - various organic polymers

Environment

The electrical portions of this non-EQ penetration assembly commodity are 

exposed to the following environments:

• Adverse localized environment caused by heat, radiation, or moisture in the 

presence of oxygen

Aging Effects Requiring Management

The following aging effects, associated with the electrical portions of this 

non-EQ penetration assembly commodity, require management:

• Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric 

strength leading to reduced IR

• Electrical failure caused by thermal/ thermoxidative degradation of organics

• Radiation-induced oxidation

• Moisture intrusion

Aging Management Programs

The following aging management programs manage the aging effects for the 

electrical portions of this non-EQ penetration assembly commodity:

• Non-EQ Electrical Commodities Condition Monitoring Program

3.6.2.1.4 Commodity: Fuse Holders (ISG-5)

Materials

The materials of construction for this fuse holder commodity are:

• Phenolic

• Copper

• Aluminum 
Page 3-405 

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Environment

The components of this fuse holder commodity are exposed to the following 

environments:

• Adverse localized environment caused by heat, radiation, or moisture in the 

presence of oxygen.

Aging Effects Requiring Management

The following aging effects, associated with this fuse holder commodity, require 

management:

• Embrittlement

• Cracking

• Melting

• Discoloration

• Moisture intrusion

• Corrosion

Aging Management Programs

The following aging management programs manage the aging effects for this 

fuse holder commodity:

• None required

3.6.2.1.5 Commodity: Non-Segregated Phase Bus and Connections (ISG-17)

Materials

The materials of construction for this non-segregated phase bus commodity 

are:

• Various Metals

• Porcelain 

Environment

The non-segregated phase bus in this commodity is exposed to the following 

environments:

• Adverse localized environment caused by heat, radiation, or moisture in the 

presence of oxygen.
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Aging Effects Requiring Management

The following aging effects, associated with this non-segregated phase bus 

commodity, require management:

• Oxidation

• Loosening of bolted connections due to thermal cycling

• Corrosion due to moisture

Aging Management Programs

The following aging management programs manage the aging effects for this 

non-segregated phase bus commodity:

• Non-EQ Electrical Commodities Condition Monitoring Program

3.6.2.1.6 Commodity: High-Voltage Transmission Conductors (ISG-2)

Materials

The materials of construction for this high voltage transmission conductor 

commodity are:

• Aluminum

• Steel

Environment

The conductors of this high voltage transmission conductor commodity are 

exposed to the following environments:

• Atmosphere/Weather

Aging Effects Requiring Management

The following aging effects, associated with this high voltage transmission 

conductor commodity, require management:

• Loss of conductor strength

• Vibration

Aging Management Programs

The following aging management programs manage the aging effects for this 

high voltage transmission conductor commodity:

• None Required
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3.6.2.1.7 Commodity: High-Voltage Switchyard Bus and Connections (ISG-2)

Materials

The materials of construction for this high voltage switchyard bus and 

connections commodity are:

• Aluminum

• Stainless Steel (Bolting)

• Copper

Environment

The busses and connections of this high voltage switchyard bus and 

connections commodity are exposed to the following environments:

• Atmosphere/Weather

Aging Effects Requiring Management

The following aging effects, associated with this high voltage switchyard bus 

and connections commodity, require management:

• Connection Surface Oxidation

• Vibration

Aging Management Programs

The following aging management programs manage the aging effects for the 

high voltage switchyard bus and connections commodity:

• None Required

3.6.2.1.8 Commodity: Inaccessible medium-voltage (2kV to 15kV) cables and 

connections not subject to 10 CFR 50.49 EQ requirements (ISG-18)

Materials

The materials of construction for this inaccessible medium voltage cables and 

connections commodity are:

• Insulation materials - various organic polymers
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Environment

The cables and connections of this inaccessible medium voltage cables and 

connections commodity are exposed to the following environments:

• Adverse localized environment caused by exposure to moisture and voltage 

stress.

Aging Effects Requiring Management

The following aging effects, associated with this inaccessible medium voltage 

cables and connections commodity, require management:

• Formulation of water trees, localized damage leading to electrical failure 

(breakdown of insulation) caused by moisture intrusion and voltage stress.

Aging Management Programs

The following aging management programs manage the aging effects for this 

inaccessible medium voltage cables and connections commodity:

• Non-EQ Electrical Commodities Condition Monitoring Program

3.6.2.1.9 Commodity: High-Voltage Insulators (ISG-2)

Materials

The materials of construction for this high voltage insulator commodity are:

• Porcelain

• Cement

• Metal

Environment

The cables and connections of this high voltage insulator commodity are 

exposed to the following environments:

• Atmosphere/Weather

Aging Effects Requiring Management

The following aging effects, associated with this high voltage insulator 

commodity, require management:

• Surface Contamination

• Cracking
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Aging Management Programs

The following aging management programs manage the aging effects for this 

high voltage insulator commodity:

• None Required

3.6.2.2 Further Evaluation of Aging Management as Recommended by 

NUREG-1801

NUREG-1801 Volume 1 Tables provide the basis for identifying those programs 

that warrant further evaluation by the reviewer in the license renewal application. 

For the Electrical and Instrumentation and Controls, those programs are 

addressed in the following sections.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

Environmental qualification of electrical equipment is a TLAA as defined in 10 

CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 

54.21(c)(1). The evaluation of this TLAA is addressed separately in Section 

4.4.

10 CFR 50.49(e)(5) contains provisions for aging that require, in part, 

consideration of all significant types of aging degradation that can affect 

component functional capability. 10 CFR 50.49(e)(5) also requires component 

replacement or maintenance prior to the end of designated life, unless 

additional life is established through ongoing qualification. 10 CFR 50.49(k) 

and (l) permit different qualification criteria to apply based on plant vintage. 

Supplemental Environmental Qualification (EQ) regulatory guidance for 

compliance with these different qualification criteria is provided in the 

Regulatory Guide 1.89, Rev. 1, “Environmental Qualification of Certain Electric 

Equipment Important to Safety for Nuclear Power Plants”, the Division of 

Operating Reactors (DOR) Guidelines, and NUREG-0588.

The Palisades EEQ Program was established to demonstrate that certain 

electrical components located in harsh plant environment (that is, those areas 

of the plant that could be subject to the harsh environmental effects of loss of 

coolant accident [LOCA], high energy line breaks [HELB] or post-LOCA 

radiation) are qualified to perform their safety function operation in those harsh 

environments after the effects of in service aging. The EEQ Program manages 

applicable component thermal, radiation, and cyclic aging effects for the 

current operating license period using the qualification methods established 

by 10 CFR 50.49(f). 
Page 3-410 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

The Palisades Electrical Equipment Qualification Program allows re-analysis 

for maintaining qualification using the methods described above. In addition, 

the EEQ Program has procedural requirements in place to monitor and track 

aging effects of EQ equipment including cables. The requirements are listed 

below:

• Monitoring equipment condition and equipment performance 

• Monitoring environmental conditions of plant areas, and 

• Incorporating the results of testing and analysis into the plant maintenance 

and surveillance program.

The EEQ Program will continue to be implemented for the extended operating 

period in accordance with 10 CFR 50.49. Continuing the existing EEQ 

Program provides reasonable assurance that the aging effects will be 

managed and that the EQ components will continue to perform their intended 

functions for the period of extended operation. 

3.6.2.2.2 Quality Assurance for Aging Management of Non-Safety Related 

Components

Quality Assurance Program applicability to non-safety-related components is 

addressed in Appendix B, Section 1.2.

3.6.2.3 Time-Limited Aging Analysis

The time-limited aging analyses (TLAA) identified below are associated with the 

Electrical and Instrumentation and Controls components. The section of the LRA 

that contains the TLAA review results is indicated in parenthesis.

• Section 4.4, Environmental Qualification of Electrical Equipment

3.6.3 Conclusion

The Electrical and Instrumentation and Controls components that are subject to aging 

management review have been identified in accordance with the requirements of 10 CFR 

54.4. The aging management programs selected to manage aging effects for the Electrical 

and Instrumentation and Controls components are identified in the summaries in Section 

3.6.2.1 above.

A description of these aging management programs is provided in Appendix B, along with 

the demonstration that the identified aging effects will be managed for the period of 

extended operation.
Page 3-411 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Therefore, based on the demonstrations provided in Appendix B, the effects of aging 

associated with the Electrical and Instrumentation and Controls components will be 

adequately managed so that there is reasonable assurance that the intended function(s) will 

be maintained consistent with the current licensing basis during the period of extended 

operation.
Page 3-412 

Table 3.6.1 Summary of Aging Management Evaluations in

Application for Renewed Operating Licenses

 Chapter VI of NUREG-1801 for Electrical Components

Item 

Number Component

Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended Discussion

3.6.1-01 Electrical equipment subject to 

10 CFR 50.49 environmental qualification (EQ) requirements

Degradation due to various aging mechanisms

Environmental qualification of electric components

Yes, TLAA (see [SRP] subsection 3.6.2.2.1)

Further evaluation documented in Section 3.6.2.2.1.

3.6.1-02 Electrical cables and 

connections not subject to 10 CFR 50.49 EQ requirements

Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced insulation resistance (IR); electrical failure caused by thermal/ thermoxidative degradation of organics; radiolysis and photolysis (ultraviolet [UV] sensitive materials only) of organics; radiation-induced oxidation; moisture intrusion

Aging management program for electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

No This is being managed by the Non-EQ 

Electrical Commodities Condition Monitoring Program.
Page 3-413 

Application for Renewed Operating Licenses

3.6.1-03 Electrical cables used in 

instrumentation circuits not subject to 10 CFR 50.49 EQ requirements that are sensitive to reduction in conductor insulation resistance (IR)

Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced IR; electrical failure caused by thermal/ thermoxidative degradation of organics; radiationinduced oxidation; moisture intrusion

Aging management program for electrical cables used in instrumentation circuits not subject to 10 CFR 50.49 EQ requirements

No This is being managed by the Non-EQ 

Electrical Commodities Condition Monitoring Program.

3.6.1-04 Inaccessible medium-voltage 

(2K VAC to 15K VAC) cables (e.g., installed in conduit or direct buried) not subject to 10 CFR 50.49 EQ requirements 

Formation of water trees, localized damage leading to electrical failure (breakdown of insulation); water trees caused by moisture intrusion

Aging management program for inaccessible medium-voltage cables not subject to 10 CFR 50.49 EQ requirements

No This is being managed by the Non-EQ 

Electrical Commodities Condition Monitoring Program.

3.6.1-05 Electrical connectors not 

subject to 10 CFR 50.49 EQ requirements that are exposed to borated water leakage

Corrosion of connector contact surfaces caused by intrusion of borated water

Boric acid corrosion No This is being managed by the Boric Acid 

Corrosion Program.

Table 3.6.1 Summary of Aging Management Evaluations in Chapter VI of NUREG-1801 for Electrical Components

Item 

Number Component

Aging 

Effect/Mechanism

Aging Management 

Programs

Further 

Evaluation 

Recommended Discussion
Page 3-414 

Table 3.6.2-1 Electrical Components - Electrical Commodi

Application for Renewed Operating Licenses

ty Groups - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes

Electrical cables and connections not subject to 10 CFR 50.49 EQ Requirements

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Insulation materials - various organic polymers

Adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen

Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced IR; electrical failure caused by thermal/ thermoxidative degradation of organics; radiation-induced oxidation; moisture intrusion

Non-EQ Electrical Commodities Condition Monitoring Program

VI.A.1-a 3.6.1-02 A

Connector Pins -Various Metals

Borated Water Leakage

Corrosion of connector contact surfaces caused by intrusion of borated water

Boric Acid Corrosion Program

VI.A.2-a 3.6.1-05 A
Page 3-415 

Application for Renewed Operating Licenses

Electrical cables and connections used in instrumentation circuits not subject to 10 CFR 50.49 EQ Requirements that are sensitive to reduction in conductor IR(ISG-15)(Nuclear Instrumentation and Radiation Monitoring Systems)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Insulation materials - various organic polymers

Adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen

Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced IR; electrical failure caused by thermal/ thermoxidative degradation of organics; radiation-induced oxidation; moisture intrusion

Non-EQ Electrical Commodities Condition Monitoring Program

VI.A.1-b 3.6.1-03 A, 602

Electrical Portion of the Non-EQ Electrical and I&C Penetration Assemblies(Cables & Connections) 

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Insulation materials - various organic polymers

Adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen

Embrittlement, cracking, melting, discoloration, swelling, or loss of dielectric strength leading to reduced IR; electrical failure caused by thermal/ thermoxidative degradation of organics; radiation-induced oxidation; moisture intrusion

Non-EQ Electrical Commodities Condition Monitoring Program

VI.A.1-a 3.6.1-02 A, 604

Table 3.6.2-1 Electrical Components - Electrical Commodity Groups - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-416 

Application for Renewed Operating Licenses

Fuse Holders(ISG-5)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals.

Phenolic, Copper, Aluminum 

Adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen.

Embrittlement, cracking, melting, discoloration, moisture intrusion, corrosion

None required None None J, 601

Non-Segregated Phase Bus and Connections(ISG-17)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Various Metals, Porcelain 

Adverse localized environment caused by heat, radiation, or moisture in the presence of oxygen.

Oxidation, Loosening of bolted connections due to thermal cycling, Corrosion due to moisture

Non-EQ Electrical Commodities Condition Monitoring Program

None None J

High-Voltage Transmission Conductors(ISG-2)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Aluminum, Steel

Atmosphere/ Weather

Loss of conductor strength, Vibration

None Required None None J, 603

Table 3.6.2-1 Electrical Components - Electrical Commodity Groups - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-417 

Application for Renewed Operating Licenses

High-Voltage Switchyard Bus and Connections(ISG-2)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

AluminumStainless Steel (Bolting)Copper

Atmosphere/ Weather

Connection Surface Oxidation, Vibration

None Required None None J, 606

Inaccessible medium-voltage (2kV to 15kV) cables and connections not subject to 10 CFR 50.49 EQ Requirements(ISG-18)

Provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals

Insulation materials - various organic polymers

Adverse localized environment caused by exposure to moisture and voltage stress

Formulation of water trees, localized damage leading to electrical failure (breakdown of insulation) caused by moisture intrusion and voltage stress.

Non-EQ Electrical Commodities Condition Monitoring Program

VI.A.1-c 3.6.1-04 A

High-Voltage Insulators(ISG-2)

Insulate and support an electrical conductor

Porcelain, Cement, Metal

Atmosphere/ Weather

Surface Contamination, Cracking

None Required None None J, 605

Table 3.6.2-1 Electrical Components - Electrical Commodity Groups - Summary of Aging Management Evaluation

Component 

Type

Intended 

Function Material Environment

Aging Effect 

Requiring 

Management

Aging Management 

Programs

NUREG 

-1801 

Volume 2 Line Item

Table 1 

Item Notes
Page 3-418 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Notes for Table 3.6.2-1

A Consistent with NUREG-1801 item for component, material, environment, and aging effect. 

AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment, and aging effect. 

AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment, 

and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 for material, environment, and 

aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 for material, environment, aging effect but a different aging 

management program is credited.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material and environment 

combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is 

not applicable.

J Neither the component nor the material and environment combination is evaluated in 

NUREG-1801.

Plant-specific Notes:

601 The aging management review determined that there was no aging mechanism for the in 

scope fuse holders. No aging management program is required for this commodity group.

602 The scope of the program is limited to select non-EQ cables associated with process and 

area radiation monitoring instrumentation circuits. Non-EQ Radiation Monitoring & Neutron 

Instrumentation systems instrumentation circuit cables require a different program other 

than the one presented in NUREG-1801, Section 2, Item XI.E2. This program will be 

consistent with ISG-15.

603 Loss of conductor strength due to corrosion of ACSR transmission conductors is not 

considered a significant contributor to the aging of transmission conductors. Transmission 

conductor vibration would be caused by wind loading. Wind loading is accounted for in the 

initial design and field installation of transmission conductors and high-voltage insulators. 

No aging management activities are required for this commodity group.
Page 3-419 

Palisades Nuclear Plant

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Technical and Administrative Information

604 The Palisades analysis for the electrical penetration assembly electrical insulations contain 

cable and connection insulation materials similar to those of the cables, and are bounded by 

the cable insulation review and aging management criteria. 

605 Surface contamination is not an applicable aging mechanism. The buildup of surface 

contamination is not prevalent at Palisades to be an aging mechanism. Cracking is not an 

applicable aging mechanism. Cracking or breaking of porcelain insulators is typically 

caused by physical damage, which is event driven rather than an age-related mechanism. 

No aging management activities are required for this commodity group.

606 Connection surface oxidation is not an applicable aging effect. Vibration is not an applicable 

aging mechanism since switchyard bus has no connections to moving or vibrating 

equipment. No aging management is required for this commodity group.
Page 4-1 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

4.0 Time-Limited Aging Analyses

10 CFR 54.21(c)(1) requires that each application for renewal of a plant operating license include a 

list of time-limited aging analyses, and a demonstration for each that, either:

“(i) The analyses remain valid for the period of extended operation;

 (ii) The analyses have been projected to the end of the period of extended operation; or

 (iii) The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.” 

10 CFR 54.3 defines Time Limited Aging Analyses as follows:

“Time-limited aging analyses, for the purposes of this part, are those licensee calculations and 

analyses that:

(1) Involve systems, structures, and components within the scope of license renewal, as 

delineated in §54.4(a);

(2) Consider the effects of aging;

(3) Involve time-limited assumptions defined by the current operating term, for example, 

40 years;

(4) Were determined to be relevant by the licensee in making a safety determination;

(5) Involve conclusions or provide the basis for conclusions related to the operability of the 

system, structure, and component to perform its intended functions, as delineated in §54.4(b); 

and

(6) Are contained or incorporated by reference in the CLB.”

This section identifies those issues that would be defined as Time-Limited Aging Analyses (TLAAs) 

in accordance with 10 CFR 54.21(c)(1), and, therefore, require explicit evaluation and discussion in 

the License Renewal Application (LRA) for Palisades. It also documents the conclusions of 

technical evaluations performed for each TLAA. 

4.1 Identification of Time-Limited Aging Analyses

This section discusses the process used to identify and evaluate TLAAs and exemptions 

applicable to Palisades.

4.1.1 Process for Identification of Time-Limited Aging Analyses 

The process for identifying TLAAs to be addressed by the Palisades License Renewal 

Application utilized extensive searches of the plant CLB, various NRC and industry 

documents, and LRAs from other applicants.
Page 4-2 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

4.1.1.1 CLB Search for TLAAs

10 CFR 54.3 defines 6 criteria, all of which must be satisfied in order for a 

calculation or analysis to be classified as a TLAA. Criterion 6 of the TLAA 

definition indicates that a calculation or analysis must be contained or 

incorporated by reference in the CLB. By this definition, any calculation or 

analysis that is not incorporated into the CLB can not be a TLAA, even if it 

includes time-limited assumptions. It is logical, then, to begin the TLAA 

identification process with a search of the CLB. 

The CLB was searched to identify discussions of calculations, analyses, and other 

subject matter that potentially satisfy the criteria of a TLAA. These searches were 

performed from a broad perspective to identify specific words that suggested 

time-sensitivity, as well as specific technical subjects that a knowledgeable 

individual might expect to be based on time-sensitive information for their 

conclusions. The following Palisades-specific information was searched for 

potential TLAAs:

• FSAR revision 24

• Technical Specifications

• NRC Safety Evaluation Reports and Safety Evaluations

• NRC Commitments

• Selected other docketed correspondence

4.1.1.2 Industry Document Search for TLAAs

TLAAs are, by definition, plant-specific issues addressed in the plant-specific 

CLB. TLAAs addressed by other plants, or in generic industry documents, will not 

necessarily be applicable to Palisades' design, but they do provide comparative 

data to perform a completeness check. After the initial list of potential TLAA 

candidates was generated directly from the Palisades CLB, various other sources 

of information were compared with that list to confirm its completeness. These 

other sources included:

• Standard Review Plan for License Renewal, NUREG-1800

• Nuclear Energy Institute “Industry Guidelines for Implementing the 

Requirements of 10 CFR Part 54 - The License Renewal Rule”, NEI 95-10, 

revisions 3 and 4

• 10 CFR 54 Statements of Consideration (60FR22461)

• LRAs from other applicants
Page 4-3 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

• Westinghouse (formerly Combustion Engineering) Owners Group Topical 

Reports (as referenced in CLB)

TLAA candidates mentioned in these sources that might have some applicability 

to Palisades were assessed for applicability in the same manner as potential 

TLAAs identified through the CLB searches. 

4.1.2 Identification of Exemptions

10 CFR 54.21(c)(2) requires that the License Renewal Application (LRA) contain a list of 

plant-specific exemptions granted pursuant to 10 CFR 54.12, and in effect, that are based 

on time-limited aging analyses. To identify exemptions which might fall within this 

requirement, a search was performed of NRC SERs and the FSAR. This search identified a 

number of exemptions that have been granted to Palisades. The NRC letters granting the 

exemptions, and any associated SEs, were then reviewed. These reviews revealed that 

none of the exemptions in effect were based on analyses that would meet the criteria of a 

TLAA. Accordingly, it is concluded that there are no plant-specific exemptions required to be 

addressed in the LRA in accordance with 10 CFR 54.21(c)(2).

4.1.3 Evaluation Process of Potential Time Limited Aging Analyses

Each of the potential TLAAs, that resulted from the searches described in Sections 4.1.1 

and 4.1.2, was then reviewed (screened) against the six 10 CFR 54.3(a) criteria. Those 

which met the six criteria were evaluated in accordance with 10 CFR 54.21(c)(1) to 

demonstrate that at least one of the following criteria was applicable:

i. The analyses remain valid for the period of extended operation.

ii. The analyses have been projected to the end of the period of extended operation.

iii. The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

The results of these evaluations are provided in Table 4.1-1 and are discussed in Sections 

4.2 through 4.7. For NRC reviewer convenience, the information is presented in a manner 

consistent with the organization of the Standard Review Plan.
Page 4-4 

Table 4.1-1 Time Limited Aging Analyses

Application for Renewed Operating Licenses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments

Reactor 

Vessel 

Neutron 

Embrittlement

Upper Shelf Energy 4.2.1

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

 Pressurized Thermal 

Shock 4.2.2

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

 Pressure - 

Temperature (P-T) 

Limits

4.2.3

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

Includes LTOP setpoint 

calculation(s)

Low Temperature 

Overpressure 

Protection (LTOP) 

PORV Setpoints

4.2.4

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

Included in Section 4.2.3

Metal Fatigue

Reactor Vessel 

Fatigue Analyses 4.3.2

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

Reactor Vessel Head 

Closure Stud Fatigue 

Analysis

4.3.3

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation
Page 4-5 

Application for Renewed Operating Licenses

Metal Fatigue

Control Rod Drive 

Mechanism (CRDM) 

Housing Fatigue 

Analyses

4.3.4 (i) remains valid for the period of extended operation

Steam Generator 

Fatigue Analyses 4.3.5 (i) remains valid for the period of extended operation

Pressurizer Fatigue 

Analyses 4.3.6

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

Regenerative Heat 

Exchanger Fatigue 

Analyses

4.3.7

(ii) projected to the end of the period 

of extended operation & (iii) effects 

of aging on the intended function will 

be adequately managed for the 

period of extended operation

ASME III Class A 

Primary Coolant 

Piping Fatigue 

Analyses

4.3.8

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

Table 4.1-1 Time Limited Aging Analyses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments
Page 4-6 

Application for Renewed Operating Licenses

Metal Fatigue

Revised Bulletin 88-11 

Fatigue Analysis of the 

Hot-Leg-toPressurizer-SurgeLine Nozzle, Surge 

Line, and Pressurizer 

Surge Nozzle

4.3.9

(i) remains valid for the period of 

extended operation, (ii) projected to 

the end of the period of extended 

operation, & (iii) effects of aging on 

the intended function will be 

adequately managed for the period 

of extended operation

Revised Fatigue 

Analysis of Nozzles 

from PCS Cold Legs 

1B and 2A to 

Pressurizer Spray and 

of the Pressurizer 

Spray Nozzle

4.3.10

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

Pressurizer Auxiliary 

Spray Line Tee 

Fatigue Analysis in 

Response to NRC 

Bulletin 88-08

4.3.11 (i) remains valid for the period of extended operation

Absence of a TLAA for 

ASME III Class 1 

HELB Locations 

Based on Fatigue 

Usage Factor

4.3.12 Not a TLAA

Table 4.1-1 Time Limited Aging Analyses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments
Page 4-7 

Application for Renewed Operating Licenses

Metal Fatigue

Assumed Thermal 

Cycle Count for 

Allowable Secondary 

Stress Range 

Reduction Factor in 

Piping and 

Components

4.3.13

(i) remains valid for the period of 

extended operation, (ii) projected to 

the end of the period of extended 

operation, & (iii) effects of aging on 

the intended function will be 

adequately managed for the period 

of extended operation

Effects of Reactor 

Coolant System 

Environment on 

Fatigue Life of Piping 

and Components 

(Generic Safety Issue 

190)

4.3.14

(ii) projected to the end of the period 

of extended operation & (iii) effects 

of aging on the intended function will 

be adequately managed for the 

period of extended operation

Environmental 

Qualification of 

Electrical 

Equipment

Environmental 

Qualification of 

Electrical Equipment

4.4

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

Containment 

Liner Plate, 

Metal 

Containments 

and 

Penetrations 

Fatigue 

Analysis

Concrete Containment 

Tendon Prestress 

Analysis

4.5

(iii) effects of aging on the intended 

function will be adequately managed 

for the period of extended operation

Table 4.1-1 Time Limited Aging Analyses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments
Page 4-8 

Application for Renewed Operating Licenses

Containment 

Liner Plate, 

Metal 

Containments 

and 

Penetrations 

Fatigue 

Analysis

Containment Liner 

Plate Load Cycles 4.6.1 (i) remains valid for the period of extended operation

 Containment 

Penetration Load 

Cycles

4.6.2 (i) remains valid for the period of extended operation

Other 

Plant-Specific 

Time-Limited 

Aging 

Analyses

Fuel Handling Crane 

Load Cycles 4.7.1 (i) remains valid for the period of extended operation

Alloy 600 Nozzle and 

Safe End Life 

Assessment Analyses

4.7.2

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

ASME Code Case 

N-481 Relaxation of 

The Primary Coolant 

Pump Weld Category 

B-L-1 Inspection 

Interval from 10 Years 

to 40 Years

4.7.3

(i) remains valid for the period of 

extended operation & (iii) effects of 

aging on the intended function will 

be adequately managed for the 

period of extended operation

.

Table 4.1-1 Time Limited Aging Analyses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments
Page 4-9 

Application for Renewed Operating Licenses

Other 

Plant-Specific 

Time-Limited 

Aging 

Analyses

Risk-Informed 

Inservice Inspection 

Program Calculations

4.7.4 (ii) projected to the end of the period of extended operation 

Absence of a TLAA for 

Reactor Coolant Pump 

Flywheel Fatigue or 

Crack Growth Analysis

4.7.5 Not a TLAA

Table 4.1-1 Time Limited Aging Analyses

TLAA Category 

from SRP TLAA Subject LRA Section Disposition per 10 CFR 54.21(c)(1) Comments
Page 4-10 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

4.2 Reactor Vessel Neutron Embrittlement

The reactor vessel is subject to neutron irradiation from the core. This irradiation results in the 

embrittlement of the reactor vessel materials. The NRC approved methodology used to 

perform neutron fluence calculations is consistent with Regulatory Guide 1.190 and is 

described in WCAP-15353, “Palisades Reactor Pressure Vessel Fluence Evaluation” 

(Reference 2). Analyses have been performed that address the following:

• Upper shelf energy

• Pressurized thermal shock (PTS)

• PCS pressure-temperature operating limits

• Low Temperature Overpressure Protection (LTOP) PORV Setpoints

Palisades began use of low leakage core designs when Regulatory Guide 1.99, Revision 2 

was issued. Gradual improvements to the low leakage core design and in the analytical 

methods used to estimate the amount of fast fluence accumulated at the reactor vessel 

beltline, resulted in the current ultra low leakage core design approved by NRC on November 

14, 2000. This core design consists of third and fourth cycle assemblies loaded in peripheral 

locations with specially designed shield assemblies placed to reduce flux at the limiting 

reactor vessel beltline axial welds. The limiting welds are estimated to reach the PTS 

screening criterion in 2014.

The flux to the reactor vessel would have to be reduced by an additional factor of 3 in order to 

reach March 24, 2031. Some additional flux reduction could conceivably be achieved by 

installation of additional shield assemblies and/or flux suppression devices (e.g., hafnium 

inserts). Flux reduction of the magnitude required at Palisades would require far more 

extraordinary measures, however, such as installation of neutron shields on the exterior of the 

core support barrel. It is unlikely that a plant modification of this magnitude would be 

cost-effective. It is highly likely that NMC would pursue alternative solutions rather than rely on 

flux reduction to extend the reactor vessel life. Other alternatives that would be considered 

would include completion of the safety analysis as specified in 10 CFR 50.61(b)(4), and the 

thermal annealing treatment as specified in 10 CFR 50.61(b)(7). Any alternative that NMC 

may propose in the future to extend the life of the Palisades reactor vessel would, of 

necessity, be discussed thoroughly with the NRC, and would be subject to formal NRC review 

and approval before it could be implemented. The ultimate method used to manage PTS for 

extended plant operation would be governed by NRC regulations independently from the 

license renewal process.
Page 4-11 

Palisades Nuclear Plant

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Estimated fluence accumulated by each reactor vessel beltline material at the clad-base metal 

interface (CBMI) and the 1⁄4-thickness (1⁄4t) location at the end of the license renewal period is 

shown in Table 4.2-1.

4.2.1 Upper Shelf Energy

Summary Description

10 CFR Part 50 Appendix G Paragraph IV.A.1 requires that the reactor vessel beltline 

materials must have Charpy upper shelf energy of no less than 68 J (50 ft-lb) throughout the 

life of the reactor vessel, unless otherwise approved by the NRC. In the event that the 50 

ft-lb requirement cannot be satisfied as stated in 10 CFR 50 Appendix G, or by alternative 

procedures acceptable to the NRC, plant operation may continue provided requirement 1 of 

Appendix G is satisfied. This requirement states that an analysis must conservatively 

demonstrate the existence of equivalent margins of safety for continued operation.

Table 4.2-1 Estimated Palisades Fluence on March 24, 2031

RPV Material Material 

Heat #

Fluence 

(1019

n/cm2)

1⁄4t Fluence 

(1019

n/cm2)

Intermediate Shell Axial Welds 2-112A/C W5214 2.084 1.251

Lower Shell Axial Welds 3-112A/C

W5214 2.084 1.251

34B009 2.084 1.251

Intermediate shell to Lower Shell 

Circumferential Weld 9-112 27204 2.998 1.800

Intermediate Shell Plate D-3803-1 C-1279 2.998 1.800

Intermediate Shell Plate D-3803-2 A-0313 2.998 1.800

Intermediate Shell Plate D-3803-3 C-1279 2.998 1.800

Lower Shell Plate D-3804-1 C-1308A 2.998 1.800

Lower Shell Plate D-3804-2 C-1308B 2.998 1.800

Lower Shell Plate D-3804-3 B-5294 2.998 1.800
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Analysis

As shown in Table 4.2.1-1, the upper shelf energy for reactor vessel lower shell plate 

D-3804-1 is expected to decrease to less than 50 ft-lbs based on predictions using 

Regulatory Guide 1.99.

The upper shelf energy for reactor vessel lower shell plate D-3804-1 is estimated to 

decrease below 50 ft-lbs during the year 2014. 

Disposition: 10 CFR 54.21(c)(1)(iii)

10 CFR 50, Appendix G requires licensees to submit an analysis at least 3 years prior to the 

time that the upper-shelf energy of any of the reactor vessel material is predicted to drop 

below 50 ft-lb., as measured by Charpy V-notch specimen testing. NMC will comply with this 

requirement.

NMC will submit an equivalent margins analysis, completed in accordance with 10 CFR 50 

Appendix G Section IV.A.1, for NRC approval, at least three years before any reactor vessel 

beltline material upper shelf energy decreases to less than 50 ft-lb.

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation. The relevant activities will be managed under the Reactor Vessel Integrity 

Surveillance Program.

Table 4.2.1-1Estimated USE on March 24, 2031

RPV 

Material

Material 

Heat # Cu (%) Initial USE (ft-lbs)

1⁄4t Neutron 

Fluence 

(1019

n/cm2)

USE (ft-lbs)

2-112A/C W5214 0.213 118 1.251 73.86

3-112A/C 34B009 0.192 111 1.251 72.01

9-112 27204 0.203 84 1.800 50.83

D-3803-1 C-1279 0.24 102 1.800 63.29

D-3803-2 A-0313 0.24 87 1.800 53.98

D-3803-3 C-1279 0.24 91 1.800 56.46

D-3804-1 C-1308A 0.19 72 1.800 48.97

D-3804-2 C-1308B 0.19 76 1.800 51.69

D-3804-3 B-5294 0.12 73 1.800 55.51
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4.2.2 Pressurized Thermal Shock

Summary Description

The pressurized thermal shock (PTS) rule, 10 CFR 50.61, established screening criteria that 

are a measure of a limiting level of reactor vessel material embrittlement beyond which 

operation cannot continue without further plant-specific evaluation. The screening criteria 

are given in terms of reference temperature RTPTS. The screening criteria are 270° F for 

plates and axial welds, and 300° F for circumferential welds. The RTPTS is defined as:

RTPTS = I + ∆RTNDT + M

Where,

I = Initial reference temperature

∆RTNDT = Mean value of adjustment in reference temperature

M = Margin

The initial reference temperature is the measured unirradiated value as defined in the 

ASME Code, Paragraph NB 2331. If measured values are unavailable for the heat of the 

material of interest, generic values may be used. The generic values are based on the data 

for materials of all heats that were made by the same vendor using similar processes. The 

generic values of initial reference temperature for welds are defined in the PTS rule and 

used in this analysis. Measured values are used for the beltline plate materials.

The ∆RTNDT depends upon the amount of neutron irradiation and the amounts of copper 

and nickel in the material. It is calculated as the product of a fluence factor and a chemistry 

factor. The fluence factor is calculated from the best-estimate neutron fluence at the 

interface of cladding, weld, and metal on the inside surface of the vessel at a location where 

the material receives the highest fluence at the end of the period of evaluation. The fluence 

value used in this analysis is based on the results of calculations performed following the 

guidance in Regulatory Guide 1.190. The chemistry factor may be determined using 

credible surveillance data or from the chemistry factor tables in the PTS rule; these tables 

are used in this analysis.

The margin term is intended to account for variability in initial reference temperature and the 

adjustment in reference temperature caused by irradiation. The value of the margin term is 

dependent on whether the initial reference temperature was a measured or generic value 

and whether the adjustment in reference temperature was determined from credible 

surveillance data or from the chemistry factor tables in the PTS rule. 
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Analysis

The results of the revised PTS analysis for the limiting material have been reviewed for 

compliance with 10 CFR 50.61. The methodology used in the PTS analysis is based on the 

projected neutron fluence at the end of the period of extended operation. The RTPTS values 

for the intermediate and lower shell plates remain below the NRC screening criterion of 

270oF. The RTPTS values for the axial and circumferential welds are projected to exceed the 

NRC screening criteria of 270oF and 300oF, respectively.

Disposition: 10 CFR 54.21(c)(1)(iii)

The Palisades reactor vessel is projected to reach the PTS screening criterion of 270o F on 

the beltline axial welds fabricated with weld wire heat W5214 in 2014.

10 CFR 50.61 requires the licensee to implement a flux reduction program that is 

reasonably practicable to avoid exceeding the screening criteria. Palisades began use of 

low leakage core designs in the late 1980’s when Regulatory Guide 1.99, Revision 2 was 

issued. Gradual improvements to the low leakage core design and in the analytical methods 

used to estimate the amount of fast fluence accumulated at the reactor vessel beltline, 

resulted in the current ultra low leakage core design.

If a flux reduction program does not prevent the reactor vessel from exceeding a PTS 

screening criterion at the end of a plant’s licensed life, 10 CFR 50.61 allows two options. 

Table 4.2.2-1Estimated RTPTS on March 24, 2031

RPV Material Material Heat 

# Cu (%) Ni (%) RTNDT(U)

(°F)

Margin 

(°F)

Fluence 

(1019

n/cm2)

RTPTS

(°F)

Welds 2-112A/C W5214 0.213 1.01 -56 65.5 2.084 287

Welds 3-112A/C

W5214 0.213 1.01 -56 65.5 2.084 287

34B009 0.192 0.980 -56 65.5 2.084 271

Weld 9-112 27204 0.203 1.018 -56 65.5 2.998 302

Plate D-3803-1 C-1279 0.24 0.50 -5 17 2.998 209

Plate D-3803-2 A-0313 0.24 0.52 -30 34 2.998 210

Plate D-3803-3 C-1279 0.24 0.50 -5 17 2.998 209

Plate D-3804-1 C-1308A 0.19 0.48 0 34 2.998 200

Plate D-3804-2 C-1308B 0.19 0.50 -30 34 2.998 173

Plate D-3804-3 B-5294 0.12 0.55 -25 34 2.998 115
Page 4-15 

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The licensee can submit a safety analysis pursuant to §50.61(b)(4) to determine what, if 

any, modifications to equipment, systems and plant operation are necessary to prevent 

failure of the reactor vessel from a postulated PTS event. The other option is to perform a 

thermal-annealing treatment of the reactor vessel pursuant to §50.61(b)(7) to recover 

fracture toughness. §50.61 requires that the details of the selected alternative be provided 

to the NRC three years prior to when the reactor vessel is projected to exceed the PTS 

screening criteria. 

At the appropriate time, prior to exceeding the PTS screening criteria, Palisades will select 

the optimum alternative to manage PTS in accordance with NRC regulations, and will make 

the applicable submittals to obtain NRC review and approval.

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation. The relevant activities will be managed under the Reactor Vessel Integrity 

Surveillance Program.

4.2.3 Pressure-Temperature (P-T) Limits

Summary Description

10 CFR Part 50 Appendix G requires that the reactor pressure vessel be maintained within 

established pressure-temperature limits including during heatup and cooldown. These limits 

specify the maximum allowable pressure as a function of reactor coolant temperature. As 

the reactor pressure vessel becomes embrittled and its fracture toughness is reduced, the 

allowable pressure (given the required minimum temperature) is reduced.

Heatup and cooldown limit curves are calculated using the adjusted RTNDT corresponding 

to the limiting beltline region material of the reactor vessel. The adjusted RTNDT of the 

limiting material in the core region of the reactor vessel is determined by using the 

unirradiated reactor vessel material fracture toughness properties, estimating the 

radiation-induced RTNDT and adding a margin.

Low temperature overpressure protection limits and setpoints are determined as part of the 

calculation of pressure/temperature operating limit curves.

Analysis

The current pressure/temperature analyses are valid beyond the current operating license 

period, but not to the end of the period of extended operation. These analyses are estimated 

to expire in 2014.
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Disposition: 10 CFR 54.21(c)(1)(iii)

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation. 10 CFR 50, Appendices G and H, require the Pressure-Temperature operating 

limits contained in Technical Specifications to be updated as needed to remain valid. The 

relevant activities will be managed under the Reactor Vessel Integrity Surveillance Program.

4.2.4 Low Temperature Overpressure Protection (LTOP) PORV Setpoints

Low temperature overpressure protection limits and setpoints are determined as part of the 

calculation of pressure/temperature operating limit curves. See Section 4.2.3.

4.3 Metal Fatigue

4.3.1 Evaluation of Fatigue in Vessels, Piping, and Components

Design analyses of vessels and piping predict fatigue effects by constructing a set of normal 

operating and abnormal cyclic load events, each of which is assumed to occur no more than 

an assumed number of times during the design life or licensed operating period. Palisades 

maintains a record of the occurrence, and cumulative number of occurrences, of the subset 

of normal and abnormal cyclic events which contribute significantly to the predicted 

cumulative usage factor of vessels, piping, and components. The design basis number of 

cycles, the estimated number of cycles experienced to date, and the estimated number of 

cycles expected to be experienced by the end of the extended operating period, are shown 

in Table 4.3.1-1.

At Palisades the cumulative effect of alternating stresses produced by these events (the 

cumulative usage factor, CUF) was originally calculated under ASME Section III Class A 

rules, 1965 edition and some addenda. ASME Section III Class 1 rules were used for later 

replacements (e.g., the steam generators), and for certain piping modifications. Reanalyses, 

to incorporate events and conditions not considered in the original design, typically used the 

original design code for the component. The code of record for each component is listed in 

Table 4.3.1-2.

At almost all Palisades locations for which a fatigue analysis was performed, the cumulative 

usage factor (CUF) predicted by the original analysis of record, based on a 40 year life, is 

not expected to approach the allowable limit of 1.0 in a 60 year life. There are a number of 

locations in the Palisades vessels and piping for which the original fatigue analysis predicts 

a cumulative usage factor of greater than 0.666 for the original 40-year design life; and, 

therefore, for which a simple proportional extension of the original analysis to 60 years 

would predict a CUF exceeding the allowable 1.0. However, the plant operating history 
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demonstrates that the number of event cycles assumed by the original analyses is 

conservative in all but a few cases, and that at the historical rate of occurrence, the analysis 

basis event cycle assumptions remain more than adequate for the extended licensed 

operating period. To confirm that this remains so, NMC plans to augment the existing cycle 

counting activities, where necessary, and continue them through the extended licensed 

operating period. See Appendix B for a discussion of the Fatigue Monitoring Program

However, for a few cases at some locations, addenda to the original fatigue analyses have 

addressed effects not contemplated in the original analyses, and plant modifications have 

required some new analyses. Some of these have used revised cycle estimates, or have 

addressed load events not contemplated in the original fatigue analyses. With these 

changes, at some locations, a simple projection to a 60-year design life at the expected rate 

of load cycle accumulation predicts a usage factor greater than 1.0. These locations, 

therefore, required reanalysis or other appropriate measures, as described below.

The reactor coolant environment may also reduce fatigue life. These effects are evaluated 

as a generic issue. At most locations the predicted cumulative usage factors are low, so that 

even with these effects the fatigue cycle count program will ensure that these effects do not 

violate the basis for the safety determination of the fatigue analysis. Alternative methods are 

needed at a few locations with both high predicted usage factors and with more severe 

effects of the reactor coolant environment, to ensure that these effects do not violate the 

basis for the safety determination of the fatigue analysis.

The component and piping analyses of record were reviewed to identify existing fatigue 

analyses of vessels and piping to ASME Section III Class A rules, and later analyses to 

ASME Section III Class 1 rules. The Palisades cycle count records were reviewed to 

determine the number of accumulated operating cycles to date for a critical set of operating 

and abnormal events.

Comparing the allowed and 60-year expected cycles shows that only a few of the events 

could reasonably be expected to occur more than 50 percent of the times assumed by the 

analyses in a 60 year design life. Therefore the CUF should not approach 0.5 in 60 years, 

even if the CUF predicted by the original 40 year analysis were at the analytic limit of 1.0, 

except in those locations affected by (1) modifications or additional effects not contemplated 

in the original analyses, or (2) the reactor coolant environmental effects described in Section 

4.3.14.

Fatigue Monitoring Aging Management Program for Vessels, Piping, and 

Components

A number of fatigue issues at Palisades will be managed through cycle counting. The 

program will record plant transients for a bounding subset of reactor pressure vessel (RPV), 
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pressurizer, steam generator, other reactor coolant system components, and Consumers 

Design Class I piping to ensure that fatigue effects are adequately managed for Consumers 

Design Class I systems and components. Cycle counting will assure that either (1) the 

analysis and licensing basis design cycle count assumptions are not exceeded during the 

period of extended operation, or (2) corrective action is taken to ensure that the basis for the 

safety determination remains valid, upon reaching the assumed cycle count for a given 

event.

This cycle counting program is described in Appendix B, Fatigue Monitoring Program.
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Table 4.3.1-1Primary Coolant system Design Transients

No Transient Cycles 

Allowed

To 9 

January 

2005i

Most 

Expected in 

60 Yearsi

1

Plant Heatup at 100°F/hr 

Plant Cooldown at 100°F/hr

Pressurizer Cooldown at 200°F/hr

500

500

500

134

119

119

240

240

240

2

Plant Loading at 5% of Full Power / 

Minute

Plant Unloading at 5% of Full Power / 

Minute

2,000

2,000

NC

NC

NC

NC

3

Plant Loading at 15% of Full Power / 

Minute

Plant Unloading at 15% of Full Power 

/ Minute

2,000

2,000

NC

NC

NC

NC

4

Step Load Increase of 10% of Full 

Power

Step Load Decrease of 10% of Full 

Power

2,000

2,000

NC

NC

NC

NC

5 Loss of Turbine Load from 100% 

Power 100 50 90

6 Loss of Primary Coolant Flow 100 11 20

7 Reactor Trip from 100% Power 500 126 240

8 Safety Valve Operation 200 NC NC

9 Steady State Pressure Fluctuation (± 

50 psi) 350,000 NC NC

10 Regenerative Heat Exchanger 

Isolation 400 NC NC
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11

Hydrostatic Test Conditions:

·Primary Side Hydrostatic Test 

Before Initial Startup @ 3110 psig

·Secondary Side Hydrostatic Test @ 

1,250 psia with Primary Side 

Pressure = >600 psia

10

10

1

2

1

2

12

Leak Test Conditions:

·Primary Side Leak Test @ 2485 psi

·Secondary Side Leak Test @ 1,000 

psia with Primary Side Pressure 

>350oF 

320

320

0

0

10

10

13

Steam Generator 

Primary-to-Secondary Pressure Test 

(Secondary @ 900 psia/532oF and 

Primary @ 0 psig

1 01

14

Steam Generator Primary Head 

Divider Plate Pressure Differential 

Transients of 85 psi (from RCP 

starts)

2,500 NC NC

15 Feedwater Addition (425 gpm @ 

32oF with plant in Hot Standby) 15.000 NC NC

16 

Feedwater Addition (300 gpm 

maximum @ 32oF with Steam 

Generator Secondary Side dry @ 

600oF)

8 04

17 Steam Line Rupture 1 0 1

18 Design Basis Earthquake 200 NC NC

i. NC = Not counted (will never approach)

Table 4.3.1-1Primary Coolant system Design Transients

No Transient Cycles 

Allowed

To 9 

January 

2005i

Most 

Expected in 

60 Yearsi
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Table 4.3.1-2 Applicable Codes for Palisades Components

4.3.2 Reactor Vessel Fatigue Analyses

Summary Description

The Palisades Reactor Vessel was designed, constructed, and analyzed to the ASME Boiler 

and Pressure Vessel Code, Section III, Subsection 4 for Class A vessels, 1965, with 

addenda through Winter, 1965. ASME III -1965 Class A vessels require a Subsection 

N-415.2 fatigue analysis for parts subject to stress ranges which exceed the criteria of 

Subsection N-415.1. The original analyses have been amended to address issues that have 

arisen since fabrication. The current highest calculated fatigue usage factors, based on the 

number of design basis load cycles assumed by the vessel analyses, have been 

determined. The number of design basis load cycles for each event was selected to be 

adequate for the originally-licensed 40-year design life.

Component Code of Construction Edition and Addenda

Reactor Vessel ASME Section III, Class A 1965 Edition with Addenda 

through Winter 1965

Pressurizer ASME Section III, Class A 1965 Edition with Addenda 

through Winter 1966

Reactor Coolant Pumps ASME Section III, Class A 1965 Edition with Addenda 

through Winter 1965

Pressurizer Safety and 

Power Operated Relief 

Valves

ASME Section III 1965 Edition with Addenda 

through Winter 1965

PCS Piping and Nozzles ANSI B31.1 Power Piping 

Code, Class 1i

i. PCS piping was subsequently reanalyzed to ASME Section III, Class A.

1955 Edition 

Containment Vessel 

Liner

ASME Section III 1965 Edition with no Addenda 

Regenerative Heat 

Exchanger

ASME Section III, Class C 1965 Edition with Addenda 

through Winter 1965

Replacement Steam 

Generators

ASME Section III, Section 

NB/NC

1977 Edition with no Addenda

Quench Tank ASME Section III, Class C 1965 Edition with Addenda 

through Winter 1965
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Of the high usage factor vessel locations, the vessel studs have the highest usage factor but 

are replaceable, and the control rod drive mechanism (CRDM) housings and appurtenances 

have been replaced. For these reasons fatigue in these components is addressed 

separately; the vessel studs in Section 4.3.3, and the replaced CRDM housings and 

appurtenances in Section 4.3.4.

Analysis

This section addresses the calculated fatigue usage factors for the reactor vessel

• Shell and bottom head

• Inlet and outlet nozzles

• Internal welded attachments

• Instrument nozzle shroud tube

• Vessel head CRDM nozzles, and

• Instrument flange bolts (on the instrument nozzle on the vessel head).

The worst-case calculated usage factor for the set of design basis load events in these 

locations is 0.4516 on the outlet nozzle, well within the code limit of 1.0. The number of 

design basis transient events is not expected to approach the number assumed by the 

analysis during the extended licensed operating period.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The number of each of the design basis events that affect the reactor pressure vessel is not 

expected to approach its design basis limit during the extended licensed operating period, 

and, therefore, the actual fatigue usage factors are not expected to approach their 

maximum calculated values during the extended licensed operating period. The calculated 

maximum usage factor for these locations on the reactor vessel is 0.4516, well within the 

analytical limit of 1.0. Therefore, this item is dispositioned under 10 CFR 54.21(c)(1)(i), the 

analysis remains valid for the period of extended operation.

The Fatigue Monitoring Program, described in Appendix B, will ensure a reanalysis or other 

appropriate corrective action in the unlikely event that a design basis cycle count limit is 

reached at any time during the extended licensed operating period.

4.3.3 Reactor Vessel Head Closure Stud Fatigue Analysis

Summary Description

The highest fatigue usage factor calculated by the reactor vessel fatigue analysis is in the 

vessel head studs. See also Section 4.3.2.
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Analysis

The calculated lifetime usage factor in the head closure studs for the set of design basis 

load events is 0.8346, within the code limit of 1.0. The number of design basis transient 

events is not expected to approach the number assumed by the analysis during the 

extended licensed operating period.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The number of each of the design basis events that affect the reactor pressure vessel and 

the head closure studs is not expected to approach its design basis limit during the 

extended licensed operating period, and, therefore, the actual fatigue usage factors are not 

expected to approach their calculated values during the extended licensed operating period. 

The calculated maximum usage factor for the studs is 0.8346, within the analytical limit of 

1.0. Therefore, this item is dispositioned under 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

The Fatigue Monitoring Program, described in Appendix B, will ensure a reanalysis or other 

appropriate corrective action in the event that a design basis cycle count limit is reached at 

any time during the extended licensed operating period.

4.3.4 Control Rod Drive Mechanism (CRDM) Housing Fatigue Analyses

Summary Description

The reactor control rod drive mechanisms (CRDM) are enclosed in pressure housings 

bolted and seal-welded to the reactor pressure vessel CRDM nozzle flanges. The CRDM 

housings, their seal housings, their instrument and vent tube nozzles, the flange bolts, and 

the Omega seal welds between the CRDM housing flanges and the reactor vessel CRDM 

nozzle flanges were all replaced in 2001. Extension of the operating license to March 24, 

2031 therefore requires a 31 year design life. The replacements are ASME III (1989) - Class 

1, NPT stamped, with a reconciliation to the 1965 code.

Analysis

CRDM Housings: The revised fatigue evaluation found that the criteria of ASME III - 1989, 

Paragraph NB-3222.4(d) are met, and therefore that no fatigue analysis is required.

CRDM Housing Bolts: The fatigue evaluation of record calculated a design lifetime 

cumulative usage factor of 0.173. This evaluation has not been revised, but will remain valid 

so long as the assumed number of lifetime design basis transient cycles remains valid. This 

analysis is very conservative since the bolts were replaced when the CRDM housings were 

replaced.
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CRDM Flange - Reactor Vessel Nozzle Flange Bolts: The fatigue evaluation of record 

calculated a design lifetime cumulative usage factor of 0.624. This evaluation has not been 

revised, but will remain valid so long as the assumed number of lifetime design basis 

transient cycles remains valid. This analysis is very conservative since the bolts were 

replaced when the CRDM housings were replaced.

CRDM Flange - Reactor Vessel Nozzle Flange Omega Seal Welds: The fatigue evaluation 

calculated a design lifetime cumulative usage factor of 0.5621. This analysis used the set of 

design transients from the original design specification, which were based on an assumed 

40-year design life.

Disposition: 10 CFR 54.21(c)(1)(i)

Since all of these components were replaced in 2001, their expected installed lifetime, 

including the extended licensed operating period (to March 24, 2031), will be only about 31 

years, compared to the 40 years upon which the estimate of design basis event cycles was 

based. The two highest calculated maximum usage factors for a 40 year life in any of these 

components is 0.624 for the flange bolts and 0.5621 for the flange Omega seal welds, well 

within the analytical limit of 1.0.

In addition, the number of each of the design basis events that affect the reactor pressure 

vessel and the CRDM housings and appurtenances is not expected to approach its design 

basis limit during the extended licensed operating period. The actual fatigue usage factors 

are therefore not expected to approach their calculated values during the extended licensed 

operating period.

Therefore, this item is dispositioned under 10 CFR 54.21(c)(1)(i), the analysis remains valid 

for the period of extended operation.

4.3.5 Steam Generator Fatigue Analyses

Summary Description

The Palisades steam generators were replaced in 1990-1991. Extension of the operating 

license to March 24, 2031 therefore requires a 40 year design life.

The replacement steam generators were designed to the ASME Boiler and Pressure Vessel 

Code, Section III, 1977. The primary coolant pressure boundary (tube side) of the steam 

generators is designed to Section III Class 1 rules. Critical components of the Class 

2-design secondary side (e.g., the feedwater nozzles) were also analyzed using Class 1 

methods.
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Analysis

Vessel and Components, Except Manway Studs: The ASME III Class 1 fatigue analyses of 

the replacement steam generators used the number of event cycles assumed for the 

original plant design for a 40-year licensed operating period. Except for the manway studs 

(below), the maximum usage factor at any location is 0.9158, on the main feedwater nozzle.

Manway Studs: The original ASME III Class 1 fatigue analyses calculated a worst-case 

usage factor for the manway studs of 0.10. However the vendor (Westinghouse) later 

issued a Nuclear Safety Advisory Letter identifying a significant bending load on the studs 

due to differential thermal expansion during the heatup and cooldown transients, which 

resulted in predicted lifetime usage factors greater than 1.0. The revised analysis found that 

the fatigue limit for the studs would be reached in about 200 reactor heatup and cooldown 

cycles.

Plant procedures require a periodic evaluation of the number of heatup and cooldown 

cycles experienced by the Primary Coolant System to assure that the manway studs are 

replaced before they can experience 200 heatup and cooldown cycles. Since the studs 

were installed at Plant Heatup Number 106, they should be replaced before Heatup Number 

306. The manway stud fatigue analysis determines the evaluation interval. It does not 

qualify the studs for the licensed operating life, and is therefore not a TLAA.

Disposition: 10 CFR 54.21(c)(1)(i)

The replacement steam generator fatigue analyses qualify them for a 40 year design life, 

except for the manway studs. The analysis for the manway studs is not a TLAA, and are 

managed separately. The qualified 40 year design life is sufficient for the extended licensed 

operating period ending in 2031. Therefore, this item is dispositioned under 10 CFR 

54.21(c)(1)(i), the analysis remains valid for the period of extended operation.

4.3.6 Pressurizer Fatigue Analyses

Summary Description

The pressurizer is a vertical, hemispherical-head vessel, supported from its lower head by a 

flanged skirt, connected to the primary coolant system by a 12 inch surge nozzle in the 

center of the lower head. The lower head also has 120 electric heater nozzles and 4 level 

instrument nozzles. There is a liquid-temperature element nozzle in the lower shell. The 

upper head has a manway, a spray nozzle for pressure control, 4 level instrument nozzles, a 

power-operated relief valve (PORV) and 3 code relief valve nozzles, and a 

vapor-space-temperature-element nozzle. The surge and spray nozzles have thermal 

sleeves.
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The vessel shell, heads, skirt, surge nozzle, and manway are carbon steel. The shell and 

upper head are clad with 304 stainless steel. The lower head and surge nozzle are clad with 

Ni-Cr-Fe alloy (Alloy 600). The heater sleeves and the remainder of the nozzles are Alloy 

600 or have Alloy 600 safe ends (or flanges, for the code safety valves), except the PORV 

nozzle safe end, which was modified as described below.

The pressurizer was designed to the ASME Boiler and Pressure Vessel Code, Section III, 

Class A, 1965, Winter 1966 addenda. The code design calculation includes a fatigue 

analysis for those nozzles or other parts which do not meet the fatigue analysis exemption 

criteria of Section III Paragraph N-415.1. These include all nozzles attached by J-welds and 

other nozzles and parts subject to more-severe thermal transients, as follows:

• The surge, spray, and temperature element nozzles and nozzle-to-shell or nozzle-to-head 

junctions

• Heater sleeve-to-head junctions

• Upper level nozzles

• Relief (PORV) and safety valve nozzles

• The liquid-vapor boundary region of the shell

• Manway, head, and studs, and

• Bottom head support skirt.

A revised set of external load cycles required reevaluation of fatigue in the three safety relief 

valve nozzles. The recalculation found that the stress intensities produced by the revised 

external loads are less than those calculated by the original analysis, and, therefore, that the 

original simplified fatigue evaluation remains valid.

The Alloy 600 safe end to-pipe weld at the power-operated relief valve nozzle was found 

cracked and leaking in 1993. It was repaired by two welds and a short section of stainless 

pipe, and the nozzle was reanalyzed. The highest usage factor calculated for the modified 

safe end and its connections is 0.7572 at the inside of the nozzle-head juncture. This 

recalculation assumed load cycles for a 40 year design life.

Analysis of the PORV nozzle safe end material removed in 1993 indicated primary water 

stress corrosion cracking (PWSCC), and prompted replacement of the remainder of the safe 

end with 316 stainless material with Alloy 690 welds, in 1995. The fatigue analysis for the 

currently-installed safe end and attachments calculated a worst-case usage factor of 0.084, 

at the inside wall of the safe end transition. See Section 4.7.2.

Other TLAAs of the Pressurizer: Thermal stratification phenomena in the surge line have 

required reanalysis of the surge nozzle, and concerns for high differential temperatures with 
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auxiliary spray have required reanalysis of the spray nozzle. See Section 4.3.9 for a 

discussion of the surge and spray nozzles.

Primary water stress corrosion cracking (PWSCC) of the of the Alloy 600 temperature 

nozzles required repair, a revised fatigue analysis, and analyses of the PWSCC effects. 

These failures, failure of the PORV nozzle safe end, and industry-wide cracking of Alloy 600 

components have required evaluation of PWSCC effects in all Alloy 600 components. See 

Section 4.7.2 for additional discussion. 

Analysis

This section addresses the remaining applicable portions of the original code analysis and 

its addenda and revisions, including those for the currently-installed 316 stainless PORV 

nozzle safe end. This section specifically addresses the calculated fatigue usage factors for 

the following:

• Bottom head support skirt

• Heater sleeve-head junctions

• Liquid-vapor boundary region of the shell

• Upper level nozzles

• Power-operated relief valve (PORV) nozzle

• Code safety valve nozzles, and

• Manway, head, and studs

For these locations the worst-case calculated usage factor is 0.7572, at the inner PORV 

nozzle-head juncture.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The fatigue analysis of the replaced PORV nozzle safe end was based on a nominal 20 year 

life beyond its 1995 installation. However, the low worst-case usage factor of 0.084 in this 

component permits a simple projection to the end of the extended licensed operating period, 

when the service life of this component would be about 36 years. A projected usage factor 

based on this 36 year life would be only about 0.15, compared to the allowable 1.0.

For those portions of the original pressurizer analysis which have not been superseded, the 

number of each of the design basis events is not expected to approach its design basis limit 

during the extended licensed operating period, and, therefore, the actual fatigue usage 

factors are not expected to approach their calculated values during the extended licensed 

operating period. The calculated maximum usage factor for these locations on the 

pressurizer is 0.7572, within the analytical limit of 1.0, at the inner PORV nozzle-head 

juncture.
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These items, therefore, are dispositioned under 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

The Fatigue Monitoring Program, described in Appendix B, will ensure that the bases for the 

modified PORV nozzle reanalysis, and for those portions of the original pressurizer analysis 

which have not been superseded, remain valid.

4.3.7 Regenerative Heat Exchanger Fatigue Analyses

Summary Description

The regenerative heat exchanger recovers energy from the letdown line to heat chemical 

and volume control system charging water for reactor system makeup (charging) and 

auxiliary pressurizer spray. The heat exchanger letdown or tube side is separated from the 

primary coolant system by a normally-open manual valve and a control valve, and is, 

therefore, a Consumers Design Class 1 component. The charging or shell side is separated 

from the primary coolant system by a check valve and control valve on each of the charging 

and auxiliary spray lines.

The charging system has three positive-displacement pumps. The pumps can not be 

throttled without lifting discharge safety valves, but one of them is variable speed. The 

charging system was designed to operate continuously, with flow from the fluid-drive 

variable-speed pump controlled by a primary coolant volume control signal. If the 

variable-speed pump is out of service, the system controls Primary Coolant System makeup 

by cycling a constant-speed pump on and off. This cycling of cold makeup water against the 

(approximately constant) hot letdown flow produces significant thermal transients in the 

regenerative heat exchanger.

Isolation of letdown flow introduces a similar differential thermal load and has a similar 

effect.

Analysis

The original design included a fatigue evaluation to ASME III -1965, Paragraph N-415. The 

final addendum to the original analysis was based on a revised definition of the load 

transient set which eliminated the 15 percent per minute load-following transient for this 

component. The worst-location cumulative usage factors (CUF) for a 40-year licensed 

operating life were 0.871 on the tubesheet, and 0.624 on the shell.

By 1993, operating experience had shown that the availability of the variable-speed pump 

was less than anticipated in the original design, and therefore that the number of thermal 

cycles from cycling a constant-speed pump was greater than anticipated. The expected 

number of lifetime thermal cycles and the fatigue usage factor at the most limiting location 

(the tube sheet) were therefore reevaluated. The transient evaluation increased the lifetime 
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number of thermal stress cycles due to this event from 5,520 to 17,822. The fatigue 

evaluation found that, with the increased number of thermal cycles described above plus the 

remainder of the design basis event set, the CUF at the limiting tube sheet location would be 

1.002, slightly above the analytic limit of 1.0. However, the design basis event set included 

60,500 load-following and reactor trip events (Transient I), of which the unit had experienced 

only about 180 by that date (1993). The fatigue evaluation therefore reduced the design 

basis Transient I cycles slightly (to 60,282), and demonstrated that the analytic limit of 1.0 

was then met.

A revision in 1995 to permit more frequent letdown isolation re-evaluated both thermal and 

pressure transient effects. The evaluation of stress pairings for Transient I load-following 

and reactor trip events found that those with the maximum stress range could be further 

reduced to 32,500 from the 60,282 assumed in the 1993 analysis, even considering the 

increased frequency of letdown isolations to 17,822 from 5,520 cycles. The 1995 revision 

shows that the highest design basis CUF is 0.880 at the inner ligament of the shell side of 

the tubesheet.

Based on the plant events in the first 20 years of operation, a recent revision to the 

calculation estimates that the number of cycles for cycling the constant-speed charging 

pump can be increased to 27,062, and Transient I can be reduced to 6,240 for 60-year plant 

life. With the new estimated numbers of transient events at the end of extended operating 

period, the maximum fatigue usage factors at the two most critical locations in the 

regenerative heat exchanger (tubesheet and tubesheet to shell junction) is 0.439.

Disposition: 10 CFR 54.21(c)(1)(ii); and Aging Management, 10 CFR 54.21(c)(1)(iii)

Re-analysis has been performed to include additional thermal cycles from cycling the 

constant-speed charging pump and reduced number of transients that were over estimated 

in the original design analysis. The projected CUF at the end of the extended operating 

period remains less than 1. Therefore, the regenerative heat exchanger meets the criteria of 

10 CFR 54.21(c)(1)(ii).

The fatigue management cycle count program will include the letdown isolation and 

variable-speed charging pump out-of-service events.

4.3.8 ASME III Class A Primary Coolant Piping Fatigue Analyses

Summary Description

A piping fatigue analysis was originally applied only to the main loops of the primary coolant 

system, the two 42 inch hot legs and the four 30 inch cold legs, and to the connecting 

nozzles for smaller piping. The hot and cold legs are seam-welded from ASTM A516 Grade 

70 plate, clad by roll-bonding with 1/4 inch (nominal) 304L stainless. The hot and cold legs 
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are supported only by the reactor and steam generator nozzles and by the primary coolant 

pumps. The original analyses calculated fatigue usage factors for the:

• Hot legs

• Cold legs

• Safety injection-shutdown cooling nozzles

• Hot leg to surge line nozzle

• Charging Inlet nozzles

• Hot leg temperature nozzles

• Shutdown cooling outlet nozzle

• Cold leg temperature nozzles

The hot leg to surge line nozzle has been reanalyzed to address transients not 

contemplated in the original analysis. See Section 4.3.9. for additional discussion

The cold-leg-to-pressurizer-spray nozzles and others, not listed above, were exempt from a 

fatigue calculation in the original analysis, because all then-known cyclic stress ranges were 

below the endurance limit. However the cold-leg-to-pressurizer-spray nozzles have since 

been evaluated for additional transients not contemplated in the original analysis. See 

Section 4.3.9 for additional discussion.

Analysis

This section addresses the remaining original analyses for the hot and cold legs, and for the 

remaining original nozzles.

The fatigue analysis of record for the hot and cold legs is not location-specific. This analysis 

uses worst-case stresses at all locations in each of a typical hot leg and cold leg to 

determine the worst-possible-case stress ranges, and from them calculates a 

worst-possible usage factor for a typical hot leg and for a typical cold leg. The calculated 

CUFs were 0.07551 and 0.7531, respectively. These usage factors are, therefore, 

considerably higher than would be calculated by a location-specific analysis. The 0.7531 

cold leg usage factor is higher than any for the nozzles in these original calculations.

The safety injection-shutdown cooling and charging inlet nozzles are also sample locations 

for evaluation of effects of the reactor coolant environment on fatigue behavior. See Section 

4.3.14 below for additional discussion.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The number of each of the design basis events that affect the hot and cold legs is not 

expected to approach its design basis limit during the extended licensed operating period, 
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and therefore that the actual fatigue usage factors are not expected to approach their 

calculated values during the extended licensed operating period. The calculated maximum 

usage factor for the hot and cold legs and their nozzles in these original calculations is 

0.7531, well within the analytical limit of 1.0. In addition, the predicted hot leg and cold leg 

usage factors are calculated on a very conservative basis. The hot leg usage factor is quite 

low, and the cold leg usage factor, though appearing significant at 0.7531, would be much 

less if calculated by a location-specific analysis. Therefore, this item is dispositioned under 

10 CFR 54.21(c)(1)(i), the analysis remains valid for the period of extended operation.

The Fatigue Monitoring Program, described in Appendix B, will ensure a reanalysis or other 

appropriate corrective action if a design basis cycle count limit is reached at any time during 

the extended licensed operating period.

4.3.9 Revised NRC Bulletin 88-11 Fatigue Analysis of the Hot Leg to Pressurizer Surge Line 

Nozzle, Surge Line, and Pressurizer Surge Nozzle

Summary Description

NRC Bulletin 88-11, dated December 1988, was issued to address pressurizer surge line 

temperature stratification concerns. The effects of thermal stratification were evaluated by 

the Combustion Engineering Owners Group. The Combustion Engineering Owners Group 

Report concluded the structural integrity of the pressurizer surge line is acceptable for the 

forty year life of the Plant. The NRC issued an SER on September 13, 1993 concluding that 

the CEOG analysis adequately demonstrates that the bounding surge line and nozzles meet 

ASME Code stress and fatigue requirements for the 40-year design. Consumers provided 

additional information detailing completion of the required actions of Bulletin 88-11, including 

the requirement to update the pressurizer surge line stress and fatigue analyses. See FSAR 

Section 4.3.7.

Analysis of Surge Line

For both nozzles and for the worst-case location in the surge line (an elbow) the calculated 

usage factor for the revised set of design basis load events is within the code limit of 1.0.

Pressurizer Surge Line Elbow: The fatigue evaluation for a typical Combustion 

Engineering plant with intermittent pressurizer spray and for the revised set of design basis 

load events, including the IEB 88-11 thermal stratification transients, calculated a maximum 

CUF of 0.937 at one of the surge line elbows.

A recent fatigue analysis, using thermal stratification conditions under the Palisades 

continuous pressurizer spray operation, shows that the CUF is reduced significantly to 

0.0135 for the expected number of cycles at the end of the 60-year operating period. If the 
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number of cycles at the end of the extended operating period were based on 1.5 times the 

40-year design basis cycles, the CUF at the surge elbow would be 0.0447.

This location is also a NUREG/CR 6260 sample location for evaluation of environmental 

effects of the reactor coolant on fatigue effects, which is discussed in Section 4.3.14.

Hot Leg to Surge Line Nozzle: The fatigue evaluation for a typical Combustion 

Engineering plant with intermittent pressurizer spray and for the revised set of design basis 

load events, including the IEB 88-11 thermal stratification transients calculated a maximum 

CUF of 0.3818 for Palisades hot leg to surge line nozzle. With Palisades’ continuous 

pressurizer spray operation, the CUF is reduced significantly, similar to the above surge line 

elbow, because piping loads due to thermal stratification are the major contributor to nozzle 

fatigue stress.

Pressurizer Surge Nozzle: The fatigue evaluation for a typical Combustion Engineering 

plant with intermittent pressurizer spray and for the revised set of design basis load events, 

including the IEB 88-11 thermal stratification transients, calculated a maximum CUF of 

0.9611 for the Palisades pressurizer surge line nozzle. With Palisades’ continuous 

pressurizer spray operation, the CUF is reduced significantly, similar to the above surge line 

elbow, because piping loads due to thermal stratification are the major contributor to the 

nozzle fatigue stress.

Design Basis Thermal Transients and Expected Thermal Transients: The additional 

thermal stratification transients are in the pressurizer surge line and nozzles during plant 

heatup and cooldown at differential temperatures of 320, 250, 200, and 150o F ∆T, and hot 

standby at 90o F ∆T. These design transients were developed by the CE owners group for a 

typical plant with severe thermal transients due to intermittent pressurizer spray.

The use of modulated, continuous spray for pressure control, and control of pressurizer to 

primary loop ∆T, significantly mitigates this problem at Palisades. An assessment of the 

thermal stratification event mechanisms for Palisades’ operating conditions found that for 

almost all such events the metal ∆T would not exceed 210o F, instead of the 320o F ∆T 

assumed by the standard plant analysis. This is further supported by the log of pressurizer 

spray events at ∆T above 200o F, which has recorded only 47 events through 9 January 

2005. These transients are auxiliary spray events, which have little or no effect on surge line 

stratification.

This moderation of the transients reduces the piping differential expansion loads and 

support and nozzle reactions. A recent fatigue analysis using thermal stratification 

conditions under the Palisades continuous pressurizer spray operation show that the CUF 

at the surge line elbow is reduced to less than 0.1 at the end of the extended operating 
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period. Since piping load is the major contributor to the nozzle fatigue stress, a similar 

reduction is expected for the surge line nozzles.

Design Basis Cycle Count and Expected Cycle Count: The number of design cycles 

developed by the CE Owners Group for each of the above thermal stratification transients 

correspond to 500 cycles of plant heatup and cooldown. The number of transient events 

which might be expected to initiate these thermal stratification events will not exceed their 

design basis limits for the extended licensed operating period; the same is, therefore, also 

true for these thermal stratification events.

Disposition for Surge Line Elbow: 10 CFR 54.21(c)(1)(ii); and 10 CFR 54.21(c)(1)(iii)

A plant-unique calculation for the surge line shows that the fatigue usage factor of the surge 

line elbow remains less than 1 at the end of the extended operating period. The calculation 

includes the revised set of design basis load events; including the plant-unique IEB 88-11 

thermal stratification transients. Therefore, the surge line elbow meets the revision criteria 

per 10 CFR 54.21(c)(1)(ii).

The Fatigue Monitoring Program, described in Appendix B, will ensure a reanalysis or other 

appropriate corrective action if a design basis primary coolant system cycle count limit is 

reached at any time during the extended licensed operating period.

Disposition for Hot Leg and Pressurizer Surge Nozzles: 10 CFR 54.21(c)(1)(i); and 10 

CFR 54.21(c)(1)(iii)

The design basis analysis calculated maximum usage factor at the hot leg surge nozzle of 

0.3818 is well below the analytical limit of 1.0. The usage factor remains less than 1 at the 

end of the extended operating period. Therefore, the surge line elbow and the pressurizer 

surge nozzle meet the validation criteria per 10 CFR 54.21(c)(1)(i).

The calculated maximum usage factor for the pressurizer surge nozzle of 0.9611 is below 

the analytical limit of 1.0. This value is the result of a generic plant analysis, which assumed 

worst-case stratification through the entire surge line, and which calculated transients based 

on intermittent pressurizer spray. Similar to the CUF of the surge line elbow, the CUF of the 

pressurizer is expected to reduce considerably, if the moderation of the transients of the 

Palisades continuous pressurizer spray is used.

As mentioned above, the number of design cycles for surge line stratification flow developed 

by the CE Owners Group for each of the above thermal stratification transients correspond 

to 500 cycles of plant heatup and cooldown.

The Fatigue Monitoring Program, described in Appendix B, will ensure a reanalysis or other 

appropriate corrective action if a design basis primary coolant system cycle count limit is 

reached at any time during the extended licensed operating period.
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4.3.10 Revised Fatigue Analysis of Nozzles from PCS Cold Legs 1B and 2A to Pressurizer 

Spray and of the Pressurizer Spray Nozzle

Summary Description

Pressurizer spray is normally supplied by reactor coolant pump head through 3 inch nozzles 

on two of the four 30 inch primary coolant system (PCS) cold legs. Normal spray flow in 

each of these 3 inch lines is continuous, through a normally throttled 3/4 inch main spray 

bypass valve, and through a 3 inch main spray control valve. The charging line downstream 

of the regenerative heat exchanger supplies auxiliary spray from the chemical and volume 

control system through a 2 inch control valve. All three of these sources supply a single 

pressurizer spray nozzle.

The original design of the pressurizer included a fatigue analysis of the pressurizer spray 

nozzle. However, the normal spray piping and the auxiliary spray piping were designed to 

the B31.1 Code. Revised operating conditions and pressurizer cooldown rate prompted 

addition of a fatigue analysis for the two cold leg nozzles and for the auxiliary spray piping 

(see Section 4.3.11).

Analysis of Other Nozzles

Cold Leg Nozzles to Pressurizer Spray: The analysis of the auxiliary spray-reverse flow 

events is based on the design basis number of thermal cycles assumed for 40 years, and 

the calculated cumulative usage factor is 0.66.

Pressurizer Spray Nozzle: The revised pressurizer spray nozzle analysis determined that 

the calculated cumulative usage factor (CUF) is 0.8214 for the design basis number of 

high-differential-temperature spray events and 200o F per hour cooldowns assumed for 40 

years, and for all other applicable transients.

The revised analysis also estimated that the maximum CUF in the spray nozzle to that date 

(October, 1991) was 0.353, and that accumulation at then-current trends indicated a 40-year 

lifetime CUF of about 0.435. On that basis a projection to the end of a 60-year extended 

licensed operating period would indicate a CUF of about 0.517.

Disposition Cold Leg to Pressurizer Spray Nozzles: 10 CFR 54.21(c)(1)(i)

The number of thermal cycles for each of the design basis temperature differential ranges 

will not exceed the design basis limit during the extended licensed operating period. The 

calculated 40-year plant life usage factor of 0.66 is well below the analytical limit of 1.0. 

Thus the usage factor remains less than 1 at the end of the extended licensed operating 

period. Therefore, the cold leg to pressurizer spray nozzles meets the validation criteria per 

10 CFR 54.21(c)(1)(i).
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Disposition Pressurizer Spray Nozzles: 10 CFR 54.21(c)(1)(iii)

The design basis cumulative usage factor (CUF) of the nozzle is 0.8214 for the original 

40-year licensed operating period. The projected number of cycles of the design basis 

events does not exceed the design basis limit during the extended licensed operating 

period. Therefore, the actual fatigue usage factor is not expected to approach the calculated 

value at the end of the extended licensed operating period.

The fatigue cycle count program, evaluates the severity of each event conservatively. The 

cycle count program will ensure a reanalysis or other appropriate corrective action in the 

unlikely event that a design basis cycle count limit is reached at any time during the 

extended licensed operating period.

4.3.11 Pressurizer Auxiliary Spray Line Tee Fatigue Analysis in Response to NRC Bulletin 

88-08

Summary Description

NRC Bulletin 88-08 and supplements describe observed effects of thermal cycling and 

thermal stratification in reactor coolant system pressure boundary components due to 

thermally-driven cyclic inleakage at isolation valves and similar phenomena. In 1989 a 

conservative, bounding analysis of the section of the Palisades auxiliary spray line from 

check valve CK 2118 to the pressurizer spray line tee demonstrated that fatigue due to 

these effects would be acceptable for the then-remaining 30 year licensed operating life.

The piping material is A 376 Type 316. The auxiliary spray line connects to the normal spray 

line vertically and below, so that the cooler auxiliary spray water does not cause a thermal 

stratification effect. The analysis assumed 500 lifetime operating basis earthquake (OBE) 

cycles and 500 lifetime full-range thermal expansion (heatup and cooldown) cycles. It 

modeled the Bulletin 88-08 phenomena (due to inleakage through the check valve) as a 

thermal cycle every two minutes, between 536 and 400 oF, or 1.84 x 105 per year at a 70 

percent availability factor.

The 500 lifetime OBE cycles are assumed to occur only once in a design lifetime, 

independent of its length. The analysis also conservatively attributed the entire 500 

full-range thermal expansion to the remaining 30 year life. These OBE and full-range 

thermal cycles contributed a negligible 0.0063 usage factor. The assumed Bulletin 88-08 

cycles contributed 0.4245 in 30 years, for an end-of-life cumulative usage factor (CUF) of 

0.43

Analysis

License renewal will add an additional 20 years to the design life assumed by the analysis. 

Increasing the lifetime contribution of the OBE cycles and full-range thermal expansion 
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cycles by 50% (a conservative assumption for OBE, and given the plant history, also for the 

full-range thermal cycles) results in a contribution of only 0.0095. Increasing the assumed 

remaining design life to 50 years results in a contribution from the Bulletin 88-08 cycles of 

0.7075, for a 60-year CUF of 0.717, well within the allowable of 1.0.

The analysis assumed 70 percent plant availability. Recent experience has been about 90 

percent, which would increase the contribution of the Bulletin 88-08 cycles to about 0.91, or 

a CUF of about 0.92. 

Disposition: 10 CFR 54.21(c)(1)(i), the analysis remains valid for the extended 

operating period

The assumptions and methods of the analysis are otherwise very conservative, and this 

result is still within the allowable of 1.0.

4.3.12 Absence of a TLAA for ASME III Class 1 HELB Locations and Leak-Before-Break 

Analyses Based on Fatigue Usage Factor

Review of the Palisades licensing basis and the associated HELB reports revealed that 

selected break locations, either inside or outside containment, were not dependent on aging 

factors. Therefore, HELB analyses at Palisades are not TLAAs.

4.3.13 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction 

Factor in Piping and Components

This section addresses the issue of assumed thermal cycle counts which determine an 

allowable secondary stress range reduction factor for some Consumers Power Design 

Class 1 piping and components, and for non-Consumers Power Design Class 1 piping and 

components.

Summary Description

Only the primary coolant system piping and components have an ASME Class 1 fatigue 

analysis (see Section 4.3.8). Other Consumers Power Design Class 1 piping and 

components were designed to the ANSI B31.1 Power Piping Code, ASME Section VIII, or 

ASME III, Class 2 and 3, which requires a stress range reduction factor to the allowable 

stress range for secondary (expansion and displacement) stresses to account for thermal 

cycling. For ANSI B31.1 the allowable secondary stress range is 1.0 SA for 7,000 equivalent 

full-range thermal cycles or less. The allowable secondary stress range is reduced to 0.5 SA

for thermal cycles greater than 100,000. Components designed to other codes, such as 

ASME VIII, have identical or very similar provisions. An increase in design life could 

increase the number full-range thermal cycles, therefore, design analyses under these 

codes are TLAAs.
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Some piping within the scope of license renewal was originally designed and built to the 

American Standard (ASA) Code for Pressure Piping, Section 1, “Power Piping Systems,” 

1955 edition.1 However, during the implementation of IE Bulletin 79-14 work, CP Co Design 

Class 1 piping, except the main primary coolant piping, was designed to the USAS B31.1.0 

(1967) Power Piping Code. In 1992, as a result of discussions between CP Co and the 

NRC, for new and existing CP Co Design Class 1 piping (except the main primary coolant 

piping), the code of record was changed to ANSI B31.1 (1973) Power Piping Code with the 

Summer (1973) Addenda (FSAR 5.10.1.1).

With regard to the stress range reduction factors and corresponding thermal cycle count 

assumptions, the Consumers Power Class 2 and 3 piping systems and components are 

designed to the same requirements as CP Co Design Class 1 piping.

The review of possible TLAAs found no Palisades piping and components design analyses 

to the B31.1 rules, which invoke lower stress range reduction factors for an increase in the 

equivalent full-range thermal and displacement cycles.

Analysis

The number of lifetime (full-range and equivalent) thermal and other displacement cycles 

applicable to most of the Palisades B31.1 piping and components are expected to be similar 

to the plant events defined in Table 4.3.1-1. Therefore, so long as the assumed number of 

the plant design basis event cycles is not exceeded, the secondary stress range reduction 

factors assumed for these B31.1 piping and components, and similar code designs remain 

valid.

Results of the TLAA fatigue review for B31.1 piping and similar code designs for mechanical 

systems within the scope of license renewal and with operating temperature in excess of 

220o F for carbon steel or 270o F for austenitic stainless steel, revealed only two piping 

systems that have additional cycles that exceed the 7000-cycle limit of the B31.1 Code. 

These systems include the charging lines inboard of the regenerative heat exchanger, which 

experience an increase in partial-range thermal cycles due to cycling of the fixed-speed 

pumps. The original 6,000 events increased to 18,000 for 40-year and 27,000 for 60-year 

life. The effects of additional cycles have been evaluated for the Regenerative Heat 

Exchanger fatigue and for the Charging Inlet nozzle (see Section 4.3.7 and Section 4.3.8). 

The calculation will be revised to include the effects of the additional cycles on charging 

lines. The other system is the PCS hot leg sampling piping, which may exceed 7,000 cycles 

during the period of extended operation. A calculation will be performed to justify PCS 

1.Predecessor to the ANSI B31.1 Power Piping Code, and sometimes identified as “ANSI B31.1 

1955." The forward to USA Standard USAS B31.1.0 1967, the first edition of USAS-ANSI B31.1, 

similarly mentions “B31.1 1955." However the 1955 Power Piping Code preceded both the USAS and 

ANSI designations, and it was not numbered.
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sampling to occur at any reasonable frequency for 60 years of operation without exceeding 

the allowable number of cycles.

Disposition for the Charging Lines Inboard of the Regenerative Heat Exchanger: 

Revision, 10 CFR 54.21(c)(1)(ii)

NMC will evaluate the effect the increase in variable speed charging pump out-of-service 

events may have on these lines, and will take actions necessary to ensure these lines meet 

licensing basis design criteria for the extended operating period. NMC will complete this 

evaluation and will advise the NRC of the results, and of any necessary corrective actions, 

before the end of the current licensed operating period.

Disposition for Other Piping and Components: Validation, 10 CFR 54.21(c)(1)(i), and 

Aging Management, 10 CFR 54.21(c)(1)(iii)

The number of lifetime (full-range and equivalent) thermal and other displacement cycles 

applicable to most of the Palisades B31.1 piping and components are expected to be similar 

to the plant events defined in Table 4.3.1-1. The number of each of these events is not 

expected to exceed the existing 40-year design basis for the 60-year extended licensed 

operating period.

The Fatigue Monitoring Program will ensure reanalysis or other appropriate corrective 

action in the unlikely event that a design basis cycle count limit is reached at any time during 

the extended licensed operating period.

4.3.14 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and 

Components (Generic Safety Issue 190)

Summary Description

The effects of the reactor coolant environment may need to be included in the calculated 

fatigue life of components. GSI-190 addressed this issue. Although the parent GSI-190 

safety issue has been resolved, NUREG-1800, Section 4.3.1.2, states that “The applicant's 

consideration of the effects of coolant environment on component fatigue life for license 

renewal is an area of review.” The GSI-190 review requirements are therefore imposed by 

the Standard Review Plan and do not depend on the individual plant licensing basis.

Analysis

NUREG/CR 6260, Table 5-43, identifies seven sample locations for older Combustion 

Engineering plants:

• Reactor Vessel (Lower Head to Shell Transition)

• Primary Coolant Inlet Nozzle

• Primary Coolant Outlet Nozzle
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• Surge Line Elbow

• Charging Nozzles

• Safety Injection Nozzles

• Shutdown Cooling Line Inlet Transition.

Of these:

• Palisades has no “shutdown cooling line inlet transition.” The safety injection and 

shutdown cooling functions share a common nozzle.

• NUREG/CR-6260 evaluated a long-radius elbow in the surge line because, in the sample 

plant, this was the highest usage factor location in the surge line and nozzles subject to 

NRC Bulletin 88-11 reanalysis for thermal stratification cycles. In the NUREG/CR-6260 

sample plant this component is SA-376 Type 316; at Palisades the surge line material is a 

similar Type 316. The only Palisades location on this line with a plant-specific fatigue 

analysis is the hot leg nozzle to the surge line. The analysis for the surge line elbow is for 

a typical C-E PWR with intermittent pressurizer spray, with thermal stratification 

transients; and the pressurizer surge nozzle analysis uses pipe loads from the same 

source. The results are therefore more conservative than would be expected for 

Palisades, which has a continuously-modulated pressurizer spray and less-severe 

thermal transients.

• The Palisades charging nozzles are SB 166 Ni-Cr-Fe Alloy 600 instead of the austenitic 

stainless of the NUREG/CR-6260 sample plant. However, Alloy 600 is evaluated the 

same as austenitic stainless for these purposes.

Of the seven NUREG/CR-6260, Section 5.2, sample locations for an older Combustion 

Engineering plant, six are therefore applicable to Palisades. See Table 4.3.14-1, below.

Environmental effects on cracking in the charging and other Alloy 600 nozzles are also 

addressed in Section 4.7.2, fatigue in the charging nozzles in Section 4.3.8, and fatigue in 

the surge nozzles in Section 4.3.9.

All of the primary coolant system at Palisades is stainless steel, Alloy 600, or carbon steel 

with stainless or Alloy 600 clad. Fatigue in clad components is evaluated using base 

material properties only; that is, as if the coolant is in contact with the base material, 

consistent with NUREG/CR-6260.
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Disposition: Revision, 10 CFR 54.21(c)(1)(ii); and Aging Management, 10 CFR 

54.21(c)(1)(iii)

A plant-specific calculation was performed for the six sample locations applicable to 

Palisades, adapted from the seven identified in NUREG/CR-6260 for older-vintage 

Combustion Engineering plants. Detailed environmental fatigue calculation use the 

appropriate Fen relationships from NUREG/CR-6583 for carbon and low-alloy steels and 

from NUREG/CR-5704 for stainless steels, as appropriate for the material at each of these 

seven locations.1

Table 4.3.14-1 Summary of Fatigue Usage Factors at NUREG/CR-6260 Sample 

Locations Applicable to Palisades

Location Material

CUF for 

Design 

Cycles

Fen

NUREG/

CR-5999 CUF 

for Design 

Cycles

Reactor Vessel (Lower 

Head to Shell 

Transition)

SA-302 Grade B 0.00364 2.53 0.009

Primary Coolant Inlet 

Nozzle SA-302 Grade B 0.01702 2.53 0.043

Primary Coolant 

Outlet Nozzle SA-302 Grade B 0.115 2.53 0.29

Charging Inlet Nozzles 

(with Thermal 

Sleeves)

SB-166 Alloy 600 0.288 15.35 4.428

Surge Line Elbow SA-376 Type 316 0.0343 15.35 0.526

Safety InjectionShutdown Cooling 

Nozzles

SA-516 Grade 70 0.048 1.79 0.085

1.Neither NUREG/CR-5704 nor NUREG/CR-5999 provide interim fatigue curves for Alloy 600 

materials. The NUREG/CR-5704/5999 values for stainless steel will therefore be used, consistent with 

the practice of NUREG/CR-6260.
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The calculation determines an appropriate Fen(i) for each individual load pair in the 

governing fatigue calculation, so that an overall Fen multiplier on cumulative usage factor 

(CUF) for environmental effects can be determined for each location. The analysis shows 

that the fatigue usage factors at all NUREG/CR-6260 sample locations, but the charging 

nozzle, including the effects of the reactor coolant environment, will remain less than 1.0 for 

the extended operation period.

The Charging nozzle has an Alloy 600 safe end, and is one of the components in the 

Palisades Alloy 600 Inspection Program, which specifies inspection methods and inspection 

frequency. The Fatigue Monitoring Program will also ensure that the original design basis 

number of load cycles for each loading event is not exceeded. If this occurs, an evaluation 

will be made and appropriate actions will be taken to confirm the basis of the safety 

determination.

4.4 Environmental Qualification of Electrical Equipment

10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants,” requires that certain electrical and instrument and control (I&C) 

equipment be qualified to perform their safety related functions in their harsh accident 

environments after the effects of in-service aging. The Electrical Equipment Qualification 

(EEQ) Program was created to establish and maintain the qualification of the applicable 

plant equipment.

All operating plants must meet the requirements of 10 CFR 50.49 for certain electrical and 

I&C components important to safety. 10 CFR 50.49 defines the scope of components to be 

included, requires the preparation and maintenance of a qualification binder that includes 

component performance specifications, electrical characteristics, and environmental 

conditions. Compliance with 10 CFR 50.49 provides evidence that the component will 

perform its intended functions during and after a design basis accident after experiencing 

the effects of in-service aging.

Summary Description

10 CFR 50.49(e)(5) contains provisions for aging that require, in part, consideration of all 

significant types of aging degradation that can affect component functional capability. 10 

CFR 50.49(e)(5) also requires component replacement or maintenance prior to the end of 

designated life, unless additional life is established through ongoing qualification. 10 CFR 

50.49(k) and (l) permit different qualification criteria to apply based on plant vintage. 

Supplemental Environmental Qualification (EQ) regulatory guidance for compliance with 

these different qualification criteria is provided in the Regulatory Guide 1.89, Rev. 1, 

“Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear 

Power Plants”, the Division of Operating Reactors (DOR) Guidelines, and NUREG-0588.
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The Palisades EEQ Program was established to demonstrate that certain electrical 

components located in harsh plant environment (that is, those areas of the plant that could 

be subject to the harsh environmental effects of loss of coolant accident [LOCA], high 

energy line breaks [HELB] or post-LOCA radiation) are qualified to perform their safety 

function operation in those harsh environments after the effects of in service aging. The 

EEQ Program manages applicable component thermal, radiation, and cyclic aging effects 

for the current operating license period using the qualification methods established by 10 

CFR 50.49(f). Maintaining qualification through the extended license renewal period 

requires that existing EQ evaluations be reanalyzed. A summary of Palisades’ application of 

these 10 CFR 50.49(f) methodologies to the EQ evaluations for the period of extended 

operations follows:

Analysis

Under 10 CFR 54.21(c)(1)(iii), a Plant EEQ Programs which implements the requirements of 

10 CFR 50.49 (as further defined and clarified by the DOR Guidelines, NUREG-0588, and 

RG 1.89, Rev. 1), is viewed as an Aging Management Program (AMP) for license renewal. 

Reanalysis of an aging evaluation to extend the qualification of components under 10 CFR 

50.49(f) is performed on a routine basis as part of the EEQ Program. Important attributes of 

the reanalysis of an aging evaluation include analytical methods, data collection and 

reduction methods, the underlying assumptions, the acceptance criteria, and corrective 

actions (if acceptance criteria are not met).

Analytical Methods: The analytical models used in the reanalysis of an aging evaluation 

are the same as those previously applied during the prior evaluation. The Arrhenius 

methodology is an acceptable thermal model for performing a thermal aging evaluation. The 

analytical method used for a radiation aging evaluation is to demonstrate qualification for 

the total integrated dose (that is, normal radiation dose for the projected installed life plus 

accident radiation dose). For license renewal, one acceptable method of establishing the 

60-year normal radiation dose is to multiply the 40 year normal radiation dose by 1.5 (that is, 

60 years/40 years). The result is added to the accident radiation dose to obtain the total 

integrated dose for the component. For cyclical aging, a similar approach may be used. 

Other models may be justified on a case-by-case basis.

Data Collection and Reduction Methods: Reducing excess conservatism in the 

component service conditions (for example, temperature, radiation, and cycles) used in the 

prior aging evaluation is frequently employed for a reanalysis. Temperature data used in an 

aging evaluation is to be conservative and based on plant design temperatures or on actual 

plant temperature data. When used, actual plant temperature data can be obtained in 

several ways, including monitors used for technical specification compliance, other installed 

monitors, measurements made by plant operators during rounds, and temperature sensors 
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on large motors (while the motor is not running). When used, a representative number of 

temperature measurements are conservatively evaluated to establish the temperatures 

used in an aging evaluation. Plant temperature data may be used in an aging evaluation in 

different ways, such as (a) directly applying the plant temperature data in the evaluation, or 

(b) using the plant temperature data to demonstrate conservatism when using plant design 

temperatures for an evaluation. Any changes to material activation energy values as part of 

a reanalysis are justified on a case-specific basis. Similar methods of reducing excess 

conservatism in the component service conditions used in prior aging evaluations may be 

used for radiation and cyclical aging.

Underlying Assumptions: EQ component aging evaluations contain sufficient 

conservatism to account for most environmental changes occurring due to plant 

modifications and events. When unexpected adverse conditions are identified during 

operational or maintenance activities that affect the normal operating environment of a 

qualified component, the affected EQ component is evaluated and appropriate corrective 

actions are taken, which may include changes to the qualification bases and conclusions.

Acceptance Criteria and Corrective Actions: The reanalysis of an aging evaluation could 

extend the qualification of the component. If the qualification cannot be extended by 

reanalysis, the component is maintained, replaced, or re-qualified prior to exceeding the 

period for which the current qualification remains valid.

Regulatory Issue Summary (RIS) 2003-09

On May 2, 2003, the staff issued NRC Regulatory Issue Summary (RIS) 2003-09, 

“Environmental Qualification of Low-Voltage Instrumentation and Control Cables”, providing 

the results of the staff's technical assessment of GSI-168, following completion of the 

NRC-sponsored cable test research. The staff's technical assessment of GSI-168 in 

RIS-2003-09 is stated as follows:

For license renewal, a re-analysis (based on the Arrhenius methodology) to extend the 

life of the cables by using the available margin based on a knowledge of the actual 

operating environment compared to the qualification environment, coupled with 

observations of the condition of the cables during walk-downs, was found to be an 

acceptable approach. Monitoring I&C cable condition could provide the basis for 

extending cable life.

The Palisades Electrical Equipment Qualification Program allows re-analysis for maintaining 

qualification using the methods described above. In addition, the EEQ Program has 

procedural requirements in place to monitor and track aging effects of EQ equipment 

including cables. The requirements are listed below:

• Monitoring equipment condition and equipment performance 
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• Monitoring environmental conditions of plant areas, and 

• Incorporating the results of testing and analysis into the plant maintenance and 

surveillance program.

Disposition: 10 CFR 54.21(c)(1)(iii)

The EEQ Program will continue to be implemented for the extended operating period in 

accordance with 10 CFR 50.49. Continuing the existing EEQ Program provides reasonable 

assurance that the aging effects will be managed and that the EQ components will continue 

to perform their intended functions for the period of extended operation. Therefore, the 

disposition of the TLAA is the performance of the existing EEQ Program which meets the 

requirement of 10 CFR 54.21(c)(1)(iii). See Appendix B, Electrical Equipment Qualification 

Program, for additional information.

4.5 Concrete Containment Tendon Prestress Analysis

Summary Description

The Palisades containment is a Consumers Design Class 1 structure. It consists of a 

post-tensioned, reinforced concrete cylinder and dome connected to and supported by a 

massive, reinforced concrete foundation slab. It is designed to ACI 318-63, with some 

adaptations of the design rules and equations, as described in FSAR Section 5.8.

The post-tensioning system consists of three groups of tendons:

• 3 sets of 55 dome tendons (165 total), spaced 120 degrees apart and anchored at 

the vertical face of the dome ring girder.

• 178 vertical tendons anchored at the top surface of the ring girder and at the bottom 

of the base slab.

• 6 sets of hoop tendons (502 total), spaced 60 degrees apart, each spanning 120 

degrees of arc, anchored at 6 vertical buttresses. (The midpoint of each hoop tendon 

therefore passes under the anchor buttress for two other sets of hoop tendons.)

Palisades tendons are ungrouted. The tendon sheaths (glands, conduits) are filled with a 

corrosion preventive medium (CPM). Some sheaths were blocked. Tendons were not 

installed in 2 of the 180 vertical sheaths, nor in 20 of the 522 hoop sheaths. Evaluation of 

the original containment design determined that these tendons were not required. See 

FSAR Section 5.8.2, Section 5.8.5.1, and Section 5.8.5.2 for additional information.

Analysis

The original design included a calculation of expected loss of prestress for the plant design 

life In accordance with ACI 318-63. The calculation evaluated loss of prestress due to 

friction and initial seating loss, tendon relaxation, concrete elasticity, concrete shrinkage, 
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and concrete creep. FSAR Section 5.8.5.3.1 lists the predicted values for remaining 

prestress at the end of the 40 year design life. This original analysis was conservative, as 

demonstrated by a regression analysis of tendon surveillance data from the twentieth and 

twenty-fifth-year tendon surveillances. This regression analysis indicated that the effective 

dome, hoop, and vertical tendon forces would remain significantly higher than values 

predicted by the original relaxation estimates beyond the 40-year licensed operating period.

Periodic surveillances of containment tendons for degradation are required by 10 CFR 

50.55a and Palisades Technical Specification 5.5.5. See FSAR Section 5.8.8 for additional 

information on the existing surveillance program requirements and results. The program is 

also described in Appendix B, Containment Inservice Inspection Program.

Disposition: 10 CFR 54.21(c)(1)(iii)

Periodic tendon surveillance program activities are implemented as part of the Containment 

Inservice Inspection Program. The program follows requirements of ASME Section XI 

Subsection IWL (1998), NRC-approved Relief Requests, 10 CFR 50.55a, including the 61 

FR 154 revision, and the guidance of Regulatory Guide 1.351. The program predicts 

time-dependent lower limits of the lift-off force (predicted lower limits, PLL) for each tendon 

subgroup by regression analysis of individual tendon surveillance data, and maintains trend 

lines of the data for each tendon surveyed. The program inspects a sample of tendons from 

each group (dome, vertical, and hoop) in each inspection interval to confirm that the trend 

lines remain within the tolerances of the predicted lower limits, and therefore that tendon 

prestresses will remain above their respective minimum required values (MRV) for the 

succeeding inspection interval. The program provides for appropriate actions if surveillance 

data indicate that a trend line may cross its MRV. See Appendix B, Containment Inservice 

Inspection Program, for a more detailed description of the aging management program.

4.6 Containment Liner Plate and Penetrations Load Cycles

The containment structure is a Consumers Design Class 1 structure. The entire interior 

surface of the containment structure is lined with 1/4 inch thick steel plate to ensure a high 

degree of leak tightness. Numerous mechanical and electrical systems penetrate the 

containment wall through steel penetrations which are welded to the containment liner plate. 

See FSAR Section 5.8.2 for additional information.

The containment liner plate and penetrations were conservatively designed, in part, to the 

rules of the ASME Boiler and Pressure Vessel Code, Section III-1965. This code edition 

1.The one- and three-year tendon inspections used Regulatory Guide 1.35 Revision 1. Subsequent 

inspections use Revision 3. Data from the one and three-year inspections cannot be used for predicted 

lower limit (PLL) calculations because the Regulatory Guide 1.35 Revision 1 methods required 

detensioning and retensioning the tendons
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classifies containment as a Class B vessel. A fatigue analysis is required under this code 

edition only for Class A vessels (reactor coolant pressure boundary, etc.). However the 

Palisades containment liner and penetration designs use some of the methods and data from 

Section III, Article 4, for design of Class A vessels for fatigue loads.

4.6.1 Containment Liner Plate Load Cycles

Summary Description

The containment liner plate is stitch welded to a gridwork of structural steel angles 

embedded in the concrete. The anchoring system is designed to prevent significant 

distortion of the liner plate during accident conditions and to ensure that the liner 

maintains its leak-tight integrity. The liner plate has been coated on the inside for 

corrosion protection. There is no paint on the side in contact with the concrete. See 

FSAR Section 5.8.2 for additional information.

The Palisades containment design relies on the liner only to maintain a leak-tight 

containment. There are no design conditions under which the liner plate is relied upon 

to assist the concrete in maintaining the integrity of the structure. At times, provide 

assistance in order to maintain deformation compatibility.

Stress concentrations around penetration openings in the liner plate are calculated 

using the theory of elasticity. These stress concentrations were then reduced, by 

thickening the liner plate around each penetration in accordance with the ASME B&PV 

Code, Section III, 1965.

FSAR Section 5.8.3.2.1 states that the following fatigue loads were considered in the 

design of the liner plate:

1. Thermal cycling due to annual outdoor temperature variations. The number of cycles 

for this loading was 40 cycles for the Plant life of 40 years. However, the impact of 

outdoor temperature variations upon liner plate stresses, insulated by the 3'6" 

concrete containment wall, is negligible in comparison with the stresses caused by 

the design basis accident temperature. The annual outdoor temperature variations 

are not the controlling design consideration because the design loads related to 

accidents result in higher stress conditions.

2. Thermal cycling due to containment interior temperature varying during the start-up 

and shutdown of the reactor system. The number of cycles for this loading was 

assumed to be 500 cycles.

3. Thermal cycling due to the DBA was assumed to be one cycle.

The liner plate was analyzed for these fatigue loadings using Figure N-415(a) of the ASME 

Boiler and Pressure Vessel Code, Section III, Article 4, 1965. Since this figure does not 
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extend below ten cycles, ten cycles were used conservatively for the DBA instead of one 

cycle as indicated above. The resulting stresses were insignificant. 

Analysis

The Palisades containment design relies on the liner to maintain a leak-tight containment. 

However, there are no design conditions under which the liner plate is relied upon to assist 

the concrete in maintaining the integrity of the structure. Forces are transmitted between the 

liner plate and the concrete through the anchorage system and through direct contact 

(pressure). At times, forces may also be transmitted by bond and/or friction. These forces 

cause, or are caused by, liner plate strains. The liner plate is designed to withstand the 

predicted strains. The effect of concrete cracking on the liner plate has also been 

considered.

The allowable liner plate strains/stress was conservatively based on the ASME B&PV Code, 

Section III, Article 4, 1965. Specifically, the following sections were adopted as guides in 

establishing allowable strain limits:

1. Paragraph N-412(m) - Thermal Stress, Subparagraph 2

2. Paragraph N-412(n) - Operational Cycle

3. Paragraph N-414.5, Table N-413, Figures N-414 and N-415(a) - Peak Stress Intensity

4. Paragraph N-415.1 - Vessels Not Requiring Analysis for Cyclic Operation

The liner strains/stresses due the (non-DBA) loads are relatively small such that the number 

of environmental and operational load cycles is insignificant compared to the allowable 

number of cycles on the fatigue curve in code Fig. N-415 (a), or compared to 3 times the Sm

value of code of Table N-421 at the operational temperature. The results of the analysis 

confirm that the design of the containment liner complies with the provisions of code 

paragraph N-415.1 for not requiring a fatigue analysis for design load cycles.

Disposition: Validation, 10 CFR 54.21(c)(1)(i)

Of the design basis fatigue load cycles of the containment liner, only the number of 

environmental and operational load cycles would increase due to the 60-year extended 

licensed operating period.

Of these two events, the effect of the assumed summer-winter annual cycles is negligible, 

and will remain negligible on increase from 40 to 60 cycles for the 60-year extended 

licensed operating period.

The assumed 500 containment interior operational heatup and cooldown cycles is very 

conservative, since it corresponds to an average of 8 1/3 cycles per year, or a PCS 
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cooldown and heatup every 6 weeks. This is more than adequate to accommodate the 

60-year extended licensed operating period.

Therefore, there will be negligible change in the fatigue resistance of the containment liner 

for the 60-year extended licensed operating period. 

4.6.2 Containment Penetration Load Cycles

Summary Description

FSAR Section 5.8.3 and Section 5.8.6.4 describe design of both the “large penetrations” 

(personnel air lock and equipment hatch) and the “small penetrations” (escape air lock, 

piping, ventilation, and electrical penetrations) to limiting strain criteria for a set of design 

loads, including thermal loads and design basis accident (DBA) loads.

FSAR Section 5.8.6.4.1 describes the design of the pipe penetrations to acceptance criteria 

for combined primary and secondary stresses under the ASME Boiler and Pressure Vessel 

Code, Section III-1965, Article 4. Figure N 415(a) of that article is a fatigue S-N diagram 

(stress versus number of allowed cycles, or vice-versa) for alternating stress intensity Sa 

versus N, for carbon steel.

Although the FSAR § 5.8.6.4.1 description states (1) that “The allowable value of stress 

intensity Sa was determined from Figure N 415(a) of the referenced ASME Code article,” 

and (2) that “For all load combinations, the strains in the pipe penetrations did not exceed 

[those for which an equivalent Sa would exceed] the values given in the ASME B&PV Code, 

Figure N 415(a),” it appears that the only event for which the N-415(a) stress criterion was 

used was the end-of-life design basis event. 

Numerous mechanical and electrical subsystems penetrate the containment wall through 

steel penetrations, which are welded to the containment liner plate. Personnel and 

equipment access to the containment is provided by a personnel air lock with 2 - 3 foot 6 

inch x 6 foot 8 inch doors, an escape air lock with 2 - 30 inch diameter doors, and an 

equipment hatch with a single door that provides total access to the 12 foot diameter 

[equipment] passageway. The air locks and hatch were fabricated from ASTM A-516, Grade 

70, firebox quality steel, made to the requirements of SA-300, Charpy V notch tested at a 

temperature of 0o F, and conforming to the requirements of the ASME Boiler and Pressure 

Vessel Code, Section III.

Containment penetrations are designed to maintain the leak tightness of the containment 

structure under normal and accident conditions. They are designated as CPCo Design 

Class 1 components of the containment structure.

Piping, HVAC, and electrical penetrations are designed, fabricated, inspected, and installed 

in accordance with the ASME B&PV Code, Section III, Subsection B.
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The design and fabrication of the personnel airlock, the escape airlock, and all portions of 

the equipment hatch extending beyond the concrete shell conform to the requirements of 

the ASME B&PV Code, Section III.

The limiting steel strain/stress in the penetrations is conservatively based on the ASME 

B&PV Code, Section III, Article 4, 1965.

The inservice functionality of each individual penetration is monitored by means of local 

leak-rate testing (LLRT, also referred to as Type B Test in 10CFR50, Appendix J) in 

accordance with Plant Technical Specifications at a frequency of at least every refueling, but 

not exceeding a two year interval.

Analysis

The allowable liner plate strains/stress was conservatively based on the ASME B&PV Code, 

Section III, Article 4, 1965. Specifically, the following sections were adopted as guides in 

establishing allowable strain limits:

1. Paragraph N-412(m) - Thermal Stress, Subparagraph 2

2. Paragraph N-412(n) - Operational Cycle

3. Paragraph N-414.5, Table N-413, Figures N-414 and N-415(a) - Peak Stress Intensity

4. Paragraph N-415.1 - Vessels Not Requiring Analysis for Cyclic Operation

The liner strains/stresses due the (non-DBA) loads are relatively small such that the number 

of environmental and operational load cycles is insignificant compared to the allowable 

number of cycles on the fatigue curve in code Fig. N-415 (a), or compared to 3 times the Sm

value of code of Table N-421 at the operational temperature. The results of the analysis 

confirm that the design of the containment liner complies with the provisions of code 

paragraph N-415.1 for not requiring a fatigue analysis for design load cycles.

Inservice Local Leak Rate Tests (LLRT)

Plant Technical Specifications requires that the inservice functionality of each individual 

penetration shall be established by means of local leak-rate testing (LLRT, also referred to 

as Type B Test in 10CFR50, Appendix J) at a frequency of at least every refueling, not 

exceeding a two year interval, except as specified below:

1. The equipment hatch and the fuel transfer tube shall be tested at each refueling 

shutdown or after each time used, if that is sooner.

2. A full personnel airlock penetration test shall be performed at six month intervals. During 

the period between the six month tests, when containment integrity is required, a reduced 

pressure test for the door seals shall be performed within 72 hours either after each 
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airlock door opening or after the first of a series of openings. Airlocks opened during 

periods when containment integrity is not required shall be tested at the end of such 

periods at full pressure.

Local leak rate tests are to be performed at a pressure of not less than 55 psig.

Local leak rate tests for checking Personnel Airlock door seals shall be performed at a 

pressure of not less than 10 psig. The Personnel Airlock door seals are tested at a lower 

pressure due to the design of the doors. This pressure is sufficient to determine Personnel 

Airlock door seal operability.

Local leak rate tests for the Emergency Escape Airlock shall be performed at 55 psig. A seal 

contact check shall be performed on the Emergency Escape Airlock following each full 

pressure test. Emergency Escape Airlock door opening, solely for the purpose of 

strongback removal and the performance of the seal contact check, does not necessitate 

additional pressure testing.

Disposition: Validation, 10 CFR 54.21(c)(1)(i)

Of the design basis fatigue load cycles of the containment penetrations, only the number of 

environmental and operational load cycles would increase due to the 60-year extended 

licensed operating period. 

Of these two events, the effect of the assumed summer-winter annual cycles is negligible, 

and will remain negligible on increase from 40 to 60 cycles for the 60-year extended 

licensed operating period.

The assumed 500 containment interior operational heatup and cooldown cycles is very 

conservative, since it corresponds to an average of 8 1/3 cycles per year, or a PCS 

cooldown and heatup every 6 weeks. This is more than adequate to accommodate the 

60-year extended licensed operating period.

Therefore, there will be negligible change in the fatigue resistance of the containment 

penetrations for the 60-year extended licensed operating period.

In addition, periodic inservice LLRTs required by Plant Technical Specifications monitor the 

continued inservice leaktight functionality of each individual penetration through the 

extended licensed operating period.
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4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Crane Load Cycles

Summary Description

A crane evaluation to the Crane Manufacturers Association of America Standard CMAA-70 

assumes a number of rated lifts in the design lifetime in order to establish the design Service 

Level, and hence the allowable stresses. At Palisades, two cranes have been reanalyzed to 

CMAA-70 design criteria. The NUREG-0612 heavy loads evaluation of the reactor building 

polar crane was performed to CMAA 70. A redesign of the Spent Fuel Pool Crane for dry 

fuel storage also included a NUREG-0612 evaluation to CMAA-70 design criteria. The 

limiting components of the containment polar crane (135 tons) and the redesigned spent 

fuel pool crane (110 tons) are now rated for CMAA-70 “Service Level A - Standby or 

Infrequent Service.” 

Therefore, the analyses of the Polar Crane and the Spent Fuel Pool Crane are TLAAs for 

license renewal purposes.

Analysis

Containment Polar Crane: The polar crane was originally designed to Electric Overhead 

Crane Institute Specification 61. The subsequent NUREG-0612 heavy loads evaluation of 

the polar crane was performed to CMAA 70 (1975). The minimally-rated components are 

CMAA 70 Service Level A. Since the minimally-rated components are Service Level A, the 

effective crane design life for fatigue or allowed number of rated lifts depends on this 

classification, which assumes 20,000 to 100,000 rated lifts in a design lifetime.

Separate evaluations have been performed of polar crane planned engineered lifts (over the 

rated capacity). The evaluations were done to ANSI/ASME Standard B30.2 (1996). Lifts 

have been evaluated and approved up to 140 T, less than 4 percent over the 135 T rating.

Spent Fuel Pool Crane: The redesign to 110 T for dry cask storage included a NUREG-0612 

evaluation to CMAA-70 Service Level A design criteria, and other considerations; and 

replacement of the trolley with a 110 T single-failure-proof trolley meeting NUREG 0554 

guidelines. The structural redesign and evaluation considered the load combinations of 

ASME NOG 1, Section NOG 4140, “Load Combinations.” 

Disposition: 10 CFR 54.21(c)(1)(i)

Polar Crane (L-1): Polar crane rated or near-rated lifts are limited to the reactor head plus 

CRDMs and insulation, and reactor internals. Only a few rated lifts are performed each 

refueling outage, and none during operation. Therefore this machine cannot realistically 

approach the 20,000 to 100,000 rated lifts, assumed for components evaluated to CMAA 70 

(1975) Service Level A, during a 60 year licensed operating period.
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Spent Fuel Pool Crane: Approximately 11 dry cask storage campaigns are expected 

between rerating and the end of the 60 year extended license. This will require loading 

about 64 casks. Each will require about two lifts of 100 T or more per cask, and some 

additional lifts of between 50 and 100 T. The total for 64 casks and 11 campaigns is about 

140 lifts of 100 T or more, and about 162 lifts between 50 and 100 T. Other lifts, and lifts prior 

to rerating the crane, were determined to be inconsequential. Therefore, this machine can 

not realistically approach the 20,000 to 100,000 rated lifts assumed for its design evaluation 

during the 60 year extended licensed operating period.

4.7.2 Alloy 600 Nozzle and Safe End Life Assessment Analyses

Summary Description 

Alloy 600 (Ni-Cr-Fe alloy) was used to clad the pressurizer lower head and surge nozzle, for 

the pressurizer heater sleeves, and for smaller nozzles and safe ends and flanges on larger 

nozzles of the Palisades reactor vessel head, primary coolant system loop piping, and 

pressurizer. There were originally 251 Alloy 600 heater sleeves, nozzles, safe ends, and 

flanges in the Palisades primary coolant system.1

By the 1990's Alloy 600 had become recognized as being susceptible to a cracking 

phenomenon identified as Primary Water Stress Corrosion Cracking (PWSCC). A significant 

contributing factor to the initiation and propagation of PWSCC was determined to be 

temperature. Thus, since the pressurizer has the highest operating temperature of any 

location in the Primary Coolant System (PCS), a reasonable first assumption is that the 

Alloy 600 in its nozzles would develop PWSCC first.

Evidence of PWSCC was first noted at Palisades in September 1993 when a through-wall 

crack was found in the pressurizer Power Operated Relief Valve (PORV) nozzle safe end to 

pipe weld heat affected zone. The crack was found after the PCS leak rate increased while 

the plant was in hot shutdown. The plant was returned to cold shutdown and the leak was 

repaired. The cracked section of field weld was removed, the safe end modified for a new 

weld prep, and a short new section of stainless steel pipe installed to replace the material 

that was removed. The failed section was saved for thorough analysis of the failure 

mechanism. The failure mechanism was attributed to PWSCC.

Second and third failures of Alloy 600, apparently by PWSCC, occurred in October 1993 

immediately following the repair of the PORV nozzle safe end. Eddy Current inspection 

identified several axially oriented cracks in the vicinity of the “J groove” weld that attaches 

the nozzle to the pressurizer head. This type of cracking in this style of weld has been seen 

1.Now 250. The PORV nozzle safe end has been has been replaced with 316 stainless plus an Alloy 

690 weld.
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in multiple other nuclear plants and is caused by PWSCC. An inspection of the lower shell 

temperature element also identified leakage from around the nozzle. Both temperature 

element nozzles were repaired by welding a new attachment pad on the exterior of the 

pressurizer. See FSAR Section 4.3.7 for additional information.

As a result of the PORV nozzle safe end failure and the metallurgical exams performed on 

the failed material, it was decided that replacement of the safe end with a less susceptible 

material was prudent. During the 1995 refueling outage, the Alloy 600 PORV nozzle safe 

end was replaced with a new Type 316 stainless steel safe end/spool piece using Alloy 690 

for the attachment weld to eliminate PCS contact with Alloy 600 from the pressurizer PORV 

nozzle. The NRC reviewed the use of forged (SB-564) Alloy 690 material, and issued an 

SER.

Due to the previous PWSCC failures, a heightened awareness to the potential for future 

PWSCC exists for the Alloy 600 penetrations in the entire Primary Coolant system. During 

the 1995 refueling outage, inspections of many of the Alloy 600 penetrations were 

performed to establish a reference for future PWSCC inspections. No indication of PWSCC 

was detected during those inspections. Also during the 1995 refueling outage, the 

Mechanical Stress Improvement Process (MSIP) was applied to the PCS nozzles on both 

ends of the pressurizer surge line and to the shutdown cooling outlet nozzle to mitigate any 

possible PWSCC by removing tensile stresses on the inside diameter of the piping. It 

consisted of using a hydraulically powered clamp ring assembly to squeeze the piping in the 

vicinity of the weldment, leaving a permanently deformed ring that is deformed 

approximately 1% in the radial direction. MSIP is accepted by the NRC for mitigating 

inter-granular stress corrosion cracking in BWRs. See FSAR Section 4.3.7 for additional 

information.

The 1995 inspections included eight in-core instrumentation (ICI) nozzles. The Combustion 

Engineering Owner's Group timing model described in CEOG-97-244 indicated that these 

nozzles were highly susceptible to PWSCC, due to high hillside angles (54.4o), high yield 

strength (60 ksi), and long service hours (approximately 100,000 effective full-power hours). 

Eddy current inspection of the ICI nozzles detected no evidence of cracking. 

Analysis

The inspection methods and intervals of the Palisades Alloy 600 aging management 

program were determined from evaluations of the susceptibility of all 250 remaining heater 

sleeves, nozzles, safe ends, and flanges to primary water stress corrosion cracking 

(PWSCC).

Alloy 600 was also used for the primary-side steam generator head drain plugs, steam 

generator tubes, and reactor flange leak detector taps. None of these were evaluated for 
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PWSCC, nor included in the Alloy 600 inspection program. The steam generator drain plugs 

are solid tapered plugs inserted from the inside and therefore not subject to ejection. The 

steam generator tubes are subject to the tube inspection and aging management program, 

whose supporting analyses do not depend on licensed design life. The reactor flange leak 

detector taps are not primary system pressure boundaries.

Assessment of Reactor Vessel Head Vent, In-Core Instrumentation, and CRDM 

Nozzles; and Pressurizer Relief Valve Flanges, Heater Sleeves, and Level Nozzle Safe 

Ends: The assessments of the susceptibility of these components to PWSCC are based on 

industry experience and industry analyses, but are qualitative and do not depend on the 

licensed operating period. 

Fracture Mechanics Assessment of the Most-Susceptible Pressurizer Locations; and 

of All Primary Coolant System Alloy 600 Loop Penetrations and Nozzle Safe Ends: An 

ASME XI, IWB-3612 fracture mechanics analysis was performed on 13 types of Alloy 600 

nozzles and safe ends on the pressurizer and on the primary coolant hot and cold legs. This 

analysis omits those locations for which only a qualitative assessment was performed, as 

described above, and the pressurizer PORV nozzle safe end, which was replaced with other 

material.

The analysis calculated allowable axial and circumferential flaw depths at three aspect 

ratios (l/a = 2, 4, and 6) for one 18-month operating cycle in each of these nozzles or safe 

ends, to confirm that a limiting allowable flaw is detectable; and calculated time to failure 

(assuming a uniform frequency of design basis cycles) for an initial 0.010-inch-deep axial 

and circumferential flaw, at each of these three aspect ratios.

Table 4.7.2-1Summary of Fracture Mechanics Assessment of Susceptible 

Pressurizer and Primary Coolant System Alloy 600 Locations

Nozzle or Safe End (SE)

Limiting Initial 

and Allowable 

Flaw Type (all 

are l/a = 6)

Limiting 

Allowable 

Flaw Depth 

for an 

18-Month 

Cycle, in.

Life for 

0.010" 

Initial 

Flaw, yr.

TLAA

?

1 Pressurizer Temperature 

Element TE-0101 and 

TE-0102 Nozzles

Axial 0.020 7.68 No

2 Pressurizer Surge SE Circumferential 0.320 40 Yes
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The analysis found that fatigue alone accounted for only about one percent of crack growth. 

Primary water stress corrosion cracking accounted for the remainder.The analysis also 

3a Pressurizer Spray SE, 

540o F Circumferential 0.360 40 No

3b Pressurizer Spray SE, 

640o F Circumferential 0.130 5.36 No

4 Hot Leg Surge SE Axial 0.320 40 Yes

5 Hot Leg -Shutdown 

Cooling SE Axial 0.300 40 Yes

6 Hot Leg Loop Drain 

Nozzle Circumferential 0.140 40 Yes

7 Hot Leg Pressure and 

Sampling Nozzle Circumferential 0.125 40 Yes

8 Hot Leg RTD J-Weld 

Nozzle Axial 0.130 40 Yes

9 Cold Leg Safety InjectionShutdown Cooling SE Axial 0.520 40 Yes

10 Cold Leg Spray Nozzle Circumferential 0.225 40 Yes

11a Cold Leg Charging 

Nozzles Circumferential 0.195 40 Yes

11b Cold Leg Loop Drain 

Nozzles Circumferential 0.195 40 Yes

12 Cold Leg Pressure and 

Sampling Nozzle Circumferential 1.180 40 Yes

13 Cold Leg RTD J-Weld 

Nozzle Circumferential 0.240 40 Yes

Table 4.7.2-1Summary of Fracture Mechanics Assessment of Susceptible 

Pressurizer and Primary Coolant System Alloy 600 Locations

Nozzle or Safe End (SE)

Limiting Initial 

and Allowable 

Flaw Type (all 

are l/a = 6)

Limiting 

Allowable 

Flaw Depth 

for an 

18-Month 

Cycle, in.

Life for 

0.010" 

Initial 

Flaw, yr.

TLAA

?
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found that a 0.010-inch flaw might grow beyond critical size in a 40-year design life in only 

the pressurizer temperature nozzles and the spray nozzle safe end, and that in all but the 

temperature nozzles the limiting allowable flaw depth was greater than that detectable by 

approved methods.

Values for all but the pressurizer surge and spray nozzle safe end (Locations 2 and 3 above) 

were calculated with a simplifying assumption of uniform through-wall stress equal to room 

temperature yield stress. With this assumption, an initial 0.010-inch deep, l/a = 6 axial flaw 

in the pressurizer temperature nozzles would fail in 7.68 years.

The final calculation for the surge and spray nozzle safe ends assumed the more realistic 

NUREG-0313 stress distribution model, and found that an initial 0.010-inch deep, l/a = 6 

circumferential flaw in the surge nozzle safe end would only fail after 40 years. A similar flaw 

in the spray nozzle would also endure 40 years at 540o F, but would fail in only 5.36 years at 

640o F.

Additional time-dependent analyses have been performed to support safety determinations 

for these nozzles:

• A fatigue analysis of the replaced PORV safe end. See Section 4.3.6.

• Revised fatigue analyses of the hot-leg-to-surge-line-nozzle and the pressurizer 

surge nozzle for thermal stratification events. See Section 4.3.9.

• Revised fatigue analyses of the cold-leg-to-spray-line-nozzles and the pressurizer 

spray nozzle for high-thermal-differential auxiliary spray actuations. See Section 

4.3.9.

• Fatigue analyses of the weld pad repair of the pressurizer temperature element 

nozzles, an ASME IX Appendix A fracture mechanics crack growth analysis of the 

vessel wall, and additional fracture mechanics and corrosion life assessments of the 

repaired nozzles, weld repair, and vessel wall inside the penetration, are discussed 

below.

• A service life assessment of the pressurizer spray and surge nozzle safe ends are 

discussed below.

Repaired Pressurizer Temperature Element Nozzles: The inner sections of these two 

nozzles are pieces of Alloy 600 pipe inserted through the pressurizer vessel wall and 

attached by welding the inner end of the nozzle to the inner wall of the vessel, using a 

“J”-shaped weld preparation machined in the vessel inner wall. Leaks through the J welds of 

these two nozzles were repaired by adding a weld-deposited pad on the vessel exterior. In 

similar situations at other units these nozzles have been repaired by the “half nozzle” 

method, in which the nozzle is cut within the vessel wall thickness to detach it from the J 
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weld at the inner wall. The outer portion of the nozzle is then welded to the outer surface of 

the vessel, with a gap left between the nozzle parts to eliminate differential expansion loads. 

At Palisades these two nozzles were repaired with similar welds without the complete cut, 

but with a partial electrodischarge machining (EDM) cut of the TE-0101 upper head nozzle, 

the one subject to the highest differential thermal expansion loads and fatigue usage factor.

The upper head nozzle is subject to the highest fatigue usage, highest temperature, and 

worst environment, and therefore this nozzle has the most limiting fatigue and fracture 

mechanics design life of these two nozzles. Fatigue analyses of the weld pad repairs 

installed in 1993 for the temperature element nozzles were based on half the specified 

event cycles for the pressurizer, that is, for a nominal remaining life of 20 years. The 

analysis assumed a very conservative stress concentration factor of 5.0, for weld 

discontinuities. The maximum calculated fatigue usage factor is 0.823, for the upper head 

nozzle repair pad.

An ASME XI Appendix A crack growth evaluation of postulated flaws in the pressurizer base 

metal at the original J-welds of the temperature element nozzles found that flaws left in 

place would not propagate sufficiently to permit a brittle fracture during the remaining portion 

of the original 40-year licensed operating period. For crack growth the only significant 

events are the cool-down transient and system leak tests. The calculation assumed the 

design basis 500 cool-down events and 320 leak tests. However this analysis was later 

superseded by a bounding ASME XI Paragraph IWB 3132.4 analysis of the hot leg, piping 

RTD and sampling nozzles, pressurizer instrument nozzles, and pressurizer heater sleeves, 

described below.

The fatigue analysis of the weld pad repairs and the ASME XI Appendix A crack growth 

evaluation are therefore TLAAs. The following additional fracture mechanics and corrosion 

evaluations of the two pressurizer temperature nozzles support safety determinations, but 

either the evaluations were not used for the final safety determination, or did not depend on 

design life, and are therefore not TLAAs.

The fracture mechanics crack growth assessment of the Alloy 600 pressurizer temperature 

nozzles found that a crack below the detectable size might propagate through the nozzle 

wall in as few as 7.68 years, for which fatigue contributed only about one percent. A 

subsequent service life assessment of these nozzles also considered general corrosion in 

the pressurizer wall, and found that the limiting concern was the previous 7.68-year crack 

growth assessment. This limit was however not used as the basis for the safety 

determination of the final justification for continued operation.

The final justification for continued operation (final JCO) of these nozzles, welds, and the 

adjacent pressurizer wall evaluated corrosion of the carbon steel pressurizer wall, and 
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primary water stress corrosion cracking (PWSCC) and fatigue in the nozzle material and in 

the repair weld pad. The final JCO found that the 7.68-year service life estimate from the 

fracture mechanics crack growth assessment is acceptable, because other effects 

(corrosion) are not limiting, and because the effects of the predicted cracks can be detected 

before a full circumferential failure can occur.

Corrosion: The carbon steel vessel wall is subject to corrosion because it is exposed to 

reactor coolant through the observed cracks in both nozzles, and because of the EDM cut 

through the upper head temperature nozzle. The final JCO cited the above service life 

assessment, a separate corrosion evaluation report, and examination results of a similar 

situation at another plant to demonstrate that the corrosion rate is “extremely low,” and to 

conclude that the nozzles are acceptable, considering this effect, “for more than 20 years.” 

This statement of the safety determination is not, per se, time-limited, but reflects the intent 

of the analysis to show that effects are acceptable for at least the original licensed operating 

period.

The supporting corrosion evaluation in the service life assessment was quantitative, 

concluding that corrosion might increase the diameter of the bore through the pressurizer 

base metal surrounding the upper temperature nozzle by about 0.28 inch, and about 0.14 

inch at the lower nozzle, for the extended 60 year licensed operating period. This corrosion 

evaluation did not complete a safety determination on a quantitative basis. The safety 

determination of the final JCO was made by a qualitative rather than a quantitative 

assessment of these facts.

PWSCC at the temperature element nozzle Inner Surface: Experience and the expected 

state of stress indicate that axial cracks may occur but that circumferential cracks are 

extremely unlikely. Axial cracks result in leaks which are readily detected on inspection, but 

which do not permit nozzle ejection.

PWSCC at the Weld Pad Root: The weld pad root is exposed to primary coolant only via 

existing or new cracks in the nozzles, or through the EDM cut in the upper temperature 

nozzle. The weld material should be less susceptible to PWSCC than the nozzle material, 

and is thicker than the nozzle material. 

This final JCO concluded that corrosion of the base material should be minimal and 

acceptable for the remaining life of the plant, that PWSCC would produce axial cracks in the 

nozzle material before any full circumferential failures of either the nozzle or nozzle-to-pad 

weld region, and which would therefore be detected as minor leakage, and repaired, before 

a full circumferential break might occur. This determination that a detectable leak will occur 

before a full circumferential break, plus limited expected corrosion, are the bases for the 

safety determination. The corrosion assessment was performed for the extended 60-year 
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licensed operating period. The limited, 7.68-year predicted life before a new through-wall 

axial crack might occur is one basis for the inspection interval for these pressurizer nozzles, 

but does not qualify the nozzles for a stated design life, and its calculation is therefore not a 

TLAA.

Pressurizer Spray and Surge Nozzle Service Life Assessment

The Service life Assessment of the Pressurizer Spray and Surge Nozzle Safe Ends 

summarized the results of the fracture mechanics survey of most-susceptible locations. The 

assessment noted that with a 40-year predicted life the surge nozzle is of less concern than 

the spray nozzle, since the spray nozzle safe end predicted life is somewhere between 5.36 

years at 640o F and 40 years at 540o F. The Palisades continuous spray operation maintains 

safe end mean temperature nearer the lower value, with greater life. The assessment made 

recommendations for material procurement against possible replacement, and for 

inspections. The inservice inspection plan requires volumetric and surface (penetrant) 

inspection of the spray nozzle safe end every other refueling outage. For the surge nozzle 

and others for which the fracture mechanics survey of most susceptible locations predicted 

a 40-year life, a safety determination is implied in that predicted life. However for the spray 

nozzle, with a more limited or ambiguous predicted life, no such inference can be drawn. 

This assessment of the likely range of the remaining life of the spray nozzle supports the 

inspection plan but supports no explicit safety determination, does not depend on the 

licensed operating period, and is therefore not a TLAA.

Final NRC Safety Evaluation: The final JCO for the temperature element nozzle repairs, 

the fracture mechanics and fatigue evaluations of other Alloy 600 components, and the 

proposed Alloy 600 inspection and aging management program were evaluated by the NRC 

staff and found acceptable in a letter from the NRC to Consumers Power, “Cracking of 

Inconel 600 Components”, dated June 27, 1995.

Bounding Fracture Mechanics Analysis of the Hot Leg, Piping RTD and Sampling 

Nozzles, Pressurizer Instrument Nozzles, and Pressurizer Heater Sleeves: A 

subsequent, bounding ASME XI Paragraph IWB 3132.4 analysis of these components 

addressed repairs of small-bore nozzles attached at the inner pressure boundary wall by 

J-welds whose pressure boundaries have been breached by PWSCC attack in the J-weld 

penetration areas, and provided a justification for leaving a flaw in the nozzle remnant. The 

justification includes the evaluations of the effects of corrosion, stress corrosion, stress 

corrosion cracking, fatigue crack growth and environmental factors.

The bounding fracture mechanics portion of the analysis employs elastic-plastic methods 

with IWB 3600 and Regulatory Guide 1.161 acceptance criteria. The Palisades analysis 

demonstrates the validity of the bounding fracture mechanics analysis by demonstrating 
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that the plant-specific load and thermal events are within those assumed by the bounding 

analysis. The basis for the safety determination of the fracture mechanics evaluation 

calculation will therefore remain valid so long as the numbers of these events do not exceed 

the design basis values. This analysis confirms the conclusions of the earlier final JCO. 

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

Disposition for Fatigue Analyses of the Weld Pad Repairs Installed in 1993 for the 

Pressurizer Temperature Element Nozzles: 10 CFR 54.21(c)(1)(iii)

NMC will monitor the cumulative number of pressurizer temperature element nozzle fatigue 

cycles within the Fatigue Monitoring Program, and maintain a special action level to ensure 

that appropriate actions are taken if at any time the cycle count for any design basis event 

since 1993 reaches the number assumed by these analyses.

For this purpose the fatigue management program will compare cycle counts since the 

repair in 1993 to appropriate action levels. Since the fatigue analyses were based on half of 

the 40-year pressurizer design basis event cycles, the action levels for cycles since then will 

be about half of the 40-year pressurizer design basis event cycles for each event.

Disposition for Corrosion Life Assessment of the TE 0101 Temperature Element 

Nozzle Bore in the Carbon Steel Pressurizer Wall: 10 CFR 54.21(c)(1)(i)

The evaluation estimated a repair lifetime of 52.3 years for this effect following initiation of 

leakage. Leakage was first detected in 1993, after 22 years of operation, which indicates 

that the pressurizer wall can withstand this effect for a total plant life of over 70 years. 

Therefore, the current analyses remain valid for the period of extended operation.

Disposition for Cycle-Dependent Aspects of the Bounding Fracture Mechanics 

Analysis of the Hot Leg, Piping RTD and Sampling Nozzles, Pressurizer Instrument 

Nozzles, and Pressurizer Heater Sleeves; and Disposition for Fatigue Portions of All 

Other Alloy 600 Fracture Mechanics Analyses for a 40-Year Design Life: 10 CFR 

54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The Palisades plant-specific bounding fracture mechanics analysis demonstrates the 

validity of the cycle-dependent aspects of the generic bounding fracture mechanics analysis 

(WCAP-15973-P) by demonstrating that the plant-specific load and thermal events are 

within those assumed by the generic bounding analysis. The basis for the safety 

determination of the fracture mechanics evaluation calculation will therefore remain valid so 

long as the numbers of these events do not exceed the design basis values.

The fatigue cycle count program described in Appendix B, Fatigue Monitoring Program, will 

ensure a reanalysis or other appropriate corrective action if a design basis primary coolant 
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system cycle count limit is reached at any time during the extended licensed operating 

period.

Disposition for All Alloy 600 Heater Sleeves, Nozzles, Safe Ends, and Flanges: 10 

CFR 54.21(c)(1)(iii)

The Palisades Alloy 600 Program identifies the Alloy 600 components in the primary coolant 

system, ranks them according to PWSCC susceptibility, and establishes a program for 

inspection, repairs, and mitigation. All 250 remaining Alloy 600 heater sleeves, nozzles, safe 

ends, and flanges are subject to the inspection program. At all 250 locations the program 

requires at least an insulated VT-2 visual inspection for leakage every refueling outage. 

Locations which are more susceptible to PWSCC, or whose failure could result in a 

more-significant safety hazard, are also subject to initial or periodic bare-metal VT-2, 

volumetric, or penetrant inspections.

NMC will re-evaluate effects of primary water stress corrosion cracking for all Alloy 600 

components for which the current analyses found acceptable crack sizes at 40 years to 

identify those for which the analysis would predict unacceptable crack sizes at 60 years, and 

to identify appropriate additional inspections for them. NMC will complete these 

re-evaluations before the period of extended operation.

4.7.3 ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld Category 

B-L-1 Inspection Interval from 10 Years to 40 Years

Summary Description

The Byron-Jackson DFSS (Diffuser Single Suction) pumps at Palisades are vertical, single 

stage, centrifugal, with top-mounted motors, bottom suction, and single discharge. These 

pumps are classified as Type E under recent ASME code editions (volute, radially-split 

casing, with diffuser vanes that also provide a structural function). Each casing hub and 

inner volute was cast separately from the outer volute shell, and the two were then welded 

together. The castings are Grade CF8M austenitic stainless.

The casings were designed and fabricated to the ASME Boiler and Pressure Vessel Code, 

Section III, 1968. The casings met all requirements of Paragraph N-415.1 for exemption 

from a fatigue analysis. However, additional crack growth and thermal embrittlement 

analyses were performed to support relaxation of the ASME Section XI 10-year Category 

B-L-1 volumetric inspection interval for casing welds, under ASME Code Case N-481.

Analysis

The analysis includes support for its assumption of an initial flaw depth of 8 percent of the 

wall thickness (8% t), instead of the 25% t specified by Code Case N-481; based on the 
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ASME code radiographic inspection standard used for these pumps which requires 

detection of a 2% t flaw.

Crack Growth: The crack growth analysis demonstrated that:

• The initial flaw would not exceed 25% t due to effects of the alternating stress for the 

design basis primary system cyclic events assumed for 40 year design life,

• The resulting 25% t flaw is stable for design, emergency, and faulted loads, and

• The resulting 25% t flaw would not grow to an unstable end-point size for another 5 

years, assuming a uniform rate of design cyclic events equal to their assumed total 

number divided by 40 years.

Thermal Embrittlement: The evaluation of the reduction of fracture toughness due to 

thermal embrittlement assumed that weld material behaved like the CF8M castings, which is 

conservative, since weld materials are not as subject to these effects. The evaluation used 

the J-R curve methodology of NUREG/CR-4513, which yields an aged material toughness 

KJc.

The evaluation of aged material toughness KJc used the most-conservative infinite 

time-at-temperature or “saturation” J-R curve for each material. The results of this 

evaluation of thermal embrittlement effects therefore do not depend on design life, and this 

aspect of the analysis is therefore not a TLAA.

End-Point Crack Size Determination: A crack will become unacceptable if any of the 

following would occur under design, emergency, or faulted loads:

• The crack is unstable against non-ductile propagation (“brittle fracture”).

• The crack is unstable against ductile tearing.

• The remaining ligament cannot carry its design loads, based on its flow stress.

Stability Against Brittle Fracture: Stability against brittle fracture is, in part, determined by 

the material fracture toughness, and, therefore, depends, in part, on any reduction of 

fracture toughness due to thermal embrittlement. Stability is indicated if the applied stress 

intensity factor KI

 (ASME Section XI, Equation A-3300 (1)), for all load conditions at all 

locations of concern, remains less than the aged material toughness KJc.

At Palisades the maximum end-point values (at the volute crotch) is KI

 = 130, minimum KJc

= 152.3, and median KJc = 223.5 (all in ksi-in1/2). Therefore substantial margins would 

remain at the end of a 40 year life, even assuming KI

 is the maximum that would result from 

a complete design basis complement of load cycles. Of these two parameters, KI

 depends 

on the loading and the flaw sizes at the end of evaluation period, and the aged material 

toughness KJc in this analysis is the saturation J-R curve for each material. Thus the 

expected additional thermal aging effect will not diminish the KJc assumed by the analysis, 
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the analysis will remain acceptable so long as the design basis complement of load cycles is 

not exceeded, which will ensure that the worst-location KI

 remains below 130 ksi-in1/2.

Stability Against Ductile Tearing: Stability against ductile tearing is ensured if the applied 

crack extension J never reaches the J-integral required to initiate ductile tearing. This 

condition is also satisfied so long as KI

 does not exceed KJc, as above.

Flow Stress Ligament Capacity Limit: The flow stress ligament capacity limit is defined as 

the crack size for which a ligament flow stress evaluation no longer demonstrates that the 

ligament will support the required loads. At Palisades the flow stress ligament capacity limit 

is the most time limiting of these three criteria. The critical crack size based on this criterion 

would be exceeded in a little over 45 years, assuming the 40 year design basis cycle count 

limit is reached at 40 years for all load events, and that the load cycles continue to 

accumulate at a constant rate.

Since the margin to the KJc vs. KI

 brittle fracture stability criterion will not change, the 

cycle-dependent ligament flow stress criterion will remain limiting for the extended licensed 

operating period.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The projected number of each of the design basis events of the primary coolant pumps will 

approach its design basis limit during the extended licensed operating period. Therefore the 

maximum end-of- 60-year life crack size is not expected to approach the critical crack size 

during the 60-year extended licensed operating period.

The fatigue cycle count program described in Section 4.3 and Appendix B, Fatigue 

Monitoring Program, will ensure a reanalysis or other appropriate corrective action if a 

design basis cycle count limit is reached at any time during the extended licensed operating 

period.

4.7.4 Risk-Informed Inservice Inspection Program Calculations

The scope and inspection intervals of the Palisades Risk-Informed Inservice Inspection 

(RI-ISI) Program depended on probabilities of failure of each pipe segment calculated at the 

time of program implementation (approximately year 29) and the time of initial license 

expiration (year 40). 

Analysis

The scope of the RI-ISI program may increase somewhat when the extended operating 

period is considered.
Page 4-64 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Disposition: 10 CFR 54.21(c)(1)(ii)

The supporting calculations for the Palisades RI-ISI program will be reviewed, and updated 

as needed, to reflect a 60-year operating period; and the program inspection scope will be 

updated accordingly, before the period of extended operation.

Therefore, these items are dispositioned under 10 CFR 54.21(c)(1)(ii), the analyses will be 

projected to the end of the period of extended operation.

4.7.5 Absence of a TLAA for Reactor Coolant Pump Flywheel Fatigue or Crack Growth 

Analysis

The four original Palisades reactor coolant pump motors were built by Allis-Chalmers. 

Westinghouse built an additional motor. One of the five is maintained as a spare, and any 

combination of four may be installed. All have flywheels at the top of the motor to provide 

additional rotational inertia for gradual coastdown and continued circulation, in case of a 

power supply loss or inadvertent trip.

A reactor coolant pump flywheel could theoretically burst because of centrifugal stresses, 

which could produce missiles inside containment and could also damage pump seals or 

other pressure boundary components. This concern is the subject of Regulatory Guide 1.14. 

The flywheels may therefore be subject to crack growth or fatigue analyses, inservice 

inspection, or both, to assess and reduce the probability of a failure.

Early Technical specifications required periodic, relatively frequent, inspections of reactor 

coolant pump motor flywheels. To justify a longer inspection frequency, the Combustion 

Engineering Owners Group prepared report SIR-94-080 (Reference 3). This report used a 

crack growth analysis of Palisades' reactor coolant pump flywheels to establish acceptable 

limits for the flywheel inspection interval. The analysis does not depend on the licensed 

operating period (10 CFR 54.3 Criterion 3) and is not a TLAA. The evaluation determined 

that the primary coolant pump would be subject to approximately 500 startup/shutdown 

cycles, and the crack growth fatigue analysis assumed 4000 cycles. It was concluded that a 

ten year inspection interval was acceptable since an assumed preservice flaw would not 

grow to a critical flaw size during the period between inspections (Reference 4). (In fact, the 

report justified that the assumed preservice flaw would not grow to critical flaw size during 

the entire licensed operating period, or extended licensed operating period) The NRC 

approved the change to the inservice inspection requirements to extend the flywheel 

examination frequency to once each ten years ((Reference 5), (Reference 6), and 

(Reference 7)).
Page 4-65 

Palisades Nuclear Plant

Application for Renewed Operating License

Technical and Administrative Information

Section 4.7 References

1. RG 1.190. US NRC Regulatory Guide 1.190, “Calculational and Dosimetry Methods for 

Determining Pressure Vessel Neutron Fluence,” March 2001.

2. WCAP 15353, Westinghouse Report WCAP-15353, Revision 0, “Palisades Reactor 

Pressure Vessel Neutron Fluence Evaluation,” January 2000.

3. Combustion Engineering Owners Group (CEOG) Report SIR 94-080. “Relaxation of 

Reactor Coolant Pump Flywheel Inspection Requirements.”

4. Letter Bordine (Consumers) to USNRC, “Docket No. 50-255 - License DPR 20 - Palisades 

Plant - Technical Specifications Change Request - Primary Coolant Pump Flywheel 

Inspections.” 1 October 1997

5. US NRC Letter, R. G. Schaff, Project Manager, Division of Reactor Projects, Office of 

Nuclear Reactor Regulation; to N. L. Haskell, Director of Licensing, Palisades Plant. 

“Palisades Plant: Issuance of Amendment Re: Primary Coolant Pump Flywheel Inspection 

Technical Specifications (TAC No. M94567).” 15 May 1998.

6. “Consumers Energy Company, Docket No. 50-255, Palisades Plant, Amendment to Facility 

Operating License. Amendment No. 182, License No. DPR 20." Washington: US NRC, 15 

May 1998.

7. “Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 

182 to Facility Operating License No. DPR 20, Consumers Energy Company, Palisades 

Plant, Docket No. 50-255.” Washington: US NRC, 15 May 1998.
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix A - FSAR Supplement

APPENDIX A

FSAR SUPPLEMENT
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix A - UFSAR Supplement

Page A-i 

A1.0 Appendix A Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-1

A2.0 Summary Descriptions of Aging Management Programs - - - - - - - - - - - - - - - - - A-2

A2.1 Alloy 600 Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-2

A2.2 ASME Section XI, Subsections IWB, IWC, IWD, IWF Inservice Inspection Program - A-2

A2.3 Bolting Integrity Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.4 Boric Acid Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - - - - A-3

A2.5 Buried Services Corrosion Monitoring Program - - - - - - - - - - - - - - - - - - - A-3

A2.6 Closed Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - A-4

A2.7 Containment Inservice Inspection Program - - - - - - - - - - - - - - - - - - - - - A-4

A2.8 Containment Leakage Testing Program - - - - - - - - - - - - - - - - - - - - - - - A-4

A2.9 Diesel Fuel Monitoring and Storage Program - - - - - - - - - - - - - - - - - - - - A-5

A2.10 Fire Protection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-5

A2.11 Flow Accelerated Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - A-5

A2.12 Non-EQ Electrical Commodities Condition Monitoring Program - - - - - - - - - - - A-6

A2.13 One-Time Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - A-6

A2.14 Open Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - A-7

A2.15 Overhead Load Handling Systems Inspection Program- - - - - - - - - - - - - - - A-7

A2.16 Reactor Vessel Integrity Surveillance Program - - - - - - - - - - - - - - - - - - - A-7

A2.17 Reactor Vessel Internals Inspection Program - - - - - - - - - - - - - - - - - - - A-8

A2.18 Steam Generator Tube Integrity Program - - - - - - - - - - - - - - - - - - - - - A-8

A2.19 Structural Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - A-8

A2.20 System Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-9

A2.21 Water Chemistry Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-9

A3.0 Summary Descriptions of Time Limited Aging Analysis Management Programs - - - - - A-10

A3.1 Electrical Equipment Qualification Program - - - - - - - - - - - - - - - - - - - - - A-10

A3.2 Fatigue Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-10

APPENDIX A

Contents
Contents

Point Beach Nuclear Plant

Application for Renewed Operating License

Appendix A - UFSAR Supplement

Page A-ii 

A4.0 Evaluation Summaries of Time-Limited Aging Analyses- - - - - - - - - - - - - - - - - - A-11

A4.1 Reactor Vessel Neutron Embrittlement - - - - - - - - - - - - - - - - - - - - - - - A-11

A4.1.1 Upper Shelf Energy - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-11

A4.1.2 Pressurized Thermal Shock - - - - - - - - - - - - - - - - - - - - - - - - - - A-12

A4.1.3 Pressure-Temperature (P-T) Limits - - - - - - - - - - - - - - - - - - - - - - A-14

A4.1.4 Low Temperature Overpressure Protection (LTOP) PORV Setpoints - - - - - - A-15

A4.2 Metal Fatigue- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-15

A4.2.1 Reactor Vessel Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - A-15

A4.2.2 Reactor Vessel Head Closure Stud Fatigue Analysis- - - - - - - - - - - - - - A-16

A4.2.3 Control Rod Drive Mechanism (CRDM) Housing Fatigue Analyses - - - - - - - A-16

A4.2.4 Steam Generator Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - A-18

A4.2.5 Pressurizer Fatigue Analyses - - - - - - - - - - - - - - - - - - - - - - - - - A-19

A4.2.6 Regenerative Heat Exchanger Fatigue Analyses- - - - - - - - - - - - - - - - A-21

A4.2.7 ASME III Class A Primary Coolant Piping Fatigue Analyses - - - - - - - - - - A-22

A4.2.8 Revised Bulletin 88-11 Fatigue Analysis of the Hot-Leg-to-Pressurizer-Surge-Line 

Nozzle, Surge Line, and Pressurizer Surge Nozzle- - - - - - - - - - - - - - - A-24

A4.2.9 Revised Fatigue Analysis of Nozzles from PCS Cold Legs 1B and 2A to Pressurizer 

Spray and of the Pressurizer Spray Nozzle - - - - - - - - - - - - - - - - - - A-27

A4.2.10 Pressurizer Auxiliary Spray Line Tee Fatigue Analysis in Response to NRC Bulletin 

88-08 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - A-28

A4.2.11 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction 

Factor in Piping and Components - - - - - - - - - - - - - - - - - - - - - - - A-29

A4.2.12 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and 

Components (Generic Safety Issue 190)- - - - - - - - - - - - - - - - - - - - A-31

A4.3 Environmental Qualification of Electrical Equipment - - - - - - - - - - - - - - - - - A-34

A4.4 Containment Liner Plate, Metal Containments and Penetrations Fatigue Analysis - - A-36

A4.4.1 Concrete Containment Tendon Prestress Analysis- - - - - - - - - - - - - - - A-36

A4.4.2 Containment Liner Plate Load and Penetrations Load Cycles - - - - - - - - - A-36

A4.5 Other Plant-Specific Time-Limited Aging Analyses - - - - - - - - - - - - - - - - - A-38

A4.5.1 Fuel Handling Crane Load Cycles - - - - - - - - - - - - - - - - - - - - - - - A-38
Contents

Point Beach Nuclear Plant

Application for Renewed Operating License

Appendix A - UFSAR Supplement

Page A-iii 

A4.5.2 Alloy 600 Nozzle and Safe End Life Assessment Analyses- - - - - - - - - - - A-39

A4.5.3 ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld Category 

B-L-1 Inspection Interval from 10 Years to 40 Years - - - - - - - - - - - - - - A-41

A4.5.4 Risk-Informed Inservice Inspection Program Calculations - - - - - - - - - - - A-43
Page A-1

Palisades Nuclear Plant

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Appendix A - FSAR Supplement

A1.0 Appendix A Introduction

10 CFR 54.21(d) requires an application for a renewed operating license to include an FSAR 

Supplement. This supplement must contain summary descriptions of the programs and activities for 

managing the effects of aging, and of the evaluation of Time-Limited Aging Analyses (TLAAs) for 

the period of extended operation. This appendix provides that supplement for the Palisades Plant 

FSAR. 

Section A2.0 of this appendix contains summary descriptions of the programs used to manage the 

effects of aging during the period of extended operation. Section A3.0 contains descriptions of 

programs used for management of TLAAs during the period of extended operation. Section A4.0 

contains summaries of TLAAs applicable to the period of extended operation. 

 In a periodic FSAR update following NRC issuance of the renewed operating license, in 

accordance with 10 CFR 50.71(e), the summary descriptions of Aging Management Programs and 

Time Limited Aging Analyses, provided in Appendix A, will be incorporated into appropriate 

sections of the FSAR.
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Appendix A - FSAR Supplement

A2.0 Summary Descriptions of Aging Management Programs 

This section provides summaries of programs credited in the License Renewal Application for 

managing the effects of aging during the period of extended operation. 

The activities implemented to manage aging at the Palisades Plant may be performed under 

discrete programs as defined herein, or they may be incorporated into other plant programs. The 

program summaries provided should be interpreted as summaries of activities to be performed to 

manage aging, and not as specific commitments to maintain unique programs with the specific titles 

and content listed.

It should also be noted that these summaries do not specifically invoke or reference the Generic 

Aging Lessons Learned Report, NUREG-1801. The activities credited for managing aging at 

Palisades were developed, to a large extent, to be responsive to the revision of GALL that existed 

at the time that the license renewal application was developed. It is expected that changes will be 

made to these programs in the future as a result of advances in the state of knowledge in the 

industry, plant modifications, and operating experience. However, no commitment is made to 

update any aging management program in response to changes in the GALL. Future changes that 

may occur to aging management programs or activities will be managed under 10 CFR 50.59 

and/or other regulatory and administrative requirements appropriate to the changes being made.

A2.1 Alloy 600 Inspection Program

The Alloy 600 Program manages aging due to PWSCC of the Primary Coolant System 

(PCS) pressure boundary Alloy 600 components, including Inconel 82/182 weld joints, 

reactor vessel head penetrations, etc. The program includes (a) PWSCC susceptibility 

assessment using industry models to identify susceptible components, (b) monitoring and 

control of primary coolant chemistry to mitigate PWSCC, (c) in-service inspections (ISI) of 

pressurizer penetrations, reactor vessel head penetrations and Alloy 82/182 PCS pressure 

boundary welds in accordance with ASME Section XI, Subsection IWB, Table IWB-2500-1, 

and (d) augmented inspections or preemptive repair/replacement of susceptible 

components or welds.

A2.2 ASME Section XI, Subsections IWB, IWC, IWD, IWF Inservice Inspection 

Program 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program facilitates inspections 

to identify and correct degradation in Class 1, 2, and 3 piping, components, their supports 

and integral attachments. The program includes periodic visual, surface and/or volumetric 

examinations and leakage tests of all Class 1, 2 and 3 pressure-retaining components, their 

supports and integral attachments, including welds, pump casings, valve bodies, 
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Appendix A - FSAR Supplement

pressure-retaining bolting, piping/component supports, and reactor head closure studs. 

These are identified in ASME Section XI, “Rules for Inservice Inspection of Nuclear Power 

Plant Components,” or commitments requiring augmented inservice inspections, and are 

within the scope of license renewal. This program is in accordance with 10 CFR 50.55a. 

A2.3 Bolting Integrity Program 

The Bolting Integrity Program manages the aging effects associated with bolting through the 

performance of periodic inspections. The program also includes repair/replacement controls 

for ASME Section XI related bolting and generic guidance regarding material selection, 

thread lubrication and assembly of bolted joints. The program considers the guidelines 

delineated in NUREG-1339 for a bolting integrity program, EPRI NP-5769 (with the 

exceptions noted in NUREG-1339) for safety related bolting, and EPRI TR-104213 for 

non-safety related bolting. 

A2.4 Boric Acid Corrosion Program

The Palisades Boric Acid Corrosion Program monitors component degradation due to boric 

acid leakage through the performance of periodic inspections. It implements the 

recommendations of NRC Generic Letter 88-05. The program requires periodic visual 

inspection of all systems within the scope of license renewal that contain borated water for 

evidence of leakage, accumulations of dried boric acid, or boric acid wastage. The program 

also provides for visual inspections and early discovery of borated water leaks such that 

structures, electrical and mechanical components that may be contacted by leaking borated 

water will not be adversely affected such that their intended functions are impaired. 

A2.5 Buried Services Corrosion Monitoring Program

The Buried Services Corrosion Monitoring Program manages aging effects on the external 

surfaces of carbon steel, low-alloy steel, and stainless steel components that are buried in 

soil or sand. This program includes (a) visual inspections of external surfaces of buried 

components for evidence of coating damage and substrate degradation to manage the 

effects of aging, (b) visual inspection of the external surfaces of buried stainless steel 

components for evidence of crevice corrosion, pitting, and MIC. The periodicity of these 

inspections for carbon, low-alloy, and stainless steel will be based on opportunities for 

inspection such as scheduled maintenance work.

A2.6 Closed Cycle Cooling Water Program 

The Closed Cycle Cooling Water Program manages aging effects in closed cycle cooling 

water systems that are not subject to significant sources of contamination, in which water 

chemistry is controlled and heat is not directly rejected to the ultimate heat sink. The 
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Appendix A - FSAR Supplement

program includes (a) maintenance of system corrosion inhibitor concentrations to minimize 

degradation, and (b) periodic or one-time testing and inspections to assess component 

aging. This program is based on the guidelines in EPRI TR-107396.

The program scope includes activities to manage aging in the Component Cooling Water 

(CCS) System, Emergency Diesel Generator (EDG) Jacket Cooling Water (Emergency 

Power System), and Shield Cooling System (SCS).

A2.7 Containment Inservice Inspection Program

The Containment Inservice Inspection (ISI) Program is designed to ensure that containment 

shell concrete, the post-tensioning system and steel pressure retaining elements continue to 

provide an acceptable level of structural integrity. In addition, it is designed to ensure that 

the liner (with associated moisture barriers), other leakage limiting steel barriers and 

pressure retaining bolted connections have not degraded. 

A2.8 Containment Leakage Testing Program 

The Containment Leakage Testing Program ensures that containment leakage is 

maintained below the upper acceptance limit of La = 0.1% / day. This testing program, in 

conjunction with the Containment Inservice Inspection Program, provides assurance that 

age related (and other) deterioration of the containment leakage limiting boundary is 

appropriately managed to ensure that postulated post-accident releases are limited to an 

acceptable level. The program is implemented through the following testing and 

examination activities:

• Overall containment leakage (integrated leakage rate or Type A) test to assess the leak 

tight integrity of the entire pressure boundary.

• Visual examinations of the containment exterior and interior.

• Local (Type B & C) tests to assess the leak tight integrity of individual penetrations.

A2.9 Diesel Fuel Monitoring and Storage Program 

The Diesel Fuel Monitoring and Storage Program assures the continued availability and 

quality of fuel oil to be used in diesel generators and diesel fire pumps. The program 

includes (a) monitoring and trending of fuel oil chemistry to maintain fuel oil quality and 

mitigate corrosion, (b) periodic draining, cleaning, and internal inspection of fuel oil storage 

tanks, and (c) verification of program effectiveness by a one-time measurement of fuel oil 

storage tank bottom thickness confirming the absence of an aging effect. Fuel oil quality is 

maintained by monitoring and controlling fuel oil contamination in accordance with the 

guidelines of the American Society for Testing Materials (ASTM) Standards D 1796, D 2276, 

D 2709, and D 4057. 
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A2.10 Fire Protection Program 

The Fire Protection Program includes (a) fire barrier inspections, (b) electric and 

diesel-driven fire pump tests, and (c) periodic maintenance, testing, and inspection of 

water-based fire protection systems. Periodic visual inspections of fire barrier penetration 

seals, fire dampers, fire barrier walls, ceilings and floors, and periodic visual inspections and 

functional tests of fire-rated doors are performed to ensure that functionality and operability 

is maintained. Periodic testing of the fire pumps ensures that an adequate flow of firewater 

is supplied and that there is no degradation of diesel fuel supply lines. Periodic 

maintenance, testing and inspection activities of water-based fire protection systems 

provides reasonable assurance that fire water systems are capable of performing their 

intended function. Inspection and testing include periodic hydrant inspections, fire main 

flushing, sprinkler inspections, pipe wall thickness testing and flow tests.

A2.11 Flow Accelerated Corrosion Program 

The Flow Accelerated Corrosion Program manages aging effects due to flow-accelerated 

corrosion (FAC) on the internal surfaces of carbon or low alloy steel piping, elbows, 

reducers, expanders, and valve bodies which contain high energy fluids (both single phase 

and two phase). The program implements the EPRI guidelines in NSAC-202L-R2 for an 

effective FAC program and includes (a) an analysis using a predictive code such as 

CHECWORKSTM to determine critical locations, (b) baseline inspections to determine the 

extent of thinning at these locations, (c) follow-up inspections to confirm the predictions, and 

(d) repairing or replacing components, as necessary. 

A2.12 Non-EQ Electrical Commodities Condition Monitoring Program 

The Non-EQ Electrical Commodities Condition Monitoring Program manages aging in 

selected non-EQ commodity groups within the scope of 10 CFR 54. Features of the 

program periodic inspection of insulated cables and connectors, testing of sensitive 

instrumentation circuits, testing of medium voltage cables, and inspection of manholes for 

the presence of water.

A2.13 One-Time Inspection Program 

The One-Time Inspection Program addresses potentially long incubation periods for 

certain aging effects, including various corrosion mechanisms, cracking, and selective 

leaching, and provides a means of verifying that an aging effect is either not occurring or 

progressing so slowly as to have negligible effect on the intended function of the structure 

or component. Hence, the One-Time Inspection Program provides measures for verifying 
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Appendix A - FSAR Supplement

an aging management program is not needed, verifying the effectiveness of an existing 

program, or determining that degradation is occurring which will require evaluation and 

corrective action.

The program includes (a) determination of appropriate inspection sample size, (b) 

identification of inspection locations, (c) selection of examination technique, with 

acceptance criteria, and (d) evaluation of results to determine the need for additional 

inspections or other corrective actions. The inspection sample includes locations where 

the most severe aging effect(s) would be expected to occur. Inspection methods may 

include visual (or remote visual), surface or volumetric examinations, or other established 

NDE techniques.

This program is used for a variety of purposes, including the following:

• To verify the effectiveness of water chemistry control for managing the effects of aging 

in stagnant or low-flow portions of piping or components, exposed to a treated water 

environment.

• To manage the aging effects of loss of material due to aging mechanisms such as 

general, crevice, pitting, and galvanic corrosion; selective leaching; and MIC.

• To verify that cracking due to stress corrosion cracking or cyclic loading, in small bore 

(< 4" NPS) ASME class 1 piping, is not occurring.

• To verify, for components in the Compressed Air System, that there are no aging 

effects requiring management in the dry air environment.

A2.14 Open Cycle Cooling Water Program 

The Open Cycle Cooling Water Program manages aging effects such as loss of material 

due to general, pitting, and crevice corrosion, erosion, MIC, and loss of heat transfer due to 

biological/corrosion product fouling (e.g., sedimentation, silting) caused by exposure of 

internal surfaces of metallic components to raw, untreated (e.g., service) water. The 

program scope includes activities to manage aging in the Service Water System (SWS) and 

Circulating Water system (CWS). The aging effects are managed through (a) monitoring 

and control of biofouling, (b) flow balancing and flushing, (c) heat exchanger testing (d) 

routine inspection and maintenance program activities to ensure that aging effects do not 

impair component intended function. Inspection methods include visual (VT), ultrasonic 

(UT), radiographic (RT), and eddy current (ECT). This program is responsive to NRC GL 

89-13. 
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Appendix A - FSAR Supplement

A2.15 Overhead Load Handling Systems Inspection Program

The Overhead Load Handling Systems Inspection Program provides for inspections of the 

structural components and rails of cranes and fuel handling machines associated with 

heavy load handling that are subject to the requirements of NUREG-0612 and are within the 

scope of license renewal requiring aging management. For Palisades these are the 

Containment Building Polar Crane, the Spent Fuel Pool Overhead Crane, the Containment 

Building jib and boom cranes, and the reactor and spent fuel pool fuel handling machines. 

These cranes comply with the Maintenance Rule requirements provided in 10 CFR 50.65. 

The Overhead Load Handling Systems Inspections Program is primarily focused on 

structural components that make up the bridge and trolley of the overhead cranes that are 

within the scope of NUREG-0612.

A2.16 Reactor Vessel Integrity Surveillance Program

The Reactor Vessel Integrity Surveillance Program manages the aging effect reduction of 

fracture toughness due to neutron embrittlement of the low alloy steel reactor vessel. 

Monitoring methods will be in accordance with 10 CFR 50, Appendix H. This program 

includes (a) capsule insertion, withdrawal and materials testing/evaluation, (including upper 

shelf energy and RTNDT determinations), (b) fluence and uncertainty calculations, (c) 

monitoring of Effective Full Power Years (EFPY), (d) development of pressure temperature 

limitations, and (e) determination of low temperature overpressure protection (LTOP) set 

points. The program ensures the reactor vessel materials (a) meet the fracture toughness 

requirements of 10 CFR 50, Appendix G, and (b) have adequate margins against brittle 

fracture caused by Pressurized Thermal Shock (PTS) in accordance with 10 CFR 50.61.

A2.17 Reactor Vessel Internals Inspection Program 

The Reactor Vessel Internals Inspection Program manages the aging effects for reactor 

vessel internals. The program provides for (a) Inservice Inspection (ISI) in accordance with 

ASME Section XI requirements, including examinations performed during the 10-year ISI 

examination; (b) Participation in industry initiatives to evaluate the significance of void 

swelling; (c) Monitoring and control of reactor coolant water chemistry in accordance with 

the EPRI guidelines in TR-105714 (See Water Chemistry Program) to mitigate SCC or 

IASCC; and (d) Participation in industry initiatives that will generate additional data on aging 

mechanisms relevant to RVI and develop appropriate inspection techniques to permit 

detection and characterization of features of interest.
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Appendix A - FSAR Supplement

A2.18 Steam Generator Tube Integrity Program 

The Steam Generator Tube Integrity Program manages the aging effects of steam generator 

tubes and tube repairs. The Program also manages the aging effects of accessible steam 

generator secondary side internal components and incorporates the guidance of NEI 97-06. 

The program manages aging effects through a balance of mitigation, inspection, evaluation, 

repair, and leakage monitoring measures. Component degradation is mitigated by 

controlling primary and secondary water chemistry. Eddy current testing is used to detect 

steam generator tube flaws and degradation. Visual examinations are performed to identify 

degradation of accessible steam generator secondary side internal components. Primary to 

secondary leakage is monitored during plant operation. 

A2.19 Structural Monitoring Program 

The Structural Monitoring Program is designed to ensure that age related (as well as other) 

deterioration of plant structures (including masonry walls) and components within its scope 

is appropriately managed to ensure that each such structure or component retains the 

ability to perform its intended function. The program is implemented through visual 

examination of these structures, components and other specified items. Damage or 

degradation found during visual examination may be further evaluated by measurements 

and testing techniques as appropriate.

This program also implements provisions of the Maintenance Rule, 10 CFR 50.65, that 

relate to masonry walls and water-control structures. It conforms to the guidance contained 

in RG 1.160 and NUMARC 93-01 as well as Nuclear Energy Institute publication NEI 96-03. 

This NEI document, which supplements NUMARC 93-01, contains additional guidance 

specific to the monitoring of structures.

A2.20 System Monitoring Program 

The System Monitoring Program manages aging effects for normally accessible, external 

surfaces of piping, tanks, and other components and equipment within the scope of License 

Renewal. These aging effects are managed through visual inspection and monitoring of 

external surfaces for leakage and evidence of material degradation. The program relies 

upon periodic system walkdowns to monitor degradation of the protective paint or coating, 

and/or the exterior steel surface area (if no paint or coatings exist, or if the existing 

protective paint and coatings are degraded to a point whereby the exterior steel surface is 

exposed). Palisades does not take credit for any above ground coating or paint for 

mitigating corrosion even though the tanks may be painted or coated. However, inspections 

of the above ground coating or paint will provide an indication of the condition of the material 

underneath the coating or paint.
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A2.21 Water Chemistry Program 

The Water Chemistry Program manages aging effects such as loss-of-material due to 

general, pitting and crevice corrosion; cracking due to SCC; and steam generator tube 

degradation caused by denting, intergranular attack (IGA) and outer diameter stress 

corrosion cracking (ODSCC), by controlling the environment to which internal surfaces of 

systems and components are exposed. The aging effects are minimized by controlling the 

chemical species that cause the underlying mechanisms that result in these aging effects. 

The program provides assurance that an elevated level of contaminants and, where 

applicable, oxygen does not exist in the systems and components covered by the program, 

thus minimizing the occurrences of aging effects, and maintaining each component’s ability 

to perform the intended functions. The program is based on the guidelines in EPRI 

TR-105714, and TR-102134.
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A3.0 Summary Descriptions of Time Limited Aging Analysis Management 

Programs

A3.1 Electrical Equipment Qualification Program 

The Electrical Equipment Qualification Program is an existing program that implements the 

requirements of 10 CFR 50.49, “Environmental Qualification of Electric Equipment 

Important to Safety for Nuclear Power Plants,” at Palisades. 10 CFR 50.49 defines the 

scope of components to be included, requires the preparation and maintenance of a list of 

in-scope components, and requires the preparation and maintenance of a qualification file 

that includes component performance specifications, electrical characteristics, the 

environmental conditions to which the components could be subjected, and the basis for 

qualification. 10 CFR 50.49(e)(5) contains provisions for aging that require, in part, 

consideration of all significant types of aging degradation that can affect component 

functional capability. 10 CFR 50.49(e)(5) also requires replacement or refurbishment of 

qualified components prior to the end of its designated life, unless additional life is 

established through ongoing qualification. EQ programs manage component thermal, 

radiation, and cyclical aging through the use of aging evaluations based on 10 CFR 50.49(f) 

qualification methods. 

A3.2 Fatigue Monitoring Program 

The Fatigue Monitoring Program is a new program that ensures that limits on fatigue usage 

are not exceeded during the renewal term. The program monitors and tracks selected cyclic 

loading transients (cycle counting) and their effects on susceptible components. Palisades 

has selected this option under 10 CFR 54.21 to manage cracking due to metal fatigue of the 

reactor coolant pressure boundary during the extended period of operation.

The Fatigue Monitoring Program provides cycle counting activities for confirming analytically 

derived cumulative usage values for applicable locations. Specific locations that may be 

subject to cyclic loading that could cause fatigue cracking are monitored using a 

computer-based monitoring program provided by EPRI, called FatiguePro. If warranted, 

other monitoring methods in addition to cycle counting may also be employed under this 

program to monitor specific locations.
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A4.0 Evaluation Summaries of Time-Limited Aging Analyses

As part of a License Renewal Application, 10 CFR 54.21(c) requires that an evaluation of 

time-limited aging analyses (TLAAs) for the period of extended operation be provided. The 

following TLAAs have been identified and evaluated to meet this requirement. These discussions 

will be inserted into the FSAR sections appropriate to the subject matter.

A4.1 Reactor Vessel Neutron Embrittlement 

A4.1.1 Upper Shelf Energy

The Charpy upper shelf energy is associated with the determination of acceptable reactor 

vessel toughness during the license renewal period. 10 CFR Part 50 Appendix G Paragraph 

IV.A.1 requires that the reactor vessel beltline materials must have Charpy upper shelf 

energy of no less than 68 J (50 ft-lb) throughout the life of the reactor vessel, unless 

otherwise approved by the NRC. In the event that the 50 ft-lb requirement cannot be 

satisfied as stated in 10 CFR 50 Appendix G, or by alternative procedures acceptable to the 

NRC, the reactor vessel may continue to operate provided requirement 1 of Appendix G is 

satisfied. This requirement states that an analysis must conservatively demonstrate, the 

existence of equivalent margins of safety for continued operation.

Analysis

As shown in Table A4.1.1-1, the upper shelf energy for reactor vessel beltline materials at 

the end of the extended period of operation is expected to decrease to less than 50 ft-lbs 

based on predictions using Regulatory Guide 1.99. A low upper-shelf fracture mechanics 

analysis has been performed to evaluate the plate and weld material for ASME Levels A, B, 

C, and D Service Loadings, based on the acceptance criteria of the ASME Code, Section 

XI, Appendix K. Combustion Engineering Report NPSD-993 has determined that 

Combustion Engineering reactor vessels maintain equivalent margins of safety, if plate 

material and circumferential weld material maintains at least 30 ft-lb upper shelf energy, and 

if longitudinal weld material maintains at least 34 ft-lb upper shelf energy. This analysis has 

not been submitted to the NRC.

Table A4.1.1-1Estimated USE on March 24, 2031

RPV Material Material 

Heat # Cu (%)

Initial 

USE 

(ft-lbs)

1⁄4t Neutron 

Fluence 

(1019 n/cm2)

USE 

(ft-lbs)

2-112A/C W5214 0.213 118 1.251 73.86
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Disposition: Aging Management, 10 CFR 54.21(c)(1)(iii)

10 CFR 50, Appendix G requires licensees to submit an analysis at least 3 years prior to the 

time that the upper-shelf energy of any of the reactor vessel material is predicted to drop 

below 50 ft-lb., as measured by Charpy V-notch specimen testing. NMC will comply with this 

requirement.

NMC will submit an equivalent margins analysis, completed in accordance with 10 CFR 50 

Appendix G Section IV.A.1, for NRC approval, at least three years before any reactor vessel 

beltline material upper shelf energy decreases to less than 50 ft-lb.

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation

A4.1.2 Pressurized Thermal Shock

The pressurized thermal shock (PTS) rule, 10 CFR 50.61, established screening criteria that 

are a measure of a limiting level of reactor vessel material embrittlement beyond which 

operation cannot continue without further plant-specific evaluation. The screening criteria 

are given in terms of reference temperature RTPTS. The screening criteria are 270° F for 

plates and axial welds, and 300° F for circumferential welds. 

Analysis

The results of the PTS analysis for the limiting material have been reviewed for compliance 

with 10 CFR 50.61. The methodology used in the PTS analysis is based on the projected 

3-112A/C 34B009 0.192 111 1.251 72.01

9-112 27204 0.203 84 1.800 50.83

D-3803-1 C-1279 0.24 102 1.800 63.29

D-3803-2 A-0313 0.24 87 1.800 53.98

D-3803-3 C-1279 0.24 91 1.800 56.46

D-3804-1 C-1308A 0.19 72 1.800 48.97

D-3804-2 C-1308B 0.19 76 1.800 51.69

D-3804-3 B-5294 0.12 73 1.800 55.51

Table A4.1.1-1Estimated USE on March 24, 2031

RPV Material Material 

Heat # Cu (%)

Initial 

USE 

(ft-lbs)

1⁄4t Neutron 

Fluence 

(1019 n/cm2)

USE 

(ft-lbs)
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neutron fluence at the end of the period of extended operation. As shown in Table A4.1.2-1, 

the RTPTS values for the intermediate and lower shell plates remain below the NRC 

screening criterion of 270oF. The RTPTS values for the axial and circumferential welds are 

projected to exceed the NRC screening criteria of 270oF and 300oF, respectively. The vessel 

is projected to reach the PTS screening criterion of 270o F on the beltline axial welds 

fabricated with weld wire heat W5214 in 2014. 

Disposition: Aging Management, 10 CFR 54.21(c)(1)(iii)

10 CFR 50.61 requires the licensee to implement a flux reduction program that is 

reasonably practicable to avoid exceeding the screening criteria. If the flux reduction 

program does not prevent the reactor vessel from exceeding the PTS screening criterion at 

the end of life, 10 CFR 50.61 allows two options. The licensee can submit a safety analysis 

pursuant to 10 CFR 50.61(b)(4) to determine what, if any, modifications to equipment, 

systems and plant operation are necessary to prevent failure of the reactor vessel from a 

postulated PTS event. The other option is to perform a thermal-annealing treatment of the 

reactor vessel pursuant to 10 CFR 50.61(b)(7) to recover fracture toughness. 10 CFR 50.61 

requires the details of the selected alternative be provided to the NRC three years prior to 

when the reactor vessel is projected to exceed the PTS screening criteria. At the 

appropriate time, prior to exceeding the PTS screening criteria, Palisades will select the 

Table A4.1.2-1Estimated RTPTS on March 24, 2031

RPV Material Material 

Heat # Cu (%) Ni (%) RTNDT(U)(°F)

Margin 

(°F)

Fluence 

(1019 n/cm2)

RTPTS

(°F)

Axial Welds 2-112A/C W5214 0.213 1.01 -56 65.5 2.084 287

Axial Welds 3-112A/C

W5214 0.213 1.01 -56 65.5 2.084 287

34B009 0.192 0.980 -56 65.5 2.084 271

Circumferential Weld 

9-112 27204 0.203 1.018 -56 65.5 2.998 302

Plate D-3803-1 C-1279 0.24 0.50 -5 17 2.998 209

Plate D-3803-2 A-0313 0.24 0.52 -30 34 2.998 210

Plate D-3803-3 C-1279 0.24 0.50 -5 17 2.998 209

Plate D-3804-1 C-1308A 0.19 0.48 0 34 2.998 200

Plate D-3804-2 C-1308B 0.19 0.50 -30 34 2.998 173

Plate D-3804-3 B-5294 0.12 0.55 -25 34 2.998 115
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optimum alternative to manage PTS in accordance with NRC regulations and make relevant 

submittals to obtain NRC review and approval.

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation. 

A4.1.3 Pressure-Temperature (P-T) Limits

10 CFR Part 50 Appendix G requires that the reactor pressure vessel be maintained within 

established pressure-temperature limits including during heatup and cooldown. These limits 

specify the maximum allowable pressure as a function of reactor coolant temperature, and 

are contained in Technical Specifications. As the reactor pressure vessel becomes 

embrittled and its fracture toughness is reduced, the allowable pressure (given the required 

minimum temperature) is reduced.

Low temperature overpressure protection limits and setpoints are determined as part of the 

calculation of pressure/temperature operating limit curves.

Analysis

The current pressure/temperature analyses are valid beyond the current operating license 

period, but not to the end of the period of extended operation. 

Disposition

This issue will be dispositioned using the method of 10 CFR 54.21(c)(1)(iii), the effects of 

aging on the intended function will be adequately managed for the period of extended 

operation. The Pressure-Temperature operating limits contained in Technical Specifications 

will be updated as required by either Appendices G or H of 10 CFR 50, or as operational 

needs dictate. 

A4.1.4 Low Temperature Overpressure Protection (LTOP) PORV Setpoints

Low temperature overpressure protection limits and setpoints are determined as part of the 

calculation of pressure/temperature operating limit curves. See Section A4.1.3.

A4.2 Metal Fatigue

A4.2.1 Reactor Vessel Fatigue Analyses

The Palisades Reactor Vessel was designed, constructed, and analyzed to the ASME Boiler 

and Pressure Vessel Code, Section III, Subsection 4 for Class A vessels, 1965, with 

addenda through Winter, 1965. The original analyses have been corrected and amended to 

address issues that have arisen since fabrication. The current design basis highest 
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calculated fatigue usage factors, based on the number of design basis load cycles assumed 

by the vessel analyses, have been determined. The number of design basis load cycles for 

each event was selected to be adequate for the originally-licensed 40-year design life.

Analysis

This section addresses the calculated fatigue usage factors for the reactor vessel

• Shell and bottom head

• Inlet and outlet nozzles

• Internal welded attachments

• Instrument nozzle shroud tube

• Vessel head CRDM nozzles, and

• Instrument flange bolts (on the instrument nozzle on the vessel head).

The worst-case calculated usage factor for the set of design basis load events in these 

locations is 0.4516 on the outlet nozzle, well within the code limit of 1.0.

The number of each of the design basis events that affect the reactor pressure vessel is not 

expected to approach its design basis limit during the extended licensed operating period. 

Therefore, the actual fatigue usage factors are not expected to approach their calculated 

values during the extended licensed operating period. The calculated maximum usage 

factor for these locations on the reactor vessel is 0.4516, well within the analytical limit of 

1.0. 

Disposition

This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

In addition, the Fatigue Monitoring Program will ensure that the effects of aging will be 

adequately managed for the period of extended operation under 10 CFR 54.21(c)(1)(iii) by 

assuring that a reanalysis or other appropriate corrective action is taken if a design basis 

cycle count limit is reached at any time during the extended licensed operating period.

A4.2.2 Reactor Vessel Head Closure Stud Fatigue Analysis

The highest fatigue usage factor calculated by the reactor vessel fatigue analysis is in the 

vessel head studs.

Analysis

The calculated lifetime usage factor in the head closure studs for the set of design basis 

load events is 0.8346, within the code limit of 1.0. The number of design basis transient 
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events is not expected to approach the number assumed by the analysis during the 

extended licensed operating period. 

Disposition

This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

In addition, the Fatigue Monitoring Program will ensure that the effects of aging will be 

adequately managed for the period of extended operation under 10 CFR 54.21(c)(1)(iii) by 

assuring that a reanalysis or other appropriate corrective action is taken if a design basis 

cycle count limit is reached at any time during the extended licensed operating period.

A4.2.3 Control Rod Drive Mechanism (CRDM) Housing Fatigue Analyses

The reactor control rod drive mechanisms (CRDM) are enclosed in pressure housings, 

bolted and seal-welded to the reactor pressure vessel CRDM nozzle flanges. The CRDM 

housings, their seal housings, their instrument and vent tube nozzles, the flange bolts, and 

the Omega seal welds between the CRDM housing flanges and the reactor vessel CRDM 

nozzle flanges were all replaced in 2001. Extension of the operating license to March 24, 

2031, therefore, only requires a 30 year design life. The replacements are ASME III (1989) - 

Class 1, NPT stamped, with reconciliation to the 1965 code.

Analysis

CRDM Housings: The revised fatigue evaluation found that the criteria of ASME III - 1989, 

Paragraph NB-3222.4(d) are met, and, therefore, that no fatigue analysis is required.

CRDM Seal Housings and Tool Access Tube Assemblies: The fatigue evaluation finds the 

criteria of N-415.2(d)(6) of ASME III are met. A revised fatigue analysis was not performed. 

The replacement material is stronger than the analyzed material.

CRDM Housing Bolts: The fatigue evaluation of record calculated a design lifetime 

cumulative usage factor of 0.173. This evaluation has not been revised, but will remain valid 

so long as the assumed number of lifetime design basis transient cycles remains valid. This 

analysis is very conservative since the bolts were replaced when the CRDM housings were 

replaced.

CRDM Flange - Reactor Vessel Nozzle Flange Bolts: The fatigue evaluation of record 

calculated a design lifetime cumulative usage factor of 0.624. This evaluation has not been 

revised, but will remain valid so long as the assumed number of lifetime design basis 

transient cycles remains valid. This analysis is very conservative since the bolts were 

replaced when the CRDM housings were replaced.
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CRDM Flange - Reactor Vessel Nozzle Flange Omega Seal Welds: The fatigue evaluation 

calculated a design lifetime cumulative usage factor of 0.5621. This analysis used the set of 

design transients from the original design specification, which were based on an assumed 

40-year design life. 

Since all of these components were replaced in 2001, their expected installed lifetime, 

including the extended licensed operating period (to March 24, 2031), will be only about 30 

years, compared to the 40 years upon which the estimate of design basis event cycles was 

based. The two highest calculated maximum usage factors for a 40 year life in any of these 

components is 0.624 for the flange bolts and 0.5621 for the flange Omega seal welds, well 

within the analytical limit of 1.0. 

In addition, the number of each of the design basis events that affect the reactor pressure 

vessel and the CRDM housings and appurtenances is not expected to approach its design 

basis limit during the extended licensed operating period. The actual fatigue usage factors 

are, therefore, not expected to approach their calculated values during the extended 

licensed operating period. 

Disposition

This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

A4.2.4 Steam Generator Fatigue Analyses

The Palisades steam generators were replaced in 1990-1991. Extension of the operating 

license to March 24, 2031 therefore requires a 40 year design life. The replacement steam 

generators were designed to the ASME Boiler and Pressure Vessel Code, Section III, 1977. 

The primary coolant pressure boundary (tube side) of the steam generators is designed to 

Section III Class 1 rules. Critical components of the Class 2-design secondary side (e.g., the 

feedwater nozzles) were also analyzed using Class 1 methods.

Analysis

Vessel and Components, Except Manway Studs: The ASME III Class 1 fatigue analyses 

of the replacement steam generators used the number of event cycles assumed for the 

original plant design for a 40-year licensed operating period.

Except for the manway studs (below), the maximum usage factor at any location is 0.9158, 

on the main feedwater nozzle.

Manway Studs: The original ASME III Class 1 fatigue analyses calculated a worst-case 

usage factor for the manway studs of 0.10. However the vendor (Westinghouse) later 

issued a Nuclear Safety Advisory Letter identifying a significant bending load on the studs 

due to differential thermal expansion during the heatup and cooldown transients, which 
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resulted in predicted lifetime usage factors greater than 1.0. The revised analysis found that 

the fatigue limit for the studs would be reached in about 200 reactor heatup and cooldown 

cycles.

This problem has been addressed by a requirement in plant procedures to evaluate the 

number of heatup and cooldown cycles every 5 operating years, and to replace the manway 

studs before they can experience 200 heatup and cooldown cycles. Since the studs were 

installed at Plant Heatup Number 106, they should be replaced before Heatup Number 306. 

This five-year evaluation interval was based on a very conservative assumption that no 

more than 12.5 startup and shutdown cycles would occur per operating year, and, therefore, 

less than 63 cycles should accumulate between evaluations.

However, since the fatigue life analysis that supports the current design and licensing basis 

safety determination for the manway studs does not depend on the licensed operating 

period, the analysis is not a TLAA.

The replacement steam generator fatigue analyses qualify them for a 40 year design life, 

except for the manway studs. The replacement steam generators were installed in 1991. 

The qualified 40 year design life is therefore sufficient for the extended licensed operating 

period ending in 2031. 

Disposition

This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis remains 

valid for the period of extended operation.

A4.2.5 Pressurizer Fatigue Analyses

The pressurizer was designed to the ASME Boiler and Pressure Vessel Code, Section III, 

Class A, 1965, Winter 1966 addenda. The code design calculation includes a fatigue 

analysis for those nozzles or other parts which do not meet the fatigue analysis exemption 

criteria of Section III Paragraph N-415.1. These include all nozzles attached by J-welds and 

other nozzles and parts subject to more-severe thermal transients:

• The surge, spray, and temperature element nozzles and nozzle-to-shell or nozzle-to-head 

junctions

• Heater sleeve-to-head junctions

• Upper level nozzles

• Relief (PORV) and safety valve nozzles

• The liquid-vapor boundary region of the shell

• Manway, head, and studs, and

• Bottom head support skirt.
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A revised set of external load cycles required reevaluation of fatigue in the three safety relief 

valve nozzles. The recalculation found that the stress intensities produced by the revised 

external loads are less than those calculated by the original analysis, and, therefore, that the 

original simplified fatigue evaluation remains valid.

The Alloy 600 safe end to-pipe weld at the power-operated relief valve nozzle was found 

cracked and leaking in 1993. The Alloy 600 safe end was repaired with a short stainless 

steel pipe, and the nozzle was reanalyzed. The highest usage factor calculated for the 

modified safe end and its connections is 0.7572 at the inside of the nozzle-head juncture. 

This calculation assumed load cycles for a 40 year design life.

Analysis of the PORV nozzle safe end material removed in 1993 indicated primary water 

stress corrosion cracking (PWSCC), and prompted replacement of the remainder of the safe 

end with 316 stainless material with Alloy 690 welds, in 1995. The fatigue analysis for the 

currently-installed safe end and attachments calculated a worst-case usage factor of 0.084, 

at the inside wall of the safe end transition. 

Other TLAAs of the Pressurizer: Thermal stratification phenomena in the surge line have 

required reanalysis of the surge nozzle, and concerns for high differential temperatures with 

auxiliary spray have required reanalysis of the spray nozzle. 

Primary water stress corrosion cracking (PWSCC) of the Alloy 600 temperature nozzles 

required repair, a revised fatigue analysis, and analyses of the PWSCC effects. These 

failures, failure of the PORV nozzle safe end, and industry-wide cracking of Alloy 600 

components have required evaluation of PWSCC effects in all Alloy 600 components. 

Analysis and Disposition

Fatigue usage factors have been calculated for the pressurizer

• Bottom head support skirt

• Heater sleeve-head junctions

• Liquid-vapor boundary region of the shell

• Upper level nozzles

• Power-operated relief valve (PORV) nozzle

• Code safety valve nozzles, and

• Manway, head, and studs

For these locations the worst-case calculated usage factor is 0.7572, at the inner PORV 

nozzle-head juncture. This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), 

the analysis remains valid for the period of extended operation.
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The fatigue analysis of the replaced PORV nozzle safe end was based on a nominal 20 year 

life beyond its 1995 installation. However, the low worst-case usage factor of 0.084 in this 

component permits a simple projection to the end of the extended licensed operating period, 

when the service life of this component would be about 36 years. A projected usage factor 

based on this 36 year life would be only about 0.15, compared to the allowable 1.0. This 

issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis remains valid 

for the period of extended operation.

For those portions of the original pressurizer analysis which have not been superseded, the 

number of each of the design basis events is not expected to approach its design basis limit 

during the extended licensed operating period, and, therefore, the actual fatigue usage 

factors are not expected to approach their calculated values during the extended licensed 

operating period. The calculated maximum usage factor for these locations on the 

pressurizer is 0.7572, within the analytical limit of 1.0, at the inner PORV nozzle-head 

juncture. This issue is dispositioned using the method of 10 CFR 54.21(c)(1)(i), the analysis 

remains valid for the period of extended operation.

In addition, the Fatigue Monitoring Program will ensure that the effects of aging will be 

adequately managed for the period of extended operation under 10 CFR 54.21(c)(1)(iii) by 

assuring that a reanalysis or other appropriate corrective action is taken if a design basis 

cycle count limit is reached at any time during the extended licensed operating period.

A4.2.6 Regenerative Heat Exchanger Fatigue Analyses

The regenerative heat exchanger recovers energy from the letdown line to heat chemical 

and volume control system charging water for reactor system makeup (charging) and 

auxiliary pressurizer spray. The charging system has three positive-displacement pumps. 

The pumps cannot be throttled without lifting discharge safety valves, but one of them is 

variable speed. The charging system was designed to operate continuously, with flow from 

the fluid-drive variable-speed pump controlled by a primary coolant volume control signal. If 

the variable-speed pump is out of service, the system controls Primary Coolant System 

makeup by cycling a constant-speed pump on and off. This cycling of cold makeup water 

against the (approximately constant) hot letdown flow produces significant thermal 

transients in the regenerative heat exchanger.

Isolation of letdown flow introduces a similar differential thermal load and has a similar 

effect.

Analysis

The original design included a fatigue evaluation to ASME III -1965, Paragraph N-415. The 

final addendum to the original analysis was based on a revised definition of the load 
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transient set which eliminated the 15 percent per minute load-following transient for this 

component. The worst-location cumulative usage factors (CUF) for a 40-year licensed 

operating life were 0.871 on the tubesheet, and 0.624 on the shell.

By 1993, operating experience had shown that the availability of the variable-speed pump 

was less than anticipated in the original design, and therefore that the number of thermal 

cycles from cycling a constant-speed pump was greater than anticipated. The expected 

number of lifetime thermal cycles and the fatigue usage factor at the most limiting location 

(the tube sheet) were therefore reevaluated. The transient evaluation increased the lifetime 

number of thermal stress cycles due to this event from 5,520 to 17,822. The fatigue 

evaluation found that, with the increased number of thermal cycles described above plus the 

remainder of the design basis event set, the CUF at the limiting tube sheet location would be 

1.002, slightly above the analytic limit of 1.0. However, the design basis event set included 

60,500 load-following and reactor trip events (Transient I), of which the unit had experienced 

only about 180 by that date (1993). The fatigue evaluation therefore reduced the design 

basis Transient I cycles slightly (to 60,282), and demonstrated that the analytic limit of 1.0 

was then met. The 1993 reanalysis retained the simplifying assumption from the original 

analysis, that the thermal effect of cycling a constant-speed charging pump produced the 

maximum stress range for all load pairings.

A revision in 1995 to permit more frequent letdown isolation re-evaluated both thermal and 

pressure transient effects. The evaluation of stress pairings for Transient I load-following 

and reactor trip events found that those with the maximum stress range could be further 

reduced to 32,500 from the 60,282 assumed in the 1993 analysis, even considering the 

increased frequency of letdown isolations. This 1995 revision again evaluated only the 

limiting inner ligament of the shell side of the tubesheet, for which the calculated lifetime 

CUF is 0.880.

Based on the plant events in the first 20 years of operation, a recent revision to the 

calculation estimates that the number of cycles for cycling the constant-speed charging 

pump can be increased to 27,062, and Transient I can be reduced to 6,240 for 60-year plant 

life. With the new estimated numbers of transient events at the end of extended operating 

period, the maximum fatigue usage factors at the two most critical locations in the 

regenerative heat exchanger (tubesheet and tubesheet to shell junction) is 0.439.

Disposition: Revision, 10 CFR 54.21(c)(1)(ii); and Aging Management, 10 CFR 

54.21(c)(1)(iii)

Re-analysis has been performed to include additional thermal cycles from cycling the 

constant-speed charging pump and reduced number of transients that were over estimated 

in the original design analysis. The projected CUF at the end of the extended operating 
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period remains less than 1. Therefore, the regenerative heat exchanger meets the criteria of 

10 CFR 54.21(c)(1)(ii).

The fatigue management cycle count program will include the letdown isolation and 

variable-speed charging pump out-of-service events.

A4.2.7 ASME III Class A Primary Coolant Piping Fatigue Analyses

A piping fatigue analysis was originally applied only to the main loops of the primary coolant 

system, the two 42 inch hot legs and the four 30 inch cold legs, and to the connecting 

nozzles for smaller piping. The original analyses calculated fatigue usage factors for the:

• Hot legs

• Cold legs

• Safety injection-shutdown cooling nozzles

• Hot leg to surge line nozzle

• Charging Inlet nozzles

• Hot leg temperature nozzles

• Shutdown cooling outlet nozzle

• Cold leg temperature nozzles

The hot leg to surge line nozzle has been reanalyzed to address transients not 

contemplated in the original analysis.

The design stress ranges of the cold-leg-to-pressurizer-spray nozzles were below the 

endurance limit in the original design basis analysis. However the 

cold-leg-to-pressurizer-spray nozzles have since been evaluated for additional transients 

not contemplated in the original analysis. The fatigue issue of the 

cold-leg-to-pressurizer-spray nozzles is addressed in Section A4.2.8.

The following section addresses the remaining original analyses for the hot and cold legs, 

and for the remaining original nozzles.

Analysis

The fatigue analysis of record for the hot and cold legs uses the bounding stresses at all 

locations in each of hot leg and cold leg to determine the worst possible stress ranges. 

These usage factors are therefore considerably higher than would be calculated by a 

location-specific analysis. The maximum CUF is 0.07551 for the hot leg, and 0.7531 for the 

cold leg.
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The cold leg charging nozzle was reanalyzed to account for the additional cycles due to the 

constant-speed charging pump recycling. CUF at the end of the extended operation period 

is 0.526.

The cold leg safety injection-shutdown cooling and charging inlet nozzles are also the 

sample locations, which were selected for evaluation of effects of the reactor coolant 

environment on fatigue behavior.

Disposition: Validation, 10 CFR 54.21(c)(1)(i), and Aging Management, 10 CFR 

54.21(c)(1)(iii)

The number of each of the design basis events that affect the hot and cold legs is not 

expected to approach its design basis limit during the extended licensed operating period, 

and therefore that the actual fatigue usage factors are not expected to approach their 

calculated values during the extended licensed operating period. The calculated maximum 

usage factor for the hot and cold legs and their nozzles in these original calculations is 

0.7531, well within the analytical limit of 1.0.

The predicted hot leg and cold leg usage factors are calculated on a very conservative 

basis. The hot leg usage factor is quite low, and the cold leg usage factor, though appearing 

significant at 0.7531, would be much less if calculated by a location-specific analysis.

The Fatigue Monitoring Program will ensure a reanalysis or other appropriate corrective 

action in the unlikely event that a design basis cycle count limit is reached at any time during 

the extended licensed operating period.

A4.2.8 Revised Bulletin 88-11 Fatigue Analysis of the Hot-Leg-to-Pressurizer-Surge-Line 

Nozzle, Surge Line, and Pressurizer Surge Nozzle

NRC Bulletin 88-11, dated December 1988, was issued to address pressurizer surge line 

temperature stratification concerns. The effects of thermal stratification were evaluated by 

the Combustion Engineering Owners Group. The Combustion Engineering Owners Group 

Report concluded the structural integrity of the pressurizer surge line is acceptable for the 

forty year life of the Plant. The NRC issued an SER on September 13, 1993 concluding that 

the CEOG analysis adequately demonstrates that the bounding surge line and nozzles meet 

ASME Code stress and fatigue requirements for the 40-year design. CPCo provided 

additional information detailing completion of the required actions of Bulletin 88-11, including 

the requirement to update the pressurizer surge line stress and fatigue analyses. See FSAR 

Section 4.3.7.

Analysis

For both surge line nozzles and the surge line elbow, the calculated usage factors for the 

revised set of design basis load events are within the code limit of 1.0.
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Pressurizer Surge Line Elbow: The fatigue evaluation for a typical Combustion 

Engineering plant with intermittent pressurizer spray and for the revised set of design basis 

load events, including the IEB 88-11 thermal stratification transients, calculated a maximum 

CUF of 0.937 at one of the surge line elbows.

A recent fatigue analysis using thermal stratification conditions under the Palisade 

continuous pressurizer spray operation show that the CUF is reduced significantly to 0.0135 

for the expected number of cycles at the end of the 60-year operating period. If the number 

of cycles at the end of the extended operating period were based on 1.5 times the 40-year 

design basis cycles, the CUF at the surge elbow would be 0.0447.

This location is also a NUREG/CR 6260 sample location for evaluation of environmental 

effects of the reactor coolant on fatigue effects.

Hot Leg to Surge Line Nozzle: The fatigue evaluation for a typical Combustion 

Engineering plant with intermittent pressurizer spray and for the revised set of design basis 

load events, including the IEB 88-11 thermal stratification transients calculated a maximum 

CUF of 0.3818 for Palisades hot leg to surge line nozzle. With Palisades continuous 

pressurizer spray operation, the CUF is reduced significantly, similar to the above surge line 

elbow, because piping loads due to thermal stratification are the major contributor to nozzle 

fatigue stress.

Pressurizer Surge Nozzle: The fatigue evaluation for a typical Combustion Engineering 

plant with intermittent pressurizer spray and for the revised set of design basis load events, 

including the IEB 88-11 thermal stratification transients calculated a maximum CUF of 

0.9611 for the Palisades pressurizer surge line nozzle. With Palisades continuous 

pressurizer spray operation, the CUF is reduced significantly, similar to the above surge line 

elbow, because piping loads due to thermal stratification are the major contributor to the 

nozzle fatigue stress.

Design Basis Thermal Transients and Expected Thermal Transients: The additional 

thermal stratification transients are in the pressurizer surge line and nozzles during plant 

heatup and cooldown at differential temperatures of 320, 250, 200, and 150o F ∆T, and hot 

standby at 90o F ∆T. These design transients were developed by the CE owners group for a 

typical plant with severe thermal transients due to intermittent pressurizer spray.

The use of modulated, continuous spray for pressure control, and control of pressurizer to 

primary loop ∆T, significantly mitigates this problem at Palisades. An assessment of the 

thermal stratification event mechanisms for Palisades operating conditions found that for 

almost all such events the metal ∆T would not exceed 210o F, instead of the 320o F ∆T 

assumed by the standard plant analysis. This is further supported by the log of pressurizer 

spray events at ∆T above 200o F, which has recorded only 47 through 9 January 2005. 
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These transients are auxiliary spray events, which have little or no effect on surge line 

stratification.

This moderation of the transients reduces the piping differential expansion loads and 

support and nozzle reactions. A recent fatigue analysis using thermal stratification 

conditions under the Palisade continuous pressurizer spray operation show that the CUF at 

the surge line elbow is reduced to less than 0.1 at the end of the extended operation period. 

Since piping load is the major contributor to the nozzle fatigue stress, a similar reduction is 

expected for the surge line nozzles.

Design Basis Cycle Count and Expected Cycle Count: The number of design cycles 

developed by the CE Owners Group for each of the above thermal stratification transients 

correspond to 500 cycles of plant heatup and cooldown. The number of transient events 

which might be expected to initiate these thermal stratification events will not exceed their 

design basis limits for the extended licensed operating period, the same is therefore also 

true for these thermal stratification events.

Disposition for Surge Line Elbow: Revision, 10 CFR 54.21(c)(1)(ii); and Aging 

Management, 10 CFR 54.21(c)(1)(iii)

A plant-unique calculation for the surge line shows that the fatigue usage factor of the surge 

line elbow remains less than 1 at the end of the extended operating period. The calculation 

includes the revised set of design basis load events; including the plant-unique IEB 88-11 

thermal stratification transients. Therefore, the surge line elbow meets the revision criteria 

per 10 CFR 54.21(c)(1)(ii).

The Fatigue Monitoring Program will ensure that the effects of aging will be adequately 

managed for the period of extended operation by assuring that a reanalysis or other 

appropriate corrective action is taken if a design basis primary coolant system cycle count 

limit is reached at any time during the extended licensed operating period.

Disposition for Hot Leg and Pressurizer Surge Nozzles: Validation, 10 CFR 

54.21(c)(1)(i); and Aging Management, 10 CFR 54.21(c)(1)(iii)

The design basis analysis calculated maximum usage factor at the hot leg surge nozzle of 

0.3818 is well below the analytical limit of 1.0. The usage factor remains less than 1 at the 

end of the extended operating period. Therefore, the surge line elbow and the pressurizer 

surge nozzle meet the validation criteria per 10 CFR 54.21(c)(1)(i).

The calculated maximum usage factor for the pressurizer surge nozzle of 0.9611 is below 

the analytical limit of 1.0. This value is the result of a generic plant analysis, which assumed 

worst-case stratification through the entire surge line, and which calculated transients based 

on intermittent pressurizer spray. Similar to the CUF of the surge line elbow, the CUF of the 
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pressurizer is expected to reduce considerably, if the moderation of the transients of the 

Palisades continuous pressurizer spray is used.

As mentioned above, the number of design cycles for surge line stratification flow developed 

by the CE Owners Group for each of the above thermal stratification transients correspond 

to 500 cycles of plant heatup and cooldown.

The Fatigue Monitoring Program will ensure that the effects of aging will be adequately 

managed for the period of extended operation by assuring that a reanalysis or other 

appropriate corrective action is taken if a design basis primary coolant system cycle count 

limit is reached at any time during the extended licensed operating period.

A4.2.9 Revised Fatigue Analysis of Nozzles from PCS Cold Legs 1B and 2A to Pressurizer 

Spray and of the Pressurizer Spray Nozzle

Summary Description

Pressurizer spray is normally supplied by reactor coolant pump head through 3 inch nozzles 

on two of the four 30 inch primary coolant system (PCS) cold legs. Normal spray flow in 

each of these 3 inch lines is continuous, through a normally throttled 3/4 inch main spray 

bypass valve, and through a 3 inch main spray control valve. The charging line downstream 

of the regenerative heat exchanger supplies auxiliary spray from the chemical and volume 

control system through a 2 inch control valve. All three of these sources supply a single 

pressurizer spray nozzle.

The original design of the pressurizer included a fatigue analysis of the pressurizer spray 

nozzle. However, the normal spray piping and the auxiliary spray piping were designed to 

the B31.1 Code. Revised operating conditions and pressurizer cooldown rate prompted 

addition of a fatigue analysis for the two cold leg nozzles and for the auxiliary spray piping.

Analysis of Other Nozzles

Cold Leg Nozzles to Pressurizer Spray: The analysis of the auxiliary spray-reverse flow 

events is based on the design basis number of thermal cycles assumed for 40 years, and 

the calculated cumulative usage factor is 0.66.

Pressurizer Spray Nozzle: The revised pressurizer spray nozzle analysis determined that 

the calculated cumulative usage factor (CUF) is 0.8214 for the design basis number of 

high-differential-temperature spray events and 200o F per hour cooldowns assumed for 40 

years, and for all other applicable transients.

The revised analysis also estimated that the maximum CUF in the spray nozzle to that date 

(October, 1991) was 0.353, and that accumulation at then-current trends indicated a 40-year 

lifetime CUF of about 0.435. On that basis a projection to the end of a 60-year extended 

licensed operating period would indicate a CUF of about 0.517.
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Disposition Cold Leg to Pressurizer Spray Nozzles: Validation, 10 CFR 54.21(c)(1)(i)

The number of thermal cycles for each of the design basis temperature differential ranges 

will not exceed the design basis limit during the extended licensed operating period. The 

calculated 40-year plant life usage factor of 0.66 is well below the analytical limit of 1.0. 

Thus the usage factor remains less than 1 at the end of the extended licensed operating 

period.

Disposition Pressurizer Spray Nozzles: Aging Management, 10 CFR 54.21(c)(1)(iii)

The design basis cumulative usage factor (CUF) of the nozzle is 0.8214 for the original 

40-year licensed operating period. The projected number of cycles of the design basis 

events does not exceed the design basis limit during the extended licensed operating 

period. Therefore, the actual fatigue usage factor is not expected to approach the calculated 

value at the end of the extended licensed operating period.

The Fatigue Monitoring Program will ensure that the effects of aging will be adequately 

managed for the period of extended operation by assuring that a reanalysis or other 

appropriate corrective action is taken if a design basis cycle count limit is reached at any 

time during the extended licensed operating period.

A4.2.10 Pressurizer Auxiliary Spray Line Tee Fatigue Analysis in Response to NRC Bulletin 

88-08

NRC Bulletin 88-08 and supplements describe observed effects of thermal cycling and 

thermal stratification in reactor coolant system pressure boundary components due to 

thermally-driven cyclic inleakage at isolation valves and similar phenomena. In 1989 a 

conservative, bounding analysis of the section of the Palisades auxiliary spray line from 

check valve CK 2118 to the pressurizer spray line tee demonstrated that fatigue due to 

these effects would be acceptable for the then-remaining 30 year licensed operating life.

The piping material is A 376 Type 316. The auxiliary spray line connects to the normal spray 

line vertically and below, so that the cooler auxiliary spray water does not cause a thermal 

stratification effect. The analysis assumed 500 lifetime operating basis earthquake (OBE) 

cycles and 500 lifetime full-range thermal expansion (heatup and cooldown) cycles. It 

modeled the Bulletin 88-08 phenomena (due to inleakage through the check valve) as a 

thermal cycle every two minutes, between 536 and 400 oF, or 1.84 x 105 per year at a 70 

percent availability factor.

The 500 lifetime OBE cycles are assumed to occur only once in a design lifetime, 

independent of its length. The analysis also conservatively attributed the entire 500 

full-range thermal expansion to the remaining 30 year life. These OBE and full-range 
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thermal cycles contributed a negligible 0.0063 usage factor. The assumed Bulletin 88-08 

cycles contributed 0.4245 in 30 years, for an end-of-life cumulative usage factor (CUF) of 

0.43

Analysis

License renewal will add an additional 20 years to the design life assumed by the analysis. 

Increasing the lifetime contribution of the OBE cycles and full-range thermal expansion 

cycles by 50% (a conservative assumption for OBE, and given the plant history, also for the 

full-range thermal cycles) results in a contribution of only 0.0095. Increasing the assumed 

remaining design life to 50 years results in a contribution from the Bulletin 88-08 cycles of 

0.7075, for a 60-year CUF of 0.717, well within the allowable of 1.0.

The analysis assumed 70 percent plant availability. Recent experience has been about 90 

percent, which would increase the contribution of the Bulletin 88-08 cycles to about 0.91, or 

a CUF of about 0.92. 

Disposition: Validation, 10 CFR 54.21(c)(1)(i)

The assumptions and methods of the analysis are otherwise very conservative, and this 

result is still within the allowable of 1.0.

A4.2.11 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction 

Factor in Piping and Components

This section addresses the issue of assumed thermal cycle counts which determine an 

allowable secondary stress range reduction factor for some Consumers Power Design 

Class 1 piping and components, and for non-Consumers Power Design Class 1 piping and 

components.

Only the primary coolant system piping and components have an ASME Class 1 fatigue 

analysis. Other Consumers Power Design Class 1 piping and components were designed to 

the ANSI B31.1 Power Piping Code, ASME Section VIII, or ASME III, Class 2 and 3, which 

requires a stress range reduction factor to the allowable stress range for secondary 

(expansion and displacement) stresses to account for thermal cycling. For ANSI B31.1 the 

allowable secondary stress range is 1.0 SA for 7,000 equivalent full-range thermal cycles or 

less. The allowable secondary stress range is reduced to 0.5 SA for thermal cycles greater 

than 100,000. Components designed to other codes, such as ASME VIII, have identical or 

very similar provisions. An increase in design life could increase the number full-range 

thermal cycles, therefore, design analyses under these codes are TLAAs.

Some piping within the scope of license renewal was originally designed and built to the 

American Standard (ASA) Code for Pressure Piping, Section 1, “Power Piping Systems,” 

1955 edition. However, during the implementation of IE Bulletin 79-14 work, CP Co Design 
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Class 1 piping, except the main primary coolant piping, was designed to the USAS B31.1.0 

(1967) Power Piping Code. In 1992, as a result of discussions between CP Co and the 

NRC, for new and existing CP Co Design Class 1 piping (except the main primary coolant 

piping), the code of record was changed to ANSI B31.1 (1973) Power Piping Code with the 

Summer (1973) Addenda (FSAR 5.10.1.1).

With regard to the stress range reduction factors and corresponding thermal cycle count 

assumptions, the Consumers Power Class 2 and 3 piping systems and components are 

designed to the same requirements as CP Co Design Class 1 piping.

The review of possible TLAAs found no Palisades piping and components design analyses 

to the B31.1 rules, which invoke lower stress range reduction factors for an increase in the 

equivalent full-range thermal and displacement cycles.

Analysis

The number of lifetime (full-range and equivalent) thermal and other displacement cycles 

applicable to most of the Palisades B31.1 piping and components are expected to be similar 

to the plant design basis events. Therefore, so long as the assumed number of the plant 

design basis event cycles is not exceeded, the secondary stress range reduction factors 

assumed for these B31.1 piping and components, and similar code designs remain valid.

Results of the TLAA fatigue review for B31.1 piping and similar code designs for mechanical 

systems within the scope of license renewal and with operating temperature in excess of 

220o F for carbon steel or 270o F for austenitic stainless steel, revealed only two piping 

systems that have additional cycles that exceed the 7000-cycle limit of the B31.1 Code. 

These systems include the charging lines inboard of the regenerative heat exchanger, which 

experience an increase in partial-range thermal cycles due to cycling of the fixed-speed 

pumps. The original 6,000 events increased to 18,000 for 40-year and 27,000 for 60-year 

life. The effects of additional cycles have been evaluated for the Regenerative Heat 

Exchanger fatigue and for the Charging Inlet nozzle. The calculation will be revised to 

include the effects of the additional cycles on charging lines. The other system is the PCS 

hot leg sampling piping, which may exceed 7,000 cycles during the period of extended 

operation. A calculation will be performed to justify PCS sampling to occur at any 

reasonable frequency for 60 years of operation without exceeding the allowable number of 

cycles.

Disposition for the Charging Lines Inboard of the Regenerative Heat Exchanger: 

Revision, 10 CFR 54.21(c)(1)(ii)

NMC will evaluate the effect the increase in variable-speed-charging-pump-out-of-service 

events may have on these lines, and will take actions necessary to ensure these lines meet 

licensing basis design criteria for the extended operating period. NMC will complete this 
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evaluation and will advise the NRC of the results, and of any necessary corrective actions, 

before the end of the current licensed operating period.

Disposition for Other Piping and Components: Validation, 10 CFR 54.21(c)(1)(i), and 

Aging Management, 10 CFR 54.21(c)(1)(iii)

The number of lifetime (full-range and equivalent) thermal and other displacement cycles 

applicable to most of the Palisades B31.1 piping and components are expected to be similar 

to the plant design basis events. The number of each of these events is not expected to 

exceed the existing 40-year design basis for the 60-year extended licensed operating 

period.

The Fatigue Monitoring Program will ensure reanalysis or other appropriate corrective 

action in the unlikely event that a design basis cycle count limit is reached at any time during 

the extended licensed operating period.

A4.2.12 Effects of Reactor Coolant System Environment on Fatigue Life of Piping and 

Components (Generic Safety Issue 190)

The effects of the reactor coolant environment may need to be included in the calculated 

fatigue life of components. GSI-190 addressed this issue. Although the parent GSI-190 

safety issue has been resolved, NUREG-1800, Section 4.3.1.2, states that “The applicant's 

consideration of the effects of coolant environment on component fatigue life for license 

renewal is an area of review.” The GSI-190 review requirements are therefore imposed by 

the Standard Review Plan and do not depend on the individual plant licensing basis.

Analysis

NUREG/CR 6260, Table 5-43, identifies seven sample locations for older Combustion 

Engineering plants:

• Reactor Vessel (Lower Head to Shell Transition)

• Primary Coolant Inlet Nozzle

• Primary Coolant Outlet Nozzle

• Surge Line Elbow

• Charging Nozzles

• Safety Injection Nozzles

• Shutdown Cooling Line Inlet Transition.

Of these:

• Palisades has no “shutdown cooling line inlet transition.” The safety injection and 

shutdown cooling functions share a common nozzle.
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• NUREG/CR-6260 evaluated a long-radius elbow in the surge line because, in the sample 

plant, this was the highest usage factor location in the surge line and nozzles subject to 

NRC Bulletin 88-11 reanalysis for thermal stratification cycles. In the NUREG/CR-6260 

sample plant this component is SA-376 Type 316; at Palisades the surge line material is a 

similar Type 316. The only Palisades location on this line with a plant-specific fatigue 

analysis is the hot leg nozzle to the surge line. The analysis for the surge line elbow is for 

a typical C-E PWR with intermittent pressurizer spray, with thermal stratification 

transients; and the pressurizer surge nozzle analysis uses pipe loads from the same 

source. The results are therefore more conservative than would be expected for 

Palisades, which has a continuously-modulated pressurizer spray and less-severe 

thermal transients.

• The Palisades charging nozzles are SB 166 Ni-Cr-Fe Alloy 600 instead of the austenitic 

stainless of the NUREG/CR-6260 sample plant. However, Alloy 600 is evaluated the 

same as austenitic stainless for these purposes.

Of the seven NUREG/CR-6260, Section 5.2, sample locations for an older Combustion 

Engineering plant, six are therefore applicable to Palisades. See Table A4.2.12-1, below.

Environmental effects on cracking in the charging and other Alloy 600 nozzles are also 

addressed in Appendix A4.5.2, fatigue in the charging nozzles in Appendix A4.2.7, and 

fatigue in the surge nozzles in Appendix A4.2.8.

All of the primary coolant system at Palisades is stainless steel, Alloy 600, or carbon steel 

with stainless or Alloy 600 clad. Fatigue in clad components is evaluated using base 

material properties only; that is, as if the coolant is in contact with the base material, 

consistent with NUREG/CR-6260.

Table A4.2.12-1Summary of Fatigue Usage Factors at NUREG/CR-6260 Sample 

Locations Applicable to Palisades

Location Material

CUF for 

Design 

Cycles

Fen

NUREG/

CR-5999 CUF 

for Design 

Cycles

Reactor Vessel (Lower 

Head to Shell 

Transition)

SA-302 Grade B 0.00364 2.53 0.009

Primary Coolant Inlet 

Nozzle SA-302 Grade B 0.01702 2.53 0.043
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Disposition: Revision, 10 CFR 54.21(c)(1)(ii); and Aging Management, 10 CFR 

54.21(c)(1)(iii)

A plant-specific calculation was performed for the six sample locations applicable to 

Palisades, adapted from the seven identified in NUREG/CR-6260 for older-vintage 

Combustion Engineering plants. Detailed environmental fatigue calculation use the 

appropriate Fen relationships from NUREG/CR-6583 for carbon and low-alloy steels and 

from NUREG/CR-5704 for stainless steels, as appropriate for the material at each of these 

seven locations.1

The calculation determines an appropriate Fen(i) for each individual load pair in the 

governing fatigue calculation, so that an overall Fen multiplier on cumulative usage factor 

(CUF) for environmental effects can be determined for each location. The analysis shows 

that the fatigue usage factors at all NUREG/CR-6260 sample locations, but the charging 

nozzle, including the effects of the reactor coolant environment, will remain less than 1.0 for 

the extended operation period.

The Charging nozzle has an Alloy 600 safe end, and is one of the components in the 

Palisades Alloy 600 Inspection Program, which specifies inspection methods and inspection 

frequency. The Fatigue Monitoring Program will also ensure that the original design basis 

Primary Coolant 

Outlet Nozzle SA-302 Grade B 0.115 2.53 0.29

Charging Inlet Nozzles 

(with Thermal 

Sleeves)

SB-166 Alloy 600 0.288 15.35 4.428

Surge Line Elbow SA-376 Type 316 0.0343 15.35 0.526

Safety InjectionShutdown Cooling 

Nozzles

SA-516 Grade 70 0.048 1.79 0.085

1.Neither NUREG/CR-5704 nor NUREG/CR-5999 provide interim fatigue curves for Alloy 600 materials. The 

NUREG/CR-5704/5999 values for stainless steel will therefore be used, consistent with the practice of 

NUREG/CR-6260.

Table A4.2.12-1Summary of Fatigue Usage Factors at NUREG/CR-6260 Sample 

Locations Applicable to Palisades

Location Material

CUF for 

Design 

Cycles

Fen

NUREG/

CR-5999 CUF 

for Design 

Cycles
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number of load cycles for each loading event is not exceeded. If this occurs, an evaluation 

will be made and appropriate actions will be taken to confirm the basis of the safety 

determination.

A4.3 Environmental Qualification of Electrical Equipment

Under 10 CFR 54.21(c)(1)(iii), a Plant EEQ Program which implements the requirements of 

10 CFR 50.49 is viewed as an Aging Management Program (AMP) for license renewal. 

Re-analysis of an aging evaluation to extend the qualification of components under 10 CFR 

50.49(f) is performed on a routine basis as part of the EEQ Program. Important attributes for 

the reanalysis of an aging evaluation include analytical methods, data collection and 

reduction methods, the underlying assumptions, the acceptance criteria, and corrective 

actions (if acceptance criteria are not met).

Analytical Methods: The analytical models used in the reanalysis of an aging evaluation 

are the same as those previously applied during the prior evaluation. The analytical method 

used for a radiation aging evaluation is to demonstrate qualification for the total integrated 

dose (that is, normal radiation dose for the projected installed life plus accident radiation 

dose). For license renewal, one acceptable method of establishing the 60-year normal 

radiation dose is to multiply the 40 year normal radiation dose by 1.5 (that is, 60 years/40 

years). The result is added to the accident radiation dose to obtain the total integrated dose 

for the component. For cyclical aging, a similar approach may be used. Other models may 

be justified on a case-by-case basis.

Data Collection and Reduction Methods: Reducing excess conservatism in the 

component service conditions (for example, temperature, radiation, and cycles) used in the 

prior aging evaluation is a typical method used for a reanalysis. Plant temperature data can 

be obtained in several ways, including monitors used for technical specification compliance, 

other installed monitors, measurements made by plant operators during rounds, and 

temperature sensors on large motors (while the motor is not running). When used, a 

representative number of temperature measurements are conservatively evaluated to 

establish the temperatures used in an aging evaluation. Plant temperature data may be 

used in an aging evaluation in different ways, such as (a) directly applying the plant 

temperature data in the evaluation, or (b) using the plant temperature data to demonstrate 

conservatism when using plant design temperatures for an evaluation. Any changes to 

material activation energy values as part of a reanalysis are justified on a case-specific 

basis. Similar methods of reducing excess conservatism in the component service 

conditions used in prior aging evaluations may be used for radiation and cyclical aging.

Underlying Assumptions: EQ component aging evaluations contain sufficient 

conservatism to account for most environmental changes occurring due to plant 
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modifications and events. When unexpected adverse conditions are identified during 

operational or maintenance activities that affect the normal operating environment of a 

qualified component, the affected EQ component is evaluated and appropriate corrective 

actions are taken, which may include changes to the qualification bases and conclusions.

Acceptance Criteria and Corrective Actions: The reanalysis of an aging evaluation could 

extend the qualification of the component. If the qualification cannot be extended by 

reanalysis, the component is maintained, replaced, or re-qualified prior to exceeding the 

period for which the current qualification remains valid.

Regulatory Issue Summary (RIS) 2003-09

On May 2, 2003, the staff issued NRC Regulatory Issue Summary (RIS) 2003-09, 

“Environmental Qualification of Low-Voltage Instrumentation and Control Cables”, providing 

the results of the staff's technical assessment of GSI-168, following completion of the 

NRC-sponsored cable test research. The staff's technical assessment of GSI-168 in 

RIS-2003-09 is stated as follows:

For license renewal, a re-analysis (based on the Arrhenius methodology) to extend the 

life of the cables by using the available margin based on a knowledge of the actual 

operating environment compared to the qualification environment, coupled with 

observations of the condition of the cables during walk-downs, was found to be an 

acceptable approach. Monitoring I&C cable condition could provide the basis for 

extending cable life.

The Palisades Plant Electrical Equipment Qualification Program allows re-analysis for 

maintaining qualification using the methods described above. In addition, the EEQ Program 

has procedural requirements in place to monitor and track aging effects of EQ equipment 

including cables. The requirements are listed below:

• Monitoring equipment condition and equipment performance 

• Monitoring environmental conditions of plant areas, and 

• Incorporating the results of testing and analysis into the plant maintenance and 

surveillance program.

Disposition

The EEQ Program will continue to be implemented for the extended operating period in 

accordance with 10 CFR 50.49. Continuing the existing EEQ Program provides reasonable 

assurance that the aging effects will be managed and that the EQ components will continue 

to perform their intended functions for the period of extended operation. Therefore, this 

TLAA is dispositioned under 10 CFR 54.21(c)(1)(iii), in that continuation of the existing EEQ 
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Program will adequately manage aging of affected components for the period of extended 

operation. 

A4.4 Containment Liner Plate, Metal Containments and Penetrations Fatigue 

Analysis

A4.4.1 Concrete Containment Tendon Prestress Analysis

The original design included a calculation of expected loss of prestress for the plant design 

life In accordance with ACI 318-63. The calculation evaluated loss of prestress due to 

friction and initial seating loss, tendon relaxation, concrete elasticity, concrete shrinkage, 

and concrete creep. FSAR Section 5.8.5.3.1 lists the predicted values for remaining 

prestress at the end of the 40 year design life. This original analysis was conservative, as 

demonstrated by a regression analysis of tendon surveillance data from the twentieth and 

twenty-fifth-year tendon surveillances. This regression analysis indicated that the effective 

dome, hoop, and vertical tendon forces would remain significantly higher than values 

predicted by the original relaxation estimates beyond the 40-year licensed operating period.

Periodic surveillances of containment tendons for degradation are required by 10 CFR 

50.55a and Palisades Technical Specification 5.5.5. See FSAR Section 5.8.8 for additional 

information on the existing surveillance program requirements and results. 

Disposition

This issue is dispositioned under 10 CFR 54.21(c)(1)(iii), the effects of aging on the 

intended function(s) will be adequately managed for the extended operating period, in that 

the existing Palisades tendon surveillance program activities will be continued in 

accordance with 10 CFR 50.55a.

A4.4.2 Containment Liner Plate Load and Penetrations Load Cycles

The containment liner plate and penetrations were conservatively designed, in part, to the 

rules of the ASME Boiler and Pressure Vessel Code, Section III-1965. This code edition 

classifies containment as a Class B vessel. A fatigue analysis is required under this code 

edition only for Class A vessels (reactor coolant pressure boundary, etc.). However the 

Palisades containment liner and penetration designs use some of the methods and data 

from Section III, Article 4, for design of Class A vessels for fatigue loads.

The Palisades containment design relies on the liner only to maintain a leak-tight 

containment. There are no design conditions under which the liner plate is relied upon to 

assist the concrete in maintaining the integrity of the structure. Containment penetrations 

are designed to maintain the leak tightness of the containment structure under normal and 

accident conditions.
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Analysis

The Palisades containment design relies on the liner to maintain a leak-tight containment. 

However, there are no design conditions under which the liner plate is relied upon to assist 

the concrete in maintaining the integrity of the structure. Forces are transmitted between the 

liner plate and the concrete through the anchorage system and through direct contact 

(pressure). At times, forces may also be transmitted by bond and/or friction. These forces 

cause, or are caused by, liner plate strains. The liner plate is designed to withstand the 

predicted strains. The effect of concrete cracking on the liner plate has also been 

considered.

The allowable liner plate strains/stress was conservatively based on the ASME B&PV Code, 

Section III, Article 4, 1965. Specifically, the following sections were adopted as guides in 

establishing allowable strain limits:

1. Paragraph N-412(m) - Thermal Stress, Subparagraph 2

2. Paragraph N-412(n) - Operational Cycle

3. Paragraph N-414.5, Table N-413, Figures N-414 and N-415(a) - Peak Stress Intensity

4. Paragraph N-415.1 - Vessels Not Requiring Analysis for Cyclic Operation

The liner strains/stresses due the (non-DBA) loads are relatively small such that the number 

of environmental and operational load cycles is insignificant compared to the allowable 

number of cycles on the fatigue curve in code Fig. N-415 (a), or compared to 3 times the Sm

value of code of Table N-421 at the operational temperature. The results of the analysis 

confirm that the design of the containment liner complies with the provisions of code 

paragraph N-415.1 for not requiring a fatigue analysis for design load cycles.

Disposition: Validation, 10 CFR 54.21(c)(1)(i)

Of the design basis fatigue load cycles of the containment liner, only the number of 

environmental and operational load cycles would increase due to the 60-year extended 

licensed operating period.

Of these two events, the effect of the assumed summer-winter annual cycles is negligible, 

and will remain negligible on increase from 40 to 60 cycles for the 60-year extended 

licensed operating period.

The assumed 500 containment interior operational heatup and cooldown cycles is very 

conservative, since it corresponds to an average of 8 1/3 cycles per year, or a PCS 

cooldown and heatup every 6 weeks. This is more than adequate to accommodate the 

60-year extended licensed operating period.
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Therefore, there will be negligible change in the fatigue resistance of the containment liner 

for the 60-year extended licensed operating period. 

In addition, periodic inservice LLRTs required by Plant Technical Specifications monitor the 

continued inservice leaktight functionality of each individual penetration through the 

extended licensed operating period.

A4.5 Other Plant-Specific Time-Limited Aging Analyses

A4.5.1 Fuel Handling Crane Load Cycles

A crane evaluation to the Crane Manufacturers Association of America Standard CMAA-70 

assumes a number of rated lifts in the design lifetime in order to establish the design Service 

Level, and hence the allowable stresses. At Palisades, two cranes have been reanalyzed to 

CMAA-70 design criteria. The NUREG-0612 heavy loads evaluation of the reactor building 

polar crane was performed to CMAA 70. A redesign of the Spent Fuel Pool Crane for dry 

fuel storage also included a NUREG-0612 evaluation to CMAA-70 design criteria. The 

limiting components of the containment polar crane (135 tons) and the redesigned spent 

fuel pool crane (110 tons) are now rated for CMAA-70 “Service Level A - Standby or 

Infrequent Service.” Service Level A cranes are designed to stress limits which assume 

either 20,000 to 100,000, or 200,000, rated lifts in a design lifetime. 

Analysis

Containment Polar Crane: The polar crane was originally designed to Electric Overhead 

Crane Institute Specification 61. The subsequent NUREG-0612 heavy loads evaluation of 

the polar crane was performed to CMAA 70 (1975). The minimally-rated components are 

CMAA 70 Service Level A. Since the minimally-rated components are Service Level A, the 

effective crane design life for fatigue or allowed number of rated lifts depends on this 

classification, which assumes 20,000 to 100,000 rated lifts in a design lifetime.

Separate evaluations have been performed of polar crane planned engineered lifts (over the 

rated capacity). The evaluations were done to ANSI/ASME Standard B30.2 (1996). Lifts 

have been evaluated and approved up to 140 T, less than 4 percent over the 135 T rating.

Spent Fuel Pool Crane: The redesign to 110 T for dry cask storage included a NUREG-0612 

evaluation to CMAA-70 Service Level A design criteria, and other considerations; and 

replacement of the trolley with a 110 T single-failure-proof trolley meeting NUREG 0554 

guidelines. The structural redesign and evaluation considered the load combinations of 

ASME NOG 1, Section NOG 4140, “Load Combinations.” 
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Disposition: 10 CFR 54.21(c)(1)(i)

Polar Crane (L-1): Polar crane rated or near-rated lifts are limited to the reactor head plus 

CRDMs and insulation, and reactor internals. Only a few rated lifts are performed each 

refueling outage, and none during operation. Therefore this machine cannot realistically 

approach the 20,000 to 100,000 rated lifts, assumed for components evaluated to CMAA 70 

(1975) Service Level A, during a 60 year licensed operating period.

Spent Fuel Pool Crane: Approximately 11 dry cask storage campaigns are expected 

between rerating and the end of the 60 year extended license. This will require loading 

about 64 casks. Each will require about two lifts of 100 T or more per cask, and some 

additional lifts of between 50 and 100 T. The total for 64 casks and 11 campaigns is about 

140 lifts of 100 T or more, and about 162 lifts between 50 and 100 T. Other lifts, and lifts prior 

to rerating the crane, were determined to be inconsequential. Therefore, this machine can 

not realistically approach the 20,000 to 100,000 rated lifts assumed for its design evaluation 

during the 60 year extended licensed operating period.

A4.5.2 Alloy 600 Nozzle and Safe End Life Assessment Analyses

Alloy 600 (Ni-Cr-Fe alloy) was used to clad the pressurizer lower head and surge nozzle, for 

the pressurizer heater sleeves, and for smaller nozzles and safe ends and flanges on larger 

nozzles of the Palisades reactor vessel head, primary coolant system loop piping, and 

pressurizer. There are 250 Alloy 600 heater sleeves, nozzles, safe ends, and flanges in the 

Palisades primary coolant system. 

Analysis

The inspection methods and intervals of the Palisades Alloy 600 aging management 

program were determined from evaluations of the susceptibility of all 250 remaining heater 

sleeves, nozzles, safe ends, and flanges to primary water stress corrosion cracking 

(PWSCC).

Disposition for Fatigue Analyses of the Weld Pad Repairs Installed in 1993 for the 

Pressurizer Temperature Element Nozzles: 10 CFR 54.21(c)(1)(iii)

NMC will monitor the cumulative number of pressurizer temperature element nozzle fatigue 

cycles within the Fatigue Monitoring Program, and maintain a special action level to ensure 

that appropriate actions are taken if at any time the cycle count for any design basis event 

since 1993 reaches the number assumed by these analyses.

For this purpose the fatigue management program will compare cycle counts since the 

repair in 1993 to appropriate action levels. Since the fatigue analyses were based on half of 

the 40-year pressurizer design basis event cycles, the action levels for cycles since then will 

be about half of the 40-year pressurizer design basis event cycles for each event.
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Disposition for Corrosion Life Assessment of the TE 0101 Temperature Element 

Nozzle Bore in the Carbon Steel Pressurizer Wall: 10 CFR 54.21(c)(1)(i)

The evaluation estimated a repair lifetime of 52.3 years for this effect following initiation of 

leakage. Leakage was first detected in 1993, after 22 years of operation, which indicates 

that the pressurizer wall can withstand this effect for a total plant life of over 70 years. 

Therefore, the current analyses remain valid for the period of extended operation.

Disposition for Cycle-Dependent Aspects of the Bounding Fracture Mechanics 

Analysis of the Hot Leg, Piping RTD and Sampling Nozzles, Pressurizer Instrument 

Nozzles, and Pressurizer Heater Sleeves; and Disposition for Fatigue Portions of All 

Other Alloy 600 Fracture Mechanics Analyses for a 40-Year Design Life: 10 CFR 

54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The Palisades plant-specific bounding fracture mechanics analysis demonstrates the 

validity of the cycle-dependent aspects of the generic bounding fracture mechanics analysis 

(WCAP-15973-P) by demonstrating that the plant-specific load and thermal events are 

within those assumed by the generic bounding analysis. The basis for the safety 

determination of the fracture mechanics evaluation calculation will therefore remain valid so 

long as the numbers of these events do not exceed the design basis values.

The fatigue cycle count program described in Appendix B, Fatigue Monitoring Program, will 

ensure a reanalysis or other appropriate corrective action if a design basis primary coolant 

system cycle count limit is reached at any time during the extended licensed operating 

period.

Disposition for All Alloy 600 Heater Sleeves, Nozzles, Safe Ends, and Flanges: 10 

CFR 54.21(c)(1)(iii)

The Palisades Alloy 600 Program identifies the Alloy 600 components in the primary coolant 

system, ranks them according to PWSCC susceptibility, and establishes a program for 

inspection, repairs, and mitigation. All 250 remaining Alloy 600 heater sleeves, nozzles, safe 

ends, and flanges are subject to the inspection program. At all 250 locations the program 

requires at least an insulated VT-2 visual inspection for leakage every refueling outage. 

Locations which are more susceptible to PWSCC, or whose failure could result in a 

more-significant safety hazard, are also subject to initial or periodic bare-metal VT-2, 

volumetric, or penetrant inspections.

A4.5.3 ASME Code Case N-481 Relaxation of The Primary Coolant Pump Weld Category 

B-L-1 Inspection Interval from 10 Years to 40 Years

The Byron-Jackson DFSS (Diffuser Single Suction) pumps at Palisades are vertical, single 

stage, centrifugal, with top-mounted motors, bottom suction, and single discharge. The 
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castings are Grade CF8M austenitic stainless. The casings were designed and fabricated to 

the ASME Boiler and Pressure Vessel Code, Section III, 1968. The casings met all 

requirements of Paragraph N-415.1 for exemption from a fatigue analysis. However, 

additional crack growth and thermal embrittlement analyses were performed to support 

relaxation of the ASME Section XI 10-year Category B-L-1 volumetric inspection interval for 

casing welds, under ASME Code Case N-481.

Analysis

The analysis includes support for its assumption of an initial flaw depth of 8 percent of the 

wall thickness (8% t), instead of the 25% t specified by Code Case N-481; based on the 

ASME code radiographic inspection standard used for these pumps which requires 

detection of a 2% t flaw.

Crack Growth: The crack growth analysis demonstrated that:

• The initial flaw would not exceed 25% t due to effects of the alternating stress for the 

design basis primary system cyclic events assumed for 40 year design life,

• The resulting 25% t flaw is stable for design, emergency, and faulted loads, and

• The resulting 25% t flaw would not grow to an unstable end-point size for another 5 

years, assuming a uniform rate of design cyclic events equal to their assumed total 

number divided by 40 years.

Thermal Embrittlement: The evaluation of the reduction of fracture toughness due to 

thermal embrittlement assumed that weld material behaved like the CF8M castings, which is 

conservative, since weld materials are not as subject to these effects. The evaluation used 

the J-R curve methodology of NUREG/CR-4513, which yields an aged material toughness 

KJc.

The evaluation of aged material toughness KJc used the most-conservative infinite 

time-at-temperature or “saturation” J-R curve for each material. The results of this 

evaluation of thermal embrittlement effects therefore do not depend on design life, and this 

aspect of the analysis is therefore not a TLAA.

End-Point Crack Size Determination: A crack will become unacceptable if any of the 

following would occur under design, emergency, or faulted loads:

• The crack is unstable against non-ductile propagation (“brittle fracture”).

• The crack is unstable against ductile tearing.

• The remaining ligament cannot carry its design loads, based on its flow stress.

Stability against brittle fracture is in part determined by the material fracture toughness and 

therefore depends in part on any reduction of fracture toughness due to thermal 
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embrittlement. Stability is indicated if the applied stress intensity factor KI (ASME Section XI, 

Equation A-3300 (1)), for all load conditions at all locations of concern, remains less than 

the aged material toughness KJc.

At Palisades the maximum end-point values (at the volute crotch) is KI

 = 130, minimum KJc

= 152.3, and median KJc = 223.5 (all in ksi in1/2). Therefore substantial margins would 

remain at the end of a 40 year life, even assuming KI

 is the maximum that would result from 

a complete design basis complement of load cycles. Of these two parameters, KI

 depends 

on the loading and the flaw sizes at the end of evaluation period, and the aged material 

toughness KJc in this analysis is the saturation J-R curve for each material. Thus the 

expected additional thermal aging effect will not diminish the KJc assumed by the analysis, 

the analysis will remain acceptable so long as the design basis complement of load cycles is 

not exceeded, which will ensure that the worst-location KI

 remains below 130 ksi in1/2.

Stability against ductile tearing is ensured if the applied crack extension J never reaches the 

J-integral required to initiate ductile tearing. This condition is also satisfied so long as KI

does not exceed KJc, as above.

The flow stress ligament capacity limit is defined as the crack size for which a ligament flow 

stress evaluation no longer demonstrates that the ligament will support the required loads.

At Palisades the flow stress ligament capacity limit is the most time limiting of these three 

criteria. The critical crack size based on this criterion would be exceeded in a little over 45 

years, assuming the 40 year design basis cycle count limit is reached at 40 years for all load 

events, and that the load cycles continue to accumulate at a constant rate. Since the margin 

to the KJc vs. KI

 brittle fracture stability criterion will not change, the cycle-dependent 

ligament flow stress criterion will remain limiting for the extended licensed operating period.

Disposition: 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii)

The projected number of each of the design basis events of the primary coolant pumps will 

approach its design basis limit during the extended licensed operating period. Therefore the 

maximum end-of-60-year life crack size is not expected to approach the critical crack size 

during the 60-year extended licensed operating period

The Fatigue Monitoring Program will ensure that the effects of aging will be adequately 

managed for the period of extended operation by assuring that a reanalysis or other 

appropriate corrective action is taken if a design basis cycle count limit is reached at any 

time during the extended licensed operating period.

A4.5.4 Risk-Informed Inservice Inspection Program Calculations

The scope and inspection intervals of the Palisades Risk-Informed Inservice Inspection 

(RI-ISI) Program depended on probabilities of failure of each pipe segment calculated at the 
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time of program implementation (approximately year 29) and the time of initial license 

expiration (year 40). 

Analysis

The scope of the RI-ISI program may increase somewhat when the extended operating 

period is considered.

Disposition: 10 CFR 54.21(c)(1)(ii)

The supporting calculations for the Palisades RI-ISI program will be reviewed, and updated 

as needed, to reflect a 60-year operating period; and the program inspection scope will be 

updated accordingly, before the period of extended operation.
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

APPENDIX B

AGING MANAGEMENT PROGRAMS
 Palisades Nuclear Plant

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Appendix B - Aging Management Programs

Page B-ii 

B1.0 Appendix B Introduction - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-1

B1.1 Overview - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-1

B1.2 Quality Assurance Program and Administrative Controls - - - - - - - - - - - - - - - - - - - B-3

B1.3 Operating Experience - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-5

B1.4 Aging Management Programs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-5

B1.5 Time Limited Aging Analyses Management Programs: - - - - - - - - - - - - - - - - - - - - B-6

B2.0 Aging Management Programs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-7

B2.1 Aging Management Programs Details - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-11

B2.1.1 Alloy 600 Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-11

B2.1.2 ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program - - - - - - - - B-17

B2.1.3 Bolting Integrity Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-25

B2.1.4 Boric Acid Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - - - - B-32

B2.1.5 Buried Services Corrosion Monitoring Program - - - - - - - - - - - - - - - - - - - B-37

B2.1.6 Closed Cycle Cooling Water Program- - - - - - - - - - - - - - - - - - - - - - - - B-41

B2.1.7 Containment Inservice Inspection Program - - - - - - - - - - - - - - - - - - - - - B-49

B2.1.8 Containment Leakage Testing Program - - - - - - - - - - - - - - - - - - - - - - - B-58

B2.1.9 Diesel Fuel Monitoring and Storage Program - - - - - - - - - - - - - - - - - - - - B-65

B2.1.10 Fire Protection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-71

B2.1.11 Flow Accelerated Corrosion Program - - - - - - - - - - - - - - - - - - - - - - - - B-81

B2.1.12 Non-EQ Electrical Commodities Condition Monitoring Program - - - - - - - - - - - B-87

B2.1.13 One-Time Inspection Program - - - - - - - - - - - - - - - - - - - - - - - - - - - B-97

B2.1.14 Open Cycle Cooling Water Program - - - - - - - - - - - - - - - - - - - - - - - - B-107

B2.1.15 Overhead Load Handling Systems Inspection Program - - - - - - - - - - - - - - - B-114

B2.1.16 Reactor Vessel Integrity Surveillance Program - - - - - - - - - - - - - - - - - - - B-119

B2.1.17 Reactor Vessel Internals Inspection Program - - - - - - - - - - - - - - - - - - - - B-126

B2.1.18 Steam Generator Tube Integrity Program - - - - - - - - - - - - - - - - - - - - - - B-131

B2.1.19 Structural Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - B-136

B2.1.20 System Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-145

B2.1.21 Water Chemistry Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-152

APPENDIX B

Contents
 Palisades Nuclear Plant

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Appendix B - Aging Management Programs

Page B-iii 

B3.0 Time Limited Aging Analyses Management Programs- - - - - - - - - - - - - - - - - - - B-159

B3.1 Electrical Equipment Qualification Program- - - - - - - - - - - - - - - - - - - - - - - - - - B-159

B3.2 Fatigue Monitoring Program - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-163

Appendix B References - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - B-171
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Appendix B - Aging Management Programs

B1.0 Appendix B Introduction

B1.1 Overview

This appendix provides aging management program descriptions for each Palisades 

program credited for managing aging effects based upon the aging management review 

results provided in Sections 3.1 through 3.6. Many of the programs have already been 

implemented in some form at Palisades, although, often under another program name, or as 

groups of individual activities. To facilitate NRC review, many existing activities have been 

realigned within the program organization described herein. For License Renewal 

Purposes, a program is considered an existing program if the types of activities it manages 

are, for the most part, already in place, even though its title, organization, or scope has 

differed from those described in NUREG-1801.

Each of the new or existing aging management programs presented in this section has been 

evaluated for consistency with the ten elements described in the applicable Section X or XI 

of NUREG-1801. Evaluation results are provided for each program to indicate whether the 

element is consistent with, or consistent with exceptions, to the assumptions made in that 

program’s description in NUREG-1801. In addition, for new or existing plant-specific 

programs that are not addressed in NUREG-1801, a discussion is provided to show how the 

program conforms with the ten elements described in NUREG-1800, Appendix A.1, “Aging 

Management Review - Generic,” Table A.1-1, “Elements of an Aging Management Program 

for License Renewal,” (SRP-LR).

Program enhancements are identified for some of the existing programs that will bring the 

programs into conformance with NUREG-1801. Each program in this appendix is described 

as if the identified enhancements have been implemented. Enhancements are discussed 

one time in the enhancement section of each program description, and are not repeated in 

the individual element discussions. New programs will not list specific enhancements, per 

se.

Each NUREG-1801 program description is considered to include the minimum features of 

the program that have been found by NRC to effectively manage aging of the SSC of 

interest. In some cases, Palisades takes exception to certain aspects of a program 

description provided in NUREG-1801. An exception to NUREG-1801 exists when a program 

feature described in NUREG-1801 is not implemented within the Palisades program. When 

the Palisades program includes additional features, or is applied to a wider scope of SSC, 

that go beyond the description in NUREG-1801, this is not considered an exception. 

Exceptions are typically taken if a NUREG-1801 program feature is not practical to 

implement at Palisades, or if NUREG-1801 program items are unnecessary to effectively 

manage aging of the plant-specific SSC for which the program is credited. 
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Appendix B - Aging Management Programs

Inservice inspection code relief requests that have been approved by NRC are not 

considered exceptions to NUREG-1801, and are not listed in this application. The NRC has 

already reviewed the requests in accordance with existing regulations, and concluded that 

they are acceptable interpretations of, or deviations from, the code requirements applicable 

to the current inspection interval. When a new inspection code of record is adopted at the 

beginning of each subsequent inspection interval, in accordance with 10 CFR 50.55a, all 

relief requests that are applicable to the new interval must be reviewed and approved by the 

NRC at that time. This process is independent from license renewal requirements under 10 

CFR 54, and is unrelated to the term of the operating license.

It should also be noted that if a Palisades program is fully consistent with NUREG-1801, but 

is based on a different revision (usually later) of a code or standard referenced in the 

NUREG-1801 program description, the program is not considered to have an exception to 

NUREG-1801. A number of the codes and standards referenced in NUREG-1801 have 

been superseded by later revisions since NUREG-1801 was written. Adoption of updated 

codes or standards for plant programs occurs frequently as the state of knowledge 

advances in the nuclear industry, and updates are sometimes mandated by NRC’s own 

requirements. Therefore, differences in reference codes or standards, between a Palisades 

program and the applicable description in NUREG-1801, are not, in themselves, considered 

to be exceptions to NUREG-1801. 

Method of Discussion

For existing or new aging management programs that are addressed in Sections X or XI of 

NUREG-1801, each program discussion is presented in the following format:

• A Program Description abstract of the overall program form and function is provided.

• A NUREG-1801 Consistency statement is made about the program.

• Exceptions to the NUREG-1801 program are outlined and a justification is provided, 

when applicable. 

For those aging management programs that are plant-specific (i.e., not in NUREG 1801), 

there will be no exceptions listed since there is no applicable NUREG-1801 reference 

standard for the program.

• Enhancements to each existing program are identified. These enhancements include 

changes initiated to achieve consistency with NUREG-1801, as well as changes to 

incorporate additional features needed for effective aging management of components 

which credit the program (e.g., manage aging for certain components or aging effects not 

assumed in NUREG-1801). Except when otherwise noted in an individual program 

discussion, enhancements are scheduled to be implemented prior to the period of 

extended operation. Note that the listed enhancements are defined at an overall program 
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Appendix B - Aging Management Programs

level, and do not include various administrative and editorial changes planned for the 

implementing documents and activity schedules.

Since new programs are, by definition, yet to be implemented, specific features that will 

be incorporated into the programs will not be listed as enhancements. The only 

“enhancement” that will be identified for any new program will be to develop and 

implement the new program as described in this section. 

• A discussion of the ten elements is provided for each program. Comparisons are made 

to, and consistency evaluated for, each NUREG-1801 or NUREG-1800 program element, 

as applicable. 

• A Conclusion Section provides a statement of reasonable assurance that the program, as 

described, will be effective.

B1.2 Quality Assurance Program and Administrative Controls

The Palisades Quality Program is described in the topical report, Quality Program 

Description for Nuclear Power Plants (Part 2) - Palisades Nuclear Plant (Reference 3). This 

NRC-approved program implements the requirements of 10 CFR 50, Appendix B, and is 

consistent with the summary in Appendix A.2 of NUREG-1800 (Reference 1).The Quality 

Program includes the Aging Management Program elements of corrective action, 

confirmation process and administrative controls.

The Quality Program implementation procedures will be expanded to apply the elements of 

corrective action, confirmation process, and administrative controls to both safety related 

and non-safety related systems, structures, and components that are subject to aging 

management review for license renewal.

Generically, these three elements will be applicable as follows:

Corrective Actions:

Corrective actions are implemented in accordance with the requirements of 10 CFR 50, 

Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing 

Plants” (Reference 4), and the NRC approved Quality Program Description for Nuclear 

Power Plants (Part 2) - Palisades Nuclear Plant (Reference 3). Controls are established to 

assure that conditions adverse to quality are identified and documented and that 

appropriate remedial action is taken. For significant conditions adverse to quality, necessary 

corrective action is promptly determined and recorded. Corrective action includes 

determining the cause and extent of the condition, and taking appropriate action to preclude 

similar problems in the future. The controls also assure that corrective action is 

implemented in a timely manner.
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Corrective actions are implemented through the initiation of an Action Request in 

accordance with plant procedures. Equipment deficiencies may be initially documented by a 

work order, but the corrective action process specifies that an Action Request also be 

initiated if required. This approach ensures that identified problems are corrected in a timely 

manner.

Confirmation Process:

The confirmation process is part of the corrective action program, which is implemented in 

accordance with the requirements of 10 CFR 50, Appendix B, “Quality Assurance Criteria 

for Nuclear Power Plants and Fuel Reprocessing Plants” (Reference 4), and the NRC 

approved Quality Program Description for Nuclear Power Plants (Part 2) - Palisades 

Nuclear Plant (Reference 3). The aging management activities required by this program 

would also uncover any unsatisfactory condition due to ineffective corrective action.

Administrative Procedures include provisions for identification, evaluation, assignment, 

tracking, monitoring, reviewing, verifying, and approving corrective actions, to ensure 

effective corrective actions are taken. The Corrective Action Process is also monitored for 

potentially adverse trends. The existence of an adverse trend due to recurring or repetitive 

adverse conditions is required to be documented in an Action Request. The post 

maintenance testing procedure includes provisions for verifying the completion and 

effectiveness of corrective actions for equipment deficiencies, establishes criteria for the 

selection and documentation of post-maintenance tests, and provides guidelines to ensure 

equipment will perform its intended function prior to return to service, and to ensure the 

original equipment deficiency is corrected and a new deficiency has not been created. 

Administrative Controls:

Plant programs are implemented through a variety of procedures and other documents. 

These implementing documents are subject to administrative controls, including a formal 

review and approval process, in accordance with the requirements of 10 CFR 50, Appendix 

B, “Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants” 

(Reference 4), and the NRC approved Quality Program Description for Nuclear Power 

Plants (Part 2) - Palisades Nuclear Plant (Reference 3). 

Administrative procedures provide guidance on procedures and other forms of 

administrative control documents. Uniform guidelines and requirements are provided for 

preparing, revising, reviewing and approving procedures. Usage and adherence 

requirements are also defined for plant procedures. 
Page B-5 

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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

B1.3 Operating Experience

Industry operating experience was incorporated into the License Renewal process through 

a review of industry documents to identify aging effects and mechanisms that could 

challenge the intended function of structures and components within the scope of License 

Renewal. Review of plant-specific operating experience (corrective actions, maintenance 

history, etc.) was also performed to identify significant aging effects previously experienced 

by the plant, and significant issues that were considered relevant to program performance. 

The results of these searches were provided as inputs to both the aging management 

review process and development of the aging management programs. The OE applicable to 

each aging management program is discussed in this section as a part of each aging 

management program discussion.

It should be noted that a new program will not have OE that can be used to assess 

effectiveness of the program, since the program has not yet established a performance 

record. OE is still included in new program discussions, but only to indicate the types of 

issues that were considered relevant to the design of the new program.

B1.4 Aging Management Programs

The following aging management programs are described in the sections listed in this 

appendix. The programs are either generic in nature (i.e., similar features apply to multiple 

plants, including Palisades) as discussed in NUREG-1801, or are plant-specific (i.e., 

features are unique to Palisades). Plant-specific programs are listed near the end of the 

table in Section B2.0. All generic programs are identified in this section as either fully 

consistent with the program description provided in NUREG-1801, or as consistent except 

for certain identified exceptions that are listed. 

1. Alloy 600 Inspection Program [Section B2.1.1]

2. ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program [Section B2.1.2] 

3. Bolting Integrity Program [Section B2.1.3] 

4. Boric Acid Corrosion Program [Section B2.1.4] 

5. Buried Services Corrosion Monitoring Program [Section B2.1.5] 

6. Closed Cycle Cooling Water Program [Section B2.1.6] 

7. Containment Inservice Inspection Program [Section B2.1.7] 

8. Containment Leakage Testing Program [Section B2.1.8]
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Appendix B - Aging Management Programs

9. Diesel Fuel Monitoring and Storage Program [Section B2.1.9] 

10. Fire Protection Program [Section B2.1.10] 

11. Flow Accelerated Corrosion Program [Section B2.1.11] 

12. Non-EQ Electrical Commodities Condition Monitoring Program [Section B2.1.12] 

13. One-Time Inspection Program [Section B2.1.13]

14. Open Cycle Cooling Water Program [Section B2.1.14] 

15. Overhead Load Handling Systems Inspection Program [Section B2.1.15]

16. Reactor Vessel Integrity Surveillance Program [Section B2.1.16] 

17. Reactor Vessel Internals Inspection Program [Section B2.1.17] 

18. Steam Generator Tube Integrity Program [Section B2.1.18] 

19. Structural Monitoring Program [Section B2.1.19] 

20. System Monitoring Program [Section B2.1.20] 

21. Water Chemistry Program [Section B2.1.21]

B1.5 Time Limited Aging Analyses Management Programs: 

1. Electrical Equipment Qualification Program [Section B3.1]

2. Fatigue Monitoring Program [Section B3.2] 
Page B-7 

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Appendix B - Aging Management Programs

B2.0 Aging Management Programs

Correlations between NUREG-1801 (Generic Aging Lessons Learned (GALL)) programs and 

Palisades’ programs are shown below. For the Palisades Programs, links to appropriate sections of 

this appendix are provided.

NUREG1801 ID

NUMBER

NUREG-1801 PROGRAM TITLE PALISADES AGING MANAGEMENT 

PROGRAM

Chapter XI Programs

XI.M1 ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, & IWD

ASME Section XI IWB, IWC, IWD, IWF 

Inservice Inspection Program [Section 

B2.1.2]

XI.M2 Water Chemistry Water Chemistry Program 

[Section B2.1.21]

XI.M3 Reactor Head Closure Studs ASME Section XI IWB, IWC, IWD, IWF 

Inservice Inspection Program [Section 

B2.1.2]

XI.M4 BWR Vessel ID Attachment Welds Not Applicable. PNP is a PWR.

XI.M5 BWR Feedwater Nozzle Not Applicable. PNP is a PWR.

XI.M6 BWR Control Rod Drive Return Line 

Nozzle

Not Applicable. PNP is a PWR.

XI.M7 BWR Stress Corrosion Cracking Not Applicable. PNP is a PWR.

XI.M8 BWR Penetrations Not Applicable. PNP is a PWR.

XI.M9 BWR Vessel Internals Not Applicable. PNP is a PWR.

XI.M10 Boric Acid Corrosion Boric Acid Corrosion Program 

[Section B2.1.4]

XI.M11 Nickel-Alloy Nozzles and Penetrations Alloy 600 Program 

[Section B2.1.1]

XI.M12 Thermal Aging Embrittlement of Cast 

Austenitic Stainless Steel (CASS)

Not applicable. Palisades does not 

have CASS piping. CASS valves and 

pump casings are managed as indicated in Section [Section B2.1.2].

XI.M13 Thermal Aging and Neutron Irradiation 

Embrittlement of Cast Austenitic Stainless Steel (CASS)

Not Applicable. Palisades does not 

have CASS reactor vessel internals.
Page B-8 

Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

XI.M14 Loose Part Monitoring Not credited for aging management

XI.M15 Neutron Noise Monitoring Not credited for aging management

XI.M16 PWR Vessel Internals Reactor Vessel Internals Inspection 

Program 

[Section B2.1.17]

XI.M17 Flow-Accelerated Corrosion Flow Accelerated Corrosion Program 

[Section B2.1.11] 

XI.M18 Bolting Integrity Bolting Integrity Program 

[Section B2.1.3]

XI.M19 Steam Generator Tube Integrity Steam Generator Tube Integrity Program 

[Section B2.1.18]

XI.M20 Open-Cycle Cooling Water System Open Cycle Cooling Water Program 

[Section B2.1.14]

XI.M21 Closed-Cycle Cooling Water System Closed Cycle Cooling Water Program 

[Section B2.1.6]

XI.M22 Boraflex Monitoring Not Credited for Aging Management

XI.M23 Inspection of Overhead Heavy Load and 

Light Load (Related to Refueling) Handling Systems

Overhead Load Handling Systems 

Inspection Program 

[Section B2.1.15]

XI.M24 Compressed Air Monitoring Not credited for aging management.

XI.M25 BWR Reactor Water Cleanup System Not Applicable. Palisades is a PWR.

XI.M26 Fire Protection Fire Protection Program

[Section B2.1.10]

XI.M27 Fire Water System Fire Protection Program

[Section B2.1.10]

XI.M28 Buried Piping and Tanks Surveillance Not credited for aging management. 

XI.M29 Aboveground Carbon Steel Tanks System Monitoring Program 

[Section B2.1.20] 

One-Time Inspection Program 

[Section B2.1.13]

NUREG1801 ID

NUMBER

NUREG-1801 PROGRAM TITLE PALISADES AGING MANAGEMENT 

PROGRAM
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Appendix B - Aging Management Programs

XI.M30 Fuel Oil Chemistry Diesel Fuel Monitoring and Storage 

Program 

[Section B2.1.9]

XI.M31 Reactor Vessel Surveillance Reactor Vessel Integrity Surveillance 

Program 

[Section B2.1.16]

XI.M32 One-Time Inspection One-Time Inspection Program 

[Section B2.1.13]

XI.M33 Selective Leaching of Materials One-Time Inspection Program 

[Section B2.1.13]

XI.M34 Buried Piping and Tanks Inspection Buried Services Corrosion Monitoring 

Program 

[Section B2.1.5]

XI.S1 ASME Section XI, Subsection IWE Containment Inservice Inspection 

Program 

[Section B2.1.7]

XI.S2 ASME Section XI, Subsection IWL Containment Inservice Inspection 

Program 

[Section B2.1.7]

XI.S3 ASME Section XI, Subsection IWF ASME Section XI IWB, IWC, IWD, IWF 

Inservice Inspection Program 

[Section B2.1.2]

XI.S4 10 CFR 50, Appendix J Containment Leakage Testing Program 

[Section B2.1.8]

XI.S5 Masonry Wall Program Structural Monitoring Program 

[Section B2.1.19]

XI.S6 Structures Monitoring Program Structural Monitoring Program

[Section B2.1.19]

XI.S7 RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear 

Power Plants

Structural Monitoring Program

[Section B2.1.19]

XI.S8 Protective Coating Monitoring and Maintenance ProgramNot credited for aging management.

NUREG1801 ID

NUMBER

NUREG-1801 PROGRAM TITLE PALISADES AGING MANAGEMENT 

PROGRAM
Page B-10 

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Appendix B - Aging Management Programs

XI.E1 Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Non-EQ Electrical Commodities Condition Monitoring Program 

[Section B2.1.12]

XI.E2 Electrical Cables Not Subject to 10 CFR 

50.49 Environmental Qualification 

Requirements Used in Instrumentation 

Circuits

Non-EQ Electrical Commodities Condition Monitoring Program

[Section B2.1.12]

XI.E3 Inaccessible Medium Voltage Cables Not 

Subject to 10 CFR 50.49 Environmental 

Qualification Requirements

Non-EQ Electrical Commodities Condition Monitoring Program 

[Section B2.1.12]

Chapter X Programs

X.M1 Metal Fatigue of Reactor Coolant Pressure BoundaryFatigue Monitoring Program 

[Section B3.2]

X.S1 Concrete Containment Tendon Prestress Containment Inservice Inspection Program 

[Section B2.1.7]

X.E1 Environmental Qualification (EQ) of Electrical ComponentsElectrical Equipment Qualification Program 

[Section B3.1]

Plant-Specific Programs

NA NA System Monitoring Program

[Section B2.1.20]

NUREG1801 ID

NUMBER

NUREG-1801 PROGRAM TITLE PALISADES AGING MANAGEMENT 

PROGRAM
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Appendix B - Aging Management Programs

B2.1 Aging Management Programs Details

B2.1.1 Alloy 600 Program 

Program Description

The Alloy 600 Program is an existing program that manages aging due to PWSCC of the 

Primary Coolant System (PCS) pressure boundary Alloy 600 components, including 

Inconel 82/182 weld joints, reactor vessel head penetrations, etc. The program includes 

(a) PWSCC susceptibility assessment using industry models to identify susceptible 

components, (b) monitoring and control of primary coolant chemistry to mitigate PWSCC, 

(c) in-service inspections (ISI) of pressurizer penetrations, reactor vessel head 

penetrations and Alloy 82/182 PCS pressure boundary welds in accordance with ASME 

Section XI, Subsection IWB, Table IWB-2500-1, and (d) augmented inspections or 

preemptive repair/replacement of susceptible components or welds.

NUREG-1801 references a long-term inspection program for the vessel head 

penetrations based on the industry responses to NRC GL 97-01. Subsequent to issuance 

of NUREG-1801, events at another nuclear plant triggered establishment of new 

regulatory requirements that superseded NRC GL 97-01 for reactor pressure vessel head 

and penetration nozzle inspections. Palisades is committed to the revised NRC Order 

EA-03-009 (Reference 5). Because these new regulatory requirements were issued after 

NUREG-1801 was published, this is not considered an exception to NUREG-1801.

It is noted that the Palisades Section XI ISI Program is currently following ASME Section 

XI, in accordance with applicable provisions and requirements of 10 CFR 50.55a, while 

NUREG-1801, Section XI.M11, references the 1995 Edition through the 1996 Addenda. 

The ASME Section XI ISI edition and addenda in effect at any time will be those required 

by 10 CFR 50.55a. Therefore, the edition and addenda on which the Palisades program 

is based are not considered exceptions to NUREG-1801.

NUREG-1801 Consistency

The Alloy 600 Program is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”

Exceptions to NUREG-1801

None.

Enhancements

None. 
Page B-12 

Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

Aging Management Program Elements

The key elements, which are used in the Alloy 600 Program, are described below. The 

results of an evaluation of each key element against NUREG-1801, Section XI.M11, 

“Nickel-Alloy Nozzles and Penetrations,” are also provided below.

Scope of Program

All Alloy 600 components and Alloy 82/182 welds that are part of the Primary 

Coolant pressure boundary are within the scope of the Alloy 600 Program, and 

include the following:

• CRDM nozzles

• Reactor vessel and vessel head mounted instrumentation penetrations

• Pressurizer nozzles and penetrations

• Reactor Coolant System piping penetrations and nozzles

• Steam Generator penetrations (Steam Generator U-tubes are Alloy 600, and 

are managed by the Steam Generator Tube Integrity Program)

This program credits the ASME Section XI IWB, IWC, IWD, IWF Inservice 

Inspection Program for the performance of required inservice inspections in 

accordance with ASME Section XI, Subsection IWB, Table IWB-2500-1. This 

program also credits the Water Chemistry Program for monitoring and control of 

primary coolant water chemistry in accordance with EPRI guideline TR-105714 

to mitigate PWSCC.

Palisades has 251 Alloy 600 penetrations, all of which are contained within the 

Primary Coolant System (PCS). As a result of Alloy 600 cracking issues 

associated with the pressurizer power-operated relief valve (PORV) nozzle, a 

project was initiated in 1993 to identify and rank all Alloy 600 penetrations 

contained within the PCS. This project ranked all 251 Alloy 600 penetrations 

based on four main criteria: primary water stress corrosion cracking (PWSCC) 

susceptibility, failure consequence, leakage detection margin, and radiation 

dose rates. 

The susceptibility of all Alloy 600 components and Alloy 82/182 welds was 

evaluated. On February 11, 2003, the NRC issued Order EA-03-009 to 

licensees operating PWRs, and revised the Order on February 20, 2004 

(Reference 5) which NMC consented to on March 8, 2004 (Reference 6). The 

Order established a minimum set of reactor vessel head inspections based on 

susceptibility categories. Palisades’ long-term inspection requirements are 
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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

based on the revised NRC Order EA-03-009 and the March 8, 2004 NMC 

response.

On May 28, 2004, the NRC issued Bulletin 2004-01, “Inspections of Alloy 

82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and 

Steam Space Piping Connections at Pressurized-Water reactors” requiring bare 

metal inspections of pressurizer heater sleeve locations and steam space piping 

connections and NDE if visual inspections indicate evidence of leakage. 

Palisades’ long-term inspection requirements for these components are based 

on the NMC response to that bulletin dated July 26, 2004.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.” 

Preventive Actions

The Alloy 600 Program is a condition monitoring program and there are no 

preventive actions associated with this program. However, this program credits 

the Water Chemistry Program for monitoring and control of primary coolant 

water chemistry to mitigate PWSCC.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”

Parameters Monitored, Inspected, and/or Tested

The Alloy 600 Program monitors the effects of PWSCC on the intended function 

of the Alloy 600 reactor vessel head penetrations by detection and sizing of 

cracks and detection of coolant leakage with the implementation of the Inservice 

Inspection Program as modified by the revised NRC Order EA-03-009.

Additionally, Palisades is committed to pressurizer and other primary coolant 

pressure boundary Alloy 600 penetration inspection requirements as discussed 

in the NMC response to Bulletin 2004-01 dated July 26, 2004.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”

Detection of Aging Effects

The Palisades Alloy 600 Program includes a variety of inspection and testing 

activities that are designed to detect degradation due to aging effects prior to 

loss of intended function. 

Inspections are based on the requirements prescribed by the revised NRC 

Order EA-03-009 and Bulletin 2004-01 rather than the model referenced in the 
Page B-14 

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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

GL 97-01 industry response. This also includes the susceptibility assessment, 

program, scope, and schedule. Inspections consist of periodic visual and NDE 

examinations and pressure tests, that are capable of detecting cracks and 

leakage before the loss of intended function of the components.

Palisades is committed to following the requirements of NRC Order EA-03-009, 

which supersedes GL 97-01 requirements for leakage detection. Therefore, the 

“leakage detection system” referred to in the NUREG-1801 program, and 

attributed to GL 97-01, is satisfied by the visual inspections of Order EA-03-009.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”

Monitoring and Trending

Periodic reactor vessel head inspections, including examination schedule, 

scope expansion, and comparison of previous examination results, are 

performed per the requirements of revised NRC Order EA-03-009. Periodic 

pressurizer heater sleeve connections and primary coolant pressure boundary 

penetration inspections are performed per the requirements of NRC Bulletin 

2004-01. Following completion of bare metal reactor vessel head, pressurizer, 

and primary coolant pressure boundary penetration inspections, all boric acid 

deposits, staining, or scaling is cleaned down to bare metal prior to installation of 

insulation. This provides assurance that any deposits discovered during reactor 

vessel head visual examinations resulted from leakage that occurred since the 

previous visual examination.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”

Acceptance Criteria

Indications and non-conformances detected will be evaluated in accordance 

with ASME Section XI Program requirements and the ASME Section XI IWB, 

IWC, IWD, IWF Inservice Inspection Program. Any evidence of leakage noted 

during the reactor vessel head visual inspections are considered recordable 

indications requiring further evaluation and inspection, and are reportable to the 

NRC, in accordance with the revised NRC Order EA-03-009. 

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”
Page B-15 

Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Alloy 600 

Program at Palisades are evaluated. The Alloy 600 Program is augmented, as 

appropriate, if these evaluations show that program changes will enhance 

program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Alloy 600 Program issues are addressed in a timely manner and 

that age related deterioration of SSC within the scope of the Alloy 600 Program 

will be effectively managed throughout the license renewal period.

A review of the industry operating experience related to the Alloy 600 Program 

revealed instances where degradation of material has occurred as a result of 

PWSCC. The review also considered related issues which included degradation 

of PCS hot leg piping and nozzles, thermal sleeves and instrument nozzles, 

reactor vessel head nozzles, control rod drive mechanism and thermocouple 

nozzles and intrusion of demineralizer resins.

A review of the plant specific operating experience revealed four (4) instances 

where the Alloy 600 program has been instrumental in discovering material 

degradation. Degradation was discovered in the following items:

• Pressurizer Temperature Element Penetration

• Pressurizer Safe End

• CRD Nozzle penetration indications (2)

Two of the safe-ends on the primary coolant piping (12-inch, schedule 140 surge 

nozzle and 12-inch, schedule 140, shutdown cooling outlet nozzle) had MSIP 

(Mechanical Stress Improvement Process) applied to them in 1995. MSIP 

changes the residual stress patterns at these locations from tensile to 

compressive by plastically deforming the piping near the welds. The 

compressive residual stress is desired to help mitigate PWSCC.
Page B-16 

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Appendix B - Aging Management Programs

The first bare metal visual examination of the reactor vessel head to meet the 

requirements of NRC Order EA-09-003 was completed during the spring, 2003 

refueling outage, with results reported to the NRC. Qualified VT-2 examiners 

using direct visual techniques performed the examinations. Visual inspection 

was also performed to identify potential boric acid leaks from pressure retaining 

components from above the reactor vessel. Results found that there were no 

accumulations of boric acid in the vicinity of, and no leakage of boric acid 

through, any of the reactor vessel head penetrations. All visual examinations of 

the reactor vessel head penetrations had acceptable results. 

The first volumetric examinations performed in accordance with the revised 

NRC order EA-03-009 were completed during the fall, 2004 refueling outage. 

Results of the inspections identified two CRD nozzle penetrations showing 

indications that required repair. These repairs were completed during the 

outage.

In response to commitments made by Palisades to NRC Bulletin 2004-01, 

“Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer 

Penetrations and Steam Space Piping Connections at Pressurized-Water 

Reactors,” a bare metal visual examination of 100% of the pressurizer heater 

sleeve locations, including 360° around each sleeve, and 36 Alloy 82/182/600 

primary system pressure boundary locations, normally operated at greater than 

or equal to 350°F, was performed during the fall 2004 refueling outage. Results 

of the bare metal visual examination of each of the penetrations were reported 

to the NRC and were acceptable, with no accumulation of boric acid in the 

vicinity of any of the penetrations. 

The Palisades Alloy 600 Program has demonstrated that it provides reasonable 

assurance that aging effects are being adequately managed for Alloy 600 

materials. This has been demonstrated through NRC inspection reports, INPO 

evaluations, audits, self-assessments, and the Corrective Action Program. The 

Alloy 600 Program has been effective in identifying material degradation in a 

timely manner, thus ensuring that age related degradation of Alloy 600 materials 

will be effectively managed throughout the license renewal period.

This element is consistent with NUREG-1801, Section XI.M11, “Nickel-Alloy 

Nozzles and Penetrations.”
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Appendix B - Aging Management Programs

Conclusion

The Alloy 600 Program is an existing program that uses as its bases, various industry and 

NRC standards. This program is consistent with NUREG-1801, Section XI.M11, 

“Nickel-Alloy Nozzles and Penetrations.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Alloy 600 

Program has been effective in maintaining the intended functions of the affected 

long-lived, passive SSCs.

The continued implementation of the Alloy 600 Program provides reasonable assurance 

that aging effects will be managed such that SSCs within the scope of this program will 

continue to perform their intended functions consistent with the current licensing bases 

for the period of extended operation.

B2.1.2 ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program 

Program Description

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program is an existing 

program that facilitates inspections to identify and correct degradation in Class 1, 2, and 3 

piping, components, their supports and integral attachments. The program includes 

periodic visual, surface and/or volumetric examinations and leakage tests of all Class 1, 2 

and 3 pressure-retaining components, their supports and integral attachments, including 

welds, pump casings, valve bodies, pressure-retaining bolting, piping/component 

supports, and reactor head closure studs. These are identified in ASME Section XI, 

“Rules for Inservice Inspection of Nuclear Power Plant Components,” or commitments 

requiring augmented inservice inspections, and are within the scope of license renewal. 

This program is in accordance with 10 CFR 50.55a. 

The Code of Federal Regulations, 10 CFR 50.55a, requires that inservice inspection of 

Class 1, 2, and 3 pressure retaining components, their integral attachments and supports 

be conducted in accordance with the latest edition of ASME Section XI approved by the 

NRC twelve months prior to the start of a ten year interval. The ISI Program for Palisades’ 

third (3rd) ten year interval, which began on May 12, 1995, implements ASME Section XI 

in accordance with applicable provisions and requirements of 10 CFR 50.55a. The 

IWB-2500 Category B-Q requirements to perform volumetric examinations of steam 

generator tubes is addressed by the Steam Generator Tube Integrity Program.
Page B-18 

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Appendix B - Aging Management Programs

Class 1, 2 and 3 Component Supports

The examination scope provided by Table 2500-1 of Code Case N491-2 

specifies the percentage of supports that must be examined. As specified by 

Table 2500-1, VT-3 examinations are conducted to determine the general 

mechanical and structural condition of components and their supports by 

verifying parameters such as clearances, settings, and physical displacement, 

and to detect discontinuities and imperfections, such as loss of integrity of bolted 

or welded connections, loose or missing parts, debris, corrosion, wear, or 

erosion. Acceptance standards for supports are given by Code Case N491-2. 

Unacceptable conditions include:

• Deformation or structural degradation of fasteners, springs, clamps, or other 

support items;

• Missing, detached, or loosened support items;

• Arc strikes, weld spatter, paint, scoring, roughness, or general corrosion on 

close tolerance machined or sliding surfaces;

• Improper hot or cold positions of spring supports and constant load supports;

• Misalignment of supports; and 

• Improper clearances of guides and stops.

Class 1, 2 and 3 Pressure-Retaining Bolting

Nondestructive examination, repair and replacement of pressure retaining 

bolting are conducted as part of the ISI Program. Examination requirements are 

in accordance with ASME Section XI, Table IWB-2500-1 or IWC-2500-1. When 

Class 1, 2 and 3 bolting must be replaced as a result of degradation, ASME 

Section XI requirements for preservice examination are performed.

Reactor Vessel Head Closure Studs

Reactor vessel head closure studs are examined as required by Table 

IWB-2500-1, examination category B-G-1, “Pressure Retaining Bolting Greater 

than 2 inches in Diameter.” Volumetric examinations are performed using 

Performance Demonstration Initiative (PDI) techniques in accordance with 

ASME Section XI, Appendix VIII and 10 CFR 50.55a. Lubrication of the studs is 

controlled via maintenance procedures.
Page B-19 

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Appendix B - Aging Management Programs

NUREG-1801 Consistency

The ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program is consistent 

with the following sections of NUREG-1801:

• Section XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD”

• Section XI.M3, “Reactor Head Closure Studs”

• Section XI.S3, “ASME Section XI, Subsection IWF” 

Exceptions to NUREG-1801

None.

Enhancements

None.

Aging Management Program Elements

The key elements, which are used in the ASME Section XI IWB, IWC, IWD, IWF Inservice 

Inspection Program, are described below. The results of an evaluation of each key 

element against NUREG-1801, Section XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor Head Closure Studs,” and 

Section XI.S3, “ASME Section XI, Subsection IWF,” are also provided below.

Scope of Program

The ASME Section XI IWB, IWC, IWD and IWF Inservice Inspection Program 

implements the requirements for inservice inspection, repair, and replacement of 

ASME Class 1, 2, and 3 components, their integral attachments and supports, 

including all pressure retaining bolting. This program also includes the ISI of the 

reactor vessel closure studs and nuts, and includes the preventive measures of 

RG 1.65, “Material and Inspection for Reactor Vessel Closure Studs,” to mitigate 

cracking. Section XI provides rules for exempting components from volumetric 

or surface examinations and Federal Law allows the NRC to grant relief from 

specific portions of the code upon demonstrated need.

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.” 
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Appendix B - Aging Management Programs

Preventive Actions

There are no preventative actions associated with the ASME Section XI IWB, 

IWC, IWD and IWF Inservice Inspection Program. 

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” and Section XI.S3, 

“ASME Section XI, Subsection IWF.”

For the reactor vessel head closure studs, preventive measures include the use 

of manganese phosphate surface treatment and stable lubricants to mitigate 

degradation. This element is consistent with Section XI.M3, “Reactor Head 

Closure Studs.” 

Parameters Monitored, Inspected, and/or Tested

The ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program 

detects degradation of components by using the examination and inspection 

techniques of ASME Section XI.

Components with pressure retaining bolting are inspected for signs of leakage 

during pressure testing.

For piping and component supports, the parameters monitored or inspected 

include corrosion, deformation, misalignment, improper clearances, improper 

spring settings, damage to close tolerance machined or sliding surfaces, and 

missing, detached, or loosened support items. Component support bolting is 

inspected for indication of potential problems, including obvious signs of 

corrosion.

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.”

Detection of Aging Effects

The ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program 

includes a variety of inspection and testing activities that are designed to detect 

degradation due to aging effects prior to loss of intended function. 

The extent and schedule of the inspection and test techniques prescribed by the 

program are designed to maintain structural integrity and ensure that aging 

effects will be discovered and repaired before the loss of a component intended 

function. Inspection can reveal crack initiation and growth, loss of material due 

to corrosion, leakage of coolant, and indications of degradation caused by wear 
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Appendix B - Aging Management Programs

or stress relaxation, such as verification of clearances, settings, physical 

displacements, loose or missing parts, debris, wear, erosion, or loss of integrity 

at bolted or welded connections.

The program uses three types of examination; visual, surface, and volumetric in 

accordance with the general requirements of Subsection IWA-2000. Visual VT-1 

examination detects discontinuities and imperfections, such as cracks, 

corrosion, wear, or erosion, on the surface of components. Visual VT-2 

examination detects evidence of leakage from pressure retaining components, 

as required during the system pressure test. Visual VT-3 examination (a) 

determines the general mechanical and structural condition of components and 

their supports by verifying parameters, such as clearances, settings, and 

physical displacements; and (b) detects discontinuities and imperfections, such 

as loss of integrity at bolted or welded connections, loose or missing parts, 

debris, corrosion, wear, or erosion. Surface examination uses magnetic particle, 

liquid penetrant, or eddy current examinations to indicate the presence of 

surface discontinuities and flaws. Volumetric examination uses radiographic, 

ultrasonic, or eddy current examinations to indicate the presence of 

discontinuities or flaws throughout the volume of material.

The ISI Program for the 3rd Inspection Interval meets the requirements of ASME 

Section XI, in accordance with applicable provisions and requirements of 10 

CFR 50.55a. These include visual VT-2 examination of all pressure retaining 

components during the system leakage test. The Palisades ISI Program 

specifies performance of the system leakage test once per refueling outage or 

each period for these examination categories, whichever applies.

Examination requirements for Class 1, 2 and 3 pressure retaining bolting are in 

accordance with ASME Section XI, Table IWB-2500-1 or IWC-2500-1. For Class 

1 components, Table IWB-2500-1, examination category B-G-1, for bolting 

greater than 2 inches in diameter, specifies volumetric examination of studs and 

bolts and visual VT-1 examination of surfaces of nuts, washers, bushings, and 

flanges. Examination category B-G-2, for bolting 2 inches or smaller requires 

only visual VT-1 examination of surfaces of bolts, studs, and nuts. For Class 2 

components, Table IWC-2500-1, examination category C-D, for bolting greater 

than 2 inches in diameter, requires volumetric examination of studs and bolts. 

Examination Categories B-P and C-H, require VT-2 visual examination 

(IWA-5240) during system leakage testing of all pressure retaining Class 1 and 

2 components, according to Tables IWB-2500-1 and IWC-2500-1 respectively. 

The extent and schedule of inspections, in accordance with Tables IWB-2500-1 
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Appendix B - Aging Management Programs

and IWC-2500-1 ensure detection of aging degradation before the loss of the 

intended function of the closure bolting.

Reactor vessel head closure studs are examined as required by Table 

IWB-2500-1, examination category B-G-1, “Pressure Retaining Bolting Greater 

than 2 inches in Diameter.” Volumetric examinations are performed using 

Performance Demonstration Initiative (PDI) techniques in accordance with 

ASME Section XI, Appendix VIII and 10 CFR 50.55a.

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.”

Monitoring and Trending

The examination schedules contained in the Palisades ISI Program meet the 

requirements of ASME Section XI, IWB-2412, IWC-2412, and IWD-2412, 

respectively (Inspection Program B). The Palisades' ISI Program also meets the 

requirements for the extent and frequency of examinations specified by ASME 

Section XI, IWB-2500-1, IWC-2500-1, and IWD-2500-1.

In some cases, an evaluation in accordance with ASME Section XI, IWB-3100 

or IWC-3100, may be used to qualify a component with flaw indications as 

acceptable for continued service. In such cases, the areas containing such flaw 

indications and relevant conditions are reexamined during the next three 

inspection periods of IWB-2410 for Class 1 components and for the next 

inspection period of IWC-2410 for Class 2 components. Examinations that 

reveal indications that exceed the acceptance standards are extended to include 

additional examinations in accordance with ASME Section XI, IWB-2430 or 

IWC-2430 for Class 1 or 2 components, respectively. The Palisades ISI Program 

meets ASME Section XI with respect to inspection schedules, extent, method, 

and frequency of examination, flaw evaluations, and additional examinations.

For reactor vessel head closure studs, the inspection schedule of IWB-2400, 

and the extent and frequency specified in Table IWB-2500-1 provide timely 

detection of stud and nut degradation. 

For piping and component support inspections, unacceptable conditions, as 

described in Code Case N-491-2 Section 3400, are noted for correction or 

further evaluation.
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This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.”

Acceptance Criteria

Indications or relevant conditions that are not removed by repair, replacement, 

or surface conditioning, where necessary, are evaluated in accordance with 

IWB-3000, IWC-3000, or IWD-3000 for Class 1, 2, or 3 components, 

respectively. Examination results are evaluated in accordance with IWB-3100 or 

IWC-3100 by comparing the results with the acceptance standards of IWB-3400 

and IWB-3500 or IWC-3400 and IWC-3500 for Class 1 or Class 2 and 3 

components, respectively. In rare cases, flaws exceeding the size of allowable 

flaws, as defined in IWB-3500 or IWC-3500, may be evaluated by using the 

analytical procedures of IWB-3600 or IWC-3600.

For reactor vessel head closure studs and Class 1 bolting, degradation is 

evaluated in accordance with IWB-3100 and the acceptance standards of 

IWB-3400 and IWB-3500.

The program for component supports utilizes the acceptance standards for 

visual examination specified in ASME Code Case N491-2, Section 3400. 

Discovery of unacceptable conditions that require corrective action triggers an 

expansion of the inspection scope in accordance with the code case. 

Reexamination of supports requiring corrective actions or acceptance by 

evaluation shall be performed during the next inspection period, in accordance 

with the code case. 

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 
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Appendix B - Aging Management Programs

whether external or plant specific, that are potentially significant to the ASME 

Section XI ISI Program at Palisades are evaluated. The ASME Section XI ISI 

Program is augmented, as appropriate, if these evaluations show that program 

changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that ASME Section XI ISI Program issues are addressed in a timely 

manner and that age related deterioration of SSC within the scope of the ASME 

Section XI ISI Program will be effectively managed throughout the license 

renewal period.

A review of the industry operating experience related to the ASME Section XI, 

Inservice Inspection (ISI) Aging Management Program revealed numerous 

instances where degradation of components, component supports, and bolting 

has occurred. In completing our review we looked at related issues which 

included stress corrosion cracking (SCC) and crack initiation and growth due to 

thermal loading.

A review of the plant specific operating experience revealed thirteen (13) 

instances where the ISI program has been instrumental in discovering 

degradation. Degradation was discovered in the following items:

• Control Rod Drive Housings

• Piping Welds

• Component Supports

• Bolting

• Temperature Element Penetration

• Reactor Coolant Pressurizer Safe End

• Engineered Safeguards Systems Check Valve

The Palisades ISI Aging Management Program has demonstrated on several 

occasions that it provides reasonable assurance that aging effects are being 

adequately managed for Class 1, 2, and 3 components, component supports, 

and bolting. This has been demonstrated through NRC inspection reports, INPO 

evaluations, audits, self-assessments, and the Corrective Action Program.

This element is consistent with NUREG-1801, Section XI.M1, “ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD,” Section XI.M3, “Reactor 

Head Closure Studs,” and Section XI.S3, “ASME Section XI, Subsection IWF.”
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Appendix B - Aging Management Programs

Conclusion

The ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program is an existing 

program that uses as its bases, various industry and NRC standards. This program is 

consistent with NUREG-1801, Section XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD.” This program is also consistent with NUREG-1801, 

Section XI.M3, “Reactor Head Closure Studs,” and Section XI.S3, “ASME Section XI, 

Subsection IWF.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the ASME Section 

XI ISI Program has been effective in maintaining the intended functions of the affected 

long-lived, passive SSCs.

The continued implementation of the ASME Section XI ISI Program provides reasonable 

assurance that aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.

B2.1.3 Bolting Integrity Program

Program Description

The Bolting Integrity Program is an existing program that manages the aging effects 

associated with bolting through the performance of periodic inspections. The program 

also includes repair/replacement controls for ASME Section XI related bolting and generic 

guidance regarding material selection, thread lubrication and assembly of bolted joints. 

The program considers the guidelines delineated in NUREG-1339 for a bolting integrity 

program, EPRI NP-5769 (with the exceptions noted in NUREG-1339) for safety related 

bolting, and EPRI TR-104213 for non-safety related bolting. 

The Bolting Integrity Program has been created to permit direct comparison with 

NUREG-1801. The program is considered to be an existing program since most of the 

activities addressed by the program are already being performed. The program credits 

activities performed under three separate aging management programs for the inspection 

of bolting. The three aging management programs are: (1) ASME Section XI IWB, IWC, 

IWD, IWF Inservice Inspection Program, (2) Structural Monitoring Program, and (3) 

System Monitoring Program.
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Appendix B - Aging Management Programs

The scope of the credited programs for bolting is summarized below.

• The ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program provides 

the requirements for inservice inspection of ASME Class 1, 2, and 3 piping, 

supports, and their integral attachments, which includes pressure retaining and 

support bolting. This program specifically discusses the inspection and lubrication of 

the reactor vessel head closure studs. The program supplements the ASME Section 

XI (Code Case N491-2), Subsection IWF requirements, by applying the inspection 

requirements of Subsection IWB, Category B-G-1 to high yield strength (>150 ksi) 

bolting used in Nuclear Steam Supply System (NSSS) component supports.

• The System Monitoring Program provides the requirements for the inspection of 

non-safety related bolting within the scope of license renewal. 

• The Structural Monitoring Program provides the requirements for the inspection of all 

structural bolting within the scope of license renewal. Other bolting and fasteners are 

also included within the scope of this program, such as those used in supports for 

cable trays, conduits and cabinet supports.

NUREG-1801 states that, “It is noted that hot torquing of bolting is a leak preventive 

measure once the joint is brought to operating temperature and before or after it is 

pressurized.” The attributes of the Palisades Bolting Integrity Program are adequate to 

manage loss of preload without hot torquing. Therefore, hot torquing to establish a 

pre-load will not be credited for aging management of bolting. 

NUREG-1801 Consistency

The Bolting Integrity Program is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Exceptions to NUREG-1801

None

Enhancements

Two enhancements are planned to bring the Bolting Integrity Program into conformance 

with the NUREG-1801 program description. The enhancements are:

Review and revise ASME ISI Master Plan, procedures that implement credited License 

Renewal Programs, and plant maintenance procedures to reflect and reference the 

applicable guidance provided in NUREG-1339 and EPRI TR-104213 for safety and 

non-safety related bolting. These revisions should also include instructions for selection 

of bolting material and use of lubricants and sealants, in accordance with the guidelines 
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Appendix B - Aging Management Programs

of EPRI NP-5769 and the additional recommendations of NUREG-1339 to prevent or 

mitigate degradation and failure of safety-related bolting.

Evaluate the high strength bolting used for component supports for susceptibility to 

cracking as described in NUREG-1801, Section XI.M.18, “Parameters 

Monitored/Inspected,” and implement appropriate inspection requirements to provide 

adequate age-management for these bolts. This is to be completed prior to the end of the 

current operating license.

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for completion 

prior to the period of extended operation.

Aging Management Program Elements

The key elements of the Bolting Integrity Program are described below. The results of an 

evaluation of each key element against the corresponding element of NUREG-1801, 

Section XI.M18, “Bolting Integrity,” are also provided.

Scope of Program

The program covers all bolting and fasteners within the scope of license 

renewal, including safety related bolting, bolting for NSSS component supports, 

bolting for other pressure retaining components, and structural bolting. The 

Bolting Integrity Program manages the aging effects associated with bolting 

through the performance of periodic inspections. The program also includes 

repair/replacement controls for ASME Section XI related bolting and generic 

guidance regarding thread lubrication and assembly of bolted flanges. The 

program considers the guidelines delineated in NUREG-1339 for a bolting 

integrity program, EPRI NP-5769 (with the exceptions noted in NUREG-1339) 

for safety related bolting, and EPRI TR-104213 for non-safety related bolting. 

The Bolting Integrity Program credits three separate aging management 

programs for the inspection of bolting.

NUREG-1801 implies conformance with the recommendations of NUREG-1339, 

EPRI NP-5769, and EPRI TR-104213 concerning material selection and testing, 

preload control, inservice inspection, plant operation and maintenance, and 

evaluation of structural integrity. NUREG-1339 documents the resolution of 

Generic Safety Issue 29 related to bolting degradation or failure in nuclear 

power plants. NUREG-1339 relies on the industry technical findings presented 

in EPRI NP-5769 as the basis for resolution of the generic safety issue. EPRI 

NP-5769 is a broadly scoped document intended to resolve the generic safety 
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Appendix B - Aging Management Programs

issue and was formatted in a manner to aid the utility engineer in addressing 

bolting problems. EPRI TR-104213 was developed with the intention of 

providing a consolidated source of generic technical information pertaining to 

the design, assembly, inspection, trouble shooting, and repair of bolted joints. 

EPRI TR-104213 also includes recommendations for the selection, 

specification, and procurement of threaded fasteners. 

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Preventive Actions

The use of lubricants and sealants is in accordance with plant guidelines, which 

generally meet the recommendations of EPRI NP-5769 and NUREG-1339. 

Replacement of bolting in ASME Section XI components is performed in 

accordance with the plant's repair and replacement program. Replacement of 

other bolting is like-for-like or evaluated on a case-by-case basis in accordance 

with the applicable monitoring program identified in the program description 

above.

Palisades normal maintenance practices and quality verification procedures for 

pressure retaining bolting includes a check of bolt torque and uniformity of 

gasket compression, when applicable. 

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Parameters Monitored, Inspected, and/or Tested

The program monitors aging effects such as loss of material, cracking, and loss 

of mechanical closure integrity. The specific parameters monitored or inspected 

are discussed in the three credited programs and include inspection of high yield 

strength (>150 ksi) bolting for NSSS component supports for cracking, pressure 

retaining bolted joints for signs of leakage, and structural bolting for signs of 

aging degradation.

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Detection of Aging Effects

The Palisades Bolting Integrity Program includes a variety of inspection and 

testing activities that are designed to detect degradation due to aging effects 

prior to loss of intended function.
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Appendix B - Aging Management Programs

Examination and inspection of ASME Section XI Class 1, 2, and MC bolting is 

performed as specified in Tables IWB-2500-1, IWC-2500-1, and IWE-2500-1 

with guidance from the recommendations of EPRI NP-5769. The tables specify 

the extent of the examination, schedule, and methodology. Information on 

exemptions from examination requirements are described in the ASME Section 

XI IWB, IWC, IWD, IWF Inservice Inspection Program.

The program uses two types of examination: visual, and volumetric. Visual VT-1 

examination detects discontinuities and imperfections such as cracks, erosion, 

wear, corrosion, or physical damage on the surface of the bolting. Visual VT-2 

examination detects evidence of leakage from pressure retaining components 

as a result of bolting degradation. Volumetric examinations detects the presence 

of discontinuities or flaws throughout the volume of the bolting. This program 

establishes an augmented inspection requirement for all high strength bolting 

(Actual Yield Strength >150 ksi.) used in NSSS component supports by applying 

the requirements of Examination Category B-G-1.

Structural bolting and fasteners both inside and outside containment are 

inspected by visual examination in accordance with the Structural Monitoring 

Program.

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Monitoring and Trending

Examination schedules contained in the Palisades ISI programs meet the 

requirements of ASME Section XI, Subsections IWB, IWC, and IWE for Class 1, 

2, and MC pressure retaining bolting. Examination schedules also meet the 

requirements of ASME Section XI, Code Case N491-2 for Class 1, 2, and 3 

component support bolting. If bolting for pressure retaining components not 

covered by ASME Section XI is reported to be leaking, the bolting will be 

addressed in accordance with the System Monitoring Program and the 

Palisades Action Request Process. Corrective Actions may include monitoring 

and trending of leakage on a daily, weekly, or biweekly basis.

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.” 

Acceptance Criteria

Indications are evaluated in accordance with IWB-3000, IWC-3000, and 

IWE-3000 for Class 1, 2, and MC pressure retaining bolting, respectively. Class 
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Appendix B - Aging Management Programs

1, 2, 3, and MC component support bolting is evaluated in accordance with the 

acceptance standards of ASME Code Case N491-2, Section 3410. All other 

bolting is evaluated in accordance with the requirements of the applicable 

monitoring program identified in the Program Description above.

Indications of cracking in component support bolting, or leaks at bolted joints of 

pressure retaining components are evaluated and repaired if the degradation 

may cause a loss of intended function or cause adverse effects, such as 

corrosion or contamination.

NUREG-1801 states that “immediate” repairs be done for major leaks that may 

cause corrosion or contamination. The Palisades Bolting Integrity Program 

makes no distinction regarding “immediate” repairs, but instead relies upon the 

plant inservice inspection program and corrective action process to evaluate, 

prioritize and schedule repairs. NUREG-1801 states that, “As discussed in the 

appendix to this report, the staff finds the requirements of 10 CFR Part 50, 

Appendix B, acceptable in addressing corrective actions.” Therefore, Palisades 

meets the intent of this NUREG-1801 element.

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Bolting 

Integrity Program at Palisades are evaluated. The Bolting Integrity Program is 

augmented, as appropriate, if these evaluations show that program changes will 

enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Bolting Integrity Program issues are addressed in a timely manner 

and that age related deterioration of SSC within the scope of the Bolting Integrity 

Program will be effectively managed throughout the license renewal period with 

the guidance and recommendation from EPRI NP-5769 and TR-104213.
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Appendix B - Aging Management Programs

A review of the industry operating experience related to the Bolting Integrity 

Program revealed numerous instances where degradation of bolting has 

occurred. In completing our review we looked at related issues which included 

degradation of threaded fasteners due to stress corrosion cracking and fatigue 

loading, plus stress corrosion cracking in high strength bolts used for NSSS 

component supports.

A review of the plant specific operating experience revealed six (6) instances 

where the ISI program has been instrumental in discovering bolting degradation.

Degradation was discovered in the following items:

• Piping Flange Bolts (1)

• Pump Studs (2)

• Tank Flange Bolts (1)

• Pipe Support Bolting (1)

• ESS Equipment Bolting (1)

The Bolting Integrity Program has been effective in identifying bolting 

degradation in a timely manner, thus ensuring that age related degradation of 

bolting will be effectively managed throughout the license renewal period.

This element is consistent with NUREG-1801, Section XI.M18, “Bolting 

Integrity.”

Conclusion

The Bolting Integrity Program is an existing program that uses as its bases, various 

industry and NRC standards. This program is consistent with NUREG-1801, Section 

XI.M18, “Bolting Integrity.” 

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Bolting Integrity 

Program has been effective in maintaining the intended functions of the affected 

long-lived, passive SSCs.

The continued implementation of the Bolting Integrity Program provides reasonable 

assurance that aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.
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Appendix B - Aging Management Programs

B2.1.4 Boric Acid Corrosion Program

Program Description

The Palisades Boric Acid Corrosion Program is an existing program that monitors 

component degradation due to boric acid leakage through the performance of periodic 

inspections. It implements the recommendations of NRC Generic Letter 88-05. The 

program requires periodic visual inspection of all systems within the scope of license 

renewal that contain borated water for evidence of leakage, accumulations of dried boric 

acid, or boric acid wastage. The program also provides for visual inspections and early 

discovery of borated water leaks such that structures, electrical and mechanical 

components that may be contacted by leaking borated water will not be adversely 

affected such that their intended functions are impaired. 

Specifically, the Boric Acid Corrosion Program includes provisions for: 

a. Identification of components exhibiting boric acid accumulations or leakage

b. Evaluation of the acceptability for continued service of components exhibiting boric 

acid accumulations or leakage

c. Trending and tracking of previously identified leaks or boric acid accumulations

d. Corrective actions per plant technical specifications, FSAR and administrative 

procedures

As part of the Boric Acid Corrosion Program, Palisades monitors operating experience 

relating to boric acid leaks and takes appropriate corrective actions. Thus, by conducting 

visual inspections, locating the source of the leaks when they are discovered, performing 

engineering evaluations, and reviewing internal and external operating experience, the 

program ensures that SSC within the scope of license renewal will continue to perform 

their intended functions. 

NUREG-1801 Consistency

The Boric Acid Corrosion Program is consistent with NUREG-1801, Section XI.M10, 

“Boric Acid Corrosion.”

Exceptions to NUREG-1801

None.
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Appendix B - Aging Management Programs

Enhancements

Three enhancements are planned to bring the Boric Acid Corrosion Program into 

conformance with the NUREG-1801 program elements. The enhancements are:

Detection of Aging Effects: Revise applicable plant procedures to include criteria for 

observing susceptible SSC, within the scope of license renewal, for boric acid leakage 

and degradation, during system walkdown inspections. 

Acceptance Criteria: Revise applicable plant procedure(s) to include explicit acceptance 

criteria for boric acid inspections.

Detection of Aging Effects: Revise applicable plant procedures to include inspection of 

structural steel and non-ASME component supports for evidence of boric acid residue 

and boric acid wastage/corrosion on a periodic frequency.

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for 

implementation prior to the period of extended operation.

Aging Management Program Elements

The key elements of the Boric Acid Corrosion Program are described below. The results 

of an evaluation of each key element against the corresponding element of 

NUREG-1801, Section XI.M10, “Boric Acid Corrosion,” are also provided. 

Scope of Program

The Boric Acid Corrosion Program includes structures or components, and 

electrical connectors within the scope of license renewal, which borated water 

may leak from or on. The program adheres to NRC Generic Letter 88-05. It 

includes (a) identification of the leakage source, (b) evaluations of the 

acceptability for continued service of components exhibiting boric acid 

accumulations or leakage (c) trending of boric acid leaks using the Palisades 

corrective action system and work request, work order system, and (d) 

corrective actions in accordance with Plant Technical Specifications, FSAR and 

administrative procedures. This will ensure that boric acid corrosion does not 

lead to degradation of the leakage source or adjacent structures or components, 

which could cause the loss of intended function of the structures or components.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.”
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Appendix B - Aging Management Programs

Preventive Actions

Preventive actions include improving maintenance practices such as revising 

the valve packing program to improve packing design and techniques, 

performance of periodic walkdowns to identify those components that may 

require corrective maintenance, and monitoring of locations where potential 

leakage could occur. Timely repair of detected leakage prevents or mitigates 

boric acid corrosion, and is accomplished through the corrective action process. 

Electrical connectors are inspected on a periodic frequency for signs of boric 

acid residue and degradation per plant procedures.

Borated water spills or pooled water on concrete floors can cause corrosion of 

structural steel, rebar, and equipment floor mounted supports. These are 

identified in a timely manner through frequent operator rounds, and various 

building walkdowns/inspections. Any leaks that are identified are evaluated and 

dispositioned in accordance with plant procedures. Borated water spills and 

pooled water on concrete floors is cleaned up when identified, in accordance 

with the standards set forth in plant procedures, to prevent degradation of 

structural components.

This program credits the System Monitoring Program for periodic walkdowns 

and inspections for signs of boric acid leakage, residue or degradation.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.” 

Parameters Monitored, Inspected, and/or Tested

Visual inspections are conducted to monitor the effects of boric acid corrosion 

on the intended function(s) of an affected structure or component. Borated water 

leakage results in deposit of white boric acid crystals and presence of moisture 

that can be observed by visual inspections during system walkdowns.

This program credits the System Monitoring Program for periodic walkdowns 

and inspections for signs of boric acid leakage, residue or degradation.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.” 

Detection of Aging Effects

The Palisades Boric Acid Corrosion Program includes visual inspections 

performed in conjunction with ISI Section XI pressure testing activities that are 

designed to detect degradation due to aging effects prior to loss of intended 
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Appendix B - Aging Management Programs

function. Degradation of components due to boric acid corrosion cannot occur 

without borated water leakage. Visual inspections and primary coolant pressure 

boundary leakage tests are conducted to identify necessary repairs and 

minimize the potential of a leak not being discovered and developing into a 

larger leak. Guidelines for detecting small leaks by visual inspections are 

utilized, and engineering evaluations are conducted when leaks are detected. 

Post maintenance inspections are conducted to verify that repairs were properly 

performed. Therefore, the Boric Acid Corrosion Program, which follows the 

guidelines of NRC GL 88-05, will assure the detection of leakage before a loss 

of intended function(s).

Electrical connectors are inspected on a periodic frequency for signs of boric 

acid residue and degradation per plant procedure. 

This program also credits the System Monitoring Program for the visual 

inspection of other SSC outside the primary coolant pressure boundary that may 

be subject to the degrading effects of any borated water leakage.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.” 

Monitoring and Trending

This program relies on visual inspections conducted both during normal plant 

operation and when the plant is shutdown for refueling. The program follows the 

guidelines in NRC GL 88-05 and provides for timely detection of leakage by 

observance of boric acid crystal deposits during plant walkdowns and 

maintenance.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.”

Acceptance Criteria

Plant procedures establish acceptance criteria and require corrective action or 

further evaluation if any leakage or boric acid residue is noted. 

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.” 

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.
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Appendix B - Aging Management Programs

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Boric 

Acid Corrosion Program at Palisades are evaluated. The Boric Acid Corrosion 

Program is augmented, as appropriate, if these evaluations show that program 

changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Boric Acid Corrosion Program issues are addressed in a timely 

manner and that age related deterioration of SSC within the scope of the Boric 

Acid Corrosion Program will be effectively managed throughout the license 

renewal period.

A review of industry operating experience associated with the Boric Acid 

Corrosion Program and aging revealed issues related to:

• Boric acid wastage of reactor coolant system piping and nozzles

• Boric acid corrosion of reactor vessel head and closure studs from leaking 

borated water

• Failure of valve packing gland bolts due to boric acid wastage

• Failure of valve body to bonnet studs/nuts due to boric acid wastage

• Boric acid wastage of reactor coolant pump closure flange studs

• Boric acid corrosion of steam generator manway closure studs

• Boric acid corrosion of high pressure safety injection pump casing

These issues were addressed in various NRC and industry communications, 

which have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Boric Acid 

Corrosion Program and aging revealed that the following issues had been 

addressed:

• Boric acid leaks in the containment spray header in containment at flanges 

with carbon steel bolting and a threaded spray nozzle connection

• Boric acid wastage of primary coolant pump studs

• Boric acid wastage of manual valve body-to-bonnet bolts
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Appendix B - Aging Management Programs

• Corrosion of flanges for primary coolant pump component cooling water 

connections due to external boric acid leakage

Recent assessments have shown that the Boric Acid Corrosion Program 

provides reasonable assurance that aging effects are being managed for Boric 

Acid Corrosion Program SSCs. This has been demonstrated through NRC 

inspection reports, audits, self-assessments, and the Corrective Action 

Program.

This element is consistent with NUREG-1801, Section XI.M10, “Boric Acid 

Corrosion.” 

Conclusion

The Boric Acid Corrosion Program is an existing program that uses as its bases, various 

industry and NRC standards, including GL 88-05. This program is consistent with 

NUREG-1801, Section XI.M10, “Boric Acid Corrosion.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Boric Acid 

Corrosion Program has been effective in maintaining the intended functions of the 

affected long-lived, passive SSCs.

The continued implementation of the Boric Acid Corrosion Program provides reasonable 

assurance that aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.

B2.1.5 Buried Services Corrosion Monitoring Program

Program Description

The Buried Services Corrosion Monitoring Program is a new program that manages 

aging effects on the external surfaces of carbon steel, low-alloy steel, and stainless steel 

components that are buried in soil or sand. This program includes (a) visual inspections 

of external surfaces of buried components for evidence of coating damage and substrate 

degradation to manage the effects of aging, (b) visual inspection of the external surfaces 

of buried stainless steel components for evidence of crevice corrosion, pitting, and MIC. 

The periodicity of these inspections for carbon, low-alloy, and stainless steel will be based 

on opportunities for inspection such as scheduled maintenance work.

Age-related degradation of buried components susceptible to selective leaching is 

managed by the One-Time Inspection Program.
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Appendix B - Aging Management Programs

NUREG-1801 Consistency

The Buried Services Corrosion Monitoring Program is consistent with NUREG1801, 

Section XI.M34, “Buried Piping and Tanks Inspection.”

Exceptions to NUREG-1801

None.

Enhancements

A Buried Services Corrosion Monitoring Program will be developed and implemented. 

Features of the program will include development and implementation of procedures for 

inspection of selected buried SSCs for corrosion, pitting and MIC. The periodicity of these 

inspections will be based on opportunities for inspection such as scheduled excavation 

and maintenance work.

Note that the element descriptions describe the program as it will exist after the program 

has been implemented. The program is scheduled to be implemented prior to the period 

of extended operation. 

Aging Management Program Elements

The key elements of the Buried Services Corrosion Monitoring Program are described 

below. The results of an evaluation of each key element against NUREG-1801, Section 

XI.M34, “Buried Piping and Tank Inspection,” are also provided below.

Scope of Program

The scope of this program addresses buried components that are within the 

scope of License Renewal. The program relies on preventive measures, such as 

coating and wrapping, and periodic inspection for loss of material caused by 

corrosion of the external surface of buried carbon, low alloy, and stainless steel 

piping and components. Palisades has no buried tanks in sand or soil. Loss of 

materials in these components, which may be exposed to a soil or sand 

environment, is caused by general, pitting, crevice corrosion, and 

microbiologically influenced corrosion (MIC). The periodicity of inspections for 

carbon, low-alloy, and stainless steel to detect degradation due to these aging 

mechanisms will be based on opportunities for inspection such as scheduled 

maintenance work.

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”
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Appendix B - Aging Management Programs

Preventive Actions

Buried components, except for stainless steel, are coated per industry practice 

prior to installation in order to protect the component outer surfaces from 

corrosion. The buried pipe specifications for Palisades Nuclear Plant required 

coating and wrapping in accordance with AWWA C203. The coatings include a 

primer, coal tar enamel, asbestos mat, coal tar enamel, paper wrap layered 

system that finishes at approximately 3/16” thickness.

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”

Parameters Monitored, Inspected, and/or Tested

The program monitors parameters such as coating and wrapping integrity that 

are directly related to loss of material due to corrosion on the external surfaces 

of buried carbon steel, and low alloy steel components. Coatings and wrappings 

are visually inspected when access becomes available. Any evidence of 

damage to the coating or wrapping, such as coating perforation, holidays, or 

other damage will cause the protected components to be inspected for evidence 

of loss of material. If no evidence of damage to the coating or wrapping is 

detected, then the coating or wrapping will not be removed for further inspection. 

Buried stainless steel components are typically not coated, and the outer 

surface is visually inspected for evidence of crevice corrosion, pitting, and MIC. 

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”

Detection of Aging Effects

The Palisades Buried Services Corrosion Monitoring Program includes 

inspection activities that are designed to detect degradation due to aging effects 

prior to loss of intended function. Visual inspections of buried carbon, low-alloy, 

and stainless steel components will be performed based on plant operating 

experience and when components are excavated for maintenance or any other 

reason. 

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”

Monitoring and Trending

The results of previous inspections will be evaluated, and used to assess the 

condition of the external surfaces of other buried carbon, low-alloy, and stainless 
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Appendix B - Aging Management Programs

steel components, and to identify susceptible locations that warrant further 

inspections.

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”

Acceptance Criteria

Any coating and wrapping degradations, or components identified with 

significant corrosion, will be documented and evaluated under the corrective 

action program, which includes provisions for a root cause analysis, if 

appropriate.

This element is consistent with NUREG-1801, Section XI.M34, “Buried Piping 

and Tanks Inspection.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Buried 

Services Corrosion Monitoring Program at Palisades are evaluated. The Buried 

Services Corrosion Monitoring Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Buried Services Corrosion Monitoring Program issues are 

addressed in a timely manner and that age related deterioration of SSC's within 

the scope of the Buried Services Corrosion Monitoring Program will be 

effectively managed throughout the license renewal period.

A review of industry operating experience applicable to aging of buried services 

reveals issues related to Diesel fuel line leakage from the absence of required 

coating leading to corrosion. None of the industry operating issues or instances 

reflect any new program issues attributed to exterior corrosion to buried services 

component materials.
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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

A review of plant specific operating experience related to the Buried Services 

Corrosion Monitoring Program and aging revealed that the following issues have 

been addressed:

• Through wall leak in buried steam line.

• Generic program deficiencies from internal Engineering Programs audit.

• See the Fire Protection Program for OE related to buried fire main ruptures.

None of the plant operating issues or instances resulted from normal aging, or 

reflect significant program deficiencies.

This element is consistent with the portions of NUREG-1801, Section XI.M34, 

“Buried Piping and Tanks Inspection,” that are applicable to SSC's that are 

buried in soil or sand.

Conclusion

The Buried Services Corrosion Monitoring Program is a new program that uses as its 

bases, various industry and NRC standards. This program is consistent with 

NUREG-1801, Section XI.M34, “Buried Piping and Tanks Inspection.”

Implementation of the Buried Services Corrosion Monitoring Program provides 

reasonable assurance that aging effects will be managed such that SSC's within the 

scope of this program will continue to perform their intended functions consistent with the 

current licensing bases for the period of extended operation.

B2.1.6 Closed Cycle Cooling Water Program

Program Description

The Closed Cycle Cooling Water Program is an existing program that manages aging 

effects in closed cycle cooling water systems that are not subject to significant sources of 

contamination, in which water chemistry is controlled and heat is not directly rejected to 

the ultimate heat sink. The program includes (a) maintenance of system corrosion 

inhibitor concentrations to minimize degradation, and (b) periodic or one-time testing and 

inspections to assess SSC aging.

The program scope includes activities to manage aging in the Component Cooling Water 

(CCS) System, Emergency Diesel Generator (EDG) Jacket Cooling Water (Emergency 

Power System), and Shield Cooling System (SCS). 

The program is based on requirements delineated in EPRI TR-107396, “Closed Cooling 

Water Chemistry Guideline,” and relies on mitigative measures to minimize corrosion 
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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

through the addition of corrosion inhibitors and maintenance of water chemistry within 

specified limits.

The program credits the One-Time Inspection Program for the inspection of selected 

Shield Cooling System and Emergency Diesel Generator system heat exchangers and a 

representative sample of stagnant portions of the system piping. The inspections will 

check for fouling and evidence of corrosion or cracking. Nondestructive examinations will 

be used, if practical and warranted, to verify pipe wall thickness at selected locations 

where loss of material has been experienced.

NUREG-1801 Consistency

The Closed Cycle Cooling Water Program is consistent with, but includes exceptions to, 

NUREG-1801, Section XI.M21, “Closed-Cycle Cooling Water System.”

Exceptions to NUREG-1801

Exceptions are taken to the selected NUREG-1801 Program elements listed below. The 

specific exceptions being taken are also discussed in the corresponding element 

discussions below. They are repeated here for ease of review.

1. Parameters Monitored, Tested and/or Inspected, Monitoring and Trending, and 

Acceptance Criteria: NUREG-1801, Section XI.M21.3, states that, “For pumps, the 

parameters monitored include flow and discharge and suction pressures. For heat 

exchangers, the parameters monitored include flow, inlet and outlet temperatures, 

and differential pressure.” Palisades does not credit active flow testing for managing 

age-related degradation of CCCW components. However, performance of selected 

heat exchangers is monitored in accordance with the Master Heat Exchanger 

Testing Plan. The performance and operability testing of selected pumps, including 

flow, suction and discharge pressure, is monitored in accordance with ASME 

Section XI, Subsection IWP, Inservice Testing Program. This is generally in 

accordance with the position taken by Fort Calhoun Station and V.C. Summer 

Nuclear Station in their license renewal applications, and accepted by the NRC in 

their respective Safety Evaluation Reports.

2. Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria: 

NUREG-1801 states “The extent and schedule of inspections and testing in 

accordance with EPRI TR-107396, assure detection of corrosion before the loss of 

intended function on the component. Performance and functional testing in 

accordance with EPRI TR-107396 ensures acceptable functional testing of the 

CCCW System or components serviced by the CCCW System.” Palisades does not 

credit active performance and functional testing for managing age-related 
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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

degradation of CCCW components. However, performance of selected heat 

exchangers is monitored in accordance with the Master Heat Exchanger Testing 

Plan. The performance and operability testing of selected pumps, including flow, 

suction and discharge pressure, is monitored in accordance with ASME Section XI, 

Subsection IWP, Inservice Testing Program. This is generally in accordance with the 

position taken by Fort Calhoun Station, and V.C. Summer Nuclear Station, and 

accepted by the NRC in their respective Safety Evaluation Reports.

Enhancements

None.

Aging Management Program Elements

The key elements, which are used in the Closed Cycle Cooling Water Program, are 

described below. The results of an evaluation of each key element against NUREG-1801, 

Section XI.M21, “Closed-Cycle Cooling Water System,” are also provided below.

Scope of Program

The Closed Cycle Cooling Water Program pertains to closed systems that are 

not subject to significant sources of contamination, in which the water chemistry 

is controlled, monitored, and kept within specified limits, and in which the heat is 

not directly rejected to the ultimate heat sink. The program is applicable to the 

Component Cooling Water System, EDG Jacket Cooling Water, and the Shield 

Cooling System. 

This element is consistent with NUREG-1801, Section XI.M21, “Closed-Cycle 

Cooling Water System.”

Preventive Actions

The program relies on the use of appropriate materials and a water treatment 

program, including corrosion inhibitors to inhibit general, crevice, and pitting 

corrosion. Sodium nitrite and tolyltriazole (TTA) are used for carbon steel and 

copper corrosion control. Applicable chemistry procedures include provisions for 

monitoring CCCW Systems water chemistry and adding chemicals as 

necessary to maintain chemistry parameters within limits. These procedures, as 

well as the administrative limits for corrosion inhibitors sodium nitrite and TTA, 

are based on the requirements and guidelines in EPRI TR-107396. 

This element is consistent with NUREG-1801, Section XI.M21, “Closed-Cycle 

Cooling Water System.”
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Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

Parameters Monitored, Tested, and/or Inspected

Heat exchangers are inspected in accordance with plant procedures. Included in 

this program for selected heat exchangers is Eddy Current Testing and/or tube 

side/shell side inspections prior to, and following tube cleaning, an inspection of 

channels, covers and welds, and an exterior bundle and shell interior inspection, 

if accessible, by the program or system engineer. 

This element is consistent with, but includes an exception to, NUREG-1801, 

Section XI.M21, “Closed-Cycle Cooling Water System.” The exception is:

• NUREG-1801, Section XI.M21.3 states that, “For pumps, the parameters 

monitored include flow and discharge and suction pressures. For heat 

exchangers, the parameters monitored include flow, inlet and outlet 

temperatures, and differential pressure.” Palisades does not credit active 

flow testing for managing age-related degradation of CCCW components. 

However, performance of selected heat exchangers is monitored in 

accordance with the Master Heat Exchanger Testing Plan. The performance 

and operability testing of selected pumps, including flow, suction and 

discharge pressure, is monitored in accordance with ASME Section XI, 

Subsection IWP, Inservice Testing Program. This is generally in accordance 

with the position taken by Fort Calhoun Station and V.C. Summer Nuclear 

Station in their license renewal applications, and accepted by the NRC in 

their respective Safety Evaluation Reports.

Detection of Aging Effects

The Palisades Closed Cycle Cooling Water Program includes a variety of 

inspection activities that are designed to detect degradation due to aging effects 

prior to loss of intended function. 

For the Shield Cooling system, Diesel Generator Jacket Water Cooling System, 

and the Component Cooling System piping inside containment, the One-Time 

Inspection Program is credited with the detection of corrosion in areas of 

stagnant flow conditions in the CCCW Systems. Periodic internal inspections of 

selected heat exchangers will provide indications of fouling and degradation. 

This element is consistent with, but includes an exception to, NUREG-1801, 

Section XI.M21, “Closed-Cycle Cooling Water System.” The exception is:

• NUREG-1801 states “The extent and schedule of inspections and testing in 

accordance with EPRI TR-107396, assure detection of corrosion before the 

loss of intended function on the component. Performance and functional 
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Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

testing in accordance with EPRI TR-107396, ensures acceptable functional 

testing of the CCCW System or components serviced by the CCCW 

System.” Palisades does not credit active performance and functional testing 

for managing age-related degradation of CCCW components. However, 

performance of selected heat exchangers is monitored in accordance with 

the Master Heat Exchanger Testing Plan. The performance and operability 

testing of selected pumps, including flow, suction and discharge pressure, is 

monitored in accordance with ASME Section XI, Subsection IWP, Inservice 

Testing Program. This is generally in accordance with the position taken by 

Fort Calhoun Station, and V.C. Summer Nuclear Station, and accepted by the 

NRC in their respective Safety Evaluation Reports.

Monitoring and Trending

Chemistry procedures provide for monitoring and analysis of the following 

chemistry parameters:

• Nitrite

• PH

• Conductivity

• Iron

• Copper

• Ammonia

• Tolyltriazole (TTA)

• Gamma Scan (CCS only)

• Microbiological Activity (Component Cooling & Emergency Diesel Generator 

Systems only)

Normal ranges for each parameter are identified, as well as administrative limits, 

sampling frequency, and corrective actions. Sampling frequencies are based on 

plant operating conditions and experience.

This element is consistent with, but includes exceptions to, the corresponding 

element of NUREG-1801, Section XI.M21, “Closed-Cycle Cooling Water 

System.” The exceptions include:

• NUREG-1801, Section XI.M21.3 states that, “For pumps, the parameters 

monitored include flow and discharge and suction pressures. For heat 

exchangers, the parameters monitored include flow, inlet and outlet 

temperatures, and differential pressure.” Palisades does not credit active 
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Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

flow testing for managing age-related degradation of CCCW components. 

However, performance of selected heat exchangers is monitored in 

accordance with the Master Heat Exchanger Testing Plan. The performance 

and operability testing of selected pumps, including flow, suction and 

discharge pressure, is monitored in accordance with ASME Section XI, 

Subsection IWP, Inservice Testing Program. This is generally in accordance 

with the position taken by Fort Calhoun Station, and V.C. Summer Nuclear 

Station, and accepted by the NRC in their respective Safety Evaluation 

Reports.

• NUREG-1801 states “The extent and schedule of inspections and testing in 

accordance with EPRI TR-107396, assure detection of corrosion before the 

loss of intended function on the component. Performance and functional 

testing in accordance with EPRI TR-107396, ensures acceptable functional 

testing of the CCCW System or components serviced by the CCCW 

System.” Palisades does not credit active performance and functional testing 

for managing age-related degradation of CCCW components. However, 

performance of selected heat exchangers is monitored in accordance with 

the Master Heat Exchanger Testing Plan. The performance and operability 

testing of selected pumps, including flow, suction and discharge pressure, is 

monitored in accordance with ASME Section XI, Subsection IWP, Inservice 

Testing Program. This is generally in accordance with the position taken by 

Fort Calhoun Station, and V.C. Summer Nuclear Station, and accepted by the 

NRC in their respective Safety Evaluation Reports.

Acceptance Criteria

Nitrite and Tolyltriazole concentrations are maintained within the limits specified 

in the EPRI water chemistry guidelines for Closed Cycle Cooling Water 

Systems. System and component performance test results are evaluated in 

accordance with plant procedures and system design parameters and functions.

This element is consistent with, but includes exceptions to, the corresponding 

element of NUREG-1801, Section XI.M21, “Closed-Cycle Cooling Water 

System.” The exceptions include:

• NUREG-1801, Section XI.M21.3 states that, “For pumps, the parameters 

monitored include flow and discharge and suction pressures. For heat 

exchangers, the parameters monitored include flow, inlet and outlet 

temperatures, and differential pressure.” Palisades does not credit active 

flow testing for managing age-related degradation of CCCW components. 
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Appendix B - Aging Management Programs

However, performance of selected heat exchangers is monitored in 

accordance with the Master Heat Exchanger Testing Plan. The performance 

and operability testing of selected pumps, including flow, suction and 

discharge pressure, is monitored in accordance with ASME Section XI, 

Subsection IWP, Inservice Testing Program. This is generally in accordance 

with the position taken by Fort Calhoun Station, and V.C. Summer Nuclear 

Station, and accepted by the NRC in their respective Safety Evaluation 

Reports.

• NUREG-1801 states “The extent and schedule of inspections and testing in 

accordance with EPRI TR-107396, assure detection of corrosion before the 

loss of intended function on the component. Performance and functional 

testing in accordance with EPRI TR-107396, ensures acceptable functional 

testing of the CCCW System or components serviced by the CCCW 

System.” Palisades does not credit active performance and functional testing 

for managing age-related degradation of CCCW components. However, 

performance of selected heat exchangers is monitored in accordance with 

the Master Heat Exchanger Testing Plan. The performance and operability 

testing of selected pumps, including flow, suction and discharge pressure, is 

monitored in accordance with ASME Section XI, Subsection IWP, Inservice 

Testing Program. This is generally in accordance with the position taken by 

Fort Calhoun Station, and V.C. Summer Nuclear Station, and accepted by the 

NRC in their respective Safety Evaluation Reports.

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses them for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Closed 

Cycle Cooling Water Program at Palisades are evaluated. The Closed Cycle 

Cooling Water Program is augmented, as appropriate, if these evaluations show 

that program changes are needed to enhance program effectiveness. 
Page B-48 

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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Closed Cycle Cooling Water Program issues are addressed in a 

timely manner and that age related deterioration of SSC within the scope of the 

Closed Cycle Cooling Water Program will be effectively managed throughout the 

license renewal period.

A review of industry operating experience associated with the Closed Cycle 

Cooling Water Program and aging reveals issues and instances related to:

• SCC in reactor coolant pump oil cooler discharge piping.

• Corroded solder connections in diesel lube oil cooler due to inadequate 

corrosion inhibitor

• Inoperable check valves (stuck open) due to corrosion product buildup

• Cracks in Component Cooling Water piping

• Fouling of diesel cooling water heat exchangers

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Closed Cycle 

Cooling Water Program and aging revealed that the following issues have been 

addressed:

• Tube blockage and fouling in Component Cooling Heat Exchanger

• Fuel Pool Heat Exchanger tube breakage due to high Component Cooling 

Water flow

• Through wall flaw in Spent Fuel Pool Cooling pipe

The Palisades Closed Cycle Cooling Water Program has demonstrated that it 

provides reasonable assurance that aging effects are being managed for Closed 

Cycle Cooling Water Program SSCs. Additionally, this has been demonstrated 

through NRC inspection reports, audits, self-assessments, and the Corrective 

Action Program.

This element is consistent with NUREG-1801, Section XI.M21, “Closed-Cycle 

Cooling Water System.”

Conclusion

The Closed Cycle Cooling Water Program is an existing program that uses as its bases, 

various industry and NRC standards. This program is consistent with, but includes 

exceptions to, NUREG-1801, Section XI.M21, “Closed-Cycle Cooling Water System.” A 
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Appendix B - Aging Management Programs

summary of each exception is provided in the discussion of the affected program element 

above.

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Closed Cycle 

Cooling Water Program has been effective in maintaining the intended functions of the 

affected long-lived, passive SSCs.

The continued implementation of the Closed Cycle Cooling Water Program provides 

reasonable assurance that aging effects will be managed such that SSCs within the 

scope of this program will continue to perform their intended functions consistent with the 

current licensing bases for the period of extended operation.

B2.1.7 Containment Inservice Inspection Program 

Program Description

The Containment Inservice Inspection (ISI) Program is an existing program that is 

designed to ensure that containment shell concrete, the post-tensioning system and steel 

pressure retaining elements continue to provide an acceptable level of structural integrity. 

In addition, it is designed to ensure that the liner (with associated moisture barriers), other 

leakage limiting steel barriers and pressure retaining bolted connections have not 

degraded. This program does not demonstrate actual containment leak tightness; that is 

done under the Containment Leakage Testing Program.

This Program incorporates, with some differences in code editions, elements of several 

applicable programs identified in NUREG-1801. These are as follows:

• XI.S1 - ASME Section XI, Sub-Section IWE

• XI.S2 - ASME Section XI, Sub-Section IWL

• X.S1 - Concrete Containment Tendon Prestress

NUREG-1801 Consistency

The Containment Inservice Inspection Program is consistent with NUREG-1801, Section 

XI.S1, “ASME Section XI, Subsection IWE,” Section XI.S2, “ASME Section XI, 

Subsection IWL,” and Section X.S1, “Concrete Containment Tendon Prestress.”

Exceptions to NUREG-1801

None. 
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Enhancements

XI.S1 ASME Section XI, Subsection IWE

None

XI.S2 ASME Section XI, Subsection IWL

None

X.S1 Concrete Containment Tendon Prestress

None

Aging Management Program Elements

The key elements, which are used in the Containment Inservice Inspection Program, are 

described below. The results of an evaluation of each key element against NUREG-1801, 

Section XI.S1, “ASME Section XI, Subsection IWE,” Section XI.S2, “ASME Section XI, 

Subsection IWL,” and Section X.S1, “Concrete Containment Tendon Prestress” are also 

provided below.

Scope of Program

Scope of Program - XI.S1 ASME Section XI, Subsection IWE

This part of the Palisades Containment ISI Program covers inspection of the 

steel pressure boundary and corresponds to the NUREG-1801 ASME Section 

XI, Sub-Section IWE, Program. This Program specifies visual examination of the 

entire accessible steel pressure boundary to uncover age related and other 

conditions that represent damage or deterioration. The steel pressure boundary 

includes: The liner with adjacent parts of integral structural attachments; 

mechanical penetration sleeves and transition pieces up to the Class 2 piping 

boundaries; electrical & spare penetration sleeves with closures; the fuel 

transfer tube & closure flange; the equipment hatch; air locks; and, pressure 

retaining bolting. The accessible part of the boundary is any surface that is not in 

contact with concrete or otherwise obstructed from view by plant structures and 

equipment.

The Palisades program follows the 1998 Code Edition (no addenda), which 

does not include a requirement to examine seals and gaskets. Seals and 

gaskets are almost entirely hidden from view by the mating flanges and cannot 

be meaningfully examined unless the flanged closure is opened or 

disassembled. Disassembly is not required by the 92 / 92 Code. As the 

continuing quality of seals and gaskets is verified by periodic leakage testing, 
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there is no need to require such examinations. This is not considered an 

exception to NUREG-1801.

Scope of Program - XI.S2 ASME Section XI, Subsection IWL

This part of the Palisades Containment ISI Program covers inspection of the 

post-tensioned concrete containment structure and corresponds to the 

NUREG-1801 ASME Section XI, Sub-Section IWL Program. 

The Containment ISI Program specifies visual examination of the entire 

accessible surface of the concrete structure, examination of all accessible 

tendon end anchorage areas and examination of and tests on a small sample of 

pre-stressing tendons. The accessible part of the concrete surface is that part 

not obstructed from view by foundation material, backfill, the liner and 

permanent plant structures and equipment.

Scope of Program - X.S1 Concrete Containment Tendon Prestress

The program addresses the assessment of Palisades' containment tendon wire 

prestressing forces. During the scheduled surveillances, the tendon prestress 

force is measured for a random sample of each tendon group. One tendon in 

each group is designated as the common tendon. The prestress force in the 

common tendon is measured during each surveillance and is used to establish 

the trend of prestress loss for the group. The trend of prestress force for each 

group is compared to the minimum required value to ensure that the prestress 

force will not fall below the minimum required value prior to the next scheduled 

inspection. 

This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Preventive Actions

The Containment Inservice Inspection Program is a condition monitoring 

program and there are no preventive actions associated with this program. As 

long as the tendon wire prestressing values are found to be within the 

acceptance criteria no actions are required. Maintaining the prestress above the 

minimum required value will ensure that the structural and functional adequacy 

of the containment are maintained.
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This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Parameters Monitored, Inspected, and/or Tested

Parameters Monitored, Inspected and/or Tested - XI.S1 ASME Section XI, 

Subsection IWE

The Palisades Containment ISI Program specifies a general visual examination 

to find evidence of age related and other conditions that represent damage to, or 

deterioration of, the steel pressure boundary and moisture barrier at the 

interface between the inner liner and the containment fill concrete. 

General and Detailed Visual Examination, as defined in the 1998 Code (no 

addenda), are further defined in the Palisades program to correspond to VT-3 

and VT-1 examinations as defined in the 92 / 92 Code. Therefore, the 

examination techniques used at the Palisades Plant are the same as those 

identified in NUREG-1801.

The examination categories identified in the Palisades program are those 

defined in the 98 Code (no addenda). The Palisades program categories 

effectively encompass NUREG-1801 categories. The differences between the 

examination categories listed in NUREG-1801 and those included in the 

Palisades program are also discussed below, and are a result of code editions 

called out in NUREG-1801 vs. Palisades’ approved program. These are not 

considered to be exceptions to NUREG-1801.

• Pressure retaining welds and pressure retaining dissimilar metal welds 

receive a General Visual Examination and not a VT-1 examination. This 

approach is consistent with 10 CFR 50.55a which (as noted in 

NUREG-1801) states that the weld examinations specified in the 92 / 92 

Code are optional.

• Neither the 98 Code (no addenda) nor the Palisades program requires seal 

and gasket examinations. As explained above, elimination of seal & gasket 

examination requirement does not impact the assessment of containment 

leak-tight integrity.

• Neither the 98 Code (no addenda) nor the Palisades program requires bolt 

torque tests. Elimination of torque tests does not impact the assessment of 

containment leak tight integrity.
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10 CFR 50, Appendix J tests are covered by the Containment Leakage Testing 

Program and are not specified in the Containment ISI Program except as 

post-repair activities. 

The containment steel pressure boundary serves primarily as a leakage limiting 

barrier. That part of the boundary not backed by concrete also functions as a 

structural pressure retaining boundary. The inspections and tests (if required) 

performed under the Containment ISI Program are designed to detect age 

related (and other) deterioration that could reduce the leak tightness and 

structural strength of this boundary.

Parameters Monitored, Inspected and/or Tested - XI.S2 ASME Section XI, 

Subsection IWL

The Palisades Containment ISI Program specifies a General Visual Examination 

of 100% of the accessible concrete surface, a Detailed Visual Examination of all 

accessible tendon end anchorage areas and a Detailed Visual Examination and 

tests on a small sample of randomly selected tendons. These examinations and 

tests are performed to find evidence of damage to, or deterioration of, the 

concrete structure and the post-tensioning system. 

Parameters Monitored, Inspected, and/or Tested - X.S1 Concrete Containment 

Tendon Prestress

The parameters monitored are the containment tendon wire prestressing forces 

in accordance with the requirements specified in Subsection IWL of Section XI 

of the ASME Code.

This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.” 

Detection of Aging Effects

The Palisades Containment Inservice Inspection Program includes a variety of 

examination and testing activities that are designed to detect degradation due to 

aging effects prior to loss of intended function.

Detection of Aging Effects - XI.S1 ASME Section XI, Subsection IWE

The Palisades Plant follows Inspection Program B which stipulates consecutive 

10 year ISI intervals, each divided (per Table IWE-2412-1) into 3 successive 

periods having nominal durations of 3, 4 and 3 years, respectively. The 

Palisades program requires a visual examination of 100% of the accessible 
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surfaces in each category during each inspection interval. These frequent, 

comprehensive examinations provide a high degree of assurance that age 

related deterioration will be detected long before it has a significant impact on 

either the structural or leak tight integrity of the containment. Areas that exhibit 

damage or deterioration must meet the requirements of IWE-3122, Acceptance. 

Detection of Aging Effects - XI.S2 ASME Section XI, Subsection IWL

Palisades performs containment concrete, tendon end anchorage and 

post-tensioning system inspections at 5 year intervals. The entire accessible 

concrete surface and all accessible tendon end anchorage areas are examined 

during each inspection. 

Detection of Aging Effects - X.S1 Concrete Containment Tendon Prestress

The loss of tendon wire prestressing forces is detected by performance of the 

tendon inspections and analyses conducted per plant procedures and 

surveillance tests.

This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Monitoring and Trending

Monitoring and Trending - XI.S1 ASME Section XI, Subsection IWE

All accessible surfaces are examined and monitored on a regular schedule per 

requirements of IWE - 2500.

The Palisades program requires augmented examination of areas that exhibit 

signs of significant damage or deterioration. Conditions in these areas are 

trended and corrective actions are scheduled as required to ensure that an 

acceptable level of containment integrity is maintained. Augmented 

examinations are ended, in accordance with 98 Code (no addenda) Table 

IWE-2500-1 / Category E-C, if there is no change in the monitored condition 

over the course of one inspection period. NUREG-1801 references the 92 / 92 

Code requirement, which requires that augmented examinations be continued 

over three consecutive periods.

The 98 Code (no addenda) requirement is reasonably conservative since any 

condition that remains stable over a three to four year period is not experiencing 

a significant rate of ongoing deterioration. Conditions that remain stable over 

one inspection period are either the result of a manufacturing defect, a 
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construction oversight, a singular incident or an earlier aggressive environment 

that has been corrected. Therefore, if there is no change in an observed 

condition over one inspection period, no benefit is gained by continuing 

augmented examination. This is not considered to be an exception to 

NUREG-1801.

Trending of observed conditions as prescribed in the Containment ISI Program 

ensures that age related deterioration of the steel pressure boundary is 

identified and controlled in timely manner throughout the license renewal period. 

Monitoring and Trending - XI.S2 ASME Section XI, Subsection IWL

The entire accessible concrete surface, all accessible tendon end anchorage 

areas, and selected tendons meeting the requirements of IWL 2520 are 

examined and, in the case of tendons, tested, to detect damage or degraded 

conditions. Unacceptable conditions are documented on action requests and 

are subject to engineering evaluation. The evaluation may require more frequent 

and detailed monitoring to determine if the observed condition is deteriorating 

with time. Trending of action requests is in accordance with the corrective action 

program.

Monitoring and Trending - X.S1 Concrete Containment Tendon Prestress

The tendon wire prestressing forces are compared to the predicted lower limit 

and upper bound lines that were developed for the period of extended operation 

in engineering analyses. Prestress force trends are also evaluated to ensure 

that the prestress force will not fall below the minimum required value prior to 

the next scheduled inspection. If the trend is not acceptable, an engineering 

evaluation is performed to determine a proper course of action (typically, 

immediate re-tensioning or reducing the length of time to the next inspection).

This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Acceptance Criteria

Acceptance Criteria - XI.S1 ASME Section XI, Subsection IWE

The Palisades program uses the acceptance standards of IWE 3000. Any item 

found not meeting the acceptance standards of IWE - 3000 is subject to an 
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engineering evaluation. The evaluation must state and justify one of the 

following conclusions:

• The observed condition is acceptable as is and no further action is required.

• The observed condition is acceptable as is but has the potential for further 

deterioration and requires augmented examination.

• The observed condition is not acceptable and repair or other remedial action 

is required.

If the observed condition includes a reduction in metal thickness in excess of 

10% of the nominal thickness, an evaluation is performed to determine if the 

reduced section satisfies design criteria.

If augmented examination is required, the evaluation report must specify the 

type of examination (Detailed Visual, surface NDE, volumetric NDE or other) 

and the frequency (once per period at a minimum) at which this is to be 

conducted.

If repair or other remedial action is required, the evaluation report must specify 

the nature of the action and the deadline for completion.

Acceptance Criteria - XI.S2 ASME Section XI, Subsection IWL

The Palisades program uses the acceptance criteria of IWL - 3000. Any item 

found not meeting the acceptance standards of IWL - 3000 is subject to an 

engineering evaluation. The acceptance criteria for concrete surfaces, corrosion 

protection medium leakage, or end-cap deformation are qualitative, and rely on 

the determination of the Responsible Engineer using the guidance of IWL 2510.

If augmented examination is required, the evaluation report must specify the 

type of examination (Detailed Visual, subsurface by concrete removal, 

subsurface by volumetric NDE or other) and the frequency (once per period at a 

minimum) at which this is to be conducted. The report must also identify and 

discuss the cause of the unacceptable condition.

Acceptance Criteria - X.S1 Concrete Containment Tendon Prestress

An evaluation is required if the acceptance criteria of ASME Section XI, 

Subsection IWL is not met, or if the trend indicates that tendon force(s) would be 

less than the minimum required value before the next scheduled inspection, as 

required by 10 CFR 50.55a(b)(2)(viii)(B).
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This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the 

Containment Inservice Inspection Program at Palisades are evaluated. The 

Containment Inservice Inspection Program is augmented, as appropriate, if 

these evaluations show that program changes will enhance program 

effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Containment Inservice Inspection Program issues are addressed in 

a timely manner and that age related deterioration within the scope of the 

Containment Inservice Inspection Program will be effectively managed 

throughout the license renewal period.

A review of the industry operating experience related to the Containment 

Inservice Inspection Program revealed instances where degradation has 

occurred within containments. In completing our review we looked at related 

issues which included degradation of containment liner plates, concrete, 

coatings, moisture barriers, bellows, tendons and tendon wires, tendon anchor 

heads, and penetrations.

A review of the plant specific operating experience revealed some instances 

where the Containment Inservice Inspection Program has been instrumental in 

discovering material degradation.

Containment degradation included:

• Liner plate corrosion

• Unacceptable tendon liftoff value

• Tendon gallery corrosion
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• Tendon grease leakage

• Moisture barrier not in place

• Tendon sheath water intrusion

The Containment Inservice Inspection Program has been effective in identifying 

material degradation in a timely manner, thus ensuring that age related 

degradation of the containment will be effectively managed throughout the 

license renewal period.

The Palisades Containment Inservice Inspection Program has demonstrated 

that it provides reasonable assurance that aging effects are being adequately 

managed for the containment. This has been demonstrated through NRC 

inspection reports, INPO evaluations, audits, self-assessments, and the 

Corrective Action Program.

This element is consistent with NUREG-1801, Section XI.S1, “ASME Section XI, 

Subsection IWE,” Section XI.S2, “ASME Section XI, Subsection IWL,” and 

Section X.S1, “Concrete Containment Tendon Prestress.”

Conclusion

The Containment Inservice Inspection Program is an existing program that uses as its 

bases, various industry and NRC standards. This program is consistent with 

NUREG-1801, Sections XI.S1, “ASME Section XI, Subsection IWE,” XI.S2, “ASME 

Section XI, Subsection IWL,” and X.S1, “Concrete Containment Tendon Prestress.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Containment 

Inservice Inspection Program has been effective in maintaining the intended functions of 

the affected long-lived, passive containment SSCs.

The continued implementation of the Containment Inservice Inspection Program provides 

reasonable assurance that aging effects will be managed such that the SSCs within the 

scope of this program will continue to perform their intended functions consistent with the 

current licensing bases for the period of extended operation.

B2.1.8 Containment Leakage Testing Program

Program Description

The Containment Leakage Testing Program is an existing program that ensures that 

containment leakage is maintained below the upper acceptance limit of La = 0.1% / day. 
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This testing program, in conjunction with the Containment Inservice Inspection Program, 

provides assurance that age related (and other) deterioration of the containment leakage 

limiting boundary is appropriately managed to ensure that postulated post-accident 

releases are limited to an acceptable level. The program is implemented through the 

following testing and examination activities:

• Overall containment leakage (integrated leakage rate or Type A) test to assess the leak 

tight integrity of the entire pressure boundary.

• Visual examinations of the containment exterior and interior.

• Local (Type B & C) tests to assess the leak tight integrity of individual penetrations.

NUREG-1801 Consistency

The Containment Leakage Testing Program is consistent with NUREG-1801, Section 

XI.S4, “10 CFR 50, Appendix J.”

Exceptions to NUREG-1801

None.

Enhancements

None.

Aging Management Program Elements

The elements of the Containment Leakage Testing Program are described below. The 

results of an evaluation of each element against NUREG-1801, Section XI.S4, “10 CFR 

50, Appendix J,” are also provided.

Scope of Program

The scope of the Palisades Containment Leakage Testing Program satisfies the 

requirements of 10 CFR 50, Appendix J, Option B, but takes the following three 

approved exceptions to the guidance given in RG 1.163, NEI 94-01, and 

ANSI/ANS 56.8: 

• Regulatory Guide 1.163 stipulates that containment purge valves are to be 

tested at least every 30 months. The NRC has approved application of 

performance based test interval extension criteria to the Palisades 

containment purge valves. However, Palisades has retained the Improved 

Technical Specification requirement to perform a leakage test on these 

valves every 184 days.
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• 10 CFR 50, Appendix J, Option B states that Type B tests are to be done at 

accident pressure. The NRC has approved testing of the Palisades 

personnel air lock door seals at 10 psig rather than Pa = 53 psig. 

• NEI 94-01 specifically requires that air lock door seals be tested following air 

lock door use when containment integrity is required. The NRC has approved 

the Palisades request to verify seal contact in lieu of performing a leakage 

test on emergency escape air lock door seals.

The above exceptions are documented in Technical Specifications Section 

5.5.14.

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Preventive Actions

The Palisades Containment Leakage Testing Program is a monitoring program 

and does not specify preventive actions. 

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Parameters Monitored, Inspected, and/or Tested

The parameters monitored or inspected under the Containment Leakage Testing 

Program include the following.

• Overall leakage through the containment pressure boundary (Type A test).

• General condition, with respect to leak tightness and structural integrity, of 

the accessible exterior and interior surfaces of the containment (visual 

examination associated with the Type A test). 

• Leakage through individual penetrations, access openings and fittings (Type 

B & C tests).

The containment leakage limiting boundary is designed to provide an essentially 

leak tight barrier against the release of fission products to the outside 

environment. The tests and inspections performed under the Containment 

Leakage Testing Program are designed to detect age related (and other) 

deterioration that reduces the leak tightness of this boundary.

The parameters monitored and inspected meet the NUREG 1801 intent that the 

program detect the effects of aging on the intended function (to limit leakage at 
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postulated post-accident pressure) of the containment throughout the license 

renewal period.

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Detection of Aging Effects

The Palisades Containment Leakage Testing Program is effective in detecting 

age related and other deterioration of containment pressure boundary leak tight 

integrity. Specifically, the program is effective in detecting such deterioration in 

the following components and items:

• The liner, the secondary system boundary, transition pieces connecting the 

liner to penetration assemblies, the fuel transfer tube assembly, air lock 

assemblies, the equipment hatch assembly, other blind flange penetration 

closures, other fixed steel pressure boundary components and associated 

welds.

• Resilient seals, gaskets and electrical penetration conductor feed-through 

seals.

• Passive isolation valves (defined in the Technical Specifications as manual 

isolation valves and deactivated, locked shut automatic valves).

In addition, this program detects age related and other deterioration that affects 

the leak tightness of active isolation valves and other active components that 

are not within the scope of the aging management program.

This program also demonstrates (during the Type A test) that the containment 

has the structural capacity to withstand design basis accident pressure (Pa).

Age related and other deterioration of the containment structural and leakage 

limiting boundaries are monitored through the Containment Leakage Testing 

Program and Containment Inservice Inspection Program. Implementing the 

visual examinations, non-destructive tests as applicable & leakage tests on the 

schedules mandated by the two programs provides a high degree of assurance 

that age related and other deterioration mechanisms having a potential impact 

on containment integrity are detected prior to the loss of the intended function 

and are effectively managed during the plant license renewal period.

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”
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Monitoring and Trending

Overall containment leakage (Type A test) and individual penetration leakages 

(Type B & C tests) are monitored at intervals determined in accordance with the 

requirements of 10 CFR 50, Appendix J, Option B and the guidance given in 

Regulatory Guide 1.163 & NEI 94-01. The leakage history of each tested item is 

evaluated considering both trended performance and risk aspects. The date of 

the subsequent test is set based on the evaluation result.

Trending of overall containment and component leakages as prescribed in the 

Containment Leakage Testing Program ensures that age related deterioration of 

leak tightness is identified and controlled in timely manner throughout the 

license renewal period.

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Acceptance Criteria

Acceptance criteria are stated in Technical Specification Section 5.5.14. These 

criteria are derived from NEI 94-01 requirements using the plant specific value 

(0.1% / day) of maximum allowable leakage rate, La. Criteria include:

• Limit on overall leakage rate: < 0.1% / day

• Maximum overall as-left leakage at the end of a Type A test: < 0.075% / day

• As-found performance leakage limit: < 0.1% / day

• Limit on as-left penetration minimum pathway leakage summation: < 0.06% / 

day 

In addition, administrative leakage limits are assigned to each component 

subject to Type B or C testing.

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues / events and assesses these for applicability to its own 
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operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues / events. Those issues and events, 

whether external or plant specific, that are potentially significant to the leak-tight 

integrity of the Palisades containment are evaluated. The Containment Leakage 

Testing Program is augmented, as appropriate, if these evaluations show that 

program changes will enhance leak-tight integrity and, as a consequence, 

operational safety.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that containment leakage issues are addressed in a timely manner and 

that age related deterioration of containment leak-tightness is effectively 

managed throughout the license renewal period. 

NUREG-1493, which provided the technical justification for the performance 

based leakage testing program defined in Appendix J, Option B, includes a 

summary of industry testing experience. This summary demonstrates that 

performance based leakage testing programs will almost always detect 

problems at an early stage and are, therefore, acceptable for managing 

containment leak tight integrity. The NUREG does include a few contrary 

examples. However, in most cases, these examples illustrate lack of 

administrative control rather than any technical deficiency in performance based 

programs. While the NUREG does not specifically address license renewal, it 

does show, by inference, that performance based leakage testing programs are 

effective as an aging management tool.

A review of additional industry operating experience associated with the 

Containment Leakage Testing Program and aging reveals issues and instances 

related to:

• Type B LLRT performed on containment penetration bellows, which was later 

invalidated by a subsequent containment ILRT.

No significant problems have been found during periodic Type A tests at 

Palisades. This confirms that the local leakage rate testing program (in 

conjunction with periodic containment examinations) has always detected 

developing deterioration before this could result in a loss of containment leak 

tight integrity (as defined by overall leakage exceeding La).

Instances of excessive (in excess of the assigned administrative limit) 

component leakage have been uncovered during the performance of Type B & 

C tests over the operating lifetime of the plant. Most instances of excessive 

leakage are the result of active isolation valve seat deterioration. Some are the 
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result of air lock door seal misalignment or damage. Active isolation valves and 

air lock door seals (which are replaced at least once every three refueling 

outages), however, are not long lived, passive components which are subject to 

aging management under this program.

Instances of problems with passive components are relatively rare. Two 

reported instances were found in a search through records going back through 

the mid 1980's. These are summarized below.

• In 1983 a leak of about 0.1 La was found at one conductor seal in electrical 

penetration EZ-104. The leak affected only one barrier so that minimum 

pathway leakage through the penetration was still essentially nil. The entire 

penetration was replaced during the 1985 outage.

• During a September 2001 Type C test on penetration MZ-66, a measured 

leak of about 0.15 La was identified primarily to leakage through a manual 

isolation gate valve. The cause of the leakage was determined to be debris 

on the seat. The problem was corrected and leakage restored to an 

acceptable level. Since the measured leakage was identified primarily to a 

single barrier, minimum pathway leakage through the penetration remained 

at a relatively low level.

The Palisades Containment Leakage Testing Program has demonstrated that it 

provides reasonable assurance that aging effects are being managed for 

in-scope SSC. Additionally, this has been demonstrated through inspection 

reports, Program Health Reports, and the Corrective Action Program. 

This element is consistent with NUREG-1801, Section XI.S4, “10 CFR 50, 

Appendix J.”

Conclusion

The Containment Leakage Testing Program is an existing program that is consistent with 

NUREG-1801, Section XI.S4, “10 CFR 50, Appendix J.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Palisades 

Containment Leakage Testing Program has been demonstrated to be an effective aging 

management tool. It is further concluded that this program, when implemented in 

conjunction with the Containment Inservice Inspection Program, provides a high degree 

of assurance that the containment will retain acceptable levels of structural and leak tight 

integrity throughout the period of license renewal.
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Appendix B - Aging Management Programs

The continued implementation of the Containment Leakage Testing Program provides 

reasonable assurance that aging effects will be managed such that the SSCs within the 

scope of this program will continue to perform their intended functions consistent with the 

current licensing bases for the period of extended operation.

B2.1.9 Diesel Fuel Monitoring and Storage Program

Program Description

The Diesel Fuel Monitoring and Storage Program is an existing program that assures the 

continued availability and quality of fuel oil to be used in diesel generators and diesel fire 

pumps. The program includes (a) monitoring and trending of fuel oil chemistry to maintain 

fuel oil quality and mitigate corrosion, (b) periodic draining, cleaning, and internal 

inspection of fuel oil storage tanks, and (c) verification of program effectiveness by a 

one-time measurement of fuel oil storage tank bottom thickness confirming the absence 

of an aging effect. Fuel oil quality is maintained by monitoring and controlling fuel oil 

contamination in accordance with the guidelines of the American Society for Testing 

Materials (ASTM) Standards D 1796, D 2276, D 2709, and D 4057. 

Exposure to fuel oil contaminants, such as water and microbiological organisms, is 

minimized by periodic draining and cleaning of tanks and by verifying the quality of new 

oil before its introduction into the storage tanks. However, corrosion may occur at 

locations in which contaminants may accumulate, such as tank bottoms. Accordingly, the 

effectiveness of the program is verified, through visual inspection and onetime ultrasonic 

thickness measurement of fuel oil storage tank bottom surface, to ensure that significant 

degradation is not occurring and that applicable component intended functions will be 

maintained during the period of extended operation. 

Per plant procedures, samples of new fuel oil are obtained and analyzed to verify quality 

prior to off-loading into storage tanks. Additionally, samples of new fuel are obtained for 

later analysis for particulates.

NUREG-1801 Consistency

The Diesel Fuel Monitoring and Storage Program is consistent with, but includes 

exceptions to, NUREG-1801, Section XI.M30, “Fuel Oil Chemistry.”

Exceptions to NUREG-1801

NUREG-1801 Section XI.M30 states, “The quality of fuel oil is maintained by additions of 

biocides to minimize biological activity, stabilizers to prevent biological breakdown of the 

diesel fuel, and corrosion inhibitors to mitigate corrosion.” 
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Appendix B - Aging Management Programs

Palisades tests the fuel in T-10A periodically for microbiological growth. 

There is no operational experience that indicates a positive test for microbiological 

growth. In the event a test would come back positive for microbiological growth, an 

evaluation would be performed, per the corrective action program, to determine whether 

addition of biocides should be performed.

Palisades performs periodic tests for particulates on the fuel oil storage tanks. 

 Additionally, the stored fuel in T-10A Fuel Oil Storage Tank is filtered approximately every 

three years, or as needed. The fuel oil storage tanks have a relatively fuel oil high 

turnover rate. T-10A typically has an operating volume of 38,000 gallons, with an average 

fuel consumption of 76,000 gallons per year. T-926 has a typical operating volume of 

15,000 gallons, with an average fuel consumption rate of 35,000 gallons per year. Based 

on these activities, and high fuel turnover in the storage tanks, an assessment has 

determined that there is no need to add fuel oil stabilizers to the diesel fuel.

Palisades fuel oil is procured to meet ASTM D975 standards, which include specifications 

and acceptance criteria for a Copper Strip Corrosion Test. Additionally, samples are 

periodically analyzed by an off-site facility for relative corrosivity of the fuel by a Copper 

Strip Corrosion Test. All Copper Strip Corrosion tests performed in the last 5 years have 

returned results that meet the ASTM standard. Consequently, Palisades does not add 

corrosion inhibitors to the diesel fuel.

Enhancements

Enhancements are planned to bring the Diesel Fuel Monitoring and Storage Program into 

conformance (with exception noted above) with the NUREG-1801 program description. 

The enhancements are:

1. Preventive Actions: Develop and implement procedures for periodic draining and 

cleaning of Fuel Oil Storage Tanks, Emergency Diesel Generator Day Tanks, and Diesel 

Fire Pump Day Tanks. These procedures shall include steps to perform a visual 

inspection of interior tank surfaces for signs of degradation or corrosion, with acceptance 

criteria, corrective actions, and documentation of inspection results. 

2. Preventive Actions: Develop and implement procedures for periodic draining of water 

accumulated in the bottom of the Fuel Oil Storage Tanks, Emergency Diesel Generator 

Day Tanks, and Diesel Fire Pump Day Tanks.

3. Detection of Aging Effects: Develop and implement procedures for periodic ultrasonic 

measurement of thickness of the bottom of Fuel Oil Storage Tanks, Emergency Diesel 

Generator Day Tanks, and Diesel Fire Pump Day Tanks.
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Appendix B - Aging Management Programs

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for completion 

prior to the period of extended operation. 

Aging Management Program Elements

The key elements of the Diesel Fuel Monitoring and Storage Program are described 

below. The results of an evaluation of each key element against the corresponding 

element of NUREG-1801, Section XI.M30, “Fuel Oil Chemistry,” are also provided. 

Scope of Program

Components in the Fuel Oil System associated with the Emergency Diesel 

Generators and Diesel Fire Pumps, including storage tanks, day tanks, piping, 

valve bodies, and other passive components that rely on the Diesel Fuel 

Monitoring and Storage Program to minimize potential for degradation and loss 

of intended function. The program manages the conditions that would cause 

general, pitting and microbiological influenced corrosion (MIC) of the diesel fuel 

tank internal surfaces.

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.”

Preventive Actions

The following activities are performed to prevent loss of intended function for 

Fuel Oil System components that take credit for the Diesel Fuel Monitoring and 

Storage Program:

• Periodic draining and cleaning of fuel oil storage tanks to remove 

accumulated sludge, and inspect/correct any locations where corrosion may 

have started.

• Periodic draining of water collected at the bottom of the fuel oil storage tanks.

There are no coatings on the interior surfaces of the fuel oil storage tanks that 

are credited with protecting the internal surfaces of the tank from contact with 

water and microbiological organisms.

This element is consistent with, but includes an exception to, NUREG-1801, 

Section XI.M30, “Fuel Oil Chemistry.” NUREG-1801 Section XI.M30 states, “The 

quality of fuel oil is maintained by additions of biocides to minimize biological 

activity, stabilizers to prevent biological breakdown of the diesel fuel, and 

corrosion inhibitors to mitigate corrosion.” 
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Appendix B - Aging Management Programs

Palisades tests the fuel in T-10A periodically for microbiological growth. 

There is no operational experience that indicates a positive test for 

microbiological growth. In the event a test would come back positive for 

microbiological growth, an evaluation would be performed, per the corrective 

action program, to determine whether addition of biocides should be performed.

Palisades performs periodic tests for particulates on the fuel oil storage tanks. 

 Additionally, the stored fuel in T-10A Fuel Oil Storage Tank is filtered 

approximately every three years, or as needed. The fuel oil storage tanks have a 

relatively fuel oil high turnover rate. T-10A typically has an operating volume of 

38,000 gallons, with an average fuel consumption of 76,000 gallons per year. 

T-926 has a typical operating volume of 15,000 gallons, with an average fuel 

consumption rate of 35,000 gallons per year. Based on these activities, and high 

fuel turnover in the storage tanks, an assessment has determined that there is 

no need to add fuel oil stabilizers to the diesel fuel.

Palisades fuel oil is procured to meet ASTM D975 standards, which include 

specifications and acceptance criteria for a Copper Strip Corrosion Test. 

Additionally, samples are periodically analyzed by an off-site facility for relative 

corrosivity of the fuel by a Copper Strip Corrosion Test. All Copper Strip 

Corrosion tests performed in the last 5 years have returned results that meet the 

ASTM standard. Consequently, Palisades does not add corrosion inhibitors to 

the diesel fuel.

Parameters Monitored, Inspected, and/or Tested

Palisades Fuel Oil Monitoring and Storage program references ASTM D4057, 

“Manual Sampling of Petroleum and Petroleum Products,” for fuel oil sampling, 

and ASTM D975 “Diesel Fuel Oils,” for monitoring fuel oil quality and the levels 

of water and microbiological organisms in the fuel oil. ASTM D2709, “Standard 

Test Method for Water and Sediment in Distillate Fuels by Centrifuge”, and 

ASTM D1796 “Standard Test Method for Water and Sediment in Fuel Oils by the 

Centrifuge Method (laboratory procedure)” are used as the basis for the water 

and sediment analysis. Modified ASTM D2276, “Standard Test Method for 

Particulate Contaminant in Middle Distillate Fuel by laboratory filtration,” is used 

as the basis for the particulate analysis.

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.”
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Appendix B - Aging Management Programs

Detection of Aging Effects

The Palisades Diesel Fuel Monitoring and Storage Program includes a variety of 

inspection and testing activities that are designed to detect signs of degradation 

due to aging effects prior to loss of intended function. The Palisades Diesel Fuel 

Monitoring and Storage Program conducts periodic multilevel sampling, tank 

draining/cleaning, internal tank visual inspections, and tank bottom thickness 

testing to detect any signs of potential adverse degradation.

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.”

Monitoring and Trending

Results of fuel oil analyses for Fuel Oil Storage Tanks and Truck Transport 

Tankers are documented within the analysis procedures, and reviewed against 

acceptance criteria. Results are also logged into the Chemistry Department 

trending database to facilitate long term trending. Additionally, clear acceptance 

criteria exist within procedures to facilitate corrective actions if parameters 

exceed these criteria.

Parameters monitored and trended include:

• Water and sediment

• Viscosity

• Specific Gravity

• Particulates

• Biological Activity

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.” 

Acceptance Criteria

Acceptance criteria are derived from the referenced ASTM standard D975-74, 

“Classification of Diesel Fuel Oils,” which contains limits for percent water and 

sediment, and viscosity. Additionally, Chemistry procedures impose further 

acceptance criteria based on ASTM D975, which references ASTM D4057 for 

oil sampling, ASTM D1796 and D2709 for water and sediment, and Modified 

ASTM D2276 for particulates.

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.”
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Appendix B - Aging Management Programs

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Diesel 

Fuel Monitoring and Storage Program at Palisades are evaluated. The Diesel 

Fuel Monitoring and Storage Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Diesel Fuel Monitoring and Storage Program issues are addressed 

in a timely manner, and that age related deterioration of SSC within the scope of 

the Diesel Fuel Monitoring and Storage Program will be effectively managed 

throughout the license renewal period.

A review of industry operating experience associated with the Diesel Fuel 

Monitoring and Storage Program and aging reveals issues and instances related 

to:

• Fuel contamination leading to corrosion of fuel oil system components.

• Improper zinc coating curing and epoxy application by the manufacturer 

leads to zinc-fuel reaction creating adverse corrosion. 

• Fuel oil leak caused by improper outer coating application.

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Diesel Fuel 

Monitoring and Storage Program was performed, and no aging issues were 

identified.

The Palisades Diesel Fuel Monitoring and Storage Program has demonstrated 

that it provides reasonable assurance that aging effects are being managed for 

the Diesel Fuel Monitoring and Storage Program SSCs. 

This element is consistent with NUREG-1801, Section XI.M30, “Fuel Oil 

Chemistry.” 
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Appendix B - Aging Management Programs

Conclusion

The Diesel Fuel Monitoring and Storage Program is an existing program that uses as its 

bases, various industry and NRC standards. This program is consistent with, but includes 

exceptions to, NUREG-1801, Section XI.M30, “Fuel Oil Chemistry.”

Although no recent internal or external assessments of the program have been 

performed, reviews for plant operating experience, and a general lack of equipment 

problems related to aging demonstrate that the program has effectively managed aging 

mechanisms that could have led to degraded conditions. It is concluded that the Diesel 

Fuel Monitoring and Storage Program has been effective in maintaining the intended 

functions of the affected long-lived, passive SSCs.

The continued implementation of the Diesel Fuel Monitoring and Storage Program 

provides reasonable assurance that aging effects will be managed such that SSCs within 

the scope of this program will continue to perform their intended functions consistent with 

the current licensing bases for the period of extended operation.

B2.1.10 Fire Protection Program

Program Description

The Fire Protection Program is an existing program that includes (a) fire barrier 

inspections, (b) electric and diesel-driven fire pump tests, and (c) periodic maintenance, 

testing, and inspection of water-based fire protection systems. Periodic visual inspections 

of fire barrier penetration seals, fire dampers, fire barrier walls, ceilings and floors, and 

periodic visual inspections and functional tests of fire-rated doors are performed to 

ensure that functionality and operability is maintained. Periodic testing of the fire pumps 

ensures that an adequate flow of firewater is supplied and that there is no degradation of 

diesel fuel supply lines. Periodic maintenance, testing and inspection activities of 

water-based fire protection systems provides reasonable assurance that fire water 

systems are capable of performing their intended function. Inspection and testing include 

periodic hydrant inspections, fire main flushing, sprinkler inspections, pipe wall thickness 

testing and flow tests.

This program manages aging of the fire protection components through detailed fire 

barrier inspections of fire barrier penetration seals, and fire rated doors. Aging related 

degradation of fire barrier walls, ceilings and floors are managed by the Structural 

Monitoring Program. Aging of the diesel-driven fire pump's fuel oil supply line is managed 

through regularly scheduled fire pump performance tests. 

The Fire Protection Program also manages aging of fire water systems through periodic 

hydrant inspections, flushes, and flow tests, fire main flushing, sprinkler system 
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Appendix B - Aging Management Programs

inspections, and pipe wall thickness testing. In addition, fire water system pressure and 

flow is continuously monitored in the plant control room through annunciator alarms and 

personnel.

Also included within the scope of the Fire Protection Program is aging management of 

spare cables for Appendix R required equipment. These spare cables are located in 

various storage locations in the event they are needed for repairs to key components 

damaged by an Appendix R type fire. The Fire Protection Program credits the Non-EQ 

Electrical Commodities Condition Monitoring Program for aging management of these 

cables.

The NRC issued ISG-4, “Aging Management of Fire Protection Systems for License 

Renewal,” in December 2002. This staff position clarified the guidance of NUREG-1801 

Section XI.M26, “Fire Protection,” and XI.M27, “Fire Water System,” with regard to wall 

thinning of fire protection piping due to internal corrosion, testing of sprinkler heads, and 

valve line-up inspections of Halon/Carbon Dioxide fire suppression systems. The Fire 

Protection Program is based on the aging management program guidance presented in 

ISG-4.

NUREG-1801 Consistency

The Fire Protection Program is consistent with, but includes exceptions to, NUREG-1801, 

Section XI.M26, “Fire Protection.” The program is consistent with, but includes exceptions 

to, Section XI.M27, “Fire Water System,” as clarified by ISG-4.

Exceptions to NUREG-1801

Exceptions are taken to the selected NUREG-1801 Program elements listed below. The 

specific exceptions being taken are also discussed in the corresponding element 

discussions below. They are repeated here for ease of review.

1. XI.M26, Detection of Aging Effects: NUREG-1801, Section XI.M26, as clarified by 

ISG-4, specifies that visual inspections as follows: “Visual inspection (VT-1 or 

equivalent) of approximately 10% of each type of seal ... Visual inspection (VT-1 or 

equivalent) of the fire barrier walls, ceilings, and floors ... Visual inspection (VT-3 or 

equivalent) detects any signs of degradation of the fire door ....” Palisades does not 

qualify the personnel performing the visual inspections of fire barrier walls, ceilings, 

floors, penetration seals and fire doors to the ASME Code type of qualification as 

stated in NUREG-1801 and ISG -04. Per plant procedures, inspectors for fire 

barriers/doors/fire seals are appropriately qualified to perform those inspections, but 

are not necessarily qualified to VT-1 or VT-3. There are no regulatory or other 

requirements specifying that these inspections be performed to VT-1 or VT-3 
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Appendix B - Aging Management Programs

standards. This is generally in accordance with the position taken by the Dresden 

and Quad Cities Nuclear Plants in their application for License Renewal, and 

subsequent NRC approval of this position in the associated Safety Evaluation 

Report.

2. XI.M27, Monitoring and Trending: NUREG-1801, Section XI.M27, as clarified by 

ISG-4, states that the results of system performance testing are monitored and 

trended as specified by the NFPA codes and standards. At Palisades, inspection 

and testing is performed as outlined in Fire Protection Implementing Procedures. 

NFPA codes of record are identified in the Palisades Fire Protection Program Report 

(FPPR) and/or FSAR. This is generally in accordance with the position taken by the 

Dresden and Quad Cities Nuclear Power Stations in their License Renewal 

Application and approved by the NRC in the associated Safety Evaluation Report.

3. XI.M26, Acceptance Criteria: NUREG-1801, as clarified by ISG-4, states “Inspection 

results are acceptable if there are no visual indications of cracking, separation of 

seals from walls and components, separation of layers of material, or ruptures or 

punctures of seals.” Palisades inspection acceptance criteria states that no cracks of 

1⁄4” wide or greater are allowed. The acceptance criteria is derived from fire test 

reports, and is acceptable.

Enhancements

Enhancements are planned to bring the Fire Protection Program into conformance (with 

exceptions noted above) with the NUREG-1801 program description. The enhancements 

are:

1. Detection of Aging Effects, and Monitoring and Trending: The Structural Monitoring 

Program implementing procedures shall be revised to include specific inspection criteria 

and documentation requirements for verifying that walls, ceilings and floors that serve as 

Fire Protection Program fire barriers are verified to be free from aging related degradation 

that would impact the fire barrier's intended function.

2. Scope of Program, Detection of Aging Effects, and Monitoring and Trending: Plant 

procedures shall be revised to more specifically address aging related degradation and 

expectations for documentation of fire door condition. 

3. Detection of Aging Effects, and Monitoring and Trending: Develop and implement 

procedures to perform visual inspections for fire door clearances.

4. Detection of Aging Effects, and Monitoring and Trending: Revise diesel-driven fire 

pump performance test procedures to more specifically address requirement to inspect 
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Appendix B - Aging Management Programs

and monitor fuel oil supply line for aging related degradation, and to document inspection 

results.

5. Detection of Aging Effects: Develop and implement procedures for inspection of below 

grade fire protection system piping. Inspections shall occur when below grade piping is 

excavated for maintenance, and shall include pipe wall thickness (NDE or direct 

measurement) and documentation of aging related degradation of pipes. Procedures 

shall include acceptance criteria, and criteria for further corrective actions if acceptance 

criteria are not met.

6. Parameters Monitored, Inspected and Tested: Plant procedures shall be revised to 

more specifically address identification of aging related degradation and expectations for 

documentation of fire hydrant condition. Also, these revisions shall include provisions to 

perform flow testing for fire hydrants within the scope of License Renewal that are 

credited for fire suppression in the Palisades current licensing basis.

7. Detection of Aging Effects: Develop and implement procedures to replace all sprinkler 

heads prior to the end of the 50 year service life, or for testing of a representative sample 

of sprinkler heads prior to the end of the 50 year service life and at 10 year intervals 

thereafter, per requirements of NFPA 25, Section 5.3.

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for completion 

prior to the period of extended operation. 

Aging Management Program Elements

The key elements of the Fire Protection Program are described below. The results of an 

evaluation of each key element against NUREG-1801, Sections XI.M26, “Fire Protection,” 

and XI.M27, “Fire Water System” as clarified by ISG-4, are also provided.

Scope of Program

SSCs included within the scope of the Fire Protection Program include both fire 

suppression and fire mitigation components. These include fire barriers, 

Appendix R spare cables, fire detection and fire suppression systems, as 

discussed in current licensing basis documents. The program focuses on 

managing loss of material due to corrosion, MIC, or biofouling of carbon steel 

and cast-iron components exposed to water and fuel oil, and aging/degradation 

of fire barrier components.

This element is consistent with NUREG-1801, Sections XI.M26, “Fire 

Protection” as clarified by ISG-4. 
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Appendix B - Aging Management Programs

This element is consistent with NUREG-1801, Section XI.M27, “Fire Water 

System” as clarified by ISG-4.

Preventive Actions

The Palisades Fire Protection Program incorporates many activities that serve 

to prevent or manage aging of the Fire Protection System. These include regular 

inspections of fire barrier penetration seals, fire rated doors, and sprinkler 

systems. Performance tests and flushes are performed on fire pumps and fire 

hydrants. These inspections and tests ensure that aging related degradation will 

be detected in the early stages to prevent loss of intended function.

The Fire Hazards Analysis Report (FHAR) quantifies the combustible loading 

and assesses the fire severity for all plant fire areas. It also specifies measures 

for fire suppression, fire containment, and safe shutdown capability for each fire 

area. Palisades fire prevention is administered through the plant procedures.

This element is consistent with NUREG-1801, Sections XI.M26, “Fire 

Protection,” as clarified by ISG-4.

This element is consistent with NUREG-1801, Sections XI.M27, “Fire Water 

System,” as clarified by ISG-4.

Parameters Monitored, Inspected, and/or Tested

Fire Protection Program activities monitor a variety of parameters to prevent 

loss of intended function due to age-related degradation. These parameters 

include: 

• Visual inspections of at least 10% of the fire barrier penetration seals for 

signs of cracking, discontinuities, spalling, shrinkage, gaps, voids, loose or 

dislodged pieces, on a refueling cycle frequency. Damming board 

inspections look for breaks, unsealed holes, discontinuities and pulling away 

from the fire barrier. 

• Fire rated hollow metal doors are visually inspected to verify integrity of door 

surfaces and proper clearances. Doors are inspected for proper functioning, 

including hardware.

• Fire rated assemblies, and fire barrier walls, ceilings and floors are inspected 

for missing components, spalling, cracking and loss of material caused by 

freeze-thaw, chemical attack and reaction with aggregates.

• Fire hydrants are flushed to test for flow restriction and proper hydrant 

operation and drainage. Hydrants are visually inspected for corrosion and 
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Appendix B - Aging Management Programs

damage, and proper thread/valve lubrication. Hydrants within the scope of 

license renewal that are credited for fire suppression in the Palisades current 

licensing basis are flow tested.

• Sprinkler system flow switches are functionally tested for blockage or 

biofouling.

• Sprinkler systems are inspected for external corrosion, damage, paint, dirt, 

and blockage

• Diesel-driven fire pump fuel supply line is inspected during pump flow tests to 

detect degradation such as corrosion.

• Pressure alarms and flow switches are continuously monitored by control 

room annunciators and personnel to detect fire suppression system 

operation or abnormalities. 

• Fire water system piping is volumetrically examined as part of the Palisades 

ASME Section XI IWB, IWC, IWD, IWF Inservice Inspection Program.

• Appendix R spare cables are inventoried, inspected and tested to ensure 

satisfactory condition and readiness, while in storage. The Fire Protection 

Program credits the Non-EQ Electrical Commodities Condition Monitoring 

Program for aging management of these components.

This element is consistent with NUREG-1801, Sections XI.M26, “Fire 

Protection,” and XI.M27, “Fire Water System” as clarified by ISG-4.

Detection of Aging Effects

The Palisades Fire Protection Program includes a variety of inspection and 

testing activities that are designed to detect degradation due to aging effects 

prior to loss of intended function.

At least 10% of the fire barrier penetration seals are visually inspected by 

qualified inspectors every 18 months for signs of age-related degradation, such 

as seal separation from walls and components, cracking, rupture and puncture 

of seals. The Fire Protection Program credits the Structural Monitoring Program 

for aging management of fire barrier walls, ceilings and floors. Fire doors are 

periodically tested and visually inspected by qualified inspectors for signs of 

corrosion, wear, or missing parts to ensure that functionality and operability is 

maintained.

For fire barrier penetration seals visual inspections, fire pump performance 

tests, and sprinkler system visual inspections, NUREG-1801 specifies a 

frequency of once per refueling outage. Palisades Fire Protection Program 
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specifies a frequency of once every 18 months. This is considered acceptable 

because Palisades has an 18 month operating cycle, which corresponds to the 

same amount of time between inspections.

Palisades credits the One-Time Inspection Program for aging management of 

RCP oil collection tank, piping and valve bodies for wall thickness and aging 

related degradation.

Testing of the fire pumps is performed every 18 months to ensure that an 

adequate flow of fire water is supplied and that there is no degradation of the 

fuel line to the diesel-driven fire pump.

Continuous fire water system pressure monitoring, and periodic functional 

testing including fire detection/actuation devices, ensure that corrosion and 

biofouling are not occurring to an extent that an intended function would be 

compromised. To determine the ability of fire water system piping to perform its 

intended pressure boundary function, volumetric inspections of selected fire 

water system piping segments are performed as part of the Palisades ASME 

Section XI IWB, IWC, IWD, IWF Inservice Inspection Program.

Sprinkler heads will be replaced, or tested in accordance with NFPA 25, prior to 

exceeding their 50 year service life. The required testing will be repeated at ten 

year intervals.

Below grade fire protection system piping will be inspected for pipe wall 

thickness and age related degradation during inspections of opportunity when 

the below grade systems are excavated for maintenance.

Annual visual inspections, flushes, and flow tests of fire hydrants within the 

scope of license renewal that are credited for fire suppression in the Palisades 

current licensing basis provide the opportunity for degradation to be detected 

before a loss of intended function can occur.

This element is consistent with, but includes an exception to, NUREG-1801, 

Sections XI.M26, “Fire Protection” as clarified by ISG-4. The exception is:

• NUREG-1801, Section XI.M26, as clarified by ISG-4, specifies that visual 

inspections as follows: “Visual inspection (VT-1 or equivalent) of 

approximately 10% of each type of seal ... Visual inspection (VT-1 or 

equivalent) of the fire barrier walls, ceilings, and floors ... Visual inspection 

(VT-3 or equivalent) detects any signs of degradation of the fire door 

....”Palisades does not qualify the personnel performing the visual 

inspections of fire barrier walls, ceilings, floors, penetration seals and fire 

doors to the ASME Code type of qualification as stated in NUREG-1801 and 
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Appendix B - Aging Management Programs

ISG -04. Per plant procedures, inspectors for fire barriers/doors/fire seals are 

qualified to perform those inspections, but are not necessarily qualified to 

VT-1 or VT-3. There are no regulatory or other requirements specifying that 

these inspections be performed to VT-1 or VT-3 standards. This is generally 

in accordance with the position taken by the Dresden and Quad Cities 

Nuclear Plants in their application for License Renewal, and subsequent 

NRC approval of this position in the associated Safety Evaluation Report.

This element is consistent with NUREG-1801, Section XI.M27, “Fire Water 

System” as clarified by ISG-4.

Monitoring and Trending

The Fire Protection Program credits the Structural Monitoring Program for 

monitoring the condition of fire barrier walls, ceilings and floors. At least 10% of 

the fire barrier penetration seals are visually inspected every 18 months for 

signs of age-related degradation, such as seal separation from walls and 

components, cracking, rupture and puncture of seals. Fire doors are tested 

and/or visually inspected by qualified inspectors semi-annually for signs of 

corrosion, wear, missing parts, and proper clearances to ensure that 

functionality and operability is maintained.

For fire barrier penetration seal visual inspections, NUREG-1801 specifies a 

frequency of once per refueling outage. Palisades Fire Protection Program 

specifies a frequency of once every 18 months. This is considered acceptable 

because Palisades has an 18 month operating cycle, which corresponds to the 

same amount of time between inspections.

Testing of the fire pumps is performed every 18 months to ensure that an 

adequate flow of fire water is supplied and that there is no degradation of the 

fuel line to the diesel-driven fire pump.

The fire protection system pressure is continuously monitored. Test results from 

the various surveillance tests are evaluated. Periodic full flow flushing of the 

main fire system underground piping is performed to assure that corrosion is not 

occurring and the system function is maintained. Any degradation identified 

either by visual inspections or as a result of testing is evaluated and corrected.

This element is consistent with NUREG-1801, Sections XI.M26, “Fire 

Protection” as clarified by ISG-4. 

This element is consistent with, but includes an exception to, NUREG-1801, 

Sections XI.M27, “Fire Water System” as clarified by ISG-4. The exception is:
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• NUREG-1801, Section XI.M27, as clarified by ISG-4, states that the results 

of system performance testing are monitored and trended as specified by the 

NFPA codes and standards. At Palisades, inspection and testing is 

performed as outlined in Fire Protection Implementing Procedures. This is 

generally in accordance with the position taken by the Dresden and Quad 

Cities Nuclear Power Stations in their License Renewal Application and 

approved by the NRC in the associated Safety Evaluation Report.

Acceptance Criteria

Acceptance criteria are defined in the Palisades procedures used to perform 

tests and inspections of the Fire Protection System. Fire seal and conduit 

wrapping inspection results are acceptable if there are no visual indication of 

cracking > 1⁄4”, separation of seals from building structures and components, 

rupture or puncture of seals. Fire door inspection results are acceptable if there 

are no visual indications of wear, holes, damaged or missing parts, and 

clearances are within limits. Diesel-driven fire pump inspections are acceptable 

if there is no evidence of corrosion or leaks on the fuel oil supply line. 

Acceptance criteria for the diesel-driven fire pump capacity is contained within 

the test procedure. 

This element is consistent with, but includes an exception to, NUREG-1801, 

Sections XI.M26, “Fire Protection” as clarified by ISG-4. The exception is:

• NUREG-1801, as clarified by ISG-4, states “Inspection results are 

acceptable if there are no visual indications of cracking, separation of seals 

from walls and components, separation of layers of material, or ruptures or 

punctures of seals.” Palisades inspection acceptance criteria states that no 

cracks of 1⁄4” wide or greater are allowed. The acceptance criteria is derived 

from fire test reports, and is acceptable. 

This element is consistent with NUREG-1801, Sections XI.M27, “Fire Water 

System” as clarified by ISG-4.

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 
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operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to fire protection 

at Palisades are evaluated. The Fire Protection Program is augmented, as 

appropriate, if these evaluations show that program changes will enhance fire 

protection and operational safety.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Fire Protection Program issues are addressed in a timely manner 

and that age related deterioration of SSC within the scope of the Fire Protection 

Program will be effectively managed throughout the license renewal period.

A review of industry operating experience associated with the Fire Protection 

Program and aging reveals issues and instances related to:

• Fire water system piping corrosion and ruptures

• Fire retardant coatings and materials

• Fouling of components in contact with raw water

• Problems with fire barriers. 

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Fire Protection 

Program and aging revealed that the following issues have been addressed:

• Blockage of Fire Protection piping with corrosion products

• Deluge valve trim piping failures due to corrosion

• Underground fire main rupture due to cyclic loadings

• Water tight fire door seal degradation

The Palisades Fire Protection Program has demonstrated that it provides 

reasonable assurance that aging effects are being managed for Fire Protection 

Program SSCs. This has been demonstrated through NRC inspection reports, 

audits, self-assessments, and the Corrective Action Program.

This element is consistent with NUREG-1801, Sections XI.M26, “Fire 

Protection,” and XI.M27, “Fire Water System” as clarified by ISG-4.

Conclusion

The Fire Protection Program is an existing program that uses as its bases, various 

industry and NRC standards. The program is consistent with, but includes exceptions to, 
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Appendix B - Aging Management Programs

NUREG-1801, Section XI.M26, “Fire Protection,” and Section XI.M27, “Fire Water 

System,” as clarified by ISG-4. A summary of each exception is provided in the 

discussion of the affected program element above. 

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Fire Protection 

Program has been effective in maintaining the intended functions of the affected 

long-lived, passive SSCs.

The continued implementation of the Fire Protection Program provides reasonable 

assurance that aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.

B2.1.11 Flow Accelerated Corrosion Program

Program Description

The Flow Accelerated Corrosion Program is an existing program that manages aging 

effects due to flow-accelerated corrosion (FAC) on the internal surfaces of carbon or low 

alloy steel piping, elbows, reducers, expanders, and valve bodies which contain high 

energy fluids (both single phase and two phase). The program implements the EPRI 

guidelines in NSAC-202L-R2 for an effective FAC program and includes (a) an analysis 

using a predictive code such as CHECWORKSTM to determine critical locations, (b) 

baseline inspections to determine the extent of thinning at these locations, (c) follow-up 

inspections to confirm the predictions, and (d) repairing or replacing components, as 

necessary. 

NUREG-1801 Consistency

The Flow Accelerated Corrosion Program is consistent with NUREG-1801, Section 

XI.M17, “Flow Accelerated Corrosion.”

Exceptions to NUREG-1801

None.

Enhancements

None.
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Appendix B - Aging Management Programs

Aging Management Program Elements

The elements of the Flow Accelerated Corrosion Program are described below. The 

results of an evaluation of each element against NUREG-1801, Section XI.M17, “Flow 

Accelerated Corrosion,” are also provided. 

Scope of Program

The Palisades FAC program implements EPRI guidelines in NSAC-202L-R2, 

and includes procedures and administrative controls to assure that the structural 

integrity of all carbon steel and low alloy steel lines containing high-energy fluids 

(two phase as well as single phase) is maintained.

This program predicts, detects, and monitors flow accelerated corrosion for the 

systems and components that are susceptible to flow accelerated corrosion and 

that are within the scope of License Renewal. These systems and components 

are modeled in CHECWORKS in accordance with the EPRI guidelines in 

NSAC-202L-R2. This program predicts, detects, and monitors flow accelerated 

corrosion wear for the systems modeled in CHECWORKS that are within the 

scope of License Renewal. 

The following systems that are within the scope of license renewal credit the 

FAC program for aging management of flow accelerated corrosion:

• Condensate

• Feedwater

• Main Steam

• Steam generators - secondary side

• Heater Extraction and Drain

• HVAC (heating steam)

• Air Ejector and Gland Seal

The program encompasses the following component types:

• Elbows

• Tees

• Straight Pipe

• Concentric Reducers/Expanders

• Nozzles

• Valves
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Appendix B - Aging Management Programs

• Pumps

• Traps

• Tanks

• Strainers

The program includes the following activities: 

• Conduct appropriate analysis and limited baseline inspections;

• Determine the extent of thinning and repair or replace components as 

appropriate;

• Perform follow up inspections to confirm or quantify previously discovered 

conditions; and 

• Take long term corrective actions if necessary.

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Preventive Actions

There are no preventive actions associated with the FAC Program. The program 

is an inspection, analysis, and verification program. Mitigation of aging due to 

FAC is by maintaining high water quality, as described in the Water Chemistry 

Program. Components with a calculated remaining life of less than one 

operating cycle are either replaced, repaired, or re-evaluated to ensure that the 

intended function of maintaining the component pressure boundary will be 

preserved.

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Parameters Monitored, Inspected, and/or Tested

The FAC program monitors the effects of FAC on the intended function of piping 

and components by measuring the wall thickness using nondestructive 

examinations and by performing analytical evaluations. 

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Detection of Aging Effects

The Palisades Flow Accelerated Corrosion Program includes a variety of 

inspection and testing activities that are designed to detect degradation due to 
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Appendix B - Aging Management Programs

aging effects caused by FAC prior to loss of intended function. The methods of 

inspection for FAC include visual observation, ultrasonic (UT), and radiography 

(RT).

The inspection schedule provides for timely detection of degradation of 

susceptible piping and components. The CHECWORKSTM Model is used to 

select components for inspection. The extent and schedule of inspections 

ensures detection of wall thinning before the loss of the intended function of the 

component.

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Monitoring and Trending

The CHECWORKSTM code is used to predict component degradation in 

systems susceptible to FAC. Plant data, including material composition, system 

flow characteristics, and operating conditions are used by CHECWORKSTM to 

determine the remaining service life, which is recalculated after each inspection. 

Per plant procedures, if inspection results indicate a higher than expected wear 

rate that is inconsistent with the predicted wear rates, the reason for those 

inconsistencies are investigated. As part of the evaluation, an updated FAC 

analysis is performed, and additional investigations conducted, to determine the 

extent of the unpredicted wear rates. CHECWORKSTM provides a bounding 

analysis for FAC. The inspection schedule developed on the basis of the results 

of this predictive code provides reasonable assurance that adequate wall 

thickness will be maintained between inspections.

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Acceptance Criteria

The acceptance criteria are defined in plant procedures. Criteria include 

minimum requirements for remaining life, program expansion criteria, repairing 

and replacing components, and engineering analyses to support actions and 

conclusions. CHECWORKSTM is used to determine if the remaining life is 

shorter than the amount of time until the next inspection. An engineering 

evaluation is also performed to determine acceptability. Activities are then 

planned and executed if the engineering evaluation determines repair or 

replacement is necessary.
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Appendix B - Aging Management Programs

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Flow 

Accelerated Corrosion Program at Palisades are evaluated. The Flow 

Accelerated Corrosion Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness. 

A review of industry operating experience associated with the Flow Accelerated 

Corrosion Program and aging reveals issues and instances related to:

• Feedwater heater shell degradation and ruptures

• Feedwater and Condensate line ruptures

• Pipe wall thinning downstream of control valves and flow restricting devices

• Valve body erosion

• Extraction steam line ruptures

• Moisture Separator Reheater Drain Tank drain line ruptures

• Steam Generator Feedwater distribution piping and J-tube damage

• Erosion of carbon steel ribs and tube supports in Steam Generators

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Flow Accelerated 

Corrosion Program and aging revealed that the following issues have been 

addressed:

• FAC on 2 inch main steam line elbows

• Higher than expected wear rates on 8 inch steam pipes and elbows on the 

outlet of Moisture Separator Reheater
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• Main Condenser tube leaks caused by FAC

• Higher than expected wear rates on high pressure extraction steam piping to 

high pressure feedwater heater

• FAC on end-bell of low pressure feedwater heater

• Valve body FAC on control valves and check valves

• FAC of feedwater heater shell side capped drains

• FAC damage to low pressure turbine extraction sleeves

• FAC damage to extraction steam lines to high pressure feedwater heaters

• FAC damage to Moisture Separator Reheater vent line

• FAC of feedwater piping

• FAC of reducer downstream of control valve

• Through wall steam leak on steam generator flash tank

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Flow Accelerated Corrosion Program issues are addressed in a 

timely manner and that age related deterioration of SSC's within the scope of 

the Flow Accelerated Corrosion Program will be effectively managed throughout 

the license renewal period.

In addition, NRC inspection reports, audits, self-assessments, and the 

Corrective Action Program were reviewed for relevant information. No significant 

findings were identified that would indicate that the program is ineffective. Some 

weaknesses have been identified that have resulted in appropriate corrective 

actions and enhancements. 

This element is consistent with NUREG-1801, Section XI.M17, “Flow 

-Accelerated Corrosion.”

Conclusion

The Flow Accelerated Corrosion Program is an existing program that uses as its bases, 

various industry and NRC standards. This program is consistent with NUREG-1801, 

Section XI.M17, “Flow -Accelerated Corrosion.” 

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Flow 

Accelerated Corrosion Program has been effective in maintaining the intended functions 

of the affected long-lived, passive SSC's.
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Appendix B - Aging Management Programs

The continued implementation of the Flow Accelerated Corrosion Program provides 

reasonable assurance that aging effects will be managed such that SSC's within the 

scope of this program will continue to perform their intended functions consistent with the 

current licensing bases for the period of extended operation.

B2.1.12 Non-EQ Electrical Commodities Condition Monitoring Program 

Program Description

The Non-EQ Electrical Commodities Condition Monitoring Program is a new program that 

manages aging in selected non-EQ commodity groups within the scope of 10 CFR 54. 

Program activities are responsive to the NRC guidance provided in NUREG-1801 and 

industry standards. 

Palisades has identified each electrical commodity group requiring aging management for 

the three applicable sections of NUREG-1801 with the additional guidance provided in 

ISG-2 and draft ISGs-5, 15, 17 and 18, as follows:

• NUREG-1801 Program XI.E1, “Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements” requires a periodic 

inspection program that visually inspects accessible cables and connections in 

adverse localized environments with any identified degradation being evaluated and, 

as appropriate per plant procedures, entered into the plant corrective action process. 

The Non-EQ Electrical Commodities Condition Monitoring Program predominantly 

inspects for adverse aging from temperature, radiation, or moisture in the presence 

of oxygen.

Electrical pinned connectors are subject to pin corrosion from boric acid leakage, 

and periodic inspections are conducted in the Boric Acid Corrosion Program to 

preclude failures resulting from leakage.

The non-segregated bus in-scope of License Renewal was conservatively 

assessed, as discussed in draft ISG-17, to require aging management. The “weak 

link” in maintaining a non-aging environment was identified to be unchecked water 

leakage through the housing seals and bus bar connections due to thermal cycling. 

Appropriate inspection activities are included in the periodic inspections.

• NUREG-1801 Program XI.E2, “Electrical Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits” requires 

routine calibration tests to be performed to identify potential existence of aging 

degradation of cables and connections used in low-level signal applications that are 

sensitive to reduction in insulation resistance (IR) such as radiation monitoring and 

nuclear instrumentation. This is revised as discussed in draft ISG-15 which allows 
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Appendix B - Aging Management Programs

testing once every 10 years in lieu of TS surveillance test trending. The Non-EQ 

Electrical Commodities Condition Monitoring Program does subject sensitive 

instrumentation circuits, identified as requiring aging management, to periodic 

testing. 

• NUREG-1801 Program XI.E3, “Inaccessible Medium-Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements” requires a periodic test to 

provide an indication of the condition of the conductor insulation for those cables 

in-scope of License Renewal exposed to long periods of high moisture (greater than 

a few days at a time) and subjected to voltage stress (energized greater than 25% of 

the time). Periodic testing will be performed on these medium voltage cables to 

provide an indication of the insulation condition. The Non-EQ Electrical Commodities 

Condition Monitoring Program includes input from draft ISG-18 for periodic 

inspections of underground raceway manholes for the accumulation of water over 

the medium-voltage cables. Periodic inspections of underground manholes for the 

accumulation of water in the medium-voltage cable manholes will minimize the 

effects of water inside the underground manholes.

The fuse holders that were not inside active equipment were evaluated per draft 

ISG-5 and determined to have no aging effect that required management.

NUREG-1801 Consistency

The Non-EQ Electrical Commodities Condition Monitoring Program is consistent with 

NUREG-1801, Sections XI.E1, “Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements,” XI.E2, “Electrical Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits,” and XI.E3, “Inaccessible Medium-Voltage Cables Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements,” and guidance provided in 

ISG-2 and draft ISGs-5, 15, 17 and 18.

Exceptions to NUREG-1801

None.

Enhancements

A Non-EQ Electrical Commodities Condition Monitoring Program will be developed and 

implemented. Features of the program will include development and implementation of 

procedures to conduct periodic inspection of insulated cables and connectors, test 

sensitive instrumentation circuits, test medium voltage cables, and inspect manhole water 

levels.
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Appendix B - Aging Management Programs

Note that the element descriptions describe the program as it will be implemented. The 

program will be implemented prior to the period of extended operation. 

Aging Management Program Elements

The key elements of the Non-EQ Electrical Commodities Condition Monitoring Program 

are described below. The results of an evaluation of each key element against 

NUREG-1801, Sections XI.E1, “Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements,” XI.E2, “Electrical Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits,” and XI.E3, “Inaccessible Medium-Voltage Cables Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements,” and guidance provided in 

ISG-2 and draft ISGs-5, 15, 17 and 18, are also provided below. 

Scope of Program

Commodities within the scope of the Non-EQ Electrical Commodities Condition 

Monitoring Program include all non-EQ insulated cables and connections 

in-scope of License Renewal identified as requiring aging management, and any 

identified in the future to be in a newly-discovered localized adverse 

environment. The non-segregated phase bus, in-scope due to being a 

component of the SBO restoration path, is also included. 

The specific commodity groups included within the scope of the Non-EQ 

Electrical Commodities Condition Monitoring Program are as follows:

• Low-Voltage Cables and Connections

• Low-Voltage Electrical Pinned Connectors

• Low-Voltage Sensitive Instrumentation Cables

• Inaccessible Medium-Voltage Cables and Connections

• Non-Segregated Phase Bus and Connections

The aging effects/mechanisms managed by the Non-EQ Electrical Commodities 

Condition Monitoring Program for these electrical commodities are as follows:

• Cable and connection jacket/insulation degradation, such as embrittlement 

and cracking, on a circuit section or component exposed to a localized 

adverse environment typically involving high temperature, radiation, and 

moisture levels

• Corrosion (Loss of Material) of the non-segregated bus duct internal metal 

components, and loose connections creating localized heating leading to 

electrical failure 
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Appendix B - Aging Management Programs

• Loss of dielectric (insulation material) properties

• Promotion of water trees 

This element is consistent with NUREG-1801, Section XI.E1, “Electrical Cables 

and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements,” Section XI.E2, “Electrical Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits,” 

Section XI.E3, “Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements,” and guidance provided in 

ISG-2 and draft ISGs-5, 15, 17 and 18.

Preventive Actions

• Accessible Non-EQ Electrical Cables and Connections

This is a periodic visual inspection program and no actions are taken as part 

of this program to prevent or mitigate aging degradation. This element is 

consistent with NUREG-1801, Section XI.E1, “Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.”

• Non-EQ Electrical Cables Used in Sensitive Instrumentation Circuits

This is a periodic testing program to provide an indication of the condition of 

the conductor insulation and no actions are taken as part of this program to 

prevent or mitigate aging degradation. This element is consistent with 

NUREG-1801, Section XI.E2, “Electrical Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits” and guidance provided in draft ISG-15.

• Inaccessible Non-EQ Medium-Voltage Cables

The periodic testing program provides an indication of the condition of the 

conductor insulation. Periodic inspections of underground manholes, for the 

accumulation of water over the medium-voltage cables, will be conducted to 

minimize prolonged moisture conditions that promote the growth of water 

trees. This element is consistent with NUREG-1801, Section XI.E3, 

“Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements” and guidance provided in draft 

ISG-18.
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Appendix B - Aging Management Programs

Parameters Monitored, Inspected, and/or Tested

• Accessible Non-EQ Electrical Cables and Connections

A periodic visual inspection will be performed of accessible insulated cables 

and connections in-scope of License Renewal that may be subjected to a 

localized adverse environment. A localized adverse environment is defined 

as when any electrical insulation material is exposed to an aging 

environment that is significantly greater than the bounding design parameter 

value.

The periodic inspection shall also include visual inspection for signs of water 

leakage or contamination into the non-segregated bus through the housing 

seals and signs of localized heating potentially from loose internal electrical 

connections that may lead to electrical failure.

This element is consistent with NUREG-1801, Section XI.E1, “Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements” and guidance provided in ISG-2 and draft ISGs17 and 18.

• Non-EQ Electrical Cables Used in Sensitive Instrumentation Circuits

This is a periodic testing program to check insulation condition and no 

actions are taken as part of this testing program to prevent or mitigate aging 

degradation.

This element is consistent with NUREG-1801, Section XI.E2, “Electrical 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits” and guidance provided in 

draft ISG-15.

• Inaccessible Non-EQ Medium-Voltage Cables 

The periodic testing program provides an indication of the condition of the 

conductor insulation. Periodic inspections of underground manholes, for the 

accumulation of water over the medium-voltage cable levels, will be 

conducted to minimize the prolonged moisture conditions that promotes the 

growth of water trees.

This element is consistent with NUREG-1801, Section XI.E3, “Inaccessible 

Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements,” and guidance provided in draft ISG-18
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Appendix B - Aging Management Programs

Detection of Aging Effects

• Accessible Non-EQ Electrical Cables and Connections

A periodic inspection of accessible insulated cables and connections 

in-scope of License Renewal will be performed at least once every 10 years. 

As stated in NUREG-1801, this is an adequate inspection period to preclude 

failures of the conductor insulation/jacket and connection since experience 

has shown that aging degradation is a slow process. The first inspection for 

License Renewal will be completed before the period of extended operation. 

The accessible insulated cable and connections shall be visually inspected 

for insulation/jacket surface anomalies, such as discoloration, swelling, 

cracking, or surface contamination. Surface anomalies are a precursor 

indication of insulation degradation. If an unacceptable condition is identified 

for an insulated cable or connection, a determination would be made as to 

whether the same condition or situation is applicable to other accessible or 

inaccessible insulated cables and connections exposed to the same type of 

localized adverse environment.

This element is consistent with NUREG-1801, Section XI.E1, “Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements.”

• Non-EQ Electrical Cables Used in Sensitive Instrumentation Circuits

Cables used in nuclear instrumentation circuits are to be periodically tested 

(such as insulation resistance tests, time domain reflectometry tests, or other 

tests effective in determining cable insulation condition), at least once every 

ten years to provide an indication of the condition of the insulated conductor 

and connection, and the ability of the circuit to perform its intended function. 

This is an adequate period to identify cable and connection degradation to 

preclude excessive leakage currents since experience has shown that aging 

degradation is a slow process. The first tests for License Renewal will be 

completed before the period of extended operation. If an unacceptable 

condition or situation is identified, a determination shall be made as to 

applicability of the condition on other cables used in the nuclear 

instrumentation circuits. 

This element is consistent with NUREG-1801, Section XI.E2, “Electrical 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits” and guidance provided in 

draft ISG-15.
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Appendix B - Aging Management Programs

• Inaccessible Non-EQ Medium-Voltage Cables 

Identified in-scope inaccessible medium-voltage insulated cables (not 

designed for submergence) subject to long periods of high moisture 

conditions and voltage stress are tested (such as insulation resistance tests, 

time domain reflectometry tests, or other tests effective in determining cable 

insulation condition) at least once every 10 years to provide an indication of 

the condition of the conductor insulation and the ability of the cable to 

perform its intended function. As stated in NUREG-1801, this is an adequate 

period to preclude failures of the conductor insulation since experience has 

shown that aging degradation is a slow process. Periodic inspections 

(periodicity will be based on inspection results) of underground manholes, for 

the accumulation of water over the medium-voltage cable levels, will be 

conducted to minimize the prolonged moisture conditions that promotes the 

growth of water trees. The first tests and inspections for License Renewal will 

be completed before the period of extended operation. If an unacceptable 

condition or situation is identified, a determination would be made as to 

whether the same condition or situation is applicable to other inaccessible, 

in-scope, medium-voltage cables. 

This element is consistent with NUREG-1801, Section XI.E3, “Inaccessible 

Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements,” and guidance provided in draft ISG-18.

Monitoring and Trending

Trending actions are not included as part of this program because the ability to 

trend inspection or test results is limited and dependant on the specific type of 

test selected. 

This element is consistent with NUREG-1801, Section XI.E1, “Electrical Cables 

and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements,” Section XI.E2, “Electrical Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits,” 

Section XI.E3, “Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements,” and guidance provided in 

ISG-2 and draft ISGs-5, 15, 17 and 18.
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Appendix B - Aging Management Programs

Acceptance Criteria

• Accessible Non-EQ Electrical Cables and Connections

The accessible insulated cables and connections are to be free from 

unacceptable levels of surface anomalies, which indicate conductor or 

connection insulation degradation. Unacceptable degradation is defined as a 

noted condition or situation that, if left unmanaged, could lead to a loss of 

intended function.

This element is consistent with NUREG-1801, Section XI.E1, “Electrical 

Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements.”

• Non-EQ Electrical Cables Used in Sensitive Instrumentation Circuits

The acceptance criteria for each test is defined by the specific type of test 

performed and the specific circuit tested in the sensitive instrumentation 

circuits.

This element is consistent with NUREG-1801, Section XI.E2, “Electrical 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits” and guidance provided in 

draft ISG-15.

• Inaccessible Non-EQ Medium-Voltage Cables 

The acceptance criteria for each test is defined for the specific type of test 

performed and the specific cable tested. Periodic inspections of underground 

manholes, for the accumulation of water around medium-voltage cables, 

shall minimize time periods exposed to water.

This element is consistent with NUREG-1801, Section XI.E3, “Inaccessible 

Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements” and guidance provided in draft ISG-18.

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 
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to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Non-EQ 

Electrical Commodities Condition Monitoring Program at Palisades are 

evaluated. The Non-EQ Electrical Commodities Condition Monitoring Program 

is augmented, as appropriate, if these evaluations show that program changes 

will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Non-EQ Electrical Commodities Condition Monitoring Program 

issues are addressed in a timely manner and that age related deterioration of 

commodities within the scope of the Non-EQ Electrical Commodities Condition 

Monitoring Program will be effectively managed throughout the license renewal 

period.

Industry experience, as documented in SAND96-0344 “Aging Management 

Guideline for Commercial Nuclear Plants - Electrical Cables and Terminations” 

(Reference 7), has shown three main causes of cable and connection failures 

well before a nominal 40 or 60-year service life: 

• Cables routed/installed in abnormal configurations, outside the prescribed or 

normal design guidelines and installation design criteria, may fail due to 

being exposed to temperatures well above the expected normal ambient 

temperature. PVC insulated cable insulation failures are the most common 

cable insulation failures to occur due to high temperature and/or radiation 

environments.

• Sensitive instrumentation cable insulations (nuclear instrumentation & 

radiation monitoring) have less tolerance for “loss of material properties” that 

adversely affect the circuit signals.

• Medium voltage power cable failures occur because of water-treeing 

(moisture & voltage stress). 

Site-specific experience has shown that existing routine switchyard inspections 

detect loose connections in the switchyard. Existing periodic and routine 

switchyard inspections preclude failures of connections in the switchyard. 

Abnormal plant configurations at Palisades were found to produce localized 

adverse environments in some specific cases. A corrective action document 

identified signs of cable jacket damage from improper design/installation that led 

to a localized adverse environment for the cables. In addition, LER 84-10 

resulted from improper design and installation outside expected normal cable 

configurations. The Corrective Action Program corrected both plant 
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configurations to eliminate the identified localized adverse temperature 

environments.

A medium-voltage cable failure has occurred at Palisades from the possible 

effects of water-treeing. LER 96-002 did demonstrate that this commodity group 

warrants periodic testing to preclude or minimize future failures. Palisades has 

also experienced that the underground manholes for the medium-voltage cables 

in-scope of License Renewal have experienced moisture for periods greater 

than a few days at a time.

One cable commodity-related assessment was conducted to address 

over-loaded cable trays. This analysis calculated power cable ohmic heating 

temperatures in those overloaded tray sections and compared it against the 

respective cable temperature rating to ensure that proper operating conditions 

exist and are maintained. The results of this analysis were considered when 

reviewing the plant electrical cables and connections, and were addressed 

when assessing and identifying those cables requiring aging management 

during the extended period of operation.

Since the Non-EQ Electrical Commodities Condition Monitoring Program is a 

new program, no NRC inspection reports, audits, self assessments, or 

program-specific corrective actions are available.

This element is consistent with NUREG-1801, Section XI.E1, “Electrical Cables 

and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements,” Section XI.E2, “Electrical Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Used in Instrumentation Circuits,” 

and Section XI.E3, “Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements” with the additional guidance 

provided in ISG-2 and draft ISGs-5, 15, 17 and 18.

Conclusion

The Non-EQ Electrical Commodities Condition Monitoring Program is a new program that 

uses as its bases, various industry and NRC standards. A number of existing activities 

are being consolidated into this new program. This program is consistent with 

NUREG-1801, Section XI.E1, “Electrical Cables and Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements,” Section XI.E2, “Electrical Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits,” and Section XI.E3, “Inaccessible Medium-Voltage Cables Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements” with the additional 

guidance provided in ISG-2 and draft ISGs-5, 15, 17 and 18.
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The implementation of the Non-EQ Electrical Commodities Condition Monitoring Program 

provides reasonable assurance that aging effects will be managed such that the electrical 

commodities within the scope of this program will continue to perform their intended 

functions consistent with the current licensing bases for the period of extended operation.

B2.1.13 One-Time Inspection Program

Program Description

The One-Time Inspection Program is a new program that addresses potentially long 

incubation periods for certain aging effects, including various corrosion mechanisms, 

cracking, and selective leaching, and provides a means of verifying that an aging effect is 

either not occurring or progressing so slowly as to have negligible effect on the intended 

function of the structure or component. Hence, the One-Time Inspection Program 

provides methods for verifying an aging management program is not needed, verifying 

the effectiveness of an existing program, or determining that degradation is occurring 

which will require evaluation and corrective action.

The program includes (a) determination of appropriate inspection sample size, (b) 

identification of inspection locations, (c) selection of examination technique, with 

acceptance criteria, and (d) evaluation of results to determine the need for additional 

inspections or other corrective actions. The inspection sample includes locations where 

the most severe aging effect(s) would be expected to occur. Inspection methods may 

include visual (or remote visual), surface or volumetric examinations, or other established 

NDE techniques.

This program is used for a variety of purposes, including the following:

• To verify the effectiveness of water chemistry control for managing the effects of aging 

in stagnant or low-flow portions of piping exposed to a treated water environment.

• To manage the aging effects of loss of material due to aging mechanisms such as 

general, crevice, pitting, and galvanic corrosion; selective leaching; and MIC.

• To verify that cracking due to stress corrosion cracking or cyclic loading, in small bore 

(< 4" NPS) ASME class 1 piping, is not occurring.

• To verify, for components in the Compressed Air System, that there are no aging 

effects requiring management in the dry air environment.

The following Aging Management Programs credit the One-Time Inspection Program:

• Closed Cycle Cooling Water Program

• Water Chemistry Program
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• Fire Protection Program

• System Monitoring Program

NUREG-1801 Consistency

The One-Time Inspection Program is a new program that is consistent with, but includes 

exceptions to, NUREG-1801, Section XI.M32, “One-Time Inspection.” 

The One Time Inspection Program is consistent with NUREG 1801, Section XI.M33, 

“Selective Leaching of Materials,” and the portions of NUREG-1801, Section XI.M29, 

“Above Ground Carbon Steel Tanks” that are associated with the thickness measurement 

of tank bottom surfaces. The balance of Section XI.M29, “Above Ground Carbon Steel 

Tanks,” is implemented by the System Monitoring Program.

Exceptions to NUREG-1801

One exception is taken to the selected NUREG-1801 Program elements listed below. The 

specific exception being taken is also discussed in the corresponding element 

discussions below. It is repeated here for ease of review.

XI.M32, One Time Inspection

1. Section XI.M32.4 of NUREG-1801 requires plant-specific destructive examination of 

replaced piping due to plant modifications, or NDE that will detect cracking on the 

inside surfaces of the small bore piping. The current state of technology does not 

provide for an effective, reliable method of performing volumetric examinations of 

small bore socket welds. The combination of these one-time volumetric 

examinations of a 10% sample of Class 1 butt welds, 4” NPS and smaller, and the 

100% VT-2 examinations of all Class 1 and 2 HSS socket welds 2” NPS and under 

each refueling outage meets the intent of NUREG-1800 and -1801 to provide aging 

management for small-bore class 1 piping. This is generally in accordance with the 

position approved by the NRC for the Dresden/Quad Cities Nuclear Plants in their 

License Renewal Application and associated Safety Evaluation Report.

Enhancements

A One Time Inspection Program will be developed and implemented. Features of the 

program will include:

• Controlling procedure and implementing documents for activities associated with the 

program. This procedure will include a listing of all SSCs that credit this program for 

aging management, the aging effects and mechanisms being managed, the materials 

and environments for the SSCs, grouping and inspection sampling techniques to be 
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used, identification of inspection locations, acceptance criteria, inspection scope 

expansion criteria, and required actions for inspection results that fall outside 

acceptance criteria. Inspection results and evaluation of results should be documented, 

and records retrievable for the life of the plant.

• Controls to ensure that at least 10% of all Class 1 butt welds less than 4” NPS receive 

a volumetric examination prior to the end of, and within the last 5 years of, the current 

operating period, with the welds to be inspected chosen from the population of Class 1 

HSS butt welds from the RI-ISI Program. In addition, ensure that 100% of all Class 1 

and 2 HSS socket welds 2” NPS and under receive a VT-2 visual inspection each 

refueling outage.

Note that the element descriptions describe the program as it will exist after it has been 

implemented. The program is scheduled to be implemented prior to the period of 

extended operation. 

Aging Management Program Elements

The key elements of the One-Time Inspection Program are described below. The results 

of an evaluation of each key element against NUREG-1801, Sections XI.M32, “One-Time 

Inspection,” XI.M33, “Selective Leaching of Materials,” and the portions of XI.M29, 

“Above Ground Carbon Steel Tanks” associated with thickness measurement of tank 

bottom surfaces, are also provided below.

Scope of Program

Scope Related to XI.M32, One Time Inspection

The One-Time Inspection Program will be used to determine the acceptability of 

components that may be susceptible to various aging effects and to verify that 

unacceptable degradation is not occurring, thereby validating the effectiveness 

of an existing aging management program or confirming that there is no need to 

manage age-related degradation for the period of extended operation. 

The scope of this program includes the following:

• Verification of the effectiveness of the Water Chemistry Program for 

managing the effects of aging in stagnant or low flow portions of piping or 

components exposed to a treated water environment.

• Verification, for components in the Compressed Air System, that there are no 

aging effects requiring management in the dry air environment.
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• Verification that cracking is not occurring on small-bore (< 4" NPS) class 1 

piping.

• Verification of the effectiveness of the Closed Cycle Cooling Water Program 

for managing the effects of aging in stagnant or low flow portions of 

closed-cycle systems.

• For susceptible components, verification that selective leaching is not 

occurring, that selective leaching is occurring so slowly that the intended 

function will remain intact throughout the period of extended operation, or to 

determine that the rate of selective leaching will require corrective actions to 

maintain the intended function.

• Verification that primary coolant pump lube-oil leakoff piping and components 

are not degrading.

• Verification that existing programs are effective in controlling aging effects for 

the applicable components.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M32, “One-Time Inspection.” 

Scope Related to XI.M33, Selective Leaching

For selective leaching, which is a slow acting corrosion process, visual 

examinations and hardness tests are performed on a selected set of accessible 

components from each material type susceptible to selective leaching, including 

cast iron, brass, bronze, and aluminum-bronze, exposed to raw water, treated 

water, or groundwater environments, to verify that this aging mechanism is not 

occurring. Results of examinations and measurements are then evaluated to 

assess ability of components to perform their intended functions during the 

period of extended operation.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M33, “Selective Leaching of Materials.” 

Scope Related to XI.M29, Above-Ground Carbon Steel Tanks

For storage tanks supported on earthen or concrete foundations, corrosion may 

occur at inaccessible locations, such as the tank bottom. This program provides 

for a one-time verification that significant corrosion is not occurring at these 

inaccessible locations, by providing for measurement of storage tank bottom 

surface thickness for those storage tanks that credit this program for aging 

management during the extended operating period.
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This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces. 

Preventive Actions

Preventive Actions Related to XI.M32, One Time Inspection

The one-time inspection activities conducted as part of this program are 

independent of methods to mitigate or prevent degradation. 

This element is consistent with NUREG-1801, Section XI.M32, “One-Time 

Inspection.” 

Preventive Actions Related to XI.M33, Selective Leaching

The one-time visual inspections and any hardness measurements conducted as 

part of this program are independent of methods to mitigate or prevent 

degradation. It is noted that for those systems where fluid chemistry is controlled 

and monitored, this inspection will verify that fluid chemistry is effective in 

mitigating the applicable aging effects.

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.”

Preventive Actions Related to XI.M29, Above-Ground Carbon Steel Tanks

There are no measures implemented by the One-Time Inspection program for 

mitigating or preventing aging of the bottom surface of above-ground carbon 

steel tanks. It is noted that for those systems where fluid chemistry is controlled 

and monitored, this internal inspection will verify that fluid chemistry is effective 

in mitigating the applicable aging effects. 

Sealants or caulking at the tank/support structure interfaces, if used, are 

inspected for degradation. However, Palisades does not credit sealants or 

caulking for prevention of water intrusion underneath tanks.

This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces. 
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Parameters Monitored, Inspected, and/or Tested

Parameters Monitored, Inspected, and/or Tested Related to XI.M32, One Time 

Inspection

For verification of the effectiveness of the Water Chemistry Program and the 

Closed Cycle Cooling Water Program for stagnant or low flow areas and for 

verification of the effectiveness of the Diesel Fuel Monitoring and Storage 

Program, a visual examination or other appropriate NDE methodology, in 

accordance with the ASME code and 10 CFR 50 Appendix B, will be used to 

verify that degradation due to the applicable aging effects is not occurring. For 

verification that corrosion on the surfaces of piping and components is not 

occurring, visual (or remote visual) or volumetric examinations will be 

performed.

This element is consistent with NUREG-1801, Section XI.M32, “One-Time 

Inspection.”

Parameters Monitored, Inspected, and/or Tested Related to XI.M33, Selective 

Leaching

For selective leaching, which is a slow acting corrosion process, visual 

examinations and hardness testing are performed on a selected set of 

accessible components from each material type susceptible to selective 

leaching, including cast iron, brass, bronze, and aluminum bronze exposed to 

raw water, treated water, or ground water environments, to verify that this aging 

mechanism is not occurring. Results of examinations and measurements are 

then evaluated to assess ability of components to perform their intended 

functions during the period of extended operation. Any corrective actions will be 

implemented through the Corrective Action Program.

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.” 

Parameters Monitored, Inspected, and/or Tested Related to XI.M29, 

Above-Ground Carbon Steel Tanks

The One-Time Inspection Program provides for the inspection and thickness 

measurement of the bottom surface of selected above ground carbon steel 

tanks. 
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This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces. 

Detection of Aging Effects

Detection of Aging Effects Related to XI.M32, One Time Inspection

The Palisades One-Time Inspection Program includes a variety of inspection 

and testing activities that are designed to detect degradation due to aging 

effects prior to loss of intended function. The examination techniques will be 

visual, volumetric, or other appropriately established NDE methods. The NDE 

will be performed by qualified personnel following procedures consistent with 

the ASME Code and 10 CFR 50, Appendix B, “Quality Assurance Criteria for 

Nuclear Power Plants and Fuel Reprocessing Plants.” A representative sample 

of the component population will be chosen for inspection. The focus will be 

placed on bounding or lead components. Factors that will be considered when 

choosing components for inspection are time in service, accessibility, severity of 

operating conditions, and operating experience. 

To verify that the Water Chemistry Program and the Closed Cycle Cooling Water 

Program are mitigating the applicable aging effects in stagnant or low flow 

areas, visual examinations or other appropriate NDE methodology will be used 

when components are inspected.

The One-Time Inspection Program will ensure that at least 10% of all Class 1 

butt welds less than 4” NPS receive a volumetric examination prior to the end of 

the current operating period, with the welds to be inspected chosen from the 

population of Class 1 HSS butt welds from the RI-ISI Program. 

This element is consistent with, but includes an exception to, NUREG-1801, 

Section XI.M32, “One-Time Inspection.” The exception is:

• Section XI.M32.4 of NUREG-1801 requires plant-specific destructive 

examination of replaced piping due to plant modifications, or NDE that will 

detect cracking on the inside surfaces of the small bore piping. The current 

state of technology does not provide for an effective, reliable method of 

performing volumetric examinations of small bore socket welds. The 

combination of these one-time volumetric examinations of a 10% sample of 

Class 1 butt welds, 4” NPS and smaller, and the 100% VT-2 examinations of 

all HSS socket welds each refueling outage meets the intent of NUREG-1800 

and -1801 to provide aging management for small-bore class 1 piping. This is 
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generally in accordance with the position approved by the NRC for the 

Dresden/Quad Cities Nuclear Plants in their License Renewal Application 

and associated Safety Evaluation Report.

Detection of Aging Effects Related to XI.M33, Selective Leaching

For selective leaching which is a slow acting process, visual examinations and 

hardness tests are performed on a selected set of accessible components from 

each material type susceptible to selective leaching, including cast iron, brass, 

bronze, and aluminum-bronze, exposed to raw water, treated water, or ground 

water environments, to verify this aging mechanism is not occurring.

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.” 

Detection of Aging Effects Related to XI.M29, Above-Ground Carbon Steel 

Tanks

The One-Time Inspection Program provides for internal inspection and 

thickness measurements of the bottom surface of selected above-ground 

carbon steel tanks. 

This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces.

Monitoring and Trending

Monitoring and Trending Related to XI.M32, One Time Inspection

This new One-Time Inspection Program does not provide for monitoring and 

trending. However, follow up examinations will be required if unacceptable 

conditions are discovered, thus expanding the sample size and locations of 

inspections.

This element is consistent with NUREG-1801, Section XI.M32, “One-Time 

Inspection.”

Monitoring and Trending Related to XI.M33, Selective Leaching

There are no monitoring and trending activities for the one-time visual 

inspections, or any hardness tests performed, unless inspection or test results 

indicate degradation. However, follow up examinations will be required if 
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unacceptable conditions are discovered, thus expanding the sample size and 

locations of inspections.

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.”

Monitoring and Trending Related to XI.M29, Above-Ground Carbon Steel Tanks

The effects of corrosion of the inaccessible external surfaces of above-ground 

carbon steel tanks are detectable by thickness measurement of the tank bottom 

and are monitored and trended if significant material loss is detected during the 

one-time inspection.

This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces.

Acceptance Criteria

Acceptance Criteria Related to XI.M32, One Time Inspection

Any indications of degradation or unacceptable thickness measurements are 

evaluated through the corrective action program. The need to increase the 

sample population will also be evaluated when indications or relevant conditions 

of degradation are found.

This element is consistent with NUREG-1801, Section XI.M32, “One-Time 

Inspection.” 

Acceptance Criteria Related to XI.M33, Selective Leaching

Any indications of degradation or unacceptable thickness measurements are 

evaluated through the corrective action program. The need to increase the 

sample population will also be evaluated when indications or relevant conditions 

of degradation are found.

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.” 

Acceptance Criteria Related to XI.M29, Above-Ground Carbon Steel Tanks

Any indications of degradation or unacceptable thickness measurements are 

evaluated through the corrective action program. The need to increase the 

sample population will also be evaluated when indications or relevant conditions 

of degradation are found.
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This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces.

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the One-Time 

Inspection Program at Palisades are evaluated. 

The One-Time Inspection Program is a new program to be implemented before 

the current operating license expires. The NDE inspection methods that will be 

used, such as visual (or remote visual), surface or volumetric, or other 

established techniques, are consistent with industry practice.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that One-Time Inspection Program issues will be addressed in a timely 

manner and that age related deterioration of SSC within the scope of the 

One-Time Inspection Program will be effectively managed.

This element is consistent with NUREG-1801, Section XI.M32, “One-Time 

Inspection.”

This element is consistent with NUREG-1801, Section XI.M33, “Selective 

Leaching of Materials.”

This element is consistent with the portions of NUREG-1801, Section XI.M29, 

“Above-Ground Carbon Steel Tanks,” that are associated with the thickness 

measurement of tank bottom surfaces.

Conclusion

The One-Time Inspection Program is a new program that uses as its bases, various 

industry and NRC standards. This program is consistent with, but includes exceptions to, 

NUREG-1801, Section XI.M32, “One-Time Inspection.” This program is consistent with 

NUREG-1801, Section XI.M33, “Selective Leaching of Materials.” This program is 
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consistent with the portions of NUREG-1801, Section XI.M29, “Above-Ground Carbon 

Steel Tanks,” that are associated with the thickness measurement of tank bottom 

surfaces. A summary of each exception is provided above in the discussion of the 

affected program element. 

The implementation of the One-Time Inspection Program provides reasonable assurance 

that aging effects will be managed such that SSCs within the scope of this program will 

continue to perform their intended functions consistent with the current licensing bases 

for the period of extended operation.

B2.1.14 Open Cycle Cooling Water Program

Program Description 

The Open Cycle Cooling Water Program is an existing program that manages aging 

effects such as loss of material due to general, pitting, and crevice corrosion, erosion, 

MIC, and loss of heat transfer due to biological/corrosion product fouling (e.g., 

sedimentation, silting) caused by exposure of internal surfaces of metallic components to 

raw, untreated (e.g., service) water. The program scope includes activities to manage 

aging in the Service Water System (SWS) and Circulating Water system (CWS). The 

aging effects are managed through (a) monitoring and control of biofouling, (b) flow 

balancing and flushing, (c) heat exchanger testing (d) routine inspection and 

maintenance program activities to ensure that aging effects do not impair component 

intended function. Inspection methods include visual (VT), ultrasonic (UT), radiographic 

(RT), and eddy current (ECT). This program is responsive to NRC GL 89-13. 

Biofouling monitoring is accomplished by having the service water pump intake bay 

inspected each refueling outage by divers for biofouling species. Periodic maintenance 

activities for the inspection of safety-related heat exchangers include steps to take 

samples for analysis and inspection for biofouling species and Microbiologically 

Influenced Corrosion (MIC). Biofouling control is accomplished by chlorinating the SWS 

and CWS to mitigate the effects of biological fouling. Chemical concentration conforms to 

the requirements set by the Michigan Department of Environmental Quality in Palisades' 

National Pollutant Discharge Elimination System (NPDES) permit MI0001457. 

To verify that components receive FSAR required flows, the Service Water System is 

balanced each refueling outage as per plant procedures. The performance of this test 

assures that flows set during testing meet the requirements set by the plant's FSAR for a 

Design Basis Accident. The testing also fulfills the recommended actions that other 

components be tested once per refueling outage to assure that components are not 

fouled or clogged. The actions to periodically flush piping and flow balance the Service 
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Water System fulfill the recommendation suggested by control technique 2 of GL 89-13 to 

assure that fouling sediment is flushed from piping.

The heat exchanger testing program main goals are to establish a framework to assess 

plant heat exchanger condition:

• To select heat exchangers requiring immediate attention and apply realistic plugging 

criteria.

• To identify problems and perform repairs where necessary to maintain the integrity of 

heat exchangers.

• To establish a sound basis for heat exchanger inspection intervals.

• To apply effective Non-Destructive Evaluation and Testing (NDE)

• To utilize a database management program to acquire, analyze, trend, and store 

data.

• To plan heat exchanger replacement.

Palisades has established a routine inspection and maintenance monitoring program for 

service water piping and components to ensure that corrosion, erosion, silting, and 

biofouling cannot degrade the performance of the safety related systems supplied by 

service water to where they are unable to perform their intended functions. This program 

has the following objectives:

• To remove excessive accumulations of biofouling agents, corrosion products, and 

silt.

• To repair defective protective coatings and corroded piping and components that 

could adversely affect performance of their intended safety functions.

NUREG-1801 Consistency

The Open Cycle Cooling Water Program is consistent with NUREG-1801, Section 

XI.M20, “Open-Cycle Cooling Water System.” 

Exceptions to NUREG-1801

None.

Enhancements

None
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Aging Management Program Elements

The key elements of the Open Cycle Cooling Water Program are described below. The 

results of an evaluation of each key element against NUREG-1801, Section XI.M20, 

“Open-Cycle Cooling Water System” are also provided. 

Scope of Program

The purpose of the Open Cycle Cooling Water Program is to perform periodic 

inspections and/or tests to detect degradation, monitoring of system integrity, 

and evaluations required to maintain reliability and operability of systems and 

components within its scope. This is accomplished by following the guidelines 

provided in GL 89-13, which include (a) monitoring and control of biofouling, (b) 

flow balancing and flushing, (c) heat exchanger testing, and (d) routine 

inspection and maintenance program activities to ensure that aging effects due 

to fouling and various corrosion mechanisms do not impair component intended 

function. 

GL 89-13 required a walkdown inspection to ensure compliance with the 

licensing basis and a review of maintenance, operating, and training practices 

and procedures. These requirements were satisfied as part of the response to 

the generic letter. These requirements are not associated with the on-going 

management of aging effects and there are no corresponding activities in the 

Open Cycle Cooling Water Program.

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Preventive Actions

Plant procedures implement commitments to GL 89-13 at Palisades. This 

program includes activities for condition and performance monitoring, and 

biofouling monitoring and control. Activities are in place to have the service 

water pump intake bay inspected and cleaned each refueling outage by divers. 

Periodic maintenance activities for the inspection of safety related heat 

exchangers include steps for sampling and analysis for biofouling species and 

MIC. Additionally, programs are in place for Chlorination and molluscicide 

treatment of the Service Water and Circulating Water Systems.

Sections of SWS that have been identified as being susceptible to fouling due to 

sediment settling have been evaluated and are periodically flushed where 

necessary. Radiography (RT) is utilized in selected piping sections to validate 
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that significant silting/sanding or corrosion product buildup is not occurring that 

would cause flow blockage in excess of design requirements.

NUREG-1801, Section XI.M20.2 states that, “The system components are 

constructed of appropriate materials and lined or coated to protect the 

underlying metal surfaces from being exposed to aggressive cooling water 

environments.” NUREG-1801, Section XI.M20.3 states that, “Cleanliness and 

material integrity of piping, components, heat exchangers, and their internal 

linings or coatings (when applicable) that are part of the OCCW system or that 

are cooled by the OCCW system are periodically inspected, monitored or tested 

to ensure heat transfer capabilities”. Neither SWS nor CWS has internal linings 

or coatings on in-scope components. The CWS and SWS piping included within 

the scope of this program are constructed of carbon steel that is not lined or 

coated on the interior side. 

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Parameters Monitored, Inspected, and/or Tested

The parameters monitored, inspected, or tested vary depending on the 

component and are based on commitments to GL 89-13 and operating 

experience. Some heat exchangers are visually inspected, some have the 

temperature of the affected components monitored for trending and acceptability 

of performance of Service Water System cooling, some are inspected to verify 

that service water is flowing through the coolers, and some are tested for heat 

transfer capability. Pressure drop across some components is measured and 

trended, while some components are periodically cleaned and inspected. 

Various actions are undertaken to verify system or component performance will 

not be compromised by the accumulation of biofouling agents, corrosion 

products, and silt. Cleanliness and material integrity of piping, components, and 

heat exchangers are periodically inspected, monitored, or tested to ensure heat 

transfer capabilities. The program ensures (a) removal of biofouling agents, 

corrosion products, and silt, and (b) detection of corroded piping and 

components that could adversely affect the performance of their intended safety 

function. The activities performed under this program were implemented as a 

result of GL 89-13, and their continued performance will ensure that the Service 

Water System will continue to perform its intended function.

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”
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Detection of Aging Effects

Plant procedures implement commitments to GL 89-13, which requires 

establishing a routine inspection and maintenance program for Service Water 

System piping and components such that corrosion, erosion, silting, and 

biofouling do not degrade the performance of the safety-related systems 

supplied by service water. The inspection program verifies that the system will 

perform its design basis heat removal function by ensuring that sufficient water 

flow is maintained.

In addition to the inspections described above, the plant has a biofouling and 

Microbiologically Influenced Corrosion (MIC) control program described in plant 

procedures. The program consists of system inspections, vendor reports, 

deposit, and coupon analyses, etc., which are performed and subsequently 

documented in corrosion reports to aid in early detection and mitigation of 

biofouling and MIC-related concerns.

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Monitoring and Trending

The scope of inspections and heat transfer tests are in accordance with 

Palisades' commitments under GL 89-13. Selected components have the 

service water flow checked, and/or are flushed, to reduce biofouling or 

sedimentation build-up. Component degradation, such as pipe wall thinning and 

silt build-up, is measured and recorded to predict the expected remaining life of 

the component such that corrective actions can be taken prior to a loss of 

intended function. 

Examination and Maintenance Frequency and Locations:

Safety related heat exchangers are inspected, cleaned and tested at various 

periodicities specified in plant procedures. The service water pump intake bay is 

inspected each refueling outage by divers for biofouling species. Selected 

locations in the Service Water system are flushed periodically as described in 

plant procedures. The SWS and Circulating Water System (CWS) are normally 

chlorinated when on line or during outages to control MIC and biofouling. As 

water conditions change, continuous chlorination and/or molluscicide treatments 

will be performed on an as needed basis. 
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Analysis of Results:

Results for visual, chemical and mechanical inspection of heat exchangers are 

documented and retained in plant records. Inspection results of safety-related 

service water piping are documented and retained in plant records. A summary 

Raw Water Corrosion Program Report on the effectiveness of the program is 

completed after each refueling outage and includes the previous operational 

cycle. Inspection activity results are reviewed for trending purposes to adjust 

inspection, performance testing, and maintenance frequencies, as necessary.

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Acceptance Criteria

The acceptance criteria are specified in the procedures that control the 

inspections of components. Pipe and tubing wall thickness is measured and 

compared to minimum required wall thickness. Biofouling is removed or reduced 

as part of the activities performed under this program. Acceptance criteria are 

based on maintaining the system free of significant sediment and biofouling 

build-up, and able to perform its intended functions. 

This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events, and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Open 

Cycle Cooling Water Program at Palisades are evaluated. The Open Cycle 

Cooling Water Program is augmented, as appropriate, if these evaluations show 

that program changes will enhance program effectiveness.
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A review of industry operating experience associated with the Open Cycle 

Cooling Water Program and aging reveals issues and instances related to:

• Accumulations of silt and corrosion products in service water piping, valves, 

and heat exchangers

• Accumulation of biological growth (mussels, clams, and shells) in service 

water piping, valves and heat exchangers

• MIC causing pitting attack of carbon steel and stainless steel service water 

piping, pump casings, and 90/10 Cu/Ni heat exchanger tubes

A review of plant specific operating experience related to the Open Cycle 

Cooling Water Program and aging revealed that the following issues have been 

addressed:

• Defective tubes in the Main Condenser that required plugging due to MIC

• Control Room Condensing Unit Condenser Drain Plug severely corroded 

due to MIC

• Large Zebra Mussel accumulation near traveling screens and inside intake 

piping

• Blockage of heat exchanger and cooler tubing

• Corroded service water piping at threaded connections

• Pinhole leaks in service water piping due to MIC

• Switch failure due to sediment and corrosion (galvanic) blocking sensing line

• Tubercles growing in carbon steel service water piping

• Erosion of pipes, cooling coils, and heat exchanger tubes causing service 

water leaks

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Open Cycle Cooling Water Program issues are addressed in a 

timely manner and that age related deterioration of SSC within the scope of the 

Open Cycle Cooling Water Program will be effectively managed throughout the 

license renewal period.

The Palisades Open Cycle Cooling Water Program has demonstrated on 

several occasions that it provides reasonable assurance that aging effects are 

being managed for Open Cycle Cooling Water Program SSC. This has been 

demonstrated through NRC inspection reports, audits, self-assessments, and 

the Corrective Action Program.
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This element is consistent with NUREG-1801, Section XI.M20, “Open-Cycle 

Cooling Water System.”

Conclusion

The Open Cycle Cooling Water Program is an existing program that uses as its 

bases, various industry and NRC standards. This program is consistent with 

NUREG-1801, Section XI.M20, “Open-Cycle Cooling Water System.”

Reports of recent internal and external assessments of the program have been 

reviewed. These reports demonstrate that the program has effectively identified 

and dispositioned issues that could have led to degraded conditions. It is 

concluded that the Open Cycle Cooling Water Program has been effective in 

maintaining the intended functions of the affected long-lived, passive SSCs.

The continued implementation of the Open Cycle Cooling Water Program 

provides reasonable assurance that aging effects will be managed such that 

SSCs within the scope of this program will continue to perform their intended 

functions consistent with the current licensing bases for the period of extended 

operation.

B2.1.15 Overhead Load Handling Systems Inspection Program 

Program Description

The Overhead Load Handling Systems Inspection Program is an existing program that 

provides for inspections of the structural components and rails of cranes and fuel 

handling machines associated with heavy load handling that are subject to the 

requirements of NUREG-0612 and are within the scope of license renewal requiring 

aging management. For Palisades these are the Containment Building Polar Crane, the 

Spent Fuel Pool Overhead Crane, the Containment Building jib and boom cranes, and the 

reactor and spent fuel pool fuel handling machines. These cranes comply with the 

Maintenance Rule requirements provided in 10 CFR 50.65. The Overhead Load Handling 

Systems Inspections Program is primarily focused on structural components that make 

up the bridge and trolley of the overhead cranes that are within the scope of 

NUREG-0612.

NUREG-1801 Consistency

The Overhead Load Handling Systems Inspection Program is an existing program that is 

consistent with, but includes exceptions to, NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.”
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Exceptions to NUREG-1801

One exception is taken to selected NUREG-1801 Program elements. The specific 

exception is also discussed in the corresponding element discussion. The exception is 

repeated here for ease of review.

1. Parameters Monitored, Inspected, and/or Tested: NUREG-1801, Section XI.M23, 

Parameters Monitored/Inspected section, states, “The number and magnitude of lifts 

made by the crane are also reviewed.” Palisades does not track the number and 

magnitude of all lifts made by cranes. Administrative controls are implemented to 

ensure that only allowable loads are handled and fatigue failure of structural 

elements is not expected. A time-limited aging analysis report (Section 4.7.1) 

concludes that, at the current service level, there are no fatigue concerns for the 

Containment polar crane and the Spent Fuel Pool crane as both the Containment 

polar and Spent Fuel Pool crane can not realistically approach the 20,000 to 100,000 

rated lifts assumed for its design evaluation during the extended operating period. 

Frequent inspections of cranes for indications of functional failures are conducted. 

However, Palisades does track the number and magnitude of lifts made that exceed 

the rated capacity of the cranes. These are called “engineered lifts,” follow the 

requirements of ANSI B30.2, and are generally only used for the polar crane lifting 

the reactor head with lead shielding. These lifts are numerically restricted, and 

evaluated by engineering analysis. This exception is generally in accordance with 

the position taken by the Dresden and Quad Cities Nuclear Power Stations in their 

License Renewal Application, and subsequently approved by the Nuclear 

Regulatory Commission in the associated Safety Evaluation Report.

Enhancements

One enhancement is planned to bring the Overhead Load Handling Systems Inspection 

Program into conformance (with exception noted above) with the NUREG-1801 program 

description. The enhancement is:

Scope of Program, Detection of Aging Effects, and Acceptance Criteria: Revise crane and 

fuel handling machine inspection procedures to specifically inspect for general corrosion 

on passive components making up the bridge, trolley, girders, etc., and to inspect rails of 

Bridge Cranes for wear. Revision should also include documentation of results of these 

inspections, acceptance criteria, and qualification requirements for inspectors and crane 

supervisors.

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for completion 

prior to the period of extended operation. 
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Aging Management Program Elements

The key elements of the Overhead Load Handling Systems Inspection Program are 

described below. The results of an evaluation of each key element against NUREG-1801, 

Section XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems” are also provided.

Scope of Program

This program manages the effects of general corrosion on the crane and trolley 

structural components, and the effects of wear on the rails, for those overhead 

cranes, and fuel handling machines that are within the scope of license renewal 

and subject to the requirements of NUREG-0612. The aging 

effects/mechanisms managed by the Overhead Load Handling Systems 

Inspection Program are loss of material due to general corrosion and/or wear. 

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.”

Preventive Actions

There are no preventive actions associated with this program. This program is 

an inspection program.

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.” 

Parameters Monitored, Inspected, and/or Tested

For the SSC within the scope of license renewal, the inspections include 

structural bolting, rail wear, and corrosion of structural components of the bridge 

and trolley.

This element is consistent with, but includes an exception to, NUREG-1801, 

Section XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems.” The exception is:

• NUREG-1801, Section XI.M23, Parameters Monitored/Inspected section, 

states, “The number and magnitude of lifts made by the crane are also 

reviewed.” Palisades does not track the number and magnitude of all lifts 

made by cranes. Administrative controls are implemented to ensure that only 

allowable loads are handled and fatigue failure of structural elements is not 
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expected. A time-limited aging analysis report (Section 4.7.1) concludes that, 

at the current service level, there are no fatigue concerns for the 

Containment polar and the Spent Fuel Pool cranes, as both the Containment 

polar and Spent Fuel Pool cranes can not realistically approach the 20,000 to 

100,000 rated lifts assumed for its design evaluation during the 60 year 

extended operating period. Frequent inspections of cranes for indications of 

functional failures are conducted. However, Palisades does track the number 

and magnitude of lifts made that exceed the rated capacity of the cranes. 

These are called “engineered lifts,” follow the requirements of ANSI B30.2, 

and are generally only used for the polar crane lifting the reactor head with 

lead shielding. These lifts are numerically restricted, and evaluated by 

engineering analysis. This exception is generally in accordance with the 

position taken by the Dresden and Quad Cities Nuclear Power Stations in 

their License Renewal Application, and subsequently approved by the 

Nuclear Regulatory Commission in the associated Safety Evaluation Report.

Detection of Aging Effects

The Palisades Overhead Load Handling Systems Inspection Program includes 

visual inspection and testing activities that are designed to detect degradation 

due to aging effects prior to loss of intended function. 

Crane rails and structural components are visually inspected on a routine basis 

for degradation. Functional tests are also performed to assure their integrity 

prior to use. Quarterly and Annual Inspections and Functional Tests of overhead 

load handling systems are performed under the direct supervision of trained 

Palisades Supervisors.

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.”

Monitoring and Trending

Monitoring and trending are not required as part of the Overhead Load Handling 

Systems Inspection Program. 

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.” 
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Acceptance Criteria

The Containment Polar Crane and the Spent Fuel Pool Overhead Crane were 

originally designed and installed in accordance with Electric Overhead Crane 

Institute (EOCI) Specification #61. The subsequent NUREG-0612 heavy loads 

evaluation of the polar crane was performed to CMAA 70 (1975). The 

minimally-rated components are CMAA 70 Service Level A.

The Spent Fuel Pool Crane was upgraded to 110 T for dry cask storage. This 

included a NUREG-0612 evaluation to CMAA-70 Service Level A design 

criteria, and replacement of the trolley with a 110 T single-failure-proof trolley.

Any significant visual indication of loss of material due to corrosion of crane 

structural members or rail wear is evaluated according to vendor 

recommendations and/or applicable industry good practice and standards.

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Overhead 

Load Handling Systems Inspection Program at Palisades are evaluated. The 

Overhead Load Handling Systems Inspection Program is augmented, as 

appropriate, if these evaluations show that program changes will enhance 

program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Overhead Load Handling Systems Inspection Program issues are 

addressed in a timely manner and that age related deterioration of SSC within 

the scope of the Overhead Load Handling Systems Inspection Program will be 

effectively managed throughout the license renewal period.
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A review of industry operating experience associated with the Overhead Load 

Handling Systems Inspection Program revealed no issues and instances related 

to aging.

A review of plant specific operating experience related to the Overhead Load 

Handling Systems Inspection Program and aging revealed that the following 

issues have been addressed:

• Damage to Spent Fuel Handling Machine Hoist Cable

• Movement identified on Containment Hatch Crane's base structure 

• Containment crane rail attachment bolt grout pads cracked

• Load limit of containment crane exceeded during head lift

• Containment crane bridge rail splice weld cracks

The Palisades Overhead Load Handling Systems Inspection Program has 

demonstrated that it provides reasonable assurance that aging effects are being 

managed for the Overhead Load Handling Systems Inspection Program SSC. 

No recent external or internal audits/assessments were conducted on this 

program.

This element is consistent with NUREG-1801, Section XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems.” 

Conclusion

The Overhead Load Handling Systems Inspection Program is an existing program that 

uses as its bases, various industry and NRC standards. This program is consistent with, 

but includes exceptions to, NUREG-1801, Section XI.M23, “Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems.” A summary of 

each exception is provided in the discussion of the affected program attribute above. 

It is concluded that the Overhead Load Handling Systems Inspection Program has been 

effective in maintaining the intended functions of the affected long-lived, passive SSCs.

The continued implementation of the Overhead Load Handling Systems Inspection 

Program provides reasonable assurance that aging effects will be managed such that 

SSCs within the scope of this program will continue to perform their intended functions 

consistent with the current licensing bases for the period of extended operation.
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Appendix B - Aging Management Programs

B2.1.16 Reactor Vessel Integrity Surveillance Program 

Program Description

The Reactor Vessel Integrity Surveillance Program is an existing program that manages 

the aging effect reduction of fracture toughness due to neutron embrittlement of the low 

alloy steel reactor vessel. Monitoring methods will be in accordance with 10 CFR 50, 

Appendix H. This program includes (a) capsule insertion, withdrawal and materials 

testing/evaluation, (including upper shelf energy and RTNDT determinations), (b) fluence 

and uncertainty calculations, (c) monitoring of Effective Full Power Years (EFPY), (d) 

development of pressure temperature limitations, and (e) determination of low 

temperature overpressure protection (LTOP) set points. The program ensures the reactor 

vessel materials (a) meet the fracture toughness requirements of 10 CFR 50, Appendix G, 

and (b) have adequate margins against brittle fracture caused by Pressurized Thermal 

Shock (PTS) in accordance with 10 CFR 50.61.

NUREG-1801 Consistency

The Reactor Vessel Integrity Surveillance Program is consistent with NUREG-1801, 

Section XI.M31, “Reactor Vessel Surveillance.” The Reactor Vessel Integrity Surveillance 

Program is also an existing program that contains the applicable elements of an 

acceptable aging management program as described in Branch Technical Position 

RLSB-1, “Aging Management Review-Generic,” which is included in Appendix A of 

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for 

Nuclear Power Plants.”

Exceptions to NUREG-1801

None.

Enhancements

1. The Reactor Vessel Integrity Surveillance Program will ensure that 

pressure-temperature and LTOP curves are updated to reflect the additional neutron 

fluence accumulated during the extended operating period. Curves will be updated and 

submitted to NRC for approval prior to the period of extended operation

2. Document and establish the requirement to save and store all pulled and tested reactor 

vessel surveillance capsules for future reconstitution use.

3. Evaluate and revise as necessary, the surveillance capsule withdrawal and testing 

schedule of FSAR Table 4-20 such that at least one capsule remains in the reactor vessel 
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and is tested during the period of extended operation to monitor the effects of long-term 

exposure to neutron irradiation.

4. Develop a program level procedure to implement and control Technical Specification 

and FSAR activities associated with the Reactor Vessel Integrity Surveillance Program, 

including activities associated with surveillance capsules, pressure-temperature limit 

curves, LTOP setpoints, neutron embrittlement calculation methodology, neutron fluence 

calculations and control, and documentation requirements. The procedure title should be 

“Reactor Vessel Integrity Surveillance Program.”

Aging Management Program Elements

The elements of the Reactor Vessel Integrity Surveillance Program are described below. 

The results of an evaluation of each element against NUREG-1801, Section XI.M31, 

“Reactor Vessel Surveillance,” are provided below. However, the NUREG-1801 program 

does not define the ten elements similar to other programs. Therefore, the results of an 

evaluation of each key element against the appropriate ten elements described in Branch 

Technical Position RLSB-1, “Aging Management Review-Generic,” which is included in 

Appendix A of NUREG-1800, “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants,” is also provided below.

Scope of Program

The Reactor Vessel Integrity Surveillance Program applies to the Palisades 

reactor pressure vessel.

The program controls the development of surveillance capsule insertion and 

withdrawal schedules and capsule materials testing. The surveillance program 

meets the requirements of ASTM E 185. The results of capsule materials 

testing, fluence analysis, and EFPY monitoring are used to predict the effects of 

neutron embrittlement through the end of extended life (EOEL). The results of 

capsule tests, fluence analysis, and EFPY monitoring are also used to 

determine compliance with the PTS screening criteria of 10 CFR 50.61. 

Fluence and Uncertainty Calculations are performed for the Palisades reactor 

vessel in accordance with RG 1.190, “Calculational and Dosimetry Methods for 

Determining Pressure Vessel Neutron Fluence.” The results are used as an 

input to embrittlement predictions.

EFPY monitoring is accomplished using operations data for the Palisades 

reactor. The results are used to project the fluence corresponding to specific 

values of EFPY.
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The Reactor Vessel Integrity Surveillance Program controls the development of 

pressure and temperature limit curves in accordance with 10 CFR 50, Appendix 

G requirements. The methods of ASME Section XI, Appendix G are used to 

determine pressure and temperature limits. The fracture toughness used in 

calculating PT limits is determined as a function of the difference in temperature 

from RTNDT. RG 1.99, Revision 2, “Radiation Embrittlement of Reactor Vessel 

Materials” is used to determine RTNDT. 

The Reactor Vessel Integrity Surveillance Program requires the calculation of 

LTOP set points for the Palisades primary coolant system. These set points 

ensure that an LTOP event will not increase the probability of brittle fracture of 

the reactor vessel. LTOP set points include the maximum pressure allowed 

before the LTOP system actuates to relieve the pressure, and the temperature 

below which the LTOP system must be effective. These pressures and 

temperatures are determined using the method of ASME Section XI, Appendix 

G.

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.

Preventive Actions

This surveillance program determines neutron embrittlement for upper shelf 

energy and pressure temperature limits for 60 years in accordance with the RG 

1.99, Revision 2, “Radiation Embrittlement of Reactor Vessel Materials,” and is 

not preventive in nature. However, there are certain activities within this program 

that provide necessary information to prevent operation of the reactor pressure 

vessel outside limits.

Calculations demonstrating that the Palisades reactor vessel meets the PTS 

screening criteria of 10 CFR 50.61 ensure the probability of brittle fracture of the 

reactor vessels during a PTS event is acceptably low. 

Fluence and uncertainty calculations do not constitute preventative actions.

EFPY monitoring is a monitoring activity, not a preventative action.

The development of, and operation within, P-T limit curves minimizes the 

probability of brittle fracture of the reactor vessel during normal operation. 

The LTOP system with the actuation setpoints and operational restrictions 

established by the LTOP analysis, minimizes the probability of an LTOP event, 

and therefore, helps to minimize the probability of reactor vessel brittle fracture.
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This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.

Parameters Monitored, Inspected, and/or Tested

The program monitors the effects of neutron irradiation on the Palisades reactor 

vessel beltline materials. Fracture toughness of beltline materials is indirectly 

monitored through measurement of the impact energy of Charpy V Notch (CV) 

specimens, made from representative materials from the reactor vessel beltline 

regions. The surveillance capsules also contain neutron dosimetry that monitors 

the amount of neutron fluence received by the test specimens. The vessel 

fluence is then used to calculate RTNDT using the method of RG 1.99, Revision 

2.

Effective Full Power Years (EFPY) are monitored and used to predict the fluence 

that the vessel will accumulate at some future time, which is then used to predict 

change in RTNDT and upper shelf energy (USE).

LTOP system relief valve operation is monitored to determine whether an LTOP 

event could have occurred had the LTOP system been inoperable. Operation 

within the P-T limits is also monitored.

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.

Detection of Aging Effects

Aging effects are detected through testing of surveillance materials. CV tests are 

performed to determine the decrease in USE and increase in transition 

temperature RTNDT, for materials that closely match reactor vessel beltline. 

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.

Monitoring and Trending

Monitoring of reactor vessel beltline fracture toughness is accomplished through 

testing of surveillance specimens from surveillance capsules that are 

periodically withdrawn from the vessel. Trending is accomplished through the 

RG 1.99, Revision 2 methods for projection of RTNDT and USE. Projection of the 
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increase in RTNDT and the decrease in USE provides early indication if the 

fracture toughness properties of the reactor vessel beltline materials will fail to 

meet regulatory requirements. The RTNDT projection is compared to the PTS 

screening criteria of 270°F for plates, forgings, and axial welds and 300°F for 

circumferential welds specified in 10 CFR 50.61. USE projections are compared 

against the requirement to maintain 50 ft-lbs or greater given by 10 CFR 50, 

Appendix G (see Section 4.2.1).

Fluence estimates from capsules are trended to verify that results are 

adequately represented by fluence models, and to project fluence for future 

dates. 

EFPY are monitored and trended to allow the EFPY for particular calendar 

dates, such as the end of the current and extended license periods, to be 

projected, and to establish deadlines for revising P-T curves that are valid only 

to a particular number of EFPY. These projections will be extended to a number 

of EFPY corresponding to the end of life - extended (EOLE).

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.

Acceptance Criteria

The upper shelf energy of the most limiting material in the reactor vessel beltline 

must remain above 50 ft-lbs until the end of extended life, using the methods of 

RG 1.99, Revision 2. The RTNDT of the most limiting material in the reactor 

vessel beltline must not exceed the PTS screening criteria specified by 10 CFR 

50.61 (270°F for plates, forgings, and axial welds, and 300°F for circumferential 

welds).

The acceptance criteria for P-T curves is that the flaw stability criteria of ASME 

Section XI, Appendix G, are met for all normal operating conditions as required 

by 10 CFR 50, Appendix G. 

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.
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Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements and with the corresponding elements described 

in the Branch Technical Position. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Reactor 

Vessel Integrity Surveillance Program at Palisades are evaluated. The Reactor 

Vessel Integrity Surveillance Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Reactor Vessel Integrity Surveillance Program issues are 

addressed in a timely manner and that age related deterioration of SSC within 

the scope of the Reactor Vessel Integrity Surveillance Program will be effectively 

managed throughout the license renewal period.

A search of industry and plant operating experience related to the Reactor 

Vessel Integrity Surveillance Program was performed. This search revealed the 

following issues relevant to Palisades Reactor Vessel Integrity Surveillance 

Program:

GL 92-01, Revision 1, “Reactor Vessel Structural Integrity,” and Supplement 1 to 

GL 92-01, Revision 1, “Reactor Vessel Structural Integrity.” Palisades' response 

to these documents has been incorporated into the Reactor Vessel Integrity 

Surveillance Program.

A review of NRC Inspection Reports, QA Audit/Surveillance Reports, and Self 

Assessments since 1999 revealed no issues or findings that could impact the 

effectiveness of the Reactor Vessel Surveillance Program.

This element is consistent with NUREG-1801, Section XI.M31, “Reactor Vessel 

Surveillance,” and with the corresponding element described in the Branch 

Technical Position.
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Conclusion

The Reactor Vessel Integrity Surveillance Program is an existing program that uses as its 

bases, various industry and NRC standards. This program is consistent with 

NUREG-1801, Section XI.M31, “Reactor Vessel Surveillance,” and with the 

corresponding elements described in the Branch Technical Position.

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Reactor Vessel 

Integrity Surveillance Program has been effective in maintaining the intended functions of 

the affected long-lived, passive SSCs.

The continued implementation of the Reactor Vessel Integrity Surveillance Program 

provides reasonable assurance that aging effects will be managed such that SSCs within 

the scope of this program will continue to perform their intended functions consistent with 

the current licensing bases for the period of extended operation.

B2.1.17 Reactor Vessel Internals Inspection Program

Program Description

The Reactor Vessel Internals Inspection Program is an existing program that manages 

the aging effects for reactor vessel internals. The program provides for (a) Inservice 

Inspection (ISI) in accordance with ASME Section XI requirements, including 

examinations performed during the 10-year ISI examination; (b) Participation in industry 

initiatives to evaluate the significance of void swelling; (c) Monitoring and control of 

reactor coolant water chemistry in accordance with the EPRI guidelines in TR-105714 

(see Water Chemistry Program) to mitigate SCC or IASCC; and (d) Participation in 

industry initiatives that will generate additional data on aging mechanisms relevant to RVI 

and develop appropriate inspection techniques to permit detection and characterization of 

features of interest.

Void Swelling is an aging mechanism for Reactor Vessel Internal components that has 

the potential to cause two aging effects: 1. Reduction in Fracture Toughness, and 2. 

Changes in Dimensions.

Reduction in Fracture Toughness due to Void Swelling

The Aging Management Review for the Reactor Vessel Internals includes a discussion of 

Reduction in Fracture Toughness due to Void Swelling, and concludes that Palisades 

does not consider void swelling to be a factor in the evaluation of reduction in fracture 

toughness.
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Changes in Dimensions due to Void Swelling

The potential significance of void swelling will be assessed through monitoring industry 

operating experience. The PWR industry (including Palisades), through EPRI, is currently 

researching the potential significance of void swelling. If judged to be significant, 

evaluations of the need for augmented examinations for the effects of void swelling will be 

performed, and the results will be reported to the NRC at least two years prior to the end 

of the current operating license.

The ASME Section XI ISI Program is currently following ASME Section XI as required by 

10 CFR 50.55a. However, NUREG-1801, Section XI.M16, “PWR Vessel Internals,” 

references the 1995 Edition through the 1996 Addenda. The ASME Section XI ISI 

Program will be updated to later editions and addenda as required by 10 CFR 50.55a; the 

code edition and addenda will not necessarily be those referenced by this revision of 

NUREG 1801.

NUREG-1801 Consistency

The Reactor Vessel Internals Inspection Program is consistent with NUREG-1801, 

Section XI.M16, “PWR Vessel Internals.”

Exceptions to NUREG-1801

None

Enhancements

Two enhancements are planned to bring the Reactor Vessel Internals Inspection Program 

into conformance with the NUREG-1801 program requirements. The enhancements are:

Scope of Program and Detection of Aging Effects: Palisades will participate in the industry 

initiatives to evaluate the effect of Changes in Dimensions due to Void Swelling, and will 

report to the NRC at least two years prior to the end of the current operating license the 

results of the industry initiative and a schedule for augmented inspections that will be 

required, if any.

Palisades will participate in industry initiatives that will generate additional data on aging 

mechanisms relevant to RVI and develop appropriate inspection techniques to permit 

detection and characterization of features of interest. Palisades will incorporate any 

recommended augmented inspections as appropriate.
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Aging Management Program Elements

The elements of the Reactor Vessel Internals Inspection Program are described below. 

The results of an evaluation of each element against NUREG-1801, Sections XI.M.16, 

“PWR Vessel Internals,” are also provided. 

Scope of Program

The program relies on the ASME Section XI examinations of the RVI to detect 

the applicable aging effects. For some components, the VT-3 examination 

required by ASME Section XI may not be adequate to detect the effects before 

the component intended function is compromised. The need for augmented 

examinations will be determined by participation in industry initiatives that will 

generate additional data on aging mechanisms relevant to RVI and develop 

appropriate inspection techniques to permit detection and characterization of 

features of interest. 

The program is focused on managing the effects of crack initiation and growth 

due to stress corrosion cracking (SCC) or irradiation assisted stress corrosion 

cracking (IASCC), and loss of fracture toughness due to neutron irradiation 

embrittlement. The program contains preventive measures to mitigate SCC or 

IASCC; ISI to monitor the effects of cracking on the intended function of the 

components; and repair and/or replacement as needed to maintain the ability to 

perform the intended function. Loss of fracture toughness is of consequence 

only if cracks exist. 

This element is consistent with NUREG-1801, Section XI.M16, “PWR Vessel 

Internals.” 

Preventive Actions

This program credits the Water Chemistry Program for monitoring and control of 

primary coolant water chemistry to reduce the susceptibility to cracking due to 

SCC.

This element is consistent with NUREG-1801, XI.M16, “PWR Vessel Internals.”

Parameters Monitored, Inspected, and/or Tested

The program monitors the effects of crack initiation and growth by implementing 

the requirements of ASME Section XI Table IWB-2500-1.

This element is consistent with NUREG-1801, Section XI.M16, “PWR Vessel 

Internals.”
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Detection of Aging Effects

The Palisades Reactor Vessel Internals Inspection Program includes a variety of 

inspection and testing activities that are designed to detect degradation due to 

aging effects prior to loss of intended function. Visual examinations are utilized 

as applicable and will be, as a minimum, the VT-3 examination specified by 

ASME Section XI, Subsection IWB, Category B-N-3. The need for augmented 

examinations will be determined by participation in industry initiatives that will 

generate additional data on aging mechanisms relevant to RVI and develop 

appropriate inspection techniques to permit detection and characterization of 

features of interest. 

NUREG-1801, Section XI.M16, Detection, states, “For bolted components, 

augmented ISI is to include other demonstrated acceptable inspection methods 

to detect cracks between the bolt head and the shank. Alternatively, the 

applicant may perform a component-specific evaluation, including a mechanical 

loading assessment to determine the maximum tensile loading on the 

component during ASME Code Level A, B, C, and D conditions. If the loading is 

compressive or low enough (<5 ksi) to preclude fracture, then supplemental 

inspection of the component is not required.”

Based on operating experience, a CEOG plant and component-specific 

evaluation, and CE's position that normal in-service inspections will detect any 

problems with these bolts, Palisades has determined that augmented 

inspections of this bolting are not necessary. This is identical to the position 

taken by the Fort Calhoun Station in their License Renewal Application, and 

subsequently approved by the NRC in the associated Safety Evaluation Report, 

NUREG-1782.

This element is consistent with NUREG-1801, Section XI.M16, “PWR Vessel 

Internals.” 

Monitoring and Trending

The reactor vessel internals are inspected per the requirements of ASME 

Section XI, subsection IWB, Table IWB-2500-1. The need for augmented 

examinations will be determined by participation in industry initiatives that will 

generate additional data on aging mechanisms relevant to RVI and develop 

appropriate inspection techniques to permit detection and characterization of 

features of interest. The inspection schedule is in accordance with IWB-2400.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M16, “PWR Vessel Internals.” 
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Acceptance Criteria

Indications or relevant conditions of degradation are evaluated in accordance 

with ASME Section XI, subsection IWB-3100, by comparing the examination 

results with the acceptance standards of IWB-3400.

This element is consistent with NUREG-1801, Section XI.M16, “PWR Vessel 

Internals.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Reactor 

Vessel Internals Inspection Program at Palisades are evaluated. The Reactor 

Vessel Internals Inspection Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Reactor Vessel Internals Inspection Program issues are addressed 

in a timely manner and that age related deterioration of SSC within the scope of 

the Reactor Vessel Internals Inspection Program will be effectively managed 

throughout the license renewal period.

In completing our review of Operating Experience we looked at related issues 

which included NRC Information Notices 84-18, “Stress Corrosion Cracking in 

PWR Systems,” and 98-11, “Cracking of Reactor Vessel Internal Baffle Former 

Bolts in Foreign Plants.”

A review of the industry operating experience related to the Reactor Vessel 

Internals Inspection Program revealed several instances where degradation has 

occurred within the reactor vessel internals. The review considered a variety of 

issues related to reactor internals which included degradation of baffle former 

bolts, barrel former bolts, guide bar bolts, core support shield to core barrel 

bolts, guide funnels, guide tube support pins, and rod cluster control assemblies.
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A review of the plant specific operating experience revealed two (2) instances 

where the Reactor Vessel Internals Inspection program has been instrumental in 

discovering material degradation. Degradation was discovered in the following 

items:

• Core barrel

• CRDM seal housings

The Reactor Vessel Internals Inspection Program has been effective in 

identifying material degradation in a timely manner, thus ensuring that age 

related degradation of Reactor Vessel Internals will be effectively managed by 

the Reactor Vessel Internals Inspection Program throughout the license renewal 

period.

This element is consistent with NUREG-1801, Section XI.M16, “PWR Vessel 

Internals.”

Conclusion

The Reactor Vessel Internals Inspection Program is an existing program that 

uses as its bases, various industry and NRC standards. This program is 

consistent with NUREG-1801, Section XI.M16, “PWR Vessel Internals.” 

Reports of recent internal and external assessments of the program have been 

reviewed. These reports demonstrate that the program has effectively identified 

and dispositioned issues that could have led to degraded conditions. It is 

concluded that the Reactor Vessel Internals Inspection Program has been 

effective in maintaining the intended functions of the affected long-lived, passive 

SSCs.

The continued implementation of the Reactor Vessel Internals Inspection 

Program provides reasonable assurance that aging effects will be managed 

such that SSCs within the scope of this program will continue to perform their 

intended functions consistent with the current licensing bases for the period of 

extended operation.

B2.1.18 Steam Generator Tube Integrity Program

Program Description

The Steam Generator Tube Integrity Program is an existing program that manages the 

aging effects of steam generator tubes and tube repairs. The Program also manages the 

aging effects of accessible steam generator secondary side internal components and 

incorporates the guidance of NEI 97-06. The program manages aging effects through a 
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Appendix B - Aging Management Programs

balance of mitigation, inspection, evaluation, repair, and leakage monitoring measures. 

Component degradation is mitigated by controlling primary and secondary water 

chemistry. Eddy current testing is used to detect steam generator tube flaws and 

degradation. Visual examinations are performed to identify degradation of accessible 

steam generator secondary side internal components. Primary to secondary leakage is 

monitored during plant operation.

The program credits the Water Chemistry Program for primary and secondary water 

chemistry control. The program also satisfies ASME Section XI, IWB- 2500, Category 

B-Q requirements to perform volumetric examinations of steam generator tubes in the 

Inservice Inspection (ISI) Program.

NUREG-1801 Consistency

The Steam Generator Tube Integrity Program is consistent with NUREG-1801, Section 

XI.M19, “Steam Generator Tube Integrity.”

Exceptions to NUREG-1801

None.

Enhancements

None

Aging Management Program Elements

The elements of the Steam Generator Tube Integrity Program are described below. The 

results of an evaluation of each element against NUREG-1801, Section XI.M19, “Steam 

Generator Tube Integrity,” are also provided. 

Scope of Program

The scope of the Steam Generator Tube Integrity Program is specific to the 

steam generator primary side U-tubes and the accessible areas of the 

secondary side internal components. The secondary side internal components 

include the top of tube sheet, stay dome region, outer bundle region, top of tube 

bundle, and upper internals which includes feed ring piping, tube supports, J 

nozzles, secondary separators, and vertical strap and diagonal bar supports. 

Tube inspection scope and frequency, plugging or repair, and leakage 

monitoring is in accordance with Technical Specification 5.5.8.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”
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Preventive Actions

The Steam Generator Tube Integrity Program is a condition monitoring program. 

However, this program credits the Water Chemistry Program for monitoring and 

control of primary and secondary water chemistry, which is in accordance with 

the EPRI Guidelines of TR-105714 for monitoring and control of primary coolant 

water chemistry and TR-102134 for monitoring and control of secondary water 

chemistry. The Program also includes the guidance from NEI 97-06 regarding 

foreign material exclusion as a means to inhibit fretting and wear degradation. 

Periodic sludge lancing is performed to minimize pitting on the outside diameter 

of the steam generator tubes due to oxidizing conditions in the sludge piles.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”

Parameters Monitored, Inspected, and/or Tested

The Steam Generator Tube Integrity Program monitors steam generator tube 

indications and growth, loss of section thickness, loss of material, tube denting, 

and stainless steel egg crate lattice support cracking. The Program inspection 

activities include detection of flaws in the steam generator tubes and 

degradation of the accessible areas of the secondary side internal components. 

The steam generator tubes are tested using the eddy current volumetric test 

method. The examinations for the accessible areas of the secondary side 

internal components are performed visually. 

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”

Detection of Aging Effects

The Palisades Steam Generator Tube Integrity Program includes a variety of 

examination and testing activities that are designed to detect degradation due to 

aging effects prior to loss of intended function. The Program complies with the 

plant Technical Specification 5.5.8 and NEI 97-06 for the examination and test 

methods, sample size, and inspection frequency. The examination and test 

methods, sample size, and frequency of the inspections prescribed by the 

Program are designed to ensure that flaws or degradation do not exceed 

established performance criteria, and are documented in a degradation 

assessment completed prior to each steam generator inspection. In response to 

NRC Generic Letter 95-03, Palisades further committed to a more rigorous 

inspection plan defined by EPRI TR-107569.
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The steam generator nondestructive examination (NDE) requirements are 

based on the applicable requirements and references in the ASME Boiler and 

Pressure Vessel Code, Section XI, used for the ISI Program.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”

Monitoring and Trending

The inspection schedule and scope expansion requirements are based on 

Technical Specification 5.5.8 and NEI 97-06. These requirements are expected 

to provide timely detection of tube degradation prior to any loss of intended 

function or challenge to tube integrity. Results of inspections are documented, 

evaluated, and compared with previous inspection results to identify adverse 

trends.

Following steam generator inspections, a condition monitoring assessment of 

the as-found condition is performed to assess degradation, and then a forward 

looking operational assessment is conducted to ensure that performance criteria 

will not be exceeded during the next operating cycle. The current condition 

monitoring assessment is also compared with the previous operational 

assessment to gain feedback and insight for the next operational assessment.

This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”

Acceptance Criteria

The acceptance criteria for steam generator inspections are in accordance with 

plant Technical Specification 5.5.8 and NEI 97-06. Loose parts or foreign objects 

that are found are removed from the steam generators unless it is shown by 

evaluation that these objects will not cause unacceptable tube damage.

Tube inspections are followed by tube integrity assessments that compare the 

as-found inspection results with the performance criteria for structural integrity 

and accident leakage. These performance criteria are expressed in terms of 

parameters that are directly measurable or that may be calculated on the basis 

of direct measurements. When steam generator tubes do not meet the 

acceptance criteria specified in the plant Technical Specifications or NEI 97-06, 

they are repaired or removed from service by plugging. The criteria for plugging 

or repairing steam generator tubes is consistent with NRC RG 1.121. The 

acceptance criteria for secondary-side internal components are delineated in the 

applicable program implementing documents.
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This element is consistent with the corresponding element of NUREG-1801, 

Section XI.M19, “Steam Generator Tube Integrity.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Steam 

Generator Tube Integrity Program at Palisades are evaluated. The Steam 

Generator Tube Integrity Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Steam Generator Tube Integrity Program issues are addressed in a 

timely manner and that age related deterioration within the scope of the Steam 

Generator Tube Integrity Program will be effectively managed throughout the 

license renewal period.

A review of the industry operating experience related to the Steam Generator 

Tube Integrity Program revealed instances where degradation has occurred 

within the steam generators. In completing our review we looked at related 

issues which included degradation of steam generator tubes, tube sheet, 

mechanical plugs, tube support plates, girth welds, antivibration bars, etc., plus 

degradation associated with loose parts, foreign objects, sludge, water 

chemistry, and wear.

A review of the plant specific operating experience revealed several instances 

where the Steam Generator Tube Integrity Program has been instrumental in 

discovering material degradation. Steam Generator tube degradation was 

discovered in the following areas:

• Top of tubesheet

• Within the tubesheet

• U-bends

• Mechanical wear at eggcrate supports, vertical straps, and diagonal bars
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The Steam Generator Tube Integrity Program has been effective in identifying 

material degradation in a timely manner, thus ensuring that age related 

degradation of steam generator subcomponents will be effectively managed 

throughout the license renewal period.

The steam generators at Palisades were replaced in late 1990. The new steam 

generators are improved in design, material selection, and construction. 

Included in the new design was a change in the tube support from solid plate to 

egg crate dividers along with other features to minimize corrosion crevices and 

denting.

This element is consistent with NUREG-1801, Section XI.M19, “Steam 

Generator Tube Integrity.”

Conclusion

The Steam Generator Tube Integrity Program is an existing program that uses as its 

bases, various industry and NRC standards. This program is consistent with 

NUREG-1801, Section XI.M19, “Steam Generator Tube Integrity.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. The Steam Generator Tube Integrity 

Program has been effective in maintaining the intended functions of the affected 

long-lived, passive steam generator subcomponents.

The continued implementation of the Steam Generator Tube Integrity Program provides 

reasonable assurance that aging effects will be managed such that the components 

within the scope of this program will continue to perform their intended functions 

consistent with the current licensing bases for the period of extended operation.

B2.1.19 Structural Monitoring Program

Program Description

The Structural Monitoring Program is an existing program that is designed to ensure that 

age related (as well as other) deterioration of plant structures (including masonry walls) 

and components within its scope is appropriately managed to ensure that each such 

structure or component retains the ability to perform its intended function. The program is 

implemented through visual examination of these structures, components and other 

specified items. Damage or degradation found during visual examination may be further 

evaluated by measurements and testing techniques as appropriate.
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This program also implements provisions of the Maintenance Rule, 10 CFR 50.65, that 

relate to masonry walls and water-control structures. It conforms to the guidance 

contained in RG 1.160 and NUMARC 93-01 as well as Nuclear Energy Institute 

publication NEI 96-03. This NEI document, which supplements NUMARC 93-01, contains 

additional guidance specific to the monitoring of structures. 

Initial baseline inspections under the Structural Monitoring Program were performed, as 

required by 10 CFR 50.65, starting in late 1996. A second complete inspection was 

performed in 1999 to validate the initial inspection results. Subsequent inspections follow 

a 10 year interval schedule that is similar to Inspection Plan B defined in the ASME Boiler 

& Pressure Vessel Code, Section XI, Table IWE-2412-1.

The 10 year inspection interval is divided into three 40 month periods. Approximately one 

third of the items in the program scope are examined in each period and all items are 

examined at least once during the 10 year interval. The first interval, first period, 

inspections have been completed, and Palisades is currently in the first interval, second 

period inspection cycle. Other features may have greater inspection frequencies such as 

watertight/flood barrier inspections (at least once per 5 years) and below-the-waterline 

water-control structures (once every 5 years). 

Augmented inspection is required for items that have been repaired or that exhibit 

significant damage or deterioration. It may also be required for items subject to 

aggressive environments. Items that are tagged for augmented inspection following repair 

or for reasons of damage / deterioration are examined, at a minimum, in the period 

immediately following the one during which the repair was performed or the deleterious 

condition was found. Augmented inspection may be performed on a 40 month period 

basis or at more closely spaced intervals as specified by the Structural Monitoring 

Coordinator or in plant procedures.

The Structural Monitoring Program includes requirements for the inspection of 

water-control structures and structural elements that are accessible above the waterline. 

Palisades is not committed to Regulatory Guide 1.127, and NUREG-1801 Program XI.S7 

provides guidance to plants that are not committed to RG 1.127. This guidance includes 

addressing those structures above the waterline in NUREG-1801 Program XI.S6, and 

addressing below-the-waterline structures in the applicable sections of NUREG-1801 

Program XI.S7. 
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NUREG-1801 Consistency

The Structural Monitoring Program is consistent with the following NUREG-1801 

programs:

• NUREG-1801 Section XI.S6, “Structures Monitoring Program” 

• The corresponding structural elements in NUREG-1801 Section XI.S5, “Masonry Wall 

Program”

• The corresponding structural elements in NUREG-1801 Section XI.S7, “RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants”

Exceptions to NUREG-1801

None.

Enhancements

One enhancement is planned to bring the Structural Monitoring Program into 

conformance with the NUREG-1801 program requirements. The enhancement is:

Scope of Program: Incorporate into the Structural Monitoring Program all structural 

members listed in Tables 3.5.2-1 through 3.5.2-10 that will use the Structural Monitoring 

Program as an AMP.

Note that the element descriptions describe the program as it will exist after the identified 

enhancement has been implemented. Enhancements are scheduled for completion prior 

to the period of extended operation. 

Aging Management Program Elements

The elements of the Structural Monitoring Program are described below. The results of an 

evaluation of each key element against NUREG-1801, Section XI.S6, “Structures 

Monitoring Program,” and the applicable structural elements of Sections XI.S5, “Masonry 

Wall Program,” and XI.S7, “RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants,” are also provided. 

Scope of Program

The Palisades Structural Monitoring Program implements the requirements of 

10 CFR 54 and 10 CFR 50.65. 

The NUREG-1801 Structures Monitoring (XI.S6) portion of this program applies 

to most structural components within the scope of license renewal, including 

those water-control structures and structural elements that are accessible above 

the waterline. 
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The NUREG-1801 Masonry Wall (XI.S5) portion of this program applies to all 

masonry walls within the scope of license renewal. The Structural Monitoring 

Program includes requirements for the examination of in-scope masonry walls 

for cracking and degradation of steel supports, and does not maintain a 

separate Masonry Wall Program. 

The NUREG-1801 Water-Control Structures (XI.S7) portion of this program 

applies to below-the-waterline structures and structural elements within the 

scope of license renewal. These structures include the Intake Crib and Intake / 

Discharge Structures. Continuously submerged structures and structural 

elements are also age managed under the this program. 

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).

Preventive Actions

The Palisades Structural Monitoring Program is a monitoring program and does 

not specify preventive actions. 

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, and the structural elements described in 

NUREG-1801, Sections XI.S5 and XI.S7 (below-the-waterline).

Parameters Monitored, Inspected, and/or Tested

XI.S6, Structures Monitoring 

The NUREG-1801 evaluation of Program XI.S6 references ACI 349.3R-96 and 

ANSI / ASCE 11-90 as industry standard publications that provide acceptable 

guidance on the selection of parameters to monitor. The Palisades Structures 

Monitoring Program conforms to the guidance and basis provided in these two 

documents.

The NUREG-1801 evaluation also identifies monitoring of site de-watering 

systems to ensure continuing control over erosion of porous concrete 

sub-foundations and building settlement. Palisades’ buildings are founded on 

dense sand and are not subject to significant settlement. Neither porous 

concrete sub-foundations nor de-watering systems are used. Therefore, the 
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issues of de-watering systems, erosion of porous concrete sub-foundations and 

settlement are not applicable.

XI.S5, Masonry Walls

The NUREG-1801 evaluation of Program XI.S5 specifies the monitoring of 

cracking and degradation of steel edge supports and bracings. The Palisades 

Structural Monitoring Program requires monitoring of cracking as well as other 

signs of damage / deterioration. The Palisades program is, therefore, in 

conformance with the Masonry Wall Program monitoring elements identified in 

NUREG-1801.

XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

The NUREG-1801 evaluation of Program XI.S7 specifies the monitoring of 

cracking, settlement & deflection and numerous other parameters that apply 

only to dams and related structures which are not used at Palisades. It 

references additional parameters as listed in USNRC Regulatory Guide 1.127, 

Section C.2. Similar to NUREG-1801 Program XI.S7, this regulatory guide 

addresses primarily dams and related structures. It does, however, list general 

guidelines for the examination of concrete structures and references ACI 

201.1R for detailed descriptions of concrete deficiencies. The Palisades 

Structural Monitoring Program conforms to these recommendations and 

incorporates the additional specific monitoring tasks addressed in the XI.S7 

program evaluation. Steel structures or portions of structures are examined for 

loss of material. This applies to the steel intake crib, and carbon steel and cast 

iron items in the intake structure.

In addition, RG 1.127 provides guidelines for examining and assessing the 

condition of conduits and inlet canals. These guidelines refer principally to 

continuously submerged surfaces and are implemented through the program 

underwater inspections.

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).
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Detection of Aging Effects

The Palisades Structural Monitoring Program is implemented in accordance with 

a 10 year interval schedule that requires completion of approximately 1/3 of the 

specified examinations within each of three consecutive 40 month periods. The 

program requires that 100% of the items included within its scope be examined 

at least once (and more often for those items requiring augmented inspection) 

during each interval. These requirements for frequent and comprehensive 

examinations provide a high degree of assurance that age related deterioration 

of an item will be detected and corrected long before it has a significant impact 

on the item’s intended function.

Examinations of structures and structural elements are performed by qualified 

personnel using techniques appropriate for the item, its environment and its 

intended function. Each individual selected to perform these examinations must 

have the following qualifications:

• A civil engineering degree from an accredited university.

• Familiarity with the design and performance requirements applicable to 

nuclear power plant structures and experience in the in-service examination 

and evaluation of these structures. 

• A minimum of 5 years experience in engineering design and / or analysis of 

nuclear power plant structures.

System engineers and plant operators augment the formal examinations by 

noting the conditions of structures / structural elements during periodic system 

walk downs, and reporting observed damage / degradation to the Structural 

Monitoring Coordinator.

XI.S6, Structures Monitoring

The NUREG-1801 evaluation of Program XI.S6 references ACI 349.3R-96 and 

ANSI / ASCE 11-90 as industry standard publications (although not required) 

that provide acceptable guidance on the use of examination techniques suitable 

to detect significant aging effects. The Palisades program conforms to the 

guidance given in these two documents.

XI.S5, Masonry Walls

The NUREG-1801 evaluation of Program XI.S5 identifies visual examination of 

the masonry walls for cracking and degradation of steel edge supports and 

bracings that could cause loss of intended functions prior to the next scheduled 

examination. The Palisades program applies the same periodic visual 
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examination techniques to masonry walls and to concrete structural elements as 

prescribed by this program element. Periodicity of examinations may vary, 

according to different reinforcement masonry configurations. 

XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

NUREG-1801 evaluation of Program XI.S7 identifies no specific requirements 

relative to detecting age related deterioration of water-control structure elements 

above the waterline. The Palisades program applies the same visual 

examination techniques to water-control structural components that it applies to 

other concrete structural components in the XI.S5 program. For structures and 

components below-the-waterline, Palisades maintains those elements 

consistent with those identified to the XI.S7 program in NUREG-1801.

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).

Monitoring and Trending

XI.S6, Structures Monitoring

Items included within the scope of this program that do not meet the acceptance 

criteria listed are evaluated for corrective action and, at a minimum, are 

scheduled for augmented examination. Items that are repaired are also 

scheduled for augmented examination. The condition of any item subject to 

augmented examination is trended to provide a basis for scheduling future 

inspections or corrective action. This approach is consistent with that described 

10 CFR 50.65 & Regulatory Guide 1.160 and referenced in NUREG-1801 

evaluation of the Structures Monitoring Program (XI.S6). 

XI.S5, Masonry Walls

NUREG-1801 evaluation of Program XI.S5 states that trending is not required 

and that monitoring is achieved by the periodic examinations to detect cracking. 

However, for the evaluation of aging effects that do not meet acceptance criteria 

at Palisades, augmented inspections may be specified to identify if continued 

degradation is occurring and if corrective action may be required. 
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XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

NUREG-1801 evaluation of Program XI.S7 states that no trending is required. 

Monitoring is to be performed in accordance with this guide, which contains no 

requirements that differ from those applied by the Palisades program to other 

structures and structural elements. Therefore, the Palisades program includes 

no special requirements to monitor or trend water-control structure condition. 

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).

Acceptance Criteria

XI.S6, Structures Monitoring

NUREG-1801 evaluation of the Structures Monitoring Program, XI.S6, states 

that, “... acceptance criteria are selected to ensure that the need for corrective 

actions will be identified before loss of intended functions. Acceptance criteria 

are to be commensurate with industry codes, standards and guidelines, and are 

also to consider industry and plant-specific operating experience. Although not 

required, ACI-349.3R-96 provides an acceptable basis for developing 

acceptance criteria ...” The Palisades Structural Monitoring Program satisfies 

the prescriptive requirements of NUREG-1801 evaluation and includes 

guidelines provided in the referenced ACI publication. 

XI.S5, Masonry Walls

The NUREG-1801 evaluation of Program XI.S5 requires an engineering 

evaluation (and subsequent corrective action if found to be necessary) of any 

observed cracking and/or degradation of steel edge supports and bracing. This 

engineering evaluation is done to determine if the wall retrains the capability to 

fulfill its intended function. The Palisades program requires such an evaluation 

(and corrective action, if specified in the evaluation report) if cracking or 

degraded steel edge supports and bracing are found during the examination. 

XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

The Palisades program applies the same acceptance criteria to water-control 

structure elements as it does similar elements in other structures per 
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NUREG-1801, Program XI.S6. Therefore, Palisades maintains elements 

consistent with those below-the-waterline SSC's identified to the XI.S7 program 

in NUREG-1801. 

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues / events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues / events. Those issues and events, 

whether external or plant specific, that are potentially significant to the structures 

and other items within the scope of the Palisades Structures Monitoring Program 

are evaluated. The Structural Monitoring Program is augmented, as appropriate, 

if these evaluations show that program changes will enhance item performance 

and, as a consequence, operational safety.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Structural Monitoring Program issues are addressed in a timely 

manner and that age related deterioration of the items within the program scope 

is effectively managed throughout the license renewal period. 

A review of industry operating experience associated with the Structures 

Monitoring Program and aging reveals issues and instances related to:

• Corrosion of steel ice condenser containment vessels caused by boric acid 

and condensation

• Cracks in concrete floors caused by flexing and shrinkage

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.
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A review of plant specific operating experience related to the Structural 

Monitoring Program and aging revealed that the following issues have been 

addressed:

• Settling of air compressor foundations

• Watertight barrier degradation

• Spalled concrete and exposed anchor bolts

• Intake crib damage due to ice and to wave action

• Cracking of concrete beams in the Auxiliary Building

• Corrosion of condenser rock anchors caused by standing water and debris

• Degradation of snubber anchor support structure concrete and grout

• Deterioration of floor plugs due to leaking water

• Moisture Separator Reheater foundation cracking

• Cracks in concrete duct bank

• Cracks in West ESS room west wall

• Spalled concrete on wall of 1-2 Diesel Generator Exhaust Plenum

• Groundwater leaks in Auxiliary Feedwater Pump room floor

The Palisades Structural Monitoring Program has demonstrated that it provides 

reasonable assurance that aging effects are being managed for Structural 

Monitoring Program SSCs. Additionally, this has been demonstrated through 

inspection reports, Program Health Reports, and the Corrective Action Program.

This element of the Palisades Structural Monitoring Program is consistent with 

NUREG-1801, Section XI.S6, “Structures Monitoring Program”, and the 

applicable structural elements described in NUREG-1801, Sections XI.S5, 

“Masonry Wall Program,” and XI.S7, “R.G.1.127, Inspection of Water Control 

Structures Associated With Nuclear Power Plants” (below-the-waterline).

Conclusion

The Structural Monitoring Program is based on an existing program (Maintenance Rule 

Structural Monitoring) and is consistent with NUREG-1801, Section XI.S6, and the 

structural elements described in NUREG-1801, Sections XI.S5 and XI.S7 

(below-the-waterline).

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. Palisades has demonstrated that the 
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Palisades Structural Monitoring Program will effectively manage aging of structural SSC's 

in-scope of License Renewal. 

It is concluded that continued implementation of the Structural Monitoring Program 

provides reasonable assurance that the effects of aging will be managed such that the 

affected components will continue to perform their intended function(s) during the period 

of extended operation.

B2.1.20 System Monitoring Program 

Program Description

The System Monitoring Program is an existing plant-specific program that manages aging 

effects for normally accessible, external surfaces of piping, tanks, and other components 

and equipment within the scope of License Renewal. These aging effects are managed 

through visual inspection and monitoring of external surfaces for leakage and evidence of 

material degradation. The program relies upon periodic system walkdowns to monitor 

degradation of the protective paint or coating, and/or the exterior steel surface area (if no 

paint or coatings exist, or if the existing protective paint and coatings are degraded to a 

point whereby the exterior steel surface is exposed). Palisades does not take credit for 

any above ground coating or paint for mitigating corrosion even though the tanks may be 

painted or coated. However, inspections of the above ground coating or paint will provide 

an indication of the condition of the material underneath the coating or paint. 

NUREG-1801 Consistency

The System Monitoring Program is a plant-specific program that contains the applicable 

elements of an acceptable aging management program as described in Branch Technical 

Position RLSB-1, “Aging Management Review-Generic,” which is included in Appendix A 

of NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for 

Nuclear Power Plants.”

The System Monitoring Program is also consistent with the portions of NUREG-1801, 

Section XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of the applicable tanks.

Exceptions to NUREG-1801

None.

Enhancements

One enhancement is planned to bring the System Monitoring Program into conformance 

with the NUREG-1801 program description. The enhancement is:
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Parameters Monitored, Inspected, and/or Tested, Detection of Aging Effects, and 

Monitoring and Trending: Enhance system walkdown procedures to more specifically 

address the types of components to be inspected, and to specifically describe the 

relevant degradation mechanisms and effects of interest, and for use of the Corrective 

Action Program to document aging related degradation, identified during the inspections, 

that may affect the ability of the SSC to perform its intended function.

Note that the element descriptions describe the program as it will exist after the identified 

enhancements have been implemented. Enhancements are scheduled for completion 

prior to the period of extended operation. 

Aging Management Program Elements

The elements of the System Monitoring Program are described below. An evaluation of 

each element against the corresponding element described in Branch Technical Position 

RLSB-1, “Aging Management Review-Generic,” which is included in Appendix A of 

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for 

Nuclear Power Plants,” is provided. Since this program includes visual inspections of the 

external surfaces of above ground carbon steel tanks, the results of an evaluation of each 

element against NUREG-1801, Section XI.M.29, “Above Ground Carbon Steel Tanks,” 

are also provided. 

Scope of Program

The System Monitoring Program is credited for managing the aging effects for 

normally accessible surfaces of piping, tanks, and other components and 

equipment within the scope of License Renewal. These aging effects are 

managed through visual inspection and monitoring of external surfaces for 

leakage and evidence of material degradation. 

The System Monitoring Program includes periodic visual inspections 

(walkdowns) of the external surfaces of various types of components to identify 

age related degradation.

NUREG-1801 for above ground carbon steel tanks states that the program 

consists of “preventive measures to mitigate corrosion by protecting the external 

surfaces of carbon steel tanks protected with paint or coatings.” Palisades 

Nuclear Plant does not take credit for any above ground coating or paint for 

mitigating corrosion even though the tanks may be painted or coated. However, 

inspections of the above ground coating or paint will provide an indication of the 

condition of the material underneath the coating or paint. Therefore, periodic 
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system walkdowns will detect the effects of corrosion if present. This meets the 

intent of NUREG-1801.

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 

This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.

Preventive Actions

There are no preventive actions associated with this program. The objective of 

this program is to identify the aging effects of concern before a loss of intended 

function occurs (i.e., condition monitoring). Palisades Nuclear Plant does not 

take credit for any above ground coating or paint for mitigating corrosion even 

though the tanks may be painted or coated. However, inspections of the above 

ground coating or paint will provide an indication of the condition of the material 

underneath the coating or paint. Therefore, periodic system walkdowns will 

detect the effects of corrosion if present. This meets the intent of NUREG-1801. 

Sealants or caulking at the tank/support structure interface, if used, are also 

inspected for degradation. However, Palisades does not credit sealants or 

caulking for prevention of water intrusion underneath tanks.

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 

The System Monitoring Program is also consistent with the portions of 

NUREG-1801, Section XI.M29, “Above Ground Carbon Steel Tanks,” that are 

applicable to the accessible external surfaces of above ground carbon steel 

tanks. 

Parameters Monitored, Inspected, and/or Tested

The program utilizes periodic plant system walkdowns to monitor for leakage 

and evidence of material degradation. Above ground carbon steel tank external 

coatings or paint are inspected to provide an indication of the condition of the 

material underneath the coating or paint. Sealants or caulking at the 

tank/support structure interface, if used, are also inspected for degradation. 

However, Palisades does not credit sealants or caulking for prevention of water 

intrusion underneath tanks.
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This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 

This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.

Detection of Aging Effects

The System Monitoring Program uses visual inspection activities to detect 

degradation due to aging effects prior to loss of intended function. The external 

surfaces of various component types (e.g., pump casings, valve bodies, piping, 

expansion joints) are visually inspected for leakage and evidence of material 

degradation, such as loss of material due to corrosion. The outer surfaces of 

above ground carbon steel tanks are visually inspected for signs of coating or 

paint degradation to provide an indication of the condition of the material 

underneath the coating or paint. The sealant or caulking at the tank/support 

structure interface, if used, is also inspected for degradation. However, 

Palisades does not credit sealants or caulking for prevention of water intrusion 

underneath tanks. This program credits the One-Time Inspection Program for 

the inspection of inaccessible portions of above ground (non-Diesel Fuel Oil) 

carbon steel tanks. Diesel Fuel Oil Tank bottom thickness tests are conducted 

periodically per the Diesel Fuel Monitoring and Storage Program.

Degradation of bolted connections is detected by visual inspections of the bolted 

components during system walkdowns. Bolted connections are inspected for 

missing fasteners and degradation such as damaged threads and evidence of 

corrosion. The minimum walkdown frequency is annual for those systems and 

components that are accessible during normal plant operation. Systems and 

components that are only accessible during plant outages, are inspected at least 

once per refueling interval. The inspection frequency may be increased based 

on the safety significance, production significance, discovery and/or operating 

experience of each system.

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 

This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.
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Monitoring and Trending

Visual inspections are performed at least annually for those systems and 

components that are accessible during normal plant operation. Systems and 

components that are only accessible during plant outages, are inspected at least 

once per refueling interval. The inspection frequency may be increased or 

reduced based on the safety significance and operating experience of each 

system. These system walkdown inspections provide for timely detection of 

aging effects (i.e., prior to a loss of intended function). Walkdown results are 

documented to provide a historical record of items monitored during the 

walkdowns. This program credits the One-Time Inspection Program for the 

inspection of inaccessible portions of above ground (non-Diesel Fuel Oil) carbon 

steel tanks. Diesel Fuel Oil Tank bottom thickness tests are conducted 

periodically per the Diesel Fuel Monitoring and Storage Program. The results 

are monitored and trended if significant material loss is detected.

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 

This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.

Acceptance Criteria

System walkdown procedures require that signs of significant degradation to 

paint, coatings or exposed external steel surfaces found that may affect the 

components ability to perform its intended function be entered into the 

Corrective Action Program for resolution. Other types of degradation are 

recorded for further evaluation.

When bolted joints for pressure retaining components are observed to have 

significant degradation or to be leaking, corrective actions are taken in 

accordance with the corrective action program. Significant degradation of tank 

coatings or paint, and sealants or caulking (if applicable) are also addressed 

within the Corrective Action Program. Significant degradation consists of 

cracking, flaking, or peeling of paint or coatings, and cracked sealant or caulking 

(if applicable). 

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A. 
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This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1800 and 

NUREG-1801 aging management program elements. See Section B1.2 for 

further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the System 

Monitoring Program at Palisades are evaluated. The System Monitoring 

Program is augmented, as appropriate, if these evaluations show that program 

changes will enhance program effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that System Monitoring Program issues are addressed in a timely 

manner and that age related deterioration of SSC within the scope of the 

System Monitoring Program will be effectively managed throughout the license 

renewal period.

A review of industry operating experience associated with the System 

Monitoring Program and aging reveals issues related to:

• Service Water Pump flange welds and bolting found excess rusting leading 

to leakage (Inadequate/infrequent system walkdowns were cited).

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the System Monitoring 

Program and aging revealed that the following issues have been addressed:

• Various pump and valve flange welds and bolting (carbon steel) were found 

having significant material loss due to high moisture environment or boric 

acid accumulations.
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• Floor-mounted pipe supports were discovered with excessive corrosion of 

bolts. (Concrete failure may have contributed from vibration and/or concrete 

boric acid contamination)

None of the industry or plant operating issues or instances have led to a system 

component functional failure due to aging.

The Palisades System Monitoring Program has demonstrated that it provides 

reasonable assurance that aging effects are being managed for System 

Monitoring Program SSCs. Additionally, this has been demonstrated through 

NRC inspection reports, audits, self-assessments, and the Corrective Action 

Program.

This element is consistent with the corresponding element of NUREG-1800, 

Appendix A.

This element is also consistent with the portions of NUREG-1801, Section 

XI.M29, “Above Ground Carbon Steel Tanks,” that are applicable to the 

accessible external surfaces of above ground carbon steel tanks.

Conclusion

The System Monitoring Program is an existing plant-specific program that uses as its 

bases, various industry and NRC standards. The elements of this program are consistent 

with the corresponding elements of NUREG-1800, Appendix A. 

This program is consistent with the portions of NUREG-1801, Section XI.M29, “Above 

Ground Carbon Steel Tanks,” that are applicable to the accessible external surfaces of 

above ground carbon steel tanks.

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the System 

Monitoring Program will be effective in maintaining the intended functions of the affected 

long-lived, passive SSCs.

Implementation of the System Monitoring Program provides reasonable assurance that 

aging effects will be managed such that SSCs within the scope of this program will 

continue to perform their intended functions consistent with the current licensing bases 

for the period of extended operation.
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B2.1.21 Water Chemistry Program 

Program Description

The Water Chemistry Program is an existing program that is credited for managing aging 

effects such as loss-of-material due to general, pitting and crevice corrosion; cracking due 

to SCC; and steam generator tube degradation caused by denting, intergranular attack 

(IGA) and outer diameter stress corrosion cracking (ODSCC), by controlling the 

environment to which internal surfaces of systems and components are exposed. The 

aging effects are minimized by controlling the chemical species that cause the underlying 

mechanisms that result in these aging effects. The program provides assurance that an 

elevated level of contaminants and, where applicable, oxygen does not exist in the 

systems and components covered by the program, thus minimizing the occurrences of 

aging effects, and maintaining each component’s ability to perform the intended functions. 

The program is based on the guidelines in EPRI TR-105714, Rev. 5, and TR-102134, 

Rev. 5. The One-Time Inspection Program verifies that the Water Chemistry Program is 

managing the effects of aging of selected components in low flow or stagnant areas.

It is important to note that both the EPRI Primary And Secondary Water Chemistry 

Guidelines make a clear distinction between “control parameters” and “diagnostic 

parameters.” Strict adherence to control parameters is expected, whereas diagnostic 

parameters are suggested, but can be plant specific. Deviations from EPRI 

recommended diagnostic parameters are not considered exceptions to NUREG-1801. 

NUREG-1801 states that the water chemistry control is based on guidelines in EPRI 

report TR-105714, Rev. 3 for primary water chemistry, and TR-102134, Rev. 3 for 

secondary water chemistry. Palisades has adopted TR-105714, Rev. 5 and TR-102134, 

Rev. 5 which are later revisions of the same documents. 

The Revision 5 changes to TR-105714 consider the most recent operating experience 

and laboratory data. It reflects increased emphasis on plant-specific optimization of 

primary water chemistry to address individual plant circumstances and the impact of the 

Nuclear Energy Institute (NEI) steam generator initiative, NEI 97-06, which requires 

utilities to meet the intent of the EPRI Guidelines. TR-105714, Rev. 5 attempts to clearly 

distinguish between prescriptive requirements and non-prescriptive guidance. 

Revision 4 of TR-102134 was issued in November 1996 and provided an increased depth 

of detail regarding the corrosion mechanisms affecting steam generators and the balance 

of plant, and also provided additional guidance on how to integrate these and other 

concerns into the plant-specific optimization process. Revision 5 provides additional 

details regarding plant-specific optimization and clarifies which portions of the EPRI 

Guidelines are mandatory under NEI 97-06. 
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Future revisions of the EPRI Primary and Secondary Water Chemistry Guidelines will be 

adopted as required, commensurate with industry standards. This is not considered an 

exception to NUREG-1801. 

NUREG-1801 Consistency

The Water Chemistry Program is an existing program that is consistent with 

NUREG-1801, Section XI.M2, “Water Chemistry.”

Exceptions to NUREG-1801

None.

Enhancements

None.

Aging Management Program Elements

The key elements of the Water Chemistry Program are described below. The results of an 

evaluation of each key element against NUREG-1801, Section XI.M2, “Water Chemistry,” 

are also provided below. 

Scope of Program

The Water Chemistry Program is credited for managing aging effects such as 

loss of material due to general, pitting and crevice corrosion; cracking due to 

SCC; and steam generator tube degradation caused by denting, intergranular 

attack (IGA), and outer diameter stress corrosion cracking (ODSCC). The 

program accomplishes this task by monitoring and controlling known detrimental 

contaminants such as chlorides, fluorides, dissolved oxygen and sulfate 

concentrations for water chemistry based on guidelines in EPRI TR-105714 for 

primary water chemistry, and TR-102134 for secondary water chemistry. The 

program includes sampling activities for primary, borated, secondary, and 

makeup water systems. 

The aging effects/mechanisms managed by the Water Chemistry Program for 

these SSCs are:

• SCC of austenitic stainless steel, Alloy 600 and Alloy 690 components

• S/G tube degradation and balance of plant materials of construction loss of 

material, due to denting, IGA, SCC, general, crevice and pitting corrosion

• Loss of material due to crevice and pitting corrosion, MIC, IGA, and fouling of 

selected components, as applicable.
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This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.”

Preventive Actions

The NUREG-1801 element states: “The program includes specifications for 

chemical species, sampling and analysis frequencies, and corrective actions for 

control of reactor water chemistry.” The specifications, sampling and analysis 

frequencies, and corrective actions are discussed in the Parameters Monitored, 

Inspected, and/or Tested; Monitoring and Trending; and Acceptance Criteria 

Sections below.

Plant procedures establish limits and controls for harmful chemicals and 

contaminants on materials of construction for components within the scope of 

license renewal. The Water Chemistry Program is primarily a mitigative program 

used to minimize contaminant concentration and mitigate aging effects such as 

loss of material, cracking due to SCC, and loss of heat transfer.

This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.”

Parameters Monitored, Inspected, and/or Tested

The concentration of corrosive impurities are monitored and trended to ensure 

concentrations are below levels known to result in loss of material or crack 

initiation and growth. Examples of impurities monitored include chlorides, 

fluorides, sulfates, and dissolved oxygen. Water quality, including pH and 

conductivity, is verified by continuous monitoring or through sampling, and 

controlled in accordance with the EPRI guidelines and plant procedures 

discussed previously. 

Plant procedures define the chemicals, impurities and parameters that are 

monitored and trended for the various water chemistry programs, and provide 

for administrative controls to assure the integrity, sampling methodology, and 

storage of samples will not cause a change in the concentration of the chemical 

species in the samples.

NUREG-1801, Section XI.M2.3 states, “The concentration of corrosive 

impurities listed in the EPRI guidelines discussed above, which include ... 

hydrogen peroxide, are monitored to mitigate degradation of structural material.” 

The addition of hydrogen peroxide to the Primary Coolant System (PCS) is an 

industry-accepted practice to reduce the source term, and provide for chemical 

degassing, and is recommended in the EPRI PWR Primary Water Chemistry 
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Guideline, Volume 2. Additions and monitoring of hydrogen peroxide in the PCS 

is accomplished by plant procedures, and is consistent with the NUREG-1801 

requirement to monitor the PCS concentration of this chemical.

This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.”

Detection of Aging Effects

The Water Chemistry Program mitigates aging effects such as loss of material 

due to general, pitting, and crevice corrosion; cracking due to SCC; and steam 

generator tube degradation caused by denting, intergranular attack (IGA) and 

outer diameter stress corrosion cracking (ODSCC), by controlling the chemical 

species that cause the underlying aging mechanisms that result in the aging 

effects. The chemistry parameters measured are defined and listed in the plant 

water chemistry program procedures for all modes of operation. The Water 

Chemistry Program does not detect aging effects directly; however in selected 

areas it does monitor for iron and copper presence, which could indicate loss of 

material in some components. In addition, inspections of selected components 

at susceptible locations in low-flow or stagnant portions of a system performed 

under the One-Time Inspection Program provide verification of the effectiveness 

of the Water Chemistry Program.

This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.”

Monitoring and Trending

Monitoring and trending requirements for all parameters controlled by the Water 

Chemistry Program are controlled by Plant procedures. Monitoring and trending 

are based on the EPRI guidelines and plant operating conditions. Whenever 

corrective actions are taken to address an abnormal chemistry condition, 

increased sampling and monitoring are typically utilized to verify the 

effectiveness of these actions. This is a normal operating practice to verify that 

the corrective action has satisfactorily corrected the parameter that was out of 

the acceptable range.

This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.” 
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Acceptance Criteria

The acceptance criteria for the chemistry parameters required to be monitored 

and controlled are based on the EPRI guidelines, Palisades Technical 

Specifications and the Operating Requirements Manual. Some of the 

parameters monitored are used for diagnostic purposes only and do not have 

acceptance criteria recommended by the EPRI guidelines. Water chemistry 

acceptance criteria are listed in plant procedures.

Any evidence of unacceptable water chemistry results is evaluated, the root 

cause identified, and the condition corrected. Plant procedures contain steps to 

be taken when parameters are out of acceptable range.

This element is consistent with, NUREG-1801, Section XI.M2, “Water 

Chemistry.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, Palisades relies on the EPRI organization to collect and 

interpret, in accordance with the Water Chemistry Guidelines, industry operating 

experience which may have an impact on chemistry control. The Palisades 

Corrective Action Program (CAP) is used to track, trend and evaluate plant and 

industry issues/events. Those issues and events, whether external or plant 

specific, that are potentially significant to water chemistry at Palisades are 

evaluated. The Water Chemistry Program is augmented, as appropriate, if these 

evaluations show that program changes will enhance water chemistry and 

operational safety.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Water Chemistry Program issues are addressed in a timely manner 

and that age related deterioration of SSC within the scope of the Water 

Chemistry Program will be effectively managed throughout the license renewal 

period.
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A review of industry operating experience associated with the Water Chemistry 

Program and aging reveals issues and instances related to:

• Cracking in steam generator welds

• Cracking and pitting of steam generator tubes and components

• Alloy 600 cracking

• Thinning of pipe and components due to erosion/corrosion

• Cracking in safety injection accumulator nozzles

• High wear of Reactor Coolant Pump Aluminum Oxide coated seals

• Cracking of Control Rod Drive Housings

• Cracking of pressurizer instrument tap nozzles

• Cracking of safety injection piping

• Cracking in feedwater piping

• Chemical impurity intrusions into primary and secondary systems

• Resin intrusions into the primary coolant systems

Various related NRC and/or industry generic communications have been issued, 

and, in turn, have been incorporated into the program as applicable.

A review of plant specific operating experience related to the Water chemistry 

Program and aging revealed that the following issues have been addressed:

• Defective tubes in the Main Condenser due to steam impingement wear and 

Microbiologically Influenced Corrosion (MIC) pitting

• Exceeding Action Level 3 Limits for Steam Generator Cation Conductivity

The second item involved exceeding of Action Level 3 limits for Steam 

Generator Cation Conductivity, which resulted in a shutdown of the plant. The 

cause of the high conductivity was traced to intrusion of glass-blasting material 

left in the turbine following a major overhaul/replacement of the turbine. 

Although there were project oversight weaknesses identified in the events 

leading up to this chemistry excursion, proper chemistry monitoring quickly 

identified the rising Cation Conductivity levels, and subsequent actions 

prevented long term age-related degradation of components as action level 3 

limits were exceeded for less than 6 hours. Compensatory actions were taken 

over the next cycle to ensure a high degree of contaminant removal or 

neutralization.
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The Palisades Water Chemistry Program has demonstrated on several 

occasions that it provides reasonable assurance that aging effects are being 

managed for Water Chemistry Program SSC. This has been demonstrated 

through NRC inspection reports, audits, self-assessments, and the Corrective 

Action Program.

This element is consistent with NUREG-1801, Section XI.M2, “Water 

Chemistry.” 

Conclusion

The Water Chemistry Program is an existing program that uses as its bases, various 

industry and NRC standards. This program is consistent with NUREG-1801, Section 

XI.M2, “Water Chemistry.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Water 

Chemistry Program has been effective in maintaining the intended functions of the 

affected long-lived, passive SSCs.

The continued implementation of the Water Chemistry Program provides reasonable 

assurance that aging effects will be managed such that SSCs within the scope of this 

program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.
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Appendix B - Aging Management Programs

B3.0 Time Limited Aging Analyses Management Programs

B3.1 Electrical Equipment Qualification Program

Program Description

The Electrical Equipment Qualification Program is an existing program that implements the 

requirements of 10 CFR 50.49, “Environmental Qualification of Electric Equipment 

Important to Safety for Nuclear Power Plants,” at Palisades. 10 CFR 50.49 defines the 

scope of components to be included, requires the preparation and maintenance of a list of 

in-scope components, and requires the preparation and maintenance of a qualification file 

that includes component performance specifications, electrical characteristics, the 

environmental conditions to which the components could be subjected, and the basis for 

qualification. 10 CFR 50.49(e)(5) contains provisions for aging that require, in part, 

consideration of all significant types of aging degradation that can affect component 

functional capability. 10 CFR 50.49(e)(5) also requires replacement or refurbishment of 

qualified components prior to the end of its designated life, unless additional life is 

established through ongoing qualification. EQ programs manage component thermal, 

radiation, and cyclical aging through the use of aging evaluations based on 10 CFR 50.49(f) 

qualification methods.

The Electrical Equipment Qualification Program is explicitly governed by regulation 

independent from license renewal, and NUREG-1801 merely credits that required program 

as sufficient for license renewal purposes. EEQ Program activities that satisfy license 

renewal considerations will continue to be managed in accordance with 10 CFR 50.49.

NUREG-1801 Consistency

The Electrical Equipment Qualification Program is consistent with NUREG-1801, Section 

X.E1, “Environmental Qualification of Electric Components.”

Exceptions to NUREG-1801

None.

Enhancements

None.

Aging Management Program Elements

The following discussion provides the results of an evaluation of each key element with the 

appropriate ten elements described in Branch Technical Position RLSB-1, “Aging 

Management Review-Generic,” which is included in Appendix A of NUREG-1800, “Standard 

Review Plan for Review of License Renewal Applications for Nuclear Power Plants,” and 
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NUREG-1801, Section X.E1, “Environmental Qualification (EQ) of Electric Components,” 

are provided below.

Scope of Program

The Electrical Equipment Qualification Program is credited for managing the 

aging effects (thermal, radiation, mechanical cycling, etc.) in components 

important to safety. The program implements the requirements of 10 CFR 50.49, 

“Environmental Qualification of Equipment Important to Safety for Nuclear 

Power Plants.”

The components (Criterion 1) within the scope of the program are safety related 

electrical equipment that will experience the direct effects of the environment 

created by a Loss of Coolant Accident (LOCA), High Energy Break (HELB), 

Main Steam Line Break (MSLB), or Feedwater Line Break (FWLB), and is 

required to function or must not fail to ensure:

a. The capability to mitigate the consequences of LOCA, HELB, MSLB, or 

FWLB accident that could result in potential offsite exposures comparable to 

10 CFR Part 100 guidelines.

b. The ability to shutdown the reactor and maintain it in a safe shutdown 

condition.

This program scope also includes non-safety related electrical equipment whose 

failure under the postulated accident environmental conditions could prevent 

satisfactory accomplishment of safety functions provided by safety related 

equipment. In addition, the scope of this program includes certain post-accident 

monitoring equipment. This program scope is as defined in 10 CFR 50.49.

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Preventive Actions

10 CFR 50.49 does not require actions that prevent aging effects. NUREG-1801 

Program X.E1 states that EEQ Program actions that could be viewed as 

preventive actions include (a) establishing the component service condition 

tolerance and aging limits (e.g., qualified life or condition limit), and (b) where 

applicable, requiring specific installation, inspection, monitoring or periodic 

maintenance actions to maintain component aging effects within the bounds of 

the qualification bases. The Palisades EEQ Program includes these features.
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This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Parameters Monitored, Inspected, and/or Tested

The qualified life of a component in the EEQ Program is not based on condition 

or performance monitoring. However, pursuant to R.G. 1.89, such monitoring 

programs can provide an acceptable basis to modify a qualified life through 

reanalysis. Monitoring or inspection of certain environmental conditions or 

component parameters may be used to ensure that a component is within the 

bounds of its qualification bases, or as a means to modify the qualified life 

during the extended period of operation.

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Detection of Aging Effects

10 CFR 50.49 does not require the detection of aging effects for in-service 

components. Refurbishment, replacement or re-qualification of qualified 

components is based on the analyses and test reports documented in each 

component's qualification file. As implemented by the EEQ Program, monitoring 

or inspection of certain environmental conditions or component parameters may 

be used to ensure that the component is within the bounds of its qualification 

bases, or as a means to modify the qualified life.

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Monitoring and Trending

10 CFR 50.49 does not require monitoring and trending of component condition 

or performance parameters of in-service components to manage the effects of 

aging. NUREG-1801, Section X.E1, states that EEQ Program actions that could 

be viewed as monitoring include monitoring how long qualified components 

have been installed. In addition, monitoring or inspection of certain 

environmental conditions or component parameters may be used to ensure that 

a component is within the bounds of its qualification bases, or as a means to 

modify the qualified life during the period of extended operation.

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”
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Acceptance Criteria

10 CFR 50.49 acceptance criteria, as implemented in the EEQ Program, 

requires each in-service EQ component to be maintained within the bounds of 

its qualification bases, including (a) its established qualified life, and (b) 

continued qualification for the projected accident conditions. 10 CFR 50.49 

requires maintenance (refurbishment, replacement), or re-qualification prior to 

exceeding the qualified life of each installed device in-scope of the program. 

When monitoring is used to modify a component qualified life (e.g., extend 

qualified life based on actual operating environment), in accordance with 

applicable 10 CFR 50.49(f) qualification methods, the revised analysis 

assumptions, in effect, establish the new acceptance criteria for the 

component's operating environment. 

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.

Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to evaluate, track, and trend plant issues/events. Those issues and events, 

whether industry or plant specific, that are potentially significant to the Electrical 

Equipment Qualification Program at Palisades, are evaluated. The Electrical 

Equipment Qualification Program is augmented, as appropriate, if these 

evaluations show that program changes are required to enhance program 

effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Electrical Equipment Qualification Program issues are addressed 

in a timely manner and that age-related deterioration of components within the 

scope of the Electrical Equipment Qualification Program will be effectively 

managed throughout the period of extended operation.

A review of applicable operating experience was performed to determine if there 

were deficiencies or recurring failures that would raise questions about EEQ 

Program effectiveness. No significant items were found. Similar reviews were 
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performed of inspection, assessment, and audit reports. No significant findings 

were identified. Some issues have been identified that have resulted in 

appropriate corrective actions and enhancements.

The Palisades Electrical Equipment Qualification Program has demonstrated 

that it provides reasonable assurance that aging effects are being managed for 

all EQ components. This has been demonstrated through NRC inspection 

reports, audits, self-assessments, and the Corrective Action Program.

This element is consistent with NUREG-1801, Section X.E1, “Environmental 

Qualification (EQ) of Electrical Components.”

Conclusion

The Electrical Equipment Qualification Program is a plant specific program, implemented in 

accordance with 10 CFR 50.49, that uses as its bases, various industry and NRC standards. 

This program is consistent with NUREG-1801, Section X.E1, “Environmental Qualification 

(EQ) of Electrical Components.”

Reports of recent internal and external assessments of the program have been reviewed. 

These reports demonstrate that the program has effectively identified and dispositioned 

issues that could have led to degraded conditions. It is concluded that the Electrical 

Equipment Qualification Program has been effective in maintaining the intended functions of 

the affected long-lived, passive SSCs.

The continued implementation of the Electrical Equipment Qualification Program provides 

reasonable assurance that aging effects will be managed such that SSCs within the scope 

of this program will continue to perform their intended functions consistent with the current 

licensing bases for the period of extended operation.

B3.2 Fatigue Monitoring Program

Program Description

The Fatigue Monitoring Program is a new program that ensures that limits on fatigue usage 

are not exceeded during the renewal term. The program monitors and tracks selected cyclic 

loading transients (cycle counting) and their effects on susceptible components. Palisades 

has selected this option under 10 CFR 54.21 to manage cracking due to metal fatigue of the 

reactor coolant pressure boundary during the extended period of operation.

The Fatigue Monitoring Program provides the cycle counting activities credited in Section 

4.3 for confirming analytically derived cumulative usage values for applicable locations. 

Specific locations that may be subject to cyclic loading that could cause fatigue cracking are 

monitored using a computer-based monitoring program provided by EPRI, called 
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FatiguePro. If warranted, other monitoring methods in addition to cycle counting may also 

be employed under this program to monitor specific locations.

NUREG-1801 Consistency

10 CFR 54.21 allows disposition of TLAAs using an aging management program (AMP). 

The new Palisades Fatigue Monitoring Program is consistent with the description presented 

in NUREG-1801, Section X.M1, “Metal Fatigue of Reactor Coolant Pressure Boundary,” as 

an acceptable option for managing metal fatigue for the reactor coolant pressure boundary, 

including consideration of environmental effects.

Exceptions to NUREG-1801

None.

Enhancements

A Fatigue Monitoring Program will be developed and implemented. Features of the program 

will include monitoring and tracking of selected cyclic loading transients (cycle counting) and 

their effects on critical reactor pressure boundary components and other selected 

components.

Note that the element descriptions describe the program as it will exist after it has been 

implemented. The program is scheduled to be implemented prior to the period of extended 

operation. 

Aging Management Program Elements

The key elements of the Fatigue Monitoring Program are described below. The results of the 

evaluation of each element against NUREG-1801, Section X.M1, “Metal Fatigue of Reactor 

Coolant Pressure Boundary,” is also provided.

Scope of Program

The aging effect/mechanism managed by the Fatigue Monitoring Program for 

components is cumulative fatigue damage/fatigue. The specific components and 

locations encompassed by the cycle counting activities performed under the 

Fatigue Monitoring Program have been identified. These locations are verified 

by analysis to be the leading locations for potential cumulative fatigue damage 

during the period of extended operation. These components include those 

shown for older vintage Combustion Engineering plants in NUREG/CR-6260, as 

applicable to Palisades. The transients to be counted under the cycle-based 

fatigue monitoring program include design transients as well as those not 

considered in the original design. 
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The Fatigue Monitoring Program also addresses the effects of the coolant 

environment on component fatigue life by analyzing the impact of the reactor 

coolant environment on a sample of critical components and adjusting the CUF 

accordingly for those locations. Critical components are evaluated by applying 

environmental correction factors to the existing fatigue analyses. Formulas for 

calculating the environmental life correction factors are those contained in 

NUREG/CR-6583 for carbon and low-alloy steels and in NUREG/CR-5704 for 

austenitic stainless steels.

This program element is consistent with NUREG-1801, Section X.M1, “Metal 

Fatigue of Reactor Coolant Pressure Boundary.” 

Preventive Actions

The Palisades Fatigue Monitoring Program includes measures to prevent 

cracking due to cumulative fatigue damage in metal components within the 

reactor coolant pressure boundary and other selected locations. Cracking 

attributable to anticipated cyclic strains in the reactor coolant pressure boundary 

or other selected locations are prevented by monitoring actual incremental 

fatigue usage to ensure that the cumulative usage factor (CUF) remains below 

the Code requirement of <1.0 during the period of extended operation. Below 

this value, fatigue cracks are not expected to occur.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.” 

Parameters Monitored, Inspected, and/or Tested

The Palisades Fatigue Monitoring program monitors selected system 

temperatures, pressures and flows to determine the number and severity of 

cyclic loading events anticipated to be significant contributors to cumulative 

fatigue damage. If conditions warrant, detailed local monitoring of cyclic loading 

stresses (stress-based fatigue monitoring) at specific locations may be used to 

compute the fatigue usage for certain components.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.” 

Detection of Aging Effects

The Fatigue Monitoring Program provides for periodic updates of the plant cycle 

count and fatigue usage calculations. The metal fatigue aging effect is 

monitored using FatiguePro, which is an EPRI software product for plant 
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transient monitoring and fatigue usage calculations. Plant operating cycles are 

tracked against design limits. Fatigue usage factors are computed on an 

on-going basis for bounding components using plant instrument data.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.” 

Monitoring and Trending

The Palisades Fatigue Monitoring Program is used to monitor a sample of high 

fatigue usage locations. This sample includes the applicable locations identified 

in NUREG/CR 6260 for older vintage CE plants.

Use of FatiguePro enables actual fatigue usage to be trended, real time, based 

upon actual plant data. FatiguePro is loaded with initial baseline data which 

includes the total transient cycles counted under the prior cycle counting 

activities, as well as the initial cumulative fatigue usage values calculated for 

monitored locations. Thereafter, the incremental contribution for defined 

transient cycles are added to the initial usage values to produce running totals of 

cumulative fatigue usage at each monitored location. These totals, as well as 

the incremental cumulative fatigue usage values for the period, are available to 

the user on demand.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.” 

Acceptance Criteria

The acceptance criteria consists of maintaining the fatigue usage factor less 

than or equal to the design code allowable limit of 1.0, considering 

environmental fatigue effects, and the cumulative number of plant cycles less 

than or equal to the cyclic design basis. For the components for which an 

environmentally-assisted fatigue evaluation is performed, the fatigue usage 

factor limit is taken to be a value of 1/Fen. The acceptance criteria ensures that 

all original structural margins considered in the plant design are maintained 

through the extended period of operation.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.” 

Corrective Actions, Confirmation Process, Administrative Controls

These elements are consistent with the corresponding NUREG-1801 aging 

management program elements. See Section B1.2 for further discussion.
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Operating Experience

Palisades has a comprehensive Operating Experience Program (OEP) that 

monitors industry issues/events and assesses these for applicability to its own 

operations. In addition, the Palisades Corrective Action Program (CAP) is used 

to track, trend and evaluate plant issues/events. Those issues and events, 

whether external or plant specific, that are potentially significant to the Fatigue 

Monitoring Program at Palisades will be evaluated. The Fatigue Monitoring 

Program will be augmented, as appropriate, if these evaluations show that 

program changes or monitoring of additional locations will enhance program 

effectiveness.

Using the OEP and CAP to focus on industry and plant operating experience 

ensures that Fatigue Monitoring Program issues are addressed in a timely 

manner and that age related deterioration of SSC within the scope of the 

Fatigue Monitoring Program will be effectively managed throughout the license 

renewal period.

Industry Operating Experience has shown that significant thermal stresses in 

piping connected to reactor coolant systems have caused piping failures and 

subsequent leakage from reactor coolant systems at some plants. NRC Bulletin 

No. 88-08 and its supplements brought wide visibility to these issues beginning 

in June 1988. Later that same year, NRC Bulletin No. 88-11 covered issues 

pertaining specifically to thermal stratification and unexpected thermal cyclic 

loadings in the pressurizer surge line. NRC Bulletins 88-08 and 88-11 

highlighted the need for evaluation and monitoring of cyclic loading events that 

were not considered in the original design of Class 1 piping and components. 

Subsequent to the identification of thermal stratification issues, significant 

resources have been expended in an effort to monitor cumulative fatigue 

damage due thermal fatigue.

While actual failures attributable to cumulative fatigue damage/thermal fatigue 

have been relatively rare, failures have occurred. EPRI has captured the 

significant operating experience in MRP-85, Materials Reliability Program: 

Operating Experience Regarding Thermal Fatigue of Piping Connected to PWR 

Reactor Coolant Systems. This experience was reviewed for development of the 

Fatigue Monitoring Program, but is not repeated here.

Since this is a new program, there is no significant plant-specific programmatic 

operating experience with which to make a determination as to its effectiveness. 

However, Palisades has been tracking and logging plant-specific transient 
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cycles. A review was performed of plant-specific analytical results and transient 

logs for all tracked transients, as well as industry operating experience related to 

metal fatigue. The need for more rigorous cycle counting methodology has been 

determined. In addition, review of the tracked transients revealed the following 

issues:

Feedwater Flow Cycling

The use of auxiliary feedwater to slug feed feedwater into the Steam Generator 

feedwater nozzles during hot standby conditions has been shown to be a 

significant thermal stratification stress cycling event, not included in original 

design bases. The replacement steam generators, installed in 1990, 

incorporated separate auxiliary feedwater nozzles which minimize the potential 

for water hammer and thermal stratification. Use of these separate auxiliary 

feedwater nozzles during hot standby has been shown to minimize the 

occurrence of thermally stratified feedwater flow into the steam generators. 

Therefore Palisades has determined that this transient need not be counted.

Charging and Letdown Transients

Charging nozzles generally show a high design basis fatigue usage due to the 

relatively large number of rapid temperature transients that can occur when 

either charging or letdown flow, or both, are terminated and reinitiated. These 

transients can occur during normal plant operation, including during surveillance 

testing of the control and isolation valves. Unlike many of the design basis 

transients, the charging and letdown transients occur fairly often in normal plant 

operation and can be nearly as severe as the design basis transient. Therefore, 

these plant transients will be added to the cycle tracking list. If warranted, the 

charging nozzles may be included as stress-based fatigue-monitored locations, 

as these nozzles tend to be the highest fatigue locations in the system and could 

serve to bound the other system locations.

Pressurizer Spray Line Cycling

The Palisades pressurizer spray nozzle can be anticipated to show a relatively 

high design fatigue usage due to the large temperature shocks that regularly 

occur during heatup and cooldown conditions. Stratified flow in the pressurizer 

spray line was not considered to be significant because Palisades operates with 

continuous pressurizer spray flow of 60 to 80 gpm. Palisades assumes that 

one spray actuation will occur during each plant cooldown. The fatigue damage 

to the spray nozzle could conceivably be tracked just by counting the number of 

plant cooldowns. However, it is expected that main spray actuations of varying 
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severities and duration could also occur during other plant conditions, such as 

plant heatup. Also, under certain conditions, the temperature difference between 

the source of the auxiliary spray and the main spray could be significant, thereby 

having the potential to cause significant thermal shocking at the auxiliary 

spray-to-main spray tee. Based upon the uncertainty in attempting to precisely 

monitor the fatigue damage of the spray nozzle, Palisades will not track spray 

cycles, but may include the spray nozzle as a stress-based fatigue-monitored 

location.

Pressurizer Surge Line Cycling

The issue of thermal stratification cycling in the surge line was addressed 

extensively in the industry's response to NRC IE Bulletin 88-11. CE evaluated 

the surge line and concluded that the fatigue usage of the pressurizer surge 

nozzle and the hot leg piping surge nozzle will be relatively high, but less than 

the ASME CUF limit of 1.0. It is a complex undertaking to identify the occurrence 

and magnitude of insurge or outsurge flow in the surge line. Based upon the 

complexity and uncertainty in the ability to adequately monitor the fatigue 

damage of the surge lines and the connected nozzles, Palisades does not 

intend to track surge cycles, but may monitor both surge line nozzles using 

stress-based fatigue-monitoring

Failures in Unisolable Piping

Intermittent valve leakage, causing thermally stratified conditions in unisolable 

sections of piping, have caused failures in safety injection nozzles and in socket 

welds near the reactor coolant piping in several plants. Such conditions were the 

subject of NRC IE Bulletin 88-08. Based upon that experience, the high 

pressure safety injection nozzles may be included in the Fatigue Monitoring 

Program as either cycle-based or stress-based fatigue locations.

This element is consistent with NUREG-1801, Section X.M1, “Metal Fatigue of 

Reactor Coolant Pressure Boundary.”

Conclusion

The Fatigue Monitoring Program is a new program that uses as its bases various industry 

and NRC documents, as well as industry operating experience, plant-specific design and 

plant-specific analysis. This program is consistent with NUREG-1801, Section X.M1, “Metal 

Fatigue of Reactor Coolant Pressure Boundary.”

Implementation of the Fatigue Monitoring Program will provide reasonable assurance that 

cumulative fatigue usage will be managed such that systems and components within the 
Page B-171 

Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

scope of this program will continue to perform their intended functions, consistent with the 

current licensing bases, during the period of extended operation.
Page B-172 

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Application for Renewed Operating Licenses

Appendix B - Aging Management Programs

Appendix B References

1. NUREG-1800, Standard Review Plan for Review of License Renewal Applications for 

Nuclear Power Plants, U.S. Nuclear Regulatory Commission, July 2001.

2. NUREG-1801, Generic Aging Lessons Learned (GALL) Report, U.S. Nuclear Regulatory 

Commission, July 2001.

3. Quality Program Description for Nuclear Power Plants (Part 2) - Palisades Nuclear Plant 

(CPC-2A)

4. 10 CFR 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and Fuel 

Reprocessing Plants”

5. EA-03-009, “Issuance of First Revised NRC Order Establishing Interim Inspection 

Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors” (dated 

2/20/04)

6. Palisades Plant Response to Revised NRC Order EA-03-009, “Issuance of First Revised 

NRC Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel 

Heads at Pressurized Water Reactors” (dated 3/8/04)

7. 45. SAND96-0344, UC-523, “Aging Management Guideline for Commercial Nuclear Power 

Plants - Electrical Cables and Terminations” (DOE and EPRI, dated September 1996)
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix C - AMR Methodology

APPENDIX C

(Not Used for This Application)
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix C

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APPENDIX C

Contents
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Application for Renewed Operating Licenses

Appendix C

C1.0 Appendix C - Not Used

Appendix C is not used in this application.
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix D - Technical Specification Changes

APPENDIX D

TECHNICAL SPECIFICATION CHANGES
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix D - Technical Specification Change

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APPENDIX D

Contents
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Application for Renewed Operating Licenses

Appendix D - Technical Specification Changes

D1.0 Appendix D - Technical Specifications Changes

10 CFR 54.22 requires that an application for license renewal include any Technical Specification 

changes or additions that are necessary to manage the effects of aging during the period of 

extended operation. A review of the information provided in this License Renewal Application and 

the Palisades Technical Specifications confirms that no changes to the Technical Specifications are 

necessary.
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix E - Environmental Report

APPENDIX E

(Provided as Linked Document)
Palisades Nuclear Plant

Application for Renewed Operating Licenses

Appendix E - Environmental Report

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APPENDIX E

Contents
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Application for Renewed Operating Licenses

Appendix E - Environmental Report

E1.0 Appendix E - Environmental Report

This page provides a link to the Environmental Report.