NUREG-1803

Safety Evaluation Report 

Related to the License 

Renewal of the Edwin I. 

Hatch Nuclear Plant,

Units 1 and 2

Docket Nos. 50-321 and 50-366 

U.S. Nuclear Regulatory Commission 

Office of Nuclear Reactor Regulation 

Washington, DC 20555-0001
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I
NUREG-1803

Safety Evaluation Report 

Related to the License 

Renewal of Edwin I. 

Hatch Nuclear Plant 

Units 1 and 2 

Docket Nos. 50-321 and 50-366 

Manuscript Completed: November 2001 

Date Published: December 2001 

Division of Regulatory Improvement Programs 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001
ABSTRACT

This safety evaluation report (SER) documents the technical review of the Edwin I. Hatch 

Nuclear Plant (Plant Hatch), Unit Nos. 1 and 2, license renewal application (LRA) by the U.S. 

Nuclear Regulatory Commission staff (staff). By letter dated February 29, 2000, Southern 

Nuclear Operating Company, Incorporated (SNC or the applicant) submitted the LRA for Plant 

Hatch in accordance with Title 10 of the Code of Federal Regulations Part 54 (10 CFR Part 54 

or the Rule). SNC is requesting renewal of the operating licenses for Unit 1 and Unit 2 (license 

numbers DPR-57 and NPF-5) for a period of 20 years beyond the current expiration of 

midnight, August 6, 2014 and midnight, June 13, 2018, respectively. 

The Plant Hatch site is located in Appling County, Georgia. Construction began on Unit 1 in 

1969 and its operating license was issued in 1974. Construction began on Unit 2 in 1972 and 

its operating license was issued in 1978. Each unit consists of a General Electric (GE) boiling

water reactor (BWR) nuclear steam supply system designed to generate 2763 MW-thermal, or 

approximately 900 MW-electric. 

This SER was issued on October 5, 2001 and presented the status of the staff's review of 

information submitted to the NRC through October 5, 2001. The staff identified open items that 

had to be resolved before it could make a determination on the application. These items and 

their resolutions are summarized in Section 1.4 of this report. The staffs final conclusion on the 

review on the Plant Hatch LRA can be found in Section 6 of this SER. 

Since its issuance, the SER has been revised to provide several clarifications. These revisions 

are identified by status bars in the right margins. 

PAPERWORK REDUCTION ACT STATEMENT 

The information collections contained in this NUREG are covered by the requirements of 10 

CFR Parts 50, 51, and 54 which were approved by the Office of Management and Budget, 

approval numbers 3150-0011, 0021, and 0155. 

PUBLIC PROTECTION NOTICIFICATION 

If a means used to impose an information collection does not display a currently valid OMB 

control number, the NRC may not conduct or sponsor, and a person is not required to respond 

to, the information collection.

-iii-
CONTENTS 

ABSTRACT ............................................................. -iii

I INTRODUCTION AND GENERAL DISCUSSION ............................... 1-1 

1.1 Introduction ..................................................... 1-1 

1.2 License Renewal Background ...................................... 1-2 

1.2.1 Safety Reviews .......................................... 1-3 

1.2.2 Environmental Reviews .................................... 1-4 

1.3 Summary of Principal Review Matters ............................... 1-4 

1.4 Summary of Open Items ........................................... 1-7 

1.5 Summary of License Conditions .................................... 1-41 

2 STRUCTURES AND COMPONENTS SUBJECT TO AN AGING MANAGEMENT 

REVIEW .......................................................... 2-1 

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

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

2.1.2 Summary of Technical Information in the Application .............. 2-1 

2.1.2.1 Technical Information for Identifying Systems, Structures, and 

Components Within the Scope of License Renewal ........ 2-2 

2.1.2.2 Technical Information for the Structures and Components 

Subject to an Aging Management Review ................ 2-6 

2.1.3 Staff Evaluation ......................................... 2-10 

2.1.3.1 Evaluation of the Methodology for Identifying Systems, 

Structures, and Components That are Within the Scope of 

License Renewal .................................. 2-10 

2.1.3.2 Evaluation of the Methodology for Identifying Structures and 

Components Subject to an Aging Management Review .... 2-19 

2.1.4 Conclusion ............................................. 2-20 

2.2 Plant Level Scoping Results ....................................... 2-20 

2.2.1 Introduction ............................................ 2-20 

2.2.2 Summary of Technical Information in the Application ............. 2-20 

2.2.3 Staff Evaluation ......................................... 2-21 

2.2.4 Conclusions ............................................ 2-23 

2.3 Scoping and Screening Results: Mechanical .......................... 2-23 

2.3.1 Introduction ............................................ 2-23 

2.3.2 Reactor Coolant System (RCS) ............................ 2-24 

2.3.2.1 Fuel ........................................ 2-24 

2.3.2.2 Nuclear Boiler System ............................. 2-25 

2.3.2.3 Reactor Assembly System .......................... 2-27 

2.3.2.4 Reactor Recirculation System ....................... 2-30 

2.3.2.5 Conclusions ..................................... 2-31 

2.3.3 Engineered Safety Features (ESF) .......................... 2-32 

2.3.3.1 Core Spray System ............................... 2-33 

2.3.3.2 High-Pressure Coolant Iniection ..................... 2-35 

2.3.3.3 Post-LOCA Hydrogen Recombiners (Unit 2 Only) ........ 2-36 

2.3.3.4 Primary Containment Purge and Inerting System ........ 2-38 

2.3.3.5 Reactor Core Isolation Cooling System ............... 2-41
2.3.3.6 Residual Heat Removal (RHR) System ................ 2-42 

2.3.3.7 Standby Gas Treatment System ..................... 2-44 

2.3.3.8 Standby Liquid Control System ...................... 2-51 

2.3.3.9 Conclusions ..................................... 2-53 

2.3.4 Auxiliary Systems ........................................ 2-54 

2.3.4.1 Access Doors System ............................. 2-54 

2.3.4.2 Condensate Transfer and Storage System ............. 2-56 

2.3.4.3 Control Building HVAC ............................ 2-58 

2.3.4.4 Control Rod Drive (CRD) System .................... 2-65 

2.3.4.5 Cranes, Hoists and Elevators System ................. 2-66 

2.3.4.6 Drywell Pneumatics System ........................ 2-67 

2.3.4.7 Emergency Diesel Generators System ................ 2-69 

2.3.4.8 Fire Protection ................................... 2-73 

2.3.4.9 Fuel Oil System .................................. 2-79 

2.3.4.10 Instrument Air System ............................ 2-80 

2.3.4.11 Insulation ..................................... 2-82 

2.3.4.12 Outside Structures HVAC ......................... 2-84 

2.3.4.13 Plant Service Water ............................. 2-88 

2.3.4.14 Primary Containment Chilled Water .................. 2-90 

2.3.4.15 Reactor Building Closed Cooling Water .............. 2-91 

2.3.4.16 Reactor Building HVAC ........................... 2-92 

2.3.4.17 Refueling Equipment System ...................... 2-96 

2.3.4.18 Sampling System ................................ 2-97 

2.3.4.19 Tornado Vents System ........................... 2-98 

2.3.4.20 Traveling Water Screens/Trash Racks System ........ 2-100 

2.3.4.21 Conclusion .................................... 2-101 

2.3.5 Steam and Power Conversion Systems ...................... 2-101 

2.3.5.1 Introduction ........................................ 2-101 

2.3.5.2 Electro-Hydraulic Control System ................... 2-102 

2.3.5.3 Main Condenser System .......................... 2-103 

2.3.5.4 Conclusion ..................................... 2-104 

2.4 Scoping and Screening Results: Structures and Structural Components ... 2-104 

2.4.1 Introduction ........................................... 2-104 

2.4.2 Conduits, Raceways, and Trays ............................ 2-105 

2.4.3 Control Building ........................................ 2-106 

2.4.4 Drywell Penetrations .................................... 2-107 

2.4.5 EDG Building .......................................... 2-109 

2.4.6 Fuel Storage ...................... ; ................... 2-110 

2.4.7 Intake Structure ........................................ 2-112 

2.4.8 Main Stack ............................................ 2-114 

2.4.9 Piping Specialties ....................................... 2-115 

2.4.10 Primary Containment .................................. 2-117 

2.4.11 Reactor Building ...................................... 2-119 

2.4.12 Reactor Building Penetrations ............................ 2-121 

2.4.13 Turbine Buildinq ...................................... 2-123 

2.4.14 Yard Structures ....................................... 2-125 

2.4.15 Conclusions ......................................... 2-127 

2.5 Scoping and Screening Results: Electrical Components ................ 2-127 

2.5.1 Summary of Technical Information in the Application ............ 2-127

-vi-
2.5.2 Staff Evaluation ........................................ 2-128 

2.5.3 Conclusions ........................................... 2-130 

3 AGING MANAGEMENT REVIEW ........................................... 3-1 

3.1 Aging Management Programs ...................................... 3-1 

3.1.1 Reactor Water Chemistry Control ............................ 3-3 

3.1.1.1 Introduction ...................................... 3-3 

3.1.1.2 Summary of Technical Information in the Application ...... 3-3 

3.1.1.3 Staff Evaluation ................................... 3-4 

3.1.1.4 Conclusions ...................................... 3-7 

3.1.2 Closed Cooling Water Chemistry Control ....................... 3-7 

3.1.2.1 Introduction .................................... 3-7 

3.1.2.2 Summary of Technical Information in the Application ...... 3-7 

3.1.2.3 Staff Evaluation ................................... 3-8 

3.1.2.4 Conclusions ..................................... 3-10 

3.1.3 Diesel Fuel Oil Testing ................................... 3-10 

3.1.3.1 Introduction ..................................... 3-10 

3.1.3.2 Summary of Technical Information in the Application ..... 3-10 

3.1.3.3 Staff Evaluation .................................. 3-11 

3.1.3.4 Conclusions ..................................... 3-14 

3.1.4 Plant Service Water and RHR Service Water Chemistry Control .... 3-14 

3.1.4.1 Introduction ..................................... 3-14 

3.1.4.2 Summary of Technical Information in the Application ..... 3-15 

3.1.4.3 Staff Evaluation .................................. 3-15 

3.1.4.4 Conclusions ..................................... 3-17 

3.1.5 Fuel Pool Chemistry Control ............................... 3-17 

3.1.5.1 Introduction .......................... ......... 3-17 

3.1.5.2 Summary of Technical Information in the Application ..... 3-17 

3.1.5.3 Staff Evaluation ................................... 3-17 

3.1.5.4 Conclusions ..................................... 3-19 

3.1.6 Demineralized Water and Condensate Storage Tank Chemistry 

Control ............................................... 3-19 

3.1.6.1 Introduction ................................... 3-19 

3.1.6.2 Summary of Technical Information in the Application ..... 3-19 

3.1.6.3 Staff Evaluation .................................. 3-20 

3.1.6.4 Conclusions ..................................... 3-21 

3.1.7 Suppression Pool Chemistry Control ......................... 3-22 

3.1.7.1 Introduction ..................................... 3-22 

3.1.7.2 Summary of Technical Information in the Application ..... 3-22 

3.1.7.3 Staff Evaluation .................................. 3-22 

3.1.7.4 Conclusions ..................................... 3-24 

3.1.8 Corrective Actions Program ................................ 3-24 

3.1.8.1 Introduction ..................................... 3-24 

3.1.8.2 Summary of Technical Information in the Application ..... 3-24 

3.1.8.3 Staff Evaluation .................................. 3-25 

3.1.8.4 Conclusion ...................................... 3-29 

3.1.9 Inservice Inspection Program ............................... 3-29 

3.1.9.1 Introduction ..................................... 3-29

-vii-
3.1.9.2 Summary of Technical Information in the Application

3.1.9.3 Staff Evaluation .................................. 3-30 

3.1.9.4 Conclusions ..................................... 3-32 

3.1.10 Overhead Crane and Refueling Platform Inspections ............ 3-32 

3.1.10.1 Introduction .................................... 3-32 

3.1.10.2 Summary of Technical Information in the Application .... 3-33 

3.1.10.3 Staff Evaluation ................................. 3-33 

3.1.10.4 Conclusions .................................... 3-35 

3.1.11 Torque Activities ....................................... 3-35 

3.1.11.1 Introduction .................................... 3-35 

3.1.11.2 Summary of Technical Information in the Application..... 3-35 

3.1.11.3 Staff Evaluation ................................. 3-35 

3.1.11.4 Conclusions .................................... 3-37 

3.1.12 Component Cyclic and Transient Limit Program ............... 3-38 

3.1.12.1 Introduction ............................. ..... 3-38 

3.1.12.2 Summary of Technical Information in the Application .... 3-38 

3.1.12.3 Staff Evaluation ................................. 3-38 

3.1.12.4 Conclusions .................................... 3-40 

3.1.13 Plant Service Water and RHR Service Water Inspection Program.. 3-40 

3.1.13.1 Introduction .................................. 3-40 

3.1.13.2 Summary of Technical Information in the Application .... 3-41 

3.1.13.3 Staff Evaluation ................................. 3-41 

3.1.13.4 Conclusions .................................... 3-45 

3.1.14 Primary Containment Leakage Rate Testing Program ........... 3-45 

3.1.14.1 Introduction .................................... 3-45 

3.1.14.2 Summary of Technical Information in the Application .... 3-45 

3.1.14.3 Staff Evaluation ................................. 3-45 

3.1.14.4 Conclusions .................................... 3-48 

3.1.15 Boiling Water Reactor Vessel and Internals (BWRVIP) Program .. 3-48 

3.1.15.1 Introduction .................................... 3-48 

3.1.15.2 Summary of Technical Information in the Application .... 3-48 

3.1.15.3 Staff Evaluation ................................. 3-49 

3.1.15.4 Conclusions .................................... 3-52 

3.1.16 W etted Cable Activities .................................. 3-52 

3.1.16.1 Introduction ........................... ....... 3-52 

3.1.16.2 Summary of Technical Information in the Application .... 3-52 

3.1.16.3 Staff Evaluation ................................. 3-53 

3.1.16.4 Conclusions .................................... 3-53 

3.1.17 Reactor Pressure Vessel (RPV) Monitoring Program ............ 3-53 

3.1.17.1 Introduction ..................................... 3-53 

3.1.17.2 Summary of Technical Information in the Application .... 3-54 

3.1.17.3 Staff Evaluation ................................. 3-54 

3.1.17.4 Conclusion ..................................... 3-56 

3.1.18 Fire Protection Activities .................................. 3-57 

3.1.18.1 Introduction .................................... 3-57 

3.1.18.2 Summary of Technical Information in the Application .... 3-57 

3.1.18.3 Staff Evaluation ................................. 3-57 

3.1.18.4 Conclusions .................................... 3-61 

3.1.19 Flow Accelerated Corrosion Program ........................ 3-61

-viiiS..... 3-30
3.1.19.1 Introduction .................................. 3-61 

3.1.19.2 Summary of Technical Information in the Application .... 3-61 

3.1.19.3 Staff Evaluation ................................. 3-62 

3.1.19.4 Conclusions .................................... 3-64 

3.1.20 Protective Coatings Program .............................. 3-64 

3.1.20.1 Introduction .................................. * 3-64 

3.1.20.2 Summary of Technical Information in the Application .... 3-64 

3.1.20.3 Staff Evaluation ................................. 3-65 

3.1.20.4 Conclusions .................................... 3-67 

3.1.21 Equipment and Piping Insulation Monitoring Program ........... 3-68 

3.1.21.1 Introduction .................................. * 3-68 

3.1.21.2 Summary of Technical Information in the Application .... 3-68 

3.1.21.3 Staff Evaluation ................................. 3-68 

3.1.21.4 Conclusions .................................... 3-70 

3.1.22 Structural Monitoring Program ............................. 3-70 

3.1.22.1 Introduction .................................. * 3-70 

3.1.22.2 Summary of Technical Information in the Application .... 3-71 

3.1.22.3 Staff Evaluation ................................. 3-71 

3.1.22.4 Conclusions .................................... 3-74 

3.1.23 Galvanic Susceptibility Inspections ......................... 3-74 

3.1.23.1 Introduction .................................... 3-74 

3.1.23.2 Summary of Technical Information in the Application .... 3-74 

3.1.23.3 Staff Evaluation ................................. 3-75 

3.1.23.4 Conclusions .................................... 3-76 

3.1.24 Treated Water Systems Piping Inspections ................... 3-77 

3.1.24.1 Introduction .................................... 3-77 

3.1.24.2 Summary of Technical Information in the Application .... 3-77 

3.1.24.3 Staff Evaluation ................................. 3-77 

3.1.24.4 Conclusions .................................... 3-79 

3.1.25 Gas Systems Component Inspections ....................... 3-79 

3.1.25.1 Introduction .................................... 3-79 

3.1.25.2 Summary of Technical Information in the Application .... 3-80 

3.1.25.3 Staff Evaluation ................................. 3-80 

3.1.25.4 Conclusions .................................... 3-82 

3.1.26 Condensate Storage Tank Inspection ....................... 3-82 

3.1.26.1 Introduction .................................... 3-82 

3.1.26.2 Summary of Technical Information in the Application .... 3-82 

3.1.26.3 Staff Evaluation ................................. 3-82 

3.1.26.4 Conclusions .................................... 3-84 

3.1.27 Passive Component Inspection Activities ..................... 3-84 

3.1.27.1 Introduction .................................... 3-84 

3.1.27.2 Summary of Technical Information in the Application .... 3-84 

3.1.27.3 Staff Evaluation ................................. 3-85 

3.1.27.4 Conclusions .................................... 3-86 

3.1.28 RHR Heat Exchanger Augmented Inspection and Testing 

Program .............................................. 3-87 

3.1.28.1 Introduction .................................... 3-87 

3.1.28.2 Summary of Technical Information in the Application .... 3-87 

3.1.28.3 Staff Evaluation ................................. 3-87

-ix-
3.1.28.4 Conclusions .............................. 

3.1.29 Torus Submerged Components Inspection Program ......... 

3.1.29.1 Introduction ................................. 

3.1.29.2 Summary of Technical Information in the Application . 

3.1.29.3 Staff Evaluation ............................. 

3.1.29.4 Conclusions ................................. 

3.1.30 Insulated Cables and Connections Aging Management Program 

3.1.30.1 Introduction ................................. 

3.1.30.2 Summary of Technical Information in the Application .

3-91 

3-91 

3-91 

3-92 

3-92 

3-94 

3-95 

3-95 

3-95

3.1.30.3 Staff Evaluation ................................. 3-95 

3.1.30.4 Conclusions .................................... 3-98 

3.1.31 Diesel Generator Maintenance Activities ...................... 3-98 

3.1.31.1 Introduction .................................... 3-98 

3.1.31.2 Summary of Technical Information in the Application .... 3-98 

3.1.31.3 Staff Evaluation ................................. 3-98 

3.1.31.4 Conclusions ................................... 3-101 

3.2 Reactor Coolant System ......................................... 3-101 

3.2.1 Introduction ........................................... 3-101 

3.2.2 Summary of Technical Information in the Application ............ 3-102 

3.2.2.1 Effects of Aging ...................................... 3-103 

3.2.2.2 Aging Management Programs ..................... 3-105 

3.2.3 Staff Evaluation ........................................ 3-106 

3.2.3.1 Effects of Aging ................................. 3-106 

3.2.3.1.1 Effects of Aging on the Reactor Assembly 

System ................................ 3-106 

3.2.3.1.2 Effects of Aging on the Nuclear Boiler System .. 3-110 

3.2.3.1.3 Effects of Aging on the Reactor Recirculation 

System ................................ 3-111 

3.2.3.2 Aging Management Programs ...................... 3-112 

3.2.3.2.1 Aging Management Programs for Cast Austenitic 

Stainless Steel (CASS) Components ......... 3-112 

3.2.3.2.2 Aging Management Programs for Vessel Flange 

Leak Detection (VFLD) Line ................ 3-113 

3.2.3.2.3 Aging Management Programs for ASME Code 

Class 1 Small-Bore Piping ................. 3-114 

3.2.4 Conclusion ............................................ 3-115 

3.3 Engineered Safety Features ...................................... 3-116 

3.3.1 Introduction ......................................... 3-116 

3.3.2 Summary of Technical Information in the Application ............ 3-116 

3.3.2.1 Aging Effects and Aging Management Programs ........ 3-119 

3.3.3 Staff Evaluation ........................................ 3-124 

3.3.3.1 Aging Effects ................................... 3-126 

3.3.3.2 Aging Management Programs ...................... 3-129 

3.3.4 Conclusions ........................................... 3-133 

3.4 Auxiliary System s .............................................. 3-133 

3.4.1 Introduction ......................................... 3-133 

3.4.2 Summary of Technical Information in the Application ............ 3-134

3.4.2.1 Aging Effects and Aging Management Programs . 

3.4.3 Staff Evaluation .................................. ....... 3-137 

....... 3-142
3.4.3.1 Aging Effects ................................... 3-142 

3.4.3.2 Aging Management Programs ...................... 3-149 

3.4.4 Conclusion ............................................ 3-164 

3.5 Steam and Power Conversion Systems ............................. 3-164 

3.5.1 Introduction ........................................... 3-164 

3.5.2 Summary of Technical Information in the Application ............ 3-165 

3.5.2.1 Aging Effects ................................... 3-165 

3.5.2.2 Aging Management Programs ...................... 3-166 

3.5.3 Staff Evaluation ........................................ 3-167 

3.5.3.1 Effects of Aging ................................. 3-167 

3.5.3.2 Aging Management Programs ...................... 3-167 

3.5.4 Conclusions ........................................... 3-168 

3.6 Structures and Structural Components .............................. 3-168 

3.6.1 Introduction ........................................... 3-168 

3.6.2 Summary of Technical Information in the Application ........... 3-169 

3.6.2.1 Effects of Aging ................................. 3-169 

3.6.2.2 Aging Management Programs ...................... 3-176 

3.6.3 Staff Evaluation ........................................ 3-177 

3.6.3.1 Effects of Aging ................................. 3-177 

3.6.3.2 Aging Management Programs ...................... 3-190 

3.6.4 Conclusion ............................................ 3-206 

3.7 Electrical and Instrumentation and Controls .......................... 3-206 

3.7.1 Summary of Technical Information in the Application ............ 3-207 

3.7.1.1 Effects of Aging ................................. 3-207 

3.7.1.2 Aging Management Programs ...................... 3-208 

3.7.2 Staff Evaluation ........................................ 3-208 

3.7.2.1 Effects of Aging ................................. 3-208 

3.7.2.1.1 Aging Effects on Phase Bussing Caused by High 

Temperature and Radiation ................ 3-209 

3.7.2.1.2 Aging Effects on Nelson Frames ............. 3-209 

3.7.2.1.3 Aging Effects on Cables, Connectors, Splices, 

and Terminal Blocks ...................... 3-210 

3.7.2.2 Aging Management Programs ...................... 3-211 

3.7.2.2.1 Aging Management Program for Wetted 

Cables ................................. 3-211 

3.7.2.2.2 Aging Management Program for Cable, 

Connectors, Splices, and Terminal Blocks ..... 3-211 

3.7.3 Conclusion ............................................ 3-212 

4 TIME-LIMITED AGING ANALYSES ...................................... 4-1 

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

4.1.1 Introduction ............................................. 4-1 

4.1.2 Summary of Technical Information in the Application .............. 4-1 

4.1.3 Staff Evaluation .......................................... 4-2 

4.1.4 Conclusions ............................................. 4-4 

4.2 Pipe Stress ..................................................... 4-4 

4.2.1 Introduction ............................................. 4-4 

4.2.2 Summary of Technical Information in the Application .............. 4-4

-xi-
4.3 Corrosion 4.2.4 Conclusion Allowance .............................................. 4-8 4-9 

4.3.1 Introduction ........................................... 4-9 

4.3.2 Summary of the Technical Information in the Application ........... 4-9 

4.3.3 Staff Evaluation ......................................... 4-10 

4.3.4 Conclusion ............................................. 4-11 

4.4 Environmental Qualification of Electrical Equipment ..................... 4-11 

4.4.1 Summary of Technical Information in the Application ............. 4-11 

4.4.2 Staff Evaluation ......................................... 4-15 

4.4.3 Conclusion ............................................. 4-18 

4.5 Containment Penetration Pressurization Cycles ........................ 4-18 

4.5.1 Summary of Technical Information in the Application ............. 4-18 

4.5.2 Staff Evaluation ......................................... 4-19 

4.5.3 Conclusion ............................................ 4-20 

4.6 Time-Limited Aging Analyses for the Reactor Vessel .................... 4-20 

4.6.1 Summary of Technical Information in the Application ............. 4-20 

4.6.2 Staff Evaluation ......................................... 4-22 

4.6.3 Conclusions ............................................ 4-28 

4.7 Main Steam Isolation Valves Operating Cycles ........................ 4-28 

4.7.1 Introduction ............................................ 4-28 

4.7.2 Summary of Technical Information in Application ................ 4-28 

4.7.3 Staff Evaluation ......................................... 4-29 

4.7.4 Conclusion ............................................. 4-29 

5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS ......... 5-1 

6 CO NCLUSIO NS ........................................................ 6-1 

Appendix A: Chronology .................................................. A-1 

Appendix B: References ................................................... B-1 

Appendix C: Abbreviations ................................................ C-1 

Appendix D: Principal Contributors ......................................... D-1 

Appendix E: Requests for Additional Information .............................. E-1

-xii4.2.3 Staff Evaluation .............. S............. 4-5
1 INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction 

This document is an SER on the application for license renewal for the Edwin I. Hatch Nuclear 

Power Plant Unit Nos. 1 and 2 (Plant Hatch), as filed by Southern Nuclear Operating Company 

(SNC or the applicant). By a letter dated February 29, 2000, SNC submitted its application to 

the United States Nuclear Regulatory Commission (NRC) for renewal of the Plant Hatch 

operating licenses for an additional 20 years. The NRC staff (the staff) prepared this report and 

summarizes the results of its safety review of the renewal application for compliance with the 

requirements of 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear 

Power Plants." The NRC license renewal project manager for the Plant Hatch license renewal 

review is William F. Burton. Mr. Burton may be contacted by calling 301-415-2853, or by writing 

to the License Renewal and Standardization Branch, U.S. Nuclear Regulatory Commission, 

Washington, D.C. 20555-0001. 

In its February 29, 2000 submittal letter, the applicant requested renewal of the operating 

licenses issued under Section 104 and Section 103 of the Atomic Energy Act of 1954, as 

amended, for Unit 1 (license number DPR-57) and Unit 2 (license number NPF-5), respectively, 

for a period of 20 years beyond the current license expirations of midnight, August 6, 2014 for 

Unit 1 and midnight, June 13, 2018 for Unit 2. Plant Hatch is located in Appling County, 

Georgia. Construction began on Unit 1 in 1969 and its operating license was issued in 1974. 

Construction began on Unit 2 in 1972 and its operating license was issued in 1978. Each unit 

consists of a General Electric (GE) boiling-water reactor (BWR) nuclear steam supply system 

designed to generate 2763 MW-thermal, or approximately 900 MW-electric. Details concerning 

the plant and the site are found in the Updated Final Safety Analysis Reports (UFSAR) for the 

units. 

The license renewal process proceeds along two tracks: a technical review of safety issues and 

an environmental review. The requirements for these reviews are stated in NRC regulations 

10 CFR Parts 54 and 51, respectively. The safety review for the Plant Hatch license renewal is 

based on the applicant's license renewal application (LRA) and on the answers to requests for 

additional information (RAIs) from the staff. In meetings and docketed correspondence, the 

applicant has also supplemented its answers to the RAIs. Unless otherwise noted, the staff 

reviewed and considered information submitted through October 5, 2001. Information received 

after that date was reviewed on a case-by-case basis, depending on the stage of the safety 

review. The LRA and all pertinent information and materials, including the UFSAR mentioned 

above, are available to the public for review at the NRC Public Document Room, 11555 

Rockville Pike, Room 1 -F21, Rockville, MD, 20852-2738 (301-415-4737/800-3974209), and at 

the Appling County Library, 242 East Parker St., Baxley, Georgia 31513. Material related to the 

LRA is also available through the NRC's website, at 

http://www.nrc.gov/NRC/REACTOR/LR/index.html. 

This SER summarizes the results of the staff's safety review of the Plant hatch LRA and 

delineates the scope of the technical details considered in evaluating the safety aspects of its 

proposed operation for an additional 20 years beyond the term of the current operating license. 

The LRA was reviewed in accordance with the NRC regulations and the guidance provided in

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the NRC draft "Standard Review Plan for the Review of License Renewal Applications for 

Nuclear Power Plants, "dated September 1997 (SRP-LR). 

Sections 2 through 4 of the SER address the staff's review and evaluation of license renewal 

issues that have been considered during the review of the application. Section 5 is reserved for 

the report of the Advisory Committee on Reactor Safeguards (ACRS). The conclusions of this 

report are in Section 6. 

Appendix A of this SER is a chronology of NRC's and the applicant's principal correspondence related to the review of the application. Appendix B of this SER is a bibliography of the 

references used during the course of the review. Appendix C of this SER is a list of 

abbreviations used throughout the report. The staff's principal reviewers for this project are listed in Appendix D of this SER. Appendix E of this SER presents an index of the staff's RAIs 

and the applicant's responses. 

Since its issuance on October 5, 2001, the SER has been revised to provide several 

clarifications. These revisions are identified by status bars in the right margins. 

In accordance with 10 CFR Part 51, the staff prepared final plant-specific supplement to the 

generic environmental impact statement (GELS) that discusses the environmental 

considerations related to renewing the licenses for Plant Hatch. The plant-specific supplement to the GElS will be issued separate from this report. 

1.2 License Renewal Background 

Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, licenses for 

commercial power reactors to operate are issued for 40 years. These licenses can be renewed 

for up to 20 additional years. The original 40-year license term was selected on the basis of 

economic and antitrust considerations -- not by technical limitations. However, some individual 

plant and equipment designs may have been engineered on the basis of an expected 40-year 

service life. 

In 1982, the NRC held a workshop on nuclear power plant aging, in anticipation of the interest 

in license renewal. That led the NRC to establish a comprehensive program plan for nuclear 

plant aging research (NPAR). On the basis of the results of that research, a technical review 

group concluded that many aging phenomena are readily manageable and do not pose technical issues that would preclude life extension for nuclear power plants. In 1986, the NRC 

published a request for comment on a policy statement that would address major policy, technical, and procedural issues related to life extension for nuclear power plants. 

In 1991, the NRC published the license renewal rule in 10 CFR Part 54. The NRC participated in, and industry sponsored, demonstration programs to apply the rule to pilot plants and 

develop experience to establish implementation guidance. To establish a scope of review for 

license renewal, the rule defined age-related degradation unique to license renewal. However, during the demonstration program, the NRC found that many aging mechanisms occur and are 

managed during the period of initial license. In addition, the NRC found that the scope of the 

review did not allow sufficient credit for existing programs, particularly the implementation of the 

maintenance rule, which also manages plant aging phenomena. As a result, in 1995 the NRC 

amended the license renewal rule. The amended 10 CFR Part 54 established a regulatory

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process that is expected to be simpler, more stable, and more predictable than the previous 

license renewal rule. In particular, 10 CFR Part 54 was clarified to focus on managing the 

adverse effects of aging rather than on identification of all aging mechanisms. The rule 

changes were intended to ensure that important systems, structures, and components (SSCs) 

will continue to perform their intended function in the period of extended operation. In addition, 

the integrated plant assessment (IPA) process was clarified and simplified to be consistent with 

the revised focus on passive, long-lived structures and components (SCs). 

In parallel with these efforts, the NRC pursued a separate rulemaking effort, 10 CFR Part 51, to 

focus the scope of the review of environmental impacts of license renewal, in fulfilling NRC's 

responsibilities under the National Environmental Policy Act of 1969 (NEPA). 

1.2.1 Safety Reviews 

License renewal requirements for power reactors are based in two key principals: 

(1) The regulatory process is adequate to ensure that the licensing bases of all currently 

operating plants provide and maintain an acceptable level of safety, with the possible 

exception of the detrimental effects of aging on the functionality of certain plant SSCs in 

the period of extended operation, and possibly a few other issues related to safety 

during the period of extended operation. 

(2) The plant-specific licensing basis must be maintained during the renewal term in the 

same manner and to the same extent as during the original licensing term. 

In implementing these two principles, the rule in 10 CFR 54.4 defines the scope of license 

renewal as those SSCs (a) that are safety-related; (b) whose failure could affect safety-related 

functions; and (c) that are relied on to demonstrate compliance with the NRC's regulations for 

fire protection, environmental qualification, pressurized thermal shock, anticipated transients 

without scram, and station blackout. 

Pursuant to 10 CFR 54.21 (a), the applicant must review all SSCs within the scope of the rule to 

identify SCs subject to an AMR. SCs subject to an AMR are those that perform an intended 

function without moving parts or without a change in configuration or properties and that are not 

subject to replacement based on qualified life or specified time period. As required by 10 CFR 

54.21(a), it must be demonstrated that the effects of aging will be managed in such a way that 

the intended function or functions of those SCs will be maintained, consistent with the current 

licensing basis, for the period of extended operation. Active equipment, however, is considered 

to be adequately monitored and maintained by existing programs. In other words, the 

detrimental aging effects that may occur for active equipment are more readily detectable and 

will be identified and corrected through routine surveillance, performance indicators, and 

maintenance. The surveillance and maintenance programs for active equipment, as well as 

other aspects of maintaining the plant design and licensing basis, are required throughout the 

period of extended operation. Section 54.21(d) requires that a supplement to the UFSAR 

contain a summary description of the programs and activities for managing the effects of aging. 

Another requirement for license renewal is the identification and updating of time-limited aging 

analyses (TLAAs). During the design phase for a plant, certain assumptions are made about 

the length of time the plant will be operated and these assumptions are incorporated into desgin

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calculations for several of the plant's SSCs. Under 10 CFR 54.21 (c)(1), these calculations must 

be shown to be valid for the period of extended operation or must be projected to the end of the 

period of extended operation, or the applicant must demonstrate that the effects of aging on 

these SSCs will be adequately managed for the period of extended operation. 

In 1996, the NRC developed and issued draft regulatory guide DG-1047, "Standard Format and 

Content for Applications to Renew Nuclear Power Plant Operating License." This guide 

proposes to endorse an implementation guideline prepared by the Nuclear Energy Institute 

(NEI) as an acceptable method of implementing the license renewal rule. The NEI guideline is 

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

License Renewal Rule," which was issued in March 1996. The NRC prepared a draft standard 

review plan for the safety review which was made available in the Public Document Room in 

September 1997. The draft regulatory guide will be used, along with the draft standard review 

plan, to review applications and to assess technical issue reports involved in license renewal as 

submitted by industry groups. As experience is gained, NRC will improve the standard review 

plan and clarify regulatory guidance. 

1.2.2 Environmental Reviews 

The environmental protection regulations, 10 CFR Part 51, were revised in December 1996 to 

facilitate the environmental review for license renewal. The staff prepared a GELS, in which the 

staff examined the possible environmental impacts associated with renewing licenses of nuclear 

power plants. For certain types of environmental impacts the GElS establishes generic findings 

that are applicable to all nuclear power plants. These generic findings are identified as 

Category 1 issues in 10 CFR Part 51, Subpart A, Appendix B. Pursuant to 10 CFR 

51.53(c)(3)(i), an applicant for license renewal may incorporate these generic findings in its 

environmental report. Analyses of those environmental impacts that must be evaluated on a 

plant-specific basis, Category 2 issues, must be included in the environmental report in 

accordance with 10 CFR 51.53(c)(3)(ii). 

In accordance with NEPA and the requirements of 10 CFR Part 51, the staff performed a plant

specific review of the environmental impacts of license renewal, including whether there was 

new and significant information not considered in the GElS. A public meeting was held on 

May 10, 2000, in Vidalia, Georgia, as part of the NRC scoping process, to identify 

environmental issues specific to the plant. Results of the environmental review and a 

preliminary recommendation with respect to the license renewal action were documented in 

NRC's draft plant-specific supplement to the GELS, which was issued by the NRC on November 

3, 2000, and which was discussed at a separate public meeting held on December 12, 2000 in 

Vidalia, GA. After consideration of comments on the draft, NRC prepared a final plant-specific 

supplement to the GELS, which was published by the NRC on May 31, 2001. These documents 

are published separate from this report. 

1.3 Summary of Principal Review Matters 

The requirements for renewing operating licenses for nuclear power plants are described in 

10 CFR Part 54. The staff performed its technical review of the Plant Hatch LRA in accordance 

with Commission guidance and the requirements of 10 CFR 54.19, 54.21, 54.22, 54.23, and 

54.25. The standards for renewing a license are contained in 10 CFR 54.29. This SER 

describes the results of the staff's safety review.

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In 10 CFR 54.19(a), the Commission requires a license renewal applicant to submit general information. The applicant provided this general information in Section 1 of its LRA for Plant 

Hatch, submitted by letter dated February 29, 2000. The staff finds that the applicant has 

submitted the information required by 10 CFR 54.19(a) in Section 1 of the LRA. 

In 10 CFR 54.19(b), the Commission requires that license renewal applications 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 applicant states the 

following in its LRA regarding this issue: 

"...Article VII of the original Indemnity Agreement, which was issued on August 2, 1973, 

along with the HNP [Plant Hatch] Materials License, provides that the Agreement will 

terminate at the expiration of the license identified in Item 3 of the Attachment (SNM

1378). Since August 2, 1973, the Indemnity Agreement has been amended from time to 

time. Two of these amendments added license numbers DPR-57 and NPF-5 to Item 3 

of the Attachment. As a consequence of these amendments, the existing Indemnity 

Agreement is presently due to terminate at midnight, June 13, 2018, as the last of these 

two licenses expires. SNC requests that conforming changes be made to Item 3 of the 

Attachment to the Indemnity Agreement (and any other provision of the Attachment or 

Indemnity Agreement) to make clear that the Indemnity Agreement is extended until the 

expiration date of the renewed HNP operating licenses issued by the Commission in 

response to this application." 

The staff intends to maintain the license numbers on issuance of the renewed license. 

Therefore, there is no need to make conforming changes to the indemnity agreement, and the 

requirements of 10 CFR 54.19(b) have been met. 

In 10 CFR 54.21, the Commission requires that each application for a renewal license for a 

nuclear facility must contain the following information: (a) an IPA, (b) current licensing basis 

(CLB) changes during Staff review of the application, (c) an evaluation of TLAAs, and (d) an 

FSAR supplement. Sections 3 and 4, and Sections A and B of the LRA, address the license 

renewal requirements of 10 CFR 54.21 (a), (c), and (d), respectively. 

In 10 CFR 54.22, the Commission states requirements regarding technical specifications. The 

applicant addresses the requirements of 10 CFR 54.22 in Appendix E of the LRA. 

The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in 

accordance with the NRC's regulations and the guidance provided by the draft SRP. The staff's 

evaluation of the LRA in accordance with 10 CFR 54.21 and 54.22 is contained in Sections 2, 3, 

and 4 of this report. 

The staff's evaluation of the environmental information required by 10 CFR 54.23 will be found 

in the draft and final plant-specific supplements to the GElS that state the considerations 

related to renewing the license for Plant Hatch. These documents will be prepared by the staff 

separate from this report. When the report of the Advisory Committee on Reactor Safeguards 

(ACRS), required by 10 CFR 54.25, is issued, it will be incorporated into Section 5 of this SER. 

The findings required by 10 CFR 54.29 will be placed in Section 6 of this report.

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Boiling Water Reactor Vessel Internals Project (BWRVIP) Topical Reports

In accordance with 10 CFR 54.17(e), the applicant also incorporated by reference several 

BWRVIP topical reports into the Plant Hatch LRA. The purpose of the topical reports is to 

generically demonstrate that the aging effects for reactor coolant system components are 

adequately managed for the period of extended operation under a renewed license. 

Specifically, the applicant incorporated the following BWRVIP topical reports into its application: 

0 BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," 

July 1996 

* BWRVIP-26, "Top Guide Inspection and Flaw Evaluation Guidelines," December 1996 

* BWRVIP-27, "Standby Liquid Control System/Core Plate AP Inspection and Flaw 

Evaluation Guidelines," April 1997 

* BWRVIP-38, "Shroud Support Inspection and Flaw Evaluation Guidelines," September 

1997 

0 BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," 

October 1997 

a BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," 

December 1997 

BWRVIP-48, "Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," 

March 1998 

BWRVIP-74, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines," September 1999. 

BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection 

Schedules (NUREG-0313)," October 1999 

BWRVIP-76, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," 

December 1999 

All the BWRVIP reports listed above have been approved by the staff, with the following 

exceptions: 

BWRVIP-74: The staff is finalizing its safety evaluation. 

BWRVIP-76: This BWRVIP report incorporates BWRVIP-01, -07 and -63. The staff's 

review of the BWRVIP-07 report is complete. The staff has issued a 

safety evaluation with open items for BWRVIP-63 and is presently 

reviewing the BWRVIP's response to these open items.

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The licensee has committed to follow the BWRVIP reports as approved by the staff. The staff 

finds this commitment to be acceptable for aging management of the systems and components 

addressed in the subject BWRVIP reports. 

1.4 Summary of Open Items 

As a result of its review of the LRA for Plant Hatch, including additional information submitted to 

the NRC through January 31, 2001, the staff identified the following issues that remained open 

at the time this report was prepared. An issue was open if the applicant had not presented a 

sufficient basis for resolution. Each open item has been assigned a unique identifying number. 

Item Description 

2.1.3.1-1 Non-Safety-Related Piping Systems (Seismic II-over-I) 

Section 54.29 of 10 CFR Part 54 (the Rule) states that a renewed license may 

be issued by the Commission if the Commission finds that actions have been or 

will be taken with respect to the matters identified in paragraphs (a)(1) and (a)(2) 

of this section such that there is reasonable assurance that the activities 

authorized by the renewed license will continue to be conducted in accordance 

with the CLB, and that any changes made to the CLB in order to comply with this 

paragraph are in accord with the Act and the Commission's regulations. These 

matters include managing the effects of aging during the period of extended 

operation to assure the functionality of structures and components that have 

been identified to require review under Section 54.21(a)(1). 

The Statements of Consideration (SOC) for the Rule states that the objective of 

a license renewal review is to determine whether the detrimental effects of aging, 

which could adversely affect the functionality of systems, structures, and 

components (SSCs) that the Commission determines require review for the 

period of extended operation, are adequately managed. 

The SOC articulates the underlying philosophy of the Rule 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. 

Aging effects that could adversely impact on the ability of SSCs to maintain 

these safety-related functions during the extended period of operation should be 

evaluated. 

Section 54.4(a)(2) of the Rule states that all non-safety-related systems, 

structures, and components whose failure could prevent satisfactory 

accomplishment of any of the functions identified in Section 54.4(a)(1) should be 

included within the scope of the Rule. The SOC provides additional guidance 

related to this scoping criterion. Specifically, the SOC states that "To limit this 

possibility for the scoping category relating to nonsafety-related systems, 

structures, and components... An applicant for license renewal should rely on 

the plant's CLB, actual plant-specific experience, industry-wide operating 

experience, as appropriate, and existing engineering evaluations to determine 

those nonsafety-related systems, structures, and components that are the initial

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focus of the license renewal review. Consideration of hypothetical failures that 

could result from system interdependencies that are not part of the CLB and that 

have not been previously experienced is not required." (Federal Register, 

Volume 60, No. 88, 22467). 

An applicant for license renewal should consider two configurations of non

safety-related piping systems that could potentially meet the 54.4(a)(2) scoping 

criterion. The first configuration includes non-safety- related piping systems 

(including piping segments and supports) which are connected to safety-related 

piping. These non-safety-related piping systems should be included within the 

scope of license renewal up to and including the first seismic support past the 

safety-related/no n-safety-related interface. The second configuration involves 

non-safety-related piping systems which are not connected to safety-related 

piping, but have a spatial relationship such that their failure could adversely 

impact on the performance of an intended safety function. For this type of piping 

system, the applicant has two options when performing its scoping evaluation: a 

mitigative option or a preventive option. With the mitigative option, the applicant 

must demonstrate that plant mitigative features (e.g., pipe whip restraints, jet 

impingement shields, spray and drip shields, seismic supports, flood barriers, 

etc.) are provided which protect safety-related SSCs from failures of non-safety

related piping segments. When evaluating the failure modes of non-safety

related piping segments and the associated consequences, age-related 

degradation must be considered. The staff notes that pipe failure evaluations 

typically do not consider age-related degradation when determining pipe failure 

locations. Rather, pipe failure locations are normally postulated based on high 

stress. Industry operating experience has shown that age-related pipe failures 

can, and do, occur at locations other than the high-stress locations postulated in 

most pipe failure analyses. Therefore, to utilize the mitigative option, an 

applicant should demonstrate that the mitigating devices are adequate to protect 

safety-related SSCs from failures of non-safety-related piping segments at any 

location where age-related degradation is plausible. If this level of protection can 

be demonstrated, then only the mitigative features need to be included within the 

scope of license renewal, and the piping segments need not be included within 

the scope. However, if an applicant cannot demonstrate that the mitigative 

features are adequate to protect safety-related SSCs from the consequences of 

non-safety-related pipe failures, then the applicant should utilize the preventive 

option, which requires that the entire non-safety-related piping system be 

brought into the scope of license renewal and an AMR be performed on the 

components within the piping system. Finally, an applicant may determine that 

in order to ensure adequate protection of the safety-related SSC, a combination 

of mitigative features and non-safety-related SSCs must be brought within 

scope. Again, it is incumbent upon the applicant to provide adequate justification 

for the approach taken with respect to scoping of non-safety-related SSCs in 

accordance with the Rule. 

A subset of non-safety-related piping systems that meet the 54.4(a)(2) criterion 

is seismic II over I (seismic II/I) piping. Seismic II/ I denotes non-seismic 

Category I SSCs interacting with seismic Category I SSCs as described in 

Position C.2 of Regulatory Guide 1.29, "Seismic Design Classification." The

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SOC specifically includes seismic Il/I as a subset of the 54.4(a)(2) scoping 

requirement. In addition, Section 2.1 .Il1.B of the Standard Review Plan for 

License Renewal (September, 1997) states that 'The reviewer verifies that the 

so-called 'seismic II over I' systems, structures, and components consistent with 

the plant's CLB are identified by the applicant's proposed screening 

methodology." 

By letter dated July 28, 2000, the staff issued two requests for additional 

information related to seismic Il/I SSCs. RAI 3.4-11 asked the applicant to clarify 

whether the scope of the auxiliary systems discussed in Section 3.2.4 of the LRA 

includes any spatially-related components and piping segments within the 

category of seismic Il/I, and how the aging management programs discussed in 

Table 3.2.4 of the application also apply to seismic Il/I piping components. RAI 

3.6-51 stated that it was not clear to the staff whether the scope of the primary 

containment system discussed in Table 3.3.1-3 of the LRA includes spatially

related components and piping systems within the category of seismic Il/I, and 

asked the applicant to clarify the scope and whether the same aging 

management programs discussed in LRA Table 3.3.1-3 also applied to seismic 

Il/I piping components. 

By letter dated October 10, 2000, the applicant responded to these RAIs. In 

response to RAI 3.4-11 the applicant stated that intended function L35-01, "Pipe 

Supports," captures all safety-related and non-safety-related supports for 

components in configurations that could potentially result in loss of function for 

seismic Category I components based on spatial relationships. The applicant 

further stated that the key to managing both seismic Category I and non-seismic 

Category I systems so that no impact on safety-related functions occurs, is to 

assure that aging effects for the supports encompassed by L35-01 are 

appropriately managed, and that, based on empirical evidence related to piping 

and pipe supports under seismic loadings, managing the aging effects 

associated with the pipe supports for systems not otherwise in scope is adequate 

to assure no loss of safety-related functions. On this basis, the applicant 

concluded that no AMPs are applied to piping segments that are not in scope, 

but are supported by seismic I!/I piping supports. 

In response to RAI 3.6-51, the applicant stated that LRA Table 3.3.1-3 

addresses components supporting the primary containment integrity function, 

including safety-related and non-safety-related components inside containment, 

but the piping supports are included in LRA Table 3.3.1-1, "Piping Specialties." 

During subsequent discussions with the staff, the applicant clarified that for the 

protection of safety-related SSCs, seismic Il/I piping segments are seismically 

supported. These seismic supports are within the scope of license renewal. The 

applicant further clarified that design features (e.g., jet impingement shielding 

and pipe whip restraints) credited for mitigating the consequences of seismic Il/I 

piping failures are also included within the scope of license renewal. However, 

the applicant also stated that it does not consider the seismically-supported 

seismic Il/I piping segments to be within the scope of license renewal and no 

aging management programs are applied to those seismic Il/I piping segments.

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The applicant believes that since the seismic Il/I piping is seismically supported, 

consideration of its failure is hypothetical. 

The staff did not agree with the applicant's scoping criteria for non-safety-related 

piping systems. The staff's concern is that seismic II/I piping, though seismically 

supported, would be subjected to the same plausible aging effects as safety

related piping. For example, depending on piping material, geometrical 

configuration, operating conditions such as water chemistry, temperature, flow 

velocity, and external environment, erosion and corrosion may be plausible aging 

effects for some seismic Il/I piping. Those effects, if not properly managed, 

could result in age-related failures and adversely impact the safety functions of 

safety-related SSCs. 

The staff reviewed the UFSAR and found that the information described in the 

UFSAR is not adequate to support the applicant's assertions that design features 

would protect safety-related SSCs from the impact associated with the potential 

aging-related failures of seismic Il/I piping such that seismic Il/I piping need not 

be included within the scope of license renewal. As a result, the staff requested 

that the applicant provide additional information to address the staff's concern. 

This was identified as Open Item 2.1.3.1-1. 

By e-mail dated 6/19/01, the applicant provided the requested information. On 

the basis of the information provided in the e-mail, the staff found that the Plant 

Hatch CLB pipe break/crack analyses mainly postulated pipe failures at specific 

locations (e.g., at terminal ends and high stress points). Further, the mitigative 

features (e.g., jet impingement shielding and pipe whip restraints), which the 

applicant wanted to credit as the basis for excluding seismic Il/I piping from 

scope, assume pipe failures in locations based on the CLB pipe break/crack 

analyses. As described above, the primary concern for license renewal is aging

related failures. Since aging-related degradation of piping depends on piping 

material, geometrical configuration, water chemistry, temperature, flow velocity, 

and external environment, the resulting pipe failure mechanism and failure 

location may be different from those postulated in the Plant Hatch CLB pipe 

break/crack analyses, which were based on stress criteria. Therefore, the staff 

concluded that the applicant had not demonstrated that safety-related SSCs at 

Plant Hatch are adequately protected from the consequences of seismic Il/I pipe 

failures due to potential aging-related degradation. Thus, the staff's position was 

that seismic Il/I piping systems, including piping segments and their supports, 

should be included within the scope of license renewal. For these seismic Il/I 

piping systems, the applicant should perform an aging management review to 

determine if there are any plausible aging effects, and identify appropriate aging 

management programs. 

By letter dated September 5, 2001, the applicant brought all seismic Il/I piping 

systems into the scope of license renewal, provided the results of the associated 

AMRs, and provided a summary of the programs and activities that will be used 

to manage aging in these piping systems. The staff's review of the applicant's 

aging management of components in these piping systems is provided in 

Section 3.1 of this SER. On the basis of the additional information provided by

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the applicant, the staff concludes that the applicant has provided sufficient 

information to demonstrate that all SSCs that meet the 54.4(a)(2) scoping 

criterion, have been identified as being within the scope of license renewal. 

Open Item 2.1.3.1-1 is closed. 

2.3.3.2-1 (a) In RAI-2.3.3-HR-1 and RAI-2.3.3-HR-4, the staff asked the applicant to 

justify its exclusion of various components (highlighted in HL-26068) from 

an AMR. Specifically, these components included the water separator, 

water spray cooler, reaction chamber, blower (CO001 A), heater ( B001 A), 

and instrument tubing. The applicant responded that these components 

are a part of skid-mounted hydrogen recombiners, which are active 

components, and thus not subject to an AMR. Therefore, the applicant 

determined that the components are also not subject to an AMR. 

In a telephone conference on September 13, 2000, the staff expressed 

its disagreement with the applicant's determination to exclude these 

components from an AMR simply because they are skid-mounted. The 

staff requested that the applicant provide additional justification for its 

position. In response, the applicant provided a paper, entitled "Active 

Assemblies Used in License Renewal," via an email, dated November 6, 

2000. 

The staff has reviewed this paper, and finds that the applicant's basis for 

excluding hydrogen recombiner components, as discussed in the paper, 

is not consistent with the License Renewal Rule. The basis for the staff's 

conclusion is summarized below and is described in more detail in 

Section 2.3.4.2 of this report discussing the emergency diesel 

generators. 

Components are subject to an AMR if they perform a passive function 

and are long-lived. A passive function is one performed without moving 

parts or a change in configuration or properties. A function performed 

with moving parts or a change in configuration or properties is considered 

an active function. Components that perform a passive function and are 

also long-lived must be subject to an AMR, whether they are skid

mounted or not. The staff believes that the water separator, water spray 

cooler, and reaction chamber are long-lived components with a passive 

function, and therefore are subject to an AMR. On this basis, the staff 

requested that the applicant identify any applicable aging effects 

associated with these components, and any other long-lived components 

performing a passive function associated with the hydrogen recombiners, 

and identify AMPs credited with managing the aging effects. This was 

identified as part of Open Item 2.3.3.2-1 (2.3.3.2-1(a)). 

By letter dated June 5, 2001, the applicant responded to this open item 

by identifying the following skid-mounted components that are subject to 

an AMR and listing these components in Table 2.3.3-8 of the LRA: blower 

casing, instrument, piping, reaction chamber, water separator, and water 

spray cooler. Further clarification was provided by letter dated

1-11
September 5, 2001, where the applicant clarified that the hydrogen 

recombiner heater is electric and does not form a part of the pressure 

boundary. Therefore, the heater is an active component and not subject 

to an AMR. The staff reviewed the additional information and finds that 

the inclusion of these components in Table 2.3.3-8 of the LRA is 

acceptable. In addition, the staff agrees that the recombiner heater is not 

subject to an AMR. Open Item 2.3.3.2-1 (a) is closed. The staff's review 

of the applicant's management of the aging effects associated with these 

components can be found in Section 3.3.3 of this SER. 

(b) In reviewing drawings HL-21074, HL-11631, HL-11638, the staff found 

that some of the pumps were highlighted as within the scope of license 

renewal, but there are no pumps listed in Table 2.3.4-12 as subject to an 

AMR. The staff requested the applicant to explain this discrepancy. The 

applicant explained that on drawings HL-1 1638 (sheets 1 and 2) and 

HL-1 1631 (sheets 1 and 2), all of the pumps are part of the diesel 

generator skid. The applicant further stated that the diesel generator is an 

active component and, thus, not subject to an AMR. Therefore, the 

applicant determined that these pumps, which are part of the diesel 

generator skid, are also not subject to an AMR. However, the pumps that 

are not part of the diesel generator skid (on drawing HL-21074) are 

subject to an AMR and appear in Table 2.3.4-19 of the LRA for the fuel 

oil system. The staff did not agree that pumps can be excluded from an 

AMR because they are part of the diesel generator skid that constitutes 

part of a complex assembly. 

In a telephone conference on September 13, 2000, the staff expressed 

its disagreement with the applicant's decision to exclude these 

components from an AMR simply because these components are skid

mounted. The staff requested that the applicant provide additional 

justification for its position. In response, the applicant provided a paper, 

via e-mail, entitled "Active Assemblies Used in License Renewal," dated 

November 6, 2000. 

The staff reviewed this paper and did not agree with the applicant's basis 

for excluding skid-mounted components that are part of a complex 

assembly from an AMR. 

Regarding complex assemblies, NEI 95-10, Revision 0, stated: 

"There are structures and components that, when combined, are 

considered a complex assembly (e.g., diesel generator starting air 

skids or heating, ventilating, and air conditioning refrigerant units). 

The Rule and associated SOC do not specifically discuss such 

assemblies. For purposes of performing an aging management 

review, it is important to clearly establish the boundaries for 

review. An applicant should establish the boundaries for such 

assemblies by identifying each structure or component that makes 

up the complex assembly and determining whether or not each

1-12
structure and component is subject to an aging management 

review. (See example 5 in Appendix C.)" 

Example 5 in Appendix C of NEI 95-10, Revision 0, provided an example 

of a control room chiller complex assembly and guidance on how to 

establish the boundaries for such an assembly. It notes that once the 

boundary is determined, long-lived components with a passive function 

would be appropriately subjected to an AMR. 

Components are subject to an AMR if they perform a passive function 

and are long-lived. A passive function is one performed without moving 

parts or a change in configuration or properties. A function performed 

with moving parts or a change in configuration or properties is considered 

an active function. Components that perform a passive function and are 

also long-lived must be subject to an AMR, whether they are skid

mounted or not. The staff believes that some of the skid-mounted 

components are long-lived components with a passive function, and 

therefore are subject to an AMR. 

In the staff's evaluation of the Oconee LRA, the staff reached a similar 

conclusion regarding the treatment of the vendor-supplied diesel 

generator skid-mounted equipment. Duke had drawn a boundary around 

the diesel generator skid and determined that everything within the 

boundary was active and therefore not subject to an AMR. The staff 

disagreed and noted that the assembly included some long-lived 

components with a passive function which were subject to an AMR. 

Duke subsequently redefined the evaluation boundaries to ensure that 

long-lived components with a passive function on the diesel generator 

skid were subject to an AMR. 

On this basis, the staff requested that the applicant identify any 

applicable aging effects associated with these components, and any 

other long-lived components with a passive function associated with the 

emergency diesel generators, and identify AMPs credited with managing 

the aging effects. This was identified as part of Open Item 2.3.3.2-1 

(2.3.3.2-1(b)). 

By letter dated June 5, 2001, the applicant provided additional 

information. The EDGs include three subsystems that contain 

components that are passive and long-lived, and that perform a 

component function that supports the system intended function of 

standby ac power supply (R43-01). The subsystems are the diesel jacket 

water cooling subsystem, the diesel lubricating oil subsystem, and the 

scavenging air subsystem. The evaluation boundary for the extended set 

of skid-mounted components ends at the engine block and does not 

include the active portion of the diesel. On the basis of the above 

information, the applicant identified the following skid-mounted 

components that are subject to an AMR and listed in Table 2.3.4-12 of 

the LRA: bolting, heater housing, heat exchanger shell, heat exchanger

1-13
tubes (piping), piping/tubing, pump casing, restricting orifice, strainer 

casing, strainer element, and valve bodies. The applicant also stated that 

aging management of these components would be accomplished with the 

torque activities, protective coatings, and diesel generator maintenance 

activities AMPs. The staff's review of the AMPs can be found in Section 

3.1 of this SER. Staff evaluation of the applicants aging management activities for these components can be found in Section 3.4.3 of this SER. 

The staff finds this response acceptable, and considers Open Item 

2.3.3.2-1 (b) closed. 

2.3.3.2-2 (a) In its responses to RAI 2.3.3-SGTS-1 and RAI 2.3.3-SGTS-2, the 

applicant stated that differential pressure indicators, guillotine damper housings, and fan housings in the SGTS are not subject to an AMR on 

the basis of the guidance provided in NEI 95-10, Appendix B. The staff 

agrees that differential pressure indicators are considered components 

with an active function and, therefore, are not subject to an AMR. 

However, the staff questioned whether it was appropriate for the 

applicant to exclude guillotine damper housings and fan housings from an 

AMR. During a telephone conference on October 31, 2000, the staff 

asked the applicant to provide justification for why the housings for the 

guillotine dampers and fans should be excluded from an AMR. 

In response to the staff's concerns regarding the exclusion from an AMR 

of the housings for components such as fans, dampers, and heating and 

cooling coils, the applicant provided, by an e-mail dated November 6, 

2000, a paper titled "Active Assemblies Used in License Renewal." 

The staff reviewed this paper and found that the applicant's basis for 

excluding fan, damper, and heating and cooling coil housings is not 

consistent with the license renewal rule, the Statements of Consideration 

(SOC) accompanying the Rule, or the staff's review guidance. 

10 CFR 54.21 (a)(1) provides that those components that perform their 

intended functions without moving parts and without a change in 

configuration or properties (10 CFR 54.21 (a)(1)(i)) and that are not 

subject to replacement based on qualified life or specified time period (10 

CFR 54.21 (a)(1)(ii)) are subject to an AMR. Such components are 

commonly considered as "long-lived" and as performing a passive 

function. 10 CFR 54.21 (a)(1)(i) states that "structures and components 

[with passive functions] include, but are not limited to.... pump casings, 

valve bodies ... " and lists other components that perform passive 

functions. The examples cited in the license renewal rule illustrate 

components with significant passive functions. 

Section IllI.f.i(a) of the SOC further explains that major components may have active functions, passive functions, or both, and cites pumps and 

valves as examples. Pumps and valves have moving parts, but the 

Commission concluded that the pressure-retaining function performed by the pump casing and the valve body were important enough to warrant

1-14
an AMR. The SOC further explains that the Commission does not limit 

the consideration of pressure boundaries to reactor coolant pressure 

boundary. The exclusion regarding components is focused on active 

functions rather than on the exclusion of the entire component, while the 

AMR applies to the passive function of the component. On this basis, the 

staff concludes that fans, dampers, and heating and cooling coils may 

include significant passive pressure-retaining and structural support 

functions. 

Section 2.2.111.A of the draft SRP-LR, September 1997, states that 

"...some functions of "active" components may meet the criteria of the "passive" description. For example, although a pump or a valve has 

some moving parts, a pump casing or valve body performs a pressure 

retaining function without moving parts. A pump casing or a valve body 

meets this description and would therefore be considered for an aging 

management review." It is clear by this passage, and by the examples 

provided of pumps and valves, that the passive functions of components 

are subject to an AMR. 

In Section 2.1.1 of the LRA, the applicant states that the specific method 

used to identify in-scope functions and to screen the SSCs required to 

perform the in-scope functions was developed considering the guidance 

provided by NEI 95-10, Revision 0, "Industry Guideline on Implementing 

the Requirements of 10 CFR Part 54 - The License Renewal Rule," 

among other regulatory and guidance documents. Appendix B of NEI 95

10 provides a list of components and their active/passive functions. Item 

numbers 155 and 163 identify dampers and ventilation fans, respectively. 

Each of these components is identified in the appendix as performing an 

active function. The staff notes that the appendix, though it specifically 

identifies the dampers and ventilation fans, does not address housings 

for these components. 

On the basis of the information in the Rule, the SOC, and guidance 

provided in the SRP-LR, the staff concludes that the housings for fans, 

dampers, and heating and cooling coils contribute to the performance of 

the intended function of fans, dampers, and heating and cooling coils 

without moving parts and without a change in configuration or properties, 

and thus are subject to an AMR. This issue also affects the scope of 

components with passive functions for the control building HVAC, outside 

structures HVAC, and reactor building HVAC systems, which are 

discussed in Section 2.3.4.2 of this SER. 

Therefore, on the basis of the above staff positions, the staff requested 

that the applicant identify the passive functions for those fans, dampers, 

and heating and cooling coils that are within the scope of license renewal. 

For those passive functions, the applicant should identify any aging 

effects associated with the components and provide an AMP to manage 

the aging. This was identified as part of Open Item 2.3.3.2-2 [2.3.3.2

2(a)].

1-15
By letter dated June 5, 2001, the applicant provided information regarding the disposition of fans, dampers, and heating and cooling coils within the 

scope of license renewal. Consistent with the staff's guidance regarding 

evaluation of active components, the applicant identified the passive 

functions of damper frames and fan housings in the SGTS and added 

these components to the list of components in the LRA that are subject to 

an AMR. The applicant also identified any aging effects associated with 

the damper frames and fan housings and provided an AMP to manage 

the aging. The applicant added these components to those listed in 

Tables 2.3.3-6 and 3.2.3-6 in the LRA. The staff's review of the aging effects and AMPs for the SGTS can be found in Section 3.3.3 of this 

SER. On the basis of the additional information provided by the 

applicant, the staff agrees that the damper frames and fan housings are 

included in the scope of license renewal and subject to an AMR. Further, 

the staff concludes that the inclusion of these components in Tables 

2.3.3-6 and 3.2.3-6 of the LRA is acceptable. On the basis of the 

additional information provided by the applicant, this part of Open Item 

2.3.3.2-2, as it relates to SGTS components, is closed. 

The applicant also agreed to clarify the function of the guillotine damper regarding, including whether this damper is safety-related and included 

within the scope of license renewal and subject to an AMR. This was also 

identified as part of Open Item 2.3.3.2-2 [2.3.3.2-2(a)]. 

By letter dated June 5, 2001, the applicant clarified the function of the 

guillotine damper utilized in the SGTS. The dampers represent a 

commodity group of dampers associated with SGTS filtration units, 

2T46-DO01A and 2T46-DO01B. During accident and normal operating 

conditions, the dampers remain open. For filter testing purposes the 

dampers may be closed as needed. However, the dampers are not 

safety-related, do not perform an intended function, and can not prevent 

an intended function. Therefore, the guillotine dampers are not included 

in the scope of license renewal and are not subject to an AMR. On the 

basis of the additional information provided by the applicant, the staff 

agrees that the guillotine dampers are not within the scope of license 

renewal and not subject to an AMR. On the basis of the previously noted 

information, this part of Open Item 2.3.3.2-2 [2.3.3.2-2(a)], as relates to 

SGTS guillotine dampers, is closed. 

(b) In its response to RAI 2.3.4-CBHVAC-1, the applicant also stated that, 

given the guidance on NEI 95-10, Appendix B, no damper housing, fan 

housing, and air handling units, including the cooling coils, are found 

within the license renewal portions of the control building HVAC system. 

The staff disagreed with the applicant's exclusion from an AMR of 

housings for fans, dampers, and air handling units, including cooling 

coils. The staff's position with regard to the treatment of the housings for 

fans, dampers, and heating and cooling coils is discussed in detail in the 

staff's review of the SGTS in Section 2.3.3 of this SER, which includes 

treatment of the component passive functions of the control building

1-16
HVAC system. Resolution of this issue was part of Open Item 2.3.3.2-2 

[2.3.3.2-2(b)]. 

By letter dated June 5, 2001, the applicant provided information regarding 

the disposition of fans, dampers, and heating and cooling coils within the 

scope of license renewal. Consistent with the staff's guidance regarding 

evaluation of active components, the applicant identified the passive 

functions of condensing unit shells, damper frames, fan housings, and 

fan screens in the control building HVAC system and added these 

components to the list of components in the LRA that are subject to an 

AMR. The applicant also identified any aging effects associated with the 

condensing unit shells, damper frames, fan housings, and fan screens 

and provided an AMP to manage the aging. The applicant added these 

components to those listed in Tables 2.3.4-20 and 3.2.4-20 in the LRA. 

The staff's review of the aging effects and AMPs for the control building 

HVAC system can be found in Section 3.4.3 of this SER. On the basis of 

the additional information provided by the applicant, the staff agrees that 

the condensing unit shells, damper frames, fan housings, and fan 

screens are within the scope of license renewal and subject to an AMR. 

On the basis of the previously noted information, this part of Open Item 

2.3.3.2-2 [2.3.3.2-2(b)], as relates to control building HVAC system 

components, is closed. 

Additionally, in a telephone conference held on October 31, 2000, the 

applicant clarified that the LPCI inverter room and the Unit 2 vital NC 

room coolers are no longer in scope because of a design modification. 

The applicant committed to provide a description of the design 

modification that clarifies how the modification impacts the LPCI inverter 

room and Unit 2 vital NC room cooler functions. The applicant also 

committed to address why heating coil housings are not specifically 

identified in Table 2.3.4-20 of the LRA. The design modification 

information and the resolution of the issue regarding Table 2.3.4-20 were 

identified as part of Open Item 2.3.3.2-2(b). 

By letter dated June 5, 2001, the applicant provided a description of the 

design modification that clarified how the modification impacts the LPCI 

inverter room and Unit 2 vital A/C room cooler functions. Over a period of 

time, the LPCI inverters became obsolete and plant design change 

packages retired the Unit 1 and Unit 2 LPCI inverters. To continue to 

provide a diverse source of power for certain LPCI valves, Unit 2 Class 

1 E AC power supplies were selected as the normal source of power for 

the Unit 1 LPCI valves and Unit 1 Class 1 E power supplies were selected 

as the normal source of power for the Unit 2 LPCI valves. The LPCI 

inverter function (R44-02) was removed from scope when the 

modifications were performed to remove the inverters, effectively deleting 

the function; therefore, the LPCI inverter room cooling function was not 

included in the LRA. By comparison, vital AC is not safety-related, as 

defined in 10 CFR 54.4(a)(1), its failure does not prevent a safety 

function, as defined in 10 CFR 54.4(a)(2), and it is not required to operate

1-17
during the events defined in 10 CFR 54.4(a)(3). Therefore, as seen in 

Table 2.2-1 of the LRA, this function does not meet the criteria for 

inclusion within license renewal scope. Consequently, the vital AC room 

cooling function is out of scope for license renewal. The applicant also 

addressed why heating coil housings are not specifically identified in 

Table 2.3.4-20 of the LRA. Control building heating coils are electric and 

thus, were considered to be active components. Consequently, the 

heating coils were screened out and not included in Table 2.3.4-20. The 

duct heater frame was evaluated in the LRA and included in Table 

2.3.4-20. The applicant provided other clarifications and/or editorial 

changes, as appropriate. On the basis of the additional information 

provided by the applicant, the staff agrees that the LPCI inverter room 

and Unit 2 vital A/C room cooler functions and the heating coil housings 

are not within the scope of license renewal and not subject to an AMR. 

On the basis of the previously noted information, this part of Open Item 

2.3.3.2-2(b), as relates to control building HVAC system components, is 

closed. 

(c) In its response to RAI 2.3.4-OSHVAC-1, the applicant stated that 

roof-mounted exhaust ventilator housings and wall-mounted unit heater 

housings are not subject to an AMR, since these housings are part of 

active components (i.e., fan/damper assembly and heater, respectively). 

The staff disagreed with the applicant's exclusion of roof-mounted 

exhaust ventilator and wall-mounted unit heater housings from being 

subject to an AMR. The staff's position with regard to the treatment of 

the housings for roof-mounted exhaust ventilators and wall-mounted unit 

heaters is discussed in detail in the staff's evaluation of the SGTS in 

Section 2.3.3 of this SER. The staff's position in Section 2.3.3 of this 

SER also applies to the treatment of the component passive functions of 

the outside structures HVAC system. Resolution of this issue was 

identified as part of Open Item 2.3.3.2-2 [2.3.3.2-2(c)]. 

By letter dated June 5, 2001, the applicant provided information regarding 

the disposition of fans, dampers, and heating and cooling coils within the 

scope of license renewal. Consistent with the staff's guidance regarding 

evaluation of active components, the applicant identified the passive 

functions of damper frames, fan housings, and unit heater housings in 

the outside structures HVAC system and added these components to the 

list of components in the LRA that are subject to an AMR. The applicant 

also identified any aging effects associated with the damper frames, fan 

housings, and unit heater housings and provided an AMP to manage the 

aging. The applicant added these components to Tables 2.3.4-17 and 

3.2.4-17 in the LRA. The staff's review of the aging effects and AMPs for 

the outside structures HVAC system components can be found in Section 

3.4.3 of this SER. On the basis of the additional information provided by 

the applicant, the staff agrees that damper frames, fan housings, and unit 

heater housings are within the scope of license renewal and subject to an 

AMR. On the basis of the previously noted information, this part of Open

1-18
Item 2.3.3.2-2, as relates to outside structures HVAC system 

components, is closed. 

(d) In its response to RAI 2.3.4-RBHVAC-1, the applicant stated that, given 

the guidance in NEI 95-10, Appendix B, safeguards equipment room 

cooler housings are not subject to an AMR. With regard to this RAI, the 

applicant also did not address the scope of license renewal and an AMR 

as it relates to air-operated valve bodies, the air-operated damper 

housings, and associated ductwork. Additionally, in a telephone 

conference held on October 31, 2000, the applicant agreed to reconsider 

its response to RAI 2.3.4-RBHVAC-3, concerning whether certain 

ductwork identified by the staff is within the scope of license renewal and 

subject to an AMR. 

The staff believes that the safeguards equipment room cooler housings 

may be within the scope of license renewal and subject to an AMR. The 

staff's position with regard to the treatment of the housings for the 

safeguards equipment room coolers is discussed in detail in the staff's 

evaluation of the SGTS in Section 2.3.3 of this SER. The staff's position 

in Section 2.3.3 of this SER applies to the treatment of the component 

passive functions of the reactor building HVAC system. Resolution of this 

issue, including the scoping clarification for the air-operated valve bodies, 

air-operated damper housing, and associated ductwork, was identified as 

part of Open Item 2.3.3.2-2 [2.3.3.2-2(d)]. 

By letter dated June 5, 2001, the applicant provided information regarding 

the disposition of fans, dampers, and heating and cooling coils within the 

scope of license renewal. Consistent with the staff's guidance regarding 

evaluation of active components, the applicant identified the passive 

functions of damper frames, fan housings, fan inlet housings, and fan 

inlet screens in the reactor building HVAC system and added these 

components to the list of components in the LRA that are subject to an 

AMR. The applicant also identified any aging effects associated with the 

damper frames, fan housings, fan inlet housings, and fan inlet screens 

and provided an AMP to manage the aging. The applicant added these 

components to those listed in Tables 2.3.4-15 and 3.2.4-15 in the LRA. 

The staff's review of the aging effects and AMPs for the reactor building 

HVAC system components can be found in Section 3.4.3 of this SER. 

The applicant provided other clarifications and/or editorial changes, as 

appropriate. On the basis of the additional information provided by the 

applicant, the staff agrees that damper frames, fan housings, fan inlet 

housings, and fan inlet screens are within the scope of license renewal 

and subject to an AMR. On the basis of the previously noted information, 

this part of Open Item 2.3.3.2-2 [2.3.3.2-2(d)], as relates to reactor 

building HVAC system components, is closed. 

2.3.4.2-1 With respect to the radwaste building, the staff reviewed the Plant Hatch FHA 

dated July 22, 1986, and concluded that fire suppression for certain areas in the 

radwaste building were included in the 1986 FHA. Specifically, Section IV.B.4.d

1-19
of the FHA states that "fixed automatic water spray systems are installed in all 

charcoal filters in the plant." The radwaste building contains charcoal filters that 

are protected by fixed sprinkler systems. Therefore, the fire suppression piping 

leading to the charcoal filters, including the nozzles and sprinkler heads, should 

be included within the scope of license renewal and subject to an AMR. 

In addition, Section IV.D of the FHA states that the guidelines for specific plant 

areas is presented for each specific plant area throughout the FHA. In both the 

June 1986 and July 1987 revisions to the FHA, the FHA analysis of fire 

area/zone 2301 (Radwaste Building - All Elevations) states that, "all sections of 

this area which contain specific fire hazards (charcoal filters) or high 

concentrations of combustibles (dry waste storage area, Radwaste Control 

Room) are equipped with detection, suppression, or both." Specifically, the west 

central portion of fire zone 2301J over the drywaste storage section is equipped 

with a wet pipe suppression system. To the staff's knowledge, the applicant has 

not submitted any information to show that the radwaste suppression system has 

been physically removed or altered so that it can't perform its intended function, 

and that no plant evaluations through 10 CFR 50.59 have determined that this 

suppression system is no longer required for compliance with Appendix A to BTP 

9.5-1. 

It was the staff's view that the radwaste suppression system should be included 

within the scope of license renewal and subject to an AMR. This issue was 

identified as Open Item 2.3.4.2-1. 

After reviewing the Plant Hatch Fire Hazards Analysis (FHA) dated July 22, 

1986, the staff raised a concern with the applicant's exclusion of the radwaste 

fire suppression system from within the scope of license renewal. The radwaste 

building contains charcoal filters which are protected by fixed sprinkler systems. 

Section IV.B.4.d of the FHA states that 'fixed automatic water spray systems are 

installed in all charcoal filters in the plant". In addition, Section IV.D of the FHA 

states that the guidelines for specific plant areas are presented for each specific 

plant area throughout the FHA. In both the June, 1986 and July, 1987 revisions 

to the FHA, the FHA analysis of fire area/zone 2301 (Radwaste Building - All 

Elevations) states that, "all sections of this area which contain specific fire 

hazards (charcoal filters) or high concentrations of combustibles (dry waste 

storage area, Radwaste Control Room) are equipped with detection, 

suppression, or both." Specifically, the west central portion of fire zone 2301J 

over the drywaste storage section is equipped with a wet pipe suppression 

system. 

In response to the staff's concern, the applicant responded in a letter dated June 

5, 2001, that the radwaste building fixed fire suppression has been included in 

scope for license renewal and is subject to an AMR. No new component types, 

component materials, or internal or external environments result from this scope 

change. In addition, the following evaluation boundary drawings were revised or 

created to reflect the change in scope:

1-20
HL-11034 HL-11901 

HL-11304, Sheet 7 HL-11905 

HL-11304, Sheet 8 HL-11909 

HL-11869 HL-21017 

HL-11873 HL-21197 

HL-11874 HL-21342 

HL-11875 HL-26372 

The staff's review of the aging effects associated with these components can be 

found in Section 3.4.3 of this SER. The staff is satisfied with the applicant's 

resolution of this issue and Open Item 2.3.4.2-1 is closed. 

3.0-1 The staff issued Open Item 3.0-1 to ensure that the applicant's FSAR 

Supplement contained an adequate description of the programs and activities 

that have been credited for managing the effects of aging, and the evaluation of 

time-limited aging analyses (TLAAs) for the period of extended operation as 

required by 10 CFR 54.21(d). The staff reviewed the aging management 

program and TLAA descriptions provided by letter dated October 10, 2000, and 

the associated FSAR Supplement provided by letter dated September 5, 2001, 

and found that the FSAR Supplement provided by the applicant contains 

descriptions of these programs and activities adequate to satisfy 10 CFR Part 54 

requirements. On the basis of the program descriptions provided by the 

applicant, the staff concludes that the FSAR Supplement contains sufficient 

information to adequately describe the content of the associated aging 

management programs and TLAAs and satisfies the requirements of 10 CFR 

54.21 (d). A condition will be included in the renewed license requiring the 

inclusion of the FSAR Supplement in the next UFSAR update, required by 10 

CFR 50.71(e). Open Item 3.0-1 is closed. 

3.1.1-1 The applicant's reactor water chemistry control program is predicated on the 

guidance provided in EPRI TR-103515, "BWR Water Chemistry Guidelines." In 

the staff's RAIs regarding program elements that deviate from the referenced 

EPRI guidelines, the applicant indicated that this program is currently being 

updated to meet the guidance of EPRI TR-1 03515, Revision 2. The staff noted 

that EPRI TR-1 03515, Revision 2, has not been reviewed by the staff for generic 

use. The staff requested that the applicant clarify the differences between 

Revision 1 and Revision 2 of EPRI TR-103515, so the staff can determine 

whether the provisions of Revision 2 are acceptable. This was identified as 

Open Item 3.1.1-1. 

By letter dated June 5, 2001, the applicant responded to the open item, stating 

that, as discussed in its response to RAI 3.1.1-2, Plant Hatch is committed to 

meeting the chemistry control parameters specified for RCS chemistry contained 

in EPRI TR-103515. The applicant identified, as a point of information, the 

applicable revision of the EPRI document which was current at the time the LRA 

was submitted, and noted that the program was being updated to a later revision 

of the document. The applicant believes, and the staff agrees, that it is 

important to maintain the flexibility to modify plant chemistry control procedures 

based on the best industry guidance developed from the collective operating

1-21
experience of similar reactors. Therefore, over time, the applicant expects to 

revise the plant chemistry procedures to reflect changes in industry guidance as 

reflected in the EPRI control parameters. 

As part of the response to Open Item 3.1.1-1, the applicant also discussed the 

significant differences between Revision 1 and Revision 2 of EPRI TR-103515. 

The first relates to the additional consideration of the beneficial effects of 

operation with hydrogen water chemistry (HWC) or with HWC with noble metal 

chemistry addition (NMCA). Revision 2 of EPRI TR-1 03515 provides an 

additional table (4-5b) which allows relaxation of the power operation Action 

Level 3 (AL3) values for chlorides and sulfates from 100 ppb to 200 ppb when 

HWC is in service and measured electrochemical potential (ECP) values are less 

than -230 mV. Currently, Plant Hatch operates in accordance with Revision 2 of 

the EPRI guidelines and current sampling and monitoring procedure allows for 

higher AL3 chloride and sulfate values under HWC. This additional flexibility is 

warranted based on the increased protection of reactor coolant system and 

reactor assembly components provided by HWC or HWC with NMCA. 

The second significant difference between Revision 1 and Revision 2 of the 

EPRI guidelines involves the allowance in Revision 2 for monitoring of chlorides 

and sulfates on less than a daily basis, if appropriate, based on site-specific 

resource allocation needs. This flexibility in monitoring frequency is acceptable 

when adequately justified and supported by the conductivity values and/or 

chemistry trends that assure that Action Level 1 limits will not be exceeded. 

On the basis of the information provided by the applicant in response to this 

open item, the staff concludes that the applicant should be allowed to maintain 

the flexibility to modify chemistry control procedures in response to new or 

updated industry information, and that the differences between Revision 1 and 

Revision 2 of the EPRI guidelines provide this flexibility. Therefore, the staff 

considers Open Item 3.1.1-1 closed. 

3.1.3-1 The diesel fuel oil testing program, like the various chemistry control programs in 

effect at Plant Hatch, is a mitigative activity which is not intended to directly 

detect age-related degradation. The implementation of this program does not 

provide information directly related to the degradation of the structures and 

components within the scope of this program. The applicant does not take credit 

for such a system. Also, water in the fuel oil will be in contact with the tank 

bottom, possibly causing corrosion. The diesel fuel oil testing program will not 

be able to detect such degradation. Therefore, the staff concludes that a one

time inspection program is warranted for the diesel fuel oil tanks to verify tank 

bottom thickness. The addition of a one-time inspection program for the tanks 

would be consistent with the applicant's approach for other chemistry control 

programs at Plant Hatch. For example, the torus submerged components 

inspection program complements the applicant's suppression pool chemistry 

control. Also, the condensate storage tank inspection complements the 

applicant's demineralized water and condensate storage tank chemistry control 

program. The staff requested that the applicant provide the specific attributes of 

an inspection program, consistent with other one-time inspections (e.g.,

1-22
inspection scope, inspection technique, acceptance criteria, etc.). This was 

identified as Open Item 3.1.3-1. 

By letter dated June 5, 2001, the applicant provided a response to this open 

item. The applicant stated that, since the license renewal application was 

submitted, one of the four buried, 40,000-gallon emergency diesel generator 

(EDG) fuel oil storage tanks (FOST) has been inspected. When Tank 1 A was 

drained for cleaning during the last outage, the applicant took this opportunity to 

conduct aging inspections. On the basis of the results obtained through visual 

examination and ultrasonic testing (UT), the applicant concluded that significant 

wall thinning has not occurred in the Plant Hatch EDG FOSTs and that no aging 

management activities are required. 

The Plant Hatch EDG FOSTs are constructed of 0.5 inch plate steel. Ultrasonic 

testing, covering 144 points along the lower portions of the tank, indicated that 

wall thickness was consistently between 0.500 and 0.524 inches. In no case was 

a reading taken less than 0.5 inches. The applicant believes that these results 

are representative of the other four tanks, since they are all the same material 

and they all have the same internal and external environments. 

Prior to performing the UT, visual inspections were conducted of the "as-found" 

conditions. Very little corrosion was noted in the tank airspace. A thin adherent 

layer of general corrosion was identified in a small area. That small amount of 

surface corrosion was removed during cleaning. In addition to the EDG FOSTs, 

the fire pump diesel fuel oil storage tanks are also in scope for license renewal. 

The internal environment of these smaller tanks is similar to the internal 

environment of the EDG FOSTs, each tank having a diesel fuel oil volume and 

an air vapor space. However, the fire pump diesel fuel oil storage tanks are not 

buried. They are above ground and are painted. Thus, the external environment 

is at least as benign as the external environment for the buried EDG FOSTs. In 

summary, the applicant stated that the FOST visual and UT inspection results 

already obtained are responsive to the issue raised in the open item and 

substantiate the LRA conclusion that loss of material is not an aging effect 

requiring management during the renewal term for either the EDG FOSTs or the 

fire pump diesel fuel oil storage tanks. 

On the basis of its review of the additional information provided by the applicant 

in its letter dated June 5, 2001, the staff concludes that the applicant has 

performed a one-time inspection of the internal surfaces of one of the FOSTs, 

has adequately determined that age-related degradation of the tank bottoms has 

been minimal, and that significant age-related degradation of the FOSTs is 

unlikely during the period of extended operation. Open Item 3.1.3-1 is closed. 

3.1.11-1 The application stated that the plant commodity group in the scope for torque 

activities is Class 1 pressure boundary bolting and Non-Class 1 pressure 

boundary bolting. Class 1 pressure boundary bolting is fabricated from low alloy 

steel. The non-Class 1 pressure boundary bolting is fabricated to the 

requirements of ASTM A-307 (Grade B), ASME SA-194 (Grade 2H), and ASME 

SA-1 93 (Grade B7). Bolting that is heat treated to a high hardness condition and

1-23
exposed to a humid environment within containment could be susceptible to 

SCC. In response to RAI 3.4-1, the applicant did not state if the yield strength for 

ASME SA-1 93 (Grade B7) or any other bolts are limited to less than 150 ksi to 

avoid the possibility of stress corrosion cracking. (See RICSIL No. 055, 

February 1, 1991, "RPV Head Stud Cracking."). In Open Item 3.1.11-1, the staff 

requested that the applicant provide this information. By letter dated June 5, 

2001, the applicant stated that these bolts were procured with a minimum yield 

strength of 105 ksi, with no upper limit stated. However, the applicant also 

stated that it has not experienced problems with these bolts and could not 

identify any problems during a survey of industry experience. On the basis that 

the applicant's operating experience has not shown that these bolts have 

experienced SCC, the staff finds the applicant's response adequate and 

considers Open Item 3.1.11-1 closed. 

3.1.13-1 (a) In Section C.2.4.3 of the LRA, the applicant credits the PSW and 

RHRSW inspection program with managing the aging effects of RHR and 

PSW components exposed to a buried environment. The protective 

coatings program includes provisions for cleaning, priming, coating, and 

wrapping underground pipelines whenever underground sections of pipe 

are uncovered. Pipelines are wrapped with coal tar enamel wrapping. 

However, this aspect of the program is not discussed in Section A.1.13 of 

the LRA or Section B.1.13 of the applicant's October 10, 2000 submittal. 

The staff requested that the applicant enhance its description of the 

PSW and RHRSW inspection program to clearly state that the scope of 

the program includes this particular aspect for managing aging effects 

associated with a buried environment, consistent with the discussion in 

Section C.2.4.3 of the LRA. This was identified as part of Open Item 

3.1.13-1 [3.1.13-1 (a)]. 

The applicant responded to this open item by letter dated June 5, 2001. 

The applicant indicated that the PSW and RHRSW inspection program 

does not directly include provisions for cleaning, priming, coating and 

wrapping underground pipelines. The protective coatings program 

addresses these activities. However, the site procedure for buried 

pipelines coating maintenance does specifically invoke the program 

inspection requirements whenever maintenance is performed on the 

components in those systems. There is, therefore, certain linkage 

between these two programs and the applicant reflected it in the LRA. In 

order to clarify this issue, the applicant will modify the LRA. It will remove 

the PSW and RHRSW inspection program from Section C.2.4.3. In 

addition, the applicant will modify Section B.3.5 of the LRA by removing 

information related to the external surfaces of buried components. A 

special instruction has been placed in the site procedure used to manage 

excavation activities to assure that buried commodities are examined by 

protective coatings personnel. The staff finds that with these 

modifications introduced in the LRA, the scope of the PSW and RHRSW 

inspection program with regard to inspection of the underground pipelines 

is well defined. The staff considers Open Item 3.1.13-1 (a) closed.

1-24
(b) In Table 3.2.3-2 of the LRA, the RHR heat exchanger augmented 

inspection and testing program is credited with managing, in part, aging 

effects for various heat exchanger components, including the tubes, 

tubesheet, and shell. However, the staff noted that the description of the 

PSW and RHRSW inspection program contained in Section B.1.13 of the 

applicant's October 10, 2000 submittal included several references to 

inspections of heat exchanger components. The staff requested that the 

applicant clarify the scope of the PSW and RHRSW inspection program 

relative to managing aging effects for the various heat exchanger 

components listed in Table 3.2.3-2 of the LRA. This was identified as 

part of Open Item 3.1.13-1 (Open Item 3.1.13-1(b)). 

The applicant responded to this open item by letter dated June 5, 2001. 

The applicant stated that managing aging effects for various heat 

exchanger components, including the tubes, tubesheet, and shell in the 

RHR system is performed by the RHR heat exchanger augmented 

inspection and testing program. As indicated in Section C.2.2.11 of the 

LRA, the PSW and RHRSW inspection program plays only a subordinate 

role, limited to visual inspection of the surfaces of the heat exchanger 

channel and shell sides. The reason that inspection of the heat 

exchanger components is referenced in Section B.1.13 of the LRA is to 

show the linkage that exists between these two programs. On the basis 

of this information, the staff concludes that the applicant has clarified the 

scope of the PSW and RHRSW inspection program regarding 

management of aging effects in the RHR heat exchanger. The staff 

considers Open Item 3.1.13-1 (b) closed. 

(c) The staff conducted a scoping inspection in the offices of SNC from 

September 11, 2000 through September 15, 2000. The results of the 

inspection are documented in Inspection Report 50-321/00-09, 50

366/00-09. During the inspection, the inspectors identified a guard pipe 

associated with Division I PSW piping in the diesel generator building. 

This guard pipe had not been considered for scoping and screening in 

the LRA. In response to this inspection finding, the applicant evaluated 

the guard pipe and concluded that it did not perform an intended function, 

and therefore was not within the scope of license renewal. The staff 

agreed with this conclusion. The staff's review of the applicant's 

evaluation of the guard pipe can be found in Section 2.3.4 of this SER. 

The internal surface of the PSW piping is exposed to raw water, and thus 

the aging effects and AMPs are consistent with other piping sections in 

this system. However, the length of the PSW piping surrounded by the 

guard pipe is sealed, that is, a plate is welded to the PSW pipe and to the 

guard pipe at both ends. Thus, the external surface of this section of 

PSW piping is not accessible for inspection. The applicant plans to 

perform a one-time inspection to assess the material condition of the 

external surfaces of this piping section. The staff requested that the 

applicant provide appropriate information about this one-time inspection, 

or a comparable engineering evaluation, prior to the end of the current 

term. This was identified as part of Open Item 3.1.13-1 (3.1.13-1(c)).

1-25
The applicant responded to this open item by letter dated June 5, 2001. 

The applicant provided additional information related to the one-time 

inspection of that portion of the PSW piping that is surrounded by a guard 

pipe. The applicant states that Plant Hatch Engineering Support is 

responsible for determining the suitable method or methods for 

conducting an inspection. Plans have been made to inspect the portion of 

the external surface of the PSW piping that is surrounded by the guard 

pipe during the 1 B EDG outage scheduled for February 2002. Currently, 

the plan is to cut a window in the guard pipe for a visual, boroscope, or 

other suitable examination to determine the condition of the external 

surface of the PSW pipe. The results will be documented and evaluated, 

with additional actions taken if needed. The staff has reviewed the 

information discussed in the applicant's open item response and, on the 

basis of this information, concludes that the approach for determining the 

current state of the guarded external surface of the PSW piping is 

appropriate and acceptable. Open Item 3.1.13-1(c) is closed. 

3.1.17-1 To evaluate whether the reactor vessel surveillance program will provide 

sufficient data for monitoring the amount of embrittlement during the license 

renewal term, the staff evaluates whether the surveillance program satisfies the 

following attributes: 

"If the ISP is not approved by the staff, and if, instead, a plant-specific 

surveillance material testing program is implemented, capsules must be 

removed periodically to determine the rate of embrittlement. Capsules 

must be removed at neutron fluence levels which provide relevant data 

for assessing the integrity of the Plant Hatch 1 and 2 RPVs; in particular, 

for the determination of RPV pressure-temperature limits through the 

period of extended operation. Capsules must contain material to monitor 

the impact of irradiation on the Plant Hatch RPVs and must contain 

dosimetry to monitor neutron fluence. If the applicant is not participating 

in an ISP and available capsules are not being removed from Plant Hatch 

during the license renewal period, the applicant must submit for staff 

review the technical basis for continued operation (including proposed 

operating restrictions, such as inlet temperature, neutron spectrum, and 

flux, ex-vessel dosimetry for monitoring neutron fluence, etc.)" 

In response to RAI 3.1.17-1, the applicant indicated that it plans to implement the 

provisions of an integrated surveillance program (ISP) that is documented in 

BWRVIP-78, "BWR Vessel and Internals Project; BWR Integrated Surveillance 

Program Plan," and it's companion document, BWRVIP-86, "BWR Vessel and 

Internals Project, BWR Integrated Surveillance Program Implementation Plan." 

In a telephone conference on November 3, 2000, the applicant clarified its 

commitment to participate in an ISP through the end of Plant Hatch's period of 

extended operation, or, if necessary, to develop a plant-specific RPV 

surveillance materials testing program for the period of extended operation. As 

part of this commitment, the staff noted that if the applicant participates in a NRC

1-26
staff-approved ISP or implements a staff-approved plant specific RPV 

surveillance program, the ISP or plant-specific program should address the 

requirements of 10 CFR Part 54, including the ten aging management program 

attributes in the SRP-LR. Further, if the proposed program cannot meet any 

program attributes, the applicant should provide a technical justification for the 

discrepancies. This was identified as Open Item 3.1.17-1. 

In response to the open item, by letter dated June 5, 2001, the applicant officially 

committed to implementing a staff-approved ISP for the extended period of 

operation based on the technical criteria of BWRVIP-78 and BWRVIP-86. The 

applicant further stated that, if an ISP is not approved by the NRC, or if the staff

approved ISP is not adequate for implementation at Plant Hatch, then the 

applicant will develop and implement a plant-specific surveillance material testing 

program for the extended period of operation. The applicant further stated that 

the plant-specific surveillance material testing program, if one is needed, will be 

developed in a manner consistent with other aging management programs, will 

include consideration of the ten program attributes utilized for other aging 

management programs, and will provide a technical justification for any program 

attribute not covered by the plant-specific surveillance material testing program. 

The staff's review of BWRVIP-78 is continuing; however, all significant issues 

necessary for approval of BWRVIP-78 have been addressed. The proposed ISP 

addressed by BWRVIP-78 and BWRVIP-86, only applies to the period of the 

current operating licenses. The BWRVIP has committed to provide 

supplemental information to extend the ISP through the period of extended 

operation, based on the same technical criteria as found in BWRVIP-78 and 

BWRVIP-86, for the BWR fleet. The staff expects this supplemental information 

to be submitted in 2002. 

Although the BWRVIP-78 and -86 reports apply only to the current term, the staff 

finds that the provisions in these reports, if implemented during the extended 

period of operation, constitute sufficient actions to manage the aging effects 

associated with the reactor vessel during the renewal term. 

With regard to the plant-specific surveillance materials testing program, in a 

telephone conference on October 5, 2001, the applicant clarified its commitment 

that the plant-specific program, if needed, will include the following actions: 

0 capsules will be removed periodically to determine the rate of 

embrittlement 

0 capsules will be removed at neutron fluence levels which provide relevant 

data for assessing the integrity of the Plant Hatch RPVs; in particular, for 

the determination of RPV pressure-temperature limits through the period 

of extended operation 

* capsules will contain material to monitor the impact of irradiation on the 

Plant Hatch RPVs and will contain dosimetry to monitor neutron fluence

1-27
On the basis of these commitments, the staff concludes that the applicant has 

identified in sufficient detail the actions that will be taken to provide reasonable 

assurance that aging effects associated with embrittlement of the reactor vessel 

will be adequately managed for the period of extended operation. On this basis, 

Open Item 3.1.17-1 is resolved. The renewed license will be conditioned to 

require that, prior to operation in the renewal term, the applicant will notify the 

NRC of th'6 its decision to implement the ISP or a plant-specific program, and 

provide the appropriate revisions to the FSAR Supplement summary descriptions 

of the vessel surveillance material testing program. 

3.1.18-1 (a) Table C.2.3.1-1 of the LRA states that, for water-based fire suppression 

system components, the fire protection activities prevent or mitigate loss 

of material by using system flushes to remove undesirable material from 

the system. However, the operability of the automatic wet-pipe sprinkler 

systems, which are required for compliance with 10 CFR 50.48, were not 

discussed. In response to RAI 3.1.18-7, in which the staff notified the 

applicant of this omission, the applicant stated that, "unobstructed water 

flow from the header test valve demonstrates that sprinkler heads and 

piping are not clogged from corrosion product debris." The staff did not 

agree with this statement since (1) the arrangement of the test header at 

the most distant point in the sprinkler system is usually located in the fire 

suppression piping, which is along the path of least water resistance, and 

(2) the sprinkler heads are located along the smaller branch line piping 

and, as a result of their orientation, are typically never exposed to the 

flow of water during the routine testing of the test header. Since there is 

little or no flow in the branch lines during testing, the water in these lines 

remains stagnant and sediment from the raw water, which flows to the 

header test connection, continues to collect in the smaller branch line 

piping. This may result in blockage and corrosion of the branch line 

piping and the sprinkler heads at accelerated rates. The staff has 

addressed this issue in Generic Letter 89-13, "Service Water Problems 

Affecting Safety-Related Equipment." The staff requested that the 

applicant discuss the specific considerations for addressing this aging 

mechanism in the automatic wet-pipe sprinkler systems. This was 

identified as part of Open Item 3.1.18-1 [3.1.18-1 (a)]. 

The applicant routinely performs sprinkler piping flow tests to check for 

clogging from corrosion products as part of the fire protection activities. 

The staff was initially concerned that these tests may not be adequate for 

demonstrating operability of the sprinkler heads during the extended 

period of operation. However, as the staff position has evolved, 

additional flow tests are not required to determine flow blockage in the 

sprinkler system. This is consistent with the staff position in the generic 

aging lessons learned (GALL) report with regard to flow blockage in fire 

protection and other systems, as a result of corrosion, biofouling, or 

silting. System flow is considered to be an active feature. However, the 

staff expects the applicant to be sensitive to the potential for flow 

degradation as a result of accumulation of corrosion products. The staff

1-28
has determined that as long as the applicant conducts the wet pipe 

sprinkler header flow tests as described in the response to RAI 3.1.18-7, 

flow degradation would be adequately managed. In addition, should flow 

degradation be discovered, the applicant has a corrective action program, 

that requires trending to determine the need for future actions. On this 

basis, the staff concludes that Open Item 3.1.18-1 (a) is closed. 

(b) With regard to the inspection frequency of fire system components, the 

applicant lists in Section B.2.1 of the applicant's October 10, 2000 

submittal the different inspection intervals for the water-based fire 

protection systems, fire protection pump diesel fuel oil supply system, 

compressed gas based fire suppression systems, fire penetration seals, 

cable tray enclosures, and fire doors. In addition to the systems listed 

above, the applicant describes a one-time inspection called the "Sprinkler 

Head Inspections" that will be performed at or before the start of the 

extended period of operation for closed sprinkler heads within the scope 

of license renewal. In RAI 3.1.18-9, the staff requested that the applicant 

provide justification for the absence of enhanced inspection programs for 

the sprinkler heads, which do not have a design life that covers the period 

of extended operation. In response the applicant stated that, in general, 

enhanced inspection programs are deemed unnecessary because the 

existing programs adequately manage the aging effects of concern, and 

that the guidelines of the National Fire Protection Act (NFPA) Code 25, 

"Standard for the Inspection, Testing, and Maintenance of Water-Based 

Fire Protection," a one-time sprinkler heads inspection are being followed 

for in-scope sprinkler heads." The staff does not agree that a one-time 

inspection is sufficient for the sprinkler heads and recommends that the 

applicant expand the scope of its inspections to include the 10-year 

inspection intervals that are recommended in NFPA 25, Section 2.3.3.1, 

"Sprinklers." Section 2.3.3.1 states that "where sprinklers have been in 

place for 50 years, they shall be replaced, or representative samples from 

one or more sample areas shall be submitted to a recognized testing 

laboratory for field service testing." It also contains guidance to perform 

this sampling every 10 years after the initial field service testing. In 

addition, the staff has notified the nuclear industry, through recent 

information notices, about the potential failures associated with sprinkler 

heads. These information notices include IN 01-10, "Failure of Central 

Sprinkler Company Model GB Series Fire Sprinkler Heads," IN 99-28, 

"Recall of Star Brand Fire Protection Sprinkler Heads;" and IN 97-72, 

"Potential for Failure of the Omega Series Sprinkler Heads." Problems 

with seals leaking and sprinkler heads failing to actuate are typically not 

detectable through the performance of existing visual inspections. 

Therefore, the staff requested that the applicant expand the scope of its 

inspections to include the 10-year inspection intervals that are 

recommended in NFPA 25 or provide additional justification for the 

applicant's proposed inspection interval. This was identified as part of 

Open Item 3.1.18-1 [3.1.18-1(b)].

1-29
The applicant has previously addressed this issue in its responses to 

RAIs 2.3.4-FPS-1 0 and 3.1.18-9. By letter dated June 5, 2001, in 

response to Open Item 3.1.18-1 (b), the applicant supplemented the 

earlier RAI responses by expanding the scope of the inspections 

referenced. Thus, the revised commitment is to use the guidance of 

NFPA-25 to perform an inspection of closed head sprinklers after 50 

years of service and at 10-year intervals thereafter. On the basis of the 

applicant's commitment, the staff finds that the applicant has adequately 

addressed the staff's concern and Open Item 3.1.18-1 (b) is closed. 

3.1.28-1 The staff was concerned about cracking in the RHR heat exchangers. The RHR 

heat exchanger augmented inspection and testing program description was 

unclear regarding its ability to manage vibration-induced cracking. Therefore, in 

order to ascertain whether this AMP is adequate to manage vibration-induced 

cracking, the staff requested that the applicant provide additional information. 

The requested information is summarized below, and was identified as Open 

Item 3.1.28-1. 

A. The applicant should provide information on the inspection methods, 

frequencies, acceptance criteria, and associated bases, which are used 

to detect vibration-induced cracking. 

B. The applicant should provide information regarding the leakage identified 

in 1996, including the analyses conducted that determined the cause of 

the leakage, the operational changes or component modifications that 

were instituted in response to the leakage, and additional programs which 

were developed and credited for managing vibration-induced cracking. 

C. The LRA states that measured and recordable values of the inspected or 

monitored parameters shall not fall below acceptable values for defined 

inspection locations. The applicant should identify the inspection 

locations, and the inspection criteria used to determine inspection 

locations, and their bases. 

D. The LRA states that a sample taken from an RHRSW drain valve 

contained nuclides and as a result, testing was performed on one of the 

Unit 1 RHR heat exchangers. Dents were found at a number of tube-to

tube support connections and the dents may indicate tube vibration. The 

applicant should provide the basis for its determination that the dents 

may have been caused by tube vibration, as opposed to localized 

corrosion. In addition, the applicant should provide information regarding 

industry experience related to the bases and criteria of the inspections 

credited in the RHR heat exchanger augmented inspection and testing 

program. 

By letters dated October 10, 2000 and June 5, 2001, the applicant provided 

additional information related to the staff's concerns regarding vibration-induced 

cracking in the RHR heat exchangers. The applicant stated that there is no site 

or industry operating experience indicating that vibration-induced fatigue

1-30
cracking is an active mechanism in the RHR heat exchangers. However, the 

RHR heat exchanger augmented inspection and testing program provides for 

inspection activities capable of detecting significant tube damage or throughwall 

leakage that could result from potential vibration-induced damage. The program 

includes the following: 

"* eddy current testing (minimum of 10 percent of the operational tubes) 

once during each 10 year inspection period to determine the overall 

condition of the heat exchanger tubes 

"* leak testing to quantify leaks in the tubes or tubesheets 

"* general visual inspection of the channel side of the heat exchanger every 

three operating cycles to include visible portions of the tubesheets and 

tubes 

"* general visual inspection of the shell side of the heat exchanger once 

during the ten year interval to include a representative portion of the tube 

bundle, tube supports, tube-to-tubesheet interface, and baffles. 

The testing frequency is based on a combination of satisfactory results of eddy 

current tests performed on three heat exchangers and on heat exchanger design margin. Except for one tube in one heat exchanger, the condition of the tubes in 

all three heat exchangers was found to be free of damage. Also, the heat 

exchanger transfer surface area is oversized by at least 5 percent to provide sufficient margin if tubes need to be plugged. On the basis of the satisfactory 

test results, along with the excessive heat transfer capacity, the staff concludes 

that the equipment will perform its intended function between inspections. 

In addition, identification of crack indications by inspection personnel are subject 

to appropriate engineering evaluation. Areas that are unavailable for inspection 

due to inability to pass the eddy current probe are noted on the inspection report. 

The applicant also provided information regarding the RHR heat exchanger tube 

leakage identified in 1996. The leakage was suspected due to detection of 

radionuclides in the RHRSW system. In October 1997, eddy current testing 

identified nine tubes, including one leaking tube, with significant damage. As a 

result, all nine tubes were plugged. Although no direct evidence of service

induced damage was identified, a follow-up inspection was recommended. In 

October 2000, eddy current inspections were performed on all heat exchanger 

tubes, except those plugged in October 1997. The result of this inspection did 

not reveal any accelerated degradation indicators and concluded that there was 

no evidence of any active service-induced degradation. 

The staff requested that the applicant provide details regarding the denting found 

on a number of tube-to-tube support connections. In response, the applicant stated that denting, as referred to in the submitted operating history on the heat 

exchanger, is indicative of the tube roundness. Though tube dents can be 

service-induced, the denting is often the result of fabrication flaws from bending

1-31
or insertion. In addition, based on the October 2000 inspection results, no 

evidence exists to support localized corrosion or vibration as a significant factor 

in the tube dents identified. 

On the basis of the additional information provided by the applicant, the staff 

concludes that this new inspection program provides a variety of methods to 

manage the aging effects associated with the RHR heat exchangers. In 

addition, the staff finds that the most recent inspection results obtained through 

the techniques emcompassed by this program support the applicant's conclusion 

that localized corrosion or vibration is not a significant factor in the tube dents 

identified. 

On the basis of the information provided by the applicant and the staff's 

evaluation of this information, the staff concludes that the RHR heat exchanger 

augmented inspection program is adequate and appropriate to manage the 

aging effects associated with the RHR heat exchangers. Open Item 3.1.28-1 is 

closed. 

3.2.3.1.1-1 Cast austenitic stainless steel (CASS) components in the reactor assembly 

system may be subject to loss of fracture toughness due to the effects of thermal 

and neutron embrittlement. CASS components are susceptible to thermal 

embrittlement if they operate at temperatures greater than 550°F (the threshold 

that the NRC has established as the point at which thermal aging of CASS 

components occurs). Also, as indicated in Appendix H to 10 CFR Part 50, 

neutron irradiation embrittlement becomes significant at neutron fluences greater 

than 1017 n/cm2 (E>1 Mev). 

Table 2.3.1-1 of the LRA indicates that jet pump assemblies and fuel supports 

contain CASS components and are within the scope of license renewal. The 

Plant Hatch fuel supports support the weight of the fuel assemblies and 

distribute core flow into the fuel assemblies. Table 2.3.1-1 indicates that the 

CASS fuel supports have no aging effects requiring management. However, due 

to the fuel supports' proximity to the core, the staff believes that the CASS fuel 

supports are likely to be susceptible to neutron embrittlement. 

In response to RAI 3.2.3.2-1, the applicant indicated that portions of the jet pump 

assemblies may experience fluence greater than 1017 n/cm2 , but will not 

experience temperatures exceeding 5500F. On the basis of this information, the 

staff concludes that jet pump assemblies fabricated from CASS will not be 

susceptible to thermal embrittlement; but may be susceptible to neutron 

embrittlement. 

The BWRVIP generic AMP for the jet pump assembly components is described 

in EPRI report TR-108728, "BWRVIP BWR Jet Pump Assembly Inspection and 

Flaw Evaluation Guidelines (BWRVIP-41)." The BWRVIP-41 report does not 

recommend an inspection of CASS jet pump assembly components because 

CASS components are considered not susceptible to IGSCC. However, the 

BWRVIP-41 report does not contain any data to indicate the threshold for 

neutron embrittlement of CASS and does not identify the neutron fluence

1-32
experienced by the CASS jet pump assembly components. Because the 

BWRVIP-41 report does not provide data to support its conclusion that 

inspection of CASS components is not needed, the staff cannot conclude that 

the loss of fracture toughness resulting from irradiation embrittlement and 

cracking is not a plausible aging effect requiring aging management. However, 

the staff notes that irradiation embrittlement of CASS components becomes a 

concern only if cracks are present in the components. Therefore, if an applicant 

can show that cracks do not occur in the CASS components, then the sfaff can 

conclude that loss of fracture toughness resulting from neutron irradiation 

embrittlement will not be a significant aging effect. 

The staff notes that industry-wide experience shows that cracking has not been 

observed in CASS jet pump assembly components. Therefore, as part of its 

safety evaluation of the BWRVIP-41 report, the staff has requested, and the 

BWRVIP is considering, the inclusion of a baseline inspection in the BWRVIP-41 

report to ensure that cracking is not present in the components. Similarly, the 

staff requested that the applicant propose a one-time inspection of the CASS jet 

pump assembly components and fuel supports to confirm that the CASS 

components have not experienced cracking. The inspection should be 

performed prior to the beginning of the extended period of operation. This was 

identified as Open Item 3.2.3.1.1-1. 

Since the development of this open item, the staff has reconsidered the safety 

basis for requiring the applicant to perform a one-time inspection of the CASS jet 

pump assemblies and fuel supports. Since neutron embrittlement becomes a 

concern only if cracking is present in the components, and because both industry 

and plant experience have not identified cracking in these components, the staff 

concludes that there is no demonstrated safety issue regarding neutron 

embrittlement of the components. Further, the BWRVIP-41 report requires 

inspections of several jet pump assembly welds, which are more susceptible to 

cracking than the CASS components and will therefore serve as an indication of 

the potential need for more extensive inspections later in life. These welds are 

considered to be more susceptible than the CASS components, which are made 

in one piece and have no welds, since the BWR environment has the potential to 

promote IGSCC under normal water chemistry conditions. Therefore, the staff 

finds that the welds to be inspected in accordance with the BWRVIP-41 report 

will provide adequate indication if additional inspections may be needed in the 

future. In addition, the staff is considering confirmatory research to determine 

the effects of high levels of neutron fluence on BWR internals. The results of 

this program will be used by the staff in evaluating the need for additional 

inspections of CASS jet pump assemblies in the renewal period. Therefore, the 

staff concludes that a one-time inspection of jet pump assemblies and fuel 

supports is not warranted at this time to support operation for the license renewal 

term. 

Therefore, the staff concludes that a one-time inspection of jet pump assemblies 

and fuel supports is not warranted at this time to support operation for the 

license renewal term.

1-33
The BWRVIP and the NRC's Office of Nuclear Regulatory Research (RES) are 

considering joint confirmatory research to determine the effects of high levels of 

neutron fluence on BWR internals. Any future research results would help to 

determine whether additional inspections, or alternatives to inspections, are 

warranted. Should research results find that inspections of CASS jet pump 

assemblies and fuel supports are warranted, the results should be included in a 

staff-approved revision to the BWRVIP-41 report, or another staff-approved 

BWRVIP report. 

By letter dated June 5, 2001, the applicant committed to continued participation 

in BWRVIP activities, including the implementation of future BWRVIP 

documents. Further, the applicant has committed to implementing the guidelines 

of the BWRVIP-41 report, and any staff-approved revisions to the BWRVIP-41 

report. 

On the basis that the industry has not observed cracking in CASS jet pump 

assemblies and fuel supports, the staff has determined that its request for the 

applicant to perform a one-time inspection to identify cracking in the CASS jet 

pump assemblies and fuel supports is not warranted at this time. 

In addition, the applicant's commitment to implement future staff-approved 

BWRVIP documents related to aging management of CASS jet pump assembly 

components and fuel supports, and staff-approved BWRVIP guidelines, provides 

additional assurance that the aging effects associated with these components 

will be adequately managed during the period of extended operation. 

On the basis of the information discussed above, the staff concludes that the 

loss of fracture toughness of CASS jet pump assemblies and fuel supports due 

to the effects of thermal and neutron embrittlement will be adequately managed 

for the period of extended operation. Open Item 3.2.3.1.1-1 is closed. 

The staff was concerned that unanticipated high cycle thermal fatigue resulting 

from thermal stratification, turbulent penetration, or intergranular stress corrosion 

could result in cracking of small bore piping. These types of cracking are not 

evaluated as part of the component cyclic or transient limit program. The ASME 

Code Class 1 inspection requirements for small-bore piping include a surface 

examination, but not a volumetric examination. In order to detect cracking 

resulting from high cycle thermal fatigue or intergranular stress corrosion, a 

volumetric examination is required. Since the proposed program does not 

include a volumetric examination, it may not be capable of detecting high cycle 

thermal fatigue cracks resulting from thermal stratification, turbulent penetration, 

or intergranular stress corrosion. Therefore, the staff requested that the 

applicant supplement the existing programs with volumetric examination of the 

limiting locations in small-bore piping systems, excluding socket welds, which 

could have thermal stratification or turbulent penetration. 

By letter dated September 5, 2001, the applicant committed to including small

bore butt-welded stainless steel piping in the scope of the treated water systems 

piping inspection (TWSPI) program. TWPSI is a one-time condition monitoring

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3.2.3.2.3-1
program that provides for visual and volumetric inspections of a sample 

population intended to detect loss of material and cracking, and confirms the 

effectiveness of existing chemistry control programs. The staff's review of this 

aging management program is found in Section 3.1.24 of this SER. On the basis 

of the applicant's commitment to provide visual and volumetric examinations of 

the small-bore piping, Open Item 3.2.3.2.3-1 is closed. 

3.6.3.1-1 In Section 2.4.7 of the LRA, the intended function of the reactor building 

penetrations (T54-01) is "maintain secondary containment leakage rates within 

design limits." In TS Section B 3.6.4.1, under "LCO," it is stated "For the 

secondary containment to be OPERABLE, it must have adequate leak tightness 

to ensure that the required (0.2 inch) vacuum can be established and 

maintained." Numerous penetrations associated with the reactor building could 

contribute towards violating the design limits established for secondary containment (i.e., reactor building). Thus, the applicant should have an AMP to 

demonstrate that the overall effect of numerous degradations has not violated 

the leakage characteristics of the reactor building. This was identified as Open 

Item 3.6.3.1-1. 

By letter dated June 5, 2001, the applicant responded to this open item. The 

applicant stated that it had revised the structural monitoring program to include 

the provisions of Surveillance Requirement 3.6.4.1.4 of the Unit 1 and 2 technical 

specifications. The draw-down test performed pursuant to the surveillance 

requirement will be credited for aging management as an additional detection 

measure that is capable of detecting gross changes in flow that may be 

indicative of age-related degradation. The applicant also revised the FSAR 

Supplement to reflect this change. 

On the basis of the applicant's inclusion of the secondary containment draw

down test as per the surveillance requirements of the TS, as a means to detect 

gross age-related degradation of secondary containment, the staff concludes 

that the applicant has an adequate AMP to demonstrate that the overall effect of 

numerous degradations will not violate the leakage characteristics of the reactor 

building. Open Item 3.6.3.1-1 is closed. 

3.6.3.2-1 (a) In response to RAI 3.6-41 related to torus corrosion, the applicant 

provided a description of torus degradation found in both Plant Hatch 

units. However, the applicant emphasized that, in spite of the 

degradation, the actual shell thicknesses are well above the required 

minimum shell thicknesses. The applicant stated that it plans to continue 

to perform desludging, visual examination, and spot coating repairs 

periodically, based on the history of past inspection. The staff believed 

that operating experience at Plant Hatch and other industry operating 

experience related to torus corrosion indicated a need for a program to 

manage torus corrosion during the period of extended operation. In 

Open Item 3.6.3.2-1 (a), the staff requested the applicant to provide 

justification as to why this program should not be a separate program in 

the LRA.

1-35
By letter dated January 31, 2001, the applicant provided a drawing 

showing a section through the torus and associated penetrations. The 

drawing also identified the AMPs associated with the penetrations above 

and below the water line. For torus penetrations above the water line, the 

applicant takes credit for implementing the inservice inspection program, 

the primary containment leakage testing program, the protective coating 

program, and the component cyclic or transient limit program. 

Additionally, for torus penetrations below the water line and in the splash 

zone of the torus shell, the applicant takes credit for implementing the 

suppression pool chemistry control program the torus submerged 

component inspection program, and the protective coatings program. 

Moreover, the applicant states, "a review of torus inspection reports 

indicates that degradation of the torus coating, in the form of thinned 

coatings, and some pitting corrosion in the torus immersion area is 

general in nature and occurs primarily on the torus shell. No specific 

corrosion has been noted around penetrations welded to the shell. 

Corrosion is generally more evident near the torus waterline and at or 

near the bottom of the torus where sludge or small debris collects." The 

applicant also provides a listing of penetrations in the torus of each unit. 

This information adequately responds to the staff's concern regarding the 

AMPs for torus degradation, and closes Open Item 3.6.3.2-1 (a). 

(b) Table 3.3.1-3 of the LRA did not provide any information regarding the 

aging management (including surveillance requirements) for gears, 

latches, and linkages of personnel hatches and penetrations. RAI 3.6-15 

requested that the applicant identify where fretting and lockup of hinges, 

locks, and closure mechanisms for personnel hatches is discussed in the 

LRA, or provide a technical justification for not considering fretting and 

lockup as applicable aging effects for these components. The RAI also 

asked that the applicant provide a description of the AMP for the 

personnel hatches, consistent with the 10 elements in the SRP-LR, in 

sufficient detail to allow the staff to assess the adequacy of this program 

to manage the applicable aging effects. The applicant responded that 

locks and closure mechanisms are active components, and are not 

subject to an AMR. Therefore, fretting and lockup of hinges, locks, and 

closure mechanisms for personnel hatches and penetrations are not 

discussed in the LRA. However, aging management for personnel 

airlocks, hatches, equipment hatches, and penetrations are managed by 

the ISl program, protective coatings program, and primary leak rate 

testing program, as discussed in LRA Sections C.2.6.2, A.1.9, A.2.3, and 

A.1.14. This was identified as Open Item 3.6.3.2-1(b). 

The primary containment leakage testing program is described in Section 

18.2.14 of the Plant Hatch FSAR Supplement. It states that the applicant 

has chosen to identify the performance-based requirements and criteria for 

pre-operational testing and subsequent periodic leakage rate testing. The 

program ensures that leakage through the primary containment, or through 

systems and components that penetrate the primary containment, does not

1-36
exceed allowable leakage rates specified in the TS, and that the integrity of 

the containment structure is maintained during its service life. 

The staff notes that the applicant's approach conforms with the 

performance-based approach described in Section XI.S4 of the Generic 

Aging Lessons Learned (GALL) report that was reviewed and approved by 

the staff, and issued in July, 2001. As such, the staff concludes that aging 

management by the ISl program, protective coatings program, and primary 

leak rate testing program, for personnel airlocks, hatches, equipment 

hatches, and penetrations, is adequate to ensure that leakage through the 

primary containment, or through systems and components that penetrate 

the primary containment, does not exceed allowable leakage rates. Open 

Item 3.6.3.2-1 (b) is closed. 

4.1.3-1 (a) Table 4.1.1-1 of the LRA identifies piping stress analyses that consider 

thermal fatigue cycles as a TLAA. The table does not identify the fatigue 

analyses of other reactor coolant pressure boundary components or the 

reactor vessel internals as TLAAs. Section 4.2 of the LRA does address the 

reactor pressure vessel. In RAI 4.1-2, the staff asked the applicant to 

identify other components of the reactor coolant pressure boundary that 

have fatigue analyses. The staff also asked the applicant to describe the 

TLAAs that were performed to address fatigue for the reactor coolant 

pressure boundary components, except for the reactor vessel, that were not 

included in Table 4.1.1-1, and to describe the TLAA performed for the 

reactor vessel internals. The staff also requested that the applicant indicate 

how these TLAAs meet the requirements of 10 CFR 54.21 (c). In response, 

the applicant stated that the criteria of BWRVIP-74 were used to determine 

which fatigue analyses were sufficiently significant to constitute a TLAA. As 

indicated in the RAI, the applicant discussed the fatigue analysis of the 

reactor vessel internals in the UFSAR. In the SER issued in February, 

2001, the staff requested that the applicant explain how the fatigue analysis 

of the vessel internals was found to be acceptable for the 60-year period. 

The staff also requested that the applicant identify any other components of 

the reactor coolant pressure boundary that had fatigue analyses, and 

explain how these analyses were found to be acceptable for the 60-year 

period. This was identified as part of Open Item 4.1.3-1 [4.1.3-1(a)]. 

The applicant provided a response to this open item by letter dated June 5, 

2001. In the letter, the applicant indicated that the initial Plant Hatch vessel 

internals AMR noted that cracking due to fatigue was an aging effect 

requiring management and that the fatigue cumulative usage factor (CUF) 

calculation was a TLAA. The applicant's response also indicated that, 

subsequent to the development of the initial AMR, the end-of-life CUF was 

determined to be substantially less than 0.5. The applicant stated that since 

the end-of-life CUF was low, the fatigue calculation did not represent a 

TLAA. The staff disagrees with the applicant's premise that, because the 

calculated CUF was low, the fatigue calculation did not represent a TLAA. 

The applicant should have identified the vessel internals fatigue analysis as 

a TLAA in the LRA and described the disposition of the TLAA per the

1-37
requirements of 10 CFR 54.21(c)(1). However, the applicant's current 

fatigue analysis of the vessel internals, which projects that the CUF will 

remain below 1.0 for the period of extended operation, provides an 

acceptable TLAA evaluation in accordance with the requirements of 10 CFR 

54.21 (c)(1)(ii). The applicant did not identify any other components of the 

reactor coolant pressure boundary that had fatigue analyses. Therefore, 

this part of Open Item 4.1.3-1 [4.1.3-1 (a)] is closed. 

(b) Section 4.2.2 of the LRA contains a discussion of the Plant Hatch licensing

basis pipe break criteria. Part of the Plant Hatch pipe break criteria involves 

postulating pipe breaks at locations where the calculated fatigue usage 

exceeds a specified value. Although the applicant identified the fatigue 

cumulative usage factor (CUF) calculation as a TLAA, the applicant 

concluded that the pipe break criteria were only a screening mechanism and 

not a TLAA. The usage factor calculation used to identify postulated pipe 

break locations meets the definition of a TLAA, as specified in 10 CFR 54.3. 

In RAI 4.2-1, the staff asked the applicant to provide a description of a TLAA 

for the pipe break criteria at Plant Hatch, and describe how the TLAA meets 

the requirements of 10 CFR 54.21 (c). In response, the applicant stated that 

it views the pipe break criteria to be selection criteria that establish a 

bounding set of locations for line break consideration. Although the staff 

agreed with the applicant's statement, the staff still considered pipe break 

postulations to be a TLAA because the fatigue calculation is a TLAA. 

Additionally, the NRC previously identified high-energy line break postulation 

founded on the fatigue CUF as a TLAA in accordance with 10 CFR 54.3 (60 

FR 22480, May 8, 1995). Therefore, the staff requested that the applicant 

include pipe break postulations founded on the fatigue usage factor as a 

TLAA. This was identified as part of Open Item 4.1.3-1 [4.1.3-1 (b)]. 

By letter dated September 5, 2001, the applicant responded to this open 

item. In the response to the open item, the applicant revised its LRA 

discussion of pipe break criteria to classify pipe break postulations based on 

fatigue CUF as TLAAs. The TLAA evaluation is discussed in Section 4.2.5 

of the revised LRA. The licensing basis pipe break criteria required that 

breaks be postulated at piping locations where the calculated CUF 

exceeded 0.1. The applicant identified additional piping locations where the 

CUF criterion may be exceeded during the period of extended operation. 

The applicant proposed to monitor three bounding locations during the 

period of extended operation using its Component Cyclic or Transient Limit 

Program to address the TLAA. The applicant's proposed program, which 

involves monitoring a sample of bounding locations during the period of 

extended operation, is an acceptable method to address the pipe break 

postulation TLAA in accordance with the requirements of 54.21 (c)(1). If the 

CCTLP identifies a location where the usage criterion may be exceeded, 

then the applicant must take corrective action in accordance with the 

corrective action program. As part of the corrective action, other potential 

locations must be addressed. This part of Open Item 4.1.3-1 [4.1.3-1 (b)] is 

closed.

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4.2.3-1 By letter dated February 9, 1998, the Electric Power Research Institute (EPRI) 

submitted two technical reports dealing with the fatigue issue. EPRI Reports 

TR-107515, "Evaluation of Thermal Fatigue Effects on Systems Requiring Aging 

Management Review for License Renewal for the Calvert Cliffs Nuclear Power 

Plant," and TR-1 05759, "An Environmental Factor Approach to Account for Reactor 

Water Effects in Light Water Reactor Pressure Vessel and Piping Evaluations" were 

part of an industry attempt to resolve GSI-1 90. As recommended in SECY 95-245, 

the EPRI analyzed components with high usage factors, using environmental 

fatigue data. The staff has open technical concerns regarding the EPRI reports. 

The staff's technical concerns were transmitted to the Nuclear Energy Institute (NEI) 

by letter dated November 2, 1998. The NEI responded to the staff's concerns in a 

letter dated April 8, 1999. The staff submitted its assessment of the response in a 

letter to the NEI, dated August 6, 1999. As indicated in the staff's letter, the NEI 

response did not resolve all of the staff's technical concerns regarding the EPRI 

reports. 

The applicant indicated that EPRI license renewal fatigue studies have 

demonstrated that sufficient conservatism exists in the design transient definitions 

to compensate for potential reactor water environmental effects for Plant Hatch. As 

discussed above, the staff does not agree with the contention that the EPRI fatigue 

studies have demonstrated that sufficient conservatism exists in the design 

transient definitions to compensate for potential reactor water environmental effects. 

Although the letter dated August 6, 1999 identified the staff's concerns regarding 

the EPRI procedure and its application to PWRs, the technical concerns regarding 

the application of the Argonne National Laboratory (ANL) statistical correlations and 

strain threshold values are also relevant to BWRs. In addition to the concerns 

referenced above, the staff has additional concerns regarding the applicability of the 

EPRI BWR studies to Plant Hatch. EPRI Report TR-107943, "Environmental 

Fatigue Evaluations of Representative BWR Components," addressed a BWR-6 

plant, and EPRI Report TR-1 10356, "Evaluation of Environmental Thermal Fatigue 

Effects on Selected Components in a Boiling Water Reactor Plant," used plant 

transient data from a newer vintage BWR-4 plant. In RAI 4.2-2, the staff requested 

that the applicant provide additional information regarding the use of the EPRI 

license renewal fatigue studies to resolve the environmental fatigue issue at Plant 

Hatch. 

In response to the RAI, the applicant discussed its assessment of the impact of the 

environmental correction factors for carbon and low-alloy steels contained in 

NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design 

Curves of Carbon and Low-Alloy Steels," and those for austenitic stainless steels 

contained in NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue 

Design of Austenitic Stainless Steels," on the results of the EPRI studies. As a 

result of its assessment, the applicant concluded that the correlations have been 

adequately accounted for via the conservatism of the design-basis transients. 

The applicant indicated that EPRI Report TR-1 10356 contained studies that are 

directly applicable to Plant Hatch because they involved a BWR-4 that is identical 

to the Plant Hatch design. The only components evaluated in TR-1 10356 are the 

feedwater nozzle and the control rod drive penetration locations. However, the

1-39
applicant indicated that both Plant Hatch units employ hydrogen water chemistry, 

whereas the plant in the EPRI study did not consider hydrogen water chemistry, 

which affects the level of dissolved oxygen in the primary system. Dissolved oxygen 

is an important factor in the environmental fatigue effects. The applicant stated that 

this issue was adequately addressed by its evaluation of the feedwater nozzle 

contained in EPRI Report TR-105759. It is not clear to the staff how the issue of 

hydrogen water chemistry was addressed in EPRI Report TR-105759. The 

applicant's response did not resolved the staff's concerns regarding the 

environmental fatigue issue at Plant Hatch. 

The staff requested that the applicant provide an assessment of the six locations 

identified in NUREG/CR-6260, "Application of NUREG/CR-5999, 'Interim Fatigue 

Curves to Selected Nuclear Power Plant Components'," dated March 1995, for an 

older vintage BWR (BWR-4) considering the applicable environmental fatigue 

correlations provided in NUREG/CR-6583 and NUREG/CR-5704 reports for Plant 

Hatch Units 1 and 2. The applicant indicated that these locations are monitored by 

the CCTLP, and that the environmental factors have been adequately accounted 

for by the conservatism in the design basis transient definitions. On the basis of the 

above discussion, the staff did not agree with the applicant that environmental 

fatigue concerns regarding the six locations identified in NUREG/CR-6260 have 

been adequately addressed at Plant Hatch. The staff, therefore, requested that the 

applicant assess these six locations, considering applicable environmental fatigue 

correlations provided in NUREG/CR-6583 and NUREG/CR-5704, as applicable. 

This was identified as Open Item 4.2.3-1. 

By letter dated September 5, 2001, the applicant provided a revised response to 

Open Item 4.2.3-1. The applicant committed to evaluate the locations identified in 

NUREG/CR-6260 using the applicable environmental fatigue correlations provided 

in NUREG/CR-6583 and NUREG/CR-5704. These locations are: 

* Reactor Vessel (Lower Head to Shell Transition) 

* Feedwater Nozzle 

* Recirculation System (RHR Return Line Tee) 

* Core Spray System (Nozzle and Safe End) 

0 Residual Heat Removal Line (Tapered Transition) 

* Feedwater Line (RCIC Tee) 

The applicant indicated that usage factor multipliers would be developed at each 

location to account for the environmental effects. The applicant further indicated 

that these environmental multipliers would be incorporated in the Hatch CCTLP. 

The applicant's CCTLP will monitor the CUF, which includes the environmental 

multipliers, at the six locations for comparison with the allowable CUF. The 

applicant's proposal adequately addresses the staff concern regarding 

environmental effects on fatigue usage and, therefore, Open Item 4.2.3-1 is 

considered closed.

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1.5 Summary of License Conditions

As a result of it's review of the LRA, including the additional information and clarifications that were 

submitted by the applicant, the staff identified 3 license conditions. The first license condition is 

associated with the resolution of Open Item 3.0-1. This license condition requires the applicant to 

include the FSAR Supplement in the next UFSAR update, required by 10 CFR 50.71(e). The 

second license condition is associated with the resolution of Open Item 3.1.17-1. This license 

condition requires that, prior to operation in the renewal term, the applicant will notify the NRC of 

the its decision to implement either the staff-approved reactor vessel integrated surveillance 

program, or a plant-specific program, and provide the appropriate revisions to the FSAR 

Supplement summary descriptions of the vessel surveillance material testing program. The third 

license condition requires that the future inspection activities identified in the FSAR Supplement 

be completed before the beginning of the extended period of operation.

1-41
2 STRUCTURES AND COMPONENTS SUBJECT TO AN AGING MANAGEMENT REVIEW 

This section of the SER describes the staff's review of the methodology used by the applicant to 

implement the scoping and screening requirements of 10 CFR Part 54 (the Rule), as well as the 

staff's evaluation of the applicant's scoping and screening results. 

By letter dated February 29, 2000, the applicant submitted its request and application for renewal 

of the operating licenses for the Edwin I. Hatch Nuclear Plant, Units 1 and 2. As an aid to the staff 

during the review, the applicant provided evaluation boundary drawings that identify the functional 

boundaries for systems and components within the scope of license renewal. These evaluation 

boundary drawings are not part of the license renewal application. 

On July 14 and July 28, 2000, the staff issued requests for additional information (RAIs) regarding 

the applicant's methodology for identifying structures, systems, and components (SSCs) at Plant 

Hatch that are within the scope of license renewal and subject to an aging management review 

(AMR) and the results of the applicant's scoping and screening process. On August 29 and 

October 10, 2000, the applicant provided responses to the RAIs. 

2.1 Scoping and Screening Methodology 

2.1.1 Introduction 

In Section 2.1, "Scoping and Screening Methodology," of the Plant Hatch license renewal 

application (LRA), the applicant described the scoping and screening methodology used to identify 

structures, systems, and components (SSCs) at Plant Hatch that are within the scope of license 

renewal, and structures and components (SCs) that are subject to an AMR. The staff reviewed the 

applicant's scoping and screening methodology to determine if it meets the scoping requirements 

set forth in 10 CFR 54.4(a) and the screening requirements set forth in 10 CFR 54.21. 

10 CFR 54.21, "Contents of Application - Technical Information," requires, in part, that each 

application for license renewal contain an integrated plant assessment (IPA) that identifies and lists 

those SSCs that satisfy the criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3) that are subject to an 

AMR. 10 CFR 54.4, "Scope," defines the criteria for including SSCs within the scope of the Rule. 

In developing the scoping and screening methodology for the Plant Hatch LRA, the applicant 

considered the requirements of the Rule, the Statements of Consideration (SOCs, 60 FR 22401, 

May 8, 1995) for the Rule, and the guidance provided by the Nuclear Energy Institute (NEI), 

"Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal 

Rule," Revision 0 (NEI 95-10). In addition, the applicant also considered the staff's correspondence 

with other applicants and with the NEI in the development of this methodology. The applicant 

stated that the methodology was also developed with the knowledge that some provisions of the 

Rule may be satisfied by implementing 10 CFR 50.65, "Requirements for Monitoring the 

Effectiveness of Maintenance at Nuclear Power Plants" (the Maintenance Rule) at Plant Hatch. 

2.1.2 Summary of Technical Information in the Application 

Section 2.1 of the Plant Hatch LRA describes the process that the applicant used to implement the 

scoping requirements of the Rule as specified in 10 CFR 54.21(a)(2). As used in the Plant Hatch

2-1
application methodology, scoping is the process of identifying systems and structures that meet 

the scoping criteria of 10 CFR 54.4(a)(1) - (3), including the identification of intended functions as 

defined by 10 CFR 54.4(b), i.e., those functions that are related to meeting one or more of the 

scoping criteria of 10 CFR 54.4(a)(1) - (3). The Plant Hatch scoping criteria, as applied to plant 

SSCs, are: 

reactor coolant pressure boundary integrity (10 CFR 54.4(a)(1)(i)) 

safe reactor shutdown and maintenance (10 CFR 54.4(a)(1)(ii)) 

accident consequence prevention or mitigation (10 CFR 54.4(a)(1 )(iii)) 

non-safety-related SSCs whose failure could prevent satisfactory accomplishment of any 

of the functions associated with the items above (10 CFR 54.4(a)(2)) 

compliance with fire protection regulations (10 CFR 50.48) (10 CFR 54.4(a)(3)) 

compliance with environmental qualification regulations for electrical equipment (10 CFR 

50.49) (10 CFR 54.4(a)(3)) 

compliance with anticipated transient without scram (ATWS) regulations (10 CFR 50.62) 

(10 CFR 54.4(a)(3)) 

compliance with station blackout (SBO) regulations (10 CFR 50.63) (10 CFR 54.4(a)(3)) 

An additional regulation, 10 CFR 50.61, "Fracture Toughness Requirements for Protection Against 

Pressurized Thermal Shock Events," does not apply to Plant Hatch, because, as specified in the 

regulation, an evaluation in accordance with Regulatory Guide 1.154, "Format and Content of 

Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water 

Reactors," January 1987 is not required for boiling water reactor plants. 

The identification and listing of SCs that are subject to an AMR is called "screening" in the Plant 

Hatch application methodology, as discussed in Section 2.1.3 of the LRA for civil/mechanical 

disciplines, and in Section 2.1.4 of the LRA for the electrical discipline. 

2.1.2.1 Technical Information for Identifying Systems, Structures, and Components Within the 

Scope of License Renewal 

As provided in 10 CFR 54.4(a)(1), design-basis events for license renewal are applied as defined 

in 10 CFR 50.49(b)(1), consistent with the current licensing basis (CLB). 10 CFR 54.4(b) provides 

that the intended functions that these SSCs 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 

10 CFR 54.4(b), paragraphs (a)(1)-(3). 

The process for implementing the requirements of 10 CFR 54.4(a) and (b) is summarized by the 

following steps and described in detail in Section 2.1.2 of the LRA: 

* Plant systems and structures, and their functions, were identified.

2-2
The function of each system and structure was reviewed to determine whether it met any 

of the scoping criteria specified in 10 CFR 54.4(a). 

The applicant performed a comprehensive review of design documents in order to create a list of 

systems and structures to be scoped. Information sources included the Plant Hatch Equipment 

Location Index (ELI) which lists system and structure nomenclature used at the plant, as well as 

the plant's Maintenance Rule Scoping Manual, System Evaluation Document (SED), and UFSARs. 

In addition, a plant design drawing, which lays out a generic listing of system nomenclature for 

boiling water reactors (BWRs), was reviewed in order to thoroughly identify all potential 

system/structure identifiers. The resultant list of potential systems and structures provided a 

starting point for system and structure function identification. 

The scoping requirements of the license renewal rule and the maintenance rule overlap. Because 

of the similarities in the rules, the Plant Hatch Maintenance Rule Scoping Manual was one of the 

information sources used to establish an initial listing of plant system and structure functions. 

The final list of functions evaluated for license renewal encompasses all plant systems and 

structures, except as described in Section 2.1.2.3 of the LRA. The functions did not necessarily 

follow traditional system boundaries, in that the functions included structures and components, 

irrespective of traditional system nomenclature, that perform or support the identified function. To 

arrive at the component level, the applicant chose to scope at a function level and screen at the 

component level. The applicant elected to use the term "component function" when referring to 

the specific structure, component, or component group functions needed to support an intended 

function. Systems and structures that only provide emergency preparedness or physical protection 

functions were not evaluated in the scoping process. 

Safety-Related Systems and Structures 

10 CFR 54.4(a)(1)(i), (ii), and (iii) provide the scoping criteria for determining the functions of 

safety-related systems and structures that are within the scope of the Rule. Each system and 

structure function in the plant listing of scoping results (LRA Table 2.2-1 ) was reviewed with respect 

to these requirements by addressing the following questions: 

Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the integrity of the reactor coolant 

pressure boundary? 

Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the capability to shut down the 

reactor and maintain it in a safe shutdown condition? 

Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the capability to prevent or 

mitigate the consequences of accidents that could result in potential offsite exposure 

comparable to the guidelines in 10 CFR 100.11 ? 

To answer these questions, the applicant used engineering and licensing documents. The ELI and 

the SED are engineering documents that provide system-related design information. The UFSARs, 

the Maintenance Rule Scoping Manual, and the SED provide function-related information. The

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UFSARs and applicable references identify the basis for design-basis events at Plant Hatch. If the 

answer to one or more of the three questions was "YES," the corresponding system or structure 

function was determined to be within the scope of the Rule and was designated as an intended 

function as identified by 10 CFR 54.4(b). 

In certain cases, the applicant has conservatively chosen to designate some systems as safety

related, even though their functions may not meet any of the scoping criteria of 10 CFR 54.4(a)(1). 

System functions brought into scope by 10 CFR 54.4(a)(1) were also reviewed to determine 

whether they were also in scope based on the requirements of 10 CFR 54.4(a)(2) or 10 CFR 

54.4(a)(3). In addition, functions may include, in a few cases, both safety-related and non-safety

related components. In those cases, a function would be identified as meeting the scoping criteria 

of 10 CFR 54.4(a)(1), as well as the requirement for 10 CFR 54.4(a)(2), as described below. 

Non-safety-Related Systems and Structures Whose Failure Could Prevent Safety-Related Systems 

and Structures from Accomplishing Their Functions 

10 CFR 54.4(a)(2) provides that "all non-safety-related systems, structures, and components 

whose failure could prevent satisfactory accomplishment of any of the functions identified in 

paragraphs (a)(11)(i), (ii), or (iii)" of 10 CFR 54.4 are within the scope of the Rule. Few system and 

structure functions at Plant Hatch satisfy this criterion because systems and structures supporting 

safety-related systems and structures were typically designed as safety-related. Each system and 

structure function in the plant's listing of scoping results was reviewed with respect to this 

requirement by addressing the following question: 

Is the function of the system or structure identified as non-safety-related whose failure could 

prevent satisfactory accomplishment of any of the functions identified in 10 CFR 

54.4(a)(1 )(i), (ii), or (iii)? 

To answer this question, the applicant used engineering and licensing documents. The ELI and 

the SED were used to provide system-related design information. The UFSARs, the Maintenance 

Rule Scoping Manual, and the SED were used to provide function-related information. The 

UFSARs and applicable references were used to identify the basis for design basis events at Plant 

Hatch. 

Based upon a review of the UFSARs, issues or events considered in association with this question 

for Plant Hatch were Seismic Il/I, flooding, jet impingement, pipe whip, and missiles. 

If a function was used to mitigate one or more of the issues or events, the answer to the above 

question was "YES," the corresponding system or structure function was brought in scope, and the 

function was identified as an intended function per 10 CFR 54.4(b). In making determinations 

associated with this question, the applicant also relied on the consideration of actual plant-specific 

experience, industry-wide operating experience, and existing plant-specific engineering evaluations 

that were originally addressed by the controlled Maintenance Rule Scoping Manual determinations. 

Hypothetical failures that result from postulated system functional interdependencies that are not 

part of the Plant Hatch safety analyses or effects evaluations and that have not been observed at 

Plant Hatch were not considered.

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Systems and Structures Relied Upon to Demonstrate Compliance With Certain NRC Regulations 

The applicant reviewed the NRC's Safety Evaluation Reports (SERs) and related docketed 

correspondence associated with four of the five regulations identified in 10 CFR 54.4(a)(3). The 

applicant used this review to identify the set of system and structure functions credited with 

satisfying the requirements associated with those regulations from the complete set of system and 

structure functions established by the process described in LRA Section 2.1.2.2. The four 

regulations are as follows: 

10 CFR 50.48, "Fire Protection" 

10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants" 

10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without 

Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants" 

10 CFR 50.63, "Loss of All Alternating Current Power" 

An additional regulation, 10 CFR 50.61, "Fracture Toughness Requirements for Protection Against Pressurized Thermal Shock Events," does not apply to Plant Hatch, because, as specified in the 

regulation, an evaluation in accordance with Regulatory Guide 1.154 is not required for boiling 

water reactor plants. 

Each system and structure function was reviewed with respect to these criteria by addressing the 

following questions: 

Is the function of the system or structure relied upon in safety analyses or plant evaluations 

to demonstrate compliance with the Commission's regulation for fire protection (10 CFR 

50.48)? 

Is the function of the system or structure relied upon in safety analyses or plant evaluations 

to demonstrate compliance with the Commission's regulation for environmental qualification 

(10 CFR 50.49)? 

Is the function of the system or structure relied upon in safety analyses or plant evaluations 

to demonstrate compliance with the Commission's regulation for ATWS events (10 CFR 

50.62)? 

Is the function of the system or structure relied upon in safety analyses or plant evaluations 

to demonstrate compliance with the Commission's regulation for SBO (10 CFR 50.63)? 

The Environmental Qualification Master List (EQML) was used to identify the systems that are 

relied upon to comply with 10 CFR 50.49. For the second question, if system or structure 

components were listed in the EQML, then each system or structure function that required 

environmental qualification of the components was designated as being relied upon to demonstrate 

compliance with 10 CFR 50.49. These system or structure functions were brought in scope, and 

they were identified as intended functions per 10 CFR 54.4(b).

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During the review of the EQML, NRC SERs, and docketed correspondence, the applicant 

confirmed that any credited functions and the systems and structures that specifically contribute 

to accomplishing the functions were included in the list of system or structure functions. For the 

remaining questions, regarding the fire protection, ATWS, and station blackout regulations, if the 

answer to any of the questions was "YES," then each corresponding system or structure function 

was brought into scope and was identified as an intended function per 10 CFR 54.4(b). The NRC 

SERs and associated docketed correspondence were used to answer these questions. 

2.1.2.2Technical Information for the Structures and Components Subject to an Aging 

Management Review 

Civil/Mechanical Component Screening 

The license renewal rule requires a review of plant SSCs to determine if the effects of aging will 

be adequately managed for certain SCs in the period of extended operation. The process 

described in LRA Section 2.1.2 was used to identify the intended functions, that is, those SSC 

functions that are within the scope of the Rule. 10 CFR 54.21(a) requires that an IPA process be 

applied to SSCs determined to be in scope per 10 CFR 54.4. The IPA process employed by the 

applicant required an initial review of those functions within the scope of the Rule, as determined 

by the process described in LRA Section 2.1.2, to define intended function evaluation boundaries. 

The intended function evaluation boundaries were then used to assist in the identification of the 

SCs that are subject to an AMR. 

10 CFR 54.21 (a)(1) requires applicants to identify and list the SCs subject to an AMR. LRA Section 

2.1.3 defines a "screening" process whereby the applicant identified and listed the SCs that met 

the criteria of 10 CFR 54.21 (a)(1)(i) and (ii). Use of the term "passive" within this application is 

intended to be identical to criterion (i). That is, SCs that perform an intended function without 

moving parts or without a change in configuration or properties are characterized as "passive." Likewise, use of the term "long-lived" is intended to be identical to criterion (ii). That is, structures 

and components that are not subject to replacement based on a qualified life or specified time 

period are characterized as "long-lived." 

The applicant performed screening of the civil/mechanical intended functions for Plant Hatch in two 

steps: 

1. Evaluation boundaries were established for each intended function. 

2. Passive, long-lived components were identified within each evaluation boundary. The 

screening process first established an evaluation boundary to define the systems or 

structures that are required to accomplish an intended function. Then each evaluation 

boundary was used to assist in identifying the complete set of SCs within the evaluation 

boundary and to identify the passive, long-lived subset that represents those SCs subject 

to an AMR. This final set of SCs is presented in the tables in LRA Sections 2.3 through 2.5 

in fulfillment of the requirement of 10 CFR 54.21 (a)(1). 

Intended Function Evaluation Boundaries 

This step of the screening process defined the evaluation boundary for the system and structure 

functions determined to be within the scope of the Rule by the process described in LRA Section

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2.1.2. These functions are the intended functions per the definition in the Rule. Defining the 

evaluation boundary focuses the screening process on the portions of systems and structures that 

contribute to the performance of one or more intended functions. Evaluation boundaries were 

established such that multiple, in-scope functions are included in one evaluation boundary 

description to the extent practical. 

Evaluation boundaries were produced using controlled procedures to ensure a consistent approach 

to preparation and documentation. Evaluation boundaries, as used in this methodology, were not 

required to match other boundaries that are defined in existing documents such as the UFSARs 

or plant piping and instrumentation diagrams. Defining evaluation boundaries for license renewal 

does not require the plant to change or redefine other existing boundaries such as pipe class 

design boundaries or inservice inspection and testing boundaries. In addition, where a functional 

boundary was defined in the CLB for an in-scope function, the CLB-defined boundary was used. 

The applicant chose to conservatively designate certain components as "in scope" more broadly 

than the Rule might otherwise require. 

The method of describing the evaluation boundary relied primarily on plant drawings. The set of 

drawings that were most appropriate to illustrate the boundary information was marked up with 

boundary designations that clearly indicate which portions or areas of the system are inside and 

which portions are outside the evaluation boundary. For example, system piping and 

instrumentation diagrams (P&IDs) were typically used to illustrate the evaluation boundary of 

intended functions from a mechanical perspective. 

Due to the nature of civil/structural functions, evaluation boundary drawings were not produced for 

intended functions associated with structures; piping, cable tray, and conduit supports; electrical 

panel and rack supports; secondary containment doors; cranes; tornado vents; and penetrations. 

Instead, a plan view of the plant site was produced to identify the in-scope structures. The 

evaluation boundary of a structure that is a building included the entire building, including slabs, 

external and internal walls, roof and internal concrete, steel columns and beams, and framing. 

Miscellaneous steel items, such as base plates and embedded plates, were also included. 

In the process of defining evaluation boundaries, emphasis was placed on ensuring that all 

interfaces were adequately considered. As necessary, other references, prepared lists, and written 

descriptions were used to supplement or further clarify the boundary designations on the marked

up drawings. The final set of illustrated mechanical and electrical drawings, references, and written 

descriptions formed the "boundary package" for an intended function, and was documented by 

controlled procedures. In order to maintain a consistent approach to screening, general and 

specific discipline interface guides were established and used to assist in designating the intended 

function evaluation boundaries and interfaces. 

The applicant's screening process first defined civil/mechanical evaluation boundaries for intended 

functions. Then, all components included in the evaluation boundary were grouped, when practical, 

and screened. The applicant stated that this approach differs from NEI 95-10, Revision 0, which 

establishes groupings after the screening process is completed. 

Component Types. Component Groups, and Component Functions 

LRA Table 2.1-1 lists component types that are in scope for license renewal at Plant Hatch. This 

table is based on a table that originated as Appendix B of NEI 95-10, Revision 0. During the

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process of screening structures and components at Plant Hatch, additional component types were 

identified and are included in LRA Table 2.1-1. 

The list in LRA Table 2.1-1 represents the plant-wide list of in-scope structures and components, 

by component type. The tables in LRA Sections 2.3 through 2.5 present the screening results 

arranged by plant system or structure member. Each component type listed in the tables in LRA 

Sections 2.3 through 2.5 is a passive component as determined in LRA Table 2.1-1. Although not 

required by the Rule, in order to more efficiently screen SCs, component types within each 

intended function evaluation boundary were grouped to the maximum extent practicable. In 

creating these component groups, only components of the same type were grouped together. That 

is, a component group of valves did not include pipe. In addition, only component types within each 

intended function evaluation boundary that were fabricated of similar materials, and which were 

subjected to similar environments were grouped. Structural or mechanical components included 

in each component group were identified and documented by one or a combination of the following 

methods: 

* by establishing a list of the MPL numbers 

* by listing the reference drawings 

• by describing the component or system 

When establishing a passive and long-lived component group, specific information required to 

accurately describe the component function(s), materials composition, and internal and external 

environments for the components included in the component group was recorded in the screening records. In addition, the applicable drawings, system descriptions, design information, material 

specifications, and/or other information that could aid in performing an AMR were documented to 

the extent necessary to accurately and efficiently screen a component group. 

Component function(s) for component types subject to an AMR were established on the basis of 

how the structure or component functions to support maintaining one or more intended functions 

consistent with the CLB, without reliance on redundancy or probabilistic considerations. LRA Table 

2.1-2 provides the list of component functions used in the structure and component screening at 

Plant Hatch. 

Passive Structures, Components, and Component Groups 

The applicant's process defined evaluation boundaries for intended functions associated with 

structures and screened the boundaries to identify the passive and long-lived elements of the 

structures. Although intended function evaluation boundary drawings were not produced for the 

structures, the structural components screening included the active/passive and long/short-lived determinations as a matter of completeness and to facilitate the aging management reviews. 

Components Subiect to Periodic Replacement at a Set Frequency or Qualified Life 

The detrimental effects of aging are assumed to be continuous and incremental. Thus, the 

detrimental effects of aging may increase as service life is extended, assuming no replacement of 

components. One way of effectively managing these effects is to replace selected structures and 

components on a specified time interval, based upon a qualified life of the structure or component. 

In this step of the screening process, the passive structures and components were reviewed to 

determine if they are subject to replacement based upon a specified time or qualified component

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life. Structures and components that are not subject to such replacement were classified as "long

lived." In the methodology employed by the applicant, a replacement life must be less than 40 

years for the structure or component to be considered "short-lived." Structures and components 

with replacement lives of 40 years or greater were considered "long-lived." Structures and 

components subject to replacement based on qualified life were identified as not being subject to 

an AMR. 

Identification of Electrical Components Subiect to an Aging Management Review 

The process used to identify electrical components that are subject to an AMR is different from the 

method used to identify civil and mechanical components that are subject to an AMR. Electrical 

screening was based on the premise that the majority of electrical components installed in the plant 

perform their function with moving parts or a change in configuration or properties, and are 

therefore not subject to an AMR per the Rule. The applicant accomplished the electrical screening 

process using the following steps: 

1. Develop a comprehensive list of all electrical component types installed in the plant without 

regard for system function or license renewal in-scope status. 

2. Determine the basic function that each component type performs. 

3. Determine which component types perform their function(s) without moving parts or a 

change in configuration or properties. This results in the list of electrical component types 

that are subject to an AMR for license renewal. 

4. Apply the scoping criteria of 10 CFR 54.4(a)(1) through (3) to the list of component types 

that meet the screening criteria to determine if the list of electrical component types 

requiring an AMR can be further reduced. 

In order to screen electrical component types to determine those which require an AMR, a 

complete list of all electrical component types installed in the plant was required. This list was 

compiled using the lists of components found in 10 CFR 54.21 (a)(1)(i) and NEI 95-10, Appendix B, 

as the starting point. The resulting list of components was evaluated by plant engineering 

personnel and system experts who used their knowledge of plant systems and drawings to ensure 

that the list was complete and contained all electrical component types in use at Plant Hatch. 

Some component types with similar functions were grouped together for simplicity. The in-scope 

electrical component types installed at Plant Hatch are included in LRA Table 2.1-1. The list of 

electrical component types that are subject to an AMR appears in LRA Table 2.5.15-1. 

Application of 10 CFR 54.21 Screening Criteria to Electrical Component Types 

Having compiled the electrical component type list, 10 CFR 54.21 criteria were applied to determine 

which component types are subject to an AMR. The screening criteria of 10 CFR 54.21 (a)(1)(i) and 

(ii) were applied to the comprehensive list of electrical component types to accomplish this step. 

Components are subject to an AMR if they meet both of the following screening criteria: 

10 CFR 54.21 (a)(1)(i) -The component performs an intended function as described in 54.4 

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

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10 CFR 54.21 (a)(1)(ii) - The component is not subject to replacement based on a qualified 

life or a specified time period. 

An active/passive determination in accordance with 10 CFR 54.21 (a)(1)(i) was documented for 

each type of electrical component installed at Plant Hatch. This determination is presented in LRA 

Table 2.1-1. 

When implementing the screening criteria of 10 CFR 54.21 (a)(1)(ii), except for those cases where 

a determination was made for individual components (e.g., components qualified pursuant to 10 

CFR 50.49), the determination was made for an entire component type or commodity group. 

Individual components within the scope of the environmental qualification (EQ) program fall into 

two categories: those with a qualified life of 40 years or greater which are covered by a time-limited 

aging analysis (TLAA), and those with a qualified life of less than 40 years which are therefore 

subject to replacement based on a specified time period. The components with qualified lives of 

less than 40 years are currently on a replacement schedule which will continue into the renewal 

term; these components are not subject to an AMR. The qualified life calculations of those 

components with qualified lives greater than 40 years are treated as TLAAs and are evaluated in 

Section 4 of this SER. These TLAAs are dispositioned in accordance with the applicable 

disposition method per the Rule. In cases where a particular TLAA cannot be extended to 60 

years, those components will be replaced or refurbished in accordance with the requirements of 

the EQ program. Therefore, no components included in the EQ program are subject to an AMR. 

Application of 10 CFR 54.4 Scoping Criteria to Electrical Component Types 

Scoping was performed as described in LRA Section 2.1. The set of passive, long-lived component 

types derived from the process described in LRA Section 2.1.4.1, steps 1 through 3, was then 

evaluated against the scoping criteria stated in step 4. This step was performed to further define 

the set of electrical component types that are subject to an AMR. The set of electrical component 

types remaining after completion of steps 1 through 4 of the screening process are included in the 

list in LRA Table 2.1-1 as component types that are subject to an AMR. 

2.1.3 Staff Evaluation 

The staff reviewed the methodology used by the applicant to identify SSCs at Plant Hatch that meet 

the scoping criteria of 10 CFR 54.4, and to identify SCs that meet the screening criteria of 10 CFR 

54.21 (a)(1) and (2). The staff used Standard Review Plan for License Renewal (SRP-LR), Section 

2.1, "Scoping and Screening Methodology," to perform the scoping and screening review. 

2.1.3.1 Evaluation of the Methodology for Identifying Systems, Structures, and Components That 

are Within the Scope of License Renewal 

The staff evaluated the applicant's scoping methodology, as described in the LRA, to determine 

whether the methodology met the requirements of 10 CFR 54.4. As part of the evaluation process, 

the staff conducted an audit from June 12 through June 15, 2000, to determine whether the 

scoping methodology described by the applicant in its LRA was implemented consistent with the 

requirements of 10 CFR Part 54 and the Plant Hatch LRA. The audit took place at the SNC offices 

in Birmingham, Alabama. The audit consisted of a review of the scoping methodology 

implementing procedures and supporting information used by the applicant to identify the Plant

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Hatch SSCs within the scope of the license renewal rule. The audit also examined a selected 

sample of products or results obtained by the applicant through its use of the scoping and 

screening methodology procedures. 

The staff followed guidance provided in Section 2.1.3.1 of the SRP-LR to evaluate the scoping methodology described in Section 2.1.2.1 of this SER. The staff reviewed the applicant's process used to identify and classify SSCs as safety-related and non-safety-related, and to identify and 

classify SSCs that meet the definition of "regulated events" (i.e., those SSCs that are relied on in 

safety analyses or plant evaluations to perform functions that demonstrate compliance with the 

requirements of the 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) regulations). Section 2.1.2.4 of the LRA described the 

applicant's process to identify safety-related SSCs that are within the scope of the Rule. Section 

2.1.2.5 of the LRA described the applicant's process to identify non-safety-related SSCs within the 

scope of the Rule. Section 2.1.2.6 or the LRA described the applicant's process to identify those 

SSCs that meet the requirements of the regulations associated with regulated events. In Section 

2.1.2.6 of the LRA, the applicant noted that 10 CFR 50.61 does not apply to Plant Hatch because, 

as specified in the regulation, an evaluation in accordance with Regulatory Guide 1.154, is not 

required for BWRs. The staff agrees with this determination. 

On the basis of its review of the scoping methodology described in the LRA and summarized in 

Section 2.1.2.1 of this SER, the staff concludes that the methodology, as described in the LRA, is 

consistent with the requirements of the Rule, and that the scoping methodology will identify SSCs 

that meet the scoping criteria of 10 CFR 54.4. A summary of the scoping portion of the audit is 

described below. 

During the audit at the SNC offices, the staff reviewed a variety of scoping methodology implementation procedures, including License Renewal Service Procedure (LRS) 1-1, "Revisions 

and Distribution of the License Renewal Services Procedures Manual," LRS 1-2, "Scoping Procedure," LRS 1-3, "Plant Hatch Scoping Template," LRS 1-4, "Boundary Procedure," and LRS 

1-9, "LRS Database Control Procedure." The team also held discussions with SNC technical 

personnel, examined licensing basis documents, and reviewed samples of system functional 

boundary description packages to better understand the scoping and screening process. 

Plant Hatch License Renewal Scopinq and Screening Procedures Review Results 

The applicant employed implementation procedures LRS 1-2 and LRS 1-3 to perform the scoping 

process. LRS 1-3 provided overall license renewal scoping evaluation guidance. The applicant began its process for identifying SSCs that are within the scope of the Rule by relying on 131 

systems and 256 functions that were previously identified in the Plant Hatch maintenance rule 

scoping manual. Additional functions were also identified through a review of the CLB, which 

includes the Plant Hatch UFSARs, operating license/technical specifications, docketed 

correspondence, SEDs, and maintenance rule scoping database, and through a review of NRC 

safety evaluations reports to identify additional functions associated with regulated events as 

defined in 10 CFR 54.4(a)(3). 

In the subsequent phase of the review, the applicant evaluated all Plant Hatch systems and 

structures on a function-by-function basis against specific license renewal criteria, including (a) safety-related - reactor coolant pressure boundary (§54.4(a)(1)(i)); (b) safety-related - safe

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shutdown (§54.4(a)(1)(ii)); (c) safety-related - prevent or mitigate the consequences of accidents 

§54.4(a)(1 )(iii)); (d) non-safety-related [functions] that affect safety-related functions (§54.4(a)(2)); 

and (e) relied on to demonstrate compliance with 10 CFR 50.48 (fire protection), 10 CFR 50.49 

(environmental qualification), 10 CFR 50.62 (anticipated transient without scram), or 10 CFR 50.63 

(station blackout). Following completion of this evaluation, 137 systems and 280 functions were 

identified and catalogued. 

The applicant used LRS 1-4 to define the evaluation boundaries for electrical, mechanical, and civil 

system and structure functions that are determined to be within the scope of the Rule. This 

procedure provided the guidance necessary to generate system boundary diagrams including 

interfaces between mechanical and electrical boundaries. Boundary description packages (BDPs) 

were developed containing written descriptions of the evaluation boundary illustrated by the 

boundary diagrams and identified all in-scope functions included in the evaluation boundary. 

Review and sign-off authority for BDPs was also identified. 

The applicant used LRS 1-9 in conjunction with TS 1-9, "Quality Assurance Records," to govern 

the documentation and quality assurance of the records of the scoping and screening process. 

Based on its review of these procedures and from discussions held with SNC personnel, the audit 

team identified certain discrepancies between the scoping and screening process described in the 

procedures and the actual process that was followed. Specifically, the procedures did not provide 

a clear description and account for all essential activities in the scoping and screening process, nor 

did they clearly portray the sequence in which these activities were actually accomplished. 

To gain a better understanding of the actual scoping and screening methodology used by the 

applicant, the staff selected three Plant Hatch systems (standby liquid control, high-pressure 

coolant injection, and service water) and performed a "walk-through" of the process described in 

the methodology procedures. SNC personnel assisted the audit team as it performed the walk

through. 

Based on the results of the walk-through, and the staff's assessment of the actual implementation 

process and its oversight as applied by the applicant, the audit team determined that the 

procedures reviewed, in combination with the review of a sample of scoping and screening 

products, and with the benefit of insights provided by SNC personnel who were directly involved 

with the development of such products, provided adequate evidence that the scoping and 

screening process was conducted in accordance with the requirements of 10 CFR 54.4 and 10 

CFR 54.21. However, the team also concluded that the applicant needed to update these 

procedures to satisfy the requirements of 10 CFR 54.37, "Additional Records and Recordkeeping 

Requirements," to reflect the actual scoping and screening process upon which the applicant relied 

and will rely to address future changes in the CLB. 

Therefore, the applicant was requested to confirm, through a July 14, 2000, request for additional 

information (RAI 2.1-1), that the Plant Hatch license renewal scoping and screening procedures 

would be updated to clearly reflect the actual process used for both the current application as well 

as future updates to the application based on changes to the CLB, and to specify the time-frame 

during which this update would be accomplished. 

In its response to the staff's RAI, dated August 29, 2000, the applicant stated its commitment to 

expand the existing procedures from a goal-oriented approach to a more detailed presentation of

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the steps employed so that the scoping and screening processes were more clearly identified in 

the procedure steps. The applicant stated that these revised procedures would be used for the 

LRA update required by 10 CFR 54.21 (b), and they would be in place prior to performing the first 

required LRA update. Accordingly, the applicant planned to have the revised procedures in place 

by September 11, 2000. 

During the scoping and screening inspection conducted on September 11 through 15, 2000, the 

inspectors reviewed the revised procedures, and confirmed that they had been revised to 

adequately reflect the scoping and screening methodology. The staff concluded that the 

applicantfs scoping and screening implementation procedures met the recordkeeping requirements 

of 10 CFR 54.37. On this basis, the issue identified in RAI 2.1-1 is resolved. 

Review of 10 CFR 50.12 Plant Hatch Exemptions 

The audit team reviewed the history of 10 CFR 50.12 exemptions at Plant Hatch to identify any 

potential SSCs that are within the scope of license renewal, but were not identified by the 

applicant's scoping methodology. The staff reviewed 32 exemptions and their associated 

correspondence. Of these, the staff noted that 1 exemption was not granted by the staff, 8 were 

no longer in effect, 22 were not age-related or time-limiting, and the remaining exemption was in 

effect, age-related, time-limiting, and the affected system had been included within the scope of 

license renewal. 

Review of Design-Basis Events 

Because the Plant Hatch scoping activities were primarily performed on the basis of intended 

function, rather than on design-basis events, the audit team reviewed the design-basis events 

identified in a study documented in a recent amendment to the Plant Hatch Unit 2 UFSAR. Plant 

Hatch Unit 2 UFSAR, Supplement 15C, "Nuclear Safety Operational Analysis" (NSOA), is a 

comprehensive summary of all design basis events, including anticipated operational occurrences, 

applicable to both Plant Hatch units and represents the culmination of an extensive design-basis 

review effort at Plant Hatch. However, the Plant Hatch license renewal scoping and screening 

process was completed before efforts associated with Supplement 15C to the Plant Hatch Unit 2 

UFSAR were finalized. 

Accordingly, the applicant wasrequested to provide information on actions it intended to undertake 

to ensure that the information relied on to generate the scoping and screening results in 

accordance with the methodology described in the Plant Hatch LRA is consistent with, and 

supported by, the design- and licensing-basis information in Supplement 15C to the Plant Hatch 

Unit 2 UFSAR. This was identified as RAI 2.1-2. 

In its response to the staff's RAI, dated August 29, 2000, the applicant stated that it had informally 

reviewed the draft NSOA during preparation of the LRA. Although the document was not used as 

an "official" source of information due to its draft status, the applicant clarified that since the 

document has been incorporated into the CLB by virtue of its inclusion in the Plant Hatch Unit 2 

UFSAR, Supplement 15C, the applicant would evaluate the NSOA using the scoping criteria of 10 

CFR 54.4 to determine whether additional SSCs should be brought in scope based on the NSOA 

event sequences. The results of this evaluation will be documented internally, and any additions 

to the Plant Hatch LRA will be provided to the NRC in the scheduled annual update.

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In its annual update of the Plant Hatch LRA, dated December 15, 2000, the applicant described 

the methodology used to complete the NSOA review to ensure that the information relied on to 

generate the scoping and screening results was consistent with the information in the NSOA. 

According to the applicant, the NSOA identifies the active system-level requirements that ensure 

that the Plant Hatch safety analysis is valid for all limiting operational conditions. However, while 

the Plant Hatch safety analysis is essentially consequences-oriented, the NSOA is event/system

oriented. 

The methodology used in completing the NSOA review focused on the consideration of each of the 

NSOA events and the system functions required to accomplish the required action (e.g., reactor 

shutdown, core cooling, etc.). In performing this review, each event diagram and corresponding 

evaluation was compared to the LRA and supporting documentation to determine if, in each case, 

the required action is achieved by system functions within the scope of license renewal. In 

addition, UFSAR Supplement 15C supporting documentation was also reviewed to ensure that the 

information was addressed by the LRA. The support systems/functions for each function (e.g., DC 

and auxiliary AC power for core spray) were also evaluated by the applicant. 

As a result of this review, Plant Hatch Function C51-02 - Rod Block Monitor, previously identified 

in the LRA as not within the scope of license renewal has been brought in scope. No new 

component types were added to the list of plant-wide electrical components that are subject to an 

AMR as a result of this scoping change. 

Based on the information provided by the applicant in its Plant Hatch LRA annual update, the staff 

has determined that the actions taken by the applicant provide reasonable assurance that the 

information relied on to generate the scoping and screening results in accordance with the 

methodology described in the Plant Hatch LRA is consistent with, and supported by, the design and licensing-basis information in Supplement 15C to the Plant Hatch Unit 2 UFSAR. On this 

basis, therefore, the concern identified in RAI 2.1-2 is resolved. 

Review of Commission Orders 

The staff reviewed 28 Commission Orders from 1974 through 1998. All of the SSCs referred to 

in each of the 28 Commission Orders were identified and compared to the list of SSCs included 

within the scope of license renewal. All SSCs identified in the 28 Commission Orders were 

included within the scope of license renewal. 

Non-Safety-Related Piping Systems (Seismic II-over-I) 

Section 54.29 of 10 CFR Part 54 (the Rule) states that a renewed license may be issued by the 

Commission if the Commission finds that actions have been or will be taken with respect to the 

matters identified in paragraphs (a)(1) and (a)(2) of this section such that there is reasonable 

assurance that the activities authorized by the renewed license will continue to be conducted in 

accordance with the CLB, and that any changes made to the CLB in order to comply with this 

paragraph are in accord with the Act and the Commission's regulations. These matters include 

managing the effects of aging during the period of extended operation to assure the functionality 

of structures and components that have been identified to require review under Section 54.21 (a)(1). 

The Statements of Consideration (SOC) for the Rule states that the objective of a license renewal 

review is to determine whether the detrimental effects of aging, which could adversely affect the

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functionality of systems, structures, and components (SSCs) that the Commission determines 

require review for the period of extended operation, are adequately managed. 

The SOC articulates the underlying philosophy of the Rule 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. Aging effects that could adversely impact on the ability 

of SSCs to maintain these safety-related functions during the extended period of operation should 

be evaluated. 

Section 54.4(a)(2) of the Rule states that all non-safety-related systems, structures, and 

components whose failure could prevent satisfactory accomplishment of any of the functions 

identified in Section 54.4(a)(1) should be included within the scope of the Rule. The SOC provides 

additional guidance related to this scoping criterion. Specifically, the SOC states that "To limit this 

possibility for the scoping category relating to nonsafety-related systems, structures, and 

components... An applicant for license renewal should rely on the plant's CLB, actual plant-specific 

experience, industry-wide operating experience, as appropriate, and existing engineering 

evaluations to determine those nonsafety-related systems, structures, and components that are 

the initial focus of the license renewal review. Consideration of hypothetical failures that could 

result from system interdependencies that are not part of the CLB and that have not been 

previously experienced is not required." (Federal Register, Volume 60, No. 88, 22467). 

An applicant for license renewal should consider two configurations of non-safety-related piping 

systems that could potentially meet the 54.4(a)(2) scoping criterion. The first configuration includes 

non-safety- related piping systems (including piping segments and supports) which are connected 

to safety-related piping. These non-safety-related piping systems should be included within the 

scope of license renewal up to and including the first seismic support past the safety-related/non

safety-related interface. The second configuration involves non-safety-related piping systems 

which are not connected to safety-related piping, but have a spatial relationship such that their 

failure could adversely impact on the performance of an intended safety function. For this type of 

piping system, the applicant has two options when performing its scoping evaluation: a mitigative 

option or a preventive option. With the mitigative option, the applicant must demonstrate that plant 

mitigative features (e.g., pipe whip restraints, jet impingement shields, spray and drip shields, 

seismic supports, flood barriers, etc.) are provided which protect safety-related SSCs from failures 

of non-safety-related piping segments. When evaluating the failure modes of non-safety-related 

piping segments and the associated consequences, age-related degradation must be considered. 

The staff notes that pipe failure evaluations typically do not consider age-related degradation when 

determining pipe failure locations. Rather, pipe failure locations are normally postulated based on 

high stress. Industry operating experience has shown that age-related pipe failures can, and do, 

occur at locations other than the high-stress locations postulated in most pipe failure analyses. 

Therefore, to utilize the mitigative option, an applicant should demonstrate that the mitigating 

devices are adequate to protect safety-related SSCs from failures of non-safety-related piping 

segments at any location where age-related degradation is plausible. If this level of protection can 

be demonstrated, then only the mitigative features need to be included within the scope of license 

renewal, and the piping segments need not be included within the scope. However, if an applicant 

cannot demonstrate that the mitigative features are adequate to protect safety-related SSCs from 

the consequences of non-safety-related pipe failures, then the applicant should utilize the 

preventive option, which requires that the entire non-safety-related piping system be brought into 

the scope of license renewal and an AMR be performed on the components within the piping 

system. Finally, an applicant may determine that in order to ensure adequate protection of the

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safety-related SSC, a combination of mitigative features and non-safety-related SSCs must be 

brought within scope. Again, it is incumbent upon the applicant to provide adequate justification 

for the approach taken with respect to scoping of non-safety-related SSCs in accordance with the 

Rule. 

A subset of non-safety-related piping systems that meet the 54.4(a)(2) criterion is seismic II over 

I (seismic II/I) piping. Seismic Ill I denotes non-seismic Category I SSCs interacting with seismic 

Category I SSCs as described in Position C.2 of Regulatory Guide 1.29, "Seismic Design 

Classification." The SOC specifically includes seismic Il/I as a subset of the 54.4(a)(2) scoping 

requirement. In addition, Section 2.1.111.B of the Standard Review Plan for License Renewal 

(September, 1997) states that 'The reviewer verifies that the so-called 'seismic II over I' systems, 

structures, and components consistent with the plant's CLB are identified by the applicant's 

proposed screening methodology." 

By letter dated July 28, 2000, the staff issued two requests for additional information related to 

seismic Il/I SSCs. RAI 3.4-11 asked the applicant to clarify whether the scope of the auxiliary 

systems discussed in Section 3.2.4 of the LRA includes any spatially-related components and 

piping segments within the category of seismic Il/I, and how the aging management programs 

discussed in Table 3.2.4 of the application also apply to seismic Il/I piping components. RAI 3.6-51 

stated that it was not clear to the staff whether the scope of the primary containment system 

discussed in Table 3.3.1-3 of the LRA includes spatially-related components and piping systems 

within the category of seismic Il/I, and asked the applicant to clarify the scope and whether the 

same aging management programs discussed in LRA Table 3.3.1-3 also applied to seismic Il/I 

piping components. 

By letter dated October 10, 2000, the applicant responded to these RAIs. In response to RAI 3.4

11 the applicant stated that intended function L35-01, "Pipe Supports," captures all safety-related 

and non-safety-related supports for components in configurations that could potentially result in 

loss of function for seismic Category I components based on spatial relationships. The applicant 

further stated that the key to managing both seismic Category I and non-seismic Category I 

systems so that no impact on safety-related functions occurs, is to assure that aging effects for the 

supports encompassed by L35-01 are appropriately managed, and that, based on empirical 

evidence related to piping and pipe supports under seismic loadings, managing the aging effects 

associated with the pipe supports for systems not otherwise in scope is adequate to assure no loss 

of safety-related functions. On this basis, the applicant concluded that no AMPs are applied to 

piping segments that are not in scope, but are supported by seismic Il/I piping supports. 

In response to RAI 3.6-51, the applicant stated that LRA Table 3.3.1-3 addresses components 

supporting the primary containment integrity function, including safety-related and non-safety

related components inside containment, but the piping supports are included in LRA Table 3.3.1-1, 

"Piping Specialties." 

During subsequent discussions with the staff, the applicant clarified that for the protection of safety

related SSCs, seismic Il/I piping segments are seismically supported. These seismic supports are 

within the scope of license renewal. The applicant further clarified that design features (e.g., jet 

impingement shielding and pipe whip restraints) credited for mitigating the consequences of 

seismic Il/I piping failures are also included within the scope of license renewal. However, the 

applicant also stated that it does not consider the seismically-supported seismic Il/I piping 

segments to be within the scope of license renewal and no aging management programs are

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applied to those seismic II/I piping segments. The applicant believes that since the seismic Il/I 

piping is seismically supported, consideration of its failure is hypothetical. 

The staff did not agree with the applicant's scoping criteria for non-safety-related piping systems. 

The staff's concern is that seismic i1/I piping, though seismically supported, would be subjected to 

the same plausible aging effects as safety-related piping. For example, depending on piping 

material, geometrical configuration, operating conditions such as water chemistry, temperature, 

flow velocity, and external environment, erosion and corrosion may be plausible aging effects for 

some seismic Il/I piping. Those effects, if not properly managed, could result in age-related failures 

and adversely impact the safety functions of safety-related SSCs. 

The staff reviewed the UFSAR and found that the information described in the UFSAR is not 

adequate to support the applicant's assertions that design features would protect safety-related 

SSCs from the impact associated with the potential aging-related failures of seismic Il/I piping such 

that seismic Il/I piping need not be included within the scope of license renewal. As a result, the 

staff requested that the applicant provide additional information to address the staff's concern. This 

was identified as Open Item 2.1.3.1-1. 

By e-mail dated 6/19/01, the applicant provided the requested information. On the basis of the 

information provided in the e-mail, the staff found that the Plant Hatch CLB pipe break/crack 

analyses mainly postulated pipe failures at specific locations (e.g., at terminal ends and high stress 

points). Further, the mitigative features (e.g., jet impingement shielding and pipe whip restraints), 

which the applicant wanted to credit as the basis for excluding seismic Il/I piping from scope, 

assume pipe failures in locations based on the CLB pipe break/crack analyses. As described 

above, the primary concern for license renewal is aging-related failures. Since aging-related 

degradation of piping depends on piping material, geometrical configuration, water chemistry, 

temperature, flow velocity, and external environment, the resulting pipe failure mechanism and 

failure location may be different from those postulated in the Plant Hatch CLB pipe break/crack 

analyses, which were based on stress criteria. Therefore, the staff concluded that the applicant 

had not demonstrated that safety-related SSCs at Plant Hatch are adequately protected from the 

consequences of seismic Il/I pipe failures due to potential aging-related degradation. Thus, the 

staff's position was that seismic Il/I piping systems, including piping segments and their supports, 

should be included within the scope of license renewal. For these seismic Il/I piping systems, the 

applicant should perform an aging management review to determine if there are any plausible 

aging effects, and identify appropriate aging management programs. 

By letter dated September 5, 2001, the applicant brought all seismic Il/I piping systems into the 

scope of license renewal, provided the results of the associated AMRs, and provided a summary 

of the programs and activities that will be used to manage aging in these piping systems. The 

staff's review of the applicant's aging management of components in these piping systems is 

provided in Section 3.1 of this SER. On the basis of the additional information provided by the 

applicant, the staff concludes that the applicant has provided sufficient information to demonstrate 

that all SSCs that meet the 54.4(a)(2) scoping criterion, have been identified as being within the 

scope of license renewal. Open Item 2.1.3.1-1 is closed. 

Impact of Rule Amendments 

In Section 2.1.2.4 of the LRA, the applicant states that 10 CFR 54.4(a)(1)(i), (ii), and (iii), provide 

the scoping criteria for determining the functions of safety-related systems and structures that are

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within the scope of the Rule. The applicant adds that each system and structure function in the plant listing of scoping results (Table 2.2-1 of the LRA) was determined with respect to these 

requirements by addressing the following questions: 

1. Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the integrity of the reactor coolant 

pressure boundary? 

2. Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the capability to shut down the 

reactor and maintain it in a safe shutdown condition? 

3. Is the function of the system or structure identified as safety-related because it is relied 

upon during and following design-basis events to ensure the capability to prevent or 

mitigate the consequences of accidents that could result in potential offsite exposure comparable to the guidelines in 10 CFR 100.11? 

The staff notes, however, that the current language in 10 CFR 54.4 states, in part, that plant SSCs 

within the scope of license renewal are (1) safety-related SSCs which are those relied upon to remain functional during and following design-basis events (as defined in 10 CFR 50.49(b)(1)) to 

maintain the following functions: 

integrity of the reactor coolant pressure boundary 

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

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 this chapter, as applicable 

By letter dated January 5, 2001, the staff requested that the applicant confirm that the information 

in the LRA met the revised requirements in 10 CFR Part 54. 

By letter dated January 31, 2001, the applicant confirmed that the LRA met the revised 

requirements of 10 CFR Part 54. Specifically, the applicant stated that the provisions of 10 CFR 

50.34(a)(1) do not impact the Plant Hatch LRA, and that the applicant has not incorporated the alternate source term provisions of 10 CFR 50.67(b)(2) into the Plant Hatch design or licensing basis. Thus, there is no effect on Plant Hatch license renewal scoping. 

The staff reviewed the provisions of 10 CFR 50.34(a)(1) and 10 CFR 100.11 and concluded that the provisions of 10 CFR 100.11 are bounding with respect to the Plant Hatch LRA. In addition, the provisions of 10 CFR 50.67(b)(2) are not applicable to the Plant Hatch CLB. Therefore, the 

staff concludes that the Plant Hatch LRA meets the revised requirements of 

10 CFR Part 54.

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2.1.3.2 Evaluation of the Methodology for Identifying Structures and Components Subject 

to an Aging Management Review 

The staff evaluated the applicant's screening methodology, as described in the LRA, to determine 

whether the methodology met the requirements of 10 CFR 54.21 (a)(1). The staff followed guidance 

provided in Section 2.1.3.2 of the SRP-LR to evaluate the screening methodology provided in 

Sections 2.1.3 and 2.1.4 of the LRA, and described in Section 2.1.2.2 of this SER. The staff 

reviewed the applicant's process used to identify and classify SCs as passive (those that perform 

their intended functions without moving parts or a change in configuration or properties) and long lived (those that are not subject to periodic replacement based on qualified life or specified time 

period). Section 2.1.3 of the LRA describes the applicant's process to identify civil/mechanical SCs 

that are subject to an AMR. Section 2.1.4 of the LRA describes the applicant's process to identify 

electrical components that are subject to an AMR. 

As part of the evaluation process, the staff conducted an audit from June 12 through June 15, 

2000, to determine whether the screening methodology described by the applicant in its LRA was 

implemented consistent with the requirements of 10 CFR Part 54 and the Plant Hatch LRA. The 

audit took place at the SNC offices in Birmingham, Alabama. 

On the basis of its review of the screening methodology described in the LRA and summarized in 

Section 2.1.2.2 above, the staff concludes that the methodology, as described in the LRA, is 

consistent with the requirements of the Rule, and that the screening methodology will identify SCs 

that meet the screening criteria of 10 CFR 54.21 (a)(1). The screening portion of the audit is 

described below. 

During the June 2000 audit, the staff reviewed a variety of screening methodology implementation 

procedures, including LRS 1-5, "CiviVMechanical Structure/Component Screening Procedure" and 

LRS 1-8, "Electrical IPA Procedure." The applicant used LRS 1-5 to identify the civil/structural, 

mechanical, long-lived, passive structures, components, and commodities determined to be within 

scope and subject to an AMR. 

LRS 1-8 was used by the applicant to screen electrical components and commodities to determine 

if they met the criteria of 10 CFR 54.21(a)(i) and (ii) regarding whether an intended function is 

performed without moving parts or change in configuration or properties and without being replaced 

based on a qualified life or specified time period. Those components and commodities that meet 

this criterion are subject to an AMR. The applicant used the "spaces approach" described in 

Sandia National Laboratory's document SAND 96-0344, "Aging Management Guideline for 

Commercial Nuclear Power Plants - Electrical Cables and Terminations." Starting with a list of 

structures in the scope of license renewal, they compiled a list of physical in-plant areas which 

contain in-scope electrical equipment. The areas were further divided using the Fire Hazards 

Analysis drawings. For these areas, the environmental parameters were determined (e.g. normal 

temperature, normal radiation dose rate, normal humidity, and "hot spots"). The applicant 

performed an extensive in-plant temperature monitoring program to gather measured temperature 

data. For the list of electrical commodities subject to an aging management review, the applicant 

then determined the 60-year life based on temperature and radiation dose. These limits were 

derived from data from the environmental qualification program, manufacturer's published data, 

and other industry information based on materials of construction. The resultant AMRs were 

documented in accordance with LRS 1-6, "Aging Management Review Procedure."

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As discussed in Section 2.1.3.1 of this SER, the staff concluded that the screening results reviewed 

by the audit team provided adequate evidence that the scoping and screening process was 

conducted in accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21. However, the 

staff identified certain discrepancies between the screening process described in the procedures 

and the actual process that was followed. This issue was the subject of RAI 2.1-1, described 

above. 

2.1.4 Conclusion 

On the basis of the staff's review of the information presented in Section 2.1 of the LRA, the 

supporting information in the Plant Hatch UFSAR, the information provided during the scoping and 

screening audit and inspection, the applicant's responses to the staff's RAIs, as discussed above, 

and the applicant's response to Open Item 2.1.3.1 -1, the staff concludes that there is reasonable 

assurance that the scoping and screening methodology used by the applicant to identify SSCs 

within the scope of the Rule, and SCs that are subject to an AMR, is consistent with the 

requirements of 10 CFR 54.4 and 10 CFR 54.21. 

2.2 Plant Level Scoping Results 

2.2.1 Introduction 

In Section 2.2, "Scoping Results," of the LRA, the applicant provides the results of its scoping 

review. The staff reviewed this section of the LRA to determine whether there is reasonable 

assurance that the applicant has properly identified all plant level systems and structures that are 

within the scope of license renewal as required by 10 CFR 54.4. 

2.2.2 Summary of Technical Information in the Application 

Table 2.2-1 of the LRA presents the results of the applicant's plant-wide scoping of systems, 

structures, and intended functions. The table indicates whether or not the intended functions of a 

given system or structure are within the scope of license renewal. The applicant states on page 

2.2-1 of the LRA that: 

"Each function is identified as either in scope or not in scope. Due to the cross-system 

nature of functions, each function has been assigned to a primary system or structure. 

However, in many cases the functional boundaries extend into other systems or structures 

as well. As was described in the scoping/screening methodology, Section 2.1, screening 

of structures/components was performed within functional boundaries. Structures or other 

features not bearing a system number were assigned to a system or structure and scoped 

with that system or structure." 

This statement means that the results of the applicant's scoping methodology, presented in Table 

2.2-1 of the LRA, do not show all intended functions for every system listed. In some cases, 

intended functions that cross system boundaries are listed under one primary system only. To 

simplify the staff's review, the applicant provided two comprehensive matrices in an e-mail dated 

May 24, 2000. Amended versions of these matrices were forwarded in an e-mail dated June 16, 

2000. The first matrix provides a correlation of plant systems to their associated intended functions. 

The second matrix provides a correlation of intended functions to the plant systems that perform

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each intended function. These matrices are intended to provide a comprehensive correlation 

between systems and structures and their intended functions. 

2.2.3 Staff Evaluation 

The staff reviewed Section 2.2 of the LRA to determine if there is reasonable assurance that the 

applicant has appropriately identified and listed systems and structures that are within the scope 

of license renewal, pursuant to the Rule. The staff focused its review on verifying that the 

implementation of the applicant's methodology discussed in Section 2.1 of this SER did not result 

in the omission of systems and structures from the scope of license renewal. Omission of in scope 

systems and components would lead to inadequate identification of structures and components 

subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). The staff reviewed 

selected systems and structures that the applicant identified as not in the scope of license renewal 

to verify that they do not have any intended functions which would require them to be in scope. 

The staff used the UFSARs for both units in performing its review. Pursuant to 10 CFR 50.34(b), 

the UFSAR contains 

"[a] description and analysis of the structures, systems, and components of the facility, with 

emphasis upon performance requirements, the bases, with technical justification therefor, 

upon which such requirements have been established, and the evaluations required to 

show that safety functions will be accomplished." 

The UFSAR is required to be updated periodically pursuant to 10 CFR 50.71 (e). Thus, the UFSAR 

contains updated plant-specific licensing-basis information regarding the SSCs and their functions. 

The staff sampled the contents of the UFSAR by referring to the listing of systems and structures 

in Table 2.2-1 of the LRA and the system-to-function matrices provided by the applicant to identify 

systems or structures that may have intended functions, meeting the criteria of 10 CFR 54.4, that 

the applicant did not include within the scope of license renewal. The staff selected several systems 

and structures, such as systems that support reactor coolant system integrity and systems that 

support primary containment cooling. In a letter to the applicant dated July 14, 2000, the staff 

requested additional information about the scoping results provided in 

Table 2.2-1 of the LRA. 

During the course of this review, the staff identified a concern with regard to the information 

provided in Table 2.2-1 of the LRA. As noted in Section 2.2.2 of this SER, LRA Table 2.2-1 

identifies system functions as being in scope or out of scope. In many cases, when multiple 

systems had the same function, the applicant grouped these individual system functions under one 

functional category. When this was done, Table 2.2-1 did not indicate that such a re-categorization 

had been made. As a result, several systems that would have been within the scope of license 

renewal based on their normal system function, were identified in Table 2.2-1 as not being within 

scope, and a function that would place these systems in scope is not listed under the system. 

On July 14, 2000, the staff sent the applicant several RAIs related to this section. RAI-2.2-SR-1 

requested that the applicant provide an updated LRA Table 2.2-1 because the staff had identified 

several systems which were clearly within the scope of license renewal, but were not shown in the 

table as being in scope. Not all of the functions of these systems were listed, and some of the 

omitted functions placed the system within the scope of license renewal. As noted above, the

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applicant stated that many SSCs were grouped with other systems by similarity of intended 

functions; however, the table provided no information on where in the LRA these SSCs are 

addressed. In its August 29, 2000, RAI response, the applicant stated that the system/function matrices provided in the e-mails on May 24, 2000 and June 16, 2000, provided the requested information. Specifically, the applicant stated, "These matrices provide the capability to efficiently identify the functions that are in scope for any given system and conversely, the systems associated with any given in-scope function." On the basis of the information provided in the 

matrices, the staff performed its review to determine whether all intended functions had been 

identified by the applicant. During the review, the staff identified several additional items that 

required clarification. 

RAI 2.2-SR-2 requested the applicant to clarify the intended function for the primary containment 

chilled water system (Unit 2 only) listed in Table 2.2-1 of the LRA because it was different from the 

function described in Section 2.3.4.10 of the LRA. Table 2.2-1 cited drywell cooling as the intended 

function of this system, putting it in scope for license renewal. However, Section 2.3.4.10 stated 

that containment integrity was an additional intended function. The applicant stated in the August 29, 2000, RAI response that the correct function was containment integrity. However, the staff 

identified another inconsistency in reviewing the RAI response. The system-to-function matrix 

submitted by the applicant listed two intended functions (drywell cooling and containment integrity). By letter dated January 5, 2001, the staff requested the applicant to resolve the discrepancies between the intended function identified in LRA 2.2-1 (drywell cooling only), the intended function 

identified in the response to RAI 2.2-SR-2 (containment integrity only), and the intended functions 

identified in LRA Section 2.3.4.10 and the matrices submitted by e-mails on May 24 and June 16, 2000 (drywell cooling and containment integrity). By letter dated January 31, 2001, the applicant responded that it has revised the description of intended function P64-02 in Section 2.3.4.10 of the 

LRA to clearly indicate that the intended function is primary containment integrity that is provided by the pressure boundary of the drywell cooling subsystem inside containment. A footnote was 

added to clarify that the "drywell cooling" label is being retained for consistency with the Plant Hatch 

Maintenance Rule function labels. A similar note was added to Table 2.2-1 of the LRA to show that 

the label is being retained but the only intended function is primary containment integrity. The letter 

goes on to state that the system-to-function matrix identifies functions that are in-scope and not 

in-scope whose boundaries include a part of the system, and cites the primary containment chilled 

water as an example. The evaluation boundaries for functions 2C61-01 (primary containment 

isolation & integrity) and 2P64-02 (drywell cooling) each include one or more primary containment 

chilled water components. Thus, the system-to-function matrix includes both functions. 

The applicant's letter included revisions to Table 2.2-1 of the LRA and Section 2.3.4.10 of the LRA 

showing the clarifications 

On the basis of the information provided by the applicant in its letter dated January 31, 2001, and 

the accompanying revisions to the table and system description, the staff finds that the applicant has clarified that containment integrity is the only intended function of the primary containment 

chilled water system. 

RAI 2.2-SR-4 requested that the applicant provide the basis for excluding the drywell cooling system (Unit 2 only) from the scope of license renewal. Section 9.4.6.2.1 of the Unit 2 UFSAR 

states that the drywell cooling system is relied upon to maintain the drywell temperature below 165 

'F during a loss of offsite power.

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In the August 29, 2000, RAI response, the applicant stated that the drywell cooling system is not 

a safety system and is not relied upon to mitigate a loss-of-coolant accident combined with a loss 

of offsite power. The applicant further stated that this system is not relied upon to control drywell 

temperature during a station blackout. The staff agrees with these statements; however, 10 CFR 

54.4 requires that non-safety systems whose failure could prevent the satisfactory capability to shut 

down the reactor or maintain it in a safe shutdown condition also be included in the scope of license 

renewal. The staff's concern relates to environmental qualification of equipment or sensors in the 

drywell. It appears from the UFSAR that this system may be required to maintain temperature 

conditions in the drywell during a loss of offsite power so that the applicant can maintain the 

capability to safely shut down the reactor or maintain it in a safe shutdown condition. The UFSAR 

does not provide any information on the basis for the 165 OF requirement. In a letter dated January 

5, 2001, the staff requested that the applicant provide the basis for the 165 OF requirement. 

By letter dated January 31, 2001, the applicant stated that the neutron monitoring cables are the 

components at issue. These cables are in the drywell and are not included in the environmental 

qualification program. Therefore, these cables do not have qualified lives. However, any event 

which could call into question the operability of the cables would be investigated under the 

corrective actions program. A temperature spike such as that postulated in the scenario in which 

a scram occurs simultaneously with a loss of drywell cooling would be the event which would result 

in a condition report being written, with a corrective action to investigate the condition and 

operability of the cables. These cables are included in the scope of the insulated cable and 

connections AMP. This AMP is evaluated in Section 3.1.30 of this SER. 

On the basis of the information provided in the applicant's letter dated January 31,2001, the staff 

concludes that the drywell cooling system does not perform an intended function and therefore is 

not in scope. 

2.2.4 Conclusions 

On the basis of the staff's review of the information presented in Section 2.2 of the LRA, the 

supporting information in the Plant Hatch UFSAR, the applicant's responses to the staff RAIs, and 

the information provided in the letter dated January 31, 2001, the staff concludes that there is 

reasonable assurance that the applicant has identified all systems and structures whose intended 

functions meet the scoping requirements of 10 CFR 54.4. 

2.3 Scoping and Screening Results: Mechanical 

2.3.1 Introduction 

In Sections 2.3.2, "Reactor Coolant System," 2.3.3, "Engineered Safety Features," 2.3.4, 

"Auxiliary," and 2.3.5, "Steam and Power Conversion Systems," of the Plant Hatch LRA, the 

applicant describes the systems and components that are within the scope of license renewal and 

subject to an AMR. The staff reviewed these sections of the LRA to determine whether there is 

reasonable assurance that all SSCs within the scope of license renewal have been identified, as 

required by 10 CFR 54.4(a), and that all components subject to an AMR have been identified, as 

required by 10 CFR Part 54.21 (a)(1).

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2.3.2 Reactor Coolant System (RCS)

In Section 2.3.1, "Reactor," and Section 2.3.2, "Reactor Coolant Systems," of the Plant Hatch LRA, 

the applicant describes the components of the RCS that are within the scope of license renewal 

and subject to an AMR. The staff reviewed these sections of the LRA to determine whether there 

is reasonable assurance that all SSCs within the scope of license renewal have been identified, as 

required by 10 CFR Part 54.4(a), and whether all components subject to an AMR have been 

identified, as required by 10 CFR Part 54.21(a)(1). 

The staff reviewed parts of the Plant Hatch UFSARs and the associated pressure boundary 

components and the structures and compared the information in the UFSAR with the information 

in the LRA to identify those structures and components that the LRA did not identify as being within 

the scope of license renewal and subject to an AMR. The staff then reviewed structures and 

components that were identified as not being within the scope of license renewal. The staff 

requested that the applicant provide additional information and/or clarifications on certain structures 

and components to verify: 

that these structures and components do not have any of the intended functions delineated 

under 10 CFR 54.4(a), and 

for structures and components that have an applicable intended function, either perform the 

function with moving parts or changes in configurations or properties, or are replaced based 

on a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1). 

The staff also reviewed the UFSAR to identify any function listed under 10 CFR 54.4(a) that was 

not identified as an intended function in the LRA, to verify that the function will be maintained for 

the period of extended operation. 

After completing the initial review, the staff issued requests for additional information (RAIs) 

regarding the RCS by letter dated July 14, 2000. The applicant responded to the RAIs by letter 

dated August 29, 2000. 

2.3.2.1 Fuel 

Summary of Technical Information in the Application 

Nuclear fuel is fissionable material that can be arranged in a critical array. This high-integrity 

assembly must be capable of efficiently transferring fission heat to the circulating coolant water 

while maintaining structural integrity and keeping the fission products contained. The external 

environment of the fuel is cladding surrounded by water. The fuel cladding experiences the 

complete range of reactor coolant pressure and temperatures. 

System Intended Functions 

Energy Source: The high-integrity assembly of fissionable material efficiently transfers 

fission heat to the circulating reactor coolant water while maintaining its structural integrity 

and keeping the fission products contained. The nuclear fuel assembly is the initial barrier 

to release of fission products. The fuel assembly is designed to ensure that fuel damage

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does not result in the release of radioactive materials in excess of the guideline values of 

10 CFR Parts 20, 50, and 100. 

Spent Fuel Fission Product Barrier: This prevents the release of fission products in the 

spent fuel. The Zircaloy-2 cladding that covers the spent fuel mitigates the consequences of a fuel handling accident. The cladding ensures that fuel damage does not result in the 

release of radioactive materials in excess of the guideline values of 10 CFR Parts 20, 50, 

and 100. 

No component groups requiring an AMR are identified in the LRA. 

Staff Evaluation 

On the basis of the information provided in the LRA and the supporting information in the Plant 

Hatch UFSAR regarding the intended functions and relevant aging effects associated with the fuel, 

the staff concludes that the fuel does not include any passive and long-lived components with aging 

effects which require aging management. 

2.3.2.2 Nuclear Boiler System 

Summary of Technical Information in the Application 

The nuclear boiler system generates steam. The functions of the nuclear boiler system are to 

supply feedwater to the reactor, conduct steam from the reactor, and protect against reactor 

overpressure. The system also has some reactor control and/or engineered safety feature 

functions. The nuclear boiler system is in operation any time the plant is in operation. Most of the 

major components in the system are part of the reactor coolant pressure boundary. The system contains the following major components: 

0 main steam lines (MSLs) 

0 safety relief valves (SRVs) * main steam isolation valves (MSIVs) * feedwater lines 

* feedwater line check valves 

0 instrumentation and controls 

System Intended Functions 

Pressure Control: The pressure control function of the nuclear boiler system prevents 

overpressurization of the nuclear system. It also provides automatic depressurization for 

small breaks to allow for low-pressure coolant injection (LPCI) and core spray (CS) 

operation. This function is called the automatic depressurization system (ADS). The low

low set (LLS) function mitigates the thrust loads on the SRV discharge lines and the high frequency loads on the torus shell from subsequent SRV actuations during small- and 

intermediate-break loss-of-coolant accidents (LOCAs). The LLS also allows the SRV 

discharge line water leg more time to return to the original level after an actuation. 

Reactor Coolant Pressure Boundary Integrity: The nuclear boiler system is designed to 

maintain the reactor coolant pressure boundary integrity. This is also the function of the

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pressure-containing Class 1 piping and components which form a portion of the reactor 

coolant pressure boundary, with the exception of the pressure control and reactor 

recirculation functions. 

Rod Worth Minimizer: The rod worth minimizer provides a means of enforcing procedural 

restrictions on preprogrammed control rod manipulations to limit rod worth to the values 

assumed in the plant accident analysis (design basis rod drop accident). 

Nuclear Boiler Instrumentation: Nuclear boiler instrumentation provides process information 

to the operator and signals to other systems in the nuclear power plant. 

Component Intended Functions 

* Pressure boundary 

* Fission product barrier 

* Flow Restriction 

The component groups requiring an AMR, identified in the LRA are as follows: bolting, crack growth 

monitor (Class 1), flow restrictor, piping (Class 1 and non-Class 1), restricting orifice (Class 1), 

thermowell (Class 1 and non-Class 1), and valve bodies (Class 1 and non-Class 1). 

Staff Evaluation 

In RAI 2.3.2-NBS-1, the staff asked the applicant to clarify why the safety relief valve (SRV) 

discharge lines and their supports have not been identified in Table 2.3.1-2 of the LRA as 

component groups requiring an AMR. The staff believes that these structures and components 

perform the passive function of withstanding significant loads, such as SRV discharges, and that 

their failure can defeat the SRVs' intended safety function. The applicant verified that the SRV 

discharge lines and supports have been identified in the application as components subject to an 

AMR, and clarified that the SRV discharge lines are scoped as part of the pressure control function 

(B21-01). The components are shown on boundary diagrams HL-1 6062 and HL-26000. Table 

2.3.1-2 identifies the SRV discharge lines as piping. The applicant further clarified that the pipe 

supports for the SRV discharge lines are scoped as part of the pipe support function (L35-01) and 

identified in Section 2.4.1 of the LRA, "Piping Specialties." LRA Table 2.4.1-1 lists the pipe 

supports for the SRV discharge lines as hangers and supports for non-ASME Class 1 piping, 

tubing, and ducts. 

On the basis of the applicant's response to this RAI, the staff concludes that the applicant has 

clarified that the SRV discharge lines and its supports are identified as requiring an AMR. 

In RAI 2.3.2-NBS-2, the staff stated that only two intended functions were identified for flow

restricting orifices (Table 2.3.1-2 of the LRA): pressure boundary and fission product barrier. 

However, some orifices are relied upon to limit mass flow rate during postulated breaks, and loss 

of material can degrade this function. The staff asked the applicant to show why limiting mass flow 

rate during postulated breaks is not an intended function of some orifices, per 10 CFR 

54.4(a)(1 )(iii), or provide an AMR for the orifices that have an intended function to limit mass flow 

rate. In response, the applicant acknowledged that some of the orifices are in fact relied upon to 

limit mass flow rate during postulated breaks, and that the component function, namely, "flow 

restriction", was inadvertently omitted from restricting orifice line items in Tables 2.3.1-2 and 3.2.1-2

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of the LRA. The staff notes that the applicant has modified the tables accordingly, as described I 

below. In addition, the flow restriction elements (venturi) of 1/2B21-NO05A-D shown on boundary 

drawings HL-16062 and HL-26000 are credited for restricting the main steam flow and for limiting the mass flow rate during postulated breaks. Thus they perform an intended function and are 

subject to an AMR. The applicant submitted its revised AMPs as part of this RAI response, as 

described below. The revised AMPs address the flow restriction as a component function, so that I 

this function will be maintained for the extended period of operation. The adequacy of the AMPs 

to manage and maintain the flow restriction function is discussed in Sections 3.1.1 and 3.1.12 of 

this SER for the reactor water chemistry control and component cyclic transient limit programs, 

respectively. 

As discussed above, the applicant identified two components that were inadvertently omitted from I 

the scope of license renewal. The main steam flow restrictor - Pipe (Class 1) and the main steam I 

flow restrictor - Venturi were added to LRA Table 2.3.1-2 and the associated aging management I 

information was added to LRA Table 3.2.1-2. The Class 1 main steam flow restrictor pipe performs I 

both pressure boundary and fission product barrier functions and is made of carbon steel. It is I 

located in a reactor water environment and can experience loss of material and cracking aging I 

effects. The applicant credits the following aging management programs with managing the aging I 

effects: reactor water chemistry control program, inservice inspection program, galvanic I 

susceptibility inspections, component cyclic or transient limit program, flow accelerated corrosion I 

program and treated water system piping inspection program. The venturi performs a flow I 

restriction function and is made of cast austenitic stainless steel. It is also located in a reactor I 

water environment and can experience loss of material and cracking aging effects. The applicant I 

credits the reactor water chemistry control and component cyclic or transient limit programs with I 

managing the aging effects. 

The staff asked the applicant to clarify "main steam flow restrictor -pipe" in the tables. In response, I 

the applicant states that this is merely the name of the section of piping that includes the venturi, 

and that the pipe does not have a flow restriction function. The flow restriction function only applies 

to the venturi. 

On the basis of the applicant's response to this RAI, the staff concludes that the applicant has 

identified orifices that provide an in-scope function to limit mass flow rate during postulated breaks. 

2.3.2.3 Reactor Assembly System 

Summary of Technical Information in the Application 

As described in the LRA, the reactor vessel has three major purposes: 

* contain core, internals, and moderator. 

* serve as a high-integrity barrier against leakage. 

• provide a floodable volume. 

The reactor assembly consists of the reactor pressure vessel (RPV) and its internal components, the core, shroud, steam separator and dryer assemblies, jet pumps, control rods, control rod drive 

(CRD) housings, and the CRD. The RPV is a vertical, cylindrical pressure vessel with 

hemispherical heads of welded construction. The major reactor internal components are the core 

(fuel, channels, control blades, and instrumentation), the core support structure (including the core

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shroud, shroud head, separators, top guide, and core support), the steam dryer assembly, and the 

jet pumps. The reactor internal structural elements are made of stainless steel or other corrosion

resistant alloys. 

The reactor vessel is inside the primary containment building. The internal environment of the RPV 

is reactor water, normally at 533 OF and 1055 psia during plant operation. Water quality is 

maintained within the specified limits. During plant conditions that require the operation of the 

shutdown cooling mode of the residual heat removal (RHR) system, reactor water can be cooled 

to approximately 117 OF via the RHR heat exchangers and recirculated back to the reactor through 

the reactor recirculating system (RRS) piping. During plant shutdown conditions, the water 

temperature in the RPV can be as low as 70 °F. 

System Intended Functions 

* The reactor vessel internals distribute coolant to allow power operation without fuel damage 

and positions and supports the fuel assemblies so that control rod movement is not 

impaired. The RPV, including the control rods and drives, is evaluated as part of the 

nuclear boiler system pressure boundary. 

0 The CRD housing supports mitigate damage to the fuel barrier in the event a drive housing 

breaks or separates from the bottom of the reactor. 

Component Intended Functions 

* pressure boundary 

* fission product barrier 

* structural support 

* flow distribution 

The component groups requiring an AMR identified in the LRA are as follows: access hole covers, 

appurtenances, attachments and connecting welds, closure studs, control rod drive, core 

AP/standby liquid control (SLC) line, core spray internal piping, core spray sparger, core support 

plate, CRD housing and control rod guide tubes, dry tube weld to guide tube, fuel supports, jet 

pump assemblies, nozzles, penetrations, safe ends, shell and closure heads, shroud, shroud 

supports, shroud tie rods, thermal sleeves, and top guide. 

Staff Evaluation 

In RAI 2.3.2-RA-1, the staff asked the applicant to identify the reactor vessel leakage monitoring 

piping as part of the pressure boundary and, accordingly, to include it in the scope of license 

renewal and to perform an AMR. If, however, the applicant believed that the component does not 

require an AMR, the applicant should provide a plant-specific justification as to why the component 

need not be subject to an AMR. In response, the applicant clarified that the RPV leakage

monitoring piping is in scope. In a June 26, 2000 telephone conference, the applicant clarified that 

the reactor vessel leakage monitoring piping is identified on Table 2.3.1-2 of the LRA as non-Class 

1, stainless steel piping. In an e-mail on November 9, 2000, the applicant provided the following 

additional information on this piping.

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The Unit 2 piping is shown on drawing HL-26000, grids C/D 3/4. Valve F062 has one inch ASME 

Section 3 Class 1 piping and valve-to-pressure switch N002 has 3/8-inch Class 2 tubing. As shown 

on the drawing, these components are within the evaluation boundary for the reactor coolant 

pressure boundary integrity function (B21-02). Tables 2.3.1-2 and 3.2.1-2 of the LRA list 

components that support nuclear boiler system intended functions. Thus, the components are 

listed in two tables. The material is stainless steel and the environment is reactor water. Thus, on 

Table 3.2.1-2, non-Class 1, reactor water, and stainless steel piping associated with this function 

are entered on the last line on page 3.2-5 of the LRA and Class 1, reactor water, and stainless 

steel piping associated with this function are entered on the next to last line on page 3.2-6 of the 

LRA. These line items provide the applicable links for the commodity evaluations and aging 

management programs. 

The Unit 1 piping is shown on drawing HL-16062, grid C/D 3/4. Both 1-inch stainless steel piping 

and 3/8-inch stainless steel tubing fabricated to ANSI B31.1 requirements, upgraded, are shown 

to support the reactor coolant pressure boundary integrity function (B21-02). Thus, this piping is 

listed with the non-Class 1 piping noted above. 

On the basis of the applicant's response to this RAI, the staff concludes that the reactor vessel 

leakage-monitoring piping was identified in the LRA as being within scope and subject to an AMR. 

In its review of the applicant's submittal, the staff noticed a footnote in Table 2.3.1-1 of the LRA: 

"No aging effects requiring management." This footnote applies to the following component 

groups: access hole covers, core AP/SLC line, core support plate, fuel supports, and shroud tie 

rods. In RAI 2.3.2-RA-2, the staff asked the applicant to provide a basis for the conclusion that no 

aging effects require management for the above-mentioned component groups. In its response, the applicant stated that the conclusion that there are "no aging effects requiring management" was 

based on review of the function, materials, and environment of each component, as discussed in 

the AMR for the components. Furthermore, the applicant stated that the component-specific 

criteria of the Boiling Water Reactor Vessel Internals Program (BWRVIP) were applied where 

applicable. 

On the basis of the applicant's response to this RAI, the staff concludes that the applicant has 

provided a basis for the conclusion that the component groups referenced above experience no 

aging effects requiring management. 

In RAI 2.3.2-RA-3, the staff asked the applicant to explain why the intended function of the reactor 

vessel internals to provide gamma and neutron shielding was not identified on page 2.3-2 or in 

Table 2.3.1-1 of the LRA. The component specifically designed to perform this function, namely the thermal shield with its supporting structures, was also not identified as within scope and subject 

to an AMR. The staff believes that the radiation shielding function of the RPV internals should be 

identified in the LRA and an AMR should be done for those components that perform this passive function. In response, the applicant stated that the BWR internals are not relied upon to provide 

gamma or neutron shielding. This function is accomplished by the water. Further, the design does 

not employ a thermal shield. Therefore, there is no need to identify such components in the LRA. 

On the basis of the applicant's response to this RAI, the staff concludes that the applicant has 

provided an adequate explanation of why the function of the reactor vessel internals to provide 

gamma and neutron shielding was not identified on page 2.3-2 of the LRA or in Table 2.3.1-1 of 

the LRA.

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The low-pressure coolant injection (LPCI) coupling was identified in BWRVIP-06, "Safety 

Assessment of BWR Reactor Internals," as a safety-related component. In RAI 2.3.2-RA-4, the 

staff asked the applicant to identify the AMR for the LPCI coupling in the LRA or justify the 

exclusion of this component from aging management review. The applicant responded that the 

use of an LPCI coupling is limited to three BWR/4 plants and BWR/5 and BWR/6 plants and that 

neither Plant Hatch unit has an LPCI coupling. Therefore, it was not mentioned in the LRA. 

On the basis of the applicant's response to this RAI, the staff concludes that the applicant has 

provided an adequate justification for the exclusion of this component from aging management 

review. 

In addition to the RAIs discussed above, the staff held several telephone conference calls with the 

applicant to clarify the applicant's positions on several issues. In the call on June 26, 2000, the 

staff asked for justification for the decision to exclude the following vessel internals from the scope 

of license renewal: steam dryer, core shroud head and separators, feedwater spargers, and 

surveillance capsule holder. The applicant stated that consistent with BWRVIP-06, these 

components are not safety-related. The applicant also stated that failure of these non-safety

related components would not adversely affect the ability of the safety-related components to 

perform their functions, and that this is consistent with industry comments to the NRC related to 

Generic Aging Lessons Learned (GALL). 

On the basis of the applicant's responses during this call, the staff concludes that the applicant has 

provided an adequate justification for excluding the vessel internals discussed above from the 

scope of license renewal. 

In the call made on June 26, 2000, the staff expressed concern that blockage of the spray holes 

of the core spray spargers through aging could keep the core spray system from performing its 

intended function of spraying the fuel bundles following a LOCA, and thus may fail to provide 

adequate core cooling for the short- and long-term following the LOCA. The applicant replied that, 

because the core spray piping is made of stainless steel, corrosion is not a credible aging 

mechanism to cause flow blockage. The applicant further stated that BWRVIP-18, "Core Spray 

Internals Inspection and Flaw Evaluation Guidelines," provides a means to inspect the core spray 

piping. The staff believes that adequate long-term core cooling can only be assured by maintaining 

the original core spray distribution that was assumed for the CLB. The staff, therefore, will rely on 

the BWRVIP inspection program to provide reasonable assurance that the original spray 

distribution will be maintained during the period of extended operation. 

On the basis of the applicant's responses during this call, the staff concludes that the applicant has 

provided an adequate justification for concluding that blockage of the spray holes through aging 

of the core spray piping is not a credible aging mechanism. The applicant has also confirmed that 

adequate core spray distribution is not an assumption or requirement in the LOCA analysis for 

Plant Hatch. 

2.3.2.4 Reactor Recirculation System 

Summary of Technical Information in the Application 

The reactor recirculation system is one of two core reactivity control systems. The RRS system 

is part of the reactor coolant pressure boundary. Therefore, it also functions to maintain the

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pressure boundary during normal operation, transients, and accident scenarios to prevent the 

release of radioactive liquid and gas. 

The RRS consists of two parallel loops, each with a recirculation pump, suction and discharge block valves, piping, fittings, flow elements and connections, and differential pressure instrumentation. The RRS interfaces with the residual heat removal and reactor water cleanup 

(RWCU) systems to provide a flow path for shutdown cooling, low-pressure coolant injection 

(LPCI), RWCU, and reactor water level control functions. 

System Intended Functions: 

Recirculating Pump Trip Breaker Trip: The recirculating pump trip (RPT) breakers are 

designed to trip the reactor recirculation pumps on appropriate signals-high reactor vessel 

steam dome pressure signal, or an indication of an ATWS (anticipated transient without 

scram)-RPT reactor water level. The RPT breakers trip to prevent the core from exceeding 

thermal limits during abnormal transients. The system is designed to help the reactor 

protection system (RPS) protect the integrity of the fuel barrier. This function meets the 

safe shutdown criteria because the RPS is necessary to allow the control rods or the 

standby liquid control system to safely and effectively shutdown the reactor. 

Reactor Coolant Pressure Boundary: The RRS ensures adequate core cooling during 

power operation by supplying coolant flow past the reactor fuel bundles. The system 

consists of two loops external to the RPV. The piping, pumps, and valves that form these 

loops make up part of the reactor coolant pressure boundary. 

Component Intended Functions 

* fission product barrier 

• pressure boundary 

The component groups requiring an AMR identified in the LRA are as follows: bolting (Class 1), flow nozzle (Class 1), piping (Class 1), pump casings and cover (Class 1), thermowell (Class 1), 

and valve bodies (Class 1). 

Staff Evaluation 

The staff has reviewed the information in the LRA, supplemented by information in the UFSAR, and 

concludes that the applicant has properly identified system and component intended functions 

associated with the RRS, and has properly identified those components within the RRS system 

which are within the scope of license renewal and which are subject to an AMR. 

2.3.2.5 Conclusions 

The staff has reviewed the information in Sections 2.3.1, "Reactor," and 2.3.2, "Reactor Coolant 

System," of the LRA. In its review, the staff identified an omission by the applicant. Specifically, the applicant had not evaluated orifices for the intended function of limiting mass flow rates during postulated breaks. The applicant subsequently evaluated the orifices and identified those that 

performed an in-scope function and revised the appropriate tables in the LRA. On the basis of this 

review, the staff concludes that the applicant has identified those components within the scope of

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license renewal and that are subject to an AMR, as required by 10 CFR 54.4(a) and 10 CFR 

54.21 (a)(1). 

2.3.3 Engineered Safety Features (ESF) 

The applicant described the systems and components of the engineered safety features (ESF) 

systems that are within the scope of license renewal and are subject to an AMR, in LRA Sections 

2.3.3.1, "Standby Liquid Control System"; 2.3.3.2, "Residual Heat Removal System"; 2.3.3.3, "Core 

Spray System"; 2.3.3.4, "High-Pressure Coolant Injection System"; 2.3.3.5, "Reactor Core Isolation 

Cooling System"; 2.3.3.6, "Standby Gas Treatment System"; 2.3.3.7, "Primary Containment Purge 

and Inerting System"; and 2.3.3.8, "Post-LOCA Hydrogen Recombiner System (Unit 2 Only)." The 

staff reviewed these sections of the LRA to determine whether there is reasonable assurance that 

the applicant has identified all components that are within the scope of license renewal, as required 

by 10 CFR 54.4(a), and all components that are subject to an AMR, as required by 10 CFR 

54.21 (a)(1). 

The staff reviewed Section 2.3.3 of the LRA to determine whether there is reasonable assurance 

that the applicant has adequately identified the ESF components and supporting structures that 

are within the scope of license renewal, and subject to AMR in accordance with the requirements 

of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). 

As part of its evaluation, the staff reviewed portions of the UFSAR for the ESF and associated 

pressure boundary components, and compared the information in the UFSAR with the information 

in the LRA to identify those portions that the LRA did not identify as being within the scope of 

license renewal and subject to an AMR. The staff then reviewed structures and components (SCs) 

that were identified as not being within the scope of license renewal. The staff requested that the 

applicant provide additional information and/or clarifications for a selected number of these 

structures and components to verify the following characteristics: 

These structures and components do not have any of the intended functions delineated 

under 10 CFR 54.4(a) 

For those structures and components that have any applicable intended function(s), verify 

that they either perform the specified function(s) with moving parts or a change in 

configuration or properties, or that they are subject to replacement on the basis of a 

qualified life or specified time period, as described in 10 CFR 54.21 (a)(1). 

The staff also reviewed the UFSAR for any function(s) that are delineated under 10 CFR 54.4(a), 

but were not identified as intended function(s) in the LRA, to verify that the SSCs with such 

function(s) will be adequately managed so that the function(s) will be maintained throughout the 

extended period of operation. 

After completing the initial review, the staff issued RAIs regarding the ESF systems by letter dated 

July 14, 2000. The applicant responded to the RAIs by letter dated August 29, 2000. 

In RAI 2.3.3-ESF-1, the staff indicated that in Section 2.3.3 of the LRA, tanks (including the vertical 

tanks erected in the field) are considered mechanical components. However, the tank foundation 

and anchorage systems are considered structural components. Tanks can have foundations that 

are made of concrete or steel. The staff requested that the applicant clarify whether the concrete

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foundations or pads of the tanks needed for the ESF systems are included within the scope of 

license renewal, and whether they are subject to an AMR. In response, the applicant verified that 

tank foundations and anchorages supporting ESF systems are in scope and subject to an AMR. 

The applicant clarified that tank foundations are evaluated as structures (either as part of a building 

or as a yard structure). Each table that includes a tank foundation (building or yard structure) also 

identifies anchors and bolts associated with the tank anchorage system. On the basis of the 

applicant's response to this RAI, the staff concludes that the applicant has identified the ESF tank 

foundations as being within the scope of license renewal and subject to an AMR. Section 2.4 of 

the LRA identifies structural components that are subject to an AMR. The staff's evaluation of the 

scoping and screening results of structural components is found in Section 2.4 of this SER. 

In RAI 2.3.3-ESF-2, the staff requested that the applicant verify whether the passive components 

(namely screens and vortex breakers) that are used in pump suction lines, for the intended function 

of protecting the pumps from debris and cavitation, respectively, and that could be located either 

inside the ESF tanks or in the sump, are subject to an AMR. If so, the staff requested that the 

applicant identify which tanks and sumps are equipped with these passive components and the 

location of the AMRs in the LRA for these components. If not, the staff requested that the applicant 

provide justification for excluding these components from an AMR. In its response, the applicant 

stated that "screens" used within ESF tanks would be considered long-lived, passive components 

subject to an AMR. The applicant further stated that at Plant Hatch, the only "screens" utilized 

within ESF tanks to protect ESF system pump suctions from debris are pump suction strainers 

located within the torus. These strainers protect the pump suctions for the following systems: 

Residual Heat Removal (RHR), Core Spray (CS), High-Pressure Coolant Injection (HPCI), and 

Reactor Core Isolation Cooling (RCIC). These strainers are included in Sections 2.3.3.2, 2.3.3.3, 

2.3.3.4, and 2.3.3.5 of the LRA. The applicant acknowledged that vortex-breaking devices would 

also be considered long-lived, passive components subject to an AMR. However, neither unit at 

Plant Hatch utilizes vortex breakers within the torus, the condensate storage tank, or the Standby 

Liquid Control (SLC) storage tank. On the basis of the applicant's response to this RAI, the staff 

concludes that applicant has identified screens as being within the scope of license renewal and 

subject to an AMR, and that vortex breakers are not used in ESF tanks. 

2.3.3.1 Core Spray System 

Summary of Technical Information in the Application 

The CS system is one of the emergency core cooling systems (ECCSs) that protect the core from 

overheating in the event of a loss-of-coolant accident (LOCA). The CS system is a low-pressure 

system that is actuated in response to low reactor vessel water level (level 1), high drywell 

pressure, or manual action. Injection valves to the reactor require a signal from the reactor low

pressure permissive switches before opening to provide overpressure protection to the system. 

The pumps take suction from the suppression pool and spray on the tops of the fuel assemblies 

to cool the core and limit the fuel cladding temperature. An alternative suction source for the CS 

system, the condensate storage tank (CST), is primarily is used to provide reactor pressure vessel 

(RPV) makeup and an injection test supply during outages, and would not normally be used 

following an accident. The CS system works in conjunction with low-pressure coolant injection 

(LPCI). 

The CS system has two independent loops. Each loop includes a 1 00-percent capacity centrifugal 

pump driven by an electric motor, a sparger ring in the reactor vessel above the core, piping,

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valves, and associated controls and instrumentation. To enable the CS system to make a quick 

startup and to minimize the water hammer possibilities during startup, the CS system discharge 

lines are always maintained full of water by the jockey pump system. The jockey pump system 

consists of two centrifugal pumps in each of the two loops. The suction and discharge lines of 

these pumps are connected through piping and valves to the suction and discharge lines of the CS 

pumps, respectively. Continuous operation of the jockey pumps ensures that the ECCS discharge 

lines remain full. The jockey pump system also provides the same feature for the RHR system. 

System Intended Functions 

The CS system serves the following intended functions: 

Core Cooling: The CS system protects the core by removing decay heat following a 

postulated design-basis LOCA or other design-basis event. 

Alternate Shutdown Cooling: The CS system provides an alternative means to cool and 

depressurize the reactor vessel following a fire. 

Emergency Core Cooling System Keep Fill: The jockey pumps of the CS system keep the 

CS and LPCI lines full of water, thereby minimizing the delay time for emergency core 

cooling and the possibility of water hammer. This function is brought into scope solely as 

a pressure boundary. 

Component Intended Functions 

The components of the CS system serve the following functions: 

& pressure boundary 

o fission product barrier 

0 flow restriction 

° debris protection 

The component groups requiring an AMR include the bolting, piping, pump casings, restricting 

orifice, strainers, and valve bodies. 

Staff Evaluation 

The staff was concerned that blockage of the spray holes of the core spray spargers could prevent 

the core spray system from performing its intended function by preventing adequate distribution 

of the spray on the fuel bundles. The staff discussed this issue with the applicant in telephone 

conferences on June 26 and June 29, 2000. In the telephone conference held on June 26, 2000, 

the staff expressed concern that blockage of the spray holes of the core spray spargers through 

aging could keep the core spray system from performing its intended function of spraying the fuel 

bundles following a LOCA, and thus may fail to provide adequate core cooling for the short- and 

long-term following the LOCA. The applicant stated that, because the core spray piping is made 

of stainless steel, corrosion is not a credible aging mechanism to cause flow blockage. Also, the 

applicant stated that BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation 

Guidelines," provides a means to inspect the core spray piping. The staff believes that adequate 

long-term core cooling can only be assured by maintaining the original core spray distribution that

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was assumed for the CLB. The staff, therefore, will rely on the BWRVIP inspection program to 

provide reasonable assurance that the original spray distribution will be maintained during the 

period of extended operation. On the basis of the staff's review of the information provided in the 

LRA and in the telephone conferences with the applicant, the staff concludes that the applicant has 

properly identified the components associated with the CS system that are within the scope of 

license renewal, as required by 10 CFR 54.4(a), and has properly identified the components that 

are subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.2 High-Pressure Coolant Iniection 

Summary of Technical Information in the Application 

The high-pressure coolant injection (HPCI) system supplies makeup coolant into the reactor vessel 

from a fully pressurized to a preset depressurized condition. Demineralized makeup water is 

supplied from the CST or treated water from the suppression pool. The flow rate of the system maintains the reactor vessel coolant inventory until the reactor pressure drops sufficiently to permit 

the low-pressure core cooling systems to automatically inject coolant into the vessel. The HPCI 

system consists of a turbine-driven pump train, piping, valves, and controls that provide a complete and independent ECCS. A test line permits functional testing of the system during normal plant operation. A minimum flow bypass line bypasses pump discharge flow to the suppression pool to 

protect the pump in the event of a stoppage in the main discharge line. Reactor vessel steam is 

supplied to the turbine, and turbine exhaust steam is then dumped to the suppression pool. 

System Intended Functions 

The HPCI system serves the intended function of core cooling. In that capacity, the HPCI system 

ensures that the reactor is adequately cooled to limit the fuel-clad temperature in the event of a 

small break in the reactor coolant system and a loss of coolant that does not result in rapid depressurization of the reactor vessel. This function permits shutdown of the plant, while 

maintaining sufficient reactor vessel water inventory until the reactor is depressurized. 

Component Intended Functions 

The components of the HPCI system serve the following functions 

0 pressure boundary 

* fission product barrier 

* structural support 

• flow restriction 

• debris protection 

The component groups requiring an AMR, as identified in the LRA, include the bolting, flexible 

connectors, piping, pump baseplate, pump casings, restricting orifice, suction strainer, thermowell, 

turbine, and valve bodies. 

Staff Evaluation 

On the basis of the staff's review of the information provided in the LRA, and described in Section 

2.3.3.2 of this SER, for the HPCI system, the staff concludes that the applicant has properly

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identified the components associated with the HPCI system that are within the scope of license 

renewal, as required by 10 CFR 54.4(a), and has properly identified the components that are 

subject to an AMR, as required by 10 CFR 54.21 (a)(1). 

2.3.3.3 Post-LOCA Hydrogen Recombiners (Unit 2 Only) 

Summary of Technical Information in the Application 

The post-LOCA hydrogen recombiner system is designed as the combustible gas control system 

to ensure that hydrogen does not accumulate within the primary containment to combustible 

concentrations following a LOCA. In Section 2.3.3.8, "Post LOCA Hydrogen Recombiner System," 

of the LRA, the applicant described the intended functions and listed the components of the system 

that are subject to an AMR. The applicant described its process for identifying the mechanical 

components within the scope of license renewal in Section 2.1.2, "Scoping," and Section 2.1.3, 

"Civil/Mechanical Component Screening," of the LRA. 

In Section 2.3.3.8 of the LRA, the applicant described the intended functions of the hydrogen 

recombiner system. The system ensures that hydrogen does not accumulate within the primary 

containment in combustible concentrations following a LOCA. This is accomplished by drawing 

primary containment atmosphere from the drywell, and passing it through the recombiner where 

the hydrogen reacts with available oxygen to form water vapor. The recombiner discharges to the 

suppression pool (torus). The hydrogen recombiner system is part of the combustible gas control 

system, and consists of two identical and independent 100 percent capacity trains. Each train 

consists of three packages, including the recombiner skid, the control console, and the power 

panel. The recombiner skid consists of inlet piping, flow meters, a flow control valve, an enclosed 

blower assembly, heater section, reaction chamber, direct contact water spray connected to the 

power panel, and the control console through instrument and power cables. Coolant for the water 

spray gas cooler is provided by the residual heat removal (RHR) system. 

The initial scoping, performed by the applicant on the basis of system functions, has determined 

that hydrogen recombiner system has one intended function, T49-01 - Containment Combustible 

Gas Control, that is within the scope of license renewal. In that capacity, the hydrogen recombiner 

system ensures that hydrogen does not accumulate within the primary containment in combustible 

concentrations following a LOCA. This function applies to Unit 2 only. 

The associated piping, valve bodies, and bolting are identified in Table 2.3.3-8 of the LRA as being 

subject to an AMR. The component functions of the piping, valve bodies, and bolting are the 

pressure boundary and fission product barrier. 

Staff Evaluation 

The applicant identified and listed the components that are subject to an AMR for the hydrogen 

recombiner system in Table 2.3.3-8 of the LRA using the screening methodology described in 

Sections 2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in 

Section 2.1 of this SER. 

The staff reviewed Section 6.2.5 of the Plant Hatch Unit 2 UFSAR to determine if there were any 

system functions that were not identified as intended functions in accordance with the requirements 

of 10 CFR 54.4. The staff then reviewed the associated boundary drawing

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HL-26068 to verify that the applicant identified all of the components that are within the scope of 

license renewal in accordance with 10 CFR 54.4. Further, the staff verified the accuracy of the 

drawings and the completeness of Table 2.3.3-8 by sampling the components adjacent to, but 

outside, the highlighted portion of the system to verify that all of the components within the scope 

of license renewal were included in the application. In addition, the staff sampled the components 

that are within the scope of license renewal, but not subject to an AMR, to verify that all of the 

components that meet the requirements of 10 CFR 54.21 (a)(1) were identified as being subject to 

an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAIs in a 

letter dated August 29, 2000. 

In response to RAI 2.3.3-HR-2, the applicant clarified that an unnamed component "BWO0A" in 

Drawing No. HL-26068, identified by multi-plant list (MPL) number 2T49-BO001A, is the heater 

subcomponent of the skid-mounted hydrogen recombiner, 2T49-ZO01A. The heater serves to 

preheat containment gases before combustion in the reaction chamber. The staff finds this 

response acceptable. 

In response to RAI 2.3.3-HR-3, the applicant also confirmed that Plant Hatch Unit 1 does not use 

a hydrogen recombiner for post-LOCA hydrogen controls. Instead, it uses the inerted nitrogen gas 

to prevent explosive concentrations of hydrogen and oxygen. Therefore, the post-LOCA hydrogen 

recombiner system, described in Section 2.3.3.8 of the LRA, applies to Unit 2 only. The staff finds 

this response acceptable. 

In RAI-2.3.3-HR-1 and RAI-2.3.3-HR-4, the staff asked the applicant to justify its exclusion of 

various components (highlighted in HL-26068) from an AMR. Specifically, these components 

included the water separator, water spray cooler, reaction chamber, blower (CO001A), heater ( 

B001 A), and instrument tubing. The applicant responded that these components are a part of skid

mounted hydrogen recombiners, which are active components, and thus not subject to an AMR. 

Therefore, the applicant determined that the components are also not subject to an AMR. 

In a telephone conference on September 13, 2000, the staff expressed its disagreement with the 

applicant's determination to exclude these components from an AMR simply because they are skid

mounted. The staff requested that the applicant provide additional justification for its position. In 

response, the applicant provided a paper, entitled "Active Assemblies Used in License Renewal," 

via an email, dated November 6, 2000. 

The staff has reviewed this paper, and finds that the applicant's basis for excluding hydrogen 

recombiner components, as discussed in the paper, is not consistent with the License Renewal 

Rule. The basis for the staff's conclusion is summarized below and is described in more detail in 

Section 2.3.4.2 of this report discussing the emergency diesel generators. 

Components are subject to an AMR if they perform a passive function and are long-lived. A 

passive function is one performed without moving parts or a change in configuration or properties. 

A function performed with moving parts or a change in configuration or properties is considered an 

active function. Components that perform a passive function and are also long-lived must be 

subject to an AMR, whether they are skid-mounted or not. The staff believes that the water 

separator, water spray cooler, and reaction chamber are long-lived components with a passive

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function, and therefore are subject to an AMR. On this basis, the staff requested that the applicant identify any applicable aging effects associated with these components, and any other long-lived 

components performing a passive function associated with the hydrogen recombiners, and identify AMPs credited with managing the aging effects. This was identified as part of Open Item 2.3.3.2-1 

(2.3.3.2-1 (a)). 

By letter dated June 5, 2001, the applicant responded to this open item by identifying the following 

skid-mounted components that are subject to an AMR and listing these components in Table 2.3.3

8 of the LRA: blower casing, instrument, piping, reaction chamber, water separator, and water 

spray cooler. Further clarification was provided by letter dated September 5, 2001, where the 

applicant clarified that the hydrogen recombiner heater is electric and does not form a part of the 

pressure boundary. Therefore, the heater is an active component and not subject to an AMR. The 

staff reviewed the additional information and finds that the inclusion of these components in Table 

2.3.3-8 of the LRA is acceptable. In addition, the staff agrees that the recombiner heater is not 

subject to an AMR. Open Item 2.3.3.2-1(a) is closed. The staff's review of the applicant's 

management of the aging effects associated with these components can be found in Section 3.3.3 

of this SER. 

On the basis of the staff's review of the LRA and associated drawings, the Plant Hatch Unit 1 and 

2 UFSARs, and the applicant's responses to the RAIs and Open Item 2.3.3.2-1 (a), the staff 

concludes that the applicant has identified the components of the Post-LOCA hydrogen 

recombiners system that are within the scope of license renewal and subject to an AMR. 

2.3.3.4 Primary Containment Purqe and Inerting System 

Summary of Technical Information in the Application 

The primary containment purge and inerting system is designed to supply and maintain an inert 

atmosphere inside primary containment for combustible gas control and fire protection. In addition, 

it is designed to purge and vent the containment atmosphere and provide vacuum relief between 

the torus and drywell, as well as between the torus and reactor building. In Section 2.3.3.7 of the 

LRA, the applicant described the intended functions and the components of the system that are 

subject to an AMR. 

In Section 2.3.3.7 of the LRA, the applicant described the primary function of the containment 

purge and inerting system in inerting the primary containment. Plant Technical Specifications require that within 24 hours of reactor operation, the inerting system injects a sufficient amount of 

gaseous nitrogen into the drywell and torus so that the oxygen concentration falls below 4-percent by volume. Major equipment for the purge and inerting system includes a purge air supply fan, 

liquid nitrogen storage tank, ambient vaporizer, steam vaporizer, vacuum breaker, valves, piping, 

controls, and instrumentation. In addition, the primary containment purge and inerting system provides containment vent paths to the standby gas treatment system, which provides a vent path 

to the main stack for containment vent and purge operations. 

The initial scoping, performed by the applicant on the basis of system functions, has determined 

that the following intended functions of the purge and inerting system are within the scope of 

license renewal.

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T48-01 - Primary Containment Nitrogen Inerting: The purge and inerting system provides and maintains an inerted atmosphere in the primary containment for combustible gas 

control and fire protection purposes. 

T48-03 - Primary Containment Vacuum Relief: The primary containment relief valves are 

designed to maintain an external pressure of not more than 2 psi greater than the 

concurrent internal pressure. This pressure prevents a collapse in either the drywell or 

torus as a result of the most rapid cooldown transient that can occur during operation or a 

postulated accident condition assuming the failure of a single active component. 

T48-04 - Containment/Reactor Building Parameter Monitoring: The containment/reactor 

building parameter monitoring function monitors and records drywell and torus safety 

parameters in the main control room. The parameters monitored include torus air and 

water temperature, water level, and pressure, and drywell pressure and temperature. 

T48-06 - Drywell Pneumatic Nitrogen Supply: The purge and inerting system provides a 

safety-grade backup supply of nitrogen gas for the drywell pneumatic system. The nitrogen 

gas provides motive force to the nuclear boiler system safety relief valves, main steam 

isolation valves, and various other safety-related valves in the event of a loss of normal 

drywell pneumatic supply. 

The associated piping, valve bodies, bolting, flex hose, nitrogen tank jacket, pressure buildup coil, 

rupture disc, storage tank, thermowell, and vaporizer are identified in Table 2.3.3-7 of the LRA as 

being subject to an AMR. The component function of piping, valve bodies, bolting, rupture disc, 

storage tank, and thermowell is to serve as a pressure boundary; the functions of the flex hose are 

to serve as a pressure boundary and fission product barrier; the function of the nitrogen tank jacket is to serve as a structure support; the functions of the pressure buildup coil and vaporizer are to 

serve as a pressure boundary and heat exchanger. 

Staff Evaluation 

The applicant identified and listed the components that are subject to an AMR for the purge and 

inerting system in Table 2.3.3-7 of the LRA using the screening methodology described in Sections 

2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in Section 2.1 of 

this SER. 

The staff reviewed Sections 5.2.3.8 and 5.2.3.9 of the Plant Hatch Unit 1 UFSAR and Section 6.2 

of the Unit 2 UFSAR to determine if any system functions were not identified as intended functions 

in accordance with the requirements of 10 CFR 54.4. The staff then reviewed the evaluation 

boundary drawings (HL-1 6024, HL-1 6000, HL-1 6239, HL-1 6153, HL-1 6286, HL-26084, HL-26079, HL-26083, and HL-26020) to verify that the applicant identified all of the 

components that are within the scope of license renewal in accordance with 10 CFR 54.4. Further, 

the staff verified the accuracy of the drawings and the completeness of LRA Table 2.3.3-7 by sampling the components that are adjacent to, but outside the highlighted portion of the system to 

verify that all of the components within the scope of license renewal were included in the 

application. In addition, the staff sampled the components that are within the scope of license 

renewal, but not subject to an AMR, to verify that all of the components that meet the requirements 

of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR.

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After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAIs in a 

letter dated August 29, 2000. 

!n RAI 2.3.3-P&1-1, the staff requested that the applicant clarify whether the "vaporizer" listed in 

Table 2.3.3.7 of the LRA, represents the ambient vaporizer only, or both the ambient and steam 

vaporizers. In Section 2.3.3.7 of the LRA, both the ambient vaporizer and steam vaporizer are 

identified as major equipment for the system. The applicant responded that the "vaporizer" listed 

in Table 2.3.3.7 of the LRA stands for the ambient vaporizer only. The steam vaporizer does not 

perform an intended function and, therefore, is not within the scope of license renewal. 

In RAI 2.3.3-P&1-3, the staff questioned the basis for excluding instrument tubing from an AMR. 

The applicant responded that, with the exception of copper, the LRA includes instrument tubing 

with piping for like materials. There is no copper instrument tubing in scope for functions 

associated with the primary containment purge and inerting system. On the basis of the 

information provided in the applicant's response to RAI 2.3.3-P&1-3, the RAI is resolved. 

To verify that the applicant identified all of the components that are within the scope of license 

renewal in accordance with 10 CFR 54.4, the staff reviewed the intended functions (primary 

containment nitrogen inerting [T48-01], primary containment vacuum relief [T48-03], 

containment/reactor building parameter monitoring [T48-04], and drywell pneumatic nitrogen supply 

[T48-06]), along with nine evaluation boundary drawings (HL-1 6024, HL-1 6000, HL-1 6239, HL

16153, HL-16286, HL-26084, HL-26079, HL-26083, and HL-26020). Each drawing has a large 

number of components associated with several overlapping functions, and each drawing may have 

several systems. In addition, each intended function may be cross-referenced in several drawings. 

In RAI 2.3.3-P&1-2, the staff requested that the applicant identify all of the drawings and major 

components that are associated with function T48-03, "Primary Containment Vacuum Relief." In 

its response, the applicant referred to drawings HL-1 6024 and HL-26084, but did not identify any 

of the components being used for function T48-03. The applicant stated that the Plant Hatch LRA 

does not present screening results on a function-by-function basis. Rather, all functions that are 

primarily associated with the system are grouped together for screening, and the results of the 

screening are listed in LRA Table 2.3.3-7. Given the available information and the RAI response, 

it was not clear to the staff whether the applicant had properly identified all of the components that 

are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4. 

To resolve the above concern, the staff included the purge and inerting system in its scoping and 

screening inspection, which was performed at the applicant's corporate offices in Birmingham, 

Alabama, during the week of September 11 - 15, 2000. During the inspection, as documented in 

NRC Inspection Report 50-321/00-09, 50-366/00-09, the NRC inspector reviewed additional onsite 

information associated with the system and concluded that the applicant had correctly identified 

the components that are subject to an AMR, as well as components that are not subject to an AMR. 

Given the results of this inspection, the staff agrees with the applicant that all of the components 

that are subject to an AMR are properly identified in Table 2.3.3.7 of the LRA. 

On the basis of the NRC inspection and review of the LRA and associated drawings, the UFSARs 

for Plant Hatch Units 1 and 2, and the applicant's responses to RAIs, the staff was unable to find 

any omissions from the components highlighted in the diagrams that identify the function-level 

scoping boundaries. The staff also compared the components listed in Table 2.3.3-7 of the LRA 

to those highlighted in the drawings, and found them consistent.

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On the basis of the review, the staff has determined that there is reasonable assurance that the 

applicant has adequately identified the intended functions of the primary containment purge and 

inerting system that are within the scope of license renewal in accordance with the requirements 

of 10 CFR 54.4 and the components that are subject to an AMR in accordance with the 

requirements of 10 CFR 54.21 (a)(1). 

2.3.3.5 Reactor Core Isolation Cooling System 

Summary of Technical Information in the Application 

The reactor core isolation cooling (RCIC) system is a high-pressure coolant makeup system that 

supports reactor shutdown when the feedwater system is unavailable. The RCIC system provides 

the capability to maintain the reactor in a hot standby condition for an extended period. Normally, however, the RCIC system is used until the reactor pressure is sufficiently reduced to permit use 

of the shutdown cooling mode of the RHR system. 

The RCIC system consists of a turbine-driven pump, piping and valves, and the instrumentation 

necessary to maintain the water level in the reactor vessel above the top of the active fuel in the 

event that the reactor vessel is isolated from normal feedwater flow. Also included in the design 

of the RCIC system is a barometric condenser and vacuum and condensate pumps to prevent 

steam from leaking into the environment. 

System Intended Functions 

The intended function of the RCIC system is core cooling. In that capacity, the RCIC system provides a high pressure makeup coolant system that supports the reactor shutdown when the 

feedwater system is unavailable. 

Component Intended Functions 

The components of the RCIC system serve the following functions 

Pressure boundary 

Fission product barrier 

Structural support 

Flow restriction 

Debris protection 

The component groups requiring an AMR, as identified in the LRA, include the bolting, flexible 

connector, piping, pump baseplate, pump casing, restricting orifices, steam trap, strainer-steam 

exhaust, suction strainer, thermowell, turbine, and valve bodies. 

Staff Evaluation 

The staff reviewed Section 2.3.3.5 of the LRA to determine whether the applicant has identified the 

components in the RCIC system that are within the scope of license renewal and subject to an 

AMR, as required by 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

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On the basis of the staff's review of the information provided in the LRA, and described for the 

RCIC system in Section 2.3.3.5 of this SER, the staff concludes that the applicant has properly 

identified the components associated with the RCIC system that are within the scope of license 

renewal, as required by 10 CFR 54.4(a), and those that are subject to an AMR, as required by 10 

CFR 54.21 (a)(1). 

2.3.3.6 Residual Heat Removal (RHR) System 

Summary of Technical Information in the Application 

The RHR system is composed of several components and subsystems that are required to perform 

the following functions: 

& Restore and maintain reactor vessel water level after a LOCA. 

0 Limit temperature and pressure inside the containment after a LOCA. 

0 Remove heat from the suppression pool water. 

0 Remove decay and residual heat from the reactor core to achieve and maintain a cold 

shutdown condition. 

The RHR system consists of four pumps and two heat exchangers divided into two loops of two 

pumps and one heat exchanger each, plus the associated instruments, valves, and piping. The 

RHR pumps take suction from the suppression pool or the reactor coolant recirculation loop. The 

pumps discharge into the recirculation loop, the suppression pool, the containment spray headers, 

or the spent-fuel pool cooling and cleanup system, depending upon the desired mode of system 

operation. The RHR system interfaces with the reactor recirculation system to provide a flow-path 

in support of shutdown cooling and LPCI. The RHR system is part of the reactor coolant pressure 

boundary; therefore, it also maintains the pressure boundary during normal operation, transients, 

and accident scenarios to prevent the release of radioactive liquid and gas. The RHR system is 

cooled through the heat exchangers by the residual heat removal service water (RHRSW) system, 

which takes suction from the Altamaha River. There are four RHRSW pumps per unit. The 

RHRSW system also serves as a standby coolant supply system by providing a means of injecting 

makeup water from the river to the RHR system to keep the core covered during an extreme 

emergency. 

System Intended Functions 

The RHR system serves the following intended functions: 

Low Pressure Coolant Injection (LPCI): The LPCI restores and maintains the coolant 

inventory in the reactor vessel so the core is adequately cooled following a design basis 

LOCA and other design basis events. 

Containment Spray: Containment spray provides post-accident containment atmosphere 

temperature and pressure control by use of spray nozzles located in both the drywell and 

the torus area.

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RHRSW Vessel/Containment Injection: RHRSW provides a reliable supply of cooling water 

to the reactor pressure vessel (RPV) following a loss of RHR/core spray or to flood the 

primary containment to provide cooling to the exterior of the reactor vessel using raw river 

water. 

Shutdown Cooling: Shutdown cooling removes decay and residual heat from the reactor 

during shutdown and cooldown when the reactor pressure is so low that the vacuum in the 

condenser cannot be maintained, rendering the condenser orthe HPCl and/or RCIC pumps 

inoperable because of a lack of steam. 

Suppression Pool Cooling: Suppression pool cooling limits the water temperature in the 

suppression pool to ensure that it has adequate heat capacity remaining in the event of a 

design-basis LOCA, and removes heat following an accident and during testing of the HPCI 

and RCIC systems. 

Alternate Shutdown Cooling: Alternate shutdown cooling provides an alternative means to 

cool and depressurize the reactor vessel following a fire or other transient that leads to a 

loss of shutdown cooling. 

Component Intended Functions 

The components of the RHR system serve the following functions: 

• pressure boundary 

* fission product barrier 

* shelter/ protection 

* structural support 

* flow restriction 

* debris protection 

The component groups requiring an AMR include the bolting, conductivity element, heat exchanger channel assembly, heat exchanger impingement plate, heat exchanger shell, heat exchanger tube 

sheet, heat exchanger tubes, piping, pump casings, pump casing bowl assembly, pump discharge head, pump sub base, restricting orifices, strainer bodies, strainers, thermowell, tubing, and valve 

bodies. 

Staff Evaluation 

In RAI 2.3.3-RHR-1, the staff indicated that in Table 2.3.3-2 of the LRA, the intended functions for 

heat removal tubes have been identified as a fission product barrier and pressure boundary. However, the staff believes that heat transfer is also an intended function of this component. The 

staff therefore requested that the applicant explain why this additional function need not be 

identified, and why an AMR is not necessary to ensure satisfactory performance of this function 

throughout the period of extended operation. The applicant responded by stating that although it 

was not listed in Table 2.3.3-2, heat transfer is part of the component function for the RHR heat 

exchanger tubes. The applicant further stated that this function was inadvertently omitted from the 

table; however, the AMR performed for the heat exchanger tubes in Section C.2.2.1 1 of the LRA 

included consideration of this function in the evaluation of aging effects requiring aging 

management.

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On the basis of the staff's review of the information provided in the LRA, described in 

Section 2.3.3.6 of this SER, for the RHR system, as well as the response to the staff's RAI, the 

staff concludes that the applicant has properly identified the components associated with the RHR 

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and those that 

are subject to an AMR, as required by 10 CFR 54.21 (a)(1). 

2.3.3.7 Standby Gas Treatment System 

Summary of Technical Information in the Application 

In Section 2.3.3.6, "Standby Gas Treatment System," of the LRA, the applicant described the 

components of the standby gas treatment system (SGTS) that are within the scope of license 

renewal and subject to an AMR. The staff reviewed this section of the LRA to determine whether 

there is reasonable assurance that the applicant has identified all components that are within the 

scope of license renewal, as required by 10 CFR 54.4(a), and all components that are subject to 

an AMR, as required by 10 CFR 54.21 (a)(1). 

In Section 2.3.3.6 of the LRA, the applicant stated that additional information for the SGTS is 

provided in Sections 5.3.3.3 and 6.2.3 of the UFSAR for Units 1 and 2, respectively. The system 

scoping is shown in SGTS evaluation boundary drawings HL-1 6020, Rev. A, and HL-1 6174, Rev. 

A, for Unit 1, and HL-26078, Rev. A, for Unit 2. 

The SGTS is an ESF system for ventilation and cleanup of the primary and secondary containment 

during certain postulated design-basis accidents (DBAs), and meets the design, quality assurance, 

redundancy, energy source, and instrumentation requirements for ESF systems. The SGTS is also 

used as a normal means of venting the drywell. 

Plant Hatch Unit 1 

The SGTS suction from the reactor building below the refueling floor and torus and drywell area 

is isolated during refueling activities by gagging closed certain valves in the reactor building suction 

lines to achieve modified secondary containment. Following the receipt of the isolation signal, the 

reactor zone and/or refueling zone isolation dampers close, supply and exhaust fans are shut off, 

and the SGTS is initiated. The SGTS system minimizes the release of radioactive material to the 

environment by filtering and exhausting via the main stack. 

The basic SGTS consists of two identical parallel air filtration assemblies (trains) separated by a 

42-inch-thick concrete wall and enclosed within a seismic Class 1 structure. The 18-inch 

underground discharge pipe leading to the main stack is seismic Class 1. Each train is full

capacity, and consists of a demister or moisture separator, electrical heating coil, pre-filter, 

high-efficiency particulate air (HEPA) filter, two charcoal adsorbers, final HEPA filter, and exhaust 

fan. 

The total free volume of the secondary containment system is approximately 2 x 106 ft 3 , and the 

portion of the volume above the refueling floor is 725,000 ft3. On the basis of the free volume of 

the secondary containment system, each SGTS train has the capability for two air volume changes 

per day (assuming no wind). The discharge lines from the Unit 1 trains tie together into an 18-in. 

header for discharge into the main stack. Unlike the Unit 2 SGTS, the Unit 1 SGTS is designed 

with a timer logic such that trains A and B are set to trip at approximately

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6 and 4 minutes, respectively, from initial start on sensing low airflow conditions. The details of the 

SGTS are described in Section 5.3.3.3 of the Unit 1 UFSAR. 

Plant Hatch Unit 2 

The SGTS is fully redundant and capable of performing following a single failure. In the event of 

a loss of offsite power (LOOP), the SGTS fans can be powered from the emergency service 

portions of the auxiliary power distribution system. The fan associated with each filter assembly 

is powered from a different emergency diesel in the event of LOOP. The system includes isolation 

dampers that fail open on loss of power to the solenoids or upon loss of instrument air to the air 

operators on the dampers. An interlock with the associated exhaust fan prevents the heating coil 

from operating when the fan is shut down. The system components and ductwork meet seismic 

Category I requirements. 

In the event of an automatic initiation signal for the SGTS, the normally operating reactor building 

and refueling floor ventilation systems are isolated. Since other boundary penetrations (such as 

access doors or electrical cables) are normally sealed, the only potential fission product release 

path is through the SGTS to the main stack. Further, since no air path other than infiltration exists 

for replacement air, the area within the boundary connected to the SGTS is maintained at a 

negative pressure. 

The SGTS automatically filters the exhaust air from the reactor building and/or the fuel handling 

area following an accident. As an alternative mode of operation, the drywell and/or torus purge 

exhaust are manually directed to the SGTS for processing before release up the main stack. 

The SGTS consists of two identical, redundant, parallel air filtration assemblies, which are 

separated by a 4-ft 6-in.-thick concrete wall and completely enclosed within a seismic Category I 

structure. Each of the filtration assemblies and their respective components are designed for 

100-percent-capacity operation. Each filtration assembly consists of a demister or moisture 

separator to reduce absolute humidity, electric heater for relative humidity control to maintain the 

adsorption efficiency of the carbon bed, pre-filter for removal of larger particulates to protect the 

HEPA filter, a HEPA filter for removal of small particulate matter, a 4-in. deep-bed impregnated

carbon adsorber to remove gaseous elemental iodine and methyl iodide, final HEPA filter for 

removal of postulated particulate matter that could be carried off the carbon adsorber by the air 

stream, and an exhaust fan to move the air. With the reactor building isolated, each of the two 

exhaust fans has the necessary capacity to reduce and hold the reactor building at a minimum 

negative pressure of 0.20-in. water. The details of the SGTS are described in Section 6.2.3 of the 

Unit 2 UFSAR. 

In Section 2.3.3.6 of the LRA, the applicant identified the following intended functions for the SGTS 

that relate to 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3): 

Minimize the release of radioactive materials to the environment during accident conditions 

and to 

Ventilate and clean up the primary and secondary containment during certain postulated 

DBAs.

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On the basis of the functions identified above, the applicant determined that all SGTS 

safety-related components (electrical, mechanical, and instrument) are within the scope of license 

renewal. The applicant described its process for identifying the mechanical components that are 

subject to an AMR in Section 2.1.2 of the LRA. On the basis of this methodology, the applicant identified the portions of the SGTS that are within the scope of license renewal in SGTS evaluation 

boundary drawings HL-1 6020, Rev. A, and HL-1 6174, Rev. A, for Unit 1, and HL-26078, Rev. A, 

for Unit 2. Using the methodology described in Section 2.1 of the LRA, the applicant compiled a 

list of the mechanical components and component types that are within the scope of license 

renewal and subject to an AMR, and identified their functions. The applicant provided this list in 

Table 2.3.3-6 of the LRA. 

The applicant identified the following 11 device types as being within the scope of license renewal 

and subject to an AMR: 

* filter housing (galvanized steel) 

* piping (carbon steel) 

• piping (stainless steel) 

* piping (copper) 

* piping (galvanized steel) 

* rupture disc (stainless steel) 

* thermowell (stainless steel) 

* valve bodies (gray cast iron) 

* valve bodies (carbon steel) 

* valve bodies (stainless steel) 

* valve bodies (copper alloy) 

In Table 2.3.3-6, the applicant further noted that the SGTS fission product barrier and pressure boundary functions are the only applicable functions associated with components of the SGTS that 

are subject to an AMR. 

Staff Evaluation 

The staff reviewed Section 2.3.3.6 of the LRA to determine whether there is reasonable assurance 

that the SGTS components that are within the scope of license renewal and subject to an AMR 

have been identified in accordance with 10 CFR 54.21 (a)(1). The staff reviewed other information 

in the LRA and Sections 5.3.3.3 and 6.2.3 of the UFSAR for Units 1 and 2, respectively. After 

completing the initial review, the staff issued an RAI regarding the SGTS by letter dated July 14, 

2000. The applicant responded to the RAI by letter dated August 29, 2000. 

In LRA Section 2.1, the applicant discussed the process of identifying mechanical components that 

are subject to an AMR. The applicant's scoping methodology is evaluated by the staff in Section 

2.1 of this SER. 

In its review of the SGTS, the staff reviewed the SGTS evaluation boundary drawings HL-1 6020, 

Rev. A, and HL-16174, Rev. A, for Unit 1, and HL-26078, Rev. A, for Unit 2. The drawings show 

the evaluation boundaries for the portions of the SGTS that are within the scope of license renewal. 

The staff also reviewed Table 2.3.3-6 of the LRA which lists those mechanical components that are 

subject to an AMR.

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The staff also reviewed Sections 5.3.3.3 and 6.2.3 of the UFSAR for Units 1 and 2, respectively, 

to determine if there were any portions of the SGTS that met the scoping criteria in 10 CFR 54.4 

that the applicant did not identify as being within the scope of license renewal. The staff also 

reviewed the UFSAR sections to determine if there was any system function that was not identified 

as an intended function in the LRA, and to determine if there were SCs that have an intended 

function that might have been omitted from the scope of SCs requiring an AMR. The staff also 

reviewed the above SGTS evaluation boundary drawings to determine if any SCs that are within 

the evaluation boundaries were omitted from the scope of SCs requiring an AMR under 10 CFR 

54.4(a)(1). The staff also compared the system and intended functions described in the UFSAR 

with those identified in the LRA. The staff then determined whether the applicant had properly 

identified SCs that are subject to AMR from among those identified as being within the scope of 

license renewal. 

The applicant identified and listed the SCs that are subject to AMR for the SGTS in Table 2.3.3-6 

of the LRA, using the screening methodology described in Section 2.1 of the LRA. The staff 

evaluated the scoping and screening methodology, and documented its findings in Section 2.1 of 

this SER. The staff sampled SCs from Table 2.3.3-6 to verify that the applicant identified the SCs 

that are subject to an AMR. The staff also sampled SCs that are within the scope of license 

renewal, but were not identified as being subject to an AMR to verify that these SCs perform their 

intended functions with moving parts or with a change in configuration or properties, or were 

subject to replacement on the basis of a qualified life or specified time period. 

To help ensure that those portions of the SGTS that were not identified as being within the scope 

of license renewal did not perform any intended functions, the staff issued an RAI'on the basis of 

the applicable information in the UFSARs and LRA. The staff noted that Section 2.3.3.6 of the LRA 

presents a summary description of the system functions, evaluation boundary drawings highlight 

the evaluation boundaries of the SGTS, and Table 2.3.3-6 tabulates components that are within 

the scope of license renewal and subject to an AMR. The corresponding drawings for this system 

in the UFSAR, however, show additional components that were not listed in Table 2.3.3-6 of the 

LRA. 

In RAI 2.3.3-SGTS-1 and RAI 2.3.3-SGTS-2, the staff requested specific information concerning 

the exclusion of the following components from the scope of license renewal and/or from an AMR: 

(1) differential pressure indicator and associated piping (Unit 1, Filter Assembly D001 B, HL

16020, SGTS Sh. 1) 

(2) temperature element and associated piping (Unit 1, Filter Assembly D001 B, HL-1 6020, 

SGTS Sh. 1 @G4) 

(3) flow switch (FS N01 1A) and open valves (NO1 1A-RV1, NO0 1A-RV2) and associated piping 

(3/8-inch diameter piping) (Unit 1, HL-16174, SGTS Sh. 2 @ C7) 

(4) filter housing with pre-filter, high-efficiency particulate air (HEPA) and carbon filters (Unit 1, 

Filter Assemblies D001A and D001 B, HL-16020 @ (C2, C3, C4, and C5) and (G2, G3, G4, 

and G5))

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(5) bird screen or wire mesh, if provided as a protective cover for exhaust stack (Unit 1, 

HL-1 6174, SGTS Sh. 2 @ C10) 

(6) guillotine damper housing (Unit 2, Filter Assemblies D001A and D001 B, HL-26078 @ C4 

and G4) 

(7) filter housing with pre-filter, HEPA and carbon filters (Unit 2, Filter Assemblies D001A and 

D001 B, HL-26078 @ (C2, C3, C4, and C5) and (G2, G3, G4, and G5)) 

(8) "buried pipe" (Unit 2, HL-26078 @ G1 0) 

(9) bird screen or wire mesh, if provided as a protective cover for an exhaust stack (Unit 2, HL

26078 @ C1) 

(10) outside air probe tubing (Unit 1, HL-1 6174, SGTS Sh. 2 @ A9, B9, and C9) 

(11) fan housing (Unit 1, HL-16174, SGTS Sh. 2 @ C5 and F5) 

(12) outside air probe tubing (Unit 2, HL-26078 @ A9, B9, and C9) 

(13) fan housing (Unit 2, HL-26078 @ C4 and G4) 

In a letter dated August 29, 2000, the applicant provided the following responses: 

(1) Differential pressure indicators are active components (NEI 95-10 Rev. 0, Appendix B, Item 

76) and, therefore, no AMR is required for the differential pressure indicators shown in HL

16020; associated tubing is made of copper and is screened as piping, and LRA 

Table 2.3.3-6 includes this component. 

(2) Temperature element was screened as thermowell, which is made of stainless steel, and 

Table 2.3.3-6 includes this component; associated tubing is made of copper and is 

screened as piping, and Table 2.3.3-6 includes this component as well. 

(3) Flow switches are active components (NEI 95-10 Rev. 0, Appendix B, Item 84) and, 

therefore, no AMR is required for the flow switches shown in HL-16174; valves and 

associated piping made of carbon steel are included in Table 2.3.3-6. 

(4) Filter housing (Unit 1) on HL-16020 is made of galvanized steel; an AMR was performed 

on the filter housing, and this item is included in Table 2.3.3-6; pre-filter, HEPA filter, and 

carbon filter are in scope; however, these items are consumables and therefore not subject 

to an AMR. (These items were inadvertently omitted from boundary drawing HL-16020). 

(5) Bird screen (Unit 1) is included in the exhaust stack as miscellaneous steel (see 

Table 2.4.11-1). 

(6) Dampers are active components (NEI 95-10, Rev.0, Appendix B, Item 155) and, therefore, 

no AMR is required for the guillotine damper housing.

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(7) Filter housing (Unit 2) on HL-26078 is made of galvanized steel; an AMR was performed 

on the filter housing, and this item is included in Table 2.3.3-6; prefilter, HEPA filter, and 

carbon filter are in scope; however, these items are consumables and therefore not subject 

to an AMR. (These items were inadvertently omitted from the boundary HL-26078). 

(8) Buried piping is made of carbon steel, and is included in Table 2.3.3-6. 

(9) Bird screen (Unit 2) is included in the exhaust stack as miscellaneous steel. 

(10) Outside air probe tubing (Unit 1) is made of copper and screened as piping, and 

Table 2.3.3-6 includes this component. 

(11) NEI 95-10, Rev. 0, Appendix B, Item 163, designates ventilation fans (Unit 1) as active 

components and, therefore, no AMR is required for the fan housing shown in 

HL-16174. 

(12) Outside air probe tubing (Unit 2) is made of copper and screened as piping, and 

Table 2.3.3-6 includes this component. 

(13) NEI 95-10, Rev. 0, Appendix B, Item 163, designates ventilation fans (Unit 2) as active 

components and, therefore, no AMR is required for the fan housings shown in HL-26078. 

The staff reviewed the applicant's responses concerning the associated tubing for differential 

pressure indicators, the temperature element and its associated tubing, valves and associated 

piping for flow switches, the filter housing (Units 1 and 2) for carbon and HEPA filters, the bird 

screen (Units 1 and 2), buried piping, and outside air probe tubing (Units 1 and 2), and found them 

acceptable, since these component commodity groupings were within the scope of license renewal 

and subject to an AMR, in accordance with the applicable requirements of 10 CFR 54.21 (a)(1), 10 

CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3). 

In its responses to RAI 2.3.3-SGTS-1 and RAI 2.3.3-SGTS-2, the applicant stated that differential 

pressure indicators, guillotine damper housings, and fan housings in the SGTS are not subject to 

an AMR on the basis of the guidance provided in NEI 95-10, Appendix B. The staff agrees that 

differential pressure indicators are considered components with an active function and, therefore, 

are not subject to an AMR. However, the staff questioned whether it was appropriate for the 

applicant to exclude guillotine damper housings and fan housings from an AMR. During a 

telephone conference on October 31, 2000, the staff asked the applicant to provide justification for 

why the housings for the guillotine dampers and fans should be excluded from an AMR. 

In response to the staff's concerns regarding the exclusion from an AMR of the housings for 

components such as fans, dampers, and heating and cooling coils, the applicant provided, by an 

e-mail dated November 6, 2000, a paper titled "Active Assemblies Used in License Renewal." 

The staff reviewed this paper and found that the applicant's basis for excluding fan, damper, and 

heating and cooling coil housings is not consistent with the license renewal rule, the Statements 

of Consideration (SOC) accompanying the Rule, or the staff's review guidance. 

10 CFR 54.21 (a)(1) provides that those components that perform their intended functions without 

moving parts and without a change in configuration or properties (10 CFR 54.21 (a)(1)(i)) and that

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are not subject to replacement based on qualified life or specified time period (10 CFR 

54.21 (a)(1)(ii)) are subject to an AMR. Such components are commonly considered as "long-lived" 

and as performing a passive function. 10 CFR 54.21(a)(1)(i) states that "structures and 

components [with passive functions] include, but are not limited to,... pump casings, valve bodies 

... " and lists other components that perform passive functions. The examples cited in the license 

renewal rule illustrate components with significant passive functions. 

Section lll.f.i(a) of the SOC further explains that major components may have active functions, 

passive functions, or both, and cites pumps and valves as examples. Pumps and valves have 

moving parts, but the Commission concluded that the pressure-retaining function performed by the 

pump casing and the valve body were important enough to warrant an AMR. The SOC further 

explains that the Commission does not limit the consideration of pressure boundaries to reactor 

coolant pressure boundary. The exclusion regarding components is focused on active functions 

rather than on the exclusion of the entire component, while the AMR applies to the passive function 

of the component. On this basis, the staff concludes that fans, dampers, and heating and cooling 

coils may include significant passive pressure-retaining and structural support functions. 

Section 2.2.111.A of the draft SRP-LR, September 1997, states that "...some functions of "active" 

components may meet the criteria of the "passive" description. For example, although a pump or 

a valve has some moving parts, a pump casing or valve body performs a pressure retaining 

function without moving parts. A pump casing or a valve body meets this description and would 

therefore be considered for an aging management review." It is clear by this passage, and by the 

examples provided of pumps and valves, that the passive functions of components are subject to 

an AMR. 

In Section 2.1.1 of the LRA, the applicant states that the specific method used to identify in-scope 

functions and to screen the SSCs required to perform the in-scope functions was developed 

considering the guidance provided by NEI 95-10, Revision 0, "Industry Guideline on Implementing 

the Requirements of 10 CFR Part 54 - The License Renewal Rule," among other regulatory and 

guidance documents. Appendix B of NEI 95-10 provides a list of components and their 

active/passive functions. Item numbers 155 and 163 identify dampers and ventilation fans, 

respectively. Each of these components is identified in the appendix as performing an active 

function. The staff notes that the appendix, though it specifically identifies the dampers and 

ventilation fans, does not address housings for these components. 

On the basis of the information in the Rule, the SOC, and guidance provided in the SRP-LR, the 

staff concludes that the housings for fans, dampers, and heating and cooling coils contribute to the 

performance of the intended function of fans, dampers, and heating and cooling coils without 

moving parts and without a change in configuration or properties, and thus are subject to an AMR. 

This issue also affects the scope of components with passive functions for the control building 

HVAC, outside structures HVAC, and reactor building HVAC systems, which are discussed in 

Section 2.3.4.2 of this SER. 

Therefore, on the basis of the above staff positions, the staff requested that the applicant identify 

the passive functions for those fans, dampers, and heating and cooling coils that are within the 

scope of license renewal. For those passive functions, the applicant should identify any aging 

effects associated with the components and provide an AMP to manage the aging. This was 

identified as part of Open Item 2.3.3.2-2 [2.3.3.2-2(a)].

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By letter dated June 5, 2001, the applicant provided information regarding the disposition of fans, dampers, and heating and cooling coils within the scope of license renewal. Consistent with the 

staff's guidance regarding evaluation of active components, the applicant identified the passive 

functions of damper frames and fan housings in the SGTS and added these components to the list 

of components in the LRA that are subject to an AMR. The applicant also identified any aging 

effects associated with the damper frames and fan housings and provided an AMP to manage the 

aging. The applicant added these components to those listed in Tables 2.3.3-6 and 3.2.3-6 in the 

LRA. The staff's review of the aging effects and AMPs for the SGTS can be found in Section 3.3.3 

of this SER. On the basis of the additional information provided by the applicant, the staff agrees that the damper frames and fan housings are included in the scope of license renewal and subject 

to an AMR. Further, the staff concludes that the inclusion of these components in Tables 2.3.3-6 

and 3.2.3-6 of the LRA is acceptable. On the basis of the additional information provided by the 

applicant, this part of Open Item 2.3.3.2-2, as it relates to SGTS components, is closed. 

The applicant also agreed to clarify the function of the guillotine damper regarding, including whether this damper is safety-related and included within the scope of license renewal and subject 

to an AMR. This was also identified as part of Open Item 2.3.3.2-2 [2.3.3.2-2(a)]. 

By letter dated June 5, 2001, the applicant clarified the function of the guillotine damper utilized 

in the SGTS. The dampers represent a commodity group of dampers associated with SGTS 

filtration units, 2T46-DO01A and 2T46-DO01 B. During accident and normal operating conditions, 

the dampers remain open. For filter testing purposes the dampers may be closed as needed. 

However, the dampers are not safety-related, do not perform an intended function , and can not 

prevent an intended function. Therefore, the guillotine dampers are not included in the scope of 

license renewal and are not subject to an AMR. On the basis of the additional information provided by the applicant, the staff agrees that the guillotine dampers are not within the scope of license 

renewal and not subject to an AMR. On the basis of the previously noted information, this part of 

Open Item 2.3.3.2-2 [2.3.3.2-2(a)], as relates to SGTS guillotine dampers, is closed. 

The staff reviewed Section 2.3.3.6 of the LRA, supporting information in the UFSAR, the applicant's 

responses to the staff's RAIs, and additional information provided by letter dated June 5, 2001. 

In addition, the staff sampled several components in thepreviously mentioned evaluation boundary drawings of the LRA to determine whether the applicant properly identified the components that 

are within the scope of license renewal and subject to an AMR. 

On the basis of this review, the staff has reasonable assurance that the applicant has adequately identified the SGTS components that are within the scope of license renewal and subject to an 

AMR in accordance with the requirements of 10 CFR 54.4, and 10 CFR 54.21. 

2.3.3.8 Standby Liquid Control System 

Summary of Technical Information in the Application 

The SLCS ensures reactor shutdown, from full-power operation to cold subcritical, by mixing a 

neutron absorber with the primary reactor coolant. The system is designed for the condition when 

an insufficient number of control rods can be inserted from the full-power setting. The neutron 

absorber is injected within the core zone in sufficient quantity to provide a sufficient margin for

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leakage or imperfect mixing. The system is not a scram or a backup scram system for the reactor; 

it is an independent backup system for the control rod drive (CRD) system. 

The SLCS is located in the reactor building, and consists of a low-temperature sodium pentaborate 

solution storage tank, a test tank, a pair of full-capacity positive displacement pumps, two explosive 

actuated shear plug valves, two accumulators, the poison sparger, and the necessary piping, 

valves, and instrumentation. The SLCS is manually initiated from the control room by use of a 

three-position key-lock switch. 

System Intended Functions 

The SLCS serves the following intended functions: 

* Reactivity control: The SLCS assures reactor shutdown from full power operation to cold 

subcritical by mixing a neutron absorber with the primary reactor coolant. 

SLCS testing: The testing function is not safety-related. However, to accomplish this 

function, equipment serving the reactivity control function is used, as well as the test tank 

and piping. The equipment common served by the reactivity control function is brought into 

scope under that condition. The test tank is qualified to seismic Il/I criteria, and therefore 

has the potential to prevent a safety-related function. For this reason, this function is 

conservatively brought into scope. 

Component Intended Function 

The function of the SLCS components is to serve as a pressure boundary. 

The component groups requiring an AMR, as identified in the LRA, include the bolting, piping, 

pump accumulators, pump casings, tanks, temperature element, temperature switch, and valve 

bodies. 

Staff Evaluation 

In RAI 2.3.3-SLCS-1, the staff indicated that Table 2.3.3-1 of the LRA identifies the pressure 

boundary as the only intended function for the components supporting the SLCS, per 

10 CFR 54.4(a)(1 )(i). However, the staff believes that the components have additional intended 

functions as delineated in 10 CFR 54.4(a)(1 )(ii) and (iii), namely, the capability to shutdown the 

reactor and maintain it in a safe shutdown condition, and the capability to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposure, respectively. It was not 

clear in the LRA whether these functions were considered to be intended functions of the 

components supporting the SLCS. The staff, therefore, requested clarification from the applicant. 

In response, the applicant explained that its scoping process identified functions, and applied all 

of the Part 54 criteria, including 10 CFR 54.4(a)(1)(i), (ii) and (iii), to determine if the functions were 

intended functions that should be in scope. Portions of the SLCS were determined to be in scope 

because they met one or more of the criteria in 10 CFR 54.4. It was clarified that Table 2.2-1 of 

the LRA presents the scoping results. Function numbers C41-01 and C41-03, which are defined 

as reactivity control and SLCS testing, respectively, are in scope. On the basis of the applicant's 

response to this RAI, the staff concludes that the applicant has clarified the intended functions of 

the SLCS.

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In RAI 2.3.3-SLCS-2, the staff questioned the basis for not including the SLCS poison standpipe/sparger within the scope of license renewal and not subjecting it to an AMR. The staff 

stated in the RAI that although the standpipe/sparger may not perform the pressure boundary function, it does perform other intended functions, such as the capability to shutdown the reactor 

and maintain it in a safe shutdown condition, and the capability to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposure. The staff further stated 

that aging effects, such as blockage of the standpipe/sparger perforations to prevent the injection of liquid poison solution and/or cracking of the component itself, may degrade its function to ensure 

good mixing and dispersion of the poison inside the reactorvessel. The staff, therefore, requested that the applicant submit an AMR, or present a justification for excluding the SLCS poison 

standpipe/ sparger from an AMR. In its response, the applicant stated in its response that the 

SLCS sparger was evaluated by the Boiling Water Reactor Vessel Internal Program (BWRVIP). 

The initial safety assessment is documented in BWRVIP-06, "Safety Assessment of BWR Reactor 

Internals," dated October, 1995, in which it was concluded that failure of the sparger as a result of 

cracking "has no performance or safety consequence." The NRC issued a safety evaluation for 

BWRVIP-06 on September 15,1998. BWRVIP later performed a more detailed assessment of the 

SLCS piping and sparger to determine the need for any inspections. The results are documented 

in BWRVIP-27, "BWR Standby Liquid Control System/Core Plate AP Inspection and Flaw 

Evaluation Guidelines." This assessment, like BWRVIP-06, considered all modes of degradation 

and identified the actions necessary to ensure safe operation. Boron mixing was specifically addressed in Section 2.2.1 of BWRVIP-27. The conclusion was that cracking of the sparger would 

not prevent the poison from mixing and shutting down the reactor. BWRVIP-27 was reviewed and 

approved for generic use by the NRC in the SERs for both the current term (May 27,1999) and for 

the license renewal term (December 20, 1999). Furthermore, the applicant stated that given the 

materials of construction and the environment, plugging of the sparger as a result of corrosion of 

the sparger is not a plausible aging effect. The applicant also stated that if crud from the bottom 

head region were to accumulate, the pressure associated with SLCS injection would dislodge any crud and flow would be ensured. Therefore, an aging management activity is not warranted. On 

the basis of the applicant's response to this RAI, the staff concludes that the standpipe/sparger 

does not perform an intended function and, therefore, is not subject to an AMR. 

On the basis of the staff's review of the information provided for the SLCS in the LRA, and 

described in Section 2.3.3.8 of this SER, the staff concludes that the applicant has properly identified the components associated with the SLCS that are within the scope of license renewal, 

as required by 10 CFR 54.4(a), and those that are subject to an AMR, as required by 10 CFR 

54.21 (a)(1). 

2.3.3.9 Conclusions 

On the basis of the staff's review of the information presented in Section 2.3.3 of the LRA, the 

supporting information in the Plant Hatch UFSAR, the applicant's response to the staff's RAIs, the 

additional information provided in telephone conversations between the applicant and the staff, and 

the applicant's responses to the open items, the staff concludes that there is reasonable assurance 

that the applicant has identified those portions of the ESF systems that are within the scope of 

license renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) 

and 10 CFR 54.21 (a)(1).

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2.3.4 Auxiliary Systems

The applicant describes the auxiliary systems that are within the scope of license renewal and 

subject to an AMR in the following sections of the LRA: 2.3.4.1, "Control Rod Drive System"; 

2.3.4.2, "Refueling Equipment System"; 2.3.4.3, "Insulation System"; 2.3.4.4, "Access Doors 

System"; 2.3.4.5, "Condensate Transfer and Storage System"; 2.3.4.6, "Sampling System"; 2.3.4.7, 

"Plant Service Water System"; 2.3.4.8, "Reactor Building Closed Cooling Water System"; 2.3.4.9, 

"Instrument Air System"; 2.3.4.10, "Primary Containment Chilled Water System"; 2.3.4.11, "Drywell 

Pneumatics System"; 2.3.4.12, "Emergency Diesel Generators System"; 2.3.4.13, "Cranes, Hoists, 

and Elevators System"; 2.3.4.14, "Tornado Vents System"; 2.3.4.15, "Reactor Building Heating, 

Ventilation, and Air Conditioning (HVAC) System"; 2.3.4.16, "Traveling Water Screens/Trash Racks 

System"; 2.3.4.17, "Outside Structures HVAC System"; 2.3.4.18, "Fire Protection System"; 2.3.4.19, 

"Fuel Oil System"; and 2.3.4.20, "Control Building HVAC System." For these systems, the applicant 

identifies the in-scope structures and components that are subject to an AMR. The staff reviewed 

these sections of the application to determine if there is reasonable assurance that the applicant 

has identified and listed those structures and components that are within the scope of license 

renewal, as required by 10 CFR 54.4, and subject to an AMR, as required by 10 CFR 54.21 (a)(1). 

The staff reviewed the LRA to determine whether there is reasonable assurance that the auxiliary 

system components and supporting structures that are within the scope of license renewal and 

subject to AMR have been identified in accordance with the requirements of 10 CFR 54.4 and 10 

CFR 54.21 (a)(1). As part of the evaluation, the staff reviewed portions of the UFSARs for the 

auxiliary systems and associated pressure boundary components, and compared the information 

in the UFSAR with the information in the LRA to identify those portions that the LRA did not identify 

as being within the scope of license renewal and subject to an AMR. The staff then reviewed SCs 

that were identified as not being within the scope of license renewal. The staff requested that the 

applicant provide additional information and/or clarifications for a selected number of these SCs 

to verify the following characteristics: 

These SCs do not have any of the intended functions delineated under 10 CFR 54.4(a) 

Those SCs that have an applicable intended function(s) either perform the specified 

function(s) with moving parts or a change in configuration or properties, or they are subject 

to replacement on the basis of a qualified life or specified time period, as described in 10 

CFR 54.21 (a)(1). 

The staff also reviewed all system functions to determine if any functions met the criteria of 10 CFR 

54.4, but were not identified as intended functions in the LRA. 

2.3.4.1 Access Doors System 

Summary of Technical Information in the Application 

The secondary containment access doors are designed to provide access to the reactor building 

for personnel and equipment. In Section 2.3.4.4 of the LRA, the applicant describes the intended 

functions and lists the components of the system that are subject to an AMR. The applicant 

describes its process for identifying the mechanical components that are within the scope of license 

renewal in Sections 2.1.2 and 2.1.3 of the LRA.

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In Section 2.3.4.4 of the LRA, the applicant states that the secondary containment, in conjunction 

with the primary containment and other engineering safeguards, provides the capability to limit the 

release to the environment of radioactive materials so that the offsite dose from a postulated 

design-basis accident will be below the guideline values of 10 CFR Part 100. 

The initial scoping, performed by the applicant on the basis of system functions, determined that 

the intended function of the access doors system, L48-01 - Containment Integrity, is within the 

scope of license renewal. Only the doors that are necessary to maintain secondary containment 

are included in this function. Secondary containment plays a role in preventing offsite releases 

from exceeding regulatory criteria. Secondary containment doors have a passive function to 

maintain structural integrity to preserve secondary containment. 

The associated structural steel is identified in Table 2.3.4-4 of the LRA as being subject to an AMR. 

The functions of the structural steel are to serve as a missile barrier and fission product barrier. 

Staff Evaluation 

The staff reviewed the above information related to the access doors system to verify that the 

intended system functions that are within the scope of license renewal and the components that 

are subject to an AMR have been identified in accordance with the requirements of 10 CFR 54.4 

and 10 CFR 54.21 (a)(1). 

The applicant identified and listed the components that are subject to an AMR for the access doors 

system in Table 2.3.4-4 of the LRA using the screening methodology described in Sections 2.1.2 

and 2.1.3 of the LRA. The staff's evaluation of the screening methodology is addressed Section 

2.1 of this SER. 

The staff reviewed Section 2.3.4.4 of the LRA to determine if there were any system functions that 

are not identified as intended functions in accordance with requirements of 10 CFR 54.4. The staff 

then verified that the applicant identified all of the components that are within the scope of license 

renewal in accordance with 10 CFR 54.4. Further, the staff verified the completeness of LRA Table 

2.3.4-4 to confirm that all of the components that are within the scope of license renewal were 

included in the application. In addition, the staff sampled the components that are within the scope 

of license renewal, but not subject to an AMR, to verify that all of the components that meet the 

requirements of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAIs in a 

letter dated August 29, 2000. 

In RAI 2.3.4-AD-1, the staff requested that the applicant justify the exclusion of the access door 

and door seals from within the scope of license renewal and from being subject to an AMR. The 

applicant responded that the secondary containment access doors and door seals are within the 

scope of license renewal. However, the door seals are not subject to an AMR because they are 

replaced or repaired on the basis of the performance and conditions under preventive maintenance 

procedures. On the basis of the applicant's response to the RAI, the staff concludes that the door 

seals are not subject to an AMR.

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In a telephone conference on September 13,2000, the applicant clarified that the access doors are 

identified as "structural steel" in Table 2.3.4-4 of the LRA. In an e-mail correspondence dated 

November 22, 2000, the applicant provided further clarification that the containment integrity 

function (L48-01) refers to secondary containment integrity, not primary containment integrity. 

Secondary containment integrity is ensured by the standby gas treatment system (SGTS) 

drawdown limitations, which are specified in plant technical specifications for secondary 

containment operability and surveillance requirements once every 18 months. 

On the basis of the staff's review of the LRA, the applicant's responses to the RAI, and followup 

discussions and correspondence, the staff was unable to find any omissions from the function level 

scoping boundaries. The staff also compared the components listed in Table 2.3.4-4 of the LRA 

and those described in the LRA. After clarification that the access doors are identified as 

"structural steel" in the table, the staff found that the table and the system description are 

consistent. 

2.3.4.2 Condensate Transfer and Storage System 

Summary of Technical Information in the Application 

The condensate transfer and storage system provides the plant system makeup, receives reject 

flow, and provides condensate for any continuous service needs and intermittent batch-type 

services. In Section 2.3.4.5, "Condensate Transfer & Storage System," of the LRA, the applicant 

describes the intended functions and lists the components of the system that are subject to an 

AMR. The applicant describes its process for identifying the mechanical components that are within 

the scope of license renewal in Section 2.1.2, "Scoping," and Section 2.1.3, "CiviVMechanical 

Component Screening," of the LRA. 

The total stored design quantity of water is predicated on the demand requirements during 

refueling for filling the dryer separator pool and the reactor well. A 500,000 gallon CST supplies 

the various unit requirements. The Unit 1 tank is constructed of aluminum, and the Unit 2 tank of 

stainless steel. The system also consists of two condensate transfer pumps and associated piping 

and valves. The CST provides the preferred supply to the HPCI and RCIC systems. All other 

suctions are located above suction lines for these systems to provide a 100,000-gallon reserve. 

The initial scoping, performed by the applicant on the basis of functions, determined that the 

intended function of the condensate transfer and storage system, P11-01 - ECCS/CRD 

Condensate Supply, is be within the scope of license renewal. While the CST is non-safety-related, 

the preferred water source for the RCIC and HPCI systems is the CST. The design of the tank 

ensures that 100,000 gallons of water are set aside for this supply. The HPCI and RCIC systems 

rely upon this volume of water during a response to station blackout. 

The associated piping, valve bodies, bolting, and tanks are identified in Table 2.3.4-5 of the LRA 

as being within the scope of license renewal and subject to an AMR. The component function of 

these components is to serve as a pressure boundary. 

Staff Evaluation 

The staff reviewed the above information to verify that the intended functions of the condensate 

transfer and storage system that are within the scope of license renewal and the components that

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are subject to an AMR have been identified in accordance with the requirements of 10 CFR 54.4 

and 10 CFR 54.21 (a)(1). 

The applicant identified and listed the components that are subject to an AMR for the condensate 

transfer and storage system in Table 2.3.4-5 of the LRA using the screening methodology described in Sections 2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the 

staff in Section 2.1 of this SER. 

The staff reviewed Section 11.9 of the UFSAR for Plant Hatch Unit 1 and Section 9.2.6 of the 

UFSAR for Unit 2 to determine if there were any system functions that were not identified as 

intended functions in accordance with the requirements of 10 CFR 54.4. The staff then reviewed 

the drawings (HL-1 6016, HL-1 6332, HL-1 6334, HL-26030, HL-26023, HL-26046) to verify that the 

applicant identified all of the components that are within the scope of license renewal in accordance 

with 10 CFR 54.4. Further, the staff verified the accuracy of the drawings and the completeness 

of Table 2.3.4-5 by sampling the components adjacent to, but outside, the highlighted portion of 

the system to verify that all of the components that are within the scope of license renewal were 

included in the application. In addition, the staff sampled the components that are within the scope of license renewal, but not subject to an AMR, to verify that all of the components that meet the 

requirements of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAis in a 

letter dated August 29, 2000. 

In reviewing drawing HL-1 6016, the staff found that valves E51 -F009 and E41 -F7010 were not 

highlighted. These valves are locked open for flow from the CST to the HPCI system and the RCIC 

system, serving the intended function of P11-01, ECCS/CRD Condensate Supply. The staff 

believed that these valves are within the scope of license renewal. Therefore, the staff requested that the applicant justify why these valves are not highlighted in the drawing. The applicant responded that these two valves are within the scope of license renewal. These valves and 

associated piping downstream are shown in "phantom" (indicating that the information is supplied for reference only) on drawing HL-16016, and are not highlighted since they appear on other 

license renewal boundary drawings. Referring to license renewal boundary drawings HL-1 6332 and 

HL-1 6334, these two valves (along with the associated piping) are highlighted, indicating that these 

valves are within the scope of license renewal. 

In reviewing the response that in-scope components are highlighted on one drawing but not on 

another drawing, the staff was concerned that onsite personnel attempting to inspect or confirm 

components within functional evaluation boundaries may have difficulty understanding which 

drawing is correct. In a telephone conference on September 28, 2000, the applicant stated that 

implementing procedures are being developed on the basis of functional drawings, scoping and 

screening procedures, and current licensing-basis documents. These documents, along with the 

staff's SER, will provide sufficient guidance and information to allow an NRC inspector to identify the functional evaluation boundaries, SSCs that are within the boundary and outside the boundary, 

and structures and components that are subject to an AMR. 

The staff requested that the applicant explain why the flow line from the CST to the control rod 

drive (CRD) system is excluded from the scope of license renewal. The applicant responded that 

for the CRD system, only the reactivity control and alternate rod insertion functions are within the

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scope of license renewal for Plant Hatch. A supply of demineralized water from the CST is not 

required for the CRD system to accomplish these two functions. Therefore, the flow line in 

question is not within the scope of license renewal. 

The staff requested that the applicant justify the exclusion of the two condensate transfer pumps 

and associated piping and valves from the scope of license renewal. The applicant's response to 

the RAI did not provide sufficient explanation. In a telephone conference on September 13,2000, 

the applicant explained that these pumps supply water from the demineralized water storage tank 

to the CST, which is not an essential water source for the intended safety function (the essential 

water source for the intended function is from the suppression pool, which has sufficient water to 

serve the safety function.) 

The staff also questioned the basis for excluding instrument tubing from an AMR. The applicant 

responded that with the exception of copper, the LRA includes instrument tubing with piping for like 

materials. There is no copper instrument tubing in scope for functions associated with the 

condensate transfer and storage system. 

On the basis of the staff's review of the LRA and associated drawings, the UFSAR for Plant Hatch 

Units 1 and 2, and the applicant's responses to RAIs, the staff was unable to find any omissions 

from the components highlighted in the diagrams that identify the function-level scoping 

boundaries. The staff also compared the components listed in Table 2.3.4-5 of the LRA and those 

highlighted in the drawings, and found them to be consistent. 

On the basis of the review described above, the staff has determined there is reasonable 

assurance that the applicant has adequately identified the intended functions of the condensate 

transfer and storage system that are within the scope of license renewal in accordance with the 

requirements of 10 CFR 54.4, and those that are subject to an AMR in accordance with the 

requirements of 10 CFR 54.21 (a)(1). 

2.3.4.3 Control Building HVAC 

Summary of Technical Information in the Application 

In LRA Section 2.3.4.20, the applicant identifies portions of the control building HVAC system and 

its components that are within the scope of license renewal and subject to an AMR. In Section 

2.3.4.20 of the LRA, the applicant states that additional information for the system is provided in 

Section 9.7 of the UFSAR for Unit 2. The system scoping is shown in control building evaluation 

boundary drawings HL-16040, Rev. A, and HL-11609 for Unit 1, and HL-16042, Rev. A, and 

HL-26116, Rev. A, for Units 1 and 2. 

The control building is served by both heating and air-conditioning (A/C) subsystems and a 

once-through ventilation subsystem. The A/C subsystems use direct expansion of chilled water 

cooling coils. Heating is provided by electric or hot water heating coils. The control room, 

computer room, water analysis room, chemistry laboratory and health physics area, and cold 

laboratory are the areas served by the heating and A/C subsystems. The LPCI inverter room and 

Unit 2 vital A/C room are served by separate coolers. All other areas of the control building are 

served by a once-through ventilation subsystem.

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Plant Hatch Unit 1

The control building is served by HVAC systems. In the general area, outside air is supplied by three 50-percent-capacity fans. The air is filtered and distributed by ductwork in proportion to the 

equipment and lighting loads in these areas. The exhaust system is split between Units 1 and 2. 

Three 50-percent-capacity Unit 1 fans and two 1 00-percent-capacity Unit 2 fans exhaust air to the 

Units 1 and 2 reactor vent plenums. 

Direct expansion water-cooled air-conditioning units fully air-condition the main control room 

(MCR), computer room, water sampling room, chemical laboratory and health physics area, cold 

lab, shift supervisors area, LPCI inverter room, and Unit 1 and 2 vital AC rooms. The battery 

rooms have exhaust fans and heaters. The cable spreading room has a separate ventilation 

system. The details of HVAC systems serving these areas are described in Section 10.9.3.6 of the 

UFSAR for Unit 1. 

Plant Hatch Units 1 and 2 

The HVAC system is shared by Units 1 and 2. The MCR habitability systems are designed to 

provide safety and comfort for operating personnel during normal operations and postulated accident conditions. These habitability systems for the MCR include radiation shielding, charcoal 

and other filter systems, HVAC, sanitary facilities, and fire protection. A discussion of the MCR 

systems that control the climatic conditions existing within the MCR is provided in Section 9.4.1 of 

the Unit 2 UFSAR. 

Previous analyses demonstrate that the LOCA is the limiting event for radiological exposures to 

operators in the MCR. The pressurization mode of operation of the MCR environmental control 

system (MCRECS) is provided to minimize the amount of radioactivity entering the MCR following 

an accident. The MCR atmosphere is recirculated through the MCRECS emergency filters with 

sufficient outside air being drawn in through the normal intake to maintain the MCR at a positive 

pressure of >0.1-in. water gauge (WG) relative to the surrounding turbine building. The MCR is 

designed to maintain its temperature below 79 OF with relative humidity of 75 percent. Fire 

protection for the MCR is discussed in Section 9.5.1 of the UFSAR for Unit 2. Since no gaseous 

chlorine is used or stored on site, the chlorine accident was not evaluated for the MCR. 

The MCRECS is discussed in Section 9.4.1 of the UFSAR for Unit 2. The Unit 1 and 2 MCRs are 

housed in a shared facility. The habitability systems are designed to serve the Unit 1 and 2 

combined control rooms. The principal equipment in the system includes (1) three 

50-percent-capacity air-handling units (AHUs) with cooling coils and fans; (2) three 

50-percent-capacity condensing units, each consisting of refrigerant compressor, condenser, and 

associated controls that service the AHU cooling coils; (3) two 100-percent-capacity exhaust air 

fans; (4) two trains of high-efficiency air filtration units consisting of a prefilter, a high-efficiency particulate air (HEPA) filter, an electric carbon drying heater, a carbon absorber, a second HEPA 

filter for emergency treatment of recirculated air or outside supply air, and two filtration unit booster 

fans, one for each filtration unit. The MCRECS is designed with sufficient redundancy and 

separation of active components to provide reliable operation under normal conditions and to 

ensure operation under emergency conditions. Where redundancy does not exist (e.g., restroom 

exhaust dampers and exhaust fan isolation dampers), the system is normally operated such that 

at least one isolation barrier is normally closed. In the case of the restrooms, the doors provide that 

barrier. Upon verification that the exhaust dampers have closed for the pressurization mode,

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access to the restrooms is allowed via these doors. In the case of the exhaust fan isolation 

dampers, the fans are normally not operated, and the dampers are normally closed. The MCRECS 

normal operation and accident condition modes, and associated instrumentation application are 

described in Section 6.4 of the UFSAR for Unit 2. The control building HVAC systems are 

described in Section 9.4.7 of the UFSAR for Unit 2. 

In Section 2.3.4.20 of the LRA, the applicant identified the following intended functions that relate 

to 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3): 

* Control Room Habitability (Z41-02) 

* Control Building Environmental Support (Z41-03) 

On the basis of the functions identified above, the applicant determined that all safety-related 

components (electrical, mechanical, and instrument) are within the scope of license renewal. The 

applicant described its process for identifying the mechanical components that are subject to an 

AMR in Section 2.1.2 of the LRA. On the basis of this methodology, the applicant identified the 

portions of the system that are within the scope of license renewal in control building evaluation 

boundary drawings HL-1 6040, Rev. A, and HL-1 1609, Rev. A, for Unit 1, and HL-1 6042, Rev. A, 

and HL-26116, Rev. A, for Units 1 and 2. Using the methodology described in Section 2.1.2 of the 

LRA, the applicant compiled a list of the mechanical components and component types within the 

license renewal boundaries that are subject to an AMR, and identified their functions. The 

applicant provided this list in Table 2.3.4-20 of the LRA. 

The applicant identified the following 22 device types as being within the scope of license renewal 

and subject to an AMR: 

* accumulator air valve (carbon steel) 

* accumulator piping (carbon steel) 

9 accumulator tanks (stainless steel) 

0 bolting (carbon steel) 

* duct gasket (fibers, non-asbestos, synthetic; elastomers, other) 

• duct heater (aluminum) 

* duct silencer (galvanized steel) 

* ductwork (carbon steel) 

* ductwork (galvanized steel) 

* ductwork flex connector (fibers, non-asbestos synthetic; elastomers, other) 

• filter housing (galvanized steel) 

* flow element (stainless steel) 

* instrument piping (copper alloy) 

• instrument piping (stainless steel) 

9 louver (carbon steel) 

* piping (stainless steel) 

* radiation element (stainless steel) 

* temperature sensor (stainless steel) 

* tubing (copper) 

* valve bodies (carbon steel) 

0 valve bodies (copper alloy) 

* valve bodies (stainless steel)

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In Table 2.3.4-20, the applicant further noted that the pressure boundary function is the only 

applicable function associated with components that are subject to an AMR. 

Staff Evaluation 

The staff reviewed the information related to the control building HVAC system to verify that the 

applicant identified components that are within the scope of license renewal and subject to an 

AMR. The staff determined whether there is reasonable assurance that the components within the 

scope of license renewal and subject to an AMR have been identified in accordance with 10 CFR 

54.4 and 10 CFR 54.21 (a)(1). The staff reviewed the information in the LRA and Sections 6.4, 

9.4.1, and 9.4.7 of the UFSAR for Unit 2 and Section 10.9.3.6 of the UFSAR for Unit 1. After 

completing the initial review, the staff issued RAIs regarding the control building HVAC system by 

letter dated July 14, 2000. The applicant responded to the RAIs in a letter dated August 29, 2000. 

In LRA Section 2.1, the applicant discussed the process for identifying mechanical components that 

are subject to an AMR. The applicant's scoping methodology is evaluated by the staff in Section 

2.1 of this SER. 

In its review of the control building HVAC system, the staff reviewed the control building evaluation 

boundary drawings HL-1 6040, Rev. A, and HL-1 1609 for Unit 1, and HL-1 6042, Rev. A, and HL

26116, Rev. A, for Units 1 and 2. The drawings show the evaluation boundaries for the portions 

of the control building HVAC system that are within the scope of license renewal. The staff also 

reviewed Table 2.3.4-20 of the LRA which lists components that are subject to an AMR. 

The staff also reviewed Sections 6.4,9.4.1, and 9.4.7 of the UFSAR for Unit 2 and Section 10.9.3.6 

of the UFSAR for Unit 1 to determine if there were any portions of the control building HVAC 

system that met the scoping criteria in 10 CFR 54.4(a) that the applicant did not identify as being 

within the scope of license renewal. The staff also reviewed the UFSAR sections to determine if 

there was any system function that was not identified as an intended function in the LRA, and to 

determine if there were SCs that have an intended function that might have been omitted from the 

scope of SCs that are subject to an AMR. The staff also reviewed the evaluation boundary 

drawings to determine if any SCs within the evaluation boundaries were omitted from the scope 

of SCs requiring an AMR. The staff compared the functions described in the UFSAR with those 

identified in the LRA. The staff then determined whether the applicant had properly identified the 

SCs that are subject to an AMR from among those identified as being within the scope of license 

renewal. 

The applicant identified and listed the SCs that are subject to AMR for the control building HVAC 

system in Table 2.3.4-20 of the LRA, using the screening methodology described in section 2.1 of 

the LRA. The staff evaluated the scoping and screening methodology, and documented its findings 

in Section 2.1 of this SER. The staff sampled SCs from Table 2.3.4-20 to verify that the applicant 

identified the SCs that are subject to an AMR. The staff also sampled SCs that are within the 

scope of license renewal, but were not identified as being subject to an AMR, to verify that these 

SCs perform their intended functions with moving parts or with a change in configuration or 

properties, or were subject to replacement on the basis of a qualified life or specified time period. 

To ensure that those portions of the control building HVAC system that were identified as not being 

within the scope of license renewal did not perform any intended functions, the staff issued RAIs 

on the basis of the information in the UFSAR and LRA. The staff noted that LRA Section 2.3.4.20

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presents a summary description of the system functions, evaluation boundary drawings highlight 

the evaluation boundaries, and Table 2.3.4-20 lists the components that are within the scope of 

license renewal and subject to an AMR. The corresponding drawings for these systems in the 

UFSAR, however, show additional components that were not listed in Table 2.3.4-20 of the LRA. 

The staff requested specific information concerning the exclusion of the following components from 

the scope of license renewal and/or an AMR: 

(1) damper housing and associated ductwork (HL-1 6042 (several dampers), HL-1 6042 @ H7 

(cable spreading room)); HL-26116 @ C4 and D4) 

(2) filter train housing with carbon and HEPA filters (HL-1 6042 @ B8 and B9, F8 and F9) 

(3) fan housing (HL-16042 @ E12 and F12, B7, E7; H5, H7 (cable spreading room)) 

(4) air handling units housing and heating and cooling coils (HL-1 6042 @ B2 and B3, D2 and 

D3, F2 and F3) 

(5) filters (HL-16042 @ B5, F5) 

(6) coolers for low-pressure coolant injection (LPCI) inverter room and Unit 2 vital A/C room 

(text of Section 2.3.4.20) 

(7) sealants 

In a letter dated August 29, 2000, the applicant provided the following responses: 

(1) The damper housing is a part of the damper, which is an active component (NEI 95-10 

Revision 0, Appendix B, Item 155). The ductwork is constructed of both carbon steel and 

galvanized steel and is subject to an AMR. Both types of ductwork are included in Table 

2.3.4-20. 

(2) The filter train housing is subject to an AMR and is included in Table 2.3.4-20. The carbon 

and HEPA filter media inside the filter housing are consumables. 

(3) The in-scope fan housings are a part of fan assemblies, which are active components (NEI 

95-10, Rev, 0, Appendix B, Item 163) 

(4) The air-handling units, including the cooling coils, are part of the active fan assemblies (NEI 

95-10, Rev. 0, Appendix B, Item 163). The heating coil housing, however, is subject to an 

AMR and is shown in Table 2.3.4-20. 

(5) The filter media shown on HL-1 6042 (B5 and G5) is consumable. An AMR was performed 

on the filter housing, which is included in Table 2.3.4-20. 

(6) The coolers for the LPCI inverter room and the Unit 2 vital AC room do not perform an 

in-scope function; however, the LPCI inverter room cooling coils do provide part of the 

pressure boundary function for P41-01, but were not subject to AMR since they are part of 

the active fan assemblies.

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(7) Sealants are not used at Plant Hatch to maintain positive pressure for the MCR pressure 

boundary; sealants used to support intended functions are listed in Table 2.4.13-1 

The staff reviewed the applicant's responses concerning the associated ductwork, the filter train 

housing with carbon and HEPA filters, and the heating coil housing, and found the responses to 

be acceptable. However, in its response to RAI 2.3.4-CBHVAC-1, the applicant also stated that, 

given the guidance on NEI 95-10, Appendix B, no damper housing, fan housing, and air handling units, including the cooling coils, are found within the license renewal portions of the control 

building HVAC system. The staff disagreed with the applicant's exclusion from an AMR of 

housings for fans, dampers, and air handling units, including cooling coils. The staff's position with 

regard to the treatment of the housings for fans, dampers, and heating and cooling coils is 

discussed in detail in the staff's review of the SGTS in Section 2.3.3 of this SER, which includes 

treatment of the component passive functions of the control building HVAC system. Resolution of 

this issue was part of Open Item 2.3.3.2-2 [2.3.3.2-2(b)]. 

By letter dated June 5, 2001, the applicant provided information regarding the disposition of fans, 

dampers, and heating and cooling coils within the scope of license renewal. Consistent with the 

staff's guidance regarding evaluation of active components, the applicant identified the passive functions of condensing unit shells, damper frames, fan housings, and fan screens in the control 

building HVAC system and added these components to the list of components in the LRA that are 

subject to an AMR. The applicant also identified any aging effects associated with the condensing unit shells, damper frames, fan housings, and fan screens and provided an AMP to manage the 

aging. The applicant added these components to those listed in Tables 2.3.4-20 and 3.2.4-20 in 

the LRA. The staff's review of the aging effects and AMPs for the control building HVAC system 

can be found in Section 3.4.3 of this SER. On the basis of the additional information provided by the applicant, the staff agrees that the condensing unit shells, damper frames, fan housings, and 

fan screens are within the scope of license renewal and subject to an AMR. On the basis of the 

previously noted information, this part of Open Item 2.3.3.2-2 [2.3.3.2-2(b)], as relates to control 

building HVAC system components, is closed. 

Additionally, in a telephone conference held on October 31, 2000, the applicant clarified that the 

LPCI inverter room and the Unit 2 vital A/C room coolers are no longer in scope because of a 

design modification. The applicant committed to provide a description of the design modification 

that clarifies how the modification impacts the LPCI inverter room and Unit 2 vital NC room cooler 

functions. The applicant also committed to address why heating coil housings are not specifically identified in Table 2.3.4-20 of the LRA. The design modification information and the resolution of 

the issue regarding Table 2.3.4-20 were identified as part of Open Item 2.3.3.2-2(b). 

By letter dated June 5, 2001, the applicant provided a description of the design modification that 

clarified how the modification impacts the LPCI inverter room and Unit 2 vital A/C room cooler 

functions. Over a period of time, the LPCI inverters became obsolete and plant design change packages retired the Unit 1 and Unit 2 LPCI inverters. To continue to provide a diverse source of 

power for certain LPCI valves, Unit 2 Class 1 E AC power supplies were selected as the normal 

source of power for the Unit 1 LPCI valves and Unit 1 Class 1 E power supplies were selected as 

the normal source of power for the Unit 2 LPCI valves. The LPCI inverter function (R44-02) was 

removed from scope when the modifications were performed to remove the inverters, effectively 

deleting the function; therefore, the LPCI inverter room cooling function was not included in the 

LRA. By comparison, vital AC is not safety-related, as defined in 10 CFR 54.4(a)(1), its failure

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does not prevent a safety function, as defined in 10 CFR 54.4(a)(2), and it is not required to 

operate during the events defined in 10 CFR 54.4(a)(3). Therefore, as seen in Table 2.2-1 of the 

LRA, this function does not meet the criteria for inclusion within license renewal scope. 

Consequently, the vital AC room cooling function is out of scope for license renewal. The applicant 

also addressed why heating coil housings are not specifically identified in Table 2.3.4-20 of the 

LRA. Control building heating coils are electric and thus, were considered to be active 

components. Consequently, the heating coils were screened out and not included in Table 

2.3.4-20. The duct heater frame was evaluated in the LRA and included in Table 2.3.4-20. The 

applicant provided other clarifications and/or editorial changes, as appropriate. On the basis of the 

additional information provided by the applicant, the staff agrees that the LPCI inverter room and 

Unit 2 vital A/C room cooler functions and the heating coil housings are not within the scope of 

license renewal and not subject to an AMR. On the basis of the previously noted information, this 

part of Open Item 2.3.3.2-2(b), as relates to control building HVAC system components, is closed. 

In RAIs 2.3.4-CBHVAC-2 and 2.3.4-CBHVAC-4, the staff also requested more specific information 

on the (1) description of the areas that constitute the main control room envelope (MCRE) for Units 

1 and 2, and (2) the failure to submit evaluation boundary drawing HL-1 6040 for the control building 

HVAC system. In a letter dated August 29,2000, the applicant responded that the MCRE consists 

of an area located on the 164' elevation of the control building and contains approximately 106,000 

ft3 . This space is enclosed by reinforced concrete walls and floors, and is served by the MCRECS, 

which realigns into a pressurization mode should an accident signal be generated. In this mode, 

the MCRECS is designed to cool and filter the MCRE, thereby maintaining habitability in the control 

room. In the pressurization mode, the return air and outside air are directed through the filtration 

units shown on HL-1 6042 (Zones B-B, 9 and E, F-B, 9). The HVAC equipment required to perform 

this function (Z41-02) is included within the scope of license renewal, and the components subject 

to an AMR are shown on Table 2.3.4-20. With regard to the missing evaluation boundary drawing, 

the applicant provided it separately. In summary, the applicant applied the screening criteria 

prescribed by the Rule in determining the set of long-lived, passive components that are subject 

to an AMR. 

The staff reviewed, and finds acceptable, the applicant's response concerning the MCRE 

description, including the applicant's treatment of those components that are inside the MCRE and 

identified on evaluation boundary drawing HL-1 6040 that are within the scope of license renewal 

and subject to an AMR. 

The staff reviewed Section 2.3.4.20 of the LRA, supporting information in the UFSAR, the 

applicant's responses to the staff's RAIs, and the resolution of Open Item 2.3.3.2-2(b), as provided 

by letter dated June 5, 2001. In addition, the staff sampled several components in the previously 

mentioned evaluation boundary drawings of the LRA to determine whether the applicant properly 

identified the components that are within the scope of license renewal and subject to an AMR. On 

the basis of this review, the staff concludes that the applicant has identified those portions of the 

control building HVAC system that are within the scope of license renewal and subject to an AMR.

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2.3.4.4 Control Rod Drive (CRD) System

Summary of Technical Information in the Application 

The CRD hydraulic system provides pressurized, demineralized water for the cooling and 

manipulation of the CRD mechanisms. In addition, the CRD system provides purge water for the 

reactor water cleanup (RWCU) pump and reactor recirculation pump seals. 

The alternate rod insertion system is a subsystem of the CRD system. It is a backup means of 

scramming the reactor by venting the scram air header. It is completely independent of the reactor 

protection system (RPS), and was installed for the purpose of reducing the probability of an 

anticipated transient without scram (ATWS) event. 

Water enters the CRD system from the condensate header downstream of the condensate 

demineralizers (normal suction) or from the CST (alternate suction). The condensate header is the 

preferred suction source because the water contains less oxygen than water from the CST. 

System Intended Functions 

The CRD system serves the following functions: 

Reactor Scram: The scram mode allows quick shutdown of the reactor by rapidly inserting 

withdrawn control rods into the core in response to a manual or automatic signal. 

Alternate Rod Insertion: Alternate rod insertion reduces the probability of the occurrence 

of a scram event. Signals are provided that respond to an ATWS event or to a manual 

initiation to depressurize the CRD scram pilot valve air header using valves that are 

different from the RPS scram valves, thus providing a parallel path for control rod insertion. 

Component Intended Function 

The components of the CRD system serve the following functions: 

* fission product barrier 

* pressure boundary 

The component groups that are subject to an AMR, as identified in the LRA include the 

accumulator, bolting, piping, rupture disc, and valve bodies. [See request for additional information 

(RAI) 2.3.4-CRD-1.] 

Staff Evaluation 

The CRD hydraulic system provides pressurized, demineralized water for the cooling and 

manipulation of the CRD mechanisms. In addition, the CRD system provides purge water for the 

RWCU pump and reactor recirculation pump seals. 

The alternate rod insertion system is a subsystem of the CRD system, which provides a backup 

means of scramming the reactor by venting the scram air header. It is completely independent of 

the reactor protection system, and was installed reduce the probability of an ATWS event.

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Water enters the CRD system from the condensate header downstream of the condensate 

demineralizers (normal suction) or from the CST (alternate suction). The condensate header is the 

preferred suction source because the water contains less oxygen than water from the CST. 

After completing the initial review, the staff issued RAIs regarding the auxiliary systems. The 

applicant submitted responses to the RAIs, by letter dated August 29, 2000, as discussed below. 

In RAI 2.3.4-CRD-1, the staff stated its belief that the scram discharge volume (SDV) of the CRD 

system (Section 2.3.4 of the LRA) is a passive, long-lived component that meets the requirements 

of 10 CFR 54.4(a) and, therefore, should be subject to an AMR. However, it was not clear in the 

LRA whether the SDV was subject to an AMR. Therefore, the staff requested that the applicant 

clarify whether the SDV is subject to an AMR and, if not, to provide a justification for excluding the 

SDV from an AMR. In response, the applicant confirmed that the SDV components are subject to 

AMR, and clarified that the components are included among those that support CRD intended 

functions as shown in Table 2.3.4-1. During a telephone conference on June 26, 2000, the 

applicant further clarified that the SDV is identified in LRA Table 2.3.4-1 as non-Class 1 stainless 

steel piping. Boundary drawings HL-1 6065 and HL-26007 include the SDV components. 

On the basis of the staff's review of Section 2.3.4.1 of the LRA, and review of the response to the 

staff's RAI, the staff concludes that the applicant identified all of the components of the CRD 

system that are within the scope of license renewal and subject to an AMR. 

2.3.4.5 Cranes. Hoists and Elevators System 

Summary of Technical Information in the Application 

In Section 2.3.4.13 of the LRA, the applicant provides a description of the cranes, hoists, and 

elevators system. The reactor building crane is the only component for this system that is within 

the scope of license renewal. The purpose of the reactor building crane is to provide the capability 

for moving major components for refueling operations and maintenance. The Unit 1 reactor 

building crane provides service to both Units 1 and 2. It has the capability to move loads up to 125 

tons with the main hook. This capability includes the handling of shield plugs, reactor vessel 

heads, drywell heads, steam dryers, steam separators, and the spent-fuel shipping casks. The 

reactor building crane main and auxiliary hooks have an electrical interlock system to prevent their 

potential movement over spent fuel. 

Although the reactor building crane provides the ability to handle the large loads associated with 

refueling operations and maintenance in the reactor building, the only intended function for the 

reactor building crane is that the load-bearing components must maintain their structural integrity. 

The applicant described its process for identifying the mechanical components that are within the 

scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of this 

methodology, the applicant identified the reactor building crane load-bearing components as the 

passive, long-lived portion of the system requiring an AMR. The applicant identified structural steel 

as the only component type that is subject to an AMR, and structural support is the function of this 

component.

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Staff Evaluation

The applicant stated in Section 2.3.4.13 of the LRA that the cranes, hoists, and elevators system is within the scope of license renewal because of the reactor building crane and its intended 

function of handling heavy loads during refueling and maintenance operations. The portions of the 

system that are identified as supporting this intended function are the load-bearing portions of the 

crane. The staff reviewed Section 10.2, "New Fuel Storage," of the Unit 1 UFSAR and Section 9.1, 

"Fuel Storage and Handling," of the Unit 2 UFSAR to verify that the reactor building crane did not 

have intended functions other than the heavy load handling intended function. In addition, the staff 

verified that all of the components that support the heavy load handling intended function were 

identified as being within the scope of license renewal. 

On the basis of the staff's review of the LRA and supporting information in the UFSAR, the staff 

has reasonable assurance that all portions of the cranes, hoists, and elevators system with 

intended functions that meet the criteria in 10 CFR 54.4 are identified as being within the scope of 

license renewal. 

Using the information provided in the LRA, the staff reviewed the application to determine whether 

the applicant properly identified the passive, long-lived components as being subject to an AMR 

in Table 2.3.4-13 of the LRA. The applicant only identified structural steel as being subject to an 

AMR. The extent to which structural steel is within the scope of license renewal for the reactor 

building crane is defined in LRA Section 2.3.4.13 as being the "load-bearing components." On the 

basis of its review, the staff concludes that there is reasonable assurance that the applicant has 

adequately captured the passive, long-lived components under the structural steel category on the 

list of components that are subject to an AMR in Table 2.3.4-13. No omissions were identified. On 

the basis of this review, the staff has reasonable assurance that the applicant has identified the 

components of the cranes, hoists, and elevators system that are subject to an AMR. 

2.3.4.6 Drywell Pneumatics System 

Summary of Technical Information in the Application 

The drywell pneumatic system supplies motive gas to equipment inside the drywell. In 

Section 2.3.4.11 of the LRA, the applicant described the intended functions and listed the 

components of the system that are subject to an AMR. The applicant described its process for 

identifying the mechanical components that are within the scope of license renewal in Section 2.1.2 

and Section 2.1.3, of the LRA. 

In Section 2.3.4.11 of the LRA, the applicant described the purpose of the drywell pneumatic 

system, which is to supply motive gas to equipment inside the drywell, including the reactor 

recirculation system sample line isolation valve, RPV head vent valve, CS system injection testable 

check valves and bypass valves, primary containment chilled water system control valves, RHR 

system LPCI check valves and bypass valves, and nuclear boiler system SRVs and main steam 

isolation valves (MSIVs). A major portion of the drywell pneumatic system is primarily obsolete and 

not currently used. The control air is supplied from the nitrogen makeup system or instrument air. 

The system components still exist in the plant, but are isolated by valve alignment or the lines are 

physically cut and capped. The drywell pneumatic system receives motive gas from the 

Unit 1 or 2 nitrogen storage tanks, the instrument air system, or the emergency nitrogen hookup stations. The system includes an air receiver, particulate filters, flow sensing elements, and various

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process piping, valves, and regulators. Normally, all system equipment upstream of the receiver 

tank is isolated, and system pressure is maintained by the nitrogen backup supply with alternate 

supply through the instrument air supply system. Under emergency conditions, specific 

components in the drywell will be supplied with control air from emergency nitrogen bottles. 

The initial scoping, performed by the applicant on the basis of system functions, determined that 

the intended function of the drywell pneumatic system, P70-01 - Nitrogen supply to Drywell 

Equipment, is within the scope of license renewal. The nitrogen supply to the drywell equipment 

provides the motive gas to various equipment. The nitrogen inerting system (T48) supplies the 

motive gas to the drywell equipment in the drywell during normal operation. After an accident, the 

motive gas to drywell equipment can be provided from either the drywell pneumatic nuclear boiler 

system (B21) accumulator, the nitrogen inerting system, or one of the two nitrogen hookup stations. 

The associated piping, valve bodies, bolting, filter housings, flexible hose, flanges, and tubing are 

identified in Table 2.3.4-11 of the LRA as being within the scope of license renewal and subject to 

an AMR. The component function of all the above components is to serve as a pressure boundary. 

Staff Evaluation 

The staff reviewed the above information related to the drywell pneumatics system to verify that 

the intended functions of the system that are within the scope of license renewal and the 

components that are subject to an AMR have been identified in accordance with the requirements 

of 10 CFR 54.4 and 10 CFR 54.21(a)(1). 

The applicant identified and listed the components that are subject to an AMR for the drywell 

pneumatics system in Table 2.3.4-11 of the LRA using the screening methodology described in 

Sections 2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in 

Section 2.1 of this SER. 

The staff reviewed Section 10.19 of the Plant Hatch Unit 1 UFSAR and Section 9.3.6 of the Unit 2 

UFSAR to determine if there were any system functions that were not identified as intended 

functions in accordance with requirements of 10 CFR 54.4. The staff then reviewed the drawings 

(HL- 16286, HL-1 6299, HL-28023, and HL-26066) to verify that the applicant identified all of the 

components that are within the scope of license renewal in accordance with 10 CFR 54.4. Further, 

the staff verified the accuracy of the drawings and the completeness of LRA Table 2.3.4-11 by 

sampling the components that are adjacent to, but outside, the highlighted portion of the system 

to verify that all of the components that are within the scope of license renewal were included in 

the application. In addition, the staff sampled the components that are within the scope of license 

renewal, but not subject to an AMR, to verify that all of the components that meet the requirements 

of 10 CFR 54.21 (a)(1) were subject to an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified, areas where additional 

information was needed to complete its safety review. The applicant responded to the RAIs in a 

letter dated August 29, 2000. 

Section 2.3.4.11 of the LRA states that the drywell pneumatics system receives motive gas from 

the nitrogen storage tanks. Since the nitrogen storage tanks are passive and long-lived, the staff 

requested, in RAI 2.3.4-DPS-1, that the applicant justify the exclusion of the tanks from Table 

2.3.4-11 from being subject to an AMR. The staff also requested that the applicant identify the

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tanks in applicable drawings. The applicant responded that the nitrogen storage tanks are within 

scope and subject to an AMR, and are included in the primary containment nitrogen inerting 

function (T48-01), in LRA Section 2.3.3.7 and Table 2.3.3-7 (instead of Table 2.3.4-11). The 

nitrogen storage tanks are highlighted on boundary drawings HL-16000 and HL-26083 for the 

primary containment purge and inerting system. The staff confirmed that the "storage tank" is 

listed in Table 2.3.3-7 of the LRA. 

Section 2.3.4.11 of the LRA states that the system includes an air receiver, particulate filters, and 

regulators, among other components. In RAI 2.3.4-DPS-2, the staff requested that the applicant 

justify the exclusion of these components from being subject to an AMR. The applicant responded 

that the air receiver was inadvertently omitted from Table 2.3.4-11. Subsequently, in a telephone 

conference on September 13, 2000, the applicant agreed to add the air receiver to Tables 2.3.4-11 

and 3.2.4-11 as a part of the revision to the RAI response. By letter dated January 31, 2001, the 

applicant provided revised Tables 2.3.4-11 and 3.2.4-11 that included the air receiver. The staff 

noted that the air receiver is identified as a tank in the tables. The staff finds this acceptable. 

The applicant stated that the particulate filters include the filter housing and a filter cartridge. The 

filter housings are included in Table 2.3.4-11. The filter cartridges are consumable items, and, 

thus, short lived. The cartridges are replaced during every refueling outage and, therefore, are not 

subject to an AMR. Regulators are pressure control valves, and are listed in Table 2.3.4-11 as 

"valve bodies." 

Section 9.3.6.3 of the Unit 2 UFSAR states that a backup supply of nitrogen to the drywell is 

provided through three interchangeable nitrogen bottles and a manifold system at one of two 

emergency nitrogen hookup stations. In RAI 2.3.4-DPS-3, the staff requested that the applicant 

justify the exclusion of nitrogen bottles and manifold system from an AMR. The applicant 

responded that the nitrogen bottles are short-lived components and, therefore, not subject to an 

AMR. The nitrogen gas is used up during the course of normal operations. Once the pressure of 

the gas bottle decreases below a predetermined setpoint, the bottle is replaced and returned to the 

vendor. The gas bottles have an inspection interval typically once every 10 years. The manifold 

assembly is subject to an AMR and listed in Table 2.3.4-11 as piping, valves, and flex hoses. 

On the basis of the staff's review of the LRA and associated drawings, the Plant Hatch UFSARs 

for Units 1 and 2, the applicant's responses to RAIs, and information provided in a telephone 

conference on September 13, 2000, and the letter dated January 31, 2001, the staff was unable 

to find any omissions from the components highlighted in the diagrams that identify the function 

level scoping boundaries. The staff also compared the components listed in Table 2.3.4-11 of the 

LRA and those highlighted in the drawings, and found them to be consistent. Therefore, the staff 

concludes that the applicant has adequately identified the components of the drywell pneumatics 

system that are within the scope of license renewal and subject to an AMR. 

2.3.4.7 Emergency Diesel Generators System 

Summary of Technical Information in the Application 

The Hatch emergency diesel generators system is designed to provide onsite emergency backup 

power in the event of a LOOP. In LRA Section 2.3.4.12, "Emergency Diesel Generators System," 

the applicant describes the intended functions and lists the components of the system that are 

subject to an AMR. The applicant described its process for identifying the mechanical components

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that are within the scope of license renewal in Section 2.1.2, "Scoping," and Section 2.1.3, 

"Civil/Mechanical Component Screening," of the LRA. 

In Section 2.3.4.12 of the LRA, the applicant states that the purpose of the diesel generators is to 

provide emergency backup power to 4160-VAC emergency buses E, F, and G in the event of a 

LOOP. The diesel generators are designed to reach rated speed and voltage within 12 seconds 

after receiving a start signal. This allows operation of emergency equipment powered from these 

buses to perform their required function to safely shutdown the plant within the required time. The 

emergency diesel generators (EDGs) provide a highly reliable source of standby, onsite, ac power. There are five diesel generators supplying standby power to emergency buses. Diesel generator 1 B is shared between Units 1 and 2 and has a selector switch with "Unit 1 control" and "Unit 2 

control" positions, depending on whether it is supplying bus 1 F or 2F. 

The initial scoping, performed by the applicant on the basis of functions, determined that the 

intended function of the EDG system, R43-01 - Standby AC Power Supply, is within the scope of 

license renewal. The standby ac power supply provides ac power in the event of a LOOP. The 

EDG load sequencers are included in this function. 

The associated piping, valve bodies, filter housing, flex hose, expansion tank, flexible connector, 

tanks, and restricting orifice are identified in Table 2.3.4-12 of the LRA as being subject to an AMR. 

The intended function of all these components is to serve as a pressure boundary. 

Staff Evaluation 

The staff reviewed the above information to verify that the intended functions of the diesel 

generators system that are within the scope of license renewal and the components that are 

subject to an AMR have been identified in accordance with the requirements of 10 CFR 54.4 and 

10 CFR 54.21(a)(1). 

The applicant identified and listed the components that are subject to an AMR for the diesel 

generators system in Table 2.3.4-12 of the LRA using the screening methodology described in 

Sections 2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in 

Section 2.1 of this SER. 

The staff reviewed Section 8.4 of the Plant Hatch Unit 1 UFSAR and Section 8.3 of the Unit 2 

UFSAR to determine if there were any system functions that were not identified as intended 

functions in accordance with the requirements of 10 CFR 54.4. The staff then reviewed drawings (HL-21074, HL-1 1631 sheet 1 and 2, HL-1 1638 sheets 1 and 2) to verify that the applicant identified all of the components that are within the scope of license renewal in accordance with 10 

CFR 54.4. Further, the staff verified the accuracy of the drawings and the completeness of Table 

2.3.4-12 bysampling the components adjacent to, but outside, the highlighted portion of the system 

to verify that all of the components that are within the scope of license renewal were included in 

the application. In addition, the staff sampled the components that are within the scope of license 

renewal, but not subject to an AMR, to verify that all of the components that meet the requirements 

of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR. 

After the initial review, in a letter of July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAI in a 

letter dated August 29, 2000.

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The staff had asked the applicant to explain the exclusion of the air receivers A005A, A006A, A003A, and A007A, which are highlighted in drawings HL-21074 and HL-1 1631, from being subject 

to an AMR. The applicant responded that air receivers are subject to an AMR, and are listed as 

"tanks" in LRA Table 2.3.4-12. The staff finds this response acceptable. 

The staff asked the applicant to identify components C001 A and C01 OA in drawing HL-1 1631 and 

justify the exclusion of these unnamed components from within the scope of license renewal. The 

applicant responded that C001A and C010A are compressors, which do not perform a passive function. The air receivers, which are within the scope of license renewal, are sized for sufficient 

air to accomplish the five required starts for the intended function. Each diesel generator is supplied with two air receivers. The staff finds this response acceptable. 

In reviewing drawing HL-1 1631, the staff also found that the scavenging air heat exchanger, engine supply header, diesel engine crankcase, and turbo superchargers were highlighted as being within 

the scope of license renewal, but were not included in Table 2.3.4-12 of the LRA, as being subject to an AMR. The staff requested that the applicant justify the exclusion of these components from 

being subject to an AMR. The applicant responded that these components are part of the diesel 

generator, which is an active component. Therefore, the applicant determined that these 

components are not subject to an AMR. 

In reviewing drawings HL-21074, HL-1 1631, HL-1 1638, the staff found that some of the pumps 

were highlighted as within the scope of license renewal, but there are no pumps listed in Table 

2.3.4-12 as subject to an AMR. The staff requested the applicant to explain this discrepancy. The 

applicant explained that on drawings HL-1 1638 (sheets 1 and 2) and HL-1 1631 (sheets 1 and 2), all of the pumps are part of the diesel generator skid. The applicant further stated that the diesel 

generator is an active component and, thus, not subject to an AMR. Therefore, the applicant determined that these pumps, which are part of the diesel generator skid, are also not subject to 

an AMR. However, the pumps that are not part of the diesel generator skid (on drawing HL-21074) 

are subject to an AMR and appear in Table 2.3.4-19 of the LRA for the fuel oil system. The staff 

did not agree that pumps can be excluded from an AMR because they are part of the diesel 

generator skid that constitutes part of a complex assembly. 

In a telephone conference on September 13, 2000, the staff expressed its disagreement with the 

applicant's decision to exclude these components from an AMR simply because these components 

are skid-mounted. The staff requested that the applicant provide additional justification for its 

position. In response, the applicant provided a paper, via e-mail, entitled "Active Assemblies Used 

in License Renewal," dated November 6, 2000. 

The staff reviewed this paper and did not agree with the applicant's basis for excluding skid

mounted components that are part of a complex assembly from an AMR. 

Regarding complex assemblies, NEI 95-10, Revision 0, stated: 

'There are structures and components that, when combined, are considered a complex assembly (e.g., diesel generator starting air skids or heating, ventilating, and air 

conditioning refrigerant units). The Rule and associated SOC do not specifically discuss 

such assemblies. For purposes of performing an aging management review, it is important 

to clearly establish the boundaries for review. An applicant should establish the boundaries 

for such assemblies by identifying each structure or component that makes up the complex

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assembly and determining whether or not each structure and component is subject to an 

aging management review. (See example 5 in Appendix C.)" 

Example 5 in Appendix C of NEI 95-10, Revision 0, provided an example of a control room chiller 

complex assembly and guidance on how to establish the boundaries for such an assembly. It 

notes that once the boundary is determined, long-lived components with a passive function would 

be appropriately subjected to an AMR. 

Components are subject to an AMR if they perform a passive function and are long-lived. A 

passive function is one performed without moving parts or a change in configuration or properties. 

A function performed with moving parts or a change in configuration or properties is considered an 

active function. Components that perform a passive function and are also long-lived must be 

subject to an AMR, whether they are skid-mounted or not. The staff believes that some of the skid

mounted components are long-lived components with a passive function, and therefore are subject 

to an AMR. 

In the staff's evaluation of the Oconee LRA, the staff reached a similar conclusion regarding the 

treatment of the vendor-supplied diesel generator skid-mounted equipment. Duke had drawn a 

boundary around the diesel generator skid and determined that everything within the boundary 

was active and therefore not subject to an AMR. The staff disagreed and noted that the assembly 

included some long-lived components with a passive function which were subject to an AMR. Duke 

subsequently redefined the evaluation boundaries to ensure that long-lived components with a 

passive function on the diesel generator skid were subject to an AMR. 

On this basis, the staff requested that the applicant identify any applicable aging effects associated 

with these components, and any other long-lived components with a passive function associated 

with the emergency diesel generators, and identify AMPs credited with managing the aging effects. 

This was identified as part of Open Item 2.3.3.2-1 (2.3.3.2-1 (b)). 

By letter dated June 5, 2001, the applicant provided additional information. The EDGs include 

three subsystems that contain components that are passive and long-lived, and that perform a 

component function that supports the system intended function of standby ac power supply (R43

01). The subsystems are the diesel jacket water cooling subsystem, the diesel lubricating oil 

subsystem, and the scavenging air subsystem. The evaluation boundary for the extended set of 

skid-mounted components ends at the engine block and does not include the active portion of the 

diesel. On the basis of the above information, the applicant identified the following skid-mounted 

components that are subject to an AMR and listed in Table 2.3.4-12 of the LRA: bolting, heater 

housing, heat exchanger shell, heat exchanger tubes (piping), piping/tubing, pump casing, 

restricting orifice, strainer casing, strainer element, and valve bodies. The applicant also stated 

that aging management of these components would be accomplished with the torque activities, 

protective coatings, and diesel generator maintenance activities AMPs. The staff's review of the 

AMPs can be found in Section 3.1 of this SER. Staff evaluation of the applicants aging 

management activities for these components can be found in Section 3.4.3 of this SER. The staff 

finds this response acceptable, and considers Open Item 2.3.3.2-1 (b) closed. 

On the basis of the staff's review of the LRA and associated drawings, the Plant Hatch Unit 1 and 

2 UFSARs, and the applicant's responses to RAIs and Open Item 2.3.3.2-1 (b), the staff concludes 

that the applicant has identified the components of the emergency diesel generator system that are 

within the scope of license renewal and subject to an AMR.

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2.3.4.8 Fire Protection

Summary of Technical Information in the Application 

In Section 2.3.4.18, "Fire Protection System [X43]," of the Plant Hatch LRA, the applicant described 

the components of the fire protection system that are within the scope of license renewal and 

subject to an AMR. The staff reviewed this section of the LRA to determine whether there is 

reasonable assurance that all systems, structures, and components (SSCs) have been identified 

as being within the scope of license renewal, as required by 10 CFR 54.4(a), and that all components that are subject to an AMR have been identified, as 

required by 10 CFR 54.21(a)(1). 

By letter dated August 29, 2000, the applicant responded to the staff's requests for additional 

information (RAIs) regarding the fire protection systems and components. In addition, the applicant provided additional information for the fire protection system during telephone conferences, which 

are documented in summaries dated September 12 and 28, 2000, October 1, 2000 (by email), October 13, 2000 (by email), and November 15, 2000. 

Structures and mechanical systems that are relied upon to perform or support performance of a 

function that demonstrates compliance with the Commission's regulations described in 

10 CFR 54.4(a)(3) are within the scope of license renewal. 10 CFR 54.4(a)(3) requires that all 

SSC's that are relied upon in safety analyses or plant evaluations to demonstrate compliance with 

the Commission's regulations in 10 CFR 50.48, be included within the scope of license renewal. 

10 CFR 50.48 requires that the applicant implement and maintain a fire protection program. The 

fire protection system is relied upon to meet the requirements of 10 CFR 50.48. At Plant Hatch, the fire hazards analysis (FHA) is the focal point for information on how regulatory commitments 

are met through analyses and plant evaluations. 

The purpose of the fire protection program at Hatch is to ensure, through defense-in-depth design, that a fire will not prevent the necessary safe plant shutdown functions from occurring. The 

defense-in-depth principle is aimed at achieving an adequate balance in these areas along with the 

following functions: 

prevent fires from starting 

detect fires quickly and rapidly suppress fires that occur and limit their damage 

design plant safety systems so that a fire that starts in spite of the fire protection program and burns for a significant period of time will not prevent essential plant safety functions 

from being performed. 

The initial scoping at Plant Hatch was performed on the basis of functions. The intended functions 

shown in LRA Section 2.3.4.18 are associated with the fire protection system. The following fire 

protection intended functions are within the scope of license renewal: 

* X43-01 - Cardox Fire Suppression for EDGs 

* X43-04 - Plant Wide Fire Suppression With Water 

* X43-06 - Fire Detection 

o X43-07 - Penseals and Fire Barriers for Preventing Fire Propagation

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* X43-08 - Manual Carbon Dioxide Fire Protection 

* X43-10 - Cardox Fire Suppression for the Computer Room 

In Table 2.3.4-18 of the LRA, the applicant identifies components that support the fire protection 

system [X43] intended functions that are within the scope of license renewal and subject to an 

AMR. The fire protection components that provide only a pressure boundary function that are 

identified in Table 2.3.4-18 are bolting, fire hydrants, fittings, fusible material, pilot valves, pipe line 

strainers, piping, pump casings, sprinkler head bulbs, sprinkler head links, strainer basket, tanks, 

tubing, tubing fittings, and valve bodies. In response to Part 7 of RAI-2.3.4-FPS-3, the applicant 

clarified in that the passive, long-lived components for hose stations are included in Table 2.3.4-18 

as piping, valves, and nozzles. 

The fire protection components that provide only a fire barrier function that are identified in Table 

2.3.4-18 are fire doors, Kaowool and hold-down straps, and penetration seals. 

Fire protection components that provide only a flow restriction function are nozzles. Restricting 

orifices provide both a pressure boundary and flow restriction function. The sprinkler heads provide 

a flow direction, pressure boundary, and flow restriction function. The tank insulation provides an 

environmental control function. 

Staff Evaluation 

The Commission's regulations in 10 CFR 54.21 (a)(1), state that for those SSCs that are within the 

scope of this part, as delineated in 10 CFR 54.4, the integrated plant assessment (IPA) must 

identify and list those SCs that are subject to an AMR. The staff reviewed Section 2.3.4.18 of the 

LRA, as supplemented by telephone conferences that are documented in summaries dated 

September 12 and 28, 2000, October 1, 2000 (by email), October 13, 2000 (by email), and 

November 15, 2000, to determine whether there is reasonable assurance that the applicant has 

appropriately identified the components and supporting systems that serve fire protection-intended 

functions, and are within the scope of license renewal in accordance with 10 CFR 54.4, and are 

subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). 

This evaluation is to determine whether the applicant has properly identified, for the fire protection 

system, the components that are within the scope of license renewal. The staff will then determine 

if the components which are within the scope of license renewal were properly identified by the 

applicant as being subject to an AMR. 

In response to RAI 2.3.4-FPS-1, the applicant stated that Plant Hatch was docketed before July 1, 

1976, and that the applicable regulatory requirements for the fire protection program were 

contained in Appendix A to Branch Technical Position (BTP) APCSB 9.5-1, "Fire Protection for 

Nuclear Power Plants," and Section 11l.G, Ill.J, and Ill. L of Appendix R. The applicant primarily used 

the FHA as the primary information source during the scoping process forfire protection SSCs. The 

FHA contains the analyses to demonstrate compliance with Appendix R and Appendix A to BTP 

9.5-1. The applicant searched its FHA for commitments made to meet 10 CFR 50.48 (including 

compliance with Appendix R and Appendix A to BTP 9.5-1) and stated that any structures or 

components that are relied upon for meeting the regulatory commitments are included within the 

scope of license renewal.

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The staff sampled portions of the FHA, which contains plant commitments and safety evaluations 

that form the basis of the fire protection program at Plant Hatch. The staff then compared a sample of the fire protection systems and components identified within the FHA to the fire protection 

system flow diagrams to verify that required components were identified within the evaluation 

boundaries of the flow diagram and were not excluded from the scope of license renewal. The staff 

also compared SSCs identified in NRC-approved SERs, which document Plant Hatch's compliance with the provisions of Appendix A to BTP 9.5-1, to the fire protection system flow diagrams to verify 

if there were additional portions of the fire protection system that were excluded from the scope of 

license renewal. As part of the evaluation, the staff also reviewed the same flow diagrams for the 

fire protection system to determine if there were any additional portions of the system piping or 

components located outside of the evaluation boundary, with intended functions that should have 

been identified as being within the scope of license renewal. 

In accordance with 10 CFR 50.48(b), only the requirements of Sections Ill.G, Ill.J, and 111.0 in 

Appendix R to 10 CFR Part 50 were backfit to all nuclear plants to the extent that fire protection 

features proposed or implemented by the applicant have been accepted by the staff as satisfying the provisions of Appendix A to BTP 9.5-1, as reflected in staff fire protection safety evaluation 

reports. The staff was concerned that the applicant had excluded from its component database fire 

protection components that were identified in an NRC-approved SER dated October 4, 1978. This 

SER documents Plant Hatch's compliance with Appendix A to BTP 9.5-1. During telephone conferences on September 13 and September 28, 2000, the staff questioned whether the fire 

protection SSCs identified in the SER dated October 4, 1978, were evaluated during the scoping 

process. During the scoping inspection on September 11-15,2000, the applicant provided the NRC 

inspector with its license renewal docketed correspondence list. This list shows all of the 

documents that the applicant reviewed for the scoping of fire protection SSCs. The staff noted that 

this list did not include any SERs before 1982, which show compliance to Appendix A to BTP 9.5-1. 

In a telephone conference, documented in a summary dated November 15, 2000, the applicant agreed to identify the path that shows how the components from the 1978 SER were captured in 

the FHA for compliance with Appendix A to BTP 9.5-1. The applicant referred the staff to a letter, 

with an accompanying SER, from NRC to Georgia Power Company dated November 24, 1986. 

On page 2 of the SER for the November 1986 letter, proposed change 1 was accepted, and the 

NRC stated "the applicant's compliance with the staff's SER [dated October 4, 1978] is now 

documented in Section 9.4, Appendix D, of the FHA." On the basis of this SER, the applicant has 

appropriately demonstrated to the staff how they were able to include components from the 1978 

SER in the scoping methodology by using the FHA as the primary scoping document for fire 

protection. 

The staff reviewed the SER dated October 4, 1978 to ensure that it did not require the fire 

protection components that are excluded from the scope of license renewal on the basis of the 

applicant's evaluation of the FHA, to meet BTP 9.5-1. Fire protection components listed in the SER 

dated October 4, 1978, which were initially excluded from the scope of license renewal, include the 

control building 112' elevation suppression system for protection of the lube oil tanks and the fire 

hydrants required for compliance with 10 CFR 50.48. After the staff's scoping inspection, the 

applicant designated these components as being within scope and revised plant documentation 

to show that they are required for compliance with 10 CFR 50.48 and are included within the scope 

of license renewal and are subject to an AMR. 

The staff was concerned that the Unit 2 remote shutdown panel (RSP) halon suppression system and the radwaste fire suppression system appeared to have fire protection intended functions that

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are required for compliance with 10 CFR 50.48, but were not included within the scope of license 

renewal and were not identified as being subject to an AMR. 

The Unit 2 remote shutdown panel halon suppression system is identified in the LRA as fire 

protection intended function X43-02. However, the associated flow diagram (HL-50048) shows that 

components that support the halon system were removed from the scope of license renewal. In 

response to RAI 2.3.4-FPS-5, the applicant stated that at the time of submittal of the LRA, the RSP 

halon suppression system was within the scope of license renewal. However, an FHA change 

physically removed this system from the plant. After questioning the applicant on these findings, 

the applicant provided a 10 CFR 50.59 evaluation, entitled "Licensing Document Change Request 

99-181, Revision 0," dated November 19, 1999, and FHA revision 18C. These documents 

analyzed the removal of the RSP halon fire suppression system from regulatory requirements, and 

provided the rationale for the decision. During the scoping inspection, the inspector questioned the 

appropriateness of using the 10 CFR 50.59 process to remove the regulatory requirement and the 

physical function of originally installed fire protection equipment without a prior Staff review. In an 

SER dated April 18, 1984 (located in FHA Section 9.3, Appendix C) the staff approved several 

exemptions from Sections III.G.3 and III.L of Appendix R to 10 CFR 50.48. Page 16 to Enclosure 

2 of the SER, "RB South of Column Line R19-U2" states that the staff was concerned that for 

locations where components for redundant shutdown pathways were either not separated by the 

water curtain or were located in close proximity to each other on either side of the curtain, a fire 

would cause damage to both, such as RSPs 2C82-P001A and lB. Since the applicant protected 

these panels by non-combustible barriers, an automatic halon fire suppression system, and fire 

detectors, the staff concluded that the existing fire protection, with the proposed modifications, 

would achieve an acceptable level of safety to that provided by Section Ill.G.2 and granted the 

applicant's exemption. Furthermore, in the applicant's letter of July 22, 1986, Section 4.11 of the 

FHA states that 'The Unit 2 RSP is also equipped with an internal Halon 1301 fire suppression 

system." 

During the NRC's scoping inspection, the applicant clarified that it had performed a detailed circuit 

analysis to demonstrate that the halon system was no longer required to protect the remote 

shutdown panel and meet Appendix R requirements. Also, the staff determined that the applicant 

had applied the 10 CFR 50.59 process appropriately in making the determination to remove the 

RSP halon fire suppression system from regulatory requirements. On this basis, the staff 

concluded that since the halon suppression system was no longer required to meet the applicant's 

CLB for fire protection, the halon suppression system was not required to be included within the 

scope of license renewal. 

In its docketed response to RAI-2.3.4-FPS-8, the applicant states that the radwaste fire 

suppression system was excluded from the scope of license renewal on the basis that the system 

was not included in the regulatory requirements because it is not relied upon in FHA Section 9.2, 

Appendix B. The staff disagrees that the fire suppression systems for the radwaste building are 

not included in the regulatory requirements for Plant Hatch. 

In an NRC-approved SER dated October 4, 1978, the staff reviewed the design criteria and bases 

for the water suppression systems in various areas that were approved to meet the guidelines of 

Appendix A to BTP 9.5-1. The radwaste building was one of the plant areas listed, which was 

equipped with an automatic suppression system. Furthermore, the applicant's October 1976 FHA 

to the staff (which the staff used as the basis for SER dated October 4, 1978) states that there is 

an automatic deluge system provided for dry waste storage and charcoal filters. This follows the

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guidance of Section F.14 of Appendix A to BTP 9.5-1, which states that the radwaste building 

should have automatic sprinklers in all areas where combustible material is located. The scope of components required to satisfy 10 CFR 50.48 includes those components that are required for 

compliance with Appendix A to BTP 9.5-1. 

By letter dated November 24, 1986, the staff approved a license amendment for Plant Hatch in 

accordance with Generic Letter 86-10, "Implementation of Fire Protection Requirements." The 

amendment revises the Technical Specification (TS) for Units 1 and 2 to relocate the fire protection surveillances to the FHA. It also states that the applicant's compliance with Appendix A to BTP 9.5

1, as shown in the staff's SER dated October 4, 1978, is now documented in FHA Section 9.4, 

Appendix D. The FHA submitted to the staff at the time of the license amendment is dated July 22, 1986. Furthermore, in Proposed Change 1 to the license amendment safety evaluation dated 

November 24, 1986, the staff states that this change also deletes the requirement to complete all 

modifications identified in the NRC's SER dated October 4, 1978. In accordance with the SER 

dated October 4, 1978, the radwaste building suppression system was already installed to satisfy 

Appendix A to BTP 9.5-1. 

As mentioned above, Plant Hatch's compliance with Appendix A to BTP 9.5-1 is documented in 

FHA Section 9.4, Appendix D. With respect to the radwaste building, the staff reviewed the Plant 

Hatch FHA dated July 22, 1986, and concluded that fire suppression for certain areas in the 

radwaste building were included in the 1986 FHA. Specifically, Section IV.B.4.d of the FHA states 

that "fixed automatic water spray systems are installed in all charcoal filters in the plant." The 

radwaste building contains charcoal filters that are protected by fixed sprinkler systems. Therefore, 

the fire suppression piping leading to the charcoal filters, including the nozzles and sprinkler heads, 

should be included within the scope of license renewal and subject to an AMR. 

In addition, Section IV.D of the FHA states that the guidelines for specific plant areas is presented 

for each specific plant area throughout the FHA. In both the June 1986 and July 1987 revisions 

to the FHA, the FHA analysis of fire area/zone 2301 (Radwaste Building - All Elevations) states 

that, "all sections of this area which contain specific fire hazards (charcoal filters) or high concentrations of combustibles (dry waste storage area, Radwaste Control Room) are equipped with detection, suppression, or both." Specifically, the west central portion of fire zone 2301 J over 

the drywaste storage section is equipped with a wet pipe suppression system. To the staff's 

knowledge, the applicant has not submitted any information to show that the radwaste suppression 

system has been physically removed or altered so that it can't perform its intended function, and 

that no plant evaluations through 10 CFR 50.59 have determined that this suppression system is 

no longer required for compliance with Appendix A to BTP 9.5-1. 

It was the staff's view that the radwaste suppression system should be included within the scope 

of license renewal and subject to an AMR. This issue was identified as Open Item 2.3.4.2-1. 

After reviewing the Plant Hatch Fire Hazards Analysis (FHA) dated July 22, 1986, the staff raised 

a concern with the applicant's exclusion of the radwaste fire suppression system from within the 

scope of license renewal. The radwaste building contains charcoal filters which are protected by fixed sprinkler systems. Section IV.B.4.d of the FHA states that "fixed automatic water spray 

systems are installed in all charcoal filters in the plant". In addition, Section IV.D of the FHA states 

that the guidelines for specific plant areas are presented for each specific plant areaothroughout the FHA. In both the June, 1986 and July, 1987 revisions to the FHA, the FHA analysis of fire 

area/zone 2301 (Radwaste Building - All Elevations) states that, "all sections of this area which

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contain specific fire hazards (charcoal filters) or high concentrations of combustibles (dry waste 

storage area, Radwaste Control Room) are equipped with detection, suppression, or both." 

Specifically, the west central portion of fire zone 2301J over the drywaste storage section is 

equipped with a wet pipe suppression system. 

In response to the staff's concern, the applicant responded in a letter dated June 5, 2001, that the 

radwaste building fixed fire suppression has been included in scope for license renewal and is 

subject to an AMR. No new component types, component materials, or internal or external 

environments result from this scope change. In addition, the following evaluation boundary 

drawings were revised or created to reflect the change in scope: 

HL-11034 HL-11901 

HL-11304, Sheet 7 HL-11905 

HL-11304, Sheet 8 HL-11909 

HL-11869 HL-21017 

HL-11873 HL-21197 

HL-11874 HL-21342 

HL-11875 HL-26372 

The staff's review of the aging effects associated with these components can be found in Section 

3.4.3 of this SER. The staff is satisfied with the applicant's resolution of this issue and Open Item 

2.3.4.2-1 is closed. 

After the staff determined which components were within the scope of license renewal, the staff 

determined whether the applicant properly identified the components subject to an AMR from 

among those identified as being within the scope of license renewal. The staff reviewed selected 

components that the applicant identified as being within the scope of license renewal to verify that 

the applicant had identified these components as subject to an AMR if they perform intended 

functions without moving parts or without a change in configuration or properties, and are not 

subject to replacement on the basis of a qualified life or specified time period. 

The staff reviewed mechanical components on flow diagrams and compared them to the list of 

components with intended functions that the applicant presented in Table 2.3.4-18 of the LRA, to 

verify that there were no omissions of passive, long-lived components that were subject to an AMR. 

The staff was concerned that the applicant's sprinkler head visual inspections would not be 

sufficient for an AMP throughout the period of extended operation and asked the applicant, in RAI 

2.3.4-FPS-10, to discuss whether NFPA 25, Section 2.3.3.1, "Sprinklers," would be implemented 

at Plant Hatch. The staff's evaluation of this issue can be found in Section 3.1.18 of this SER. 

In addition, the staff asked the applicant to justify the exclusion of fire extinguishers, air packs, and 

CO2 hoses from an AMR. The applicant provided justification in an email to the staff dated October 

13, 2000, to support that these components are short-lived and, therefore, by 10 CFR 54.21, are 

excluded from an AMR. The applicant considers that these components are short-lived, given the 

replacement intervals established by plant procedures. CO2 fire extinguishers are replaced every 

5 years, dry chemical fire extinguishers are replaced every 12 years, air packs are replaced every 

15 years, CO2 hoses are replaced every 5 years. The plant procedures also specify inspection and 

testing intervals. Water hoses are routinely monitored gor condition and performance, and are 

replaced on the basis of degradation criteria specified in a site-approved procedure. By plant 

procedure, water hoses are to be unracked, visually inspected, and hydrostatically tested every 2

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years. Water fire hoses that do not meet the inspection or hydrostatic test criteria are replaced. Water hoses were inadvertently omitted from LRA Table 3.2.4-18. On the basis of the information 

provided by the applicant and summarized above, the staff concludes that the applicant has 

provided an acceptable basis to exclude these components from an AMR. 

The staff did not find any other omissions of long-lived, passive components with intended 

functions. 

On the basis of its review of the information presented in Section 2.3.4.18 of the LRA, the 

applicant's responses to the staff's RAIs, additional information provided in telephone conferences 

between the staff and the applicant, and resolution of Open Item 2.3.4.2-1, the staff concludes that 

there is reasonable assurance that the applicant has identified those portions of the fire protection 

system that are within the scope of license renewal and subject to an AMR. 

2.3.4.9 Fuel Oil System 

Summary of Technical Information in the Application 

The fuel oil system is designed to receive, store, and supply fuel oil to the diesel generator system. 

In Section 2.3.4.19, "Fuel Oil System," of the LRA, the applicant described the intended functions 

of the system, and listed the components that are subject to an AMR. The applicant described its 

process for identifying the mechanical components that are within the scope of license renewal in 

Section 2.1.2, "Scoping," of the LRA and and those that are subject to an AMR in Section 2.1.3, 

"Civil/Mechanical Component Screening," of the LRA. 

In Section 2.3.4.19 of the LRA, the applicant states that the function of the fuel oil system is to 

receive, store, and supply fuel oil to the diesel generator system. Diesel engine fuel for Hatch Units 

1 and 2 is stored in five interconnected buried tanks. Diesel fuel is transferred to the engine day tanks using dedicated, redundant transfer pumps and piping. The diesel fuel storage tanks are 

filled by gravity from a truck connection through a common header. Two of the buried tanks are 

dedicated to each of the Unit 1 and Unit 2 diesel generators. The remaining tank is used to supply the swing diesel (1 B) to serve either Unit 1 or Unit 2. The fuel oil system transfer pumps operate 

continuously on demand from the day tank level controllers. Tank levels are monitored and 

alarmed (low level) in the main control room (MCR). 

The initial scoping, performed by the applicant on the basis of functions, determined that the 

intended function of the fuel oil system, Y52-01 - Emergency Diesel Generator (EDG) Fuel Oil 

Supply, is within the scope of license renewal. The EDG fuel oil system provides a 7-day supply of fuel oil to the diesels in the event of a LOOP. The availability of the storage tanks is needed for 

an extended duration LOOP, which is a risk-significant event. The components associated with 

this function include the fuel oil supply piping, instrumentation, and valves in the piping from the fuel 

oil pumps to the EDGs. 

The associated piping, valve bodies, bolting, discharge head, flex hose, manway shell, pump, strainer basket, and tank are listed in Table 2.3.4-19 of the LRA as being subject to an AMR. The 

component functions for the manway shell and strainer basket is to provide shelter/protection, and 

the function for the piping, valve bodies, bolting, discharge head, flex hose, pump, and tank is to 

serve as the pressure boundary.

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The staff reviewed the above information to verify that the intended functions of the fuel oil system that are within the scope of license renewal and the components that are subject to an AMR have 

been identified in accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). 

The applicant identified and listed the components that are subject to an AMR for the fuel oil 

system in Table 2.3.4-19 of the LRA using the screening methodology described in Sections 2.1.2 

and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in Section 2.1 of this 

SER. 

The staff reviewed Section 8.4 of the Plant Hatch Unit 1 UFSAR and Section 9.5.4 Unit 2 UFSAR 

to determine if there were any system functions that were not identified as intended functions in 

accordance with requirements of 10 CFR 54.4. The staff then reviewed drawings (HL-1 1037, HL

11631 sheet 2, HL-1 1638 sheet 2, and HL-21074) to verify that the applicant identified all of the 

components that are within the scope of license renewal in accordance with 10 CFR 54.4. Further, 

the staff verified the accuracy of the drawings and the completeness of LRA Table 2.3.4-19 by sampling the components adjacent to, but outside, the highlighted portion of the system to verify that all of the components that are within the scope of license renewal were included in the 

application. In addition, the staff sampled the components that are within the scope of license 

renewal, but not subject to an AMR, to verify that all of the components that meet the requirements 

of CFR 54.21 (a)(1) were subject to an AMR. 

After the initial review, the staff had a few questions in identifying components in the drawings. In 

a telephone conference on July 6, 2000, the applicant responded to the staff's questions by 

clarifying the information and identifying all of the fuel oil storage tanks in the drawings (HL-1 1037 

and HL-21074) so that the staff was able to complete its review. 

On the basis of the staff's review of the LRA and associated drawings, the Plant Hatch Units 1 and 

2 UFSAR, and the applicant's responses in the telephone conference, the staff was unable to find 

any omissions from the components highlighted in the diagrams that identify the function-level 

scoping boundaries. The staff also compared the components listed in Table 2.3.4-19 of the LRA 

and those highlighted in the drawings, and found them consistent. 

On the basis of the review described above, the staff has determined there is reasonable 

assurance that the applicant has adequately identified the intended functions of the fuel oil system 

that are within the scope of license renewal in accordance with the requirements of 10 CFR 54.4 

and those that are subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1). 

2.3.4.10 Instrument Air System 

Summary of Technical Information in the Application 

The instrument air system provides dried and filtered air to all of the air-operated instruments and 

valves throughout the entire plant (with the exception of equipment inside the drywell). In Section 

2.3.4.9, "Instrument Air System," of the LRA, the applicant described the intended functions and 

listed the components of the system that are subject to an AMR. The applicant described its 

process for identifying the mechanical components that are within the scope of license renewal in 

Section 2.1.2, "Scoping," and Section 2.1.3, "Civil/Mechanical Component Screening," of the LRA.

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In Section 2.3.4.9 of the LRA, the applicant states that the purpose of the instrument air system 

is to provide dried and filtered air to all of the air-operated instruments and valves throughout the 

entire plant (with the exception of equipment inside the drywell). The instrument air system is 

divided into the following two subsystems: 

The noninterruptible system provides instrument air for the operation of certain emergency 

system components. 

The interruptible system provides instrument air to all other components not supplied by the 

noninterruptible system. 

The drywell pneumatic system supplies the motive gas for components within the drywell. The 

requirements for the remainder of the compressed air systems are supplied by three oil-free screw

type compressors. Two of these air compressors have a capacity of 500 SCFM, and one has a 

capacity of 700 SCFM. During normal operation, the 700 SCFM compressor supplies all instrument 

air and high-pressure service air requirements outside of the drywell with one of the two 500 SCFM 

compressors on automatic standby and the other (which requires operator action for start) in the 

backup mode. Each compressor discharges into an air receiver, which in turn discharges into a 

common manifold that feeds the instrument and service air systems. 

The initial scoping, performed by the applicant on the basis of functions, determined that the 

intended function of the instrument air system, P52-01 - Noninterruptible Essential Instrument Air 

Supply, is within the scope of license renewal. The noninterruptible essential instrument air supply 

includes the instrument air system downstream of the noninterruptible essential instrument air 

check valves, and includes the nitrogen backup supply valves. The P52 system is fed from the P51 

air compressors under normal operating conditions, and has a nonredundant backup of the safety

related nitrogen distribution system. The noninterruptible portion of the instrument air system 

services certain valves in emergency systems for which operation is desirable, although not 

essential, following a loss of pressure in the service air or interruptible portion of the instrument air 

system. 

The associated piping, valve bodies, bolting, hose, pressure regulator and tubing are identified in 

Table 2.3.4-9 of the LRA as being within the scope of license renewal and subject to an AMR. The 

component function for these components is to serve as a pressure boundary. 

Staff Evaluation 

The staff reviewed the above information to verify that the intended functions of the instrument air 

system that are within the scope of license renewal and the components that are subject to an AMR 

have been identified in accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(1). 

The applicant identified and listed the components that are subject to an AMR for the instrument 

air system in Table 2.3.4-9 of the LRA using the screening methodology described in Sections 

2.1.2 and 2.1.3 of the LRA. The screening methodology is evaluated by the staff in Section 2.1 of 

this SER. 

The staff reviewed Section 10.11 of the Plant Hatch Unit 1 UFSAR and Section 9.3.1 of the Unit 2 

UFSAR to determine if there were any system functions that were not identified as intended 

functions in accordance with requirements of 10 CFR 54.4. The staff then reviewed drawings (HL2-81
16299, HL-1 1667, HL-16251, HL-28023, HL-26064, HL-26070) to verifythat the applicant identified 

all of the components that are within the scope of license renewal in accordance with1 0 CFR 54.4. 

Further, the staff verified the accuracy of the drawings and the completeness of Table 2.3.4-9 by sampling the components adjacent to, but outside, the highlighted portion of the system, to verify that all of the components that are within the scope of license renewal were included in the 

application. In addition, the staff sampled the components that are within the scope of license 

renewal, but not subject to an AMR, to verify that all of the components that meet the requirements of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAI in a 

letter dated August 29, 2000. 

Section 9.3.1.2 of the Unit 2 UFSAR states that the instrument air system includes an air dryer and 

two 100 percent-capacity pre- and after-filters connected in parallel. The staff requested that the 

applicant justify the exclusion of the air-dryer, pre- and after-filters from LRA Table 2.3.4-9 from 

being subject to an AMR. The applicant responded that the only equipment that is within the scope of license renewal are the gas accumulators and the associated piping and valves. During normal 

operation, the accumulators are filled with dry nitrogen. The accumulators can be used following 

a design-basis accident to provide additional operational flexibility for certain air-operated valves. 

The air dryer, pre-filters, and after-filters are located in the portion of the system that is not 

associated with the accumulators and are not relied upon to perform a safety function. 

Since the accumulators are within the scope of license renewal and subject to an AMR, the staff 

asked the applicant why the accumulators are not listed in Table 2.3.4-9 as being subject to an 

AMR. The applicant stated that the accumulators are listed in the table as "air receivers." 

On the basis of the staff's review of the LRA and associated drawings, the Plant Hatch Unit 1 and 

2 UFSAR, and the applicant's responses to RAIs, the staff was unable to find any omissions from 

the components highlighted in the diagrams that identify the function-level scoping boundaries. 

The staff also compared the components listed in Table 2.3.4-9 of the LRA and those highlighted in the drawings, and found them to be consistent. 

On the basis of the review described above, the staff has determined that there is reasonable 

assurance that the applicant has adequately identified the intended functions of the instrument air 

system that are within the scope of license renewal in accordance with the requirements of 10 CFR 

54.4, and those that are subject to an AMR in accordance with the requirements of 10 CFR 

54.21 (a)(1). 

2.3.4.11 Insulation 

Summary of Technical Information in the Application 

The intended function of insulation is to retain heat in process piping and equipment in various 

locations outside the drywell, prevent moisture from condensing on cold surfaces, protect equipment and personnel from high temperatures, prevent piping from freezing in cold areas of the 

plant, and protect heat tracing from damage. The application further states that heat tracing with 

insulation is required for the standby liquid control system to operate in order to meet ATWS 

requirements. Insulation is also credited in heat load calculations for safety-related rooms. Failure

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of piping insulation in safety-related rooms could allow the heat load of the room to exceed the 

capability of the HVAC system, thereby exceeding the design temperature of the room. The 

insulation intended function can be more concisely stated as minimizing heat transfer between 

process piping and the environment and protecting heat tracing on piping. 

The applicant provided eight drawings for Unit 1 and six drawings for Unit 2 that had intended 

function designations marked on the drawings to indicate piping insulation that is within the scope of license renewal. These drawings are DL-1 1001, DL-1 1004, HL-1 1033 (sheet 1), HL-1 1600, HL

16061, HL-16332, HL-16334, HL-16016, HL-21033, HL-21039, HL-26009, HL-26020, HL-26046, and HL-26023. The applicant described its process for identifying the mechanical components that 

are within the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the 

basis of this methodology, the applicant identified insulation in various areas outside the drywell 

as the passive, long-lived portion of the system that requires an AMR. The six component types that were identified as being subject to an AMR include the aluminum jacket, insulation, insulation 

bolting (galvanized steel), insulation bolting (stainless steel), stainless steel jacket, and wire. The 

applicant identified environmental control as the function of these components. 

Staff Evaluation 

In Section 2.3.4.3 of the LRA, the applicant states that insulation in various locations outside the 

drywell is within the scope of license renewal because of its intended function. Specifically, the 

applicant identified the intended functions of insulation as retaining heat in process piping and 

equipment, preventing condensation on cold surfaces, protecting equipment and personnel from 

high temperatures, preventing freezing in cold areas of the plant, and protecting piping heat tracing. The applicant provided eight drawings for Unit 1 and six drawings for Unit 2 that had intended 

function designations to indicate piping and equipment insulation that is within the scope of license 

renewal. These drawings are DL-1 1001, DL-1 1004, HL-1 1033 (sheet 1), HL-1 1600, HL-1 6061, HL

16332, HL-16334, HL-16016, HL-21033, HL-21039, HL-26009, HL-26020, HL-26046, and HL

26023. The staff reviewed these drawings to ensure that the in-scope insulation was appropriately identified on the drawings. The staff sampled portions of the systems in these drawings that did 

not have insulation identified as in scope to verify that the insulation in these areas did not perform 

an intended function. The staff compared the drawings with the system descriptions in the UFSAR, LRA, and Technical Specifications to ensure that intended functions were not performed by insulation that was not identified as being within the scope of license renewal. Examples of written 

descriptions and technical requirements that were reviewed by the staff include: 

Sections 3.6.1.5 and B3.6.1.5, "Drywell Air Temperature," of the Unit 2 Technical 

Specifications 

Sections 9.4.2.2.3, "ECCS Room Coolers," and 4.2.3.4, "SLCS," of the Unit 2 UFSAR 

Sections 2.3.4.1, "Control Rod Drive (CRD) System," 2.3.3.5, "Reactor Core Isolation 

Cooling System (RCIC)," and 2.3.4.15, "Reactor Building HVAC System" of the LRA 

On the basis of the staff's review of these documents and drawings, the staff identified several 

questions that were forwarded as RAIs to the applicant by letter dated July 14, 2000. The following additional information was provided by the applicant in their RAI response dated August 29, 2000:

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* The insulation on heat bearing piping and equipment located in the Unit 1 and 2 RHR, CS, 

and HPCI rooms is within the scope of license renewal. 

* Although the insulation on heat-bearing piping and equipment located in the RCIC pump 

room is not required to be within the scope of license renewal, it is conservatively included 

within scope. 

0 The insulation on heat-bearing piping and equipment located in the CRD pump room is not 

credited in the sizing of the room coolers and, therefore, is not within the scope of license 

renewal. 

0 Insulation that is within the scope of license renewal and located on outdoor piping to 

prevent freezing ceases to be in scope when the piping passes into either an 

environmentally controlled atmosphere or underground. 

a Large-bore piping (12-inch diameter or greater) located outdoors, the condensate storage 

tank, and the fire protection storage tanks are not insulated per plant design. 

0 The SLC tank is insulated, but the insulation is not within the scope of license renewal 

because it is not needed to maintain the sodium pentaborate in solution. The SLC tank is 

located in an environmentally controlled portion of the plant. 

The staff found the applicant's RAI responses to be acceptable. On the basis of the staff's review 

of the LRA, the drawings provided by the applicant, supporting information in the UFSAR, and the 

applicant's RAI responses, the staff has reasonable assurance that all portions of the insulation 

system that perform an intended function meeting the criteria in 10 CFR 54.4 are identified as being 

within the scope of license renewal. 

Using the information provided in the LRA, the staff evaluated insulation components to determine 

whether the applicant properly identified the passive, long-lived components as being subject to 

an AMR in Table 2.3.4-3 of the LRA. The staff verified that the passive, long-lived components 

identified in LRA Section 2.3.4.3 appeared in the list of components that are subject to an AMR in 

Table 2.3.4-3. No omissions were identified. On the basis of this review, the staff has reasonable 

assurance that the applicant has identified the components of the insulation system that are subject 

to an AMR. 

2.3.4.12 Outside Structures HVAC 

Summary of Technical Information in the Application 

In LRA Section 2.3.4.17, the applicant identified portions of the outside structures HVAC system 

and its components that are within the scope of license renewal and subject to an AMR. The 

applicant stated in Section 2.3.4.17 of the LRA that additional information for the outside structures 

HVAC system is provided in Sections 9.4.5 and 9.4.10 of the UFSAR for Unit 2. The system 

scoping is shown in outside structures HVAC system evaluation boundary drawing HL-44073, Rev. 

A. 

The purpose of the intake structure HVAC system is to protect the intake structure equipment from 

adverse temperature conditions that could affect the reliability of the equipment. The diesel

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generator building HVAC system protects diesel generator building equipment from adverse 

temperature conditions that could affect the reliability of the equipment. 

The river intake structure HVAC system consists of three 50percent-capacity roof-mounted exhaust 

ventilators, four gravity-operated louvers, and six wall-mounted unit heaters. The ventilators are 

powered from separate power sources. Each ventilator has a separate control station and is 

operated by an individual thermostat. The independent controls are powered from the motor 

control center control transformer for the associated fan. Since selected plant service water pumps operate during normal and accident conditions in the plant, the three thermostats and the individual 

fan control stations are located in the Unit 1 and 2 PSW pump bay areas. The locations of the 

thermostats ensure that the ventilation system is always activated when operation of the PSW 

pumps causes a heat buildup in the area. The six unit heaters and their associated thermostats 

are strategically located in different areas of the building to provide adequate area coverage to 

maintain the building above freezing temperatures. 

The heating and ventilating systems in the diesel generator rooms consist of one power roof 

exhaust ventilator in each room for exhausting heat from the rooms when the generator is shut 

down, and two 1 00percent-capacity power roof exhaust ventilators in each room for exhausting heat from the rooms during generator actuation. Two motor-operated wall air intake louvers, with 

fire dampers in each room, replenish the air that is removed by the exhaust ventilation. One louver 

serves as the air intake to the generator area; the other serves as the air intake to the battery 

rooms through the generator area. 

In Section 2.3.4.17 of the LRA, the applicant identified the following intended functions for the 

outside structures HVAC system that relate to 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 

54.4(a)(3): 

* Intake structure environmental control 

* EDG building environmental control 

0 EDG building battery room H2 control 

* EDG switchgear room heating and ventilation 

0 EDG building oil storage room ventilation 

On the basis of the functions identified above, the applicant determined that all outside structures 

HVAC system safety-related components (electrical, mechanical, and instrument) are within the 

scope of license renewal. The applicant described its process for identifying the mechanical 

components subject to AMR in Section 2.1.2 of the LRA. On the basis of this methodology, the 

applicant identified the portions of the outside structures HVAC system that are within the scope of license renewal in evaluation boundary drawing HL-44073, Rev. A. Using the methodology described in Section 2.1.2 of the LRA, the applicant compiled a list of the mechanical components and component types that are within the license renewal boundaries and that are subject to an 

AMR, and identified their functions. The applicant provided this list in Table 2.3.4-17 of the LRA. 

The applicant identified the following five device types that are identified as being within the scope of license renewal and subject to an AMR: 

* bolting (carbon steel) 

• bolting (stainless steel) 

* duct sleeve (carbon steel)

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* flow element (stainless steel) 

* tubing (copper) 

In Table 2.3.4-17 of the LRA, the applicant further noted that the outside structures HVAC system 

pressure boundary function is the only applicable function associated with components of the 

outside structures HVAC system that are subject to an AMR. 

Staff Evaluation 

The staff reviewed the above information related to the outside structures HVAC system to verify 

that the applicant identified the components that are within the scope of license renewal and 

subject to an AMR. The staff determined whether there is reasonable assurance that the 

components within the scope of license renewal and subject to an AMR have been identified in 

accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). The staff reviewed the information in 

the LRA and Sections 9.4.5 and 9.4.10 of the UFSAR for Unit 2. After completing the initial review, 

the staff issued a request for additional information (RAI) by letter dated July 14, 2000. The 

applicant responded to the RAI by letter dated August 29, 2000. 

In LRA Section 2.1, the applicant discussed the process for identifying mechanical components that 

are subject to an AMR. The applicant's scoping methodology is evaluated by the staff in Section 

2.1 of this SER. 

In its review, the staff reviewed the evaluation boundary drawing HL-44073, Rev. A. The drawing 

shows the evaluation boundaries for the portions of the outside structures HVAC system that are 

within the scope of license renewal. The staff also reviewed Table 2.3.4-17 of the LRA which lists 

components that are subject to an AMR. 

The staff also reviewed Sections 9.4.5 and 9.4.10 of the UFSAR for Unit 2 to determine if there 

were any portions of the outside structures HVAC system that met the scoping criteria in 10 CFR 

54.4(a) that the applicant did not identify as being within the scope of license renewal. The staff 

also reviewed the UFSAR sections to determine if there was any system function that was not 

identified as an intended function in the LRA, and to determine if there were SCs that have an 

intended function that might have been omitted from the scope of SCs that are subject to an AMR. 

The staff also reviewed the evaluation boundary drawing to determine if any SCs within the 

evaluation boundaries were omitted from the scope of SCs that are subject to an AMR under 10 

CFR 54.4(a)(1). The staff compared the system and intended functions described in the UFSAR 

with those identified in the LRA. The staff then determined whether the applicant had properly 

identified the SCs that are subject to an AMR from among those identified as being within the 

scope of license renewal. 

The applicant identified and listed the SCs that are subject to an AMR for the outside structures 

HVAC system in Table 2.3.4-17 of the LRA, using the screening methodology described in Section 

2.1 of the LRA. The staff evaluated the scoping and screening methodology, and documented its 

findings in Section 2.1 of this SER. The staff sampled SCs from Table 2.3.4-17 to verify that the 

applicant did identify the SCs subject to an AMR. The staff also sampled SCs that were within the 

scope of license renewal, but not subject to an AMR, to verify that these SCs perform their intended 

functions with moving parts or with a change in configuration or properties, or were subject to 

replacement on the basis of a qualified life or specified time period.

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To help ensure that those portions of the outside structures HVAC system that were identified as 

not being within the scope of license renewal did not perform any intended functions, the staff 

issued an RAI on the basis of the applicable information in the UFSAR and LRA. The staff noted 

that Section 2.3.4.17 of the LRA presents a summary description of the system functions, 

evaluation boundary drawings highlight the evaluation boundaries of the outside structures HVAC 

system, and Table 2.3.4-17 of the LRA lists components that are within the scope of license 

renewal and subject to an AMR. The corresponding drawings for this system in the UFSAR, 

however, show additional components that were not listed in Table 2.3.4-17. 

The staff requested specific information concerning the exclusion of the following components from 

the scope of license renewal and/or from an AMR: 

(1) roof-mounted exhaust ventilators housing (each with backdraft damper and vent fan), (HL

44073 @ G8, G9, and G10) 

(2) wall-mounted unit heater housing (HL-44073 @ F7) 

(3) gravity-operated louvers (each with inlet screen), (HL-44073 @ D6 and E6) 

In the letter dated August 29, 2000, the applicant provided the following responses: 

(1) The roof-mounted exhaust ventilator housing is part of an active component (fan and 

damper assembly - see NEI 95-10, Rev. 0, Appendix B, Items 155 and 163) and, 

consequently, no AMR is required. 

(2) The wall-mounted unit heater housing is part of an active component (heater) and, 

consequently, no AMR is required. 

(3) The gravity-operated louvers with inlet screens are active components and, consequently, 

no AMR is required. 

In its response to RAI 2.3.4-OSHVAC-1, the applicant stated that roof-mounted exhaust ventilator 

housings and wall-mounted unit heater housings are not subject to an AMR, since these housings 

are part of active components (i.e., fan/damper assembly and heater, respectively). The staff 

disagreed with the applicant's exclusion of roof-mounted exhaust ventilator and wall-mounted unit 

heater housings from being subject to an AMR. The staff's position with regard to the treatment 

of the housings for roof-mounted exhaust ventilators and wall-mounted unit heaters is discussed 

in detail in the staff's evaluation of the SGTS in Section 2.3.3 of this SER. The staff's position in 

Section 2.3.3 of this SER also applies to the treatment of the component passive functions of the 

outside structures HVAC system. Resolution of this issue was identified as part of Open Item 

2.3.3.2-2 [2.3.3.2-2(c)]. 

By letter dated June 5, 2001, the applicant provided information regarding the disposition of fans, 

dampers, and heating and cooling coils within the scope of license renewal. Consistent with the 

staff's guidance regarding evaluation of active components, the applicant identified the passive functions of damper frames, fan housings, and unit heater housings in the outside structures HVAC 

system and added these components to the list of components in the LRA that are subject to an 

AMR. The applicant also identified any aging effects associated with the damper frames, fan 

housings, and unit heater housings and provided an AMP to manage the aging. The applicant

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added these components to Tables 2.3.4-17 and 3.2.4-17 in the LRA. The staff's review of the 

aging effects and AMPs for the outside structures HVAC system components can be found in 

Section 3.4.3 of this SER. On the basis of the additional information provided by the applicant, the 

staff agrees that damper frames, fan housings, and unit heater housings are within the scope of 

license renewal and subject to an AMR. On the basis of the previously noted information, this part 

of Open Item 2.3.3.2-2, as relates to outside structures HVAC system components, is closed. 

The staff reviewed Section 2.3.4.17 of the LRA, supporting information in the UFSAR, the 

applicant's responses to the staff's RAI, and additional information provided by letter dated June 

5,2001. In addition, the staff sampled several components in the previously mentioned evaluation 

boundary drawings of the LRA to determine whether the applicant properly identified the 

components that are within the scope of license renewal and subject to an AMR. On the basis of 

its review, the staff concludes that the applicant has adequately identified the components of the 

outside structures HVAC system that are within the scope of license renewal and subject to an 

AMR. 

2.3.4.13 Plant Service Water 

Summary of Technical Information in the Application 

The PSW system provides cooling waterto safety-related and non-safety-related equipment during 

normal operating and shutdown conditions. The PSW also provides makeup water to the 

circulating water system heat exchangers, and is available for spent fuel pool emergency makeup, 

fire fighting, and radwaste dilution. The PSW is described in Sections 10.7 and 9.2.1 of the UFSAR 

for Plant Hatch Units 1 and 2, respectively. 

The PSW system consists of four, one-third capacity vertical wetpit service water pumps and 

associated piping and controls, which divides into two divisions. Each division supplies cooling 

water to one redundant train of safety-related equipment. Water for equipment cooling is taken 

from the river via the intake structure by these pumps and distributed by the two headers to 

different areas for use, including the diesel generator building, the reactor and control buildings, 

and fuel pool cooling. 

The applicant describes its process for identifying the mechanical components within the scope of 

license renewal and subject to an AMR in Section 2.1, "Scoping," of the LRA. On the basis of its 

methodology, the applicant identified the portions of the PSW system that are within the scope of 

license renewal on evaluation boundary diagrams DL-1 1004, HL-1 1600, HL-1 1609, HL-21033, and 

HL-21035. The intended functions of the PSW system are essential mechanical/environmental 

support, turbine building isolation, and 1B emergency diesel generator cooling. The applicant 

compiled a list of mechanical components and component functions within the license renewal 

boundaries that are subject to an AMR. The applicant also identified their functions and listed them 

in Table 2.3.4-7 of the LRA. The applicant identified 14 component types as being subject to an 

AMR, including the bolting, flexible connector, piping, pump bowl assembly, pump discharge 

column, pump discharge head, pump sub base, restricting orifices, sight glass body, strainer, 

strainer basket, thermowells, valve bodies, and venturi. The applicant stated that maintaining the 

pressure boundary, structural support, and debris protection are the applicable component 

functions.

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Staff Evaluation

The staff reviewed Section 2.3.4.7 of the LRA and Sections 10.7 and 9.2.1 of the UFSAR for Units 

1 and 2, respectively to determine whether there is reasonable assurance that the applicant appropriately identified the PSW components that are within the scope of license renewal in 

accordance with the requirements of 10 CFR 54.4, and that are subject to an AMR in accordance 

with the requirements of 10 CFR 54.21 (a)(1). 

The applicant provided evaluation boundary diagrams DL-1 1004, HL-1 1600, HL-1 1609, HL-21033, 

and HL-21035 for the PSW, and identified the mechanical components that are within the scope of license renewal. The applicant highlighted the diagrams to identify those portions of the 

components that perform at least one intended function meeting the scoping requirements of 10 

CFR 54.4. The staff compared the LRA flow diagrams to the description in the UFSAR to ensure 

that they were representative of the PSW system. The staff verified that the components that were 

not highlighted do not perform any intended functions that meet the requirements of 10 CFR 54.4. 

Using the information on the PSW flow diagrams, the staff sampled several components to 

determine whether the applicant properly identified the passive long-lived components on the list 

of components identified as being subject to an AMR. The staff also verified that the passive long lived components are highlighted on the flow diagrams and appear on the list of components that 

are subject to an AMR for the PSW system. No omissions were identified. 

In a letter dated July 14,2000, the staff issued RAI 2.3.4-PSW-1 regarding the functional boundary of turbine building isolation piping that ends in the middle of the piping run, and does not appear 

to be within the scope of license renewal. By letter dated August 29, 2000, the applicant stated that 

drawing HL-1 1600 shows that turbine building service water flow is monitored by safety-related differential pressure (dP) switches that are located downstream of the isolation valves. These 

switches are needed to annunciate in the control room such that the isolation valves to isolate the 

non-safety loads from the rest of the system during a break can be closed. The isolation valves 

and instrumentation for these dP switches are within the scope of license renewal and subject to 

an AMR. The dP switches located downstream of these valves detect flow and are required for 

proper isolation of the line. Because the location of the dP switches and the associated 

instrumentation extends beyond the point that would normally serve as the evaluation boundary, the applicant conservatively extends the AMR evaluation boundary up to the first anchor point at 

the valve box located beyond the location of each dP switch. The applicant committed to revise 

the drawing to include reference notes that depict this condition. By letter dated January 31, 2001, the applicant provided a revised version of evaluation boundary drawing HL-1 1600, which identifies 

the valve box walls that serve as the boundary for scoping evaluation. The staff finds this 

acceptable. 

The applicant also responded that the loop seals to the diesel generator coolers in drawing HL-21033 provide a sealing function and keep the diesel generator coolers full of water by preventing the service water from leaving the cooler because of the vacuum created in the service 

water discharge line to the river. The loop seals and associated components are safety-related and 

within the scope'of license renewal. The piping downstream of the loop seal connects to the 

radwaste dilution line, which is non-safety-related and discharges the water to the river. A break 

downstream of the loop seal piping will not impact the sealing function.

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Also, during a scoping inspection conducted on September 11 through 15,2000, the staff identified 

a guard pipe surrounding part of the PSW piping. The applicant stated that the function of this 

guard pipe could not be verified or confirmed in any plant licensing documents and, therefore, 

concluded that this guard pipe was not within the scope of license renewal. The applicant, 

however, stated that the PSW piping section that runs through the guard pipe is within the scope 

of license renewal and subject to an AMR. The applicant committed to perform a one-time 

inspection of the PSW outer piping surface inside the guard pipe to verify the integrity of this 

portion of the PSW piping. The one-time inspection is discussed in the response to RAI 3.1.4-1 

and is evaluated in Sections 3.1.13 and 3.4.3.2 of this SER. 

On the basis of its review of the LRA and supporting information in the UFSAR, the staff has 

reasonable assurance that all portions of the PSW system with intended functions meeting the 

criteria in 10 CFR 54.4 are identified as being within the scope of license renewal. The staff has 

also verified that all passive long-lived components have been identified as being subject to an 

AMR for the PSW system. No omissions were identified. 

2.3.4.14 Primary Containment Chilled Water 

Summary of Technical Information in the Application 

In Section 2.3.4.10 of the LRA, the applicant describes the primary containment chilled water 

system (PCCW) for Unit 2 only. The PCCW is designed to maintain the drywell area below a 

maximum volumetric average temperature of 150 OF dry bulb during normal operation by providing 

chilled water to the drywell fan coil units. The system consists of two chilled water recirculation 

pumps, two centrifugal chillers, a chemical addition tank, a chemical feed pump, and an expansion 

tank. Each chiller includes a refrigerant compressor, condenser, cooler, accessories, and controls. 

The chilled water recirculation pumps circulate chilled water through their respective chiller to the 

fan coil units. Service water from the reactor building service water system is circulated through the 

chiller condensers for cooling. Demineralized water provides a source of makeup water for the 

chilled water system. The expansion tank, chemical addition tank, and associated makeup water 

supply are shared with the reactor and radwaste building chilled water system. 

The only intended function of the PCCW system is to maintain containment integrity. Specifically, 

the components that are within the scope of license renewal function to maintain primary 

containment integrity via a closed loop inside containment. The controls and instrumentation 

associated with primary containment isolation for this system function are evaluated as part of LRA 

Section 2.5.3. 

The applicant provided one drawing (HL-26081) for Unit 2 that is highlighted to indicate piping from 

this system that is within the scope of license renewal. The applicant described its process for 

identifying the mechanical components that are within the scope of license renewal and subject to 

an AMR in Section 2.1.3 of the LRA. On the basis of this methodology, the applicant identified the 

piping system inside the drywell as the passive, long-lived portion of the system that requires an 

AMR. The five component types that were identified as being subject to an AMR include the 

bolting, caps, piping, valve bodies, and thermowells. The applicant identified pressure boundary 

integrity as the function of these components.

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Staff Evaluation

The applicant stated in Section 2.3.4.10 of the LRA that the PCCW system is within the scope of 

license renewal because of its containment integrity intended function. The applicant further stated 

that the in-scope components are those portions of the PCCW system that form a closed loop inside containment. The applicant provided one drawing (HL-26081) for Unit 2 that is color-coded 

to indicate the piping from this system that is within the scope of license renewal. Essentially all of 

the piping inside containment except small-bore piping downstream of vent and drain isolation 

valves is indicated as within the scope of license renewal. The staff reviewed the drawing and 

found that the piping identified as being within the scope of license renewal is consistent with the 

intended function description in LRA Section 2.3.4.10. 

On the basis of the staff's review of the LRA, the applicant's RAI responses, and supporting 

information in the UFSAR, the staff has reasonable assurance that all portions of the PCCW 

system with intended functions that meet the criteria in 10 CFR 54.4 are identified as being within 

the scope of license renewal. 

Using the information provided in the LRA, the staff sampled several components to determine 

whether the applicant properly identified the passive, long-lived components on the list of 

components that are subject to an AMR in Table 2.3.4-10 of the LRA. The staff verified that the 

passive, long-lived components identified in LRA Section 2.3.4.10 appeared on the list of 

components that are subject to an AMR in Table 2.3.4-10. No omissions were identified. On the 

basis of this review, the staff has reasonable assurance that the applicant has identified the 

components of the PCCW system that are subject to an AMR. 

2.3.4.15 Reactor Building Closed Cooling Water 

Summary of Technical Information in the Application 

The intended functions of the reactor building closed cooling water (RBCCW) system are to provide cooling water to certain auxiliary equipment in the reactor building, and to serve as a closed-cycle barrier between potentially radioactive systems and the plant service water system. The RBCCW 

system consists of three one-half-capacity pumps, two full-capacity heat exchangers, a surge tank, 

and a chemical addition system. Two of the RBCCW pumps are normally operating with the third 

pump on standby. The heat rejected by the RBCCW system to the heat exchanger is removed by the PSW system. As discussed in Section 10.5 of the Unit 1 UFSAR Section 9.2.2 of the Unit 2 

UFSAR, any possible leakage from the reactor auxiliary systems equipment will be into the 

RBCCW closed loop. The RBCCW system is continuously monitored for radioactivity by the 

process radiation monitoring system. Operation of the RBCCW system is not vital for safe 

shutdown of either Plant Hatch unit under normal or accident conditions, and the system is not 

required to be operable following a LOCA. In addition, failure of any component of the RBCCW 

will not cause a significant release of radioactivity. The RBCCW system is only within the scope 

of license renewal to the extent that it provides containment integrity. 

The applicant described its process for identifying the mechanical components that are within the 

scope of license renewal and subject to an AMR in Section 2.1.2 of the LRA. On the basis of its 

methodology, the applicant identified the portions of the RBCCW system that are within the scope 

of license renewal on evaluation boundary diagrams HL-1 6009, HL-1 6066, HL-26003, and HL

26055. The applicant listed the mechanical components and component functions within the

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license renewal boundaries that are subject to an AMR. In Table 2.3.4-8 of the LRA, the applicant 

identified nine component types as being subject to an AMR, including the bolting, flexible 

connectors, flow element, heat exchanger shells, piping, relief valve base, temperature probe, 

thermowell, and valve bodies. The applicant identified maintaining the pressure boundary as the 

function of each component. 

Staff Evaluation 

The applicant provided evaluation boundary diagrams HL-16009, HL-16066, HL-26003, and 

HL-26055 of the RBCCW, and identified the mechanical components that are subject to an AMR 

and their functions. The applicant highlighted the detailed flow diagrams-to identify those portions 

of the RBCCW system that are within the scope of license renewal. The applicant highlighted 

those components that perform at least one intended function meeting the scoping requirements 

of 10 CFR 54.4. The staff compared the LRA flow diagrams to the descriptions in the UFSAR to 

ensure that they are representative of the RBCCW system. The staff verified that the components 

that were not highlighted do not perform any intended functions meeting the requirements of 10 

CFR 54.4. 

On the basis of a review of the LRA and supporting information in the UFSAR, the staff has 

reasonable assurance that all portions of the RBCCW system with intended functions that meet 

the criteria in 10 CFR 54.4 are identified as being within the scope of license renewal. 

Using the information on the flow diagrams for the RBCCW, the staff sampled several components 

to determine whether the applicant properly identified the passive, long-lived components on the 

list of components that are subject to an AMR. The staff verified that the passive, long-lived 

components that are highlighted on the flow diagrams appear on the list of components that are 

subject to an AMR for the RBCCW system. No omissions were identified. On the basis of this 

review, the staff has reasonable assurance that the applicant has identified the components of the 

RBCCW system that are subject to an AMR. 

2.3.4.16 Reactor Building HVAC 

Summary of Technical Information in the Application 

In LRA Section 2.3.4.15, the applicant identified portions of the reactor building HVAC System and 

the components that are within the scope of license renewal and subject to an AMR. The applicant 

stated in Section 2.3.4.15 of the LRA that additional information for the reactor building HVAC 

system is provided in Sections 10.9 and 9.4.2 of the UFSAR for Units 1 and 2, respectively. The 

system scoping is shown in evaluation boundary drawings HL-1 6005, Rev. A, HL-1 6014, Rev. A, 

and HL-16023, Rev. A, for Unit 1, and HL-26067, Rev. A, HL-26072, Rev. A, and HL-26071, Rev. 

A, for Unit 2. 

The reactor building HVAC system utilizes a combination of air conditioning, heating, and once

through ventilation. Heat removal is provided by the ventilation air and the chilled-water (Unit 2 

only) and service-water cooling coils that are served by the reactor and radwaste building chilled

water system and the PSW system, respectively. Hot water heating coils, served by the plant 

heating system, are provided for heating.

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In Section 2.3.4.15 of the LRA, the applicant identified the following component functions that relate 

to 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3): 

* indirect radioactive release control 

* essential mechanical/environmental support - ECCS room coolers 

* essential mechanical/environmental support - RCIC and CRD room coolers 

On the basis of the functions identified above, the applicant determined that all reactor building 

HVAC system safety-related components (electrical, mechanical, and instrument) are within the 

scope of license renewal. The applicant described its process for identifying the mechanical 

components subject to an AMR in Section 2.1.2 of the LRA. On the basis of this methodology, the 

applicant identified the portions of the reactor building HVAC system that are within the scope of 

license renewal in the system evaluation boundary drawings previously mentioned. Using the 

methodology described in Section 2.1.2 of the LRA, the applicant compiled a list of the mechanical 

components and component types within the license renewal boundaries that are subject to an 

AMR and identified their intended functions. The applicant provided this list in Table 2.3.4-15 of 

the LRA. 

The applicant identified the following four device types that are identified as within the scope of 

license renewal and subject to an AMR: 

* bolting (carbon steel) 

• ductwork (galvanized steel) 

* flow element (stainless steel) 

* tubing (copper alloy) 

In Table 2.3.4-15 of the LRA, the applicant further noted that the reactor building HVAC system 

fission product barrier and pressure boundary functions are the only applicable functions 

associated with components of the reactor building HVAC system that are subject to an AMR. 

Staff Evaluation 

The staff reviewed the above information to verify that the applicant identified the reactor building 

HVAC system components that are within the scope of license renewal and subject to an AMR. 

The staff determined whether there is reasonable assurance that the reactor building HVAC system 

components that are within the scope of license renewal and subject to an AMR have been 

identified in accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). The staff reviewed the 

information in the LRA and Sections 10.9 and 9.4.2 of the UFSAR for Units 1 and 2, respectively. 

After completing the initial review, the staff issued requests for additional information (RAIs) by 

letter dated July 14, 2000, regarding the reactor building HVAC system. The applicant responded 

to the RAIs by letter dated August 29, 2000. 

In LRA Section 2.1, the applicant discussed the process for identifying mechanical components that 

are subject to an AMR. The applicant's scoping methodology is evaluated by the staff in Section 

2.1 of this SER. 

In its review of the reactor building HVAC system, the staff reviewed the reactor building HVAC 

system evaluation boundary drawings. The drawings show the evaluation boundaries for the 

portions of the reactor building HVAC system that are within the scope of license renewal. The

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staff also reviewed Table 2.3.4-15 of the LRA which lists the components that are subject to an 

AMR. 

The staff also reviewed Sections 10.9 and 9.4.2 of the UFSAR for Units 1 and 2, respectively, to 

determine if there were any portions of the reactor building HVAC system that met the scoping criteria in 10 CFR 54.4(a) that the applicant did not identify as being within the scope of license 

renewal. The staff also reviewed the UFSAR sections to determine if there was any system function that was not identified as an intended function in the LRA, and to determine if there were 

SCs that have an intended function that might have been omitted from the scope of SCs that are 

subject to an AMR. The staff also reviewed the reactor building HVAC evaluation boundary drawings to determine if any SCs within the evaluation boundaries were omitted from the scope of SCs that are subject to an AMR. The staff compared the system and intended functions 

described in the UFSAR with those identified in the LRA. The staff then determined whether the 

applicant had properly identified SCs that are subject to an AMR from among those identified as 

being within the scope of license renewal. 

The applicant identified and listed the SCs that are subject to an AMR for the reactor building HVAC system in Table 2.3.4-15 of the LRA, using the screening methodology described in Section 

2.1 of the LRA. The staff evaluated the scoping and screening methodology, and documented its 

findings in Section 2.1 of this SER. The staff sampled SCs from Table 2.3.4-15 to verify that the 

applicant identified the SCs that are subject to an AMR. The staff also sampled SCs that were 

identified as being within the scope of license renewal, but were not identified as being subject to 

an AMR, to verify that these SCs perform their intended functions with moving parts or with a 

change in configuration or properties, or are subject to replacement on the basis of a qualified life 

or specified time period. 

To help ensure that those portions of the reactor building HVAC system that were identified as not 

being within the scope of license renewal do not perform any intended functions, the staff issued 

an RAI on the basis of the applicable information in the UFSAR and the LRA. The staff noted that 

Section 2.3.4.15 of the LRA presents a summary description of the system functions, evaluation 

boundary drawings highlight the evaluation boundaries of the reactor building HVAC system, and Table 2.3.4-15 of the LRA lists components that are within the scope of license renewal and subject 

to an AMR. The corresponding drawings for this system in the UFSAR, however, show additional 

components that were not listed in Table 2.3.4-15. 

In RAIs 2.3.4-RBHVAC-1, 2.3.4-RBHVAC-2, and 2.3.4-RBHVAC-3, the staff requested specific information concerning the exclusion of the following components from the scope of license 

renewal and/or from an AMR: 

(1) air operated valve bodies, air-operated damper housing, and associated ductwork (Unit 1) 

(2) safeguards equipment room cooler housing, especially the CRD pump room cooler housing 

that is not identified as being within scope (Unit 1) 

(3) air-operated valve bodies, air-operated damper housing, and associated ductwork (Unit 2) 

(4) safeguards equipment room cooler housing, especially the CRD pump room cooler housing 

that is not identified as being within scope (Unit 2)

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(5) sealant materials

(6) ductwork (Unit 1) 

!n the letter dated August 29, 2000, the applicant provided the following responses: 

(1) Air-operated valve dampers and associated damper operators (Unit 1) are active 

components and, therefore, are not subject to an AMR. Damper operators consist of 

control valves and piping. 

(2) Although safeguards equipment cooler housings (Unit 1) are within the scope of license 

renewal, cooler housings are considered to be part of an active component (fan-coil unit) 

and, therefore, no AMR is required for these components. 

(3) Air-operated valve dampers and associated damper operators (Unit 2) are active 

components and, therefore, are not subject to an AMR. 

(4) Although safeguards equipment cooler housing (Unit 2) are within the scope of license 

renewal, cooler housings are considered to be part of an active component (fan-coil unit) 

and, therefore, no AMR is required for these components. 

(5) Sealant materials that are used to protect against unfiltered out-leakage from secondary containment are within the scope of license renewal, and are shown as "panel joint seals 

and sealants" in Table 2.4.5-1 of the LRA. 

(6) Ductwork identified by the staff is not within the scope of license renewal. Ductwork that 

is within the scope of license renewal and subject to an AMR is shown in Table 2.3.4-15 of 

the LRA and appears as highlighted ductwork on the appropriate boundary drawings 

The staff reviewed the applicant's response for sealant materials and found the response to be 

acceptable. However, in its response to RAI 2.3.4-RBHVAC-1, the applicant stated that, given the 

guidance in NEI 95-10, Appendix B, safeguards equipment room cooler housings are not subject to an AMR. With regard to this RAI, the applicant also did not address the scope of license renewal 

and an AMR as it relates to air-operated valve bodies, the air-operated damper housings, and 

associated ductwork. Additionally, in a telephone conference held on October 31, 2000, the 

applicant agreed to reconsider its response to RAI 2.3.4-RBHVAC-3, concerning whether certain 

ductwork identified by the staff is within the scope of license renewal and subject to an AMR. 

The staff believes that the safeguards equipment room cooler housings may be within the scope of license renewal and subject to an AMR. The staff's position with regard to the treatment of the 

housings for the safeguards equipment room coolers is discussed in detail in the staff's evaluation 

of the SGTS in Section 2.3.3 of this SER. The staff's position in Section 2.3.3 of this SER applies to the treatment of the component passive functions of the reactor building HVAC system. Resolution of this issue, including the scoping clarification for the air-operated valve bodies, air-operated damper housing, and associated ductwork, was identified as part of Open Item 

2.3.3.2-2 [2.3.3.2-2(d)]. 

By letter dated June 5, 2001, the applicant provided information regarding the disposition of fans, 

dampers, and heating and cooling coils within the scope of license renewal. Consistent with the

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staff's guidance regarding evaluation of active components, the applicant identified the passive 

functions of damper frames, fan housings, fan inlet housings, and fan inlet screens in the reactor 

building HVAC system and added these components to the list of components in the LRA that are 

subject to an AMR. The applicant also identified any aging effects associated with the damper 

frames, fan housings, fan inlet housings, and fan inlet screens and provided an AMP to manage 

the aging. The applicant added these components to those listed in Tables 2.3.4-15 and 3.2.4-15 

in the LRA. The staff's review of the aging effects and AMPs for the reactor building HVAC system 

components can be found in Section 3.4.3 of this SER. The applicant provided other clarifications 

and/or editorial changes, as appropriate. On the basis of the additional information provided by the 

applicant, the staff agrees that damper frames, fan housings, fan inlet housings, and fan inlet 

screens are within the scope of license renewal and subject to an AMR. On the basis of the 

previously noted information, this part of Open Item 2.3.3.2-2 [2.3.3.2-2(d)], as relates to reactor 

building HVAC system components, is closed. 

The staff reviewed Section 2.3.4.15 of the LRA, supporting information in the UFSAR, the 

applicant's responses to the staff's RAI, and additional information provided by letter dated June 

5,2001. In addition, the staff sampled several components in the previously mentioned evaluation 

boundary drawings of the LRA to determine whether the applicant properly identified the 

components that are within the scope of license renewal and that are subject to an AMR. On the 

basis of the staff's review,, the staff concludes that the applicant has adequately identified the 

components of the reactor building HVAC system that are within the scope of license renewal and 

that are subject to an AMR. 

2.3.4.17 Refueling Equipment System 

Summary of Technical Information in the Application 

Section 2.3.4.2 of the LRA provides a description of the refueling equipment (RE) system and a 

list of structures and components that are subject to an AMR. The refueling platform equipment 

assembly is used to handle and transport reactor core internals and service and handling 

equipment associated with the refueling operation. The refueling platform assembly consists of 

the refueling platform, fuel grapple, grapple headlight, and the hardware required to assemble 

these components into a workable unit. The applicant states that the intended function of the RE 

system is to support fuel movement and control rod change out. The SCs that support this 

intended function include the refueling bridge, grapple, hoists, spentfuel servicing equipment, tools, 

and refueling interlocks. The applicant identified the structural integrity of the refueling platform 

as the passive, long-lived portion of the assembly that is within the scope of license renewal. 

The applicant described its process for identifying the mechanical components that are within the 

scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of this 

methodology, the applicant identified the refueling platform structure as the passive, long-lived 

portion of the system that requires an AMR. The four component types that were identified as 

being subject to an AMR include the anchors and bolts, miscellaneous steel, rivets, and structural 

steel. The applicant identified maintaining the structural integrity of the refueling platform as the 

function of these components.

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Staff Evaluation

The applicant stated that the RE system is within the scope of license renewal because of its 

fuel/control rod handling intended function. The portions of the system that were identified as 

supporting this intended function include the refueling bridge, grapple, hoists, spent fuel servicing 

equipment, tools, and refueling interlocks. The staff reviewed Section 7.6, "Refueling Interlocks," 

of the Unit 1 UFSAR and Section 9.1, "Fuel Storage and Handling," of the Unit 2 UFSAR. The staff 

verified that the RE system did not have intended functions other than the fuel/control rod handling 

intended function. In addition, the staff verified that all components supporting the fuel/control rod 

handling intended function were identified as being within the scope of license renewal. 

On the basis of the staff's review of the LRA and supporting information in the UFSAR, the staff 

has reasonable assurance that all portions of the RE system with intended functions that meet the 

criteria in 10 CFR 54.4 were identified as being within the scope of license renewal. Using the 

information provided in the LRA, the staff sampled several components to determine whether the 

applicant properly identified the passive, long-lived components on the list of components as being 

subject to an AMR in Table 2.3.4-2 of the LRA. The staff verified that the passive, long-lived 

components identified in Section 2.3.4.2 of the LRA appeared on the list of components that were 

identified as being subject to an AMR in Table 2.3.4-2. No omissions were identified. On the basis 

of this review, the staff has reasonable assurance that the applicant has identified the components 

of the RE system that are subject to an AMR. 

2.3.4.18 Sampling System 

Summary of Technical Information in the Application 

The purpose of the primary containment hydrogen and oxygen analyzing (sampling) system is to 

provide a means of monitoring hydrogen and oxygen in the primary containment (drywell and 

torus). The system consists of two separate, redundant subtems, each of which is capable of 

analyzing the hydrogen and oxygen content from the drywell or torus. Each analyzer channel is 

operated in parallel from separate penetrations in the drywell and torus. The sample is drawn 

through a sample cooler by the sample system inlet pump, and then pumped to the hydrogen and 

oxygen analyzer cells. The sample is then returned to the primary containment by the sample 

system outlet pump. 

System Intended Functions 

The intended function of the sampling system is to display hydrogen/oxygen information. The 

hydrogen-oxygen analyzer system continually measures the hydrogen and oxygen concentrations 

in the primary containment atmosphere following a LOCA. This information is recorded in the 

MCR, and hydrogen concentrations in the drywell above a predetermined level are annunciated. 

The system is treated as safety-related, consistent with the requirements of Regulatory Guide 1.97, 

"Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs 

Conditions During and Following an Accident," and is included in the environmental qualification 

program.

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Component Intended Function

The components of the sampling system perform the following functions: 

• fission product barrier 

* pressure boundary 

The component groups requiring an AMR, as identified in the LRA, include the piping and valve 

bodies. 

Staff Evaluation 

The purpose of the primary containment hydrogen and oxygen analyzing (sampling) system is to 

provide a means of monitoring hydrogen and oxygen in the primary containment (drywell and 

torus). The system consists of two separate, redundant subsystems, each of which is capable of 

analyzing the hydrogen and oxygen content from the drywell or torus. Each analyzer channel is 

operated in parallel from separate penetrations in the drywell and torus. The sample is drawn 

through a sample cooler by the sample system inlet pump, and then is pumped to the hydrogen 

and oxygen analyzer cells. The sample is then returned to the primary containment by the sample 

system outlet pump. 

The staff reviewed Section 2.3.4.6 of the LRA to determine whether the applicant has identified the 

components in the sampling system that are within the scope of license renewal and subject to an 

AMR. 

On the basis of the staff's review of the information presented in Section 2.3.4.6 of the LRA and 

the supporting information in the Plant Hatch UFSAR, the staff did not find any omissions by the 

applicant and, therefore, concludes that there is reasonable assurance that the applicant has 

adequately identified those portions of the sampling system that fall within the scope of license 

renewal and are subject to an AMR, in accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). 

2.3.4.19 Tornado Vents System 

Summary of Technical Information in the Application 

In LRA Section 2.3.4.14 of the LRA, the applicant describes the tornado vents system (TV) system, 

which is comprised of blowout panels that are designed to relieve excess pressure in various site 

structures. The TV system will blowout and vent the reactor and control building roofs under the 

following conditions: 

* when wind velocity reaches 300 mph or greater 

* when the internal static pressure in the building is increased to 55 lb/ft2 

• when the temperature reaches approximately 212°F 

The applicant identified pressure equalization as the intended function of the TV system. A rapid 

depressurization of air surrounding site structures can occur if a tornado funnel suddenly engulfs 

a structure. In this case, venting is accomplished by the blowout panels, which are designed to fail 

at a pressure lower than the safe internal building pressure capability, thereby relieving excess 

pressure in all essential parts of such structures. The reactor building tornado relief vents are

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safety-related, and are required to maintain secondary containment during normal operation and 

during an earthquake. An inadvertent opening of the tornado vents could compromise secondary containment integrity. Tornado vents are relied upon to remain closed to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposure. The opening of the vents 

during a tornado is a safety function to prevent collapse of safety-related structures. 

The applicant described its process for identifying the mechanical components within the scope of 

license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of this 

methodology, the applicant identified tornado vents as passive, long-lived structures that are 

subject to an AMR. The component types that are identified as being subject to an AMR include 

the screws, support frame, and tornado vent relief dome. The applicant identified structural 

support as the function of the screw and support frame components, and fission product barrier 

as the function of the tornado vent relief dome component. 

Staff Evaluation 

In Section 2.3.4.14 of the LRA, the applicant states that the tornado vents (TVs) are within the 

scope of license renewal because of their pressure equalization intended function. The TVs prevent the collapse of safety-related structures by failing before the structure can become pressurized. The staff reviewed Section 3.3, 'Wind and Tornado Loadings," of the Unit 2 UFSAR to verify that 

the TV system does not have intended functions other than the pressure equalization intended 

function. In addition, the staff verified that all components that support the pressure equalization 

intended function were identified as being within the scope of license renewal. 

On the basis of the staff's review of the LRA and supporting information in the UFSAR, the staff 

has reasonable assurance that all portions of the TV system with intended functions that meet the 

criteria in 10 CFR 54.4 were identified as being within the scope of license renewal. 

Using the information provided in the LRA, the staff sampled several components to determine 

whether the applicant properly identified the passive, long-lived components on the list of 

components identified as being subject to an AMR in Table 2.3.4-14 of the LRA. Figure 3.3-1 in the 

Unit 2 UFSAR provides a diagram of the tornado vent structural grill system. The staff identified 

two components in the diagram that are not listed in LRA Table 2.3.4-14 as being subject to an 

AMR. Specifically, these components are the tornado vent concrete curb and the tornado vent grill. 

In RAI 2.3.4-TV-1, the staff asked the applicant to explain the functions of these components and 

the bases for excluding them from an AMR. The applicant responded that the concrete curb is 

within scope, and is addressed as part of the reactor building in Tables 2.4.5-1 and 3.3.1-5 of the 

LRA. The applicant further stated that the function of the vent grill is primarily to prevent debris from 

falling into the spent fuel pool. The vent grill does not perform an intended function. After 

reviewing the applicant's response, the staff found the response acceptable. The staff verified that 

the passive, long-lived components identified in LRA Section 2.3.4.14 appeared on the list of 

components that are subject to an AMR in LRA Table 2.3.4-14. No omissions were identified. On 

the basis of this review, the staff has reasonable assurance that the applicant has identified the 

components of the TV system that are subject to an AMR.

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2.3.4.20 Traveling Water Screens/Trash Racks System

Summary of Technical Information in the Application 

The intended functions of the traveling water screens/trash racks system are intake structure trash 

removal and screen wash isolation. The traveling water screens prevent debris from entering the 

portion of the intake structure from which the PSW pumps take suction. Large pieces of debris are 

prevented from reaching the traveling screens by the trash racks. The traveling screens system 

at Plant Hatch is composed of two traveling screens, two motors, and two screen wash lines. For 

the intended function of intake structure trash removal, the intake structure is equipped with trash 

screens and racks to keep debris out of the pump wells. The debris is removed from the screens 

by the screen wash water. 

The screens and racks must remain structurally intact during an accident, but are not required to 

move. Therefore, the applicant only considered the screens and racks to be in scope for license 

renewal, and not the motors or screen wash lines. For the intended function of screen wash 

isolation, isolation of the screen wash lines in the safe shutdown mode is required during a fire to 

maintain safe shutdown paths 1 and 3. 

The applicant described its process for identifying the mechanical components that within the scope 

of license renewal and subject to an AMR in Section 2.1.2 of the LRA. On the basis of its 

methodology, the applicant identified the portions of the traveling water screens/trash racks system 

that are within the scope of license renewal on evaluation boundary diagrams DL-1 1001 and HL

21033. The applicant listed the mechanical components and component functions within the 

license renewal boundaries that are subject to an AMR. In Table 2.3.4-16 of the LRA, the applicant 

identified five component types as being subject to an AMR, including sight glasses, trash racks, 

traveling screens, bolting and valve bodies. The applicant identified maintaining the pressure 

boundary as the function of the sight glasses, bolting and valve bodies. The function of the trash 

racks and traveling screens was identified as debris protection. 

Staff Evaluation 

The applicant provided evaluation boundary diagrams DL-1 1001 and HL-21033 of the traveling 

water screens/trash racks, and identified the mechanical components that are subject to an AMR 

and their functions. The applicant highlighted the detailed flow diagrams to identify those portions 

of the traveling water screens/trash racks system that are within the scope of license renewal. The 

applicant highlighted those components which, they believe, perform at least one intended function 

meeting the scoping requirements of 10 CFR 54.4. The staff compared the LRA flow diagrams to 

the descriptions in Section 9.2.1.2 of the Unit 2 UFSAR to ensure that they were representative of 

the traveling water screens/trash racks system. The staff verified that the components that were 

not highlighted do not perform any intended functions meeting the requirements of 10 CFR 54.4. 

On the basis of a review of the LRA and supporting information in the UFSAR, the staff has 

reasonable assurance that all portions of the traveling water screens/trash racks system with 

intended functions meeting the criteria in 10 CFR 54.4 are identified as being within the scope of 

license renewal. 

Using the information on the flow diagrams for the traveling water screens/trash racks system, the 

staff sampled several components to determine whether the applicant properly identified the

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passive, long-lived components in the list of components that were identified as being subject to 

an AMR. The staff verified that the passive, long-lived components highlighted on the flow diagrams appear on the list of components that are subject to an AMR for the traveling water screens/trash racks system. No omissions were identified. On the basis of this review, the staff 

has reasonable assurance that the applicant has identified the components of the traveling water 

screens/trash racks system that are subject to an AMR. 

2.3.4.21 Conclusion 

On the basis of the staff's review of the information presented in Section 2.3.4 of the LRA, the supporting information in the Plant Hatch UFSAR, and the applicant's response to the staff's RAIs 

and Open Items 2.3.3.2-1, 2.3.3.2-2, and 2.3.4.2-1, the staff did not find any omissions by the applicant. Therefore, the staff concludes that there is reasonable assurance that the applicant adequately identified those portions of the auxiliary systems and their associated (supporting) SCs 

that fall within the scope of license renewal and are subject to an AMR, in accordance with 10 CFR 

54.4(a) and 10 CFR 54.21 (a)(1). 

2.3.5 Steam and Power Conversion Systems 

2.3.5.1 Introduction 

In Section 2.3.5, "Steam and Power Conversion Systems," of the Plant Hatch LRA, the applicant described the components of the electro-hydraulic control (EHC) system and the main condenser 

system that are within the scope of license renewal and subject to an AMR. The staff reviewed 

these sections of the LRA to determine whether there is reasonable assurance that the applicant has identified all of the SSCs that are within the scope of license renewal, as required by 10 CFR Part 54.4(a), as well as all of the structures and components that are subject to an AMR, as 

required by 10 CFR Part 54.21 (a)(1). 

The staff reviewed the information submitted by the applicant to verify that the applicant has 

identified the intended functions of the steam and power conversion system that are within the 

scope of license renewal, and the components that are subject to an AMR, in accordance with the 

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). 

The applicant identified and listed the components that are subject to an AMR for the steam and 

power conversion system in Tables 2.3.5-1 and 2.3.5-2 of the LRA using the screening methodology described in Sections 2.1.2 and 2.1.3 of the LRA. The screening methodology is 

evaluated by the staff in Section 2.1 of this SER. 

The staff reviewed Plant Hatch Unit 1 UFSAR Section 11.2 and Unit 2 UFSAR Sections 10.1, 10.2A.1, and 10.4.1 to determine if there were any system functions that were not identified as intended functions in accordance with requirements of 10 CFR 54.4. The staff then reviewed the 

evaluation boundary drawings (HL-1 1601, HL-1 1602, HL-21012, HL-26000, HL-21012, HL-21031, HL-21046, HL-21056, HL-21205, and HL-26045) to verify that the applicant identified of all the 

components that are within the scope of license renewal in accordance with 10 CFR 54.4. Further, the staff verified the accuracy of the drawings and the completeness of Tables 2.3.5-1 and 2.3.5-2 by sampling the components adjacent to, but outside, the highlighted portion of the system to verify that all of the components that are within the scope of license renewal were included in the application. In addition, the staff sampled the components that are within the scope of license

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renewal, but not subject to an AMR, to verify that all of the components that meet the requirements 

of 10 CFR 54.21 (a)(1) were identified as being subject to an AMR. 

After the initial review, in a letter dated July 14, 2000, the staff identified areas where additional 

information was needed to complete its safety review. The applicant responded to the RAIs in a 

letter dated August 29, 2000. 

In reviewing Section 2.3.5 of the LRA, the staff found that this section, which is entitled "Steam and 

Power Conversion Systems," describes only the EHC and main condenser systems. The main 

steam and feedwater systems, which are also included in the Plant Hatch steam and power 

conversion systems, are not described in the LRA. This is inconsistent with the description in Plant 

Hatch Unit 2 UFSAR Section 10.1, which states that portions of the main steam and feedwater 

systems provide safety functions. These portions meet the requirements of 10 CFR 54.4 and, as 

such, should be within the scope of license renewal. In response to RAI 2.3.5-SPCS-1, the 

applicant stated that LRA scoping is based on functions. The only in-scope function performed by 

the feedwater system and main steam system is captured in function B21-02, reactor coolant 

pressure boundary, which is described in Section 2.3.1.2 of the LRA. The steam and power 

conversion systems at Plant Hatch only include piping downstream of the MSIVs. The staff's 

scoping review of these safety-related portions of the main steam and feedwater systems is 

discussed in Section 2.3.2, "Reactor Coolant System," of this SER. The staff finds the applicant's 

response to this RAI acceptable. 

2.3.5.2 Electro-Hydraulic Control System 

Summary of Technical Information in the Application 

The function of the EHC system is to provide control of reactor pressure during reactor startup, 

power operation, and shutdown. The EHC system also provides a means of controlling main 

turbine speed and acceleration during turbine startup, and protects the main turbine from 

undesirable operating conditions by initiating alarms, trips, and runbacks. 

The initial scoping, performed by the applicant and based on the functions, has determined that 

intended function N32-02, Main Turbine Pressure Regulators, is within the scope of license renewal 

for the EHC system. The main turbine pressure regulator function controls turbine control valve 

position by adjusting EHC pressure based on main steam pressure. The EHC regulators that are 

within the scope of license renewal are 1N 11-N042A/B and 2N32-N301 A/B. Transient analysis 

takes credit for the backup pressure regulator to function to prevent fuel damage in the event of 

a downscale failure of the inservice regulator. The associated piping and valve bodies are listed 

in Table 2.3.5-1 of the LRA as being within the scope of license renewal and subject to an AMR. 

The component function for the identified piping and valve bodies is the pressure boundary. 

Staff Evaluation 

In RAI 2.3.5-EHC-1, the staff noted that four EHC regulators, identified in Section 2.3.5.1 of the 

LRA as being within scope, could not be located on the boundary drawings. The RAI requested 

that the applicant identify the EHC regulators (1 Ni 1 -N042NB and 2N32-N301 A/B) in the boundary 

drawings. In response, the applicant clarified the locations on the boundary drawings for the two 

Unit 1 regulators (drawing No. HL-1 1601), as well as for the two Unit 2 regulators (drawing No. HL

21012). However, the applicant indicated that there was an error on drawing HL-1 1601, in that it

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identified two separate components with the same identifying number (N1 1-N042B). Based on the additional information, the staff was able to find these four regulators in the drawings as stated. By letter dated January 31,2001, the applicant provided revised drawing HL-1 1601 that corrected 

the component identification error. The staff finds this acceptable. 

Section 2.3.5.1 of the LRA states that transient analysis takes credit for the backup pressure regulator to function to prevent fuel damage in the event of a downscale failure of the inservice 

regulator. In the referenced UFSAR Sections (Section 11.2 for Unit 1, and Section 10.2A.1 for Unit 

2), the staff found the information about the turbine overspeed protection function, but nothing about the "downscale failure of the inservice regulator." In RAI 2.3.5-EHC-2, the staff requested that the applicant explain the event of a "downscale failure of the inservice regulator" and the involvement of the EHC and associated components in the event. In response, the applicant stated that Unit 2 UFSAR Section 15.2.3.8 discussed the event of the "downscale failure of the inservice 

regulator," but called it "Pressure Regulator Failure -Closed." If the controlling regulator fails in the 

closed position, the backup regulator takes control of the turbine admission valves, preventing a serious transient. The event is only significant if the regulator fails closed without an operable backup regulator. Only the regulators and the piping and valves from the main steam piping to the regulators are needed for this function. The applicant stated that the main function of the EHC 

system is turbine control, which is not within the scope of license renewal. Furthermore, in a telephone conference on September 13, 2000, the applicant clarified that these regulators are instruments, which are active components (per the guidance in NEI 95-10) and therefore, are not subject to an AMR. On the basis of the information provided in the RAI response and the 

telephone conference on September 13, 2000, the staff concludes that the applicant has 

adequately clarified the nature of the "downscale failure of the inservice regulator." 

2.3.5.3 Main Condenser System 

Summary of Technical Information in the Application 

The function of the main condenser system is to provide a heat sink for turbine exhaust steam, turbine bypass steam, and other flows such as cascading heater drains, air ejector condenser 

drains, exhaust from the feed pump turbines, gland seal condenser, feedwater heater shell operating vents, and condensate pump suction vents. The main condenser also deaerates and 

provides storage capacity for the condensate water to be used. 

The main condenser system is a two-shell, single-pass, divided water box, deaerating type designed for condenser duty of 5.66 x 109 Btu/h, an inlet water temperature of 90 OF, and an 

average back pressure of 3.5 in. Hg absolute. During plant operation, steam from the last-stage, low-pressure turbine is exhausted directly downward into the condenser shells through exhaust openings in the bottom of the turbine casings. The condenser serves as a heat sink for several 

others flows, such as exhaust steam from the feed pump turbines, cascading heater drains, air ejector condenser drain, gland-seal condenser drain, feedwater heater shell operating vents, and condensate pump suction vents. Other flows occur periodically. These originate from condensate and reactor feed pump startup vents, reactor feed pump minimum recirculation flow, feedwater lines startup flushing, turbine equipment clean drains, low-point drains, extraction steam spills, makeup, and condensate. During abnormal conditions, the condenser is designed to receive (not simultaneously) turbine bypass steam, feedwater heater high-level dumps, and relief valve discharge from feedwater heater shells, steam-seal regulator, and various steam supply lines.

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The initial scoping, performed by the applicant and based on the functions, has determined that 

the post-accident radioactive decay holdup function (N61-03) of the main condenser system is the 

intended function within the scope of license renewal. The main condenser system provides a 

method for main steam isolation valve (MSIV) leakage treatment. It uses the main steam drain 

lines to convey the MSIV leakage during post-accident conditions to the isolated main condenser. 

The main condenser provides holdup and allows "plate-out" of the fission products that may leak 

out from the closed MSIV during post-accident conditions. MSIV leakage that enters the condenser 

is ultimately released to the turbine building as noncondensible gases through the low-pressure 

turbine seal after significant plate-out of iodine. This function applies to Unit 2 only. 

The associated piping, valve bodies, bolting, condenser shell, preheater, orifices, strainer, and 

thermowell are identified in LRA Table 2.3.5-2 as being subject to an AMR. The component 

functions of the valve bodies is pressure boundary, and the functions of all other components are 

pressure boundary and fission product barrier. 

Staff Evaluation 

In RAI 2.3.5-MC-1, the staff asked the applicant to explain the reason why the intended function 

of post-accident radioactive decay holdup (N61-03) for the main condenser system is not applicable 

for Unit 1. In response, the applicant stated that the licensing basis of the MSIV leakage control for 

Unit 1 and Unit 2 is different. Unit 1 was built and licensed without an MSIV leakage control 

system. Unit 2 was originally licensed with an MSIV leakage control system, but the MSIV leakage 

control system of Unit 2 was subsequently removed, with NRC approval, based on a commitment 

to include a portion of the Unit 2 condenser and associated piping as the radioactive decay holdup 

boundary for performing the MSIV leakage control function. Therefore, the intended function is not 

applicable for Unit 1. On the basis of the information provided in the RAI response, the staff 

concludes that the post-accident radioactive decay holdup function is applicable to Unit 2 only. 

2.3.5.4 Conclusion 

On the basis of the staff's review of the information presented in Section 2.3.5 of the LRA, the 

supporting information in the Plant Hatch UFSAR, the applicant's responses to the staff's RAIs, and 

the additional information provided in telephone conversations between the applicant and the staff, 

and letters dated September 13, 2000 and January 31, 2001, the staff concludes that there is 

reasonable assurance that the applicant has identified those portions of the steam and power 

conversion systems that are within the scope of license renewal, as required by 10 CFR 54.4(a), 

and subject to an AMR, as required by 10 CFR 54.21 (a)(1). 

2.4 Scoping and Screening Results: Structures and Structural Components 

2.4.1 Introduction 

The applicant described the structures and structural components that are within the scope of 

license renewal and subject to an AMR in the following sections of the LRA: 2.4.1, "Piping 

Specialties"; 2.4.2, "Conduits, Raceways, and Trays"; 2.4.3, "Primary Containment"; 2.4.4, "Fuel 

Storage"; 2.4.5, "Reactor Building"; 2.4.6, "Drywell Penetrations"; 2.4.7, "Reactor Building 

Penetrations"; 2.4.8, 'Turbine Building"; 2.4.9, "Intake Structure"; 2.4.10, "Yard Structures"; 2.4.11, 

"Main Stack"; 2.4.12, "EDG Building"; and 2.4.13, "Control Building." The staff reviewed these 

sections of the LRA to determine whether there is reasonable assurance that the applicant has

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identified all of the structures, systems, and components (SSCs) that are within the scope of 

license renewal, as required by 10 CFR 54.4(a), and all of the structures and components (SCs) 

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1). 

2.4.2 Conduits, Raceways, and Trays 

Summary of Technical Information in the Application 

LRA Section 2.4.2 describes the extent to which conduits, raceways, and trays are within the scope 

of license renewal and subject to an AMR. The purpose of conduits, raceways, and trays is to 

support cables and penetrations that are selected, routed, and located to prevent a loss of function 

of any system as a result of a cable failure, in order to ensure survivability during design-basis 

events. 

The applicant listed two intended functions for conduits, raceways, and trays. The first is function 

R33-01, "Wire and Cable Integrity." This intended function is performed by conduits, raceways, 

and trays that are mounted seismic Category I. Conduits, raceways, and trays that perform this 

intended function are considered safety-related. Seismic Category I conduits, raceways, and trays 

support essential cable that feeds power supplies and controls. The second intended function is 

R33-02, "Wire and Cable Integrity - Non-Safety-Related." This intended function is performed by 

conduits, raceways, and trays that are not mounted seismic Category I or seismic Category Il/I, and 

are considered non-safety-related. Non-safety-related conduits, raceways, and trays support non

essential cable that feeds power supplies and controls. Also, some nonseismic raceways are 

included in safe shutdown pathways. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified cable trays and supports as passive and long-lived 

components that are subject to an AMR. Specifically, the component types that were identified as 

being subject to an AMR in Table 2.4.2-1 of the LRA include cable trays and supports (carbon 

steel, galvanized steel, and aluminum). The applicant identified maintaining the structural support 

and non-safety-related structural support as the functions of these components. 

Staff Evaluation 

In Section 2.4.2 of the LRA, the applicant stated that conduits, raceways, and trays are within the 

scope of license renewal because of their wire and cable integrity intended functions. Conduits, 

raceways, and trays ensure the integrity of safety-related cables to survive a design-basis event. 

Seismic Category I conduits, raceways and trays are considered safety-related. The staff reviewed 

the application, as well as Section 8.8 of the UFSAR for Plant Hatch Unit 1 and Section 8.3 of the 

UFSAR for Plant Hatch Unit 2, to verify that the conduits, raceways, and trays do not have intended 

functions other than the cable integrity intended functions that are listed in the application. In 

addition, the staff verified that all of the components that support the cable integrity intended 

functions were identified as being within the scope of license renewal. 

The staff reviewed the LRA and supporting information in the UFSAR, and forwarded one RAI to 

the applicant by letter dated July 14, 2000. RAI 2.4-CRT-1 primarily related to defining the 

boundaries of conduits, raceways, and trays that the applicant considers to be within the scope of 

license renewal. Since the applicant did not provide drawings to show which conduits, raceways,

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and trays are considered to be within the scope of license renewal, the staff requested clarification 

as to the boundaries that define which conduits, raceways, and trays are within the scope of license 

renewal and those that are not within scope. In its response to the staff's RAI, dated August 29, 

2000, the applicant provided the following additional information to clarify the boundaries of 

conduits, raceways, and trays that are considered to be within the scope of license renewal: 

"Except for non-safety-related conduits, raceways and trays and their supports 

(R33-02) that are not located within in-scope buildings and structures, all conduits, 

raceways and trays with the intended functions R33-01 (safety-related) and the 

remaining R33-02 (non-safety-related) components are in scope for license 

renewal." 

Thus, intended functions R33-01 (Wire and Cable Integrity) and R33-02 (Wire and Cable 

Integrity/Non-Safety-Related) include the following components that are within the scope of license 

renewal: 

1. all safety-related conduits, raceways, and trays regardless of location 

2. all non-safety-related conduits, raceways, and trays that are located in buildings or 

structures that are within the scope of license renewal 

The staff finds this to be acceptable. On the basis of the staff's review of the application and the 

applicant's RAI response, the staff concludes that there is reasonable assurance that the applicant 

has identified all portions of conduits, raceways, and trays with intended functions that meet the 

criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA and the UFSAR, the staff sampled several components 

to determine whether the applicant properly identified the passive, long-lived SCs that the applicant listed as being subject to an AMR in Table 2.4-2 of the LRA. No omissions were identified. On 

the basis of this review, the staff has reasonable assurance that the applicant has identified the 

SCs related to conduits, raceways, and trays that are subject to an AMR in Table 2.4-2. 

2.4.3 Control Building 

Summary of Technical Information in the Application 

LRA Section 2.4.13 describes the basis for including the control building within the scope of license 

renewal, and identifies the components that are subject to an AMR. The control building houses 

the common control room for Units 1 and 2 and associated auxilia0es. The building is a reinforced 

concrete structure with steel framing that consists of the following major reinforced concrete 

structural components: 

0 foundation mat 

0 floors with reinforced concrete beam and girder framing 

0 reinforced concrete or concrete block interior walls 

0 columns 

0 exterior walls and prestressed exterior wall panels 

a slab on metal roof deck system supported by steel framing

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The application lists function Z29-01, "Equipment Integrity and Personnel Habitability," as the only intended function of the control building. The control building includes the substructure, 

foundations, superstructure, walls, floors, and roof, which are necessary to maintain equipment integrity and personnel habitability. The control building is designed as a seismic Category I 

structure to protect vital equipment and systems both during and following the most severe natural 

phenomena. Access doors are separately addressed under function L48-01, "Containment 

Integrity." 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components that are subject to an AMR in Table 2.4.13-1 of the LRA. Specifically, the identified 

component types include anchors and bolts, blowout panels, miscellaneous steel, reinforced 

concrete, and structural steel. The applicant identified five component functions that support the 

control building intended function of these component types. These component functions are 

structural support, non-safety-related structural support, missile barrier, fission product barrier, and 

shelter/protection. 

Staff Evaluation 

In Section 2.4.13 of the LRA, the applicant states that the control building is within the scope of 

license renewal because of its equipment integrity and personnel habitability intended function. 

The staff reviewed the application, as well as Section 12.3.3 1.1 of the UFSAR for Plant Hatch Unit 

1 and Section 3.2.1 of the UFSAR for Plant Hatch Unit 2, to verify that all control building intended 

functions are identified in the application. In addition, the staff verified that all components that 

support the control building intended function are identified as being within the scope of license 

renewal. 

On the basis of the staff's review of the application and information in the UFSAR, the staff 

concludes that there is reasonable assurance that the applicant has identified all portions of the 

control building with intended functions that meet the criteria in 10 CFR 54.4(a) as being within the 

scope of license renewal. 

Using the information provided in the LRA and the UFSAR, the staff sampled components to 

determine whether the applicant properly identified the passive, long-lived SCs that are listed as 

being subject to an AMR in Table 2.4.13-1 of the LRA. No omissions were identified. On the basis 

of this review, the staff has reasonable assurance that the applicant has identified the control 

building SCs that are subject to an AMR in Table 2.4.13-1. 

2.4.4 Drywell Penetrations 

Summary of Technical Information in the Application 

LRA Section 2.4.6 describes the extent to which drywell penetrations are within the scope of license 

renewal and subject to an AMR. Drywell penetrations provide a path for cable currents/signal 

transmissions to pass through the primary containment to support various operating modes of 

associated systems, while maintaining the integrity of the primary containment. The general 

category of containment penetrations includes both electrical penetration assemblies, as well as 

the mechanical penetrations. However, mechanical penetrations, which serve a similar function

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for mechanical piping penetrations as the electrical penetrations covered in this section, are 

covered under Section 2.4.3 of the LRA. Electrical penetrations are hermetically sealed 

penetrations thatare welded to the primary containment shell plate. They are designed to maintain 

primary containment pressure integrity during all postulated operating and accident conditions. 

Accordingly, they are designed for the same pressure and temperature conditions as the drywell 

and pressure suppression chamber. 

The application lists function T52-01, "Primary Containment Integrity," as the only intended function 

of the drywell penetrations. The penetrations maintain containment integrity, while providing a free 

path for cable currents/signals to pass through the primary containment. These signals support 

the various modes of operation of the systems that are associated with the cables. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified structural steel as the passive and long-lived component 

that is subject to an AMR in Table 2.4.6-1 of the LRA. The applicant identified the fission product 

barrier as the function of this component type. 

Staff Evaluation 

In Section 2.4.6 of the LRA, the applicant states that the drywell penetrations are within the scope 

of license renewal because of their primary containment integrity intended function. In this section 

of the LRA, the applicant referred only to electrical penetrations. Mechanical system penetrations 

are covered with the primary containment in Section 2.4.3 of the LRA. The drywell penetrations 

discussed in Section 2.4.6 provide a path for cable currents and signals to pass through the 

primary containment boundary to support operation of the various plant systems. The staff 

reviewed the application, as well as Section 5.2 of the Unit 1 UFSAR and Section 6.2.1 of the Unit 

2 UFSAR, to verify that the drywell penetrations do not perform intended functions beyond the 

primary containment integrity intended function listed in the application. In addition, the staff 

verified that all components that support the drywell penetration intended function were identified 

as being within the scope of license renewal. 

The staff reviewed the LRA and supporting information in the UFSAR, and issued an RAI related 

to this section, which was forwarded to the applicant by letter dated July 14, 2000. RAI 2.4-1 

requested that the applicant provide clarifying information (either drawings or written descriptions) 

to define the boundaries of drywell penetrations that are within the scope of license renewal. The 

drywell penetration components subject to an AMR are listed in Table 2.4.6-1 of the LRA. In its 

response to the staff's RAI, dated August 29, 2000, the applicant provided no additional 

information. However, by letter dated January 31, 2001, the applicant clarified that all drywell 

penetrations are within the scope of license renewal. The staff finds this acceptable. 

On the basis of the staff's review of the application, the staff concludes that there is reasonable 

assurance that the applicant has identified all drywell penetrations with intended functions that meet 

the criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA and the UFSAR, the staff reviewed the application to 

determine if the applicant properly identified the penetration components that are passive, long

lived, and subject to an AMR. Drywell penetration SCs that are subject to an AMR are identified 

in Table 2.4.6-1 of the LRA. No omissions were identified. On the basis of this review, the staff

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has reasonable assurance that the applicant has identified the drywell penetration SCs that are 

subject to an AMR in Table 2.4.6-1. 

2.4.5 EDG Building 

Summary of Technical Information in the Application 

LRA Section 2.4.12 describes the basis for including the emergency diesel generator (EDG) 

building within the scope of license renewal, and identifies components subject to an AMR. The 

EDG building houses the EDGs and their accessories, which are essential for safe plant shutdown 

for both Unit 1 and Unit 2. The EDG building is a reinforced concrete structure consisting of the 

following major reinforced concrete structural components: 

* foundation mat 

* exterior walls and interior walls 

• roof and parapet wall 

The EDG building includes labyrinth access openings for protection against tornado missiles. The 

building is designed as a seismic Category I structure because it protects vital equipment and 

systems both during and following the most severe natural phenomena. 

The application lists function Y39-01, "EDG and Equipment Integrity," as the only intended function 

of the EDG building. In performing this intended function, the EDG building supports the EDGs and 

their accessories, and protects the equipment integrity for the EDGs, which provide essential ac 

power. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components requiring an AMR in Table 2.4.12-1 of the LRA. Specifically, the identified component 

types include anchors and bolts, miscellaneous steel (carbon and galvanized), reinforced concrete, 

and structural steel (carbon and galvanized). The applicant identified four component functions 

that support the EDG building intended function for these component types. These component functions are structural support, non-safety-related structural support, missile barrier, and 

shelter/protection. 

Staff Evaluation 

In Section 2.4.12 of the LRA, the applicant stated that the emergency diesel generator (EDG) 

building is within the scope of license renewal because of its EDG and equipment integrity intended 

function. The staff reviewed the application, as well as Section 12.2.6 of the Unit 1 UFSAR and 

Section 9.4.5 of the Unit 2 UFSAR, to verify that all EDG building intended functions are identified 

in the application. In addition, the staff verified that all components that support the EDG building 

intended function are identified as being within the scope of license renewal. 

In its review of the LRA and supporting information in the UFSAR, the staff forwarded one RAI to 

the applicant by letter dated July 14, 2000. RAI 2.4-EDGB-1 primarily related to clarifying 

information on whether ventilation components for the EDG (both cooling and combustion air) are 

within the scope of license renewal. EDG building components subject to an AMR are listed in

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Table 2.4.12-1 of the LRA. The following summarizes the information provided in the applicant's 

RAI response, dated August 29, 2000: 

The following components associated with the EDG are within the scope of license renewal: 

the EDG combustion air intake and exhaust air components (intended function R43-01), 

and the EDG building ventilation components (intended functions X41-02, X41-03, X41-04, 

and X41-05). The ventilation components are listed on LRA Table 2.3.4-17. The following 

combustion components are listed on LRA Table 2.3.4-12: filter housing, carbon steel 

piping, and galvanized steel piping. 

The staff finds the applicant's RAI response to be acceptable. On the basis of the staff's review 

of the application and the applicant's RAI response, the staff concludes that there is reasonable 

assurance that the applicant has identified all portions of the EDG building with intended functions 

that meet the criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA, the applicant's RAI response, and the UFSAR, the staff 

sampled components to determine whetherthe applicant properly identified the passive, long-lived 

SCs that are listed as being subject to an AMR in Table 2.4.12-1 of the LRA. No omissions were 

identified. On the basis of this review, the staff has reasonable assurance that the applicant has 

identified the EDG building SCs that are subject to an AMR in Table 2.4.12-1, or in other 

appropriate sections of the LRA. 

2.4.6 Fuel Storage 

Summary of Technical Information in the Application 

LRA Section 2.4.4 provides a description of the extent to which the fuel storage system is within 

the scope of license renewal and subject to an AMR. The fuel storage system provides specially 

designed underwater storage space for the spent-fuel assemblies that require shielding during 

storage and handling. The fuel storage facility is located inside the secondary containment on the 

refueling floor, and includes the spent fuel pool, concrete vault and stainless steel liner, fuel pool 

gates, fuel racks, and other equipment that is necessary to properly store irradiated fuel and 

components. 

The application lists two intended functions of the fuel storage system. The first is function T24-01, 

"Spent Fuel Integrity." This intended function is performed by the spent fuel pool, concrete vault 

and stainless steel liner, fuel pool gates, fuel racks, and other equipment that is necessary to 

properly store irradiated fuel and components. The fuel storage facility provides specially designed 

underwater storage space for the spent fuel assemblies that require shielding and cooling during 

storage and handling. The second intended function is T24-02, "New Fuel Integrity." This intended 

function is performed by the concrete vault and fuel racks. The portion of the fuel storage facility 

provides specially designed dry, clean storage areas for the new fuel assemblies. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components that are subject to an AMR in Table 2.4.4-1 of the LRA. Specifically, the identified 

component types include anchors/bolts (carbon and stainless steel), miscellaneous steel, 

reinforced concrete, seismic restraints for the spent fuel storage racks (aluminum), storage racks

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(aluminum), and structural steel. The applicant identified four functions of these components, including structural support, non-safety-related structural support, shelter/protection, and fission 

product barrier. 

Staff Evaluation 

In Section 2.4.4 of the LRA, the applicant stated that the fuel storage system is within the scope of license renewal because of its spent and new fuel integrity intended functions. The fuel storage system ensures integrity by providing safe storage either under water for spent fuel or in dry storage for new fuel. The staff reviewed the application, as well as Sections 10.2 and 10.3 of the 

Unit 1 UFSAR and Section 9.1 of the Unit 2 UFSAR, to verify that the fuel storage system does not 

have intended functions beyond the fuel integrity intended functions listed in the application. In 

addition, the staff verified that all components that support the fuel integrity intended functions were 

identified as being within the scope of license renewal. 

The staff reviewed the LRA and supporting information in the UFSAR, and forwarded three RAIs 

to the applicant by letter dated July 14, 2000. RAls 2.4-FS-1, 2.4-FS-2, and 2.4-FS-3 primarily related to clarifying information on the fuel storage system components subject to an AMR, as 

listed on Table 2.4.4-1 of the LRA. Since the applicant did not provide drawings to show which SCs 

are considered to be within the scope of license renewal, the staff requested clarification as to the 

boundaries that define which SCs are subject to an AMR. In its response to the staff's RAIs, dated 

August 29, 2000, the applicant provided the following additional information and clarifications: 

The new fuel storage racks are made of aluminum. The spent fuel storage racks are made 

of stainless steel and include Boral as a neutron absorber material. These racks were 

identified as Structural Steel in Table 2.4.4-1. 

The spent fuel storage racks are credited in maintaining the stored spent fuel in a 

subcritical state under all normal and abnormal storage configurations. The Boral plates 

are used as a neutron absorber. Therefore, reactivity control is an intended function of the 

Boral plates. The applicant determined that Boral had no aging effects that required I 

management. I 

The term "other equipment" used in the application in describing the boundaries of SCs that 

perform intended function T24-01 (Spent Fuel Integrity) includes items such as 

miscellaneous embedded steel, anchors and bolts, and a leak chase system. These items 

also contribute to maintaining the integrity of the spent fuel pool to meet its intended 

function. 

On the basis of its response to the staff's RAIs, the applicant provided amended information which I corresponds to the relevant line items in Table 2.4.4-1. The new fuel storage racks and spent fuel 

storage racks, their functions, and their materials are explicitly identified. Boral was added as a I 

component material, and reactivity control was added as a component function for the spent fuel 

storage racks. 

The staff finds the applicant's RAI responses to be acceptable. On the basis of the staff's review 

of the application and the applicant's RAI responses, the staff concludes that there is reasonable 

assurance that the applicant has identified all portions of the fuel storage system with intended 

functions that meet the criteria in 10 CFR 54.4(a) as being within the scope of license renewal.

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Using the information provided in the LRA and the UFSAR, the staff sampled several components 

to determine whether the applicant properly identified the passive, long-lived SCs that are listed as 

being subject to an AMR in Table 2.4.4-1 of the LRA. No omissions were identified. On the basis 

of this review, the staff has reasonable assurance that the applicant has identified the fuel storage 

system SCs that are subject to an AMR in Table 2.4.4-1. 

2.4.7 Intake Structure 

Summary of Technical Information in the Application 

LRA Section 2.4.9 describes the basis for including the plant service water system intake structure 

within the scope of license renewal, and for identifying its components as being subject to an AMR. 

The intake structure protects both the residual heat removal service water and plant service water 

equipment from the influence of adverse environmental conditions such as flooding, earthquakes, 

and tornadoes. Constructed of concrete and steel, the intake structure consists of the following 

major structural components: 

0 reinforced concrete foundation mat 

* reinforced concrete exterior walls and internal walls 

0 reinforced concrete floors and roof 

* structural steel framing and grating, steel water spray and internal missile shield barriers, 

stairs, and platforms 

The intake structure is shared by both units. Labyrinth access openings protect the intake structure 

internal safety-related components from tornado missiles. 

The application lists function W35-01, "RHRSW and PSW System Integrity," as the only intended 

function of the intake structure. The purpose of the intake structure is to prevent the influence of 

environmental conditions (e.g., flooding, earthquake, and tornadoes) from adversely impacting 

equipment that is essential for plant shutdown. The intake structure is a seismic Category I 

structure. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components requiring an AMR in Table 2.4.9-1 of the LRA. Specifically, the identified component 

types include anchors and bolts, miscellaneous steel (carbon and galvanized), reinforced concrete, 

and structural steel (carbon and galvanized). The applicant identified six component functions that 

support the intake structure intended function of these component types. These component 

functions are structural support, non-safety-related structural support, shelter/protection, flood 

barrier, missile barrier, and flow direction. 

Staff Evaluation 

In Section 2.4.9 of the LRA, the applicant states that the plant service water (PSW)/residual heat 

removal service water (RHRSW) system intake structure is within the scope of license renewal 

because of its RHRSW and PSW system integrity intended function. The staff reviewed the 

application, as well as Section 12.2.7 of the Unit 1 UFSAR and Sections 3.8.4, 3.8.5, and 3.8.6 of 

the Unit 2 UFSAR, to verify that all intake structure intended functions are identified in the

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application. In addition, the staff verified that all components that support the intake structure 

intended function are identified as being within the scope of license renewal. 

In its review of the LRA and supporting information in the UFSAR, the staff forwarded four RAIs 

to the applicant by letter dated July 14, 2000. RAIs 2.4-IS-1, 2.4-IS-2, 2.4-IS-3, and 2.4-IS-4 

primarily related to clarifying information regarding whether intake structure components have been 

adequately identified as being within the scope of license renewal. Intake structure components subject to an AMR are listed in Table 2.4.9-1 of the LRA. The following summarizes the new and 

clarifying information provided in the applicant's RAI responses, dated August 29, 2000: 

The difference between "miscellaneous steel" and "structural steel" in Table 2.4.9-1 is that 

structural steel is defined as substructure or superstructure steel that is part of the primary 

structural support function of a building or structure. Miscellaneous steel is defined as steel 

that does not perform a primary structural integrity function for a building, but does provide secondary structural support for equipment or components that are within the building. In 

some cases, it may provide protection around openings in floors or walls. For the intake 

structure, structural steel includes steel barriers utilized as water spray barriers and 

internally generated missile barriers. Miscellaneous steel includes embedded plates and/or 

frames and anchors used to support the missile or spray shields. The term "flow direction" 

used in LRA Table 2.4.9-1 is a label described in LRA Table 2.1-2 as "Provide spray shield 

or curbs for directing flow." 

Coarse trash racks, trash rakes, traveling water screens, and stop logs are within the scope of license renewal. Trash rakes and water screens are included in the traveling water 

screen/trash rack system, and stop logs are included in the intake structure. Traveling water 

screens and trash racks are described in LRA Section 2.3.4.16 and Table 2.3.4-16. Stop logs and steel supports for the trash racks are included in Section 2.4.9 of the LRA. In LRA 

Table 2.4.9-1, stop logs are included as structural steel components, and trash rack 

supports are included as miscellaneous steel components. Aging management of these 

components is addressed in Section C.2.6.3 of the LRA. 

The steel sheet piles are not considered to be within the scope of license renewal. The 

sheet piles were installed to facilitate dewatering of the intake structure excavation, and 

subsequent construction of the intake structure. As described in Section 12.2.7 of the Unit 

1 UFSAR, the sheet piles provide protection to the intake structure from a direct hit by river 

traffic or debris flowing across the river channel. However, the UFSAR states that the sheet 

piles could fail and not prevent a safety function. Wood fender piles provide protection to 

the sheet pile cells by dissipating dynamic effects of moving loads. Impact of debris or river 

traffic on the sheet piles, wood fender piles, or on the front of the intake structure would not 

prevent the structure from providing water to the plant service water and RHR service water 

systems. 

The creosote wall constructed near the intake structure is not considered to be within the 

scope of license renewal. The UFSAR does describe the creosote wall as rerouting river 

water flow and preventing undercutting of the intake structure. However, given the flow 

characteristics of the river, and the river channel being located near the north bank and the, intake structure being located on the south bank of the river, undercutting of the intake 

structure is not a credible event requiring protection for the Plant Hatch intake structure. 

Therefore, the creosote wall was not considered to be within the scope of license renewal.

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The staff finds the applicant's RAI responses to be acceptable. On the basis of the staff's review 

of the application and the applicant's RAI responses, the staff concludes that there is reasonable 

assurance that applicant has identified all portions of Intake Structure with intended functions that 

meet the criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA, the applicant's RAI responses, and the UFSAR, the staff 

sampled components to determine whether the applicant properly identified the passive, long-lived 

SCs that are listed a§ being subject to an AMR in Table 2.4.9-1 of the LRA. No omissions were 

identified. On the basis of this review, the staff has reasonable assurance that the applicant has 

identified the Intake Structure SCs that are subject to an AMR in Table 2.4.9-1, or in other 

appropriate sections of the LRA. 

2.4.8 Main Stack 

Summary of Technical Information in the Application 

LRA Section 2.4.11 describes the basis for including the main stack within the scope of license 

renewal, and for identifying components subject to an AMR. The main stack supports and protects 

monitoring equipment, and provides for the monitoring and elevated release of gaseous waste. 

The main stack is a cylindrical concrete structure that consists of the following major reinforced 

concrete components: 

• the foundation mat supported on steel "H" piles 

• the truncated conical cylinder stack structure 

• the internal floors 

• the loading bay, which consists of a concrete base slab, external and internal walls, and 

roof 

Units 1 and 2 share a single main stack used to discharge gaseous waste. The main stack extends 

120 meters above ground level. 

The application lists function Y32-01, "Gaseous Effluent Elevated Release," as the only intended 

function of the main stack. In performing this intended function, the main stack houses equipment 

for monitoring gaseous effluent releases and ensures elevated release of these gaseous wastes 

to the environment. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components requiring an AMR in Table 2.4.11-1 of the LRA. Specifically, the identified component 

types include anchors and bolts (carbon and stainless steel, copper alloy (bronze)), miscellaneous 

steel (galvanized), reinforced concrete, and structural steel (galvanized). The applicant identified 

five component functions that support the main stack intended function of these component types. 

These component functions are structural support, non-safety-related structural support, fission 

product barrier, radiation shielding, and shelter/protection.

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Staff Evaluation

In Section 2.4.11 of the LRA, the applicant states that the main stack is within the scope of license 

renewal because of its gaseous effluent elevated release intended function. The staff reviewed 

the application, as well as Section 5.3.4 of the Unit 1 UFSAR and Section 11.3 of the Unit 2, to 

verify that all main stack intended functions are identified in the application. In addition, the staff 

verified that all components that support the main stack intended function are identified as being 

within the scope of license renewal. 

On the basis of the staff's review of the application and supporting UFSAR information, the staff 

concludes that there is reasonable assurance that the applicant has identified all portions of the 

main stack with intended functions that meet the criteria in 10 CFR 54.4(a) as being within the 

scope of license renewal. 

Using the information provided in the LRA and the UFSAR, the staff sampled components to 

determine whether the applicant properly identified the passive, long-lived SCs that are listed as 

being subject to an AMR in Table 2.4.11-1 of the LRA. No omissions were identified. On the basis 

of this review, the staff has reasonable assurance that the applicant has identified the main stack 

SCs that are subject to an AMR in Table 2.4.11-1. 

2.4.9 PiDing Specialties 

Summary of Technical Information in the Application 

LRA Section 2.4.1 describes of the extent to which structural piping supports are within the scope of license renewal and subject to an AMR. Piping specialties provide support for essential piping systems. The application defines "essential piping systems" as those required to maintain the 

integrity of safety-related and non-safety-related systems during normal operations and 

transientlaccident mitigation. Section 2.4.1 also states that the "piping specialties" category also 

includes such components as snubbers and pipe restraints, regardless of the associated system supported, as well as non-ASME HVAC duct supports and tube trays. 

The applicant listed two intended functions of piping specialties. The first is function L35-01, "Pipe Supports." This intended function is performed by all safety-related plant pipe supports, pipe restraints, and tubing supports. These pipe supports are provided for the reactor coolant system and subsystems to ensure the pressure-retaining capability of the piping systems when subjected to weight, seismic, and fluid dynamic loads. Pipe supports maintain the integrity of non-safety functions during accident and seismic events. The second intended function is L35-02, "Nonseismic Pipe Supports." This intended function is performed by pipe supports on non-safety related piping (nonseismic category) located throughout the plant. These supports are designed only for dead weight and thermal loads. They are not designed for seismic loads. Section 2.4.1 

of the LRA states that all seismic Category II supports are excluded from the scope of license 

renewal, unless they are required to support functions X43-04 (Plant Wide Fire Suppression With 

Water), W33-03 (Screen Wash Isolation), and N61-03 (Post-Accident Radioactive Decay Holdup). 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified pipe supports, tube trays, and covers as passive and

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long-lived components which require AMRs. The following three component types were specifically 

identified as being subject to an AMR in Table 2.4.1-1 of the LRA: 

* hangers and supports for ASME Class I piping o hangers and supports for non-ASME Class I piping, tubing, and ducts 

* tube trays and covers 

The applicant identified maintaining structural support as the component function that supports the 

piping specialties intended functions for these component types. 

Staff Evaluation 

In Section 2.4.1 of the LRA, the applicant states that piping specialties are within the scope of 

license renewal because of their piping support intended functions. These piping supports ensure 

the pressure retaining capability of piping, and are designed to withstand weight, seismic, and fluid 

dynamic loads. The staff reviewed the application to verify that the piping specialties do not have 

intended functions other than the piping support intended functions listed in the application. In 

addition, the staff verified that all components that support the piping support intended functions 

were identified as being within the scope of license renewal. 

The staff reviewed the LRA and supporting information in the UFSAR, and forwarded several RAIs 

to the applicant by letter dated July 14, 2000. RAIs 2.4-PS-1, 2.4-PS-2, and 2.4-PS-3 primarily 

related to defining the boundaries of piping supports that the applicant considered to be within the 

scope of license renewal. Since the applicant did not provide drawings to show which piping 

specialty components are considered to be within the scope of license renewal, the staff requested 

clarification as to the boundaries that define the piping supports that are within the scope of license 

renewal, and those that are not within scope. In its response to the staff's RAIs, dated August 29, 

2000, the applicant provided the following additional information to clarify the scope of piping 

supports that are considered to be within the scope of license renewal: 

"Pipe supports for non-safety-related piping that ensure the functionality of 

boundary valves that separate portions of systems required to remain functional 

during and after a design basis event are included in function L35-01. These 

supports comprise the group referenced in the second sentence of the L35-01 

intended function in Section 2.4.1 that states, "[Other] Pipe supports maintain the 

integrity of non-safety functions during accident and seismic events." This sentence 

can be clarified to state that these non-safety pipe supports, which are located in 

Seismic Category I structures, are considered for Seismic Il/I criteria to prevent 

failure of the non-safety piping system from adversely impacting the ability of a 

safety system to perform its function. Thus, all pipe supports located in a Seismic 

Category I structure, regardless if the supports are for safety-related or non-safety

related systems, are conservatively included in function L35-01 and are in-scope for 

license renewal. The only Seismic Category II supports not located in a Seismic 

Category I structure that are included in-scope for license renewal are for functions 

X43-04, W33-03, and N61-03." 

Thus, intended function L35-01 (Pipe Supports) includes piping supports that are qualified to 

seismic Category I or seismic Category Il/I requirements, regardless of system designation. The 

staff finds this to be acceptable. On the basis of the staff's review of the application and the

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applicant's RAI responses, the staff concludes that there is reasonable assurance that the applicant 

has identified all portions of the piping specialties with intended functions that meet the criteria in 

10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA, the staff sampled several components to determine 

whether the applicant properly identified the passive, long-lived SCs that are listed as being subject 

to an AMR in Table 2.4-1 of the LRA. No omissions were identified. Treatment of piping 

segments for seismic Category Il/I is addressed in Section 2.1.3.1 of this SER. On the basis of this 

review, the staff has reasonable assurance that the applicant has identified the piping specialty SCs 

that are subject to an AMR in Table 2.4.1-1. 

2.4.10 Primary Containment 

Summary of Technical Information in the Application 

LRA Section 2.4.3 describes the primary containment and its intended function, which places it 

within the scope of license renewal and identifies it as being subject to an AMR. The purpose of 

the primary containment is to isolate and contain fission products that are released from the reactor 

primary system following a design-basis accident (DBA), and to confine the postulated release of 

radioactive material. The primary containment is a pressure suppression containment design which 

consists of a drywell, a pressure suppression chamber (torus) that stores a large volume of water 

(the suppression pool), a connecting vent system between the drywell and the pressure 

suppression pool, isolation valves, vacuum relief system, containment cooling systems, and other 

service equipment. The drywell houses the reactor vessel, the reactor coolant recirculating loops, 

and other branch connections of the reactor primary system. The pressure suppression chamber 

is a steel, torus-shaped pressure vessel located below the drywell. The torus is approximately 107 

ft in its outer diameter and has a cross-sectional diameter of approximately 28 ft. The primary 

containment is designed so that seismic loadings are transmitted by the suppression chamber to 

the reinforced concrete foundation slab of the reactor building. The suppression chamber is 

designed so that it can be inspected from the outside. 

The applicant provided nine evaluation boundary drawings for Unit 1 and seven drawings for Unit 

2, all of which had intended function designations marked on the drawing to indicate the piping that 

is within the scope of license renewal because of the torus/drywell function (T23-01) intended 

function. These drawings are HL-1 6013, HL-16015, HL-1 6024, HL-1 6060, HL-1 6135, HL-1 6173, 

HL-16176, HL-16286, HL-16561, HL-26016, HL-26026, HL-26042, HL-26047, HL-26057, HL

26058, and HL-26993. The applicant lists T23-01, "Torus/Drywell," as the only intended function 

of the primary containment. The intended function of the primary containment system is to limit the 

release of fission products in the event of a postulated DBA so that offsite doses do not exceed the 

guidelines of 10 CFR Part 100. The pressure suppression pool initially serves as a heat sink for 

any postulated transient or accident condition in which the normal heat sink (main condenser or 

shutdown cooling system) is unavailable. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components which require AMRs in Table 2.4.3-1 of the LRA. Specifically, the identified 

components include anchors/bolts, blind flanges, containment isolation valves (carbon and 

stainless steel), containment penetrations (mechanical), miscellaneous steel, piping (carbon and

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stainless steel), reinforced concrete, steel bellows, structural steel, tubing, unreinforced concrete, 

vent pipe, vent header, and downcomers. The applicant identified several functions of these 

components, including structural support, non-safety-related structural support, fission product barrier, radiation shielding, pipe whip restraint, flood barrier, shelter/protection, missile barrier, high energy/moderate energy (HE/ME) shielding, heat exchange, and pressure boundary. 

Staff Evaluation 

In Section 2.4.3 of the LRA, the applicant stated that the primary containment system is within the 

scope of license renewal because of its intended function to limit the release of fission products during a design basis accident. The staff reviewed the application, as well as Sections 5.1.2 of the 

Unit 1 UFSAR and Section 6.2.1 of the Unit 2 UFSAR, and the 16 drawings provided by the 

applicant (showing the portions of the primary containment that are within the scope of license 

renewal), to verify that all of the primary containment intended functions are identified in the 

application. In addition, the staff verified that all components that support the primary containment 

intended function are identified as being within the scope of license renewal. 

The staff reviewed the LRA, the drawings provided by the applicant, and supporting information in 

the UFSAR, and forwarded two RAIs to the applicant by letter dated July 14,2000. RAIs 2.4-PC-1 

and 2.4-PC-2 primarily related to clarifying information on the primary containment system 

components subject to an AMR, as listed in Table 2.4.3-1 of the LRA. The following summarizes 

the staff's RAIs and the applicant's responses, dated August 29, 2000: 

Unidentified component number D001, located at position G3 on DWG HL-26016, was 

identified on the drawing as supporting intended function T23-01 (Torus/Drywell) and as 

being within the scope of license renewal. The staff could not determine what type of 

component it was from the legend provided by the applicant. In its RAI response, the 

applicant stated that this component is a flex hose made of stainless steel and was 

screened as piping in Table 2.4.3-1 of the LRA. In addition, the applicant stated that the 

aging management of this component can be found in Section C.2.2.9.2 of the LRA. 

The applicant neglected to identify five components as being within the scope of license 

renewal for the primary containment in drawings referenced for intended function T23-01, 

even though they do perform a primary containment pressure boundary function. 

Specifically, the five omitted components include 1) the tubing segment penetrating the 

primary containment at position B2 on DWG HL-26057, 2) the tubing segment penetrating 

the primary containment at position A2 on DWG HL-26057, 3) the personnel lock located 

at position D2 on DWG HL-26057, 4) the two equipment access hatches and the control 

rod drive removable hatch described in Section 3.8.2.1.3 of the Unit 2 UFSAR, and 5) the 

traversing in-core probe guide tube penetration described ection 3.8.2.1 of the Unit 2 

UFSAR. The staff requested that the applicant indicate where these components are 

evaluated for an AMR in the LRA, or justify their exclusion from the scope of license 

renewal. In its RAI response, the applicant stated that tubing segments are routinely 

identified in the LRA as piping. The specific tubing segments penetrating the primary 

containment at A2 and B2 on HL-26057 are included in LRA Table 3.3.1-3 as piping. (This 

table links to LRA Section C.2.2.9.2 for the AMR and demonstration.) Personnel locks and 

equipment hatches penetrating containment are identified in LRA Table 2.4.3-1 as intended 

function T23-01 penetrations. The TIP is included in function C51-03 (Traversing In-core 

Probe), and is not within the scope of license renewal. However, the TIP guide tube does

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support primary containment intended function T23-01, and is addressed in Table 2.4.3-1. 

The penetration for the TIP guide tube is covered under intended function T52-01 (Primary 

Containment Integrity) in Section 2.4.6 of the LRA. 

The staff finds the applicant's RAI responses to be acceptable. On the basis of the staff's review 

of the application and the applicant's RAI responses, the staff concludes that there is reasonable 

assurance that the applicant has identified all portions of the primary containment system with 

intended functions that meet the criteria in 10 CFR 54.4(a) as being within the scope of license 

renewal. 

Using the information provided in the LRA and the UFSAR, the staff sampled several components 

to determine whether the applicant properly identified the passive, long-lived SCs that are listed as 

being subject to an AMR in Table 2.4.3-1 of the LRA. No omissions were identified. On the basis 

of this review, the staff has reasonable assurance that the applicant has identified the primary 

containment system SCs that are subject to an AMR in Table 2.4.3-1. 

2.4.11 Reactor Buildinq 

Summary of Technical Information in the Application 

LRA Section 2.4.5 describes the extent to which the reactor building is within the scope of license 

renewal and subject to an AMR. The purpose of the reactor building is to shelter and support the 

refueling and reactor servicing equipment, new and spent fuel storage facilities, and other reactor 

auxiliary and service equipment. The building is a reinforced concrete structure with a steel 

superstructure that consists of the following major reinforced concrete structural components: 

0 foundation mat 

• exterior walls and prestressed exterior wall panels 

* floors with reinforced concrete beams and girders framing 

* interior walls with some blockouts filled with concrete masonry 

0 roof slab on metal roof deck system supported by steel superstructure 

The reactor building also completely houses the primary containment system, as well as the core 

standby cooling systems, reactor water cleanup demineralizer system, standby liquid control 

system, control rod drive system, reactor protection system, and electrical equipment components. 

The building is designed for minimum leakage to ensure the capability of the standby gas treatment 

system to reduce and hold the reactor building at a subatmospheric pressure under normal wind 

conditions. 

The application lists intended function T29-01, "Containment and Support," as the only intended 

function of the reactor building. The reactor building provides primary containment during reactor 

refueling and maintenance operations. During these conditions, the primary containment may be 

open. When the primary containment is functional, the reactor building also provides an additional 

barrier to fission product release. Therefore, it is relied on to prevent or mitigate the consequences 

of accidents that could result in potential offsite exposure comparable to the guidelines of 10 CFR 

Part 100. This evaluation includes the blowout panels in the pipe-chase between the reactor 

building and the turbine building.

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The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components which require AMRs in Table 2.4.5-1 of the LRA. Specifically, the identified 

component types include anchors/bolts, blowout panels, (aluminum) miscellaneous steel, panel 

joint seals and sealants, reinforced concrete, and structural steel. The applicant identified various 

functions for these components, including structural support, non-safety-related structural support, 

HE/ME shielding, flood barrier, radiation shielding, missile barrier, fire barrier, shelter/protection, 

and fission product barrier. 

Staff Evaluation 

In Section 2.4.5 of the LRA, the applicant states that the reactor building is within the scope of 

license renewal because of its intended function to mitigate the consequences of accidents that 

could result in offsite exposure comparable to the guidelines in 10 CFR Part 100. The staff 

reviewed the application, as well as Section 12.2.1 of the Unit 1 UFSAR and Section 3.0 of the Unit 

2 UFSAR, to verify that all reactor building intended functions are identified in the application. In 

addition, the staff verified that all components that support the reactor building intended function 

are identified as being within the scope of license renewal and subject to an AMR. 

In its review of the LRA and supporting information in the UFSAR, the staff forwarded three RAIs 

to the applicant by letter dated July 14, 2000. RAIs 2.4-RB-1, 2.4-RB-2, and 2.4-RB-3 primarily 

related to clarifying information regarding the boundaries of the reactor building that are within the 

scope of license renewal, as well as clarifying information as to whether certain components are 

within the scope of license renewal. Reactor building components subject to an AMR are listed in 

Table 2.4.5-1 of the LRA. The following summarizes the information provided in the applicant's RAI 

responses, dated August 29, 2000: 

The reactor building structural components that are within the scope of license renewal 

include the refueling water seal assembly, the main steam line enclosure, the reactor 

pedestal, and the reactor coolant pump supports. The applicant indicated that the refueling 

water seal assembly is generically included in LRA Table 2.4.3-1 under "Structural Steel," 

the main steam line enclosure is included in Table 2.4.3-1 under the generic heading of 

"Concrete," and the reactor pedestal is included in LRA Table 2.4.3-1. The reactor pedestal 

is made of unreinforced concrete encased in a structural steel frame for Unit 2, and of 

reinforced concrete for Unit 1. In addition, the lug support attachments at the reactor 

recirculation pumps are evaluated as part of the pump casing in LRA Table 2.3.2-1 of the 

LRA. The supports and lug attachments to the structural steel are evaluated in LRA Table 

2.4.1-1 as part of hangers and supports for ASME Class 1 piping. The foam glass inserts 

between buildings, described in Section 12.2.15.2.2 of the Unit 1 UFSAR, are not within the 

scope of license renewal. The foam glass originally maintained a gap between structures 

during construction so that there can be free movement during an earthquake. After 

construction of the plant, the foam glass was removed in all areas except below grade 

between the reactor building and its adjacent structures (control, turbine, and radwaste 

buildings). The foam glass served only as form work for maintaining the gap, and has no 

intended structural function. 

In general, the LRA includes the entire reactor building, along with all structural components 

that are within its boundary, within the scope of license renewal. These components are

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primarily evaluated under function T29-01 (Containment and Support). However, several items have been addressed in greater detail in separate sections. For example, these 

separate sections in the reactor building include SCs with intended functions associated 

with primary containment (Torus/Drywell [T23-01]), fuel storage (Spent Fuel Integrity [T24 01] and New Fuel Integrity [T24-02]), penetrations (Primary Containment Integrity [T52-01] and Secondary Containment Integrity [T54-01 ]), cranes (Reactor Building Crane [T31-02]), tornado vents (Pressure Equalization [T38-01]), and so forth. These SCs were separately considered to facilitate evaluation of the components for specialized loadings, environmental parameters, and/or aging effects. 

In RAI-2.4-RB-3, the staff stated that airlock water stops appear to perform an intended 

function because they are part of the pressure boundary for the secondary containment. 

Accordingly, they should be included within the scope of license renewal. The applicant responded that only the three-bulb rubber water stop in the joint between the railroad airlock 

and the reactor building should have been in the LRA. The applicant stated that the three

bulb water stop is part of the pressure boundary for the secondary containment, does 

contribute to the intended function, and should have been included in the LRA. The applicant stated that the water stop will be subject to an AMR, and the results will be 

provided in a subsequent submittal. By letter dated January 31,2001, the applicant stated that a screening record was prepared for the three-bulb waterstop embedded in the 

separation joint between the Unit 1 reactor building and the railroad airlock structure. Thus, the three-bulb waterstop has been added to the scope of license renewal. The letter stated 

that the intended function of this waterstop is to provide a pressure boundary or a fission 

product retention barrier to protect public health and safety during any postulated design basis events. The waterstop has been addressed by an AMR. 

On the basis of the staff's review of the application and the applicant's RAI responses, as well as the clarifying information provided in the applicant's letter dated January 31, 2001, the staff concludes that there is reasonable assurance that the applicant has identified all portions of the 

reactor building with intended functions that meet the criteria in 10 CFR 54.4(a) as being within the 

scope of license renewal. 

Using the information provided in the LRA, the applicants RAI responses, and the UFSAR, the staff sampled several components to determine whether the applicant properly identified the passive, long-lived SCs that are listed as being subject to an AMR in Table 2.4.5-1 of the LRA. No omissions were identified. On the basis of this review, the staff has reasonable assurance that the applicant has identified the reactor building SCs that are subject to an AMR in Table 2.4.5-1, or in 

other appropriate sections of the LRA. 

2.4.12 Reactor Building Penetrations 

Summary of Technical Information in the Application 

LRA Section 2.4.7 describes the basis for including reactor building penetrations that are within the 

scope of license renewal, and for identifying components subject to an AMR. The purpose of the 

reactor building penetrations is to allow mechanical and electrical equipment and personnel to pass through the secondary containment to support plant operations, while maintaining secondary containment integrity within design limits. As noted in LRA Section 2.4.5, the reactor building provides a barrier to fission product release when the primary containment is open (e.g., for

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refueling or maintenance operations). Penetrations for piping and ducts are designed for leakage 

characteristics consistent with containment requirements for the entire building. Electrical cables 

and instrument leads pass through ducts that are sealed into the building wall. 

The application lists function T54-01, "Secondary Containment Integrity," as the only intended 

function of reactor building penetrations. In performing this intended function, reactor building 

electrical and mechanical penetrations maintain secondary containment leakage rates within design 

limits, while allowing piping and conductors to penetrate the secondary containment boundary. The 

applicant stated that this function also includes the structural support feature of Nelson Frames. 

The electrical aspect of Nelson Frames is included as part of Electrical Screening (refer to LRA 

Table 2.5.15-1), and is evaluated in Section 2.5 of this SER. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified structural steel (galvanized and carbon steel) as the 

passive and long-lived component requiring an AMR in Table 2.4.7-1 of the LRA. The applicant 

identified the fission product barrier as the function of this component type. 

Staff Evaluation 

In Section 2.4.7 of the LRA, the applicant states that the reactor building penetrations are within 

the scope of license renewal because of their secondary containment integrity intended function. 

In this section of the LRA, the applicant referred to both mechanical and electrical penetrations. 

The reactor building penetrations discussed in Section 2.4.7 provide a path for mechanical and 

electrical components and signals, and personnel, to pass through the secondary containment to 

support pperating modes of various plant equipment and systems, while maintaining secondary 

containment integrity. The staff reviewed the application, as well as Section 5.3.3.2 of the Unit 1 

UFSAR and Figure 8.3-11 of the Unit 2 UFSAR, to verify that the reactor building penetrations do 

not perform intended functions beyond the secondary containment integrity intended function listed 

in the application. In addition, the staff verified that all components that support the reactor building 

penetration intended function were identified as being within the scope of license renewal. 

The staff reviewed the LRA and supporting information in the UFSAR, and issued an RAI related 

to this section, which was forwarded to the applicant by letter dated July 14, 2000. RAI 2.4-1 

requested that the applicant provide clarifying information (either drawings or written descriptions) 

to define the boundaries of reactor building penetrations that are within the scope of license 

renewal. The reactor building penetration components subject to an AMR are listed in Table 2.4.7

1 of the LRA. In its response to the staff's RAI, dated August 29, 2000, the applicant provided no 

additional information. However, by letter dated January 31, 2001, the applicant clarified that all 

external reactor building penetrations are within the scope of license renewal. The staff finds this 

acceptable. 

On the basis of the staff's review of the application, the staff concludes that there is reasonable 

assurance that the applicant has identified all reactor building penetrations with intended functions 

that meet the criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA and the UFSAR, the staff sampled components to 

determine if the applicant properly identified the penetration components that are passive, long

lived, and subject to an AMR. Reactor building penetration SCs that meet the intended function

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are subject to an AMR and are identified in Table 2.4.7-1 of the LRA. No omissions were 

identified. On the basis of this review, the staff has reasonable assurance that the applicant has 

identified the reactor building penetration SCs that are subject to an AMR in Table 2.4.7-1. 

2.4.13 Turbine Building 

Summary of Technical Information in the Application 

LRA Section 2.4.8 describes the basis for including the turbine building within the scope of license 

renewal, and identifies the components subject to an AMR. The turbine building houses the 

turbine-generator and associated auxiliaries, such as the condensate and feedwater systems. Constructed of steel and concrete, the turbine building consists of the following major, reinforced 

concrete, structural components: 

• foundation mat 

• both self-supporting floors and floors supported by structural steel framing 

* concrete block or reinforced concrete interior walls 

* turbine pedestal resting on concrete mat foundation 

* exterior walls 

• concrete slab on metal roof deck system supported by steel framing 

The turbine building does not house any equipment or instrumentation that would preclude the 

ability to safely shut down the reactor if it were damaged by a high-energy line failure. The turbine 

building is designed and constructed to ensure that it will not damage Category I structures or 

equipment located inside or adjacent to it in the event of a design-basis event (DBE). 

The application lists function U29-01, "BOP [Balance of Plant] Equipment Integrity and Support," 

as the only intended function of the turbine building. This intended function places portions of the 

turbine building within the scope of license renewal. Specifically, the cable chase area below 

elevation 147 ft is designed to seismic Category I criteria. A seismic Category I barrier is located 

between the main steam and feedwater piping above elevation 147 ft and the cable chase area 

below. This barrier prevents the postulated failure of the main steam or feedwater piping in the 

turbine building from adversely affecting the cables below. These cables provide trip inputs for the 

recirculation pump trip and reactor scram following either a generator load rejection or turbine trip 

originating in the turbine building. On the basis of these considerations, the portions of the Unit 1 

turbine building and the cable chase area below elevation 147 ft are within the scope of license 

renewal. Similarly, the portions of the Unit 2 turbine building and the cable chase area below 

elevation 147 ft are also within scope, as are the supports over the radioactive release pathway for 

the main condenser. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components requiring an AMR in Table 2.4.8-1 of the LRA. Specifically, the identified component 

types include anchors and bolts, miscellaneous steel, reinforced concrete, and structural steel. The 

applicant identified four component functions that support the turbine building intended function for 

these component types. These component functions are structural support, non-safety-related 

structural support, shelter/protection, and radiation shielding.

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Staff Evaluation

In Section 2.4.8 of the LRA, the applicant states that the turbine building is within the scope of 

license renewal because of its balance of plant equipment integrity and support intended function. 

The staff reviewed the application, as well as Section 12.2.2 of the Unit 1 UFSAR and Section 3.2 

of the Unit 2 UFSAR, to verify that all turbine building intended functions are identified in the 

application. In addition, the staff verified that all components that support the turbine building 

intended function are identified as being within the scope of license renewal. 

In its review of the LRA and supporting information in the UFSAR, the staff forwarded one RAI to 

the applicant by letter dated July 14,2000. RAI 2.4-TB-1 primarily related to clarifying information 

on the boundaries of the turbine building that are within the scope of license renewal. Turbine 

building components subject to an AMR are listed in Table 2.4.8-1 of the LRA. The following 

summarizes the information provided in the applicant's RAI responses, dated August 29, 2000: 

The staff identified an apparent discrepancy in the information provided by the applicant. 

Section 2.4.8 of the LRA states that the turbine building is designed and constructed to 

ensure that it will not damage any seismic Category I structure or equipment located inside 

or adjacent to it. In addition, cables that are important to safety are located in a seismic 

Category I chase area within the turbine building. Drawing EL-1 0173, "General Building 

Site Plan," indicates that the entire turbine building for Units 1 and 2 is within the scope of 

license renewal. However, Section 2.4.8 of the LRA indicates that the applicant proposed 

to include only certain portions of the structure within the scope of license renewal. The 

staff, therefore, requested that the applicant clarify whether the entire turbine building 

structure for Units 1 and 2 is within the scope of license renewal, or provide a justification 

for omitting portions of the turbine building from the scope of license renewal. In its 

response, the applicant stated that only certain portions of the Unit 1 and 2 turbine buildings 

meet any of the scoping criteria of the License Renewal Rule. The turbine buildings are 

Category II structures. Therefore, failure of either structure will neither result in the release 

of significant radioactivity nor prevent reactor shutdown. The Unit 1 and 2 turbine buildings, 

as structures, are only within the scope of license renewal to the extent that they are non

safety-related structures that could prevent a safety-related function. That extent is 

discussed in the following paragraphs. 

A portion of each turbine building was designed to seismic Category I criteria. The cable 

chase area below elevation 147 ft, described in Unit 1 UFSAR Section N.3.2.4 and Unit 2 

UFSAR Section 15A.3.2.D, has been included witin the scope of license renewal. As stated 

in Section 12.2.15.2.2 of the Unit 1 UFSAR, the turbine buildings are designed and 

constructed to ensure that they will not damage Category I structures or equipment located 

inside or adjacent to them in the event of a DBE. Thus, the applicant only considered those 

portions of each turbine building adjacent to Category I structures or having Category I 

equipment inside them as being within scope. The applicant's assessment also includes 

within scope for license renewal the south end of the Unit 1 turbine building up to and 

including the bay extending north of the Unit 1 reactor building, and the north end of the 

Unit 2 turbine building up to and including the bay extending south of the Unit 2 reactor 

building. The structural elements included in this scope are the base mat, columns, exterior 

walls, and roof, as well as the cable chase areas described above.

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The evaluation boundary drawing (EL-10173) depicting the in scope structures shows that 

the entire turbine building is in scope for both units. This drawing reflects the practical 

consideration that the scope of the program credited to manage aging effects for the 

turbine building structural components includes the entire building. Thus, in practice, any 

distinction as to the portions of the turbine buildings that are in scope is rendered 

unnecessary. 

The staff finds the applicant's RAI response to be acceptable. On the basis of the staff's review 

of the application and the applicant's RAI response, the staff concludes that there is reasonable 

assurance that the applicant has identified all portions of the turbine building with intended 

functions that meet the criteria in 10 CFR 54.4(a) as being within the scope of license renewal. 

Using the information provided in the LRA, the applicant's RAI responses, and the UFSAR, the staff 

sampled several components to determine whether the applicant properly identified the passive, 

long-lived SCs that are listed as being subject to an AMR in Table 2.4.8-1 of the LRA. No 

omissions were identified. On the basis of this review, the staff has reasonable assurance that the 

applicant has identified the turbine building SCs that are subject to an AMR in Table 2.4.8-1. 

2.4.14 Yard Structures 

Summary of Technical Information in the Application 

LRA Section 2.4.10 describes the basis for including yard structures in the scope of license 

renewal, and identifies the components subject to an AMR. Yard structures provide structures for 

maintaining equipment integrity and personnel habitability on the plant site. Among others, this 

category includes: 

* the concrete wall and foundation accommodating the condensate storage tank 

* the foundation of the nitrogen storage tank 

* the service water valve pit boxes 

* the foundation for the fire pump house 

* the foundations for the two fire protection water storage tanks 

• the foundations for the two fire protection diesel pump fuel tanks 

* the underground concrete duct runs and pull boxes between Class I structures 

The application lists function Y29-01, "Equipment Integrity and Personnel Habitability," as the only 

intended function of yard structures. In performing this intended function, the yard structures 

provide for equipment integrity and personnel habitability within the various structures listed above. 

For instance, the liquid nitrogen tank foundation is within the scope of license renewal because the 

foundation is seismic Category I, thus ensuring the integrity of the nitrogen tank during a seismic 

event. The liquid nitrogen tank provides the safety-related backup supply of motive gas for the 

drywell inerting system and the drywell pneumatic system, and is relied upon in certain safety 

analyses described in the UFSAR. In addition, the liquid nitrogen tank is relied upon to achieve 

safe shutdown in the event of a fire. Similarly, the enclosure around the CST, the wall, and the 

CST foundation are also seismically qualified to Category 1 requirements to ensure the functionality 

of the CST during a seismic event. The service water valve boxes are also within the scope of 

license renewal because they contain piping for the plant service water system that is also within 

the scope of license renewal. As stated above, the concrete duct runs and pull boxes that traverse 

the yard between various Class I structures are also within the scope of license renewal. These

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duct runs provide protection for the safety-related circuits that are routed through them. The 

foundations for the fire pump house, fire protection water storage tanks, and fire protection diesel 

pump fuel tanks are also within the scope of license renewal. 

The applicant described its process for identifying the structural/civil components that are within 

the scope of license renewal and subject to an AMR in Section 2.1.3 of the LRA. On the basis of 

this methodology, the applicant identified various component types as the passive and long-lived 

components requiring an AMR in Table 2.4.10-1 of the LRA. Specifically, the identified component types include anchors and bolts, pull box cover plates (aluminum), miscellaneous steel, reinforced 

concrete, and structural steel. The applicant identified four component functions that support the 

yard structures intended function of these component types. These component functions are 

structural support, non-safety-related structural support, shelter/protection, and flood barrier. 

Staff Evaluation 

In Section 2.4.10 of the LRA, the applicant states that yard structures are within the scope of 

license renewal because of their equipment integrity and personnel habitability intended function. 

The staff reviewed the application, as well as Section 5.2.3.9 of the Unit 1 UFSAR and 

Section 3.8.5.1 of the Unit 2 UFSAR, to verify that all yard structures' intended functions are 

identified in the application. In addition, the staff verified that all components that support the yard structures intended function are identified as being within the scope of license renewal. 

In its review of the LRA and supporting information in the UFSAR, the staff forwarded one RAI to 

the applicant by letter dated July 14, 2000. RAI 2.4-1 primarily related to clarifying information on 

what yard structures are within the scope of license renewal. Yard structures components subject to an AMR are listed in Table 2.4.10-1 of the LRA. The following information was provided in the 

applicant's RAI response, dated August 29, 2000: 

"Yard structures are addressed in Section 2.4.10 and screening results shown in 

Table 2.4.10-1. On page 2.4-1 of the application, Section 2.4, the application "[notes] that the intended functions define the boundaries by which various 

component groups are analyzed for aging management purposes. The system description is informational and is not intended to define boundaries." Not all yard 

structures are in the scope of license renewal. This is why the application refers to "some of the structures" on page 2.4-19. Only the yard structures that support an 

intended function are included within the evaluation boundaries described on pages 2.4-19 and 2.4-20. Supporting information for the scoping and screening of 

structures pursuant to both the Rule requirements and the scoping and screening methodology described in the LRA is available at the SNC corporate offices for NRC 

review." 

This response did not adequately provide the information that the staff needed to complete its 

review. Therefore, a telephone conference was held with the applicant on December 28, 2000. 

In this conference call, the applicant stated that the yard structures listed in Section 2.4.10 of the 

LRA are the only yard structures with an intended function. Therefore, they are the only yard 

structures that are within the scope of license renewal. After further review, the staff did not identify 

any yard structures with intended functions that were not included in this list, or covered elsewhere 

in the application. Therefore, the staff finds that the applicant's RAI response is acceptable. On 

the basis of the staff's review of the application and the applicant's RAI response, the staff

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concludes that there is reasonable assurance that the applicant has identified all portions of the 

yard structures with intended functions that meet the criteria in 10 CFR 54.4(a) as being within the 

scope of license renewal. 

Using the information provided in the LRA, the applicant's RAI response, and the UFSAR, the staff 

sampled components to determine whether the applicant properly identified the passive, long-lived 

SCs that were listed as being subject to an AMR in Table 2.4.10-1 of the LRA. No omissions were 

identified. On the basis of this review, the staff has reasonable assurance that the applicant has 

identified the yard structure SCs that are subject to an AMR in Table 2.4.10-1. 

2.4.15 Conclusions 

As part of this evaluation, the staff reviewed the information presented in Sections 2.4.1 through 

2.4.13 of the LRA, the supporting information in the Plant Hatch UFSARs, the applicant's 

responses to the staff's RAIs, and the additional information provided in telephone conferences and 

by letter dated January 31, 2001. On the basis of that review, the staff concludes that there is 

reasonable assurance that the applicant has identified those portions of the Plant Hatch structures 

and structural components that are within the scope of license renewal and subject to an AMR, in 

accordance with 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1). 

2.5 Scoping and Screening Results: Electrical Components 

In Section 2.5, "Electric Power and Instrumentation and Controls Screening Results," of the Plant 

Hatch LRA, the applicant describes the electrical components that are within the scope of license 

renewal and subject to an AMR. The staff reviewed this section of the LRA to determine whether 

there is reasonable assurance that all SSCs within the scope of license renewal have been 

identified, as required by 10 CFR Part 54.4(a), and that all structures and components subject to 

an AMR have been identified, as required by 10 CFR Part 54.21 (a)(1). 

2.5.1 Summary of Technical Information in the Application 

The electrical component screening process has the following steps: 

* Develop a comprehensive list of all electrical component types installed in the plant without 

regard for system function or license renewal in-scope status. 

* Determine the basic function of each type of electrical component. 

* Determine which component types perform their functions without moving parts or a change 

in configuration or properties. This results in the list of electrical component types which 

are subject to an aging management review for license renewal. 

0 Apply the scoping criteria of 10 CFR 54.4(a)(1) through (3) to the list of component types 

to determine if the list can be reduced. 

On the basis of this scoping methodology, the applicant identified the following systems in order 

to determine which electrical components groups are subject to an aging management review: 

* analog transmitter trip system

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* nuclear steam supply shutoff system * primary containment isolation system 

• reactor protection system * remote shutdown panels system 

• process radiation monitoring system 

* heat trace system * main control room panels system * in-plant auxiliary control panels system 

• plant AC electrical system 

* DC electrical system 

• plant communications system 

• power transformers system * emergency response facilities system

The applicant's scoping methodology identified the following electrical 

intended functions as subject to an aging management review:

0 Cable 

(inside containment) 

* Cable 

(outside containment) 

* Electrical connectors, 

splices, terminal blocks 

* Electrical penetration 

assemblies 

* Nelson frames 

* Phase bussing

device types and their

Provides insulation resistance to 

prevent shorts, grounds, and 

unacceptable leakage currents 

Provides insulation resistance to 

prevent shorts, grounds, and 

unacceptable leakage currents 

Provides insulation resistance to 

prevent shorts, grounds, and 

unacceptable leakage currents 

Provide insulation resistance to 

prevent shorts, grounds, and 

unacceptable leakage currents 

Fission product barrier 

Fire protection 

Provides insulation resistance to 

prevent shorts, grounds, and 

unacceptable leakage currents

2.5.2 Staff Evaluation 

The staff reviewed Section 2.5 of the LRA to determine whether there is reasonable assurance that the applicant has identified the electrical components within the scope of license renewal, in accordance with 10 CFR 54.4, and subject to an AMR, in accordance with 10 CFR 54.21 (a)(1).

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Electrical Components Within the Scope of License Renewal and Subiect to an Aging Management 

Review 

In the first step of its evaluation, the staff determined that the applicant had properly identified the 

electrical component types installed in the plant. The applicant developed the following 

comprehensive list of electrical component types installed in the plant without regard for system 

function or license renewal in-scope status:

alarm units 

analyzers 

annunciators 

batteries 

battery chargers 

cables 

circuit breakers 

controllers 

converters 

electric heaters 

electrical connectors 

electronic devices 

emergency lighting 

fuses 

grounding 

heat tracing 

indicators 

installed communication equipment 

isolators

magnetic contactors 

motor-generator sets 

motors 

penetration assemblies 

penetrations (Nelson frames) 

phase bussing 

power distribution 

power supply 

recorders 

regulators 

relays 

sensors 

signal conditioners 

switches 

timers 

transformers 

transmitters 

valve operators

In the second step of its evaluation, the staff reviewed the basic function of each component type 

and the applicant's determination of which component types perform their functions without 

moving parts or a change in configuration or properties (passive and long-lived components) and 

therefore are subject to an AMR. The staff concludes that the applicant has properly identified the 

passive, long-lived component types. 

In the third step of its evaluation, the staff reviewed the list of passive, long-lived component types 

to determine which met the criteria of 10 CFR 54.4(a)(1) through (3). This step defined the set of 

electrical component types subject to an AMR 

The following is a list of in-scope electrical component types subject to an aging management 

review: 

* cable (inside containment) 

0 cable (outside containment) 

0 electrical connectors, splices, terminal blocks 

0 electrical penetration assemblies 

0 Nelson frames (penetrations) 

* phase bussing

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Finally, the staff reviewed the information submitted by the applicant and verified that the applicant 

had not omitted or misclassified any electrical components requiring an AMR. 

2.5.3 Conclusions 

On the basis of the staff's review of the information presented in Section 2.5 of the LRA and the 

supporting information in the Plant Hatch UFSAR, the staff did not find any omissions by the 

applicant, and therefore concludes that there is reasonable assurance that the applicant has 

identified those parts of the electrical systems that are within the scope of license renewal, as 

required by 10 CFR Part 54.4(a), and subject to an AMR, as required by 10 CFR Part 54.21 (a)(1).

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3 AGING MANAGEMENT REVIEW

This section presents the staff's evaluation of the applicant's AMR. The applicant provided a 

proposed supplement to the Final Safety Analysis Report (FSAR Supplement) in Appendix A to the 

LRA, in accordance with 10 CFR 54.21 (d). The purpose of the proposed FSAR supplement is to 

provide an appropriate description of the programs and activities for managing the effects of aging 

and the evaluation of time-limited aging analyses (TLAAs), so that any future changes to the 

programs or activities that may affect their effectiveness will be controlled under 10 CFR 50.59. 

By letter dated July 28, 2000, the staff issued RAIs related to Appendix A to the LRA. In response, 

by letter dated October 10, 2000, the applicant provided Appendix B to the LRA, which addressed 

many of the RAIs related to Appendix A of the LRA. 

The staff issued Open Item 3.0-1 to ensure that the applicant's FSAR Supplement contained an 

adequate description of the programs and activities that have been credited for managing the 

effects of aging, and the evaluation of time-limited aging analyses (TLAAs) for the period of 

extended operation as required by 10 CFR 54.21(d). The staff reviewed the aging management 

program and TLAA descriptions provided by letter dated October 10, 2000, and the associated 

FSAR Supplement provided by letter dated September 5, 2001, and found that the FSAR 

Supplement provided by the applicant contains descriptions of these programs and activities 

adequate to satisfy 10 CFR Part 54 requirements. On the basis of the program descriptions 

provided by the applicant, the staff concludes that the FSAR Supplement contains sufficient 

information to adequately describe the content of the associated aging management programs and 

TLAAs and satisfies the requirements of 10 CFR 54.21 (d). A condition will be included in the 

renewed license requiring the inclusion of the FSAR Supplement in the next UFSAR update, 

required by 10 CFR 50.71 (e). Open Item 3.0-1 is closed. 

In addition, the applicant committed to performing future inspections before the extended period 

of operation. These commitments are identified in the FSAR Supplement, submitted pursuant to 

10 CFR 54.21(d), as part of the proposed aging management programs. Upon satisfactory 

completion of these activities prior to entering the extended period of operation (i.e., no later than 

August 6, 2014 for Unit 1, and June 13, 2018 for Unit 2), the staff can conclude that there is 

reasonable assurance that the activities authorized by the renewed license will continue to be 

conducted in accordance with the CLB, as required by 10 CFR 54.29. A condition will be included 

in the renewed license requiring completion of these activities before the beginning of the period 

of extended operation. 

3.1 Aging Management Programs 

This section contains the staff's evaluation of the AMPs that are documented in Appendices A, B, 

and C of the LRA, and Appendix B of the applicant's October 10, 2000 submittal, and referenced 

as a part of the aging management for the various systems and/or structures of Plant Hatch. It 

should be noted that the staff's conclusions on its evaluations for some of these AMPs assume that 

they are implemented in conjunction with other relevant AMPs, as discussed in Sections 3.2 

through 4.7 of this SER, for managing aging effects for a particular structure or component. 

The staff's evaluation of the applicant's AMPs focused on program elements, ratherthan the details 

of specific plant procedures. To determine whether the applicant's AMPs are adequate to manage 

the effects of aging so that the intended functions will be maintained in a manner that is consistent

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with the CLB throughout the period of extended operation, the staff evaluated 10 elements, 

including (1) scope of program, (2) preventive actions, (3) parameters monitored or inspected, (4) 

detection of aging effects, (5) monitoring and trending, (6) acceptance criteria, (7) corrective 

actions, (8) confirmation processes, (9) administrative controls, and (10) operating experience. 

The draft SRP-LR, released in 1997, describes the 10 basic elements of an effective AMP. The 

staff evaluated the proposed programs against the 10 elements. This SER describes the extent 

to which the 10 elements are applicable to particular components and aging effects. Based on 

experience with maintenance programs, the staff concludes that conformance with the applicable 

elements provides the basis to conclude that the programs are demonstrably effective at managing 

the associated aging effects. 

The applicant indicated that elements (7) corrective actions, (8) confirmation processes, and (9) 

administrative controls for license renewal are in accordance with the site-controlled corrective 

actions program pursuant to 10 CFR Part 50, Appendix B, and covers all structures and 

components (SCs) that are subject to an AMR. The staff's evaluation of the applicant's corrective 

actions program is discussed in Section 3.1.8 of this SER. 

Aging Management of Seismic Il/I Piping 

By letter dated September 5, 2001, in response to Open Item 2.1.3.1-1, the applicant brought 

additional seismic Il/I piping systems into the scope of license renewal. These piping systems 

consist of non-safety-related piping and supports whose failure could adversely impact nearby 

safety-related components, as well as non-safety-related piping that is attached to safety-related 

piping from the safety class break to the first seismic anchor, as credited in the associated seismic 

analysis. The applicant also provided information regarding the management of aging effects 

associated with these piping systems. 

For non-safety-related piping that is attached to safety-related piping from the safety class break 

to the first seismic anchor, the applicant will use the same aging management programs (AMPs) 

as are used for the attached safety-related piping. If exceptions are identified in the future, where I 

the credited programs do not adequately manage the aging effects, then the applicant will revise I 

the aging management programs to assure proper aging management. I 

For non-attached seismic Il/I piping systems, the applicant stated that the piping will be managed 

using the water chemistry control, Flow-Accelerated Corrosion (FAC), and Structural Monitoring 

Program AMPs, supplemented by one-time inspections, where applicable, as well as by the 

Corrective Actions Program. These programs are evaluated in Section 3.1 of this SER. 

To manage loss of material due to various corrosion mechanisms, other than FAC, and cracking 

due to stress corrosion cracking of stainless steel in seismic Il/I piping systems, the applicant stated 

that area walkdowns would also be performed to detect leaks in the piping. These walkdowns will 

be conducted as part of the existing structural monitoring program AMP. These walkdowns will use 

a "spaces" approach in the reactor, control, and diesel generator buildings, as well as the turbine 

building above the condenser system, and the intake structure. 

The FAC program will be used to manage FAC in carbon steel, high-energy, seismic Il/I lines (there 

are no low or moderate energy lines that are in scope and susceptible to FAC). In addition,

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appropriate chemistry controls will be used and one-time confirmatory inspections will be 

performed, as stated above. 

On the basis of the additional information provided by the applicant in response to Open Item 2.1.3.1-1, the staff concludes that the aging management of the seismic Il/I piping systems 

is adequate and provides reasonable assurance that safety-related structures, systems, and 

components will be adequately protected from the consequences of a failure in the seismic Il/I 

piping systems. 

3.1.1 Reactor Water Chemistry Control 

3.1.1.1 Introduction 

The applicant described its reactor water chemistry control AMP in Sections A.1.1, and C.1.2.1 of 

the LRA, and Section B.1.1 of the applicant's October 10, 2000 submittal. The staff reviewed these 

sections of the LRA to determine whether the applicant has demonstrated that the effects of aging 

will be adequately managed so that intended function(s) will be maintained in a manner that is 

consistent with the CLB throughout the period of extended operation, as required by 10 CFR 

54.21 (a)(3). 

The components that are exposed to the reactor water environment and require aging 

management are contained in various commodity groups, including the reactor pressure vessel, 

reactor pressure vessel internals, Class 1 carbon steel components, Class 1 wrought and forged 

stainless steel components, Class 1 cast austenitic stainless steel components, non-Class 1 carbon 

steel components and non-Class 1 stainless steel components. 

The management of aging effects by the reactor water chemistry control program for the 

components contained in the above commodity groups is described in Sections C.2.1.1.1, 

C.2.1.1.2, C.2.1.1.3, C.2.1.1.4, C.2.1.1.5, C.2.2.1.1 and C.2.2.1.2 of the LRA. The objective of the 

reactor water chemistry control AMP is to optimize the water chemistry to minimize the potential 

for degradation due to the aging effects. The staff reviewed these sections of the LRA to 

determine whether the applicant has demonstrated that it will adequately manage the effects of 

aging caused by the reactor water environment in the plant throughout the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.1.2 Summary of Technical Information in the Application 

In the LRA, the applicant identified the following mechanical systems, which contain the 

components that are affected by the reactor water chemistry: 

* reactor assembly system 

0 nuclear boiler system 

0 reactor recirculation system 

* high-pressure coolant injection system 

* reactor core isolation cooling system 

• main condenser system 

• electro-hydraulic control system 

The details of these systems are described in Section 2.3 of the LRA.

3-3
The applicant evaluated the potential aging effects requiring management for the components that 

are exposed to the reactor water environment. The following aging effects are applicable to these 

components: 

* loss of material as a result of general corrosion, crevice corrosion and pitting 

* cracking as a result of stress corrosion cracking and intergranular attack (IGA) 

The control of reactor water chemistry is accomplished in accordance with Electric Power Research 

Institute (EPRI), TR-103515, "BWR Water Chemistry Guidelines." 

3.1.1.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's reactor water chemistry control program 

to ensure that the effects of aging on components exposed to reactor water will be adequately 

managed, so that the functions will be maintained consistent with the CLB for the period of 

extended operation for all components in a reactor water environment. 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the LRA regarding the applicant's demonstration of the reactor water chemistry control 

program to ensure that the effects of aging attributable to the reactor water chemistry will be 

adequately managed, so that the intended functions will be maintained consistent with the CLB for 

the period of extended operation for all components in the systems included in the scope of the 

program. After completing the initial review, by letter dated July 28, 2000, the staff issued several 

RAIs. By letter dated October 10, 2000, the applicant responded to the staff's RAIs. 

The components exposed to the reactor water environment are made of carbon steel, low-alloy 

carbon steel, austenitic stainless steel, and nickel-based alloys. The aging effects to be managed 

by the reactor water chemistry control program are loss of material and cracking. Loss of material 

is attributable to pitting, crevice corrosion, and general corrosion occurring mainly in carbon steel. 

Cracking is due to stress corrosion cracking (SCC) and intergranular (IGA) in austenitic stainless 

steels and nickel-based alloys. 

The IGA is considered a precursor for the SCC and provides the sites for crack initiation. The SCC 

consists of intergranular stress corrosion cracking (IGSCC), transgranular stress corrosion cracking 

(TGSCC), and irradiation assisted stress corrosion cracking (IASCC). The mechanisms of these 

aging effects that could be managed by the subject program are discussed in Section C.1.2 of the 

LRA. The aging effects are caused by the presence of excessive detrimental impurities (such as 

chlorides and sulfates) and oxidizing species in the reactor water. The staff's review did not identify 

any other aging effects that may be induced by the reactor water environment. 

The applicant's reactor water chemistry control program is predicated on the guidance provided 

in EPRI TR-103515, "BWR Water Chemistry Guidelines." In the staff's RAIs regarding program 

elements that deviate from the referenced EPRI guidelines, the applicant indicated that this 

program is currently being updated to meet the guidance of EPRI TR-103515, Revision 2. The 

staff noted that EPRI TR-1 03515, Revision 2, has not been reviewed by the staff for generic use. 

The staff requested that the applicant clarify the differences between Revision 1 and Revision 2 

of EPRI TR-103515, so the staff can determine whether the provisions of Revision 2 are 

acceptable. This was identified as Open Item 3.1.1-1.

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By letter dated June 5, 2001, the applicant responded to the open item, stating that, as discussed 

in its response to RAI 3.1.1-2, Plant Hatch is committed to meeting the chemistry control 

parameters specified for RCS chemistry contained in EPRI TR-103515. The applicant identified, 

as a point of information, the applicable revision of the EPRI document which was current at the 

time the LRA was submitted, and noted that the program was being updated to a later revision of 

the document. The applicant believes, and the staff agrees, that it is important to maintain the 

flexibility to modify plant chemistry control procedures based on the best industry guidance 

developed from the collective operating experience of similar reactors. Therefore, over time, the 

applicant expects to revise the plant chemistry procedures to reflect changes in industry guidance 

as reflected in the EPRI control parameters. 

As part of the response to Open Item 3.1.1-1, the applicant also discussed the significant 

differences between Revision 1 and Revision 2 of EPRI TR-103515. The first relates to the 

additional consideration of the beneficial effects of operation with hydrogen water chemistry (HWC) 

or with HWC with noble metal chemistry addition (NMCA). Revision 2 of EPRI TR-103515 provides 

an additional table (4-5b) which allows relaxation of the power operation Action Level 3 (AL3) 

values for chlorides and sulfates from 100 ppb to 200 ppb when HWC is in service and measured 

electrochemical potential (ECP) values are less than -230 mV. Currently, Plant Hatch operates in 

accordance with Revision 2 of the EPRI guidelines and current sampling and monitoring procedure 

allows for higher AL3 chloride and sulfate values under HWC. This additional flexibility is warranted 

based on the increased protection of reactor coolant system and reactor assembly components 

provided by HWC or HWC with NMCA. 

The second significant difference between Revision 1 and Revision 2 of the EPRI guidelines 

involves the allowance in Revision 2 for monitoring of chlorides and sulfates on less than a daily 

basis, if appropriate, based on site-specific resource allocation needs. This flexibility in monitoring 

frequency is acceptable when adequately justified and supported by the conductivity values and/or 

chemistry trends that assure that Action Level 1 limits will not be exceeded. 

On the basis of the information provided by the applicant in response to this open item, the staff 

concludes that the applicant should be allowed to maintain the flexibility to modify chemistry control 

procedures in response to new or updated industry information, and that the differences between 

Revision 1 and Revision 2 of the EPRI guidelines provide this flexibility. Therefore, the staff 

considers Open Item 3.1.1-1 closed. 

Program Scope 

The objective of the program is to mitigate the aging effects that are attributable to loss of materials 

and cracking. The components in the relevant commodity groups and systems that are exposed 

to the reactor water environment and require aging management by this program are listed in 

Section C.2 of the LRA. The staff finds that the scope of the subject AMP is adequate because 

it applies to components that are exposed to the reactor water environment. 

Preventive or Mitigating Actions 

The subject program controls the fluid purity and composition of the reactor water in the reactor 

coolant system and other systems, such as condensate/feedwater cycle, and the RWCU system. 

This is achieved through the use of filters/demineralizers that limit impurities within the feedwater, 

and hydrogen injection that minimizes the amount of oxygen produced by radiolysis within the core.

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The staff finds that the mitigation methods are acceptable because they are effective in minimizing 

the aging effects in the affected components. 

Parameters Monitored or Inspected 

The subject program monitors coolant conductivity, as well as sulfate and chloride concentrations. 

Currently, when HWC is in service, ECP is also monitored. The staff finds that the monitoring of 

these parameters is adequate to determine the quality of the reactor water. 

Detection of Aging Effects 

The applicant stated that the reactor water chemistry control is a mitigative activity and, as such, 

is not intended to directly detect age-related degradation of the affected components. The staff 

concurs with the applicant's statement. 

Monitoring and Trending 

The subject program does not monitor or trend age-related component degradation. However, 

the BWR water chemistry guidelines provide guidelines for data collection and trending 

methodologies for evaluation of reactor water chemistry control parameters. The conductivity is 

monitored continuously, and the chloride and sulfate concentrations are monitored daily. Currently, 

ECP is monitored continuously when HWC is in service. The staff finds that the monitoring and 

trending of the reactor water chemistry control parameters based on BWR water chemistry 

guidelines will identify deterioration of the reactor water chemistry. 

Acceptance Criteria 

The applicant stated that the acceptance criteria for the reactor water chemistry control parameters 

are founded on those provided in the BWR water chemistry guidelines. The acceptance criteria 

for the reactor water chemistry control parameters vary with the plant operating modes (cold 

shutdown, startup/hot shutdown, or power operation) and the water chemistry condition (normal 

water chemistry or HWC). In Section B.1.1 of the LRA, the applicant identified the minimum 

reactor water control parameters (conductivity < 0.30gS/cm, chlorides < 5 ppb and sulfates < 5 

ppb) for action level 1 during normal power operation and referenced the BWR water chemistry 

guidelines as its basis. 

Operating Experience 

The major age-related component degradation in the reactor water environment is attributable to 

IGSCC in austenitic stainless steel materials. The applicant identified environmentally induced 

cracking, IGSCC in instrument penetrations, core spray sparger, and various components in the 

jet pump, core shrouds and recirculation system piping. These degraded components were either 

repaired or replaced. One of the key contributors to SCC degradation is the content of oxidizing 

species in the reactor water. The applicant installed HWC equipment in both units to reduce the 

content of oxidizing species in the reactor water to minimize the aging effect of IGSCC in the 

affected components. The applicant implemented NMCA to Unit 1 during the 1999 refueling 

outage and to Unit 2 during the 2000 refueling outage. The implementation of NMCA would further 

reduce the content of oxidizing species in the reactor water. The staff concludes that the 

applicant's reactor water chemistry control program will adequately manage the referenced aging

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effects, so that the structure and component intended functions will be maintained during the period 

of extended operation. 

The staff notes that in its response to RAI 3.1.1-2, the applicant committed to meet the reactor 

water chemistry control parameters provided in the BWR water chemistry guidelines, but did not 

commit to a specific acceptable water chemistry mode. This is acceptable because the BW R water 

chemistry guidelines allow for both HWC and normal water chemistry operation. However, this 

would impact the applicant's in-service inspection (ISI) program. As delineated in BWRVIP-75, 

"Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules (NUREG-0313)" and 

BWRVIP-62, "Technical Basis for Inspection Relief for BWR Internal Components with Hydrogen 

Injection," the extent and frequency of the required IGSCC inspection for those affected 

components depends on the mode of the reactor water chemistry operating condition. 

3.1.1.4 Conclusions 

The staff has reviewed the information in Section A.1.1, "Reactor Water Chemistry Control," and 

Section B.1.1, "Reactor Water Chemistry Control," of the LRA, and the applicant's responses to 

the staff's RAIs. On the basis of its review, the staff concludes that the applicant has demonstrated 

that, in conjunction with other AMPs, the effects of aging associated with SCs that are exposed to 

a reactor water environment will be adequately managed so that intended functions will be 

maintained, consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

3.1.2 Closed Cooling Water Chemistry Control 

3.1.2.1 Introduction 

The applicant described its closed cooling water (CCW) chemistry control AMP in Sections A.1.2, 

B.1.2, and C.1.2.3 of the LRA. The staff reviewed these sections of the LRA to determine whether 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

intended function(s) of systems that are exposed to the CCW environment will be maintained, 

consistent with the current licensing basis, for the period of extended operation, as required by 10 

CFR 54.21 (a)(3). 

3.1.2.2 Summary of Technical Information in the Application 

In Sections A.1.2 of the LRA, and Section B.1.2 of the applicant's October 10, 2000 submittal, the 

applicant describes the CCW chemistry control program, which manages, in part, the aging effects 

of stainless steel, carbon steel, and copper-based alloy components that are exposed to the CCW 

environment. The makeup water for this system is clean, deionized water that is exclusively 

provided by the demineralized water system. 

The applicant stated in the LRA that the components exposed to the CCW environment are found 

in the reactor building closed cooling water system (RBCCW) and the primary containment chilled 

water system (Unit 2 only).

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3.1.2.3 Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding CCW chemistry control program to ensure that the 

effects of aging on components exposed to CCW will be adequately managed, so that the functions 

will be maintained consistent with the CLB for the period of extended operation for all components 

in a CCW environment. 

Program Scope 

The CCW chemistry controls are applied to the RBCCW system and the primary containment 

chilled water system (Unit 2 only), which include stainless steel, carbon steel, and copper-based 

alloy components. The CCW chemistry control program is applied to all closed cycle cooling water 

systems; however, only limited parts of these systems are within the scope of license renewal since 

these systems are not vital to safe shutdown of the plant under normal or accident conditions. The 

staff finds it appropriate and acceptable to include these systems in this AMP since these portions 

are in scope to maintain primary containment integrity. 

Preventive or Mitigative Actions 

The CCW chemistry control program is designed to mitigate and prevent age-related degradation 

(loss of material through corrosion) by controlling fluid purity and composition. Specifically, this 

program provides for the addition of corrosion inhibitors and biocides. Currently, the applicant adds 

nitrite/molybdate as a ferrous alloy corrosion inhibitor and tolytriazole (TTA) as a copper alloy 

inhibitor to promote protective oxide layer formation on surfaces. Although the source of makeup 

water for this system is clean, deionized water, biological contamination of this closed system may 

occur from in-leakage and/or maintenance activities. Therefore, EPRI-recommended biocides 

(currently isothiazolone and glutaraldehyde) are added to the water to control the formation of 

microbe populations. In the event of elevated chloride concentrations, contributed by the addition 

of corrosion inhibitors and biocides, the system is fed and bled with demineralized water, or an 

engineering evaluation is performed to insure that no long-term aging effects will result. 

The staff finds it appropriate and acceptable to treat the cooling water system with these chemical 

additions to preclude the internal loss of material. 

Parameters Inspected or Monitored 

The application states that EPRI TR-107396, "Closed Cooling Water Chemistry Guideline," 

provides the basis for monitoring closed cooling water to ensure adequate chemistry control at 

Plant Hatch. This guideline provides several treatment options and includes control parameters 

such as pH and corrosion inhibitor concentrations. Diagnostic parameters include biocide, 

ammonia, chloride, and sulfate concentrations; microbe populations; and conductivity. The 

RBCCW system is equipped with carbon steel corrosion coupons,which are periodically analyzed 

to verify the effectiveness of the corrosion inhibitor system. 

The staff finds that the monitoring of these parameters is appropriate and acceptable to maintain 

he effectiveness of this AMP.

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Detection of Aging Effects

The application states the CCW chemistry control program is a mitigative activity,which is not 

intended to directly detect age-related degradation of components within the scope of this program. The staff agrees that the implementation of this program does not provide information directly related to the degradation of the specific material,and that there is no need to do so because this 

program, in conjunction with other AMPs, provides a means of mitigating or preventing age-related 

degradation. 

Monitoring and Trending 

The application states that the CCW chemistry control program does not directly monitor or trend 

age-related degradation and is not credited for such; however, the EPRI document provides the 

basis for trending, tracking, and evaluating CCW chemistry. The applicant notes that engineering personnel assist in performing evaluations of the structural integrity of the in-scope plant systems and, when necessary, chemistry modification is performed. These evaluations involve the 

identification of sources of raw-water in-leakage and evaluations to limit and prevent future 

chemistry excursions in the CCW system. The staff agrees that there is no need to directly monitor 

or trend age-related degradation, and finds that the applicant's implementation of guidelines from 

the EPRI document is appropriate and conservative. 

Acceptance Criteria 

The application states that the EPRI document provides the basis for the related to sulfates, 

chlorides, pH, Na 2MoO 4, NaNO 2, and TTA. In addition, the applicant monitors bacteria populations monthly, and weighs carbon steel corrosion coupons semiannually. 

The staff finds that the applicant's acceptance criteria, which are founded on the EPRI document, validate the effectiveness of this chemistry control AMP and ensure that the corrosion rates 

occurring within the CCW systems are not significant. Therefore, the staff concludes that the 

acceptance criteria are appropriate and adequate to ensure that the aging effects of components exposed to component cooling water are effectively managed during the period of extended 

operation. 

Operating Experience 

The application states that the CCW chemistry has evolved as a result of increased industry research, operating experience, and specific issues associated with chemical additions and testing methods. In the past, CCW treatments consisted of molybdates only because nitrite additions were 

contributing to bacteria population growth. However, the molybdates consumed dissolved oxygen in the system, and left the carbon steel surfaces vulnerable to corrosion. Plant Hatch returned 

nitrites to the system, which effectively corrected the corrosion issues associated with using molybdates alone. Plant Hatch resolved the issue of increased bacteria population growth by adding new biocides. While these biocides were effective in controlling bacteria population growth, this addition increased chloride concentrations. In response to this increase, a bleed and makeup 

process using demineralized water was used in the past to reduce the chloride concentrations. The 

applicant makes note that the corrosion coupon data is currently well within the limits 

recommended by industry standards.

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Given the applicant's operating history and the industry-wide use of this program, the staff finds 

that the CCW chemistry control program will adequately manage the aging effects of components 

that are exposed to the CCW environment. 

3.1.2.4 Conclusions 

The staff has reviewed the information in Section A.1.2, "Closed Cooling Water Chemistry Control," 

Section B.1.2, "Closed Cooling Water Chemistry Control," and Section C.1.2.3 of the LRA, and the 

applicant's responses to the staff's RAIs. On the basis of its review, the staff concludes that, in 

conjunction with other AMPs, the applicant has demonstrated that the effects of aging associated 

with structures and components exposed to a CCW environment will be adequately managed so 

that intended functions will be maintained, consistent with the current licensing basis, for the period 

of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.3 Diesel Fuel Oil Testing 

3.1.3.1 Introduction 

The applicant described its diesel fuel oil testing program in Sections A.1.3, C.2.2.7.1, and 

C.2.2.7.2 of the LRA and Section B.1.3 of the applicant's October 10, 2000 submittal. The staff 

reviewed these sections of the LRA to determine whether the applicant has demonstrated that the 

effects of aging on components in systems exposed to a fuel oil environment will be adequately 

managed so that intended function(s) will be maintained, consistent with the current licensing basis, 

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.3.2 Summary of Technical Information in the Application 

The applicant specified that the diesel fuel testing program applies to the emergency diesel 

generator fuel oil storage tanks, fuel oil day tanks, and the associated transfer piping and other 

components. It also covers the fire pump diesel fuel oil storage tanks and the associated piping 

and other components in the fire protection system included in the LRA scope. Tables 3.2.4-18 

and 3.2.4-19 of the LRA identify the components. 

The applicant evaluated aging effects for the components that are subject to an AMR and 

determined that the aging effects of the components remaining within the scope of license renewal 

and exposed to diesel fuel oil containing accumulated water and additives are caused by (1) loss 

of material caused by general corrosion, galvanic corrosion, crevice corrosion, pitting and 

microbiologically influenced corrosion (MIC), (2) cracking due to thermal fatigue. 

In the LRA, the applicant identified only one AMP. The diesel fuel oil testing activities manages the 

corrosive effects of diesel fuel oil, while cracking of the piping due the thermal fatigue is adequately 

addressed by a TLAA (see Section 4.2.3 of this SER). The corrosive effects of diesel fuel oil are 

managed by the diesel fuel oil testing program, which consists of two elements: 

regularly checking diesel fuel oil storage and day tanks associated with the emergency 

diesel generators and the fire pump diesels for the presence of water, verifying that the total 

particulate concentration is within acceptable limits, and removing accumulated water

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sampling new fuel oil before off loading from the delivery vehicle, and introducing an 

additive which minimizes growth of microorganisms that could induce MIC 

The program for managing cracking of piping caused by thermal fatigue is generically addressed 

in the TLAA program in Section 4.2 of the LRA. The staff's review of this TLAA can be found in 

Section 4.2 of this SER. The applicant concluded that these programs will manage aging effects 

in such a way that the intended function of the components of the diesel fuel oil storage and 

transfer systems will be maintained consistent with the CLB under all operating conditions during 

the period of extended operation. 

3.1.3.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's diesel fuel oil testing program to ensure 

that the effects of aging on components exposed to fuel oil will be adequately managed, so that 

the functions will be maintained consistent with the CLB for the period of extended operation for 

all components in a fuel oil environment. 

The environment in the diesel fuel oil storage and transfer system consists of the fuel oil, which 

may contain accumulated water and be contaminated with some impurities. Although fuel oil in its 

pure form is noncorrosive to metals, the presence of water, naturally occurring contaminants, or 

some fuel additives can create a corrosive environment. In the emergency diesel fuel storage and 

transfer systems, the components included within the scope of license renewal and exposed to this 

environment are constructed from carbon steel and stainless steel. These components are subject 

to loss of material as a result of general corrosion, galvanic corrosion, crevice corrosion, pitting, 

MIC, and cracking as a result of thermal fatigue. However, operating experience in several plants 

indicated an extremely low incidence of corrosion failure of the components exposed to diesel fuel 

oil. The recorded incidents were primarily related to clogging of strainers with sediments and 

degraded oil. At Plant Hatch, the deficiencies in the diesel fuel oil supply system with age-related 

implications were limited to unacceptable sediment and water levels in the diesel fuel oil storage 

tanks, and these deficiencies were successfully resolved. No significant aging attributable to 

thermal fatigue cracking is expected. However, since several components are potentially exposed 

to thermal fatigue, the applicant included this aging effect in the LRA. 

On the basis of the above discussion, the staff finds that there is reasonable assurance that the 

applicant has included all the plausible aging effects related to the diesel fuel oil system for aging 

management consideration. 

Program Scope 

The scope of the program includes emergency diesel generator fuel oil storage and transfer 

systems, and fire pump diesel fuel oil storage tanks, and the associated systems containing 

structures and components for which age-related effects were identified. The staff finds that all the 

relevant systems were included in the program. 

Preventive or Mitigating Actions 

Regular checking for the presence of water, particulates, and other contaminants is performed in 

these systems, and accumulated water is removed. Also, in order to prevent introduction of

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contaminants into the diesel fuel oil system, new oil is sampled before it is introduced into the 

storage tanks. During the off-loading, a biocide is added to minimize corrosion attributable to MIC. 

The staff finds that these procedures are adequate because they include all the activities needed 

to mitigate age-related effects in SCs that are within the scope of license renewal. 

Parameters Monitored or Inspected 

The staff finds that inspection for water, particulates, and other contaminants in the storage tanks, 

and sampling new fuel oil for contaminants before its introduction into the tanks, will give sufficient 

protection against formation of corrosive environments that could cause damage to in-scope SSCs. 

Detection of Aging Effects 

The diesel fuel oil testing program, like the various chemistry control programs in effect at Plant 

Hatch, is a mitigative activity which is not intended to directly detect age-related degradation. The 

implementation of this program does not provide information directly related to the degradation of 

the structures and components within the scope of this program. The applicant does not take 

credit for such a system. Also, water in the fuel oil will be in contact with the tank bottom, possibly 

causing corrosion. The diesel fuel oil testing program will not be able to detect such degradation. 

Therefore, the staff concludes that a one-time inspection program is warranted for the diesel fuel 

oil tanks to verify tank bottom thickness. The addition of a one-time inspection program for the 

tanks would be consistent with the applicant's approach for other chemistry control programs at 

Plant Hatch. For example, the torus submerged components inspection program complements the 

applicant's suppression pool chemistry control. Also, the condensate storage tank inspection 

complements the applicant's demineralized water and condensate storage tank chemistry control 

program. The staff requested that the applicant provide the specific attributes of an inspection 

program, consistent with other one-time inspections (e.g., inspection scope, inspection technique, 

acceptance criteria, etc.). This was identified as Open Item 3.1.3-1. 

By letter dated June 5, 2001, the applicant provided a response to this open item. The applicant 

stated that, since the license renewal application was submitted, one of the four buried, 40,000

gallon emergency diesel generator (EDG) fuel oil storage tanks (FOST) has been inspected. When 

Tank 1A was drained for cleaning during the last outage, the applicant took this opportunity to 

conduct aging inspections. On the basis of the results obtained through visual examination and 

ultrasonic testing (UT), the applicant concluded that significant wall thinning has not occurred in the 

Plant Hatch EDG FOSTs and that no aging management activities are required. 

The Plant Hatch EDG FOSTs are constructed of 0.5 inch plate steel. Ultrasonic testing, covering 

144 points along the lower portions of the tank, indicated that wall thickness was consistently 

between 0.500 and 0.524 inches. In no case was a reading taken less than 0.5 inches. The 

applicant believes that these results are representative of the other four tanks, since they are all 

the same material and they all have the same internal and external environments. 

Prior to performing the UT, visual inspections were conducted of the "as-found" conditions. Very 

little corrosion was noted in the tank airspace. A thin adherent layer of general corrosion was 

identified in a small area. That small amount of surface corrosion was removed during cleaning. 

Plant Hatch has five 40,000 gallon underground diesel fuel oil tanks with each one, as required by 

technical specifications, containing a minimum of 33,320 gallons. Three of these underground

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tanks (in conjunction with the associated day tanks) are sufficient to meet the 7-day supply I 

requirement of two diesel generators at full load. The tank system has the ability to transfer fuel I 

oil between tanks. Thus, the failure of any one tank would not prevent adequate plant response to I 

a design basis accident. The Plant Hatch UFSAR contains the results of this failure analysis. 

The FOSTs are checked monthly by technical specifications for level to assure that the 33,320- 1 

gallon requirement is maintained in each tank. Level can be checked either manually or by level I 

indication in the main control room. Thus, any significant leak that could result in a level 

reduction over a short period of time would be observed. As stated in the UFSAR, there are I 

sufficient fuel oil sources around Plant Hatch site to provide assurance that fuel oil can be obtained I 

within 24 hours if necessary. Thus, there is assurance of an adequate EDG fuel oil supply if one I 

tank experiences a substantial leak. 

The Plant Hatch "Combined Oil / PCB and Hazardous Substance Spill Prevention, Control and I 

Countermeasure and Spill Contingency Plan" would address Plant Hatch actions if a tank were to I 

experience a leak. The Plan was prepared in accordance with the provisions of the Environmental I 

Protection Agency's 40 CFR regulations and would be used to contain and clean up any spilled oil. I 

In summary, the design of the FOSTs and the operating experience to date suggests that corrosion I 

is not a concern either on the exterior or the interior of these tanks. If at some point in the 

future, operating experience were to suggest otherwise, appropriate changes to plant programs I 

would be made to address the issue. There are sufficient measures to detect a significant leak I 

from these tanks. Leaks from these tanks are not a safety concern but are an environmental 

concern and would be addressed by the Plant Hatch spill and countermeasure program. 

In addition to the EDG FOSTs, the fire pump diesel fuel oil storage tanks are also in scope for 

license renewal. The internal environment of these smaller tanks is similar to the internal 

environment of the EDG FOSTs, each tank having a diesel fuel oil volume and an air vapor space. 

However, the fire pump diesel fuel oil storage tanks are not buried. They are above ground and are 

painted. Thus, the external environment is at least as benign as the external environment for the 

buried EDG FOSTs. In summary, the applicant stated that the FOST visual and UT inspection 

results already obtained are responsive to the issue raised in the open item and substantiate the 

LRA conclusion that loss of material is not an aging effect requiring management during the 

renewal term for either the EDG FOSTs or the fire pump diesel fuel oil storage tanks. 

On the basis of its review of the additional information provided by the applicant in its letter dated 

June 5, 2001, the staff concludes that the applicant has performed a one-time inspection of the 

internal surfaces of one of the FOSTs, has adequately determined that age-related degradation 

of the tank bottoms has been minimal, and that significant age-related degradation of the FOSTs 

is unlikely during the period of extended operation. Open Item 3.1.3-1 is closed. 

Monitoring and Trending 

There is no monitoring and trending aspects to the diesel fuel oil testing program, nor did the staff 

identify a need for such.

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Acceptance Criteria

The acceptance criteria specified by the applicant requires less than 0.05 percent by volume of 

water and sediments to be present in the new fuel oil shipments, and the stored fuel oil should have 

no more than 10 mg/liter of particulates. In addition, a three-level composite sample from the 

emergency diesel generator storage tank and middle sample from the fire pump diesel oil storage 

tank should have water and sediment concentration not exceeding 0.05 percent by volume. The 

concentration in a bottom sample from these tanks should not exceed 0.1 percent of water and 

sediment by volume. The staff concurs with the applicant that these criteria will ensure that the 

aging effects in the diesel fuel oil system will be properly managed. 

Operating Experience 

Inspection of the industry-wide data showed an extremely low incidence of failure of components 

exposed to fuel oil. The inspection did not identify any incidents caused by corrosion and the only 

deficiency reported in several plants was clogging of strainers with sediments and degraded oil. 

A review of the applicant's data for the past 5 years has uncovered several deficiencies. These 

deficiencies were screened to determine which of them were potentially related to aging. The 

results of the screening have indicated that the deficiencies were limited to instances of 

unacceptable sediment and water levels within the diesel fuel oil storage tanks. However, they 

were promptly restored to acceptable limits through the corrective actions program. No instances 

of component failure attributable to age-related degradation were identified. As discussed above 

under the element "Detection of Aging Effects," this mitigative program should be supplemented by a one-time inspection to provide direct evidence of the absence of corrosion caused by either 

external or internal environments. 

3.1.3.4 Conclusions 

The staff has reviewed the information in Sections A.1.3, "Diesel Fuel Oil Testing," C.2.2.7.1, and 

C.2.2.7.2 of the LRA, Section B.1.3 of the applicant's October 10, 2000 submittal, and the 

applicant's responses to the staff's RAIs. On the basis of its review, the staff concludes that, in 

conjunction with other AMPs, the applicant has demonstrated that the effects of aging associated 

with structures and components exposed to a fuel oil environment will be adequately managed so 

that intended functions will be maintained, consistent with the current licensing basis, for the period 

of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.4 Plant Service Water and RHR Service Water Chemistry Control 

3.1.4.1 Introduction 

The applicant described its plant service water and RHR service water (PSW and RHRSW) 

chemistry control AMP in LRA Sections A.1.4, and C.1.2.4 and Section B.1.4 of the applicant's 

October 10, 2000 submittal. The staff reviewed these sections of the LRA to determine whether 

the applicant has demonstrated that the effects of aging of components in systems exposed to 

PSW and RHRSW will be adequately managed so that intended function(s) will be maintained, 

consistent with the current licensing basis, for the period of extended operation, as required by 10 

CFR 54.21 (a)(3).

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3.1.4.2 Summary of Technical Information in the Application

In LRA Section A.1.4 and Section B.1.4 of the applicant's October 10, 2000 submittal, described 

the PSW and RHRSW chemistry control program, which manages, in part, the aging effects of 

carbon steel, cast iron, copper alloy, and stainless steel components exposed to the PSW and 

RHRSW system environment. The PSW and RHRSW are drawn from the Altamaha River. The 

components exposed to a PSW and RHR service water environment are found in the PSW system 

and the residual heat removal system. 

3.1.4.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's PSW and RHRSW chemistry control 

program to ensure that the effects of aging on components exposed to PSW and RHRSW will be 

adequately managed, so that the functions will be maintained consistent with the CLB for the period 

of extended operation for all components in PSW and RHRSW environments. 

Program Scope 

PSW and RHR service water chemistry controls are applied to the PSW system, RHRSW system, 

and traveling water screens/trash rack system, which include carbon steel, copper alloy, gray cast 

iron, cast austenitic stainless steel, stainless steel clad carbon steel and stainless steel 

components. The staff finds it appropriate and acceptable to include these systems in this AMP. 

The staff found a discrepancy regarding whether the PSW and RHRSW chemistry control program 

manages aging effects associated with valve bodies in the traveling water screens/trash racks 

system. By letter dated January 31, 2001, the applicant clarified that the isolation valve in the 

screen wash system credits the PSW and RHRSW chemistry control program. Specifically, a 

single isolation valve in the screen wash line, credited by the FHA safe shutdown list, credits this 

chemistry program to mitigate the effects of aging. 

Preventive or Mitigative Actions 

The PSW and RHRSW chemistry control program is designed to mitigate and prevent age-related 

degradation (loss of material through corrosion) by controlling the biological growth in the service 

water systems. Specifically, this program adds sodium hypochlorite alone or in conjunction with 

sodium bromide, and is coordinated with the periodic operation of the RHRSW to maximize 

chemical treatment. 

The staff finds it appropriate and acceptable to treat the service water system with these chemical 

additions to preclude the internal loss of material through biofouling. 

Parameters Inspected or Monitored 

The application states that during PSW system chlorination and bromination, free available oxidant 

(FAO) concentration is periodically monitored at the PSW discharge to the circulating water flume 

to ensure program efficiency. The plant's National Pollutant Discharge Elimination System 

(NPDES) permit governs the levels of discharged measurable chlorine, FAO, and total residual 

oxidant levels.

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The staff finds that monitoring of these parameters is appropriate and acceptable in determining 

the effectiveness of this AMP. Specifically, the FAO concentration at the discharge is a good indicator of the effectiveness of the chlorination and bromination in controlling the biofouling. 

Detection of Aging Effects 

The application states the PSW and RHRSW chemistry control program is a mitigative activity 

which is not intended to directly detect age-related degradation of components within the scope of 

this program. The staff agrees that the implementation of this program does not provide 

information directly related to the degradation of the specific material and that there is no need to 

do so because this program, in conjunction with other AMPs, provides a means of mitigating or 

preventing age-related degradation. 

Monitoring and Trending 

The application states that chemical additions under this AMP are monitored routinely through the 

treatment cycles which occur 5 times per week for 6 to 12 hours. During this treatment, FAO is 

monitored, which ensures that the chemical additions are at levels that result in program effectiveness and system is operating consistent with the requirements and limitations of the plant 

NPDES permit. 

The staff finds that the frequency of monitoring the established chemistry parameters is acceptable 

and appropriate to ensure that the aging effects of components within the scope of this program 

are managed. 

Acceptance Criteria 

The application states that the site NPDES permit provides diagnostic parameters and associated 

limitations for effective control of plant discharges. In addition, the permit provides for additional 

chemical monitoring every fifteen minutes until no residual oxidant is detected. These sample 

results are reported quarterly to the State of Georgia Department of Natural Resources. 

The staff finds that the applicant's criteria, which are founded on the applicant's NPDES permit, are 

acceptable and appropriate to ensure that a deviation from these parameters can be corrected to 

ensure that component functions of the components will be maintained during the period of 

extended operation. 

Operating Experience 

The application states that the plant has experienced biofouling problems with algae and has found 

evidence of the Asiatic clam. These sources of biofouling have yet to impair the effectiveness of 

components within the scope of this AMP. The applicant currently implements the chemical 

treatments consistent with the recommendations of Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and incorporates industry guidance, vendor 

recommendations, and plant-specific experience. The applicant states that periodic evaluation of 

this chemical treatment optimizes control of biofouling while maintaining discharge limits within the 

NPDES permit. Given the applicant's operating history and the industry-wide use of this program, 

the staff finds that the PSW and RHRSW chemistry control program will adequately manage the 

aging effects in the PSW system, RHRSW system, and the traveling screens/trash racks system.

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During a teleconference with the applicant on November 8, 2000, the staff noted that LRA Table 

3.2.4-16 identifies the PSW and RHRSW chemistry control program as managing aging associated 

with valve bodies in the traveling water screens/trash racks system. However, the description of 

the PSW and RHRSW chemistry control program in LRA Section B.1.4 does not include the 

traveling water screens/trash racks system within the scope of the program. During the 

teleconference, the applicant committed to revise Section B.1.4 in the FSAR Supplement to include 

the traveling screens/trash racks system within the scope of the PSW and RHRSW chemistry 

control program. By letter dated January 31, 2001, the applicant clarified this formally. 

3.1.4.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.4, of the LRA, "Plant Service Water 

(PSW) and Residual Heat Removal (RHR) Service Water Chemistry Controls," Section B.1.4, of 

the applicant's October 10, 2000 submittal, "Plant Service Water (PSW) and Residual Heat 

Removal (RHR) Service Water Chemistry Controls," and Section C. 1.2.4, the applicant's responses 

to the staff's RAIs, and additional information submitted by letter dated January 31,2001. On the 

basis of its review, the staff concludes that, in conjunction with other AMPs, the applicant has 

demonstrated that the effects of aging associated with structures and components in systems 

exposed to PSW and RHRSW will be adequately managed so that intended functions will be 

maintained, consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

3.1.5 Fuel Pool Chemistry Control 

3.1.5.1 Introduction 

The applicant described its fuel pool chemistry control AMP in LRA Sections A.1.5,C.2.6.5, and 

C.2.6.6 and Section B.1.5 of the applicant's October 10, 2000 submittal. The staff reviewed these 

sections of the LRA to determine whether the applicant has demonstrated that the effects of aging 

on structures and components in systems exposed to a fuel pool environment will be adequately 

managed so that intended function(s) will be maintained, consistent with the current licensing basis, 

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.5.2 Summary of Technical Information in the Application 

The fuel pool chemistry control activities mitigate aging in the fuel pool liner and associated 

components through the control of fluid purity and composition. The basis for the methodology 

employed to maintain fuel pool chemistry parameters within acceptable limits is provided in EPRI 

document TR-103515, "BWR Water Chemistry Guidelines." These activities are applicable to 

stainless steel liners for the spent fuel pool, spent fuel pool plugs, spent fuel pool gate, refueling 

canal, spent fuel pool racks, and miscellaneous steel inside the spent fuel pool. In addition, 

aluminum seismic restraints for the spent fuel pool racks are managed through these activities. 

3.1.5.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's fuel pool chemistry control program to 

ensure that the effects of aging on components exposed to fuel pool water will be adequately

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managed, so that the functions will be maintained consistent with the CLB for the period of 

extended operation for all components in a fuel pool water environment. 

Program Scope 

Fuel pool chemistry control activities are applied to the fuel storage system, which includes the 

spent fuel pool liner, components, and racks. 

Fuel pool chemistry control activities are applied to the fuel storage and refueling equipment 

systems, which include aluminum components. 

The staff agrees that it is appropriate to include the systems listed above within the scope of fuel 

pool chemistry control activities. 

Preventive or Mitigative Actions 

Fuel pool chemistry control is designed to mitigate and prevent age-related degradation by controlling fluid purity and composition. Specifically, this program focuses on minimizing 

detrimental ionic species (such as sulfates, chlorides, and organic carbons) and conductivity. The 

staff finds that the control of these and other impurities, as provided in the EPRI document, can 

mitigate and prevent age-related degradation. 

Parameters Inspected or Monitored 

The application states that fuel pool water is sampled regularly for conductivity, chlorides and 

sulfates, and total organic carbons, as provided in the EPRI document. Fuel pool pH and filterable 

solids are also periodically monitored. The staff finds that monitoring these parameters is adequate 

and sufficient to mitigate age-related degradation of the materials in the spent fuel pool. 

Detection of Aging Effects 

The application states that the fuel pool chemistry control program is a mitigative activity which is 

not intended to directly detect age-related degradation of the fuel pool and associated internal 

structures. The staff agrees that the implementation of this program does not provide information 

directly related to the degradation of the specific material and that there is no need to do so 

because this program, in conjunction with other AMPs, provides a means of mitigating or 

preventing age-related degradation. 

Monitoring and Trending 

The application states that spent fuel pool chemistry parameters are maintained in accordance 

within the parameters set forth in Appendix B of the EPRI document. These parameters include 

sulfates, chlorides, conductivity, and total organic carbon which are monitored weekly as provided 

in the EPRI document. In addition, fuel pool pH and filterable solids are regularly monitored. The 

staff finds that the frequency of monitoring the established chemistry parameters is acceptable and 

appropriate to ensure that a deviation from the set parameters can be corrected in a timely manner.

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Acceptance Criteria

The application states that the EPRI document provides diagnostic parameters and associated 

limitations for chemistry analyses. The staff finds that the criteria provided in the EPRI document 

are acceptable and appropriate for ensuring that a deviation from these parameters can be 

corrected to ensure that functions of the components are maintained during the period of extended 

operation. 

Operating Experience 

The application states that a review of the past 5 years has revealed no age-related deficiencies 

on the fuel pool or associated internal structures. Rare instances of minor fuel pool chemistry 

excursions have occurred but these instances have been determined not to be significant. In 

addition, the application states that the corrective actions program provides for evaluation of aging 

effects and significant operating events, and requires that reasonable actions be taken to enhance 

programs and activities to prevent future occurrences. Given the applicant's operating history and 

the industry-wide use of this program, the staff finds that the spent fuel pool chemistry control 

activities will adequately manage aging effects associated with the fuel pool for the period of 

extended operation. 

3.1.5.4 Conclusions 

The staff has reviewed the information in LRA Sections A.1.5, "Fuel Pool Chemistry Control," 

C.2.6.5, and C.2.6.6, Section B.1.5 of the applicant's October 10, 2000 submittal, and the 

applicant's responses to the staff's RAIs. On the basis of its review, the staff concludes that, in 

conjunction with other AMPs, the applicant has demonstrated that the effects of aging associated 

with structures and components in systems exposed to a fuel pool water environment will be 

adequately managed so that intended functions will be maintained, consistent with the current 

licensing basis, for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.6 Demineralized Water and Condensate Storage Tank Chemistry Control 

3.1.6.1 Introduction 

The applicant described its demineralized water and condensate storage tank chemistry control 

activities in LRA Sections A.1.6 and C.2.2.2 and Section B.1.6 of the applicant's October 10, 2000 

submittal. The staff reviewed these sections of the LRA to determine whether the applicant has 

demonstrated that the effects of aging on structures and components in systems exposed to 

demineralized water and condensate storage tank environments will be adequately managed so 

that intended functions will be maintained, consistent with the current licensing basis, for the period 

of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.6.2 Summary of Technical Information in the Application 

The demineralized water and CST chemistry control activities are intended to mitigate aging by 

monitoring fluid purity and composition in the makeup water to multiple systems. The principal 

elements of these activities are regular sampling, results analysis and, when applicable, chemistry 

modification.

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3.1.6.3 Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demineralized water and CST chemistry 

control program to ensure that the effects of aging on components exposed to demineralized and 

CST water will be adequately managed, so that the functions will be maintained consistent with the 

CLB for the period of extended operation for all components in demineralized water and CST water 

environments. 

Program Scope 

The demineralized water and CST chemistry control is directly or indirectly monitored in the 

following systems: 

B21 -Nuclear Boiler 

C11 -CRD 

E41-HPCI 

E51-RCIC 

P11-Condensate Transfer and Storage 

R43-EDG 

T23-Primary Containment 

It is noted that while the demineralized water system proper is not within the scope of license 

renewal, several systems and components that receive makeup water from the demineralized 

water storage tank (DWST) are within the scope of license renewal. Therefore, the DWST 

chemistry control is an important aspect of aging management for the systems indicated above. 

The staff finds the applicant's scope to be appropriate and acceptable, since these systems are 

monitored by the demineralized water chemistry control. 

Preventive or Mitigative Actions 

The staff finds that the control of detrimental ionic species and other impurities in demineralized 

water, as provided in the BWR water chemistry guidelines can mitigate and prevent age-related 

degradation. By controlling the water chemistry in the CST and DWST, the applicant reduces the 

potential for significant corrosion of plant systems and components exposed to a demineralized 

water environment. Therefore, the staff finds this approach acceptable. 

Parameters Inspected or Monitored 

The BWR water chemistry guidelines provide the basis for the monitored demineralized water 

chemistry parameters to ensure adequate chemistry control at Plant Hatch. The staff finds that 

monitoring these parameters is adequate and sufficient to mitigate age-related degradation of the 

systems and components exposed to a demineralized water environment. 

Detection of Aging Effects 

The application states that the demineralized water and CST chemistry control program is a 

mitigative activity which is not intended to directly detect age-related degradation of the systems

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and components exposed to a demineralized water environment. The staff agrees that the 

implementation of this program does not provide information directly related to the degradation of 

the specific material and that there is no need to do so because this program, in conjunction with 

other AMPs, provides a means of mitigating or preventing age-related degradation. 

Monitoring and Trending 

The application states that demineralized water chemistry control does not directly monitor or trend 

age-related degradation and as such is not credited to perform this attribute. However, the BWR 

water chemistry guidelines provide the basis for the methodology employed for periodic monitoring 

of demineralized water chemistry parameters at Plant Hatch. These parameters include sulfates, 

chlorides, total organic carbon, and silica, which are monitored weekly as recommended by the 

EPRI document. In addition, conductivity and pH are diagnostically monitored. The staff finds that 

the monitoring frequency identified in the BWR water chemistry guidelines is acceptable and 

appropriate to ensure that a deviation from the set parameters can be corrected within a timely 

manner. 

Acceptance Criteria 

The application states that the BWR water chemistry guidelines provide diagnostic parameters and 

associated limitations for chemistry analyses. In addition to the EPRI requirements, the applicant 

also diagnostically monitors pH and conductivity. The staff finds that the criteria provided in the 

EPRI document is acceptable and appropriate for ensuring that a deviation from these parameters 

can be corrected to ensure that intended functions of the components are maintained during the 

period of extended operation. 

Operating Experience 

The application states that a review of the past 5 years has revealed that no age-related 

deficiencies were found as a result of significant corrosion of system components. Rare instances 

of CST and DWST chemistry excursions have occurred, but these instances have been determined 

not to be significant. In addition, the EPRI TR-1 03515 guidelines for auxiliary systems incorporated the input of industry experts and utility experience. Therefore, the operation, according to the 

guidelines specified by these EPRI guidelines, ensures that pertinent industry issues were 

considered. Therefore, given the applicant's operating history and the industry-wide use of this 

program the staff finds that the demineralized water and CST chemistry control activities will 

adequately manage the aging effects associated with the CST and DWST for the period of 

extended operation. 

3.1.6.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.6, "Demineralized Water and 

Condensate Storage Tank Chemistry Control," and Section B.1.6, "Demineralized Water and 

Condensate Storage Tank Chemistry Control," of the applicant's October 10, 2000 submittal. On 

the basis of its review, the staff concludes that, in conjunction with other AMPs, the applicant has 

demonstrated that the effects of aging associated with structures and components in systems exposed to demineralized water and CST environments will be adequately managed so that 

intended functions will be maintained, consistent with the current licensing basis, for the period of 

extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.7 Suppression Pool Chemistry Control

3.1.7.1 Introduction 

The applicant described its suppression pool chemistry control AMP in LRA Section A.1.7. The 

applicant supplemented the description of this AMP in Section B.1.7 of the applicant's submiital 

dated October 10, 2000. The staff reviewed these sections of the LRA to determine whether the 

applicant has demonstrated that the effects of aging on structures and components in systems 

exposed to a suppression pool environment will be adequately managed so that intended 

function(s) will be maintained, consistent with the current licensing basis, for the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.7.2 Summary of Technical Information in the Application 

In LRA Sections A.1.7 and B.1.7, the applicant describes an existing AMP, the suppression pool 

chemistry control program, that manages, in part, aging effects for various structures and 

components exposed to the suppression pool environment. The affected systems include nuclear 

boiler, residual heat removal, core spray, high-pressure coolant injection, reactor core isolation 

cooling, primary containment, and primary containment purge and inerting. The applicant lists the 

specific system structures and components that are exposed to the suppression pool environment 

in LRA Sections 3.2 and 3.3. These structures and components are fabricated from either carbon 

steel or stainless steel. 

As discussed in LRA Section C.1.2.2, loss of material is an applicable aging effect that may affect 

both carbon steel and stainless steel structures and components through several corrosion 

mechanisms. These mechanisms include general corrosion, galvanic corrosion, crevice corrosion, 

pitting, MIC, and erosion corrosion. The applicant also considers cracking to be an applicable 

aging effect that may affect specific stainless steel components (that experience higher operating temperatures) as a result of stress corrosion cracking or intergranular attack. To mitigate these 

corrosion-related aging effects, the applicant relies on the suppression pool chemistry control 

program. 

The suppression pool water (also called "torus water" in the LRA) contained within the torus 

consists of demineralized water supplied from demineralized water sources (such as the 

condensate storage tank). The applicant relies on chemistry controls to mitigate aging associated 

with corrosion in structures and components exposed to the suppression pool water by controlling 

the water purity and composition. The program consists of periodic sampling and testing of the 

suppression pool water for conductivity, chlorides, sulfates, and total organic compounds. The 

applicant stated that the program is found on the applicable portions of the EPRI BWR Water 

Chemistry Guidelines. 

3.1.7.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's suppression pool chemistry control 

program to ensure that the effects of aging on components exposed to a suppression pool environment will be adequately managed, so that the functions will be maintained consistent with 

the CLBfor the period of extended operation for all components in a suppression pool environment.

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Program Scope

The applicant stated that the scope of this program included structures and components within the 

nuclear boiler (including safety relief valve tailpipes and associated supports), residual heat 

removal, core spray, high pressure coolant injection, reactor core isolation cooling, and primary containment purge and inerting systems, and primary containment (including the torus). The staff 

finds the program scope to be acceptable because the scope is comprehensive in that it includes 

all components exposed to the suppression pool water environment. 

Preventive or Mitigative Actions 

The program minimizes detrimental ionic species and conductivity in the suppression pool environment. The staff finds these actions acceptable because by minimizing ionic species and 

conductivity, one mitigates degradation as a result of corrosion. 

Parameters Inspected or Monitored 

The program monitors conductivity, chlorides, sulfates, and total organic carbons in accordance 

with the BWR water chemistry guidelines (EPRI TR-103515). The staff finds this acceptable because published literature and operating experience to date support the monitoring and control 

of these specific parameters to mitigate corrosion-related degradation. 

Detection of Aging Effects 

The applicant stated that the suppression pool chemistry control program is a mitigative activity which is not intended to directly detect age-related degradation. The staff agrees that the 

implementation of this program does not provide information directly related to the degradation of 

the structures and components within the scope of this program and that there is no need to do so 

because this program, in conjunction with other AMPs, provides a means of mitigating or 

preventing age-related degradation. 

Monitoring and Trending 

The applicant stated that the frequency of the suppression pool water sampling is on a quarterly basis, consistent with the EPRI guidelines. The staff finds this frequency to be acceptable because 

operating experience to date supports this frequency to be often enough to detect and correct 

anomalous chemistry conditions before there is a loss of intended functions. The applicant also 

stated that they monitor and trend the sampling results. Monitoring and trending provide important information about how a program is performing relative to acceptance criteria. Proactive monitoring and understanding of trending behavior allow for corrective actions to be taken prior to exceeding the acceptance criteria. Monitoring and trending of water chemistry parameters are also consistent 

with the EPRI BWR water chemistry guidelines. The staff therefore finds this approach to be 

acceptable. 

Acceptance Criteria 

The applicant applies the acceptance criteria consistent with those in the BWR water chemistry guidelines. The staff finds this acceptable because the acceptance criteria have low thresholds to 

allow for the early detection and correction of anomalous chemistry conditions.

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Operating Experience 

Operating experience provides the staff additional information about the acceptability of an AMP. 

The applicant reviewed plant deficiency cards over the past 5 years that showed that no age related deficiency report had been written on the structures or components within the scope of 

license renewal for which suppression pool chemical control is credited. Suppression pool chemistry excursions have been rare. In the past 5-years, only minor excursions above the EPRI 

criteria have occurred. The applicant stated that none of these excursions was determined to be 

significant. 

Additionally, the program follows the EPRI BWR water chemistry guidelines that incorporate the 

input of industry experts and utility experience and thus ensures the consideration of pertinent 

industry issues. These guidelines have been used by the industry for many years. Given the 

acceptable operating experience to date, the staff believes that this guidance has proven itself 

effective in minimizing corrosion-related degradation in the suppression pool water environment. 

3.1.7.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.7, "Suppression Pool Chemistry Control" 

Section B.1.7, "Suppression Pool Chemistry Control" of the applicant's October 10, 2000 submittal, 

and the applicant's responses to the staff's RAIs. On the basis of its review, the staff concludes 

that, in conjunction with other AMPs, the applicant has demonstrated that the effects of aging 

associated with structures and components exposed to a suppression pool environment will be 

adequately managed so that intended functions will be maintained, consistent with the current 

licensing basis, for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.8 Corrective Actions Program 

3.1.8.1 Introduction 

In LRA Section A. 1.8, "Corrective Action Program" and Section B. 1.8, "Corrective Actions Program" 

of the applicant's October 10, 2000 submittal, the applicant describes the aging management 

program credited for initiating corrective actions when age-related degradation is identified in 

structures and components subject to an AMR. The staff reviewed this AMP to determine if the 

applicant has included the attributes needed for an adequate AMP. 

The license renewal applicant is required to demonstrate that the effects of aging on structures and 

components subject to an AMR will be adequately managed to ensure that their intended functions 

will be maintained consistent with the CLB of the facility for the period of extended operation. Therefore, those aspects of the AMR process that affect the quality of safety-related structures, 

systems, and components, are subject to the quality assurance (QA) requirements of Appendix B 

to 10 CFR Part 50. For non-safety-related structures and components subject to an AMR, the 

existing 10 CFR Part 50, Appendix B QA program may be used by the applicant to address the 

elements of corrective actions, confirmation process, and administrative controls. 

3.1.8.2 Summary of Technical Information in the Application 

LRA Section A. 1.8 and Section B. 1.8 of the applicant's October 10, 2000 submittal provide a brief 

description of the corrective actions program (CAP) and state that the CAP applies to all SSCs

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within the scope of license renewal. The CAP is also described as part of the applicant's Quality 

Assurance Program required by 10 CFR Part 50, Appendix B. 

LRA Section A.1.8.1 states that the CAP is briefly described in Chapter 17 of the Plant Hatch Unit 

2 UFSAR, and asserts that this process will be effective for correcting potential age-related 

degradation that may be discovered during the renewal term. The primary vehicle for initiating 

corrective action at the plant is the condition reporting process. Existing procedures include the 

necessary forms and instructions for reporting potential problems related to aging management of 

the SSCs that are within the scope of license renewal. Significant conditions adverse to quality 

require initiation of a special report. Significant occurrences are investigated to determine root 

cause, and actions are taken to preclude recurrence. Forms and guidance for root cause analysis 

are provided in Plant Hatch procedures and guidelines. Corrective actions are part of the QA 

program, as required for the Plant Hatch current license term under Criterion XVI of Appendix B 

to 10 CFR Part 50. 

3.1.8.3 Staff Evaluation 

During the scoping and screening audit conducted from June 12 through June 15, 2000, the 

applicant's implementation of the corrective actions process described in LRA Section 3.1.8 was 

reviewed by the staff. 

Section C.2 of the LRA provides an AMR summary for each unique structure, component, or 

commodity group determined to require aging management during the period of extended 

operation. This summary includes identification of aging effects requiring management, aging 

management programs utilized to manage these aging effects, and attribute tables that 

demonstrate how the identified aging management programs manage aging effects. The staff 

found that the attributes identified for each AMR were consistent with those attributes described 

in Table A.1-1 of the draft SRP-LR. However, the Plant Hatch LRA does not describe each of 

these attributes and, therefore, the applicant was requested to provide this information in RAI 3.1.8

1, issued on July 28, 2000. 

In its response to the staff's RAI dated October 10, 2000, the applicant confirmed that the 

description for each of the 10 attributes is the same as the description given in the draft SRP-LR. 

Section B to the submittal dated October 10, 2000, included a description of these attributes. The 

staff has reviewed the corrective actions, administrative controls, and confirmation process aging 

management program attributes described by the applicant in Section B to the RAI response and 

concluded that they are consistent with the description given in the draft SRP-LR and are, 

therefore, acceptable. Accordingly, RAI 3.1.8-1 is closed. 

Section A.2 of the draft SRP-LR, requires a license renewal applicant to demonstrate that the 

effects of aging on structures and components subject to an aging management review will be 

adequately managed to ensure that their intended functions will be maintained consistent with the 

current licensing basis of the facility for the period of extended operation. Consistent with this 

approach, the applicant's aging management programs should contain the elements of corrective 

action, confirmation process, and administrative controls in order to ensure proper management 

of the aging programs. 

LRA Section C.2 provides an aging management summary for each unique structure, component, 

or commodity group at Plant Hatch determined to require aging management during the period of

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extended operation. For the majority of these AMRs, corrective actions, confirmation process, and 

administrative controls are specifically addressed by reference to the applicant's CAP. However, 

LRA Section A.1.8, does not describe how the CAP program specifically addresses those three 

attributes for which credit is being sought. Therefore, in RAI 3.1.8-2, the applicant was requested 

to provide a description of how the CAP program specifically addresses these three attributes for 

the aging management programs at Plant Hatch during the period of extended operation. 

In its October 10, 2000, response to the staff's RAI, the applicant stated that the LRA used the 

label "Corrective Actions Program" for a combination of plant activities that includes the plant's 

corrective actions program and portions of the plant's 10 CFR Part 50 Appendix B QA program. 

The applicant added that Appendix B to the RAI response provided a description of how this 

program addresses the attributes credited. 

In Section B to its October 10, 2000, RAI response, the applicant provided a summary of aging 

management programs for license renewal. Under Section B.1 of the Section, the applicant stated 

the following: 

"The Corrective Actions Program is credited for the following four attributes for all 

aging management activities at Plant Hatch: 

* Attribute 7 - Corrective actions, including root cause determination and 

prevention of recurrence, are included. 

0 Attribute 8 - Confirmation process is included. 

* Attribute 9 - Administrative controls should provide a formal review and approval 

process. 

* Attribute 10 - Operating experience of the aging management program, including 

past corrective actions resulting in program enhancements or additional programs, 

are considered." 

Further, in Section B.1.8 of the submittal dated October 10, 2000, the applicant described in detail 

how corrective actions, confirmation process, and administrative control elements are to be met 

for all aging management programs at Plant Hatch. As described in Section B.1.8, the applicant 

has established and implemented a QA Program for Plant Hatch that conforms to the criteria set 

forth in 10 CFR Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel 

Reprocessing Plants". The QA program addresses all aspects of quality assurance at Plant Hatch. 

The two elements of the Plant Hatch QA program that are most pertinent to the aging management 

programs credited for license renewal are corrective actions and administrative controls. These 

elements are discussed in Chapter 17 of the Plant Hatch Unit 2 UFSAR, and are outlined below. 

Corrective action and administrative control requirements apply to all components within the scope 

of license renewal. 

Program Scope 

The plant condition reporting process applies to all plant systems and components within the scope 

of license renewal. Administrative controls are in place for existing aging management programs

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and activities and for the currently required portions of enhanced programs and activities. 

Administrative controls will also be applied to new programs and activities as they are implemented. As a minimum, these programs and activities are or will be performed in accordance with written 

procedures. Those procedures are or will be reviewed and approved in accordance with Plant 

Hatch's 10 CFR Part 50, Appendix B, QA Program. 

The staff finds that the applicant has adequately identified that all structures, components, and 

commodity groups are within the scope of the CAP. 

Preventive or Mitigative Actions 

The CAP provides a means to correct conditions identified as being adverse to quality. There are 

no preventive or mitigative attributes specifically credited for this program. The staff finds that the 

CAP is not a preventive or mitigative activity and instead, corrects conditions found to be adverse 

to quality. 

Parameters Inspected or Monitored 

No specific parameters are inspected or monitored as part of this program. Generally, when 

parameters inspected or monitored by other plant programs indicate a condition adverse to quality, the CAP provides a means to correct the identified condition. The staff agrees that this program does not inspect or monitor parameters, nor should it. 

Detection of Aging Effects 

Detecting aging effects is not part of the CAP. The CAP provides a means to address the aging effects identified by other AMPs. The staff agrees that the purpose of this program is not to detect 

aging effects, but to provide corrective actions when other AMPs identify aging effects. 

Monitoring and Trending 

The corrective action process is monitored and trended to ensure that corrective actions taken are 

adequate and timely. Significant and in-significant conditions are trended. Plant Hatch monitors 

significant conditions that are adverse to quality (significant occurrence reports) and requires a 

formal cause determination and corrective actions to prevent recurrence. The staff finds that the 

CAP adequately monitors and trends significant conditions to identify and correct the adverse 

conditions in a timely manner. 

Acceptance Criteria 

The CAP does not include specific acceptance criteria for in-scope components. Generally, when 

the acceptance criteria of other AMPs are not met, the CAP provides a means to ensure 

appropriate corrective actions are taken. The staff agrees that the purpose of the CAP is to correct 

and restore components that do not meet acceptance criteria. 

Corrective Actions 

Corrective action is initiated following the determination of conditions adverse to quality, and 

documented as required by appropriate procedures. Various processes are used to identify

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problems requiring corrective action. The primary vehicle for initiating corrective action at Plant 

Hatch is the condition reporting process described in Section 17.2.15 of the Unit 2 UFSAR. 

The various components of corrective action provide for timely corrective actions, including root 

cause determination and prevention of recurrence. The QA program provides control over activities 

affecting the quality of systems, structures, and components consistent with their importance to 

safety. In accordance with plant procedures, condition reports are analyzed for adverse trends. 

Any identified adverse trends are reported to the appropriate department for corrective action. 

The staff finds the corrective action process acceptable, appropriate, and sufficient to identify and 

correct conditions adverse to quality in a timely manner. 

Confirmation Process 

As described in Section 17.2.15 of the Unit 2 UFSAR, condition reports are reviewed to determine 

the regulatory reportability and significance. Those items found to be significant conditions adverse 

to quality are also reviewed. Corrective actions taken for significant items are reviewed for 

assurance that appropriate action has been taken. 

The staff finds that the confirmation process is adequate to ensure that corrective actions are 

appropriate and complete. 

Administrative Controls 

Activities affecting quality are prescribed by documented instructions, procedures, or drawings of 

a type appropriate to the circumstances and are accomplished in accordance with these 

instructions, procedures, or drawings. They contain appropriate acceptance criteria and 

documentation requirements for determining whether important activities have been satisfactorily 

accomplished. Site procedures establish review and approval requirements. 

The staff finds the administrative controls to be adequate to ensure that corrective actions are 

uniform and thorough. 

Operating Experience 

The CAP provides for evaluation of aging effects and significant operating events and requires that 

reasonable actions be taken to enhance programs and activities to prevent future occurrences. 

Review of the operating experience sections for the other AMPs provides numerous examples of 

the CAP being used to address and correct age-related conditions adverse to quality. 

The results of CAP audits since 1995 were reviewed. The review determined that findings from 

the CAP audits have resulted in enhancements to the CAP. 

On the basis of its review of operating experience discussed in the LRA, the staff finds that the 

CAP has been effective in correcting conditions adverse to quality. Further, the staff finds that the 

applicant's evaluation process for the CAP has resulted in improvements to the program.

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On the basis of the information provided in the LRA, as supplemented by the information in Section 

B to the applicant's October 10, 2000, RAI response, with respect to the applicability of Appendix 

B to 10 CFR Part 50 requirements to the corrective actions, confirmation process, and 

administrative control attributes for the aging management programs at Plant Hatch, the staff has 

determined that there is reasonable assurance that the applicant's QA program will adequately 

address those attributes during the period of extended operation. Therefore, RAI 3.1.8-2 is closed. 

In addition, on the basis of the information provided in the LRA, as supplemented by the 

information in Section B to the applicant's October 10, 2000, submittal, with respect to the 

remaining program attributes, the staff has determined that there is reasonable assurance that the 

applicant's QA program will adequately address those attributes during the period of extended 

operation. 

3.1.8.4 Conclusion 

The staff has reviewed the information presented in Section A.1.8, of the LRA, "Corrective Actions 

Program" and Section B.1.8, of the applicant's October 10, 2000 submittal, "Corrective Actions 

Program." On the basis of this review, the staff concludes that the Plant Hatch FSAR Supplement containing the corrective actions, confirmation process, and administrative control attributes 

described in Section B to the applicant's RAI response dated October 10, 2000, and which are 

governed by the Plant Hatch QA program, will provide reasonable assurance that these aging 

management program attributes will be implemented in an acceptable manner during the period of extended operation. In addition, the staff concludes that the remaining program attributes 

provide reasonable assurance that the corrective actions program will manage the aging effects 

associated with components within the scope of license renewal and subject to an AMR. 

3.1.9 Inservice Inspection Program 

3.1.9.1 Introduction 

The applicant described its ISI program AMP in LRA Sections A.1.9 and Section B.1.9 of the 

applicant's October 10, 2000 submittal. The staff reviewed these sections of the LRA to determine 

whether the applicant has demonstrated that this program will manage the effects of aging on 

structures and components such that the associated systems will perform their intended 

function(s), consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

The ISI Program is a condition monitoring program that provides for the implementation of ASME 

Code, Section Xl, in accordance with the provisions of 10 CFR 50.55a. The ISI Program also 

includes augmented examinations required to satisfy commitments made by the applicant (e.g., GL 88-01, NUREG-0619). The 10-year examination plan provides a systematic guide for 

performing nondestructive examination of passive components within the scope of license renewal. 

Plant Hatch has two units with different dates for construction permits and operating licenses. 

However, Unit 2's first 10-year interval was completed early (1986), so both units would be 

committed to the same version of ASME Section XI. Accordingly, Plant Hatch is currently in the 

third 10-year interval. The period of extended operation will include the fifth and sixth ISI intervals.

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3.1.9.2 Summary of Technical Information in the Application

The IS! program provides examination methods and acceptance criteria for Class 1, 2, 3 

(equivalent), and Class MC pressure boundary components, as well as the associated supports. 

it also provides for periodic pressure testing of those same components, along with repair, 

replacement, and modification activities. 

Three types of inspection methods are used for inservice examination at Plant Hatch. They are 

visual inspections, surface inspections, and volumetric inspections. Visual inspections are 

performed as defined in ASME Code, Section Xl, Subsection IWA-2210. Three types of visual 

examinations are used: VT--, VT-2, and VT-3. VT-1 inspections are used to determine the 

condition of the part, component, or surface examined, including cracks, wear, corrosion, and/or 

physical damage. VT-2 inspections are used to locate evidence of leakage from pressure retaining 

components during a system pressure test. VT-3 inspections are used to determine the general 

mechanical and structural condition of components and in associated supports, such as verification 

of clearances, physical displacements, and loose or missing parts. This includes inspection for 

debris, corrosion, wear, erosion, and/or loss of integrity at bolted or welded connections. 

Surface examinations are performed as defined in Subsection IWA-2220 to determine whether 

surface cracks or discontinuities exist. Acceptable examination methods include magnetic particle and liquid penetrant methods. Volumetric examinations are performed as defined in IWA-2230 to 

locate discontinuities throughout the volume of material. These examinations may be conducted 

from the inside or outside surface of a component. Either radiographic (RT) or UT methods may 

be used. 

ASME Section Xl, Subsections IWB, IWC, IWD, and IWE provide examination requirements for 

ASME Class 1, 2, and 3 (equivalent) and Class MC components, respectively. Subsection IWF 

addresses component supports, which are treated the same as the Code Class component they 

support. Code Case N-491 is an acceptable alternative to the tables and scope expansion 

requirements of ASME Section Xl, Subsection IWF. 

3.1.9.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the ISI program to 

ensure that the applicable component aging effects will be managed so that system intended 

functions will be maintained consistent with the CLB for the period of extended operation. 

Program Scope 

The applicant stated that the ISI program contains examination requirements and acceptance 

criteria for Class 1, 2, and 3 (equivalent), and Class MC pressure boundary components, as well 

as the associated supports. It also provides for repair, replacement, and modification activities. 

The ISI Program is credited for monitoring potential age-related degradation in portions of the 

following systems: 

Bll - Reactor Assembly 

B21 - Nuclear Boiler

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B31 - Reactor Recirculation 

El 1 - Residual Heat Removal (RHR) and RHR Service Water 

P41 - Plant Service Water 

T23 - Primary Containment 

T52 - Containment Penetrations 

The staff finds the program scope to be acceptable because the scope is comprehensive in that 

it includes all components for which the ISI program applies. 

Preventive or Mitigative Actions 

The applicant stated that the ISI program is a condition monitoring program. Therefore, there are 

no preventive or mitigative attributes associated with this program. The staff agrees that the ISI 

program does not prevent or mitigate age-related degradation, but rather identifies age-related 

degradation. 

Parameters Inspected or Monitored 

The applicant stated that the ISl program utilizes visual, surface, and volumetric examinations of 

Class 1, 2, and 3, and Class MC pressure boundary components, as well as the associated 

supports, that would detect potential degradation of their intended functions, as a result of loss of 

material and cracking, during the period of extended operation. In LRA Section B.1.9 the applicant 

stated that the ISI program will also be used to detect loss of preload for the applicable in-scope 

Class 1 systems and components. 

The staff finds the parameters to be inspected or monitored to be acceptable. 

Detection of Aging Effects 

The applicant stated that the ISI Program monitors the aging effects using visual, surface, and 

volumetric inspection methods. To ensure that the aging effects are identified before there is a loss 

of intended function, the staff relies on an adequate program scope, appropriate monitoring of 

parameters, and appropriate frequency interval. Where specific ASME Section Xl inspection requirements are credited to manage the effects of aging in the LRA, the extent and frequency of 

examinations are predicated on the tables in Article 2500 of ASME Section Xl, Subsections IWB, 

IWC, IWD, IWE, and IWF. The staff finds that the ASME Code requirements used to detect aging 

effects are adequate. 

Monitoring and Trending 

The applicant stated that deficiencies discovered during the performance of the program activities 

are documented in accordance with the procedures implementing the Plant Hatch ISI program. 

Deficiencies discovered through the ISI program are monitored in accordance with ASME Code 

requirements. Deficiencies requiring repair or replacement are entered into the plant corrective 

action program. The staff finds this process adequate to effectively monitor and trend age-related 

degradation.

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Acceptance Criteria

The applicant stated that, for the third 10-year inspection interval, Plant Hatch uses the 1989 

Edition of the ASME Code, Section Xl, for Class 1, 2, and 3 systems and components. 

Components not meeting the acceptance criteria defined in ASME Section Xl, Tables IWB-2500-1, 

IWC-2500-1, and IWD-2500-1 are evaluated, repaired, or replaced before returning to service. In 

1996, Plant Hatch submitted a request for relief from meeting the requirements of the ASME Code 

for Class MC component repairs and replacement until September 9, 1997. The NRC approved the request for relief in May 1997. Accordingly, repairs, replacements, or modifications for Class 

MC components that occurred after September 9,1997, have been performed in accordance with 

the requirements of the ASME Code, Section XI, 1992 Edition with 1992 Addenda. The staff finds 

that the acceptance criteria used by the applicant is acceptable. 

Operating Experience 

The applicant stated that the Plant Hatch ISI program is founded on the requirements of the ASME 

Code. The ASME Code development process includes extensive review and approval by industry 

experts, thereby assuring that any significant industry data has been considered in the 

development of the ASME Code, which forms the basis for the Plant Hatch ISI program. In 

addition, the Commission's process of reviewing Editions and Addenda of the ASME Code and 

incorporating them into 10 CFR 50.55a provides additional assurance that all significant issues 

have been considered. The applicant stated that several deficiencies have been identified on the 

in-scope components and systems. For those identified as age-related, the applicant's corrective 

actions program was used to address the concerns, in accordance with Plant Hatch's 

implementation of ASME Code, Section Xl, within the ISI program. The corrective actions program 

provides for evaluation of aging effects and significant operating events and requires that 

reasonable actions be taken to enhance programs and activities to prevent future occurrences. The 

staff finds that the acceptance criteria used by the applicant for this AMP is appropriate. 

3.1.9.4 Conclusions 

The staff has reviewed the information in LRA Sections A.1.9, "Inservice Inspection Program," and 

Section B.1.9 of the applicant's October 10, 200 submittal. On the basis of this review, the staff 

concludes that the applicant has demonstrated that the aging effects managed by the ISI program will be adequately managed so that there is reasonable assurance that the systems covered by this 

inspection program will perform their intended functions in accordance with the CLB during the 

period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.10 Overhead Crane and Refueling Platform Inspections 

3.1.10.1 Introduction 

The applicant described its overhead crane and refueling platform inspections in LRA 

Sections A.1.10 and B.1.10. The staff reviewed these sections of the LRA to determine whether 

the applicant has demonstrated that the effects of aging managed by the overhead crane and 

refueling platform inspections will be adequately managed so that there is reasonable assurance 

that the systems covered by this inspection program will perform their intended functions in 

accordance with the CLB during the period of extended operation, as required by 10 CFR 

54.21 (a)(3).

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3.1.10.2 Summary of Technical Information in the Application

In Section A.1.10 of the LRA and Section B.1.10 of the applicant's submittal dated October 10, 

2000, the applicant describes an existing aging management program, the overhead crane and 

refueling platform inspection program, that provides for periodic visual inspections to monitor the 

condition of the passive structural elements of the crane and refueling platform with respect to their 

structural integrity. The applicant identified loss of material as a result of corrosion as the aging 

effect requiring management by this program. The affected mechanical systems include the 

refueling platform equipment assembly and the reactor building crane. The applicant lists the 

specific systems, structures, and components in LRA Section 3.2. These two mechanical systems 

are fabricated from either carbon steel or aluminum. In addition to the overhead crane and 

refueling platform inspection program, the protective coatings program, which is described in LRA 

Section A.2.3, is also used to manage the loss of material aging effect for these two mechanical 

systems. 

The applicant states that the overhead crane and refueling platform inspection activities satisfy the 

requirements of the Unit 1 Technical Requirements Manual, which has provisions for surveillance 

testing of the 5-ton hoist and the crane /hoist used for handling fuel assemblies or control rods. 

The overhead crane and refueling platform hoist, rigging, slings and lifting devices are visually 

inspected to detect evidence of loss of material. The overhead crane and refueling platform 

inspection program also includes a number of other inspection activities that are not credited for 

license renewal aging management, such as a pre-operational static inspection, pre-operational 

dynamic inspection, operational inspection, and maintenance inspection. 

3.1.10.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the overhead crane and 

refueling platform inspections program to ensure that the applicable component aging effects will 

be managed so that system intended functions will be maintained consistent with the CLB for the 

period of extended operation. 

Program Scope 

In Section B.1.10 of its October 10, 2000 submittal, the applicant stated that the reactor building 

overhead crane and refueling platform are generally considered to be active components; however, 

the components that are responsible for the structural integrity of the crane and refueling platform 

are considered to be passive, and are thus within the scope of license renewal. The passive 

structural load-bearing components include the crane girder, rails, and bolts. Regarding the 

inspection scope, the applicant stated, in response to RAI 3.1.10-2, that the active moving sub

components of the overhead crane and refueling platform, such as the wire rope, drums, and other 

associated parts, are not within the scope of license renewal. Therefore, aging effects such as 

cracking of the wire rope and mechanical degradation/distortion attributable to fatigue were not 

considered for the overhead crane and refueling platform inspection program. In response to RAI 

3.1 .10-5, the applicant stated that galvanic corrosion between the aluminum rivets and structural 

steel of the refueling equipment assembly is not an aging effect requiring management because 

the aluminum surfaces exposed to air will develop a thin oxide coating, and no electrolyte is present 

to initiate or sustain a galvanic reaction. The staff finds that the scope of the overhead crane and 

refueling platform inspections program is acceptable since it includes a visual inspection of all of

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the passive components that are responsible for the structural integrity of the overhead crane and 

refueling platform. 

Preventive and Mitigative Actions 

There are no preventive or mitigative actions taken as part of this program, and the staff did not 

identify the need for such actions. 

Parameters Inspected or Monitored 

The contacting surfaces of the passive structural load bearing components of the overhead crane 

and refueling platform such as the crane girder, rails, and bolts, are periodically inspected in accordance with plant procedures. The staff finds that visual inspections will be adequate for identifying loss of material from these surfaces during the period of extended operation. 

Detection of Aging effects 

With respect to the frequency interval of inspections, the applicant stated in Section B.1.10 of its 

October 10, 2000, submittal that general visual inspections are performed monthly and that the overhead cranes are inspected daily when in use. The staff finds that the applicant's operating experience to date supports the continuation of this inspection frequency interval and will provide reasonable assurance that the loss of material aging effect will be detected before there is a loss 

of intended function. 

Monitoring and Trending 

The applicant stated that the results of the system inspections and tests are documented in accordance with procedural requirements. In addition the corrective actions program is used to 

monitor the component deficiencies and to implement timely corrective actions. The staff finds that these monitoring activities are adequate to ensure that corrective actions will be taken before 

exceeding the acceptance criteria. 

Acceptance Criteria 

The applicant states that the acceptance criteria for the overhead crane and refueling platform inspection program is that, "bridges, bridge rails, trolley, and trolley rails must be straight, and 

without evidence of physical damage such as cracking." The staff finds that the acceptance criteria specified above are adequate to ensure that the system intended function(s) are maintained under 

all CLB design conditions during the period of extended operation. 

Operating Experience 

The overhead crane and refueling platform inspection program is an existing program; however, the applicant did not provide a description of the program inspection findings. In response to RAI 

3.1.10-6, the applicant stated that a review of the "plant deficiency cards" from the past 5 years did 

not reveal any loss of material from the in-scope components of the overhead crane or the refueling platform. The staff finds that the applicant's operating experience has demonstrated that the 

overhead crane and refueling platform inspection program has effectively maintained the structural 

integrity of the overhead crane and refueling platform, and the effects of aging will be adequately

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managed so that the system intended function will be maintained during the period of extended 

operation. 

3.1.10.4 Conclusions 

The staff has reviewed the information in LRA Sections A.1.10, "Overhead Crane And Refueling 

Platform Inspections," and Section B.1.10 of the applicant's October 10, 2000 submittal. On the 

basis of this review, the staff concludes that the applicant has demonstrated that the aging effects 

managed by the overhead crane and refueling platform inspection program will be adequately 

managed so that there is reasonable assurance that the systems covered by this inspection 

program will perform their intended functions in accordance with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

3.1.11 Torque Activities 

3.1.11.1 Introduction 

The applicant described its torque activities AMP in LRA Sections A.1.11, C.2.1.1.6, and C.2.2.10 

and Section B.1.11 of the applicant's October 10, 2000 submittal. The staff reviewed these 

sections of the LRA to determine whether the applicant has demonstrated that the effects of aging 

managed by the torque activities will be adequately managed so that the systems covered by this 

activity will perform their intended functions in accordance with the CLB during the period of 

extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.11.2 Summary of Technical Information in the Application. 

Torque activities are intended to mitigate loss of preload through use of proper torque techniques 

at Plant Hatch. Plant procedures provide specific instructions for maximizing the effectiveness of 

torque activities. 

Hardened steel washers may be used in conjunction with joint bolting, since they allow more of the 

applied torque to be translated to bolt stress, which provides the preload necessary for a tightly 

sealed joint. In joints subject to thermal or process load cycling, Belleville washers may be used 

to provide better response to the changing conditions caused by cycling. 

Bolting threads and load bearing faces are lubricated with an approved thread lubricant 

immediately before assembly to allow the maximum torque to be translated to bolt stress. Leveling 

passes are performed using a calibrated torquing tool and continue until there is no rotational 

movement of the fasteners at the final torque value. 

For any joint considered at high risk for leakage, as demonstrated by past performance or 

suggested by the judgment of the responsible supervision, leveling passes may be repeated at the 

final torque value after 24 hours. This may be done to compensate for gasket relaxation (creep) 

before putting the joint into service. 

3.1.11.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the torque activities AMP

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to ensure that the applicable component aging effects will be managed so that system intended 

functions will be maintained consistent with the CLB for the period of extended operation. 

Program Scope 

The application stated that the plant commodity group in the scope for torque activities is Class 1 

pressure boundary bolting and Non-Class 1 pressure boundary bolting. Class 1 pressure boundary bolting is fabricated from low alloy steel. The non-Class 1 pressure boundary bolting is fabricated 

to the requirements of ASTM A-307 (Grade B), ASME SA-1 94 (Grade 2H), and ASME SA-1 93 

(Grade B7). Bolting that is heat treated to a high hardness condition and exposed to a humid 

environment within containment could be susceptible to SCC. In response to RAI 3.4-1, the applicant did not state if the yield strength for ASME SA-1 93 (Grade B7) or any other bolts are 

limited to less than 150 ksi to avoid the possibility of stress corrosion cracking. (See RICSIL No. 

055, February 1, 1991, "RPV Head Stud Cracking."). In Open Item 3.1.11-1, the staff requested that the applicant provide this information. By letter dated June 5, 2001, the applicant stated that 

these bolts were procured with a minimum yield strength of 105 ksi, with no upper limit stated. 

However, the applicant also stated that it has not experienced problems with these bolts and could 

not identify any problems during a survey of industry experience. On the basis that the applicant's operating experience has not shown that these bolts have experienced SCC, the staff finds the 

applicant's response adequate and considers Open Item 3.1.11 -1 closed. 

The systems where torque activities are applied that contain Class I pressure boundary bolting are: 

B21 - Nuclear Boiler 

B31 - Reactor Recirculation 

The systems where torque activities are applied that contain Non-Class 1 pressure boundary 

bolting are: 

B21 - Nuclear Boiler 

Cl I - Control Rod Drive 

El1 - Residual Heat Removal 

E21 - Core Spray 

E41 - High Pressure Coolant Injection 

E51 - Reactor Core Isolation Cooling 

N61 - Main Condenser 

P41 - Plant Service Water 

P42 - Reactor Building Closed Cooling Water 

P52 - Instrument Air 

P64 - Primary Containment Chill Water 

P70 - Drywell Pneumatic 

T23 - Primary Containment 

T41 - Reactor Building HVAC 

T48 - Primary Containment Purge and Inerting 

T49 - Post-LOCA Hydrogen Removal 

W33 - Traveling Water Screens, Trash Racks 

X41 - Outside Structures HVAC 

X43 - Fire Protection 

Y52- Fuel Oil

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Z41 - Control Room HVAC

The staff agrees that it is appropriate to include the systems listed above within the scope of torque 

activities. 

Preventive or Mitigative Actions 

The applicant states for both Class 1 and Non-Class 1 bolting, the torque activities are designed 

to mitigate age-related degradation by controlling preload within bolted connections. The staff 

agrees that torque activities are preventive actions and are appropriate for the systems listed. 

Parameters Inspected or Monitored 

The applicant states that the torque activities sufficiently mitigate loss of preload such that this 

attribute of aging management is not required. The staff agrees that this attribute is not needed. 

Detection of Aging Effects 

The applicant states that the torque activities sufficiently mitigate loss of preload such that this 

attribute of aging management is not required. The staff agrees that this attribute is not needed. 

Monitoring and Trending 

The applicant states that the torque activities sufficiently mitigate loss of preload such that this 

attribute of aging management is not required. The staff agrees that monitoring and trending is 

not required for torque activities. 

Acceptance Criteria 

The torque activities provide acceptance criteria for loss of preload by specifying torque values, bolt 

sequence, number of passes, and thread engagement. The staff agrees that the activities 

specified provide an adequate acceptance criteria. 

Operating Experience 

The application states that the corrective actions program provides for evaluation of aging effects 

and significant operating events, and requires that reasonable actions be taken to enhance 

programs and activities to prevent future occurrences. The staff finds this acceptable. 

3.1.11.4 Conclusions 

The staff has reviewed the information in LRA Sections A. 1.11, 'Torque Activities," C.2.1.1.6, and 

C.2.2.10, and Section B.1.11 of the applicant's October 10, 2000 submittal. On the basis of this 

review, the staff concludes that the applicant has demonstrated that the aging effects managed 

by the torque activities will be adequately managed so that there is reasonable assurance that the 

systems covered by this activity will perform their intended functions in accordance with the CLB 

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.12 Component Cyclic and Transient Limit Program

3.1.12.1 Introduction 

The applicant described its component cyclic and transient limit program (CCTLP) in LRA Sections 

A.1.12 and Section B.1.12. The staff reviewed these sections to determine whether the applicant 

has demonstrated that the effects of aging managed by the CCTLP will be adequately managed 

so that the systems covered by this program will perform their intended functions in accordance 

with the CLB during the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.12.2 Summary of Technical Information in the Application 

In LRA Section A.1.12 and Section B.1.12, the applicant described an existing aging management 

program, the component cyclic and transient limit program, that "is designed to track cyclic and 

transient occurrences to ensure that reactor coolant pressure boundary components and the torus 

will remain within ASME Code Section III fatigue limits, including the effects of a reactor water 

environment." The monitored locations include four limiting high-stress RPV boundary components 

on each unit, limiting locations for the torus on each unit, and eight locations within the Class 1 

boundary. These monitoring locations are discussed in greater detail in Section 4.2 of this SER. 

The program requires that the cumulative usage factor (CUF) for each limiting component for each 

unit be updated at least once per operating cycle. The program also requires that corrective 

actions be initiated if the CUF is projected to exceed the Code limit during the 60-year plant life. 

The applicant identified this AMP as the method it uses to manage the Class 1 fatigue analyses for the period of extended operation in accordance with 54.21 (c)(1)(iii). 

A criterion of CUF> 0.1 was also used as the basis for postulating pipe breaks at Plant Hatch. The 

applicant also identified this AMP as the method it uses to manage pipe break postulation based 

on CUF for the period of extended operation in accordance with 54.21 (c)(1)(iii). 

3.1.12.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the component cyclic and transient limit program to ensure that the reactor coolant pressure boundary components and 

the torus will remain within the acceptance criteria discussed above for the period of extended 

operation. 

Program Scope 

The scope of the program includes the RPV, the torus and all Class 1 piping. The program 

monitors locations of high fatigue usage determined by the applicant's review of the design 

calculations. The staff identified Open Item 4.1.3-1 in Section 4.1 of this SER regarding the scope of the applicant's fatigue TLAA evaluation. Specifically, the staff requested that the applicant 

explain how the fatigue analysis of the vessel internals was found to be acceptable for the 60-year 

period. The staff also requested that the applicant identify any other components of the reactor 

coolant pressure boundary that had fatigue analyses and explain how these analyses were found 

acceptable for the 60-year period. As discussed in Section 4.1 of this SER, the applicant 

performed an evaluation of the vessel internals to demonstrate that the allowable CUF will not be 

exceeded during the period of extended operation. Additionally, the applicant did not identify any

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other components of the reactor coolant pressure boundary with fatigue analysis. On the basis of 

the applicant's response to Open Item 4.1.3-1, the staff finds the scope of the CCTLP adequate 

to address fatigue reactor coolant pressure boundary components. 

As part of the resolution of Open Item 4.1.3-1, the applicant proposed to monitor three locations 

for comparison to the pipe break postulation criteria of CUF > 0.1. These are locations where pipe 

breaks were not postulated in the initial design, but locations where the pipe break postulation 

criterion could be exceeded during the period of extended operation. The staff finds the applicant's 

proposal to monitor sample bounding locations an adequate method to address pipe break 

postulation criterion based on fatigue usage. 

Preventive and Mitigative Actions 

There are no preventive or mitigative actions taken as part of this program, and the staff did not 

identify the need for such actions. 

Parameters Inspected or Monitored 

The monitored locations are discussed in Sections 4.1 and 4.2 of this SER. The staff finds that 

monitoring these selected high fatigue usage locations provides an acceptable method to monitor 

the fatigue usage associated with design transients for the RPV, torus, and Class 1 piping. 

Detection of Aging Effects 

The program monitors design transients used in the fatigue analysis of components and the 

information is used to update the fatigue calculation. The staff identified Open Item 4.2.3-1 in 

Section 4.2.3 of this SER regarding the applicant's evaluation of environmental fatigue concerns. 

Specifically, the staff disagreed with the applicant's determination that environmental fatigue 

concerns regarding the six locations identified in NUREG/CR-6260 have been adequately 

addressed at Plant Hatch. In response to Open Item 4.2.3-1, the applicant proposed to modify the 

program and apply overall multipliers on the CUFs that account for environmental effects at the six 

locations identified in NUREG/CR-6260. The staff finds that the aging effects will be adequately 

monitored by this modified program. 

Monitoring and Trending 

According to the applicant, the projected 60-year CUF is updated at least once per operating cycle. 

The applicant indicates that if the fatigue usage factor is projected to exceed the acceptance 

criteria, a condition report is initiated to determine, and take, appropriate corrective action. The 

applicant lists the following potential corrective actions: 

trend the 60-year CUF projection and verify that CUF will not exceed 1.0 during the current 

operating cycle 

refine the fatigue analysis and modify the monitoring formula 

use fracture mechanics analysis to determine a critical flaw size and establish an 

appropriate inspection schedule

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perform corrective maintenance

* replace the component 

The staff considers refinement of the fatigue analysis, repair, or replacement of the component acceptable corrective actions. The use of a fracture mechanics analysis for cases where the CUF 

is projected to exceed 1.0 would require staff review and approval on a case-by-case basis. 

Acceptance Criteria 

As stated above, the applicant's acceptance criteria is the condition that the CUF for the monitored 

locations not exceed 1.0. The applicant will also monitor potential pipe break postulation locations 

to assure that the CUF does not exceed 0.1. The staff considers this criteria acceptable. 

Operating Experience 

The applicant's program involves tracking transients at locations of high calculated fatigue usage 

to manage the fatigue TLAAs. The applicant indicated that it has modified its counting procedure 

to reflect operating experience, and has added additional monitoring points to the program. Thus, the staff concludes that the applicant considered operating experience in the program 

development. 

3.1.12.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.12, "Component Cyclic and Transient 

Limit Program," and Section B.1.12 of the applicant's October 10, 2000 submittal. The applicant references the component cyclic and transient limit program in its discussion of the fatigue TLAAs 

as a method to manage the fatigue usage of selected components. The staff identified open items 

regarding the applicant's TLAA evaluation in Sections 4.1 and 4.2 of this SER. The resolutions of 

those open items are also discussed in Sections 4.1 and 4.2 of this SER. The staff considers the 

applicant's program, which monitors the number of plant transients that were assumed in the fatigue design of selected high-fatigue-usage components, including pipe break postulation, to be an 

acceptable method to manage the fatigue usage of the RPV, torus structure, and RCS piping. 

The staff concludes that the component cyclic and transient limit program will adequately manage thermal fatigue of RCS components and torus structure components for the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.13 Plant Service Water and RHR Service Water Inspection Program 

3.1.13.1 Introduction 

The applicant described the PSW and RHRSW inspection program in LRA Section A.1.13. The 

applicant supplemented the description of this AMP in Section B.1.13 of its October 10, 2000 

submittal. The applicant credits this inspection program with managing, in part, aging effects for 

a variety of carbon steel, stainless steel, copper alloy, and gray cast iron components that are 

exposed to a raw water or buried environment. The staff reviewed these sections of the LRA to 

determine whether the applicant has demonstrated that the PSW and RHRSW inspection program

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will adequately manage aging effects during the period of extended operation as required by 10 

CFR 54.21 (a)(3). 

3.1.13.2 Summary of Technical Information in the Application 

In Sections A.3.1.13 and Section B.1.13 of the applicant's October 10, 2000 submittal, the applicant 

describes the PSW and RHRSW inspection program, that manages, in part, aging effects for 

various structures and components exposed to a raw water or buried environment. The affected 

systems include the RHR system, PSW system, and traveling water screens/trash racks system. 

The applicant lists the specific system structures and components in Tables 3.2.3-2, 3.2.4-7, and 

3.2.4-16 of the LRA. These structures and components are fabricated from either carbon steel, 

stainless steel, copper alloy, or gray cast iron. 

As discussed in Sections C.1.2.4 and C.1.2.10 of the LRA, loss of material is an applicable aging 

effect that may affect carbon steel, stainless steel, copper alloy, or gray cast iron components 

exposed to raw water or buried environments through several corrosion mechanisms, including 

general corrosion, galvanic corrosion, crevice corrosion, pitting, MIC, selective leaching, and erosion 

corrosion. The applicant also considered fouling to be an applicable aging effect. Fouling is not a 

material degradation phenomenon but may increase corrosion rates within raw water system 

components for a limited set of component geometries. Additionally, fouling may result in a loss of 

intended function (i.e., decreased flow or pressure) due to the buildup of material on raw water 

system component internal surfaces. Although the applicant also identified wear and cracking due 

to vibration fatigue as applicable aging mechanisms, these mechanisms are specific to the RHR 

heat exchanger which has its own AMP (the RHR heat exchanger augmented inspection and testing 

program), and thus are not addressed by the PSW and RHRSW inspection program. 

Plant Hatch has two sources of raw water, river and well water. River water from the Altamaha 

River is supplied and rough screened at the intake structure. The applicant assumes that some 

debris, silt, and macroorganisms may be introduced into the PSW and RHRSW systems. This is 

the type of raw water relevant to this inspection program. The applicant relies on a combination of 

AMPs to mitigate and detect aging effects for the various structures and components exposed to 

the river water environment. These complementary programs include the PSW and RHRSW 

chemistry control program, the PSW and RHRSW inspection program, galvanic susceptibility 

inspections, and the RHR heat exchanger augmented inspection and testing program. This section 

of the SER describes and evaluates the applicant's plant service water and RHR service water 

inspection program. 

3.1.13.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the PSW and RHRSW 

inspection program to ensure that the applicable component aging effects will be managed so that 

system intended functions will be maintained consistent with the CLB for the period of extended 

operation. 

Program Scope 

The applicant stated in Section B.1.13 of the applicant's October 10, 200 submittal, that the scope 

of this program included structures and components within the RHR system, RHRSW system, and

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traveling water screens/trash rack system, as specified in Tables 3.2.3-2, 3.2.4-7, and 3.2.4-16 of 

the LRA. The inspection scope consists of a representative sample of the most susceptible 

locations for corrosion or fouling. Locations susceptible to corrosion include infrequently used piping 

(stagnant water), submerged piping, piping with low fluid velocity, piping with high fluid velocity 

(erosion), small diameter piping, backing rings, socket welds, and heat affected zone of welds. 

Locations susceptible to fouling include those also susceptible to corrosion, horizontal runs of piping 

at the bottom of vertical runs, intermittently used piping, or low point drains. To address selective 

leaching, the applicant will include one PSW component fabricated from brass and one component 

fabricated from gray cast iron. 

In Section C.2.4.3 of the LRA, the applicant credits the PSW and RHRSW inspection program with 

managing the aging effects of RHR and PSW components exposed to a buried environment. The 

protective coatings program includes provisions for cleaning, priming, coating, and wrapping 

underground pipelines whenever underground sections of pipe are uncovered. Pipelines are 

wrapped with coal tar enamel wrapping. However, this aspect of the program is not discussed in 

Section A.1.13 of the LRA or Section B.1.13 of the applicant's October 10, 2000 submittal. The staff 

requested that the applicant enhance its description of the PSW and RHRSW inspection program 

to clearly state that the scope of the program includes this particular aspect for managing aging 

effects associated with a buried environment, consistent with the discussion in Section C.2.4.3 of 

the LRA. This was identified as part of Open Item 3.1.13-1 [3.1.13-1(a)]. 

The applicant responded to this open item by letter dated June 5, 2001. The applicant indicated that 

the PSW and RHRSW inspection program does not directly include provisions for cleaning, priming, 

coating and wrapping underground pipelines. The protective coatings program addresses these 

activities. However, the site procedure for buried pipelines coating maintenance does specifically 

invoke the program inspection requirements whenever maintenance is performed on the 

components in those systems. There is, therefore, certain linkage between these two programs and 

the applicant reflected it in the LRA. In order to clarify this issue, the applicant will modify the LRA. 

It will remove the PSW and RHRSW inspection program from Section C.2.4.3. In addition, the 

applicant will modify Section B.3.5 of the LRA by removing information related to the external 

surfaces of buried components. A special instruction has been placed in the site procedure used 

to manage excavation activities to assure that buried commodities are examined by protective 

coatings personnel. The staff finds that with these modifications introduced in the LRA, the scope 

of the PSW and RHRSW inspection program with regard to inspection of the underground pipelines 

is well defined. The staff considers Open Item 3.1.13-1 (a) closed. 

In Table 3.2.3-2 of the LRA, the RHR heat exchanger augmented inspection and testing program 

is credited with managing, in part, aging effects for various heat exchanger components, including 

the tubes, tubesheet, and shell. However, the staff noted that the description of the PSW and 

RHRSW inspection program contained in Section B.1.13 of the applicant's October 10, 2000 

submittal included several references to inspections of heat exchanger components. The staff 

requested that the applicant clarify the scope of the PSW and RHRSW inspection program relative 

to managing aging effects for the various heat exchanger components listed in Table 3.2.3-2 of the 

LRA. This was identified as part of Open Item 3.1.13-1 (Open Item 3.1.13-1 (b)). 

The applicant responded to this open item by letter dated June 5, 2001. The applicant stated that 

managing aging effects for various heat exchanger components, including the tubes, tubesheet, and 

shell in the RHR system is performed by the RHR heat exchanger augmented inspection and testing 

program. As indicated in Section C.2.2.11 of the LRA, the PSW and RHRSW inspection program

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plays only a subordinate role, limited to visual inspection of the surfaces of the heat exchanger 

channel and shell sides. The reason that inspection of the heat exchanger components is 

referenced in Section B.1.13 of the LRA is to show the linkage that exists between these two 

programs. On the basis of this information, the staff concludes that the applicant has clarified the 

scope of the PSW and RHRSW inspection program regarding management of aging effects in the 

RHR heat exchanger. The staff considers Open Item 3.1.13-1 (b) closed. 

The staff conducted a scoping inspection in the offices of SNC from September 11, 2000 through 

September 15, 2000. The results of the inspection are documented in Inspection Report 50

321/00-09,50-366/00-09. During the inspection, the inspectors identified a guard pipe associated 

with Division I PSW piping in the diesel generator building. This guard pipe had not been 

considered for scoping and screening in the LRA. In response to this inspection finding, the 

applicant evaluated the guard pipe and concluded that it did not perform an intended function, and 

therefore was not within the scope of license renewal. The staff agreed with this conclusion. The 

staff's review of the applicant's evaluation of the guard pipe can be found in Section 2.3.4 of this 

SER. The internal surface of the PSW piping is exposed to raw water, and thus the aging effects 

and AMPs are consistent with other piping sections in this system. However, the length of the PSW 

piping surrounded by the guard pipe is sealed, that is, a plate is welded to the PSW pipe and to the 

guard pipe at both ends. Thus, the external surface of this section of PSW piping is not accessible 

for inspection. The applicant plans to perform a one-time inspection to assess the material condition 

of the external surfaces of this piping section. The staff requested that the applicant provide 

appropriate information about this one-time inspection, or a comparable engineering evaluation, 

prior to the end of the current term. This was identified as part of Open Item 3.1.13-1 (3.1.13-1 (c)). 

The applicant responded to this open item by letter dated June 5, 2001. The applicant provided 

additional information related to the one-time inspection of that portion of the PSW piping that is 

surrounded by a guard pipe. The applicant states that Plant Hatch Engineering Support is 

responsible for determining the suitable method or methods for conducting an inspection. Plans 

have been made to inspect the portion of the external surface of the PSW piping that is surrounded 

by the guard pipe during the 1 B EDG outage scheduled for February 2002. Currently, the plan is 

to cut a window in the guard pipe for a visual, boroscope, or other suitable examination to determine 

the condition of the external surface of the PSW pipe. The results will be documented and 

evaluated, with additional actions taken if needed. The staff has reviewed the information discussed 

in the applicant's open item response and, on the basis of this information, concludes that the 

approach for determining the current state of the guarded extemal surface of the PSW piping is 

appropriate and acceptable. Open Item 3.1.13-1(c) is closed. 

The staff finds that the scope of the PSW and RHRSW inspection program is acceptable because 

it includes all the components in the RHR system, PSW system, and traveling water screens/trash 

rack system that are exposed to a raw water environment. In addition, the inspection scope includes 

a representative inspection sample set that is conservatively biased to those locations considered 

to be most susceptible to corrosion or fouling. 

Preventive or Mitigative Actions 

One aspect of the PSW and RHRSW inspection program is mitigative in nature. The program 

requires the regular, periodic visual inspections of the intake structure pump suction pit. Any 

accumulations of biological fouling organisms, sediment, or corrosion products found during the

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inspection will be removed to prevent their entry into the system. The staff agrees this action will 

help to mitigative the impact such accumulations have on corrosion and fouling. 

Parameters Monitored or Inspected 

The applicant applies qualified inspection techniques, including visual and volumetric (radiographic 

and ultrasonic) inspections of structures and components to detect corrosion-related aging effects. 

The applicant also performs flow testing and visual or volumetric inspections to detect fouling. 

Lastly, the applicant will perform hardness testing or a metallurgical analysis on brass or gray cast 

iron components to detect selective leaching. The staff finds the inspections and flow rate and 

hardness testing/metallurgical analysis to be acceptable because the methods are consistent with 

current industry practice and found to be effective in detecting these aging effects. 

Detection of Aging Effects 

To ensure that aging effects are identified before there is a loss of intended function, the staff relies 

on an adequate program scope, appropriate monitoring of parameters, and appropriate frequency 

interval. The program scope and parameter monitoring are discussed above. With respect to 

frequency, the applicant stated that the visual inspection of the intake structure pump suction pit is 

performed every twelve months. The hardness testing of the brass or gray cast iron components will be a one-time inspection, unless results indicate a need for future or expanded inspections. 

Inspection frequencies for all other structures and components within the scope of this program are 

based on past inspection results, to ensure that minimum wall thickness values or flow areas are 

not reduced to unacceptable levels. The staff finds this approach of basing inspection frequency 

on inspection results to be reasonable and therefore acceptable. 

Monitoring and Trending 

As discussed above, the applicant stated that inspection results are trended to determine the scope and frequency of subsequent inspections. This approach is reasonable and consistent with industry 

practice and staff expectations and therefore, is acceptable to the staff. 

Acceptance Criteria 

For wall loss evaluations, minimum wall thickness is calculated in accordance with the piping design 

code, piping stress requirements, and piping specification drawings. Flow rate testing for the 

evaluation of pipe blockage is based upon functional performance requirements for a particular 

component under normal and accident conditions. Hardness testing is based on the component's 

material specifications (e.g., ASME, ASTM, etc.). These criteria are reasonable and consistent with 

industry practice and staff expectations and therefore, are acceptable to the staff. 

Operating Experience 

The applicant stated that review of Plant Hatch operating experience over the past 5 years has 

indicated some aging-related problems in the PSW and RHRSW systems. The problems consisted 

of loss of material, cracking, and loss of heat exchanger performance. The applicant addresses 

these deficiencies through its corrective actions program. The applicant stated that significant 

improvements have been made to the plant service water and RHR service water inspection 

program. For example, the frequency of inspections has been increased and additional non3-44
destructive examinations introduced. In some cases replacement components were made of 

improved materials. The staff concludes that the applicant has appropriately incorporated operating 

experience into the PSW and RHRSW inspection program. In addition, the applicant in its January 

31, 2001 letter discusses hardness testing for selective leaching of gray cast iron and brass 

components and in LRA Section B.2.3 discusses operating experience relative to corrosion of buried 

piping. The staff finds that this operating experience supports the attributes of this program specific 

to selective leaching and buried piping. 

3.1.13.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.13 and Section B.1.13 of the applicant's 

October 10, 2000 submittal. On the basis of this review, pending completion of the license 

condition, the staff concludes that the applicant has demonstrated that the PSW and RHRSW 

inspection program will adequately manage, in conjunction with other AMPs, aging effects 

associated with the raw water or buried environment for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

3.1.14 Primary Containment Leakage Rate Testing Program 

3.1.14.1 Introduction 

The applicant described its primary containment leakage rate testing program in LRA 

Section A.1.14. The applicant supplemented the description of this AMP in Section B.1.14 of its 

October 10, 2000 submittal. The applicant credits this inspection program with ensuring the 

structural integrity of primary containment through visual inspection and performance testing 

activities. Loss of material is the aging effect monitored by this program. The staff reviewed the 

application to determine whether the applicant has demonstrated that the primary containment 

leakage rate testing program will adequately manage aging effects during the period of extended 

operation as required by 10 CFR 54.21 (a)(3). 

3.1.14.2 Summary of Technical Information in the Application 

In LRA Section A.1.14 and Section B.1.14 its October 10, 2000 submittal, the applicant describes 

an existing aging management program, the primary containment leakage rate testing program, that 

ensures the structural integrity of primary containment. The program applies to steel primary 

containments, containment penetrations, and containment internal structures that perform a 

structural or pressure retaining function. It also includes the steel and nonferrous components of 

the containment airlocks, equipment hatches, and control rod drive removal hatches. The applicant 

lists the specific system, structures, and components in LRA Section 3.3. 

3.1.14.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the primary containment 

leakage rate testing program to ensure that the applicable component aging effects will be managed 

so that system intended functions will be maintained consistent with the CLB for the period of 

extended operation.

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Program Scope

In LRA Section A.1.14, the applicant states that the primary containment leakage rate testing 

program complies with all 10 CFR Part 50 Appendix J, Option B leakage rate testing requirements for systems, structures, and components within the scope of license renewal. The applicant also 

states that the primary containment leakage rate testing program involves Type A, B, and C 

pressure testing and that a general visual inspection of the accessible interior and exterior surfaces 

of the drywell and torus are performed before conducting a Type A test. Given the staff's review 

of the above information, staff RAI 3.6-1 asked the applicant to provide a discussion of the key elements of the primary containment leakage rate testing program and specifically describe the 

implementation of regulatory positions Cl through C4 of Regulatory Guide 1.163, "Performance

Based Containment Leak-Test Program." The RAI also asked the applicant to provide the bases 

for any exceptions to these regulatory positions. 

In response to RAI 3.6-1, the applicant stated that the program provides for the implementation of 

all 10 CFR Part 50 Appendix J, Option B leakage rate testing requirements, as required by the Unit 

1 and Unit 2 Technical Specifications. The applicant further stated that the program was developed through the use of 10 CFR Part 50, Appendix J, Option B, Regulatory Guide 1.163, NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," July 26, 1995, and ANSI/ANS 56.8-1994, "American National Standard for Containment System Leakage Testing Requirements." The applicant stated that no exceptions are taken to regulatory positions C.1 through C.4 of RG 1.163. This response is acceptable, and RAI 3.6-1 is closed. 

The staff finds that the scope of the program, as described above, is acceptable since it includes 

Type A, B, and C pressure testing and performance of a general visual inspection of the accessible 

interior and exterior surfaces of the drywell and torus, which are shown to be a reliable means of 

ensuring containment functions on the basis of past Plant Hatch operating experience. 

Preventive and Mitigative Actions 

There are no preventive or mitigative actions taken as part of this program, and the staff did not 

identify the need for such actions. 

Parameters Inspected or Monitored 

Among the parameters monitored during the testing and visual inspection are containment pressure, compartment/penetration pressures, overall containment leak rate, localized 

penetration/compartment closure leak rates, extent of loss of material of inspected surfaces, and 

localized general degradation of components or coatings. 

With respect to the third paragraph of Section A.1.14.1, "Description," on page A.1-17 of the LRA, 

the applicant stated that "Type A tests are performed in accordance with ANSI/ANS 56.8-1994 

and/or Bechtel Topical Report BN-TOP-1 "Testing Criteria for Integrated Leakage Rate Testing of 

Primary Containment Structures for Nuclear Power Plants," November 1972, 

and implemented through plant procedures." In RAI 3.6-2, the staff requested that the applicant explain the extent to which Plant Hatch intends to adopt the provisions of the referenced ANSI/ANS 

standard/report in its implementation of the Type A test program. The applicant was also requested 

to clarify if the provisions that were adopted from the Bechtel Topical Report BN-TOP-1 are either 

equivalent to or more stringent than those corresponding provisions of ANSI/ANS 56.8-1994. If not,

3-46
the applicant was requested to list those BN-TOP-1 provisions that are less stringent than those of 

ANSI/ANS 56.8-1994 and reconcile the differences. 

The applicant responded that presently Type A integrated leak rate tests (ILRTs) are performed in 

accordance with Bechtel Topical Report BN-TOP-1. The next ILRT is scheduled to be performed 

during the Unit 1 spring 2002 outage. Plans are to conduct the ILRT in accordance with BN-TOP-1. 

The Plant Hatch Unit 1 UFSAR, Section 5.2.5.1, states that "the containment leak test program is 

performed in the manner described in BN-TOP-1 or ANSI/ANS-56.8-1994." The applicant also 

stated that Regulatory Guide 1.163 endorses NEI 94-01, which states in Section 1.1, "Generally, 

an FSAR describes plant testing requirements, including containment testing. In some cases, 

UFSAR testing requirements differ from those of Appendix J. The alternate performance-based 

testing requirements contained in Option B of Appendix J will not invalidate such exemptions." The 

applicant also stated that no formal comparison of ANSI/ANS 56.8-1994 with BN-TOP-1 has been 

performed at this time. The staff finds this applicant's response adequate and reasonable and 

considers RAI 3.6-2 closed. 

Detection of Aging Effects 

Test and inspection frequencies are determined in accordance with plant procedures. An as-found 

Type B or C test is performed before any maintenance, repair, modification, or adjustment activities 

that could affect the primary containment boundary's leak-tightness. Since the primary containment 

leakage rate testing program cannot detect loss of material or cracking before the pressure 

boundary is compromised, this testing program is used in conjunction with other programs, such as 

the protective coatings program and the inservice inspection program, to manage the aging effects 

of the primary containment components and drywell penetrations. The staff finds that the 

applicant's operating experience to date supports the continuation of these test and inspection 

frequencies and they will provide reasonable assurance that loss of material, as well as loss of 

containment leak tightness will be detected before there is a loss of intended function. 

Monitoring and Trending 

The applicant indicated that the results of tests and inspections are documented in accordance with 

procedural requirements. In addition, the corrective actions program is used to monitor the 

deficiencies found and to implement timely corrective actions. The staff finds that these monitoring 

activities are adequate to ensure that corrective actions will be taken before exceeding the 

acceptance criteria. 

Acceptance Criteria 

The applicant stated that criteria are defined for establishing Type A, B, and C test frequencies and 

administrative leakage limits, on the basis of performance. Type A tests are performed in 

accordance with ANSI/ANS 56.8-1994 and/or Bechtel Topical Report BN-TOP-1 to demonstrate the 

integrity of the primary containment pressure vessel. Type A, B, and C test intervals are established 

in accordance with Regulatory Guide 1.163. Type B and C tests are performed in accordance with 

ANSI/ANS 56.8-1994, to demonstrate the integrity of individual penetrations and components, with 

NRC-approved Technical Specification amendments and exemptions. The acceptance criteria for 

visual inspection are no visual detection of loss of material or cracking. The staff finds that the 

acceptance criteria specified above are adequate to ensure that the containment intended functions 

are maintained under all CLB design conditions during the period of extended operation.

*3-47
Operating Experience

The primary containment leak rate testing program is an existing program. In LRA Section C.2.6.2 

the applicant stated that several instances of age related degradation of the containment as a result 

of minor corrosion were found to date but there were no containment functional failures. These 

deficiencies were discovered during required visual inspections and pressure testing. The corrective 

actions program was utilized to correct/repair these deficiencies. The staff finds that the applicant's 

operating experience has demonstrated that the program has effectively maintained the containment 

integrity and functionality, and the effects of containment aging will be adequately managed so that 

intended functions will be maintained during the period of extended operation. 

3.1.14.4 Conclusions 

The staff has reviewed the information in LRA Sections A.1.14 "Primary Containment Leakage Rate 

Testing Program," and Section B.1.14 of the applicant's October 10, 2000 submittal. On the basis 

of this review, the staff concludes that the applicant has demonstrated that the aging effects 

managed by the primary containment leakage rate testing program will be adequately managed so 

that there is reasonable assurance that the structures covered by this inspection program will 

perform their intended functions in accordance with the CLB during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.15 Boiling Water Reactor Vessel and Internals (BWRVIP) Program 

3.1.15.1 Introduction 

The applicant described its BWRVIP inspection program in Section A.1.15 of LRA, and 

supplemented the description of this AMP in Section B.1.15 of its October 10, 2000, submittal. The 

applicant credits this program with verifying the structural integrity of the RPV internal components 

to ensure the continued integrity of the load bearing and operating components. The staff reviewed 

the application to determine whether the applicant has demonstrated that the BWRVIP inspection 

program will adequately manage aging effects during the period of extended operation, as required 

by 10 CFR 54.21 (a)(3). 

3.1.15.2 Summary of Technical Information in the Application 

In LRA Section A.1.15 and Section B.1.15 its October 10, 2000, submittal, the applicant describes 

an existing generic aging management program, the Boiling Water Reactor Vessel and Internals 

program (BWRVIP), which references the following nine BWRVIP inspection and evaluation (I&E) 

reports for internals components (these reports apply to both the current term and the extended 

period of operation): 

Reactor Assembly BWRVIP Document Applicability 

Component Reference 

Core Spray Piping and Sparger BWRVIP-18 

Top Guide BWRVIP-26 

Standby Liquid Control System/Core Plate dP BWRVIP-27

3-4&
Shroud Support BWRVIP-38 

Jet Pump Assemblies BWRVIP-41 

Control Rod Guide Tube BWRVIP-47 

Vessel ID Attachment Weld BWRVIP-48 

Reactor Pressure Vessel BWRVIP-74 

Shroud (including repair hardware) BWRVIP-76 

These nine BWRVIP reports together constitute the BWRVIP AMP. With regard to license renewal, 

these I&E reports specifically address the subject internals systems and components relative to the 

requirements of 10 CFR Part 54. The staff's SERs on the BWRVIP I&E reports established the 

adequacy of the generic BWRVIP reports for renewal by concluding that the license renewal rule 

provisions have been satisfied, including the identification and assessment of aging effects, the 

evaluation of the adequacy of the BWRVIP programs with regard to managing the aging effects, 

and the demonstration that these programs will ensure the functionality of internals during the period 

of extended operation. 

The applicant has evaluated the BWRVIP program for its applicability to the Plant Hatch Units 1 and 

2 design, construction, and operating experience, stating that the RPV internals, including the 

materials of construction, are addressed by the BWRVIP program I&E reports and that the plant 

operating parameters, including temperature, pressure, and water chemistry, are consistent with 

those used for the development of the I&E reports. The applicant has determined that the 

components which require aging management review, in accordance with the license renewal rule, 

are covered bythe referenced BWRVIP program reports, and that the referenced BWRVIP program 

reports cover all Plant Hatch internals design. 

The BWRVIP program provides for periodic inspections to monitor the condition of each internal 

BWR component that could impact safety, enabling degradation to be detected before the 

component's function is adversely affected. The applicant stated that the RPV internals requiring 

aging management within the scope of license renewal are the shroud, shroud supports, core spray 

piping and spargers, control rod guide tubes, jet pump assemblies, control rod drive housings, and 

dry tubes. Initially, only the Unit 1 top guide was included within the scope of the AMP. In response 

to RAI 3.1.15-2, the applicant stated that, given the original design conditions, Unit 2 was shown to 

not require inspection and, thus, was not referenced in the LRA. However, subsequent to submitting 

the application, the applicant determined that, because of extended power up-rate, the Unit 2 top 

guide must also be included. All of the above listed components are included as part of the reactor 

assembly system. 

The reactor internals are examined using a combination of ultrasonic, visual, and surface methods. 

The methods to be used and the frequency of examination will be as specified in the applicable 

BWRVIP inspection and evaluation document, unless specific exception has been identified and 

approved by the staff. Therefore, the applicant has established that the BWRVIP program reports 

bound the Plant Hatch Units 1 and 2 design and operation. 

3.1.15.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration that the BWRVIP will 

adequately manage the applicable component aging effects so that system intended functions will 

be maintained consistent with the CLB for the period of extended operation.

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The staff evaluated the nine BWRVIP reports that constitute the BWRVIP AMP against the ten 

aging management program criteria below. 

Program Scope 

In Section B.1.15 of its October 10, 2000, submittal, the applicant stated that the reactor vessel 

internals requiring aging management within the scope of the Plant Hatch implementation of the 

BWRVIP are the shroud and associated shroud repair hardware, shroud supports, core spray piping 

and spargers, control rod guide tubes, jet pump assemblies, control rod drive housings, and dry tubes. In the original application, only the Unit 1 top guide was included. Subsequent to submitting 

the application, the applicant determined that, because of extended power up-rate, the Unit 2 top 

guide must also be included. All of the above listed components are included as part of the reactor 

assembly system. 

The staff finds that the applicant has adequately identified all of the components that are within the 

program scope. 

Preventive or Mitigative Actions 

The BWRVIP program is a condition monitoring program which utilizes enhanced visual inspections, 

as well as volumetric and surface examinations, to detect IGSCC, IASCC, and fatigue within reactor 

vessel internals such that proper evaluations and corrective actions may be accomplished. Early 

detection and subsequent evaluation and corrective actions are considered adequate to mitigate 

degradation of reactor assembly internals before component function is adversely affected. 

The staff finds that the BWRVIP program, as used at Plant Hatch, will be adequate to monitor plant 

conditions to identify conditions adverse to quality in a timely manner. 

Parameters Inspected or Monitored 

The BWRVIP program reviewed the function of each internal BWR component. For those internals 

that could impact safety, the BWRVIP program considered the mechanisms that might cause 

degradation of the internal components and developed an inspection program that would enable 

degradation to be detected and evaluated before the component function was adversely affected. 

Details regarding inspection and evaluation are contained within the component-specific BWRVIP 

inspection and evaluation documents. The staff finds that the applicant has appropriately 

characterized how the BWRVIP will inspect and monitor components at Plant Hatch to identify and 

evaluate aging effects. 

Detection of Aging Effects 

The reactor internals are examined using a combination of ultrasonic, visual, and surface methods. 

The methods to be used and the frequency of examination will be as specified in the applicable I&E 

report. 

The staff finds the detection methods, as specified, are appropriate to identify and evaluate age

related degradation in internals.

3-50
Monitoring and Trending

Monitoring of the detrimental effects of aging within reactor assembly components are specified 

within the BWRVIP I&E reports. The frequency of examination specified within applicable BWRVIP 

I&E reports varies for each component or subassembly. The frequency is founded on the 

component's design, flaw tolerance, susceptibility to degradation, and the method of examination 

used. In cases where a component may be inspected using either visual or ultrasonic methods, the 

interval between examinations is shorter when visual methods are used. The Plant Hatch corrective 

actions program provides for trending of significant indications noted during BWRVIP inspections. 

The staff finds the applicant's approach to monitoring and trending aging in components within the 

scope of the BWRVIP reports appropriate. 

Acceptance Criteria 

BWRVIP I&E reports provide the basis for Plant Hatch reactor vessel internals inspection 

requirements, acceptance criteria, and proper corrective actions. The applicant has incorporated 

these applicable I&E reports into the Plant Hatch license renewal application by specific reference. 

The staff finds that the acceptance criteria, as provided in the referenced BWRVIP reports, are 

acceptable. 

Operating Experience 

The applicant states that the operating experience for the Plant Hatch internals was reviewed. Over 

time there have been several occurrences of cracking, all of which have been repaired or are 

currently being monitored in accordance with prescribed procedures and programs. Early in life, 

IGSCC was detected on the Unit 1 core spray sparger. It was repaired by installation of a 

mechanical clamp. The sparger has been full-flow tested and the clamp examined afterwards with 

no evidence of degradation. Multiple indications have been detected over the years on the non

safety-related steam dryers. Some have been repaired while others are monitored. Jet pump 

inspections have resulted in minor indications associated with setscrew gaps, diffuser-to-adapter 

welds, riser pipe welds, and tack welds. These are being monitored and reexamined in accordance 

with the provisions of the BWRVIP. Crack-like indications were also detected in the core shrouds 

for both units. The applicant conservatively decided to make pre-emptive repairs to eliminate the 

concern of cracking in shroud circumferential welds. The repair hardware and vertical welds are 

periodically examined as specified in the BWRVIP. 

The applicant has evaluated the BWRVIP AMP for its applicability to the Plant Hatch Units 1 and 

2 design, construction and operating experience, including the applicant action items associated with 

the BWRVIP reports as well as any exceptions to the action items, and has established that the 

BWRVIP reports bound the Plant Hatch Units 1 and 2 design. The RPV components, including the 

materials used for construction, are addressed by the BWRVIP inspection and evaluation 

documents. The plant operating parameters, including temperature, pressure, and water chemistry, 

are consistent with those used for the development of the inspection and evaluation documents. The 

staff has reviewed the applicant's evaluation and finds it acceptable.

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In summary, the staff concludes that the applicant has determined the following: 

The components which require aging management review in accordance with the rule, are 

covered by the BWRVIP reports. 

The BWRVIP reports cover all Plant Hatch RPV and internals designs. 

Plant Hatch has met the provisions of the referenced BWRVIP reports, including the 

associated applicant action items, or has adequately addressed any exceptions to the 

applicant action items. 

3.1.15.4 Conclusions 

The staff has reviewed the information in LRA Section A.1.15, "Boiling Water Reactor Vessel and 

Internals Program," and Section B.1.15 of the applicant's October 10, 2000 submittal, including the 

bases for the applicant's determination that Plant Hatch meets the provisions of the referenced 

BWRVIP reports, including the applicant action items, or exceptions thereto, and concludes that 

implementation of the referenced BWRVIP reports, including the associated applicant action items, 

and staff-approved exceptions, provides reasonable assurance that the aging effects associated 

with the components within the scope of the referenced reports will be adequately managed during 

the period of extended operation to ensure the continued performance of their intended functions 

during the period of extended operation. On the basis of this review, the staff concludes that the 

applicant meets the requirements of 10 CFR 54.21 (a)(3). 

3.1.16 Wetted Cable Activities 

3.1.16.1 Introduction 

The applicant described its wetted cable activities in LRA Section A. 1.16 and Section B. 1.16 of the 

applicant's October 10, 2000 submittal. The staff reviewed these sections of the LRA to determine 

whether the applicant has demonstrated that the effects of aging on structures and components in 

systems managed by the wetted cables activities will be adequately managed so that intended 

functions will be maintained, consistent with the current licensing basis, for the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.16.2 Summary of Technical Information in the Application 

In LRA Section A.1.16 and Section B.1.16 of the applicant's October 10, 2000 submittal, the 

applicant describes an existing AMP, wetted cables activities, that provides for mitigating activities 

as well as condition monitoring activities associated with cables exposed to a wetted environment. 

Plant Hatch wetted cable activities include monitoring for and removing water, along with testing to 

detect changes in insulation resistance. Several 4kV power cables and transformer feeder cables 

within the scope of license renewal are routed through the underground duct bank system consisting 

of outdoor pull boxes containing underground conduits routed between in-scope buildings. Change 

in insulation resistance is the aging effect mitigated and monitored by the wetted cables activities. 

The affected systems include RHR, RHRSW, core spray, and PSW.

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3.1.16.3 Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the wetted cable activities 

program to ensure that the applicable component aging effects will be managed so that system intended functions will be maintained consistent with the CLB for the period of extended operation. 

Water level is measured, recorded, and the pull boxes drained, where these in-scope 4-kV power and transformer cables are routed. Megger and polarization index testing are periodically performed. When new terminations are made, the cables are hipot tested to provide additional 

assurance that the cable insulation integrity is sound. In addition, the pull boxes are drained 

quarterly and testing is performed on in-scope 4-kV motor windings and the associated feeder 

cables during regular motor and pump maintenance tasks. 

The wetted cable activities meet the intent of IEEE 43-1974, "Recommended Practice for Testing Insulation Resistance of Rotating Machinery"; and IEEE 95-1977, "Recommended Practice for 

Insulation Testing of Large AC Rotating Machinery with High Direct Voltage." Pull boxes found to 

contain water are drained to 1 inch of water or less. Cables and loads must successfully pass 

megger and polarization index testing. Corrective actions are taken if testing results are 

unacceptable. Plant-specific operating experience did not identify any in-scope age-related cables 

failures attributable to moisture intrusion. 

The staff finds that the Plant Hatch wetted cable activities manage the effects of cable aging attributable to moisture intrusion so that the intended functions will be maintained consistent with 

the CLB for the period of extended operation. 

3.1.16.4 Conclusions 

The staff has reviewed the information in LRA Sections A.1.16, 'Wetted Cable Activities," and 

Section B.1.16 fo the applicant's October 10, 2000 submittal. On the basis of its review, the staff 

concludes that the applicant has demonstrated that the effects of aging associated with structures 

and components in systems managed by wetted cable activities will be adequately managed so that 

intended functions will be maintained, consistent with the current licensing basis, for the period of 

extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.17 Reactor Pressure Vessel (RPV) Monitoring Program 

3.1.17.1 Introduction 

The applicant described its RPV monitoring program in Section A.1.17 of the LRA, and in Section 

B.1.17 of the applicant's October 10, 2000 submittal. The program consists of a combination of 

fatigue monitoring, code-required and augmented inspections, and surveillance material testing. The staff has reviewed these sections of the LRA to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed by the RPV monitoring program 

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.17.2 Summary of Technical Information in the Application

The RPV Monitoring Program is an existing condition monitoring and surveillance program at Plant 

Hatch. It is based on detailed evaluation of the Plant Hatch Unit 1 and 2 RPVs. The program is 

supported by an industry topical report for the license renewal period, BWRVIP-74. 

The RPV Monitoring Program covers the reactor vessel beltline shells, feedwater nozzles, core 

spray nozzles, control rod drive return line nozzle, recirculation inlet and outlet nozzles, jet pump 

instrumentation nozzles, and penetration seals. The core dP and standby liquid control nozzle, the 

support skirt and closure studs, the core spray pipe, jet pump riser brace pad, and shroud support 

welds are also included. 

RPV monitoring is accomplished through a combination of fatigue monitoring, code-required and 

augmented inspections, pressure tests, and surveillance material testing. RPV shell and head aging 

management is accomplished by performing ultrasonic examinations of the RPV vertical shell welds, 

periodic pressure tests with visual examination for leakage, and surveillance capsule testing. Plant 

Hatch uses an NRC-approved technical alternative in lieu of ultrasonic testing of circumferential shell 

welds. The basis for the alternative is contained in the BWR reactor pressure vessel shell weld 

inspection recommendations, and associated supplements. 

3.1.17.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration that the RPV monitoring 

program ensures that the applicable component aging effects will be managed so that system intended functions will be maintained consistent with the CLB for the period of extended operation. 

In LRA Section B.1.17 of the October 10, 2000 submittal, the applicant describes the RPV 

monitoring program for Plant Hatch. The RPV monitoring program employs the programs 

documented in the following topical reports: 

BWRVIP-27, "BWR Standby Liquid Control/Core AP Inspection and Flaw Evaluation Guidelines" 

BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines" 

BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines" 

BWRVIP-48, 'Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines" 

BWRVIP-74, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines" 

The staff's evaluation of these RPV-specific reports, and the other BWRVIP reports referenced by 

the applicant, are found in Section 3.1.15 of this SER. 

LRA Section B.1.17 of the applicant's October 10, 2000 submittal discusses the elements of the 

RPV monitoring program. The elements discussed are program scope, preventive or mitigation 

actions, parameters inspected or monitored, method of detecting aging effects, monitoring and 

trending, and acceptance criteria. The scope of the program includes all components in the reactor 

assembly system. The description of the other elements of the program consists of a general

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discussion of the inspections, monitoring, surveillance, and analyses that are documented in the 

BWRVIP topical reports. These topical reports have been reviewed by the staff in Section 3.1.15 

of this SER and form the basis for the staff's review of the RPV monitoring program. 

Fatigue Monitoring 

The staff evaluation of fatigue monitoring is discussed in Sections 3.1.12, "Component Cyclic or 

Transient Limit Program" and 4.2, "Pipe Stress" of this SER. 

Code-Required and Augmented Inspection and Pressure Tests 

The staff evaluation of the Inservice Inspection Program is discussed in Section 3.1.9 of this SER. 

Surveillance Material Testing 

To evaluate whether the reactor vessel surveillance program will provide sufficient data for 

monitoring the amount of embrittlement during the license renewal term, the staff evaluates whether 

the surveillance program satisfies the following attributes: 

"If the ISP is not approved by the staff, and if, instead, a plant-specific surveillance material 

testing program is implemented, capsules must be removed periodically to determine the 

rate of embrittlement. Capsules must be removed at neutron fluence levels which provide relevant data for assessing the integrity of the Plant Hatch 1 and 2 RPVs; in particular, for 

the determination of RPV pressure-temperature limits through the period of extended 

operation. Capsules must contain material to monitor the impact of irradiation on the Plant 

Hatch RPVs and must contain dosimetry to monitor neutron fluence. If the applicant is not 

participating in an ISP and available capsules are not being removed from Plant Hatch 

during the license renewal period, the applicant must submit for staff review the technical 

basis for continued operation (including proposed operating restrictions, such as inlet 

temperature, neutron spectrum, and flux, ex-vessel dosimetry for monitoring neutron 

fluence, etc.)" 

In response to RAI 3.1.17-1, the applicant indicated that it plans to implement the provisions of an 

integrated surveillance program (ISP) that is documented in BWRVIP-78, "BWR Vessel and 

Internals Project; BWR Integrated Surveillance Program Plan," and it's companion document, 

BWRVIP-86, "BWR Vessel and Internals Project, BWR Integrated Surveillance Program 

Implementation Plan." 

In a telephone conference on November 3, 2000, the applicant clarified its commitment to participate in an ISP through the end of Plant Hatch's period of extended operation, or, if necessary, to develop 

a plant-specific RPV surveillance materials testing program for the period of extended operation. As part of this commitment, the staff noted that if the applicant participates in a NRC staff-approved 

ISP or implements a staff-approved plant specific RPV surveillance program, the ISP or 

plant-specific program should address the requirements of 10 CFR Part 54, including the ten aging 

management program attributes in the SRP-LR. Further, if the proposed program cannot meet any 

program attributes, the applicant should provide a technical justification for the discrepancies. This 

was identified as Open Item 3.1.17-1.

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In response to the open item, by letter dated June 5, 2001, the applicant officially committed to 

implementing a staff-approved ISP for the extended period of operation based on the technical 

criteria of BWRVIP-78 and BWRVIP-86. The applicant further stated that, if an ISP is not approved by the NRC, or if the staff-approved ISP is not adequate for implementation at Plant Hatch, then the 

applicant will develop and implement a plant-specific surveillance material testing program for the 

extended period of operation. The applicant further stated that the plant-specific surveillance 

material testing program, if one is needed, will be developed in a manner consistent with other aging 

management programs, will include consideration of the ten program attributes utilized for other 

aging management programs, and will provide a technical justification for any program attribute not 

covered by the plant-specific surveillance material testing program. 

The staff's review of BWRVIP-78 is continuing; however, all significant issues necessary for 

approval of BWRVIP-78 have been addressed. The proposed ISP addressed by BWRVIP-78 and 

BWRVIP-86, only applies to the period of the current operating licenses. The BWRVIP has 

committed to provide supplemental information to extend the ISP through the period of extended 

operation, based on the same technical criteria as found in BWRVIP-78 and BWRVIP-86, for the 

BWR fleet. The staff expects this supplemental information to be submitted in 2002. 

Although the BWRVIP-78 and -86 reports apply only to the current term, the staff finds that the 

provisions in these reports, if implemented during the extended period of operation, constitute 

sufficient actions to manage the aging effects associated with the reactor vessel during the renewal 

term. 

With regard to the plant-specific surveillance materials testing program, in a telephone conference 

on October 5, 2001, the applicant clarified its commitment that the plant-specific program, if needed, 

will include the following actions: 

* capsules will be removed periodically to determine the rate of embrittlement 

* capsules will be removed at neutron fluence levels which provide relevant data for assessing the integrity of the Plant Hatch RPVs; in particular, for the determination of RPV pressure

temperature limits through the period of extended operation 

0 capsules will contain material to monitor the impact of irradiation on the Plant Hatch RPVs 

and will contain dosimetry to monitor neutron fluence 

On the basis of these commitments, the staff concludes that the applicant has identified in sufficient 

detail the actions that will be taken to provide reasonable assurance that aging effects associated 

with embrittlement of the reactor vessel will be adequately managed for the period of extended 

operation. On this basis, Open Item 3.1.17-1 is resolved. The renewed license will be conditioned 

to require that, prior to operation in the renewal term, the applicant will notify the NRC of the its 

decision to implement the ISP or a plant-specific program, and provide the appropriate revisions to 

the FSAR Supplement summary descriptions of the vessel surveillance material testing program. 

3.1.17.4 Conclusion 

On the basis of the acceptability of the BWRVIP reports referenced above, along with the applicants commitment to implement the actions quoted above regarding the surveillance materials testing 

program, the staff concludes that the RPV monitoring program is adequate to manage the aging

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effects associated with the components in the reactor assembly system, as required by 10 CFR 

54.21 (a)(3). 

3.1.18 Fire Protection Activities 

3.1.18.1 Introduction 

The applicant described its fire protection activities program in LRA Sections A.2.1, "Fire Protection 

Activities"; C.2.3, "Aging Management Reviews for Fire Protection System Components"; and C.2.4, 

"Aging Management Reviews for Mechanical Component External Surfaces," and Section B.2.1 of 

the applicant's October 10, 2000 submittal. The staff reviewed the application to determine whether 

the applicant has demonstrated that the fire protection activities inspection program will adequately 

manage aging effects during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

3.1.18.2 Summary of Technical Information in the Application 

Fire protection activities comprised inspections and condition monitoring and performance monitoring activities. These activities provide assurance that a fire will not prevent the performance 

of necessary safe shutdown functions. The fire protection activities use both direct visual 

examination and indirect flow testing to detect flow blockage, loss of material, cracking, and 

changes in material properties. The fire protection activities are designed to minimize both the 

probability and consequences of postulated fires through a defense-in-depth philosophy. 

Plant Hatch fire protection activities credit Appendix B of the FHA and includes passive long-lived 

components in water-based and gas-based fire suppression systems. In addition, the fire pump diesel fuel oil supply system (tanks and piping) and various fire rated assemblies are also included. 

The water-based fire protection header loop piping is flushed regularly and the fire pump casings 

are visually inspected and operationally tested. The sprinklers are visually inspected and open-head sprinklers and nozzles are flow tested using air. Fire water tank internals are inspected for localized 

and general pitting, average dry film thickness and general condition of the protective coating. Sizes 

and depth of the pits are recorded. Interior surfaces are cleaned as required to facilitate inspection. Fire pump diesel fuel oil supply and various gaseous fire suppression system components are 

visually inspected and performance tested. In-scope fire-rated assemblies are visually inspected 

periodically. 

3.1.18.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the fire protection activities program to ensure that the applicable component aging effects will be managed so that 

system intended functions will be maintained consistent with the CLB for the period of extended 

operation. 

Program Scope 

Fire protection activities are applied to the X43 - Fire Protection System which includes the following 

commodity groups:

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* water-based fire suppression systems 

0 fire protection diesel fuel oil supply system 

0 compressed gas-based fire suppression systems 

0 fire barriers for preventing fire propagation 

• external surfaces exposed to an inside environment 

0 external surfaces exposed to an outside environment 

The staff requested in RAI 3.1.18-10(b) that the applicant identify the long-lived components in the 

water-based and gas-based fire suppression systems. In its response, the applicant stated that, 

"all fire-rated penetration seals, excluding those inside the radwaste building, are included in the 

scope of license renewal." The staff did not agree that the fire protection components that are 

located in the radwaste building could be excluded from the scope of license renewal. This was 

identified as Open Item 2.3.4.2-1. Resolution of this open item is discussed in Section 2.3.4.8 of 

this SER. On the basis of the resolution of this open item, the applicant has included fire protection 

components that are located within the radwaste building within the scope of license renewal. No 

new commodity groups were subject to an AMR as a result of these additional in-scope 

components. 

Preventive or Mitigative Actions 

Table C.2.3.1-1 of the LRA states that, for water-based fire suppression system components, the 

fire protection activities prevent or mitigate loss of material by using system flushes to remove 

undesirable material from the system. However, the operability of the automatic wet-pipe sprinkler 

systems, which are required for compliance with 10 CFR 50.48, were not discussed. In response 

to RAI 3.1.18-7, in which the staff notified the applicant of this omission, the applicant stated that, "unobstructed water flow from the header test valve demonstrates that sprinkler heads and piping 

are not clogged from corrosion product debris." The staff did not agree with this statement since 

(1) the arrangement of the test header at the most distant point in the sprinkler system is usually 

located in the fire suppression piping, which is along the path of least water resistance, and (2) the 

sprinkler heads are located along the smaller branch line piping and, as a result of their orientation, 

are typically never exposed to the flow of water during the routine testing of the test header. Since 

there is little or no flow in the branch lines during testing, the water in these lines remains stagnant 

and sediment from the raw water, which flows to the header test connection, continues to collect in 

the smaller branch line piping. This may result in blockage and corrosion of the branch line piping 

and the sprinkler heads at accelerated rates. The staff has addressed this issue in Generic Letter 

89-13, "Service Water Problems Affecting Safety-Related Equipment." The staff requested that the 

applicant discuss the specific considerations for addressing this aging mechanism in the automatic 

wet-pipe sprinkler systems. This was identified as part of Open Item 3.1.18-1 [3.1.18-1 (a)]. 

The applicant routinely performs sprinkler piping flow tests to check for clogging from corrosion 

products as part of the fire protection activities. The staff was initially concerned that these tests 

may not be adequate for demonstrating operability of the sprinkler heads during the extended period 

of operation. However, as the staff position has evolved, additional flow tests are not required to 

determine flow blockage in the sprinkler system. This is consistent with the staff position in the 

generic aging lessons learned (GALL) report with regard to flow blockage in fire protection and other 

systems, as a result of corrosion, biofouling, or silting. System flow is considered to be an active 

feature. However, the staff expects the applicant to be sensitive to the potential for flow degradation 

as a result of accumulation of corrosion products. The staff has determined that as long as the 

applicant conducts the wet pipe sprinkler header flow tests as described in the response to RAI

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3.1.18-7, flow degradation would be adequately managed. In addition, should flow degradation be 

discovered, the applicant has a corrective action program, that requires trending to determine the 

need for future actions. On this basis, the staff concludes that Open Item 3.1.18-1 (a) is closed. 

Parameters Inspected or Monitored 

The applicant states that surveillance and inspection of fire protection systems and components are 

performed in accordance with Appendix B of the FHA. Fire protection activities provide for visual 

inspection or performance testing for the water-based fire suppression system components and the 

diesel fuel oil system components. For the water-based fire suppression system, diesel fire pumps 

are visually inspected and operationally tested on a regular schedule, the fire water storage tank 

internal surfaces are periodically inspected, the sprinkler nozzles are visually inspected and air-flow

tested on a regular schedule, and valves are cycled to verify functionality. Visual inspections and 

performance testing of the fire protection diesel fuel oil supply system are conducted on a regular 

basis to detect degradation of the fuel system components prior to the loss of intended function. 

Visual inspections and performance testing of the compressed gas fire suppression systems and 

inspections of the insulation installed on the C02 storage tanks are conducted on a regular basis. 

Visual inspections are performed on fire penetration seals, in-scope cable tray enclosures and fire 

doors. Exterior coatings or paint are inspected per the industry guidance reflected in the protective 

coatings program. 

The staff finds that the parameters inspected or monitored under this aging management program 

are adequate to ensure that aging effects will be identified for disposition through the corrective 

actions program. 

Detection of Aging Effects 

The applicant states that flow blockage, loss of material, cracking, and changes in material 

properties are detected directly by visual examinations of component surfaces and indirectly through 

the use of flow functional testing. 

With regard to the inspection frequency of fire system components, the applicant lists in Section 

B.2.1 of the applicant's October 10, 2000 submittal the different inspection intervals for the water

based fire protection systems, fire protection pump diesel fuel oil supply system, compressed gas 

based fire suppression systems, fire penetration seals, cable tray enclosures, and fire doors. In 

addition to the systems listed above, the applicant describes a one-time inspection called the 

"Sprinkler Head Inspections" that will be performed at or before the start of the extended period of 

operation for closed sprinkler heads within the scope of license renewal. In RAI 3.1.18-9, the staff 

requested that the applicant provide justification for the absence of enhanced inspection programs 

for the sprinkler heads, which do not have a design life that covers the period of extended operation. 

In response the applicant stated that, in general, enhanced inspection programs are deemed 

unnecessary because the existing programs adequately manage the aging effects of concern, and 

that using the guidelines of the National Fire Protection Act (NFPA) Code 25, "Standard for the 

Inspection, Testing, and Maintenance of Water-Based Fire Protection," a one-time sprinkler heads 

inspection is to be performed for in-scope sprinkler heads. The staff does not agree that a one-time 

inspection is sufficient for the sprinkler heads and recommends that the applicant expand the scope 

of its inspections to include the 10-year inspection intervals that are recommended in NFPA 25, 

Section 2.3.3.1, "Sprinklers." Section 2.3.3.1 states that "where sprinklers have been in place for 

50 years, they shall be replaced, or representative samples from one or more sample areas shall

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be submitted to a recognized testing laboratory for field service testing." It also contains guidance 

to perform this sampling every 10 years after the initial field service testing. In addition, the staff 

has notified the nuclear industry, through recent information notices, about the potential failures 

associated with sprinkler heads. These information notices include IN 01-10, "Failure of Central I 

Sprinkler Company Model GB Series Fire Sprinkler Heads;" IN 99-28, "Recall of Star Brand Fire I 

Protection Sprinkler Heads;" and IN 97-72, "Potential for Failure of the Omega Series Sprinkler Heads." Problems with seals leaking and sprinkler heads failing to actuate are typically not 

detectable through the performance of existing visual inspections. Therefore, the staff requested that the applicant expand the scope of its inspections to include the 10-year inspection intervals that 

are recommended in NFPA 25 or provide additional justification for the applicant's proposed 

inspection interval. This was identified as part of Open Item 3.1.18-1 [3.1.18-1(b)]. 

The applicant has previously addressed this issue in its responses to RAIs 2.3.4-FPS-10 and 

3.1.18-9. By letter dated June 5, 2001, in response to Open Item 3.1.18-1(b), the applicant supplemented the earlier RAI responses by expanding the scope of the inspections referenced. 

Thus, the revised commitment is to use the guidance of NFPA-25 to perform an inspection of closed 

head sprinklers after 50 years of service and at 10-year intervals thereafter. On the basis of the 

applicant's commitment, the staff finds that the applicant has adequately addressed the staff's 

concern and Open Item 3.1.18-1(b) is closed. 

Monitoring and Trending 

The applicant states that the results of fire protection system tests and inspections are documented 

in accordance with procedural requirements. In addition, the corrective actions program is used to 

monitor and trend fire protection deficiencies and to implement timely corrective actions. The staff 

finds that the monitoring and trending activities described by the applicant are adequate to ensure 

that corrective actions will be taken before exceeding the acceptance criteria. 

Acceptance Criteria 

The applicant states that significant degradation of components managed by this aging 

management program are noted and corrective actions are implemented on the basis of the 

corrective actions program. Acceptance criteria for each test or inspection is specifically stated in 

plant procedures and includes system frictional pressure drop; adequate air flow; detection of leaks 

present; sampling for water, sediment, and other oil contaminants; and CO2 tank pressure, general 

condition, and pressure boundary leakage. 

Based on the discussion above and the operating history of this aging management program, the 

staff finds that the acceptance criteria established in plant procedures reasonable to detect aging effects which were evaluated by the corrective actions program before failure occurred. 

Operating Experience 

For the water-based fire suppression systems, deficiencies included leaking piping, deterioration 

of coatings within the fire water storage tank, and fouling of lines attributable to corrosion buildup. These were identified during testing and inspection as required by the fire protection activities or 

normal walk down activities.

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Per LRA Section C.2.3.2, IN 91-46 identified a potential deficiency managed in the fire protection 

activities. This potential deficiency is clogging of strainers with sediment and degraded fuel oil. 

Deficiencies of the external surfaces are managed by the applicant's protective coatings program. 

The staff concludes that the operating experience, to date, supports the attributes of the fire 

protection activities. 

3.1.18.4 Conclusions 

The staff has reviewed the fire protection activities for the aging management program described 

in LRA Sections: A.2.1, "Fire Protection Activities;" C.2.3, "Aging Management Reviews for Fire 

Protection System Components;" and C.2.4, "Aging Management Reviews for Mechanical 

Component External Surfaces," and Section B.2.1 of the applicant's October 10, 2000 submittal. 

On the basis of its review, the staff concludes that the fire protection activities program will 

adequately manage the identified aging effects for the period of extended operation, as required by 

10 CFR 54.21 (a)(3). 

3.1.19 Flow Accelerated Corrosion Program 

3.1.19.1 Introduction 

The applicant described its flow-accelerated corrosion (FAC) program in LRA Sections A.2.2, "Flow 

Accelerated Corrosion Program," and Section B.2.2 of the applicant's October 10, 2000 submittal. 

It also included relevant materials from Section 3.2.1, "Reactor," Section 3.2.3, "Engineering Safety 

Features (ESF) System," and Section 3.2.5, "Steam and Power Conversion." These sections 

address aging effects of the components in reactor, engineering safety features, and steam and 

power conversion systems. The components in these systems belong to two commodity groups, one 

representing Class 1 carbon steel components within the reactor water environment, and the other, 

non-Class 1 carbon steel components within the reactor water environment. Both of these 

commodity groups contain components that are subject to aging effects managed by the FAC 

program. The objective of this program is to ensure that the damage caused by flow-accelerated 

corrosion will not cause component failures. This objective is accomplished by predicting the rate 

of degradation of components and taking corrective actions once the degradation is detected. 

The staff reviewed the applicant's description of the program in LRA Sections A.2.2, Section B.2.2 

of the applicant's October 10, 2000 submittal, and relevant material in other referenced sections of 

the LRA to determine whether the applicant has demonstrated that the program will adequately 

manage the effects of aging caused by FAC in the plant during the period of extended operation, 

as required by 10 CFR 54.21 (a)(3). 

3.1.19.2 Summary of Technical Information in the Application 

In the LRA the applicant has identified the following systems which contain the components that are 

affected by FAC: 

* nuclear boiler system 

* high pressure coolant injection system 

* reactor core isolation system 

* main condenser

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The applicant identified loss of material by FAC as the aging effect for carbon steel components 

exposed to reactor water. (However, main steam piping is not susceptible to FAC.) 

In the LRA, the applicant identified a FAC program for managing the aging effects caused by FAC. 

The program is predicated on EPRI recommendations for effective control of FAC. For license 

renewal, the applicant will enhance the existing program by adding components in certain systems 

which are already included in the FAC program. For Unit 2, these systems will consist of portions 

of the radioactive decay holdup volume (main steam and steam line drains, and condensate drains). 

Also, it will enhance examination methods and frequencies for the components, such as smaller

than-two-inch piping, whose FAC wall thinning could not be predicted by the computer code used 

in the program. Examinations of these components will be predicated on industry and plant-specific 

operating experience as opposed to computer modeling. The applicant concluded that this 

enhanced program will adequately manage aging effects in the components affected by FAC. 

3.1.19.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the FAC program to 

ensure that the applicable component aging effects will be managed so that system intended 

functions will be maintained consistent with the CLB for the period of extended operation. 

The components in the systems affected by FAC are made of carbon steel. This material, when 

exposed to the environment of moving single or two-phase reactor water with relatively low oxygen 

content and high temperature, corrodes at rates higher than if it were in contact with a stagnant fluid. 

The resulting loss of material produces thinning walls in the affected components. To prevent 

component failure, loss of material has to be managed. The staff finds that there is reasonable 

assurance that this mode of degradation is the only plausible aging effect related to FAC for aging 

management considerations. 

The applicant has a program for managing aging effects attributable to FAC. The program is 

predicated on the EPRI recommendations, specified in Report NSAC-202L, "Recommendations for 

an Effective Flow-Accelerated Corrosion Program," and in the associated CHECWORKS computer 

code. The program predicts, detects, and monitors flow accelerated corrosion wear in high-energy carbon steel piping in the nuclear boiler system, high pressure coolant injection system, reactor core 

isolation system, and main condenser. It includes determination of the extent of wall thinning in the 

FAC-affected components and specifies repair or replacement of the components with wall 

thickness not meeting the acceptance criteria. 

Program Scope 

The applicant will enhance the existing program during the period of extended operation, starting 

midnight August 6, 2014, for Unit 1 and midnight June 13, 2018, for Unit 2. The enhancement 

includes additional components for inspection, and adds an inspection method for the components 

which could not be inspected by the method presently existing in the program. The staff finds that 

the enhanced scope of the program will be adequate for managing loss of material due to FAC.

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Preventive and Mitigative Actions 

The FAC program is designed to monitor the aging effects attributable to FAC before a loss of 

intended function. The staff agrees that the FAC program is not intended to prevent or mitigate the 

effects associated with FAC. Instead the program is designed to monitor the aging effects 

attributable to FAC. The staff concludes that the program will provide assurance that FAC will be 

adequately monitored. 

Parameters Monitored or Inspected 

The FAC program monitors the effects of FAC by measuring wall thickness of the components 

exposed to the environment favoring FAC. Analytical models are used to predict wall thinning in 

piping systems susceptible to FAC on the basis of the specific plant data, including material of 

construction, chemistry, and hydrodynamic and operating conditions. The subsequent examination 

of the selected components is made by visual, ultrasonic, or radiographic techniques. The staff 

finds this methodology adequate to detect the aging effects attributable to FAC. 

Detection of Aging Effects 

Wall thickness is measured by ultrasonic testing or, in the case of small-bore pipes, by radiography 

since ultrasonic testing of small-bore pipes is impractical. The staff finds these to be standard, well 

developed techniques that will produce reliable results. 

Monitoring and Trending 

Using the methods stated above, the applicant will be able to evaluate the rate at which component 

wall thinning by FAC is occurring. The CHECWORKS computer program contains a database that 

maintains inspection data which can be used for that purpose. Trending the data will permit 

determination of the timing for future inspections. Also, if degradation is detected such that the wall 

thickness may reach a value below the minimum allowed by the acceptance criteria, the component 

will be repaired or replaced, and additional examinations will be performed of the components in the 

adjacent areas to bound the damaged component. The staff finds adequate the monitoring and 

trending method and subsequent actions. 

Acceptance Criteria 

The criteria for component replacement are predicated on allowable minimum wall thickness, 

determined by the design code of record. If the predictive methods indicate that a component will 

reach its minimum allowable wall thickness before the next inspection interval, proper corrective 

actions will be undertaken. The staff finds the acceptance criteria adequate. 

Operating Experience 

The applicant monitors the FAC-related developments occurring in the industry. This is 

accomplished through contacts with EPRI and review of the information generated by the industry. 

Additionally, EPRI NSAC-202L provides lessons learned from years of industry-wide operating 

experience which could be used to improve the FAC program. A review of plant data for the past 

5 years has revealed FAC damage in small bore piping of the HPCI and RCIC main steam supply 

drain to the condenser. The damaged components were replaced with material not susceptible to

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FAC. Also, as a result of FAC program inspection and corrective action implementation, the high

pressure drain manifold was replaced with chrome-moly piping. The staff finds that plant experience 

has indicated that the FAC program is successful in managing aging caused by FAC. 

3.1.19.4 Conclusions 

The staff has reviewed the information in LRA Section A.2.2, "Flow-Accelerated Corrosion Program," 

and Section B.2.2 of the applicant's October 10, 2000 submittal. On the basis of its review, the staff 

concludes that the applicant has demonstrated that the flow accelerated corrosion program will 

adequately manage aging effects caused by flow accelerated corrosion for the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.20 Protective Coatings Program 

3.1.20.1 Introduction 

The applicant described the protective coatings program in LRA Section A.2.3 and Section B.2.3 

of the applicant's October 10, 2000 submittal. The staff reviewed the application to determine 

whether the applicant has demonstrated that the protective coatings program will adequately 

manage aging effects during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

3.1.20.2 Summary of Technical Information in the Application 

The protective coatings program provides a means of preventing or minimizing aging effects that 

would otherwise result from contact of the base metal with the associated environment. It is a 

mitigation and condition monitoring program designed to provide base metal aging management 

through application, maintenance, and inspection of protective coatings on selected components 

and structures. 

The protective coatings program will be expanded to include the external surfaces of carbon steel 

commodities in-scope for license renewal that are exposed to inside, outside, submerged, and 

buried environments, as made accessible. Portions of multiple systems will be included, consistent 

with plant-specific operating experience and conditions. Affected systems will include, but may not 

be limited to, the nuclear boiler, standby liquid control, residual heat removal, residual heat removal 

service water, core spray, high pressure coolant injection, and reactor core isolation cooling. 

Certain portions of the post-accident radioactive decay holdup, PSW, instrument air, drywell chilled 

water, drywell pneumatics, standby gas treatment, nitrogen inerting, fire protection, and diesel fuel 

oil systems, as well as piping supports, raceway supports, and building structural steel will also be 

included. The affected components in these systems will be piping, valves, pumps, bolts, tanks, and 

structural steel. 

The protective coatings program will be revised to require periodic inspections of in-scope 

components to ensure that they are properly coated and free of significant age-related degradation. 

Coated surfaces of certain components, including those that are normally inaccessible but made 

accessible as a result of maintenance or other activities, will also be inspected when they become 

accessible. 

Program expansions and revisions will be implemented by midnight August 6, 2014, for Unit 1 and 

common system components, and midnight June 13, 2018, for Unit 2.

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3.1.20.3 Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the protective coatings 

program to ensure that the applicable component aging effects will be managed so that system 

intended functions will be maintained consistent with the CLB for the period of extended operation. 

Program Scope 

The protective coatings program provides a means of preventing or minimizing aging effects that 

would otherwise result from contact of the base metal with the associated environment. It is a 

mitigation and condition monitoring program designed to provide base metal aging management 

through application, maintenance, and inspection of protective coatings on selected components 

and structures. 

The systems where the protective coatings program is applied are: 

B21 - Nuclear Boiler 

C41 - Engineered Safety Features 

Cli - Control Rod Drive 

El 1 - Residual Heat Removal 

E21 - Core Spray 

E41 - High Pressure Coolant Injection 

E51 - Reactor Core Isolation Cooling 

F15 - Refueling Equipment 

H1 1 - Main Control Room Panels 

H21 - In Plant Auxiliary Control Panels 

L35 - Pipe Specialties 

L48 - Access Doors 

N61 - Main Condenser 

P41 - Plant Service Water 

P42 - Reactor Building Closed Cooling Water 

P52 - Instrument Air 

P64 - Primary Containment Chill Water 

P70 - Drywell Pneumatic 

R33 - Conduits, Raceways, and Trays 

T23 - Primary Containment 

T24 - Fuel Storage 

T29 - Reactor Building 

T31 - Cranes, Hoists, and Elevators 

T52 - Drywell Penetrations 

T54 - Reactor Building Penetrations 

T41 - Reactor Building HVAC 

T48 - Primary Containment Purge and Inerting 

T49 - Post LOCA Hydrogen Removal 

U29 - Turbine Building 

W33 - Traveling Water Screens, Trash Racks 

W35 - Intake Structure 

X41 - Outside Structures HVAC

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X43 - Fire Protection 

Y29 - Yard Structures 

Y32 - Off Gas Stack 

Y39 - EDG Building 

Y52 - Fuel Oil 

Z29 - Control Building 

Z41 - Control Room HVAC 

The staff agrees that it is appropriate to include the systems listed above within the scope of the 

program. 

Preventive or Mitigative Actions 

The applicant states that the protective coatings program is a mitigation program designed to 

provide metal aging management through application, maintenance, and inspection of protective 

coatings on selected components and structures. The staff agrees that a properly developed 

coating program that is properly implemented, constitutes a mitigative action. 

Parameters Inspected or Monitored 

The parameters inspected are the condition of coatings on the systems listed above. This includes 

bolts and base metal surfaces exposed to inside, outside, submerged, and underground 

environments. 

The applicant stated that a protective coatings surveillance is normally performed once per operating cycle for service level I components (service level I components are used in areas inside 

the reactor containment where failure could adversely affect the operation of post-accident fluid 

systems and thereby impair safe shutdown). Other component surveillance is performed as 

determined by the protective coatings specialist, consistent with trends and plant specific operating 

experience. The applicant stated that there will be a baseline inspection of all in-scope coated 

components, with the exception of buried piping, which will be inspected as available as a result of 

excavation activities. Subsequent inspection frequencies will be determined on the basis of the 

results of the baseline inspection. The staff agrees that the parameters inspected are appropriate. 

Detection of Aging Effects 

The applicant states that aging effects are detected using visual examinations. The staff agrees 

that visual inspections are appropriate for bolts and base metal surfaces exposed to inside, outside, 

and submerged environments since this is a common and accepted practice. Visual inspections 

are also appropriate for buried commodities for identifying damaged or degraded coatings and any 

subsequent loss of material attributable to corrosion. 

Monitoring and Trending 

Results of coatings inspections are documented in accordance with Plant Hatch procedural 

requirements. For service level I coatings, a record will be kept concerning locations of minor 

deterioration, and subsequent evaluation. For all coatings, a summary of findings and 

recommendations for future actions will be maintained. Significant degradation identified during 

coatings inspections are also identified utilizing the Plant Hatch corrective actions program.

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A baseline inspection of all in-scope coated components will be performed, with the exception of 

buried piping that will be inspected as available during excavation activities. Subsequent inspection 

frequencies will be determined on the basis of the results of the baseline inspection. The staff 

concludes that the monitoring and trending are adequate. 

Acceptance Criteria 

Multiple codes and standards were considered in the development of the plant protective coatings 

program. These include ANSI N5.12-1972, "Protective Coatings (Paints) forthe Nuclear Industry"; 

ANSI N1 01.2 - 1972, "Protective Coatings (Paints) for Light Water Nuclear Reactor Containment 

Facilities"; ASTM, Section 6, Volume 06.02, "Paints-Products and Applications, Protective Coatings, 

Pipeline Coatings"; AWWA C203, "Coal-Tar Protective Coatings for Steel Water Pipelines - Enamel 

and Tape - Hot Applied"; and AWWA C209, "Cold Applied Tape Coatings for the Exterior of Special 

Sections, Connections, and Fittings for Steel Water Pipelines." 

Coatings application is not allowed to proceed until applicable solvent cleaning, removal of stratified 

rust, loose mill scale, non-adherent paint, weld flux and splatter, and thick edge paint feathering has 

been verified. Prepared steel must conform to SSPC-SP1 1 (Steel Structures Painting Council) visual 

standards SSPC-VIS3, or equivalent. 

The staff has reviewed the references and agrees that the acceptance criteria in the references 

provides reasonable assurance that the acceptance criteria are effective in controlling the aging 

effect of loss of material. 

Operating Experience 

The applicant reviewed plant deficiency cards submitted over the past 5 years which identified many 

instances of coating degradation. Primarily, these deficiencies related to corrosion of carbon steel 

and low-alloy components in areas where the existing coating had broken down, no coating was 

originally applied, or wetting attributable to leakage had occurred. 

Relevant operating experience for in-scope buried piping is limited to PSW, RHRSW, and diesel fuel 

oil supply piping since no credit was taken for the coatings installed on fire protection cast iron 

piping. A review of more than 36,000 plant deficiency cards and interviews with key personnel 

revealed no age related failures of piping attributable to coating degradation over the past 5 years. 

Based on the applicant's review of plant records, the staff finds that the coating program will 

adequately manage the effects of aging for the period of extended operation. 

3.1.20.4 Conclusions 

The staff has reviewed the information in Section A.2.3, "Protective Coatings Program," of the LRA, 

the applicant's responses to the staff's RAIs, and Section B.2.3 of the applicant's October 10, 2000 

submittal. On the basis of its review, the staff concludes that the applicant has demonstrated that 

the effects of aging associated with structures and components in systems managed by the 

protective coatings program will be adequately managed so that intended functions will be 

maintained, consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3).

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3.1.21 Equipment and Piping Insulation Monitoring Program

3.1.21.1 Introduction 

"The applicant described its equipment and piping insulation monitoring program in LRA 

Sections A.2.4, C.2.4.4, C.2.4.4.1 and C.2.4.4.2. Supplemental information is further provided in 

Section B.2.4 of the October 10, 2000, submittal, which provided the applicant's responses to the 

staff's RAI. The equipment and piping insulation monitoring program at Plant Hatch is a condition 

monitoring program designed to detect insulation damage through periodic inspection of specific passive component insulation. The staff reviewed the application to determine whether the applicant 

has demonstrated that the program will adequately manage aging effects for the affected equipment 

and piping during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

3.1.21.2 Summary of Technical Information in the Application 

The applicant stated that equipment and piping insulation includes insulation and associated 

jacketing for in-scope components installed on emergency core cooling system (ECCS), PSW and 

RHR service water system components. Thermal insulation serves to maintain design calculation 

limits, provide freeze protection, and prevent overheating of ECCS diagonals and HPCI pump 

rooms. The metallic jackets and fasteners serve to protect the insulation from environmental attack 

and fix the insulation in place. 

3.1.21.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the equipment and piping insulation monitoring program to ensure that the applicable component aging effects will be 

managed so that system intended functions will be maintained consistent with the CLB for the period 

of extended operation. 

The applicant stated that for insulation, aging effects requiring management include loss of material 

as a result of wear and intrusion of water borne agents; cracking as a result of thermal effects and 

intrusion of water borne agents; and change in material properties as a result of compaction and 

settling, material separation, intrusion of water and water-borne agents, and thermal effects. The 

applicant also stated that the in-scope insulation jacketing components and associated fasteners 

are fabricated from stainless steel, galvanized steel, and aluminum alloys. The aging effects 

requiring management for these materials include loss of material as a result of general corrosion, 

galvanic corrosion, pitting, crevice corrosion and MIC, and cracking as a result of thermal fatigue. 

Program Scope 

The equipment and piping insulation monitoring program currently inspects insulation of piping and 

equipment within the scope of license renewal. The applicant stated that the program will be 

enhanced to include portions of the following systems that are within the scope of license renewal: 

C41 - SLC 

Eli - RHR and RHRSW 

E21 - core spray 

E41 - HPCI

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E51 - RCIC 

P11 - condensate transfer and storage 

P41 - PSW 

X43 - fire protection 

The applicant indicated that program enhancements will be implemented by midnight August 6, 

2014, for Unit 1, and midnight June 13, 2018, for Unit 2. The staff finds that the scope of the 

program will be adequate for managing the aging of insulation within the scope of license renewal. 

Preventive or Mitigative Actions 

In Section C.2.4.4, the applicant stated that no reasonable method is available to mitigate potential deterioration of insulation at Plant Hatch. However, it is expected that deterioration of insulation at 

Plant hatch will occur slowly and would be adequately managed by a focused inspection program provided by the equipment and piping insulation monitoring program. Therefore, no program is 

required to prevent or mitigate aging degradation. Plant Hatch procedures contain precautions limiting climbing on pipe insulation unless specifically justified by an engineering review and 

evaluation. Damage is further mitigated by procedures that provide specific instructions for removal, 

storage, and installation of thermal and reflective insulation. The staff finds there are no preventive 

or mitigative attributes associated with this program. The licensee will inspect the in-scope 

insulation for deterioration. 

Parameters Inspected or Monitored 

The applicant stated that the equipment and piping insulation monitoring program will be enhanced 

to periodically inspect in-scope insulation that is readily accessible to identify any holes, tears, 

compaction, material separation, wetting, missing insulation and general deterioration. Aluminum 

and galvanized steel insulation jackets and their binders will be inspected for cracking and loss of 

material. The staff finds the examination of in-scope insulation is adequate for detecting 

degradation of the insulation. 

Detection of Aging Effects 

The applicant stated that appropriate visual inspection techniques will be used for the inspection. These techniques will include remote visual inspection using binoculars or other devices for some 

locations. The exterior surfaces of the insulation system are visually inspected for obvious 

degradation. Exterior surfaces may consist of protective metal jacket covers that are not removed 

unless there is obvious degradation or evidence of a problem in the underlying insulation, such as 

significant corrosion or water egress from within the jacketing system. Once degradation is found, 

the outer metal jacket may be removed to further investigate the underlying insulation material 

condition. All in-scope external jackets and binders are visually inspected for holes, tears, cracks, 

significant corrosion, missing material, and generally deteriorated condition. When warranted by external inspection, the affected underlying insulation material is visually inspected for holes, tears, 

compaction, material separation, wetting, missing insulation, and generally deteriorated condition 

as a result of cracking, settling, and thermal degradation. The applicant stated that none of these 

conditions (holes, tears, cracks, missing material, etc.) is acceptable. If degradation is discovered, 

corrective action will be initiated to remedy the condition. Since the entire in-scope insulation 

system, to the extent it is accessible, is inspected, there is no sample size. The staff finds this 

approach reasonable.

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Monitoring and Trending

The applicant stated that deficiencies discovered during these insulation inspections will be 

documented in accordance with the Plant Hatch corrective actions program. For outside insulation 

and jackets, the frequency of inspections is once per year. For inside insulation and jackets, all in

scope insulation is to be inspected within 2 refueling cycles of issuance of the new operating license 

and at least once every 10 years thereafter. The staff finds this approach reasonable. 

Acceptance Criteria 

The applicant stated that any unacceptable indication of corrosion or insulation damage will be 

evaluated and, if warranted, additional inspections will be performed. Unacceptable conditions 

include holes, tears, cracks, missing material, etc. Corrective actions, if required, will be addressed 

through the existing Plant Hatch corrective actions program. The applicant stated that the plant 

procedures specify the acceptance criteria for the equipment and piping insulation, including 

insulation jackets. The staff concurs with the applicant that these criteria will ensure that degraded 

insulation will be managed properly. 

Operating Experience 

A review of plant deficiency cards over the past 5 years did not identify any significant age-related 

degradation in insulation or insulation jacketing for the components within the scope of license 

renewal. The applicant stated that several deficiencies were identified related to damaged, torn, or 

missing insulation. These areas were localized, generally attributed to mechanical damage, and not 

deemed to significantly impact thermal performance of the insulated system. Only one record that 

related to generally deteriorated insulation was discovered. This deterioration was confined to a 

small area and was not determined to significantly affect the thermal performance of the insulated 

system. Given the applicant's operating history, the staff finds that the equipment and piping 

insulation monitoring program will adequately manage aging effects associated with insulation and 

jackets for the period of extended operation. 

3.1.21.4 Conclusions 

The staff has reviewed the information in Section A.2.4, of the LRA, "Equipment and Piping 

Insulation Monitoring Program," and Section B.2.4, "Equipment and Piping Insulation Monitoring 

Program," of the applicant's October 10, 2000 submittal. On the basis of its review, the staff 

concludes that the applicant has demonstrated that the effects of aging associated with the 

insulation of piping and equipment in systems managed by this program will be adequately 

managed such that the insulation and jacketing will continue to perform their intended functions, 

consistent with the current licensing basis, for the period of extended operation, as required by 10 

CFR 54.21 (a)(3). 

3.1.22 Structural Monitoring Program 

3.1.22.1 Introduction 

The applicant described its structural monitoring program in LRA Section A.2.5, and supplemented 

its description of this AMP in Section B.2.5 of the October 10, 2000 submittal. The applicant credits 

this inspection program with assessing the overall conditions of buildings and structures and

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identifies any ongoing degradation through a visual inspection process. The program monitors and 

assesses the condition of structures affected by aging, which may cause loss of material, cracking, 

loss of adhesion, and change of material properties. The staff reviewed the application to determine 

whether the applicant has demonstrated that the structural monitoring program will adequately 

manage aging effects during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

3.1.22.2 Summary of Technical Information in the Application 

In LRA Section A.2.5 and Section B.2.5 of its October 10, 2000 submittal, the applicant describes 

an existing aging management program, the structural monitoring program, that provides for 

periodic visual inspections to monitor the condition of structures, components, and commodities. 

The monitored structures include the switchyard, reactor buildings, turbine buildings, intake 

structure, main stack, diesel generator building, control building, and waste gas building. In addition, 

the condensate storage tank foundation and walls, plant service water valve pits, and nitrogen 

storage tank foundations are also monitored by the structural monitoring program. The applicant 

lists the specific structural components, which are fabricated from either carbon steel, stainless 

steel, or concrete, and inspected as part of the structural monitoring program in LRA Sections 3.2 

through 3.4. 

The aging effects managed by the structural monitoring program are discussed in LRA 

Section C.1.4. The structural monitoring program is relied on for management of loss of material 

attributable to general corrosion for steel structures in seismic Category I buildings, the turbine 

building, Category I yard structures and component supports. For concrete components (i.e., walls, 

beams, slabs, columns, floors, roof, underground duct runs and pull boxes, foundations) and block 

walls in concrete structures, the structural monitoring program is relied on for management of 

cracking and spalling resulting from corrosion for embedded steel, and cracking in masonry block 

walls. In response to RAI 3.4-PSW-3, the applicant indicated that pit and diving activities originally 

listed under the SMP will now be done in the PSW and RHRSW inspection program, which is 

described in LRA Section B.1.13. The pit inspection and diving activities help manage flow blockage 

by removal of accumulated silt and debris from the intake structure pump suction pit. In addition, 

the structural monitoring program also manages loss of adhesion, material property changes, and 

cracking of the reactor building joint seal and caulk sealant. The applicant states that the structural 

monitoring program is patterned after the Westinghouse Owners Group Life Cycle 

Management/License Renewal Program. The structural monitoring program is an existing program 

that will be enhanced for license renewal to include the inspection of sealants in the joints between 

the reactor building exterior precast siding panels and seismic Category I and seismic Category Il/I 

piping, cable trays, conduits, control room panels, auxiliary panels, and their supports. These 

program enhancements will be implemented by August 6, 2014, for Unit 1 and by June 13, 2018, 

for Unit 2. 

3.1.22.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the structural monitoring 

program to ensure that the applicable component aging effects will be managed so that system 

intended functions will be maintained consistent with the CLB for the period of extended operation.

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Program Scope

The applicant lists the structures, components, and commodities that are covered by the structural 

monitoring program in Section B.2.5 of the October 10, 2000 submittal. In Open Item 3.6.3.1-1, the 

staff was concerned that there was no demonstration that the leakage characteristics of the reactor 

building would be maintained during the extended period of operation. By letter dated June 5,2001, 

the applicant responded to this open item, stating that the structural monitoring program would be 

revised to include the provisions of Surveillance Requirement 3.6.4.1.4 of the Unit 1 and 2 technical 

specifications (TS). The draw-down test performed pursuant to the surveillance requirement will be 

credited for aging management as an additional detection measure that is capable of detecting 

gross changes in flow that may be indicative of age-related degradation. The applicant also revised 

the FSAR Supplement to reflect this change. 

On the basis of the applicant's inclusion of the secondary containment draw-down test as per the 

surveillance requirements of the TS, as a means to detect gross age-related degradation of 

secondary containment, the staff concludes that the applicant has an adequate AMP to demonstrate 

that the overall effect of numerous degradations will not violate the leakage characteristics of the 

reactor building. 

The staff finds that the scope of the structural monitoring program is acceptable since it includes 

a walkdown inspection of all structures and components within the scope of license renewal and 

includes a draw-down test to confirm that the leakage characteristics of the reactor building will be 

maintained during the extended period of operation. 

Preventive and Mitigative Actions 

There are no preventive or mitigative actions taken as part of this program, and the staff did not 

identify the need for such actions. 

Parameters Inspected or Monitored 

The structural monitoring program requires a visual inspection of structures and components. 

Specifically, the applicant stated that (1) concrete structures are inspected for cracking and spalling, (2) masonry block walls are inspected for cracking, (3) steel structures and components are 

inspected for corrosion, (4) panel joints, seals, and sealants are inspected for loss of adhesion, 

material property changes, and cracking, and (5) acrylic domes on the tornado vents will be 

inspected for cracking. For structures located below ground or embedded, the applicant stated that 

when normally inaccessible structures are exposed because of excavation or modification, an 

examination of the exposed surfaces is performed. This approach is acceptable to the staff. The 

staff finds the parameters monitored, such as cracking and spalling of concrete, and corrosion of 

steel, acceptable because they are directly related to the degradation of civil structures and 

components, and visual inspections are effective and adequate to detect such conditions. 

Detection of Aging Effects 

The aging effects that are managed by the structural monitoring program are identified through visual inspections. In response to RAI 3.1.22-5, the applicant stated that the implementing 

document for the structural monitoring program provides a detailed description of the walkdown 

procedures, acceptance criteria, evaluation of results, and checklists. In response to RAI 3.1.22-4,

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the applicant stated that structural monitoring is performed by qualified personnel, using inspection 

tools. In addition, all inspection results are documented and noted degradation may be documented 

utilizing digital photography. With respect to the inspection frequency, the applicant stated that a 

5 operating cycle inspection frequency was established for the structural monitoring program. In 

addition, the applicant stated that this frequency will continue unless the conditions, environment, 

or noted degradation warrant a change. The intake structure is inspected during every operating 

cycle because of the humid environmental conditions; however, given the results of future intake 

structure inspections, the monitoring program may go to a 5 operating cycle frequency. The 

applicant's operating experience to date supports the continuation of a 5-year frequency for 

inspections. Furthermore, the staff finds that the 5 operating cycle frequency is consistent with 

industry experience and is, therefore, acceptable. 

Monitoring and Trending 

The applicant did not identify any monitoring and trending activities in its description of the structural 

monitoring program; however, in response to RAI 3.1.22-2, the applicant stated that structures are 

monitored for changes in previously identified findings and for newly developed conditions. Trending 

of such findings is performed to predict degrading conditions and to determine the potential long

term impact of the finding. The staff finds that the monitoring and trending activities described by 

the applicant are adequate to ensure that corrective actions will be taken before exceeding the 

acceptance criteria. 

Acceptance Criteria 

The applicant did not identify any specific acceptance criteria in its description of the structural 

monitoring program; however, in response to RAI 3.1.22-1 the applicant identified the following 

criteria: 

"* Concrete is inspected for spalling (> 3/4" in depth and 8" in dimension), cracking (> 0.04" 

in width), exposed rebar that has not progressed and has not resulted in loss of cross 

section greater than 10 percent, and signs of separation or environmental degradation 

present in joints or joint materials. 

"* Masonry walls are inspected for cracks, for appropriate anchoring, for lateral supports for 

seismic block walls, and for evidence of damage or movement in the interfaces between the 

block walls and concrete floors. 

"* Structural steel is inspected for general corrosion (flaking rust, surface stains, spots) and 

localized corrosion with the presence of small diameter pitting or the presence of loose rust 

flakes peeling or blooming from metal surfaces. 

In addition, in response to RAI 3.1.22-3, the applicant stated that the acceptance criteria for the 

structural monitoring program are consistent with the recommended criteria in ACI 349.3R-96, 

"Evaluation of Existing Nuclear Safety-Related Concrete Structures," and also include additional 

criteria for roof ponding, water leakage, coatings, penetration seals, etc. The applicant also stated 

that the results of the inspections are evaluated in accordance with the guidance given in NEI 96-03, 

"Guideline for Monitoring the Condition of Structures at Nuclear Power Plants" and NRC Regulatory 

Guide 1.160 (Revision 2), "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." 

The staff has not accepted the NEI 96-03 guideline for use in license renewal (letter from Thomas

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T. Martin, NRC, to Thomas E. Tipton, NEI, dated October 1, 1996). NRC Regulatory Guide 1.160 

endorses NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants." Although the staff has not accepted NEI 96-03, the staff finds that the 

acceptance criteria specified above are adequate to ensure that the structure and component 

intended function(s) are maintained under all CLB design conditions during the period of extended 

operation. 

Operating Experience 

In LRA Section B.2.5 of the applicant's October 10, 2000 submittal, the applicant stated that in 1996 

and 1997 an initial inspection was performed to establish the baseline condition of the buildings and 

structures within the scope of the structural monitoring program. Areas were visually inspected and 

photographs were made to document any notable degradation. The applicant found that all 

inspected areas were within the limits of the acceptance criteria. The staff finds that the applicant's 

operating experience has demonstrated that the structural monitoring program has effectively 

maintained the integrity of the structures and components and that the effects of aging will be 

adequately managed during the period of extended operation. 

3.1.22.4 Conclusions 

The staff has reviewed the information in LRA Sections A.2.5, "Structural Monitoring Program," of 

the LRA, and B.2.5, "Structural Monitoring Program," of the applicant's October 10, 2000 submittal. 

On the basis of this review, the staff concludes that the applicant has demonstrated that the aging effects managed by the structural monitoring program will be adequately managed so that there is 

reasonable assurance that the commodities and components covered by this inspection program 

will perform their intended functions in accordance with the CLB during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.23 Galvanic Susceptibility Inspections 

3.1.23.1 Introduction 

The applicant described the galvanic susceptibility inspection program in LRA Section A.3.1 and 

Section B.3.1 of the applicant's October 10, 2000 submittal. The program is described under A.3 

"New Programs and Activities" of the Final Safety Analysis Report Supplement. The program is 

aimed at verifying the integrity of the components subject to galvanic corrosion. The staff reviewed 

this section of the application to determine whether the applicant demonstrated that the effects of 

aging caused by galvanic corrosion will be adequately managed during the period of extended 

operation as required by 10 CFR 54.21 (a)(3). 

3.1.23.2 Summary of Technical Information in the Application 

LRA Section A.3.1 and Section B.3.1 of the applicant's October 10, 2000 submittal include a 

discussion of the galvanic susceptibility inspection program, which determine the acceptability of the 

components that are exposed to galvanic corrosion. This type of corrosion occurs when two 

electrically coupled metal surfaces characterized by different corrosion potentials are exposed to 

an electrolyte. In this situation, a less noble material (carbon steel for example) will corrode. The 

applicant has identified three types of galvanic couples at Plant Hatch: carbon steel-stainless steel, 

aluminum alloy-galvanized steel and galvanized steel-stainless steel. The carbon steel-stainless

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steel couple exposed to an electrolyte is most conducive to galvanic corrosion since these two 

materials are far apart in the galvanic series. The LRA has identified some of the carbon-to

stainless steel connections (welded or flanged) exposed to corrosive environments that are 

susceptible to galvanic corrosion in the following systems: nuclear boiler, CRD, RHR, HPCI, RCIC, 

main condenser, PSW, EDG, primary containment, containment atmospheric control, and screen 

wash isolation. Some dissimilar metal connections of aluminum alloy-galvanized steel, and 

galvanized steel-stainless steel used in the CST are also susceptible to galvanic corrosion. 

The applicant's galvanic susceptibility inspection program is a one-time inspection for condition 

monitoring that will provide objective evidence that the galvanic susceptibility is being maintained 

for the specific components within the scope of license renewal. Since galvanic corrosion is most 

likely to occur in commodities within environments that are highly corrosive (high impurity and 

conductivity levels), these inspections will start with the corrosive raw water environment. The 

galvanic susceptibility inspection will utilize a volumetric examination method for a sample population 

of carbon-to-stainless steel weld connections for thickness measurements using an ultrasonic or 

radiographic technique, or a depth gauge, where feasible, or by the removal of a specimen and 

conducting an analysis. This inspection may also utilize an examination method similar to that 

described for the VT-1 visual examination of the ASME Code, Section XI. Any unacceptable 

indication of loss of material will be evaluated by an engineering analysis and, if warranted, 

additional inspections will be performed. The results of examination will also be evaluated to 

determine whether the sample set should be expanded to cover other environments. The applicant 

will implement corrective actions through the ,existing Plant Hatch corrective actions program. 

3.1.23.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the galvanic susceptibility 

program to ensure that the applicable component aging effects will be managed so that system 

intended functions will be maintained consistent with the CLB for the period of extended operation. 

Program Scope 

The galvanic susceptibility inspections are one-time inspections of a given sample that are intended 

to provide objective evidence that the applicable aging effects are being adequately managed. In 

this program, the applicant has stated that it would provide for the condition monitoring of the 

components within the scope of license renewal to determine whether galvanic corrosion is being 

managed for the period of extended operation. This determination will be achieved by inspecting 

selected components. Samples for inspection will be selected from raw water carbon steel-to

stainless steel weld connections since these two materials are the farthest apart in the galvanic 

series, and therefore have the greatest potential for galvanic corrosion. Examination results will be 

evaluated to determine whether the sample set should be expanded to other environments. The 

staff finds the scope of the program to be adequate because it bounds the galvanic corrosion rates 

occurring in other components within the scope of license renewal and, therefore, provides for 

meaningful detection of age-related damage caused by galvanic corrosion. The applicant stated that 

the Unit 1 inspections will be performed on or after August 6, 2009, but before midnight August 6, 

2014. Unit 2 inspection will be performed on or after June 13, 2013, but before midnight June 13, 

2018.

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Preventive or Mitigative Actions

There are no activities in the galvanic susceptibility inspection program with regard to preventive or 

mitigative actions. The staff did not identify the need for such actions. 

Parameters Inspected or Monitored 

The applicant stated that the galvanic susceptibility inspections are one-time inspections that will 

focus on whether there is loss of material due to galvanic corrosion. Appropriate examination 

methods will be utilized and inspection locations will be selected for thickness measurement. The 

staff finds this approach to be acceptable. 

Detection of Aging Effects 

Volumetric examination will be conducted for a sample population of the carbon to stainless steel 

weld connections for thickness measurements using an ultrasonic or radiographic technique, or a 

depth gauge, where feasible, or by removing of a specimen and conducting an analysis. The 

inspection may also utilize an examination method similar to that described for the VT-1 visual 

examination of the ASME Code, Section X1. The wall thickness inspection of the representative sample will determine the loss of material due to galvanic corrosion and, hence, assess the impact of this aging effect on other components of the plant included in the LRA. The staff finds this to be 

acceptable. 

Monitoring and Trending 

There are no activities in the galvanic susceptibility inspection program with regard to monitoring 

and trending. The staff did not identify the need for such. 

Acceptance Criteria 

The acceptance criteria will be based on the applicable sections of the design codes. The program also requires that corrective action be taken if any unacceptable condition of loss of material is 

detected. The staff finds that, as proposed by the applicant, an engineering analysis followed by implementation of specific corrective actions specified by the site-controlled corrective action 

program, will provide an acceptable technical basis for management of the aging effects caused by 

galvanic corrosion. 

Operating Experience 

The applicant conducted a review of records dating back 5 years on the components within the 

scope of license renewal to determine deficiencies related to the loss of material attributable to 

galvanic corrosion, and did not find any deficiency. 

3.1.23.4 Conclusions 

The staff has reviewed the information in LRA Section A.3.1 and Section B.3.1 of the applicant's 

October 10, 2000 submittal. On the basis of this review, the staff concludes that the applicant has 

demonstrated that the galvanic susceptibility inspection program will adequately manage the aging

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effects attributable to galvanic corrosion of components within the scope of license renewal for the 

period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.24 Treated Water Systems Piping Inspections 

3.1.24.1 Introduction 

The applicant described its treated water systems piping inspection program in LRA Section A.3.2. 

Supplemental information on the inspection program is further provided in Section B.3.2 of the 

October 10, 2000, submittal, which provided the applicant's responses to the staff's RAIs. The staff 

reviewed these sections of the LRA to determine whether the applicant has demonstrated that the 

effects of aging on structures and components in systems managed by this inspection program will 

be adequately managed so that intended functions will be maintained, consistent with the current 

licensing basis, for the period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.24.2 Summary of Technical Information in the Application 

The treated water systems piping inspections will provide for condition monitoring via one-time 

examinations intended to provide objective evidence that existing chemistry control is managing 

aging in piping that is not examined under another inspection program. 

The program will examine a sample population of carbon and stainless steel tubing and piping in 

the treated water systems. The results of the sample population examinations will be recorded and 

evaluated, and subsequent examinations will be conducted where evaluation results warrant. If 

significant degradation is noted, the sample set may be expanded. 

The applicant stated that the treated water system piping inspections program will be conducted 

using techniques appropriate for piping examination and trending. The specific sample population, 

examination methods and acceptance criteria will be defined in the inspection and trending 

procedures. 

3.1.24.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the treated water systems 

piping inspection program to ensure that the applicable component aging effects will be managed 

so that system intended functions will be maintained consistent with the CLB for the period of 

extended operation. 

Program Scope 

The applicant stated that portions of the following systems are included within the scope of this 

program: 

B21 - Nuclear Boiler 

B31 - Reactor Recirculation 

Cl I - Control Rod Drive 

C41 - Standby Liquid Control 

E21 - Core Spray

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E41 - High Pressure Coolant Injection 

E51 - Reactor Core Isolation Cooling 

N32 - Main Turbine Auxiliaries 

P11 - Condensate Storage and Transfer 

P42 - Reactor Building Closed Cooling Water 

P64 - Primary Containment Chilled Water 

R43 - Emergency Diesel Generator Auxiliaries 

T23 - Primary Containment 

T48 - Containment Atmospheric Control System 

The applicant stated that the Unit 1 inspections will be performed on or after August 6, 2009, but 

before midnight August 6.2014. The Unit 2 inspections will be performed on or after June 13, 2013, 

but before midnight June 13, 2018. The staff finds the scope of the program adequate. 

Preventive or Mitigative Actions 

The applicant stated that the treated water systems piping inspections will be condition monitoring activities which utilize visual inspections to identify unacceptable age-related degradation within the 

applicable systems. Therefore, there are no preventive or mitigative attributes associated with this 

program nor did the staff identify a need for such. 

Parameters Inspected or Monitored 

The applicant stated that these one-time inspections will focus on determining whether there has 

been loss of material from, or cracking in, Class 1 and non-Class 1 carbon and stainless steels 

within the reactor water, torus water, demineralized water, closed cooling water, and borated water 

environments. Appropriate examination methods will be utilized, and inspection locations will be 

selected, on the basis of engineering judgement. The selection will include areas predicted to be 

most susceptible to corrosion, erosion-corrosion, erosion, and cracking. The staff finds the 

parameters inspected acceptable because appropriate examination methods will be employed to 

detect loss of material and cracking. 

Detection of Aging Effects 

The applicant stated that a one-time visual inspection of the sample set will be conducted using the 

best available examination method for the inspected component. Inspections may utilize an 

examination method similar to that described for VT-1 in ASME Section Xl, Paragraph IWA-221 0. 

Where possible and practical, accessible components may be inspected using volumetric 

examination methods. The staff finds that the detection of aging effects before there is a loss of 

intended function can be reasonably expected from the inspection program because of the adequate 

inspection scope, technique, and frequency. Satisfactory operating experience to date also supports 

this conclusion. 

Monitoring and Trending 

The applicant stated that periodic monitoring and trending of degradation for inspection locations 

will be established provided that the one-time inspection results indicate a concern that components 

may not be able to perform their intended function during the period of extended operation. Failures 

will be documented in accordance with the Plant Hatch corrective actions program. The staff finds

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this approach acceptable because it will provide predictability of the extent of degradation so timely 

corrective or mitigative actions are possible. 

Acceptance Criteria 

The applicant stated that any unacceptable indication of corrosion will be evaluated by further 

engineering analysis. Component wall thickness acceptability will be founded on the component 

design code of record. Cracks identified via visual examinations shall be further inspected via 

volumetric examinations for evaluation by engineering analysis. Corrective actions, if required, will 

be addressed through the existing Plant Hatch corrective actions program. 

The applicant stated that if components do not meet the acceptance criteria defined in the 

inspection procedure, they will be evaluated, repaired, or replaced before being returned to service. 

If a significant number of the initial sample population fail to meet the acceptance criteria, the 

sample population may be increased. If the applicable acceptance criteria are met for the sample 

population, expansion of the sample set will not be necessary. The staff finds this approach 

acceptable because any indication of components not meeting the pre-established acceptance 

criteria would require the applicant to implement corrective actions. 

Operating Experience 

The treated water system piping inspections will be a one-time activity. Thus, there is no operating 

experience directly associated with the treated water system piping inspection. The applicant 

stated, however, that a review of plant deficiency cards submitted over the past 5-years revealed 

no significant deficiencies in the in-scope treated water components as a result of age-related 

degradation. 

3.1.24.4 Conclusions 

The staff has reviewed the information in LRA Section A.3.2, "Treated Water Systems Piping 

Inspections," of the LRA and Section B.3.2, "Treated Water Systems Piping Inspections," of the 

applicant's October 10, 2000 submittal. On the basis of its review, the staff concludes that the 

applicant has demonstrated that the effects of aging associated with structures and components in 

systems managed by this program will be adequately managed so that intended functions will be 

maintained, consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

3.1.25 Gas Systems Component Inspections 

3.1.25.1 Introduction 

The applicant described the gas systems components inspections program in LRA Section A.3.3 

and Section B.3.3 of the applicant's October 10, 2000 submittal. The program is described under 

A.3 "New Programs and Activities" of the Final Safety Analysis Report Supplement. The program 

verifies that age-related degradation is not inhibiting component function in gas-bearing systems 

within the scope of license renewal. The staff reviewed this section of the application to determine 

whether the applicant has demonstrated that the effects of aging caused by the humid and wetted 

gas internal environment will be adequately managed during the period of extended operation, as 

required by 10 CFR 54.21 (a)(3).

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3.1.25.2 Summary of Technical Information in the Application

Section B.3.3 of the applicant's October 10, 2000 submittal describes the gas systems component 

inspection program, which implements condition monitoring with regard to age-related degradation 

of components having an internal environments of humid or wetted gas. Loss of material as a result 

of general corrosion in carbon steel, material property changes, and cracking in low-alloy and 

stainless steels are also likely to occur because of contaminants such as chlorides and oxygen in 

the presence of moisture. The applicant has included portions of the following systems within the 

scope of the gas systems component inspection program: nuclear boiler (comprising the safety relief 

valve tail pipes to the torus and the associated attached instrumentation valves and piping), CRD, 

RHR, HPCI, RCIC, sampling, EDG, primary containment, reactor building HVAC, standby gas 

treatment, primary containment purge and inerting, post-LOCA hydrogen recombiners, outside 

structure HVAC, fuel oil, and control building HVAC. 

The applicant's inspection program is a one-time inspection for condition monitoring that will provide 

objective evidence that the aging effects predicted for systems with gas as the internal environment 

are being adequately managed during the period of extended operation. Since loss of material 

attributable to general corrosion and cracking are associated with the presence of moisture and/or 

liquid pooling or wet/dry cycling, a sample population of components exposed to such an 

environmental condition at various temperatures will be inspected. In addition, certain external 

surfaces in gas-bearing components of the EDG, outside structure HVAC, and control building HVAC will also be included in the sample population. The gas systems component inspection will 

utilize an examination method similar to that described for VT-1 visual examination of the ASME 

Code, Section Xl, or a volumetric examination for condition monitoring. Any unacceptable indication 

of corrosion will be evaluated by engineering analysis. The applicant will implement corrective 

actions through the existing Plant Hatch corrective action program. 

3.1.25.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the gas systems piping inspection program to ensure that the applicable component aging effects will be managed so that 

system intended functions will be maintained consistent with the CLB for the period of extended 

operation. 

Program Scope 

Gas systems component inspections are one-time inspections of a given sample that are intended 

to provide objective evidence that the applicable aging effects are being adequately managed. The 

applicant has stated that it would provide for condition monitoring of the components in the systems 

with gases as internal environment within the scope of license renewal to determine whether age related degradation is being managed for the period of extended operation. This determination will 

be achieved by performing inspections of selected sample populations of gas system components 

exposed to moisture and/or liquid pooling or wet/dry cycling at various temperatures. The applicant 

has included portions of the following systems within the scope of the program: nuclear boiler 

(consisting of the safety relief valve tail pipes to the torus and the attached instrumentation tubing 

and valves), CRD, RHR, HPCI, RCIC, sampling, EDG, primary containment, reactor building HVAC, 

standby gas treatment, primary containment purge and inerting, post-LOCA hydrogen recombiners, 

outside structure HVAC, fuel oil, and control building HVAC. For Unit 1, the inspection will be

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performed on or after August 6, 2009, but before midnight August 6, 2014. Unit 2 inspection will be 

performed on or after June 13, 2013, but before midnight June 13, 2018. The staff finds the scope of the program to be acceptable because it covers the systems within license renewal that are 

susceptible to the aging effects of loss of material and cracking caused by the humid and wetted 

gas internal environments. 

Preventive or Mitigative Actions 

There are no preventive or mitigative attributes with this program. The staff did not identify the need 

for such attributes. 

Parameters Inspected or Monitored 

The gas systems component inspection will primarily ensure that the component wall thickness has 

not degraded to such an extent that the function of the component is inhibited. Appropriate 

examination methods will be utilized and inspection locations will be selected based on engineering 

judgement. The staff finds the parameters inspected to be acceptable. 

Detection of Aging Effects 

The inspection will utilize an examination method similar to that described for the VT-1 visual 

examination of the ASME Code, Section Xl, or a volumetric examination for condition monitoring. For those stainless steel components that normally operate at temperatures above 1400 F, and that 

contain wetted gases, volumetric examination may be used as part of the inspections to detect the 

presence of stress-corrosion cracking. The staff finds the method of detection of aging effects to 

be acceptable. 

Monitoring and Trending 

There are no monitoring and trending attributes with this program. The staff did not identify the 

need for such attributes. 

Acceptance Criteria 

The acceptance criterion will be based on the applicable sections of the design codes. The wall 

thickness inspection of unacceptable indications of corrosion will determine the loss of material due 

to general corrosion and assess the impact of this aging effect on other components in the balance 

of the plant included in the LRA. The program also requires that corrective actions be taken if any unacceptable indication of corrosion is detected. The staff finds that, as proposed by the applicant, 

an engineering analysis followed by implementation of specific corrective actions, as specified by the site-controlled corrective action program, will provide an acceptable technical basis for the 

management of the aging effects in the gas systems components. The staff finds the acceptance 

criteria to be satisfactory. 

Operating Experience 

The applicant reviewed records dating back 5 years on the in-scope gas system components, to 

determine deficiencies that inhibited component function, and did not find any deficiencies. However,

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because of the possibility of occurrence of this type of age-related degradation, it established a one

time inspection. 

3.1.25.4 Conclusions 

The staff has reviewed the information in LRA Sections A.3.3 and Section B.3.3 of the applicant's 

October 10, 2000 submittal. On the basis of this review, the staff concludes that the applicant has 

demonstrated that the inspection program will adequately manage aging effects associated with the 

gas system components in a humid and wetted environment for the period of extended operation, 

as required by 10 CFR 54.21 (a)(3). 

3.1.26 Condensate Storage Tank Inspection 

3.1.26.1 Introduction 

The applicant described its CST inspection in LRA Section A.3.4 and Section B.3.4 of the applicant's 

October 10, 2000 submittal. The staff reviewed these sections to determine whether the applicant 

has demonstrated that the structures and components managed by the condensate storage tank 

inspection will be adequately managed during the period of extended operation as required by 10 

CFR 54.21 (a)(3). 

3.1.26.2 Summary of Technical Information in the Application 

The applicant stated in the LRA that the CST inspection is a one-time condition monitoring 

inspection of each CST designed to provide objective evidence that no unacceptable degradation 

is occurring. The internal surfaces of each CST will be examined to verify that age-related 

degradation is not occurring. The examination will focus on the standpipes and the connections 

between aluminum standpipes and galvanized steel flanges, since these locations would be the 

most susceptible to corrosion. This inspection is intended to validate the adequacy of current 

demineralized water chemistry controls to manage aging effects. 

3.1.26.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the CST inspection 

program to ensure that the applicable component aging effects will be managed so that system 

intended functions will be maintained consistent with the CLB for the period of extended operation. 

Program Scope 

The CSTs are part of the condensate transfer and storage system. The staff agrees with the 

applicant that only those CST components required to ensure the availability of 100,000 gallons of 

water for HPCI and RCIC system operation are within the scope of license renewal and therefore 

the CST inspection. Therefore, the staff finds the applicant's scope, as indicated in the application, 

to be appropriate and acceptable.

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Preventive or Mitigative Actions

The CST inspection is a condition monitoring activity that utilizes visual inspections to identify 

unacceptable corrosion within the CSTs. As such, there are no preventive or mitigative attributes 

associated with this program, nor did the staff identify a need for such. 

Parameters Inspected or Monitored 

The Plant Hatch Unit 1 CST is fabricated from aluminum alloy structural shapes, pipe, and plate. Nozzle flanges on the Unit 1 CST are fabricated from galvanized carbon steel. Visual inspection 

on the Unit 1 tank will focus on selected areas associated with the standpipes, associated supports, 

and nozzles. 

The Unit 2 CST is fabricated entirely from austenitic stainless steel. Visual inspection of the Unit 2 

tank will focus on selected areas associated with the standpipes, associated supports, and nozzles. 

Inspection locations will be determined on the basis of engineering judgement, and will include areas 

predicted to be most susceptible to corrosion, such as weld heat affected zones and crevices. The 

applicant indicated that detailed visual inspections are adequate to detect localized corrosion. The 

applicant also stated that if significant degradation is identified, actions will be taken by the 

corrective actions program to repair the degraded components and implement any additional 

inspections that may be warranted. The staff finds that monitoring these parameters are adequate 

and sufficient to mitigate age-related degradation of the systems and components exposed to CST 

internal environments. 

Detection of Aging Effects 

The CST inspection will utilize visual inspection techniques, including lighting and resolution 

requirements, that are similar to the VT-1 provisions in ASME Code recommendations to detect 

unacceptable corrosion. The applicant also indicated, as stated above, that if significant 

degradation is identified, actions will be taken by the corrective actions program to repair the 

degraded components and implement any additional inspections that may be warranted. The staff 

finds this approach acceptable. 

Monitoring and Trending 

The CST inspection is a one-time inspection, designed to validate the adequacy of the 

demineralized water chemistry control in minimizing corrosion. Therefore, monitoring and trending 

is not addressed by the applicant for this AMP, nor did the staff identify a need for such. 

Acceptance Criteria 

Unacceptable indications of corrosion will be further evaluated by engineering analysis, and, if 

warranted, additional inspections will be performed. Corrective actions, if required, will be 

addressed through the existing Plant Hatch corrective actions program. The staff finds this 

approach acceptable.

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Operating Experience

The applicant indicated that, from a review of its plant deficiency records over the past 5 years, no 

age-related deficiencies of in-scope CST surfaces were found. The CST inspection will be a new 

one-time inspection activity. Therefore, there is no operating experience directly associated with 

the CST inspection, nor does the staff identify a need for such. 

3.1.26.4 Conclusions 

The staff has reviewed the information in LRA Section A.3.4 and Section B.3.4 of the applicant's 

October 10, 2000 submittal. On the basis of its review, the staff concludes that the applicant has 

demonstrated that the effects of aging associated with structures and components managed by the 

condensate storage tank inspection will be adequately managed so that intended functions will be 

maintained, consistent with the current licensing basis, for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.1.27 Passive Component Inspection Activities 

3.1.27.1 Introduction 

The applicant described the passive component inspection activities in LRA Section A.3.5 and 

Section B.3.5 of the applicant's October 10, 2000 submittal. The program verifies the effectiveness 

of preventive or mitigative programs/activities credited for aging management. The staff reviewed 

this section of the application to determine whether the applicant has demonstrated that the effects 

of aging will be monitored and adequately managed by the passive component inspection activities 

during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

3.1.27.2 Summary of Technical Information in the Application 

In LRA Sections A.3.5 and Section B.3.5 of the applicant's October 10 2000 submittal, the applicant 

described the passive component inspection activities, a new program for condition monitoring 

inspection to confirm that, for gas-bearing in-scope systems and components, age-related 

degradation is not inhibiting component function. Loss of material and cracking are the aging 

effects that will be monitored by the passive component inspection activities. The applicant has 

included portions of various systems within the scope of the passive components inspection 

activities, including the nuclear boiler (safety relief valve tail pipes to the torus), control rod drive, 

residual heat removal (including buried or embedded components), high-pressure coolant injection, 

reactor core isolation cooling, plant service water (including buried or embedded components), 

emergency diesel generator (starting air and engine exhaust), primary containment (including the 

drain lines for the drywell sump discharge), reactor building HVAC, standby gas treatment (including 

buried or embedded components), primary containment purge and inerting, post-LOCA hydrogen 

recombiners, outside structure HVAC, fire protection (including buried or embedded components), 

fuel oil (including buried or embedded components), and control building HVAC (including gaskets). 

In LRA Section B.3.5 of the applicant's October 10, 2000 submittal, the applicant stated that the 

passive component inspection activities will be a set of on-going condition monitoring inspections 

that will provide objective evidence that the aging effects predicted for in-scope systems are being 

adequately managed during the period of extended operation. The passive component inspection 

activities will be invoked when the normally inaccessible surfaces of these components are made

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available for inspection as a result of maintenance and other activities. The preferred inspection 

sites will be those locations in the in-scope components where liquid pooling or wet/dry cycling is 

most likely to occur during normal operation. In addition, certain external surfaces of buried or 

embedded components of residual heat removal, plant service water, standby gas treatment, fire 

protection, and fuel oil systems will also be included in the inspection. The passive component 

inspection activities will utilize an examination method similar to that described for VT-1 visual 

examination of the ASME Code, Section Xl or a volumetric examination for condition monitoring and 

will identify aging effects before any loss of intended function. Any unacceptable indication of 

corrosion will be evaluated by engineering analysis. The applicant will implement corrective actions 

through the existing Plant Hatch corrective action program. 

3.1.27.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicanfs LRA regarding the applicant's demonstration of the passive component 

inspection activities to ensure that the applicable component aging effects will be managed so that 

system intended functions will be maintained consistent with the CLB for the period of extended 

operation. 

Program Scope 

In response to RAI 3.1.27-1, the applicant listed the systems and components covered by the 

passive component inspection activities program in Section B.3.5 of the applicant's October 10, 

2000 submittal. The program provides for condition monitoring of predominantly gas bearing in

scope systems and components to confirm that age-related degradation is not inhibiting component 

function. In addition to piping, this activity will include the internal and external surfaces of other 

passive components, such as valve bodies, ducts, and strainers. Piping and valves between the 

drywell sump and the liquid radwaste system are also included in the scope of the passive 

component inspection activities. These pipes and valves serve as part of the primary containment 

and are not otherwise in-scope for license renewal. The passive component inspection activities 

will also be used for aging management of gaskets associated with the control building HVAC 

system. The passive component inspection activities will be invoked when the normally inaccessible 

surfaces of these components are made available for inspection as a result of maintenance and 

other activities. The staff finds that the scope of the passive component inspection activities 

program is acceptable since it includes condition monitoring inspection of all in-scope systems. 

Preventive or Mitigative Actions 

There are no activities in the passive component inspection activities program for preventive or 

mitigative actions and the staff did not identify the need for such actions. 

Parameters Inspected 

In response to RAI 3.1.27-1, the applicant, in Section B.3.5 of the applicant's October 10, 2000 

submittal, stated that the passive component inspection activities will primarily ensure that the 

component wall thickness has not degraded such that component function is inhibited, and for 

gaskets, the passive component inspection activities will inspect for the presence of cracks or 

degradation. The staff finds that the inspected parameters will be adequate for identifying loss of 

material or cracking during the period of extended operation.

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Detection of Aging Effects

In LRA Section A.3.5, the applicant stated that the passive component inspection activities will 

include a baseline examination of the in-scope components, as they become available as a result 

of normal maintenance activities. The applicant further stated that the inspection will utilize an 

examination method similar to that described for the VT-1 visual examination of the ASME Code, 

Section Xl, paragraph IWA-2210, to detect corrosion of metallic components and material property changes and cracking of gaskets. The applicant also stated that liquid penetrant (PT) examinations, 

or other suitable methods dictated by the situation for the affected component, will be used to detect 

discontinuities open to the component surface. In response to RAI 3.1.27-1, in Section B.3.5, the 

applicant stated that, where possible and practical, accessible components will be inspected for 

stress corrosion cracking using volumetric examination methods. The staff finds that the 

applicants's examination methods will be adequate for detecting loss of material or cracking during 

the period of extended operation. 

Monitoring and Trending 

In response to RAI 3.1.27-1, the applicant, in Section B.3.5 of the applicant's October 10, 2000 

submittal, stated that the passive component inspection activities program will be designed to 

collect, report, and trend age-related data. These inspections will assist in the early discovery of 

aging effects so that timely corrective actions may be taken before the effects inhibit component 

functions. The staff finds that these monitoring activities are adequate to ensure that corrective 

actions will be taken before exceeding the acceptance criteria. 

Acceptance Criteria 

In response to RAI 3.1.27-1, the applicant, in Section B.3.5 of the applicant's October 10, 2000 

submittal, stated that any unacceptable indication of corrosion will be evaluated by further 

engineering analysis and the component wall thickness acceptability will be founded upon the 

component design code of record. If the gasket exhibits cracking or a change in material properties, then corrective action will be taken through the existing Plant Hatch corrective action program. The 

staff finds the applicant's acceptance criteria specified above are adequate to ensure that the 

intended functions of in-scope systems are maintained during the period of extended operation. 

Operating Experience 

The passive component inspection activities program is a new program; thus, the applicant did not 

submit plant-specific operating experience. However, in response to RAI 3.1.27-1, the applicant, in Section B.3.5, stated that its review of plant deficiency cards over the past 5-years showed that 

age-related deficiencies that inhibited component function were not written on components within 

the scope of passive component inspection activities. The staff finds that operating experience is 

satisfactorily incorporated into the development of the program. 

3.1.27.4 Conclusions 

The staff has reviewed the information in LRA Section A.3.5, "Passive Component Inspection Activities," and Section B.3.5 of the applicant's October 10, 2000 submittal. On the basis of this 

review, the staff concludes that the applicant has demonstrated that the inspection program will 

provide adequate assurance that in-scope components that are susceptible to aging effects that

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require management will be inspected for age-related degradation during the period of extended 

operation. 

3.1.28 RHR Heat Exchanger Augmented Inspection and Testing Program 

3.1.28.1 Introduction 

The applicant described its RHR heat exchanger augmented inspection and testing program in LRA 

Sections A.3.6, "RHR Heat Exchanger Augmented Inspection and Testing Program," C.2.2.1 1, 

"Non-Class 1 Heat Exchanger Evaluation;" and Section B.3.6 of the applicant's October 10, 2000 

submittal. The applicant credits this inspection and testing program with managing, in part, aging 

effects for the RHR heat exchanger components used to remove heat from the reactor vessel or 

suppression pool. The staff reviewed the application to determine whether the applicant has 

demonstrated that the RHR heat exchanger augmented inspection and testing program will 

adequately manage aging effects, in conjunction with other AMPs, during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.1.28.2 Summary of Technical Information in the Application 

In Section A.3.6. of the LRA and Section B.3.6 of the applicant's October 10, 2000 submittal, the 

applicant describes the RHR heat exchanger augmented inspection and testing program, which 

manages, in part, the aging effects on carbon steel, stainless steel, and stainless steel-clad carbon 

steel components exposed to multiple fluid environments. The heat exchanger components 

managed by this AMP are: tubes; shell; shell nozzles and shell internals; channel assembly 

(including channel head, water box, and partition plate); tube sheet; and impingement plate. 

3.1.28.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the LRA regarding the applicant's demonstration that the RHR heat exchanger 

augmented inspection and testing program will ensure that the applicable component aging effects 

will be managed so that system intended functions will be maintained consistent with the CLB for 

the period of extended operation. 

Program Scope 

The RHR heat exchanger augmented inspection and testing program is applied to the residual heat 

removal system heat exchangers, which includes components made of carbon steel, stainless steel, 

and stainless steel-clad carbon steel. The staff finds this scope to be appropriate and acceptable. 

Preventive or Mitigative Actions 

The RHR heat exchanger augmented inspection and testing program is designed to mitigate and 

prevent age-related degradation (flow blockage and loss of thermal performance) through inspection 

and cleaning of the tubes and channel interior every 3 cycles. These actions prevent buildup of 

debris inside the tubes and the channel interior. This program satisfies one of the requirements of 

Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and 

implements guidance found in SAND 93-7070.UC-523, "Aging Management Guideline for 

Commercial Nuclear Power Plants - Heat Exchangers (DOE, July 1984)." The operating history

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shows that, as recently as 1996, leakage was detected in the heat exchangers. The staff had 

concerns with the leakage identified in 1996, which may have been attributable to vibration-induced 

cracking. (See Open Item 3.1.28-1, below.) 

This program works in conjunction with the pit and diving inspection activities of the PSW and 

RHRSW Inspection Program. These activities provide for inspection and removal of sediment in 

the pump suction pit to prevent or minimize flow blockage and loss of material. 

The staff finds it appropriate and acceptable to perform heat exchanger tube inspection and 

cleaning to prevent flow blockage and loss of thermal performance. These actions, in conjunction with the removal of sediment from the suction pit, prevent or minimize flow blockage and loss of 

material. 

Parameters Inspected or Monitored 

The LRA states that the RHR heat exchanger augmented inspection and testing program monitors 

loss of material, flow area reduction, and cracking. Specifically, the LRA states that visual 

inspections of the internal surfaces of the heat exchanger channel and shell sides are performed 

at scheduled intervals. In addition, eddy current testing and leak testing are performed at scheduled 

intervals, and whenever leaks are suspected in tubes and/or tube sheets. 

The staff finds that the visual inspections of the heat exchanger channel and shell sides are 

adequate and appropriate for identifying and removing buildup on the tubes to manage loss of 

material attributable to general corrosion. 

Detection of Aging Effects 

The LRA states that the RHR heat exchanger augmented inspection and testing program currently 

includes visual inspection of the channel side and tube interior every three cycles and inservice 

inspection of the shell welds and base material at prescribed frequencies. In addition, this program will be augmented to include eddy current testing; visual inspection of the shell side of tube sheets, 

internals, and impingement plates; and tube and tube sheet leak testing. 

The staff finds the methods discussed above appropriate and acceptable since these methods allow 

for early detection of aging effects. 

Monitoring and Trending 

The LRA states that the RHR heat exchanger augmented inspection and testing program includes 

visual inspection of the channel side and tube interior every three cycles. Eddy current testing will 

be performed at least once per 10-year inspection interval, and when leaks are suspected. Visual 

inspection of the shell side internals will also be performed once every 10-year inspection interval, 

where accessible. Tube and tube sheet leak testing will be performed whenever leaks are 

suspected. However, the bases for these frequencies was not clear (see Open Item 3.1.28-1, 

below). 

Corrective actions are implemented through the corrective actions program and frequency of 

inspection or testing may be adjusted on the basis of observed trends. The LRA further states that 

if the monitored parameters fall below the acceptance criteria, repair and/or replacement is

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performed before returning the component to service, unless an engineering analysis allows 

continued operation. 

On the basis of the information above, and on satisfactory resolution of the open item below, the 

staff finds that the frequencies of monitoring and trending of the stated parameters are acceptable 

and appropriate to ensure that the aging effects of components within the scope of the program are 

managed. 

Acceptance Criteria 

The LRA states that measured or recordable values of the inspected or monitored parameters shall 

not fall below the acceptable values for inspection locations and inspection criteria, as defined by the program. The staff requested that the applicant provide additional information with regard to the 

inspection locations (see Open Item 3.1.28-1, below). 

On the basis of the information above, and on satisfactory resolution of the open item below, the 

staff finds that the acceptance criteria are adequate and appropriate. 

Operating Experience 

The LRA states that a review of the applicant's condition reporting database revealed one significant 

event in 1996. At this time, a sample taken from an RHRSW drain valve contained nuclides and, 

as a result, a helium leak test and eddy current test were performed on the 1 El 1 -B001 B RHR heat 

exchanger. The testing identified possible leakage in nine heat exchanger tubes. Subsequent inspection revealed that, other than the leaking tubes, the tube bundle was in good condition. The 

nine suspected tubes were plugged. The applicant noted that dents were found at the tube-to-tube 

support connections of many tubes and may have been indicative of tube vibration. The staff 

requested that the applicant provide additional information regarding the leakage (see Open Item 

3.1.28-1, below). 

However, since no exact cause of the tube leakage was identified, and because the damaged areas 

were minor, no corrective actions were required. Eddy current testing performed on 1 El1-BO01A 

during Spring 1999 and on 2E1 1 -B001 B during September/October 1998, did not identify any significant deterioration of the tubes. No tube leaks for other RHR heat exchangers occurred during the 5-year period. The staff requested that the applicant provide additional information regarding 

industry experience and the bases for the inspection schedule for the RHR heat exchangers (see 

Open Item 3.1.28-1, below). 

On the basis of the information above, and on satisfactory resolution of the open item below, the 

staff concludes that the applicant has adequately considered the plant-specific and industry-wide 

operating experience related to the RHR heat exchangers in developing the RHR heat exchanger 

augmented inspection and testing program. 

The staff was concerned about cracking in the RHR heat exchangers. The RHR heat exchanger 

augmented inspection and testing program description was unclear regarding its ability to manage vibration-induced cracking. Therefore, in order to ascertain whether this AMP is adequate to 

manage vibration-induced cracking, the staff requested that the applicant provide additional 

information. The requested information is summarized below, and was identified as Open Item 

3.1.28-1.

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A. The applicant should provide information on the inspection methods, frequencies, acceptance criteria, and associated bases, which are used to detect vibration-induced 

cracking. 

B. The applicant should provide information regarding the leakage identified in 1996, including the analyses conducted that determined the cause of the leakage, the operational changes 

or component modifications that were instituted in response to the leakage, and additional 

programs which were developed and credited for managing vibration-induced cracking. 

C. The LRA states that measured and recordable values of the inspected or monitored 

parameters shall not fall below acceptable values for defined inspection locations. The 

applicant should identify the inspection locations, and the inspection criteria used to 

determine inspection locations, and their bases. 

D. The LRA states that a sample taken from an RHRSW drain valve contained nuclides and 

as a result, testing was performed on one of the Unit 1 RHR heat exchangers. Dents were 

found at a number of tube-to-tube support connections and the dents may indicate tube 

vibration. The applicant should provide the basis for its determination that the dents may have been caused by tube vibration, as opposed to localized corrosion. In addition, the 

applicant should provide information regarding industry experience related to the bases and 

criteria of the inspections credited in the RHR heat exchanger augmented inspection and 

testing program. 

By letters dated October 10, 2000 and June 5, 2001, the applicant provided additional information 

related to the staff's concerns regarding vibration-induced cracking in the RHR heat exchangers. The applicant stated that there is no site or industry operating experience indicating that vibration

induced fatigue cracking is an active mechanism in the RHR heat exchangers. However, the RHR 

heat exchanger augmented inspection and testing program provides for inspection activities capable of detecting significant tube damage or throughwall leakage that could result from potential vibration-induced damage. The program includes the following: 

A. eddy current testing (minimum of 10 percent of the operational tubes) once during each 10 

year inspection period to determine the overall condition of the heat exchanger tubes 

B. leak testing to quantify leaks in the tubes or tubesheets 

C. general visual inspection of the channel side of the heat exchanger every three operating cycles to include visible portions of the tubesheets and tubes 

D. general visual inspection of the shell side of the heat exchanger once during the ten year interval to include a representative portion of the tube bundle, tube supports, tube-to

tubesheet interface, and baffles. 

The testing frequency is based on a combination of satisfactory results of eddy current tests 

performed on three heat exchangers and on heat exchanger design margin. Except for one tube 

in one heat exchanger, the condition of the tubes in all three heat exchangers was found to be free 

of damage. Also, the heat exchanger transfer surface area is oversized by at least 5 percent to 

provide sufficient margin if tubes need to be plugged. On the basis of the satisfactory test results,

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along with the excessive heat transfer capacity, the staff concludes that the equipment will perform 

its intended function between inspections. 

In addition, identification of crack indications by inspection personnel are subject to appropriate 

engineering evaluation. Areas that are unavailable for inspection due to inability to pass the eddy 

current probe are noted on the inspection report. 

The applicant also provided information regarding the RHR heat exchanger tube leakage identified 

in 1996. The leakage was suspected due to detection of radionuclides in the RHRSW system. In 

October 1997, eddy current testing identified nine tubes, including one leaking tube, with significant 

damage. As a result, all nine tubes were plugged. Although no direct evidence of service-induced 

damage was identified, a follow-up inspection was recommended. In October 2000, eddy current 

inspections were performed on all heat exchanger tubes, except those plugged in October 1997. 

The result of this inspection did not reveal any accelerated degradation indicators and concluded 

that there was no evidence of any active service-induced degradation. 

The staff requested that the applicant provide details regarding the denting found on a number of 

tube-to-tube support connections. In response, the applicant stated that denting, as referred to in 

the submitted operating history on the heat exchanger, is indicative of the tube roundness. Though 

tube dents can be service-induced, the denting is often the result of fabrication flaws from bending 

or insertion. In addition, based on the October 2000 inspection results, no evidence exists to 

support localized corrosion or vibration as a significant factor in the tube dents identified. 

On the basis of the additional information provided by the applicant, the staff concludes that this new 

inspection program provides a variety of methods to manage the aging effects associated with the 

RHR heat exchangers. In addition, the staff finds that the most recent inspection results obtained 

through the techniques emcompassed by this program support the applicant's conclusion that 

localized corrosion or vibration is not a significant factor in the tube dents identified. 

On the basis of the information provided by the applicant and the staff's evaluation of this 

information, the staff concludes that the RHR heat exchanger augmented inspection program is 

adequate and appropriate to manage the aging effects associated with the RHR heat exchangers. 

Open Item 3.1.28-1 is closed. 

3.1.28.4 Conclusions 

The staff has reviewed LRA Sections A.3.6, "RHR Heat Exchanger Augmented Inspection and 

Testing Program;" and C.2.2.11, "Non-Class 1 Heat Exchanger Evaluation," and Section B.3.6 of 

the applicant's October 10, 2000 submittal. On the basis of its review, the staff has determined that 

the RHR heat exchanger augmented inspection and testing program activities will adequately 

manage the aging effects in the RHR heat exchangers, as required by 10 CFR 54.21 (a)(3). 

3.1.29 Torus Submerged Components Inspection Program 

3.1.29.1 Introduction 

The applicant described its torus submerged components inspection program in LRA Section A.3.7. 

The applicant supplemented the description of this AMP in Section B.3.7 of its October 10, 2000 

submittal. The applicant credits this inspection program with managing, in part, aging effects for

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a variety of stainless steel and uncoated steel structures and components that are exposed to the 

suppression pool environment. The staff reviewed the application to determine whether the 

applicant has demonstrated that the torus submerged components inspection program will 

adequately manage aging effects during the period of extended operation as required by 10 CFR 

54.21 (a)(3). 

3.1.29.2 Summary of Technical Information in the Application 

In LRA Section A.3.7 and Section B.3.7 of the October 10, 2000 submittal, the applicant describes 

a new aging management program, the torus submerged components inspection program, that 

manages, in part, aging effects for various structures and components exposed to the suppression 

pool environment. The affected systems include the high pressure coolant injection, primary 

containment purge and inerting, nuclear boiler, residual heat removal, core spray, and reactor core 

isolation cooling. The applicant lists the specific systems, structures, and components in LRA 

Section 3.2. These structures and components are fabricated from either uncoated carbon steel 

or stainless steel. 

As discussed in LRA Section C.1.2.2, loss of material is an applicable aging effect that may affect 

both carbon steel and stainless steel components through several corrosion mechanisms. These 

mechanisms include general corrosion, galvanic corrosion, crevice corrosion, pitting, and MIC. The 

applicant also considers cracking to be an applicable aging effect that may affect specific stainless 

steel components as a result of stress corrosion cracking or intergranular attack. The applicant 

plans to implement the torus submerged components inspection program to provide direct evidence 

to validate the adequacy of the current suppression pool chemistry controls to mitigate corrosion

related aging effects on specific stainless steel and uncoated carbon steel structures and 

components. The program will be implemented by midnight August 6,2014, for Unit 1 and midnight 

June 13, 2018, for Unit 2. 

The suppression pool water (also called "torus water" in the LRA) contained within the torus consists 

of demineralized water supplied from demineralized water sources (such as the condensate storage 

tank). The applicant relies on chemistry controls to mitigate aging attributable to corrosion in 

structures and components exposed to the suppression pool water by controlling the water purity and composition. To supplement this water chemistry program, the applicant will implement the 

torus submerged components inspection program to provide direct confirmation of the effectiveness 

of the suppression pool chemistry controls. The applicant will perform visual inspections of 

accessible stainless steel and uncoated carbon steel components submerged in suppression pool 

water to detect evidence of loss of material and cracking. 

3.1.29.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the torus submerged 

components inspection program to ensure that the applicable component aging effects will be 

managed so that system intended functions will be maintained consistent with the CLB for the period 

of extended operation.

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Program Scope

The applicant stated in LRA Section B.3.7 of the applicant's October 10, 2000 submittal that the 

scope of this program included structures and components within the nuclear boiler system, residual 

heat removal system, core spray system, high pressure coolant injection system, reactor core 

isolation cooling system, and primary containment purge and inerting system. In a letter dated 

January 31, 2001, the applicant provided additional information regarding the program scope of the 

torus submerged component inspection program. The initial inspection scope will consist of a 

sample set of approximately 10 percent of the uncoated components located within the torus. This 

initial population would be biased toward the areas that are most likely to exhibit corrosion-related 

degradation. These locations include austenitic stainless steel welds and weld heat affected zones, 

crevices, areas potentially covered by debris or sludge, and dissimilar metal connections or mating 

surfaces. The sample set may also include inspection points above the suppression pool water level 

because the "splash zone" can be a susceptible area. The sample size for subsequent inspections 

may be revised on the basis of the initial inspection results. The staff considers an initial sample 

size of 10 percent large enough to provide a reasonable indicator of the general condition of the 

uncoated structures and components exposed to the suppression pool water environment. In 

addition, that initial sample will be biased toward those locations that are considered to be most 

susceptible to localized corrosion. The staff also finds it reasonable to revise subsequent 

inspections on the basis of initial inspection results. Therefore, the staff finds that the scope of the 

torus submerged component inspection program is acceptable. 

Preventive or Mitigative Actions 

There are no preventive or mitigative actions taken as part of this program, and the staff did not 

identify the need for such actions. 

Parameters Inspected or Monitored 

The applicant performs visual inspections of specific uncoated carbon and stainless steel structures 

and components using an examination method similar to VT-1 in ASME Section Xl, paragraph IWA

2210, or other suitable method, as dictated by the component configuration. The staff finds visual 

inspections generally adequate for identifying loss of material. However, the staff finds visual 

inspections not sensitive enough to detect the early stages of stress corrosion cracking. In LRA 

Section C.1.2.2.2 the applicant stated that stainless steel components in the HPCI and RCIC turbine 

discharge headers inside the torus may be susceptible to SCC. The staff requested that the 

applicant discuss how it manages this aging effect. In it's response to RAI 3.1.29-7, dated October 

10, 2000, the applicant stated that the postulation that certain stainless steel components 

submerged in the suppression pool could experience SCC was very conservative. The staff agrees 

this is a very conservative assumption given the operating conditions and industry experience to 

date. In addition, because the function of the HPCI and RCIC turbine discharge headers is to direct 

exhaust steam into the suppression pool, only advanced and extensive SCC would have an impact 

on this function. The applicant stated that such significant cracking would be visible to the unaided 

eye. Given the very unlikely occurrence of SCC or IGA, and the fact that only advanced and 

extensive SCC or IGA must be present to impact the intended functions of these particular 

components, the staff finds that the use of VT-1 quality visual examinations is sufficient to detect 

degradation before it impacts intended functions.

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Detection of Aging Effects 

To ensure that aging effects are identified before there is a loss of intended function, the staff relies 

on an adequate program scope, appropriate monitoring of parameters, and appropriate frequency 

interval. The program scope and parameter monitoring is discussed above. With respect to 

frequency, the applicant stated that the first inspections will be implemented by midnight August 6, 

2014 for Unit 1, and midnight June 13, 2018 for Unit 2. These dates coincide with the end of the 

current operating period. The staff finds this inspection schedule acceptable. The staff did not 

identify a need for a specific commitment from the applicant to perform the inspection at a particular 

time. Recognizing that there are both advantages and disadvantages to performing inspections 

earlier rather than later in the time period following approval of the renewed license, the staff 

accepts the applicant's general commitment to complete the inspection before the current operating 

license expires. The environment is not particularly corrosive, and the system design is robust; on 

this basis, the staff concludes that system intended functions should remain intact. The applicant 

will base subsequent inspection frequencies on the engineering evaluation of results from this first 

inspection. In summary, the staff finds that the torus submerged components inspection program 

has an adequate inspection scope, uses adequate inspection techniques, and has an adequate inspection schedule. Thus, it may be relied upon to provide reasonable assurance that aging effects 

will be detected before there is a loss of intended function. 

Monitoring and Trending 

The applicant stated that results from the baseline inspections will be assessed to determine the 

scope and the frequency of subsequent inspections. This is acceptable to the staff because it is 

reasonable to base the need for future inspections on the baseline inspection results. 

Acceptance Criteria 

The applicant stated in its letter of January 31, 2001, that any indication of corrosion, if judged to 

be significant by the inspection personnel, will be evaluated by an engineering analysis and, if 

warranted, additional inspections will be performed. The applicant indicated that inspectors are 

trained to question acceptability on initial identification of conditions that might warrant further 

evaluation or correction. Engineering evaluations of component acceptability are consistent with 

the design code of record, if applicable. The staff finds this approach reasonable and consistent 

with current industry practice and therefore acceptable. 

Operating Experience 

The torus submerged components inspection program is a new program; thus, the applicant did not 

submit plant-specific operating experience. However, industry experience to date supports the 

attributes of the applicant's program. Thus, the staff finds that operating experience is satisfactorily 

incorporated into the development of this new program. In addition, the applicant has been 

performing regular inspections of the torus as part of its protective coatings program and did not 

identify any significant degradation associated with corrosion. 

3.1.29.4 Conclusions 

The staff has reviewed the information in LRA Sections A.3.7, 'Torus Submerged Components Inspection Program," Section B.3.7 of the applicant's October 10, 2000 submittal, and information

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provided by letter dated January 31,2001. On the basis of this information, the staff concludes that 

the applicant has demonstrated that the torus submerged components inspection program will 

adequately manage, as a supplement to the suppression pool chemistry controls, aging effects 

associated with the suppression pool water environment for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

3.1.30 Insulated Cables and Connections Aging Management Program 

3.1.30.1 Introduction 

The applicant described its insulated cables and connections aging management program in a letter 

dated January 31, 2001. The staff reviewed the letter to determine whether the applicant has 

demonstrated that the insulated cables and connections aging management program will adequately 

manage aging effects during the period of extended operation as required by 10 CFR 54.21 (a)(c). 

3.1.30.2 Summary of Technical Information in the Application 

In the letter dated January 31, 2001, the applicant described the insulated cables and connections 

aging management program as a condition monitoring program designed to confirm that age-related degradation is not inhibiting component function of insulated cables and connections within the 

scope of license renewal during the period of extended operation. The scope of this program includes accessible and inaccessible insulated cables within the scope of license renewal that are 

installed in an adverse, localized environment which is defined as a condition in a limited plant area 

that is significantly more severe than the specified service condition for the equipment. 

3.1.30.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding the applicant's demonstration of the insulated cables and 

connections AMP to ensure that the applicable component aging effects will be managed so that 

system intended functions will be maintained consistent with the CLB for the period of extended 

operation. 

Program Scope 

The applicant stated that the program includes accessible and inaccessible insulated cables within 

the scope of license renewal that are installed in adverse, localized environments in the primary 

containment structure, reactor building, radwaste building, diesel generator building, turbine building, control building, intake structure, and main stack, which could be subject to applicable aging effects 

from heat or radiation. This program does not include cables and connections that are in the 10 

CFR 50.49 Environmental Qualification program. An adverse, localized environment is defined as 

a condition in a limited plant area that is significantly more severe than the specified service 

condition for the equipment. An applicable aging effect is an aging effect that, if left unmanaged, 

could result in the loss of a component's license renewal intended function in the period of extended 

operation. 

On the basis of the information provided in the letter dated January 31, 2001, the staff concludes 

that the applicant adequately identified the accessible and inaccessible locations for insulated cables 

and connections within the scope of the aging management program.

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Preventive or Mitigative Actions

Accessible insulated cables and connections installed in adverse, localized environments will be 

visually inspected for jacket surface anomalies such as embrittlement, discoloration, cracking or 

surface contamination. Surface anomalies are indications that can be visually monitored to preclude 

the conductor insulation applicable aging effect. 

Inaccessible insulated cables and connections will be tested. The specific type of test performed 

will be determined before each test. 

The staff finds that the different methods used for accessible and inaccessible cables and 

connections to be sufficient to detect degradation before it impacts intended functions. 

Parameters Inspected or Monitored 

The applicant stated that change in material properties of the conductor insulation is the applicable 

aging effect and changes in material properties managed by this program are those caused by 

severe heat or radiation (conditions that establish an adverse, localized environment). The staff 

finds the visual examinations and testing to be sufficient to detect changes in material properties 

before they result in degradation that may impact intended functions. 

Detection of Aging Effects 

Accessible insulated cables and connections installed in adverse, localized environments will be 

inspected at least once every 10 years. Inaccessible cables and connections will be tested at least 

once every 10 years. Samples may be used for this program and if used, an appropriate sample 

size will be determined before the inspection or test. 

Following issuance of a renewed operating license for Plant Hatch, the initial inspections and tests 

will be completed by the end of the initial license term for each unit (August 6, 2014 for Unit 1 and 

June 13, 2018 for Unit 2). 

The staff finds that the insulated cables and connections aging management program has an 

adequate inspection schedule regarding the detection of aging effects such that it provides reasonable assurance that the aging effects will be detected before there is a loss of intended 

function. 

Monitoring and Trending 

The applicant stated that for accessible and inaccessible insulated cables and connections, the 

monitoring and trending activities will be defined by the specific type of inspection (visual or testing) 

to be performed. Plant Hatch procedures require that deficiencies discovered during the 

performance of the program activities be documented in accordance with the condition reporting 

process. Chapter 17 of the Unit 2 UFSAR is part of the Plant Hatch QA program and describes the 

corrective action process. 

The staff finds that it is acceptable to base the monitoring and trending activities on the specific type 

of inspection to be performed on the accessible and inaccessible insulated cables and connections.

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Acceptance Criteria

The applicant stated that for accessible insulated cable and connections installed in adverse, 

localized environments, the acceptance criterion is no unacceptable, visual indications of jacket 

surface anomalies, which suggest that conductor insulation applicable aging effects may exist, as 

determined by engineering evaluation. An unacceptable indication is defined as a noted condition 

or situation that, if left unmanaged, could lead to a loss of the license renewal intended function. 

For inaccessible insulated cables and connections, the acceptance criteria for the test will be defined 

by the specific type of test to be performed and the specific type cable to be tested. 

The staff concludes that the applicant has identified acceptance criteria for accessible insulated 

cables and connections and will identify acceptance criteria for inaccessible insulated cables and 

connections (depending on the test and cable chosen) which will support the detection and 

evaluation of aging effects such that the intended functions for the insulated cables and connections 

will remain intact.. 

Corrective Actions 

The applicant stated that when the acceptance criteria are not met on accessible and inaccessible 

insulated cables and connections, further investigation by engineering will be performed. This will 

be done in order to ensure that the license renewal intended functions will be maintained consistent 

with the current licensing basis. Corrective actions may include, but are not limited to, testing, 

shielding or otherwise changing the environment, relocation or replacement. Specific corrective 

actions will be implemented in accordance with the CAP, which applies to all structures and 

components within the scope of the insulated cables and connections aging management program. 

When an unacceptable condition or situation is identified, a determination will be made as to 

whether this same condition or situation could be applicable to other accessible or inaccessible 

insulated cables and connections. 

The staff finds the CAP and corrective actions as described above and in Chapter 17 of the Unit 2 

UFSAR to be acceptable for managing aging for components within the scope of the insulated 

cables and connections aging management program. 

Confirmation Process, Administrative Controls, and Operating Experience 

The applicant stated that the confirmation process will ensure that preventive actions are adequate 

and that appropriate corrective actions have been completed and are effective. For accessible and 

inaccessible insulated cables and connections, the confirmation process will be defined by the 

specific type of inspection or test to be performed. 

Administrative controls will provide a formal review and approval process. For accessible and 

inaccessible insulated cables and connections, the administrative controls process will be identified 

by the specific type of inspection or test to be performed. 

The CAP provides for evaluation of aging effects and significant operating events and requires that 

reasonable actions be taken to enhance programs and activities to prevent future occurrences. 

The staff finds that the CAP satisfies the elements of the confirmation process, the administrative 

controls, and operating experience such that it provides reasonable assurance that the insulated

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cables and connections program will adequately manage the effects of aging during the period of 

extended operation. 

3.1.30.4 Conclusions 

The staff has reviewed the information in the letter dated January 31,2001, which described a new 

program "Insulated Cables and Connections Aging Management Program." On the basis of the 

information provided in the letter, the staff concludes that the applicant has demonstrated that the 

insulated cables and connections inspection program (visual and test) will adequately manage the 

aging effects associated with insulated cables and connections for the period of extended operation, 

as required by 10 CFR 54.21 (a)(3). 

3.1.31 Diesel Generator Maintenance Activities 

3.1.31.1 Introduction 

The applicant described the diesel generator maintenance activities (DGMA) in LRA Section B.1.18 

of the applicant's June 5, 2000 submittal. The program is also described in chapter 18.2.18 under 

"Existing Programs/Activities" of the Final Safety Analysis Report Supplement. The program 

manages the applicable aging effects for the EDG components that are within scope of license 

renewal. The staff reviewed this section of the application to determine whether the applicant has 

demonstrated that the effects of aging caused by a variety of environments (demineralized 

water/antifreeze, raw water, lubricating oil, and moist air) will be adequately managed during the 

period of extended operation, as required by 10 CFR 54.21 (a)(3). 

3.1.31.2 Summary of Technical Information in the Application 

Section B.1.18 of the applicant's June 5,2001 submittal describes the diesel generator maintenance 

activities. The DGMA are existing activities that address the aging effects for the diesel generator 

skid-mounted components within the jacket water cooling, lubricating oil, and scavenging air 

subsystems within the boundary of the EDG skid. The components are limited to piping, tubing, 

restricting orifices, valve bodies, pump casings, heat exchangers, heater casings, filter housings, 

strainer bodies, and strainer elements. The aging effects for these components managed with the 

DGMA are loss of material, cracking, and loss of heat exchanger performance. 

The DGMA include visual inspections, chemical analysis, eddy current testing, and performance 

based inspections. These activities are performed on the in-scope EDG components at various 

frequencies depending on the task. Preventative maintenance activities are usually performed 

during plant refueling outages, and surveillance performance tests are performed at frequencies 

determined by plant procedures or the technical specifications. These inspections and analyses are 

designed to identify aging effects before they inhibit system performance by testing for corrosion, 

wear products, contamination, and deterioration in process variables, e.g. temperature and 

pressure. 

3.1.31.3 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in the relevant 

sections of the applicant's LRA regarding diesel generator maintenance activities to ensure that, for

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the applicable component aging effects, the intended function of the system will be consistent with 

the CLB for the period of extended operation. 

Program Scope 

Section B.1.18 of the applicant's June 5,2001 submittal describes the diesel generator maintenance 

activities that address the aging effects for the diesel generator skid-mounted components (jacket 

water cooling, lubricating oil, and scavenging air subsystems). The components are limited to 

piping, tubing, restricting orifices, valve bodies, pump casings, heat exchangers, heater casings, 

filter housings, strainer bodies, and strainer elements. The aging effects for these components 

managed with the DGMA are loss of material, cracking, and loss of heat exchanger performance. 

The staff concludes that the applicant adequately identified the EDG components within the scope 

of the aging management program. 

Preventive or Mitigative Actions 

The preventative and mitigative DGMA include visual inspections, chemical analyses, eddy current 

testing, and performance based inspections that are designed to identify aging effects before they inhibit system performance and that ensure that technical specifications are met. Other preventative 

and mitigative actions include the use of antifreeze with corrosion inhibitors in the jacket water 

coolant and the option to replace adversely affected components and fluids. 

The DGMA are performed at various times depending on the task. Major preventative maintenance 

activities are currently performed on a cycle corresponding to plant refueling outages. Surveillance 

performance tests are performed more frequently as prescribed in the Plant Hatch Technical 

Specification surveillance requirements. 

The staff finds the preventative and mitigative diesel generator activities that the applicant described 

are sufficient to detect degradation before it impacts the intended functions of the EDG system. 

Parameters Inspected or Monitored 

During the performance of DGMA, the fluid and material condition of the in-scope EDG components 

are evaluated and inspected. In addition, the performance of the EDG system is monitored. 

The jacket water coolant is evaluated for quality and the amount of antifreeze in solution. The 

lubricating oil is tested for wear products, water, fuel oil, and antifreeze. The chemical properties 

of the lubricating oil are monitored to ensure that the lubricating oil subsystem can perform to 

maintain EDG operability. Heat exchanger water boxes, tubes, tube sheets, and sacrificial zinc rods 

are visually inspected for damage, debris, deposits and corrosion. Eddy current testing is performed 

on an as-desired basis to evaluate the heat exchanger tube walls for defects and changes in wall 

thickness. In addition, the performance of the EDG system is monitored for compliance with 

technical specifications. 

The staff finds the chemical analysis, visual examinations, and eddy current testing to be sufficient 

to detect changes in chemical and material properties before they result in degradation that may 

impact intended the functions of the EDG system.

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Detection of Aging Effects

The DGMA include performance surveillance tests, maintenance activities, chemical analysis, visual 

inspection, and eddy current testing to detect aging effects in the EDG in-scope components. 

During the surveillance tests and preventative maintenance activities, aging effects (cracking, loss 

of material, and loss of heat exchanger performance) would be identified. In addition, evidence of 

corrosion or wear products in the chemical analysis of the lubricating oil would identify loss of 

material. Loss of material would also be identified during the visual inspections and eddy current 

testing of the heat exchangers. Loss of heat exchanger performance would be detected through 

the pressure and temperature indications during the performance tests. 

The staff finds the methods of detection of aging effects acceptable. 

Monitoring and Trending 

Chemical analysis data for the lubrication oil is used to detect and trend wear and corrosion 

products. In addition, inspection and performance data for the heat exchangers is maintained in 

plant records. The chemical analysis, inspection, and performance data combined with the 

mitigative performance testing and the preventative maintenance are sufficient to adequately 

monitor and trend the aging effects in the EDG system. 

The staff finds these monitoring and trending activities acceptable. 

Acceptance Criteria 

The acceptance criteria for performance tests and maintenance activities are listed in specific plant 

procedures. Performance test acceptance criteria ensure that system operating temperatures, 

pressures, and expansion tank levels are within acceptable operating ranges. Maintenance activity 

acceptance criteria correspond to the safety significance of the component inspected. After 

maintenance, the performance of components must meet the performance test criteria. Industry 

codes and standards are not applied to the performance of DGMA. 

The staff finds the applicant's acceptance criteria specified above are adequate to ensure that the 

intended functions of in-scope systems are maintained during the period of extended operation. 

Operating Experience 

The applicant reviewed condition reports and identified several instances where cooler tubes 

required replacement or repair for excessive loss of material up to and including leakage of the 

tubes. These corrective actions took place prior to a loss of the system intended function. In 

addition, performance deficiencies were identified with the AMOT thermostatic flow control valves 

where the valves leaked past the valve seat or were not otherwise performing their temperature 

control function adequately. These deficiencies were not the same as those described in NRC 

Information Notice 91-85, "Potential Failures of Thermostatic Control Valves for Diesel Generator 

Jacket Cooling Water." Neither a loss of material nor cracking in the valve body caused these 

performance deficiencies. The valves were replaced or refurbished prior to loss of system intended 

function.

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3.1.31.4 Conclusions

The staff has reviewed the information in LRA Section B.1.18 and Section 18.2.18 of the applicant's 

June 5, 2000 submittal. On the basis of this review, the staff concludes that the applicant has 

demonstrated that the inspection program will adequately manage aging effects associated with the 

emergency diesel generator components in a variety of environments (demineralized 

water/antifreeze, raw water, lubricating oil, and moist air) for the period of extended operation, as 

required by 10 CFR 54.21 (a)(3). 

AGING MANAGEMENT PROGRAMS - CONCLUSION 

The staff has reviewed the 30 AMPs included in Sections A, and C of the applicant's LRA and 

Section C of the applicant's October 10, 2000 submittal. On the basis of its review, the staff 

concludes that the applicant has demonstrated that the effects of aging associated with structures 

and components within the scope of license renewal and subject to an AMR, will be adequately managed so that the intended functions will maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21 (a)(3). 

3.2 Reactor Coolant System 

3.2.1 Introduction 

The applicant described its AMR of the reactor vessel, reactor vessel internals, and reactor coolant 

systems for license renewal in Sections 3.0, "Aging Management Review Results," and 3.2, 

"Mechanical Systems," and Appendix C, "Identification of Aging Effects and Aging Management 

Review Summaries" of the LRA. The staff reviewed these sections of the LRA to determine whether 

the applicant has demonstrated that the effects of aging on the reactor and RCS will be adequately managed so that the intended function(s) will be maintained in a manner that is consistent with the 

CLB during the period of extended operation as required by 10 CFR 54.21 (a)(3). The environment, 

material, aging effects, and aging management program for each component in the reactor and 

reactor coolant systems are documented in Tables 3.2.1-1,3.2.1-2, and 3.2.2-1 of the LRA. Section 

C.1 of the LRA contains the evaluation of aging effects requiring management review, and Section 

C.2 of the LRA contains the aging management reviews for each commodity group. A commodity 

group is defined as systems or components that were constructed using similar materials and are 

operating in similar environments. 

External environments are defined in Sections C.1.2.8, "Inside"; C.1.2.9, "Outside"; and C.1.2.10, 

"Buried or Embedded" of the LRA. "Inside" external environments are defined as environments 

where equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. SCs that 

perform their functions in external environments are, in general, discussed in Sections 3.2, 3.3, 3.4, 

3.5, 3.6, and 3.7 of the LRA, and are evaluated in Sections 3.6 and 3.7 of this SER, unless 

otherwise noted.

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3.2.2 Summary of Technical Information in the Application

The RCS consists of the fuel, nuclear boiler system, reactor assembly system, and reactor 

recirculation system. Each of these systems is described below. 

Fuel 

Nuclear fuel is provided as a high-integrity assembly of fissionable material, which can be arranged 

in a critical array. The assembly must be capable of efficiently transferring the generated fission 

heat to the circulating coolant water, while maintaining structural integrity and keeping the fission 

products contained. 

The external environment of the fuel is a cladding surrounded by water. The fuel cladding 

experiences the complete range of reactor coolant pressure and temperatures. 

Additional information may be found in Section 4.2.1.2 of the Plant Hatch Unit 2 UFSAR. 

Nuclear Boiler System 

The nuclear boiler system is composed of several components and subsystems that are required 

to generate steam. Functions provided by the nuclear boiler system include supplying feedwater 

to the reactor, conducting steam from the reactor, reactor overpressure protection, and some 

reactor control and/or engineered safety feature functions. The nuclear boiler system is in operation 

any time the plant is in operation. Most of the major components in the system are part of the 

reactor coolant pressure boundary. 

The system contains the following major components: 

* main steam lines (MSLs) 

* safety relief valves (SRVs) 

* main steam isolation valves (MSIVs) 

* feedwater lines 

* feedwater line check valves 

0 instrumentation and controls 

Reactor Assembly System 

The reactor assembly consists of the RPV and its internal components of the core, shroud, steam 

separator and dryer assemblies, and jet pumps. Also included in the reactor assembly are the 

control rods, control rod drive (CRD) housings, and the CRDs. The RPV is a vertical, cylindrical 

pressure vessel with hemispherical heads of welded construction. The major reactor internal 

components are the core (fuel, channels, control blades, and instrumentation), the core support 

structure (including the core shroud, shroud head, separators, top guide, and core support), the 

steam dryer assembly, and the jet pumps. The reactor internal structural elements are stainless 

steel or other corrosion-resistant alloys. 

The reactor vessel is located inside the primary containment building. The internal environment of 

the RPV is reactor water, normally at about 533 OF and 1055 psia during plant operation. Water 

quality is maintained within the specified limits. During plant conditions that require the operation

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of the shutdown cooling mode of RHR, reactor water can be cooled to approximately 117 OF via the 

RHR heat exchangers and recirculated back to the reactor through the reactor recirculation system 

(RRS) piping. During plant shutdown conditions, the water temperature in the RPV can be as low 

as 70 OF. 

Reactor Recirculation System (RRS) 

The RRS is one of two core reactivity control systems. The RRS is part of the reactor coolant 

pressure boundary. Therefore, it also functions to maintain the pressure boundary during normal 

operation, transients, and accident scenarios to prevent the release of radioactive liquid and gas. 

The RRS consists of two parallel loops, each consisting of a recirculation pump, suction and 

discharge block valves, piping, fittings, flow elements and connections supporting flow, and 

differential pressure instrumentation. The RRS interfaces with the RHR and RWCU systems to 

provide a flow-path in support of shutdown cooling, low-pressure coolant injection (LPCI), RWCU, 

and reactor water level control functions. 

More information about this system may be found in Section 4.3 of the Plant Hatch Unit I UFSAR 

and Section 5.5.1 of the Plant Hatch Unit 2 UFSAR. 

3.2.2.1 Effects of Aging 

The applicant identified the aging effects, component functions, environment, and materials for each 

component in the reactor assembly system, the nuclear boiler system, and the reactor recirculation 

system in Tables 3.2.1-1, 3.2.1-2, and 3.2.2-1 of the LRA, respectively. 

Since fuel is subject to replacement within a specified time period, according to 10 CFR 

54.21 (a)(1)(ii), fuel does not require an integrated assessment. 

The aging effects for the nuclear boiler system are as follows: 

• cracking 

• loss of preload 

* loss of material 

• loss of fracture toughness in cast austenitic stainless steel valve bodies 

The aging effects for the reactor assembly system are as follows: 

• cracking 

• loss of fracture toughness of beltline materials 

The aging effects for the reactor recirculation system are as follows: 

* cracking 

loss of preload 

loss of material

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loss of fracture toughness of cast austenitic stainless steel pump casing and covers and 

valve bodies 

Survey of Industry Experience 

Industry experience was collected from resources such as NRC generic letters, bulletins and 

information notices; GE service information letters; INPO significant operating event reports; and 

topical information from various industry working groups. Plant-specific information was derived 

through plant walkdowns, interviews, and records searches. A list of generic communications 

considered by the applicant is provided in Section C.1.5 of the LRA. 

Survey of Industry Experience for the Nuclear Boiler System 

As a result of the review of the condition reporting database, the only age-related deficiency 

identified was a loss of material due to erosion corrosion of carbon steel components within the 

Class 1 boundary and exposed to reactor water. NRC Integrated Inspection Report 99-02 

concluded that flow-accelerated corrosion (FAC) inspections were conducted and evaluated in 

accordance with procedures, and the applicant had implemented an effective program to maintain 

high-energy carbon steel piping systems within acceptable wall thickness limits. 

Several instances of leaking Class 1 bolted closures were found during pressure testing conducted 

prior to drywell closure. These leaks were minor and, in the majority of cases, may be attributed to 

the thermal effects associated with cooldown of the Class 1 systems for outages. In all cases, these 

leaks were corrected in accordance with Plant Hatch's implementation of ASME Section Xl in

service inspection (ISI) program. Activities performed in accordance with vendor service information 

letters also contribute to the overall reduction of these leaks. Operating experience with CRD flange 

bolts indicates numerous instances of pitting and crevice corrosion. These conditions were 

discovered during ISI program inspections. All fasteners demonstrating evidence of corrosion were 

replaced. 

Several failures of piping components downstream of orifices or other pressure reduction devices 

within steam systems were noted. In all cases, the cause of the failure was attributed to erosion 

corrosion related to pressure fluctuations within the system. This experience validates the 

conclusion that erosion corrosion can occur in areas not identified by the FAC model. The FAC 

program and treated water systems piping inspections will specifically target these suspect areas 

for increased inspections in order to minimize future loss of component function. NRC Integrated 

Inspection Report 99-02 concluded that FAC inspections were conducted and evaluated in 

accordance with procedures, and the applicant had implemented an effective program to maintain 

high-energy carbon steel piping systems within acceptable wall thickness limits. 

Survey of Industry Experience for the Reactor Assembly System 

A review of the operating experience for both Plant Hatch units indicates that there are no 

outstanding problems. Routine examinations as part of the ISI program and augmented in-vessel 

inspections, as well as normal maintenance and refueling activities, have not revealed any 

unanticipated age-related issues for the reactor vessel. There was one instrument penetration that 

developed a leak attributed to intergranular stress corrosion cracking (IGSCC). The leak was 

detected as part of normal drywell outage activities and repaired. Corrosion was detected on the

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mating surface of the Unit 2 RPV head vent flange and repaired. Finally, during a routine 

maintenance activity, CRD flange bolts were found to have evidence of pitting. All CRD flange bolts 

were replaced and are inspected routinely upon disassembly. 

The operating experience for the Plant Hatch internals was reviewed. Over time, there have been 

several occurrences of cracking, all of which have been repaired or are currently being monitored 

in accordance with prescribed procedures and programs. Early in life, IGSCC was detected on the 

Unit 1 core spray sparger. It was repaired by installing a mechanical clamp. The sparger has been 

full-flow tested and the clamp examined afterwards with no evidence of degradation. Multiple indications have been detected over the years on the non-safety-related steam dryers. Some have 

been repaired, while others are monitored. Jet pump inspections have resulted in minor indications 

associated with set-screw gaps, diffuser-to-adapter welds, riser pipe welds, and tack welds. These 

are being monitored and reexamined in accordance with the provisions of the BWRVIP. Crack-like 

indications were also detected in the core shrouds for both units. The applicant conservatively decided to make pre-emptive repairs to eliminate the concern of cracking in shroud circumferential 

welds. The repaired hardware and vertical welds are periodically examined as specified in the 

BWRVIP. 

Survey of Industry Experience for the Reactor Recirculation System 

While no significant failure trends were found within the prior 5 years, the RRS piping has 

experienced significant age-related degradation due to IGSCC of weld heat-affected zones. 

Specifically, the Unit 1 piping components have undergone extensive weld overlay repair, and the 

Unit 2 piping has been replaced with 316NG stainless steel. A primary contributor to these IGSCC 

failures is dissolved oxygen content in the reactor water. Prior to initiation of hydrogen injection, higher levels of dissolved oxygen produced by radiolysis within the core region created an oxidizing 

environment conducive to IGSCC. Implementation of hydrogen water chemistry has effectively arrested existing IGSCC-induced cracks, and has prevented new cracks from forming. Therefore, 

the current reactor water chemistry control in conjunction with other mitigative activities has proven 

effective in mitigating failures caused by IGSCC. 

3.2.2.2 Aging Management Programs 

The applicant identified the aging management programs for components in the reactor assembly 

system, the nuclear boiler system, and the reactor recirculation system in Tables 3.2.1-1, 3.2.1-2 

and 3.2.2-1, respectively, of the LRA. 

The aging management programs for the nuclear boiler system are as follows: 

* torque activities 

* protective coatings program 

* inservice inspection program 

* reactor water chemistry program 

0 component cyclic or transient limit program 

* treated water systems piping inspections 

* galvanic susceptibility inspections 

* flow-accelerated corrosion program 

* demineralized water and condensate storage tank chemistry control program * suppression pool chemistry control program

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* torus submerged components inspection 

* gas system components inspections activities 

* passive components inspection program 

The aging management programs for the reactor assembly system are as follows: 

* boiling water reactor vessel internals program 

0 reactor pressure vessel monitoring program 

* reactor water chemistry control program 

0 component cyclic or thermal transient limit program 

* inservice inspection program 

The aging management programs for the RRS are as follows: 

• reactor water chemistry control program * component cyclic or transient limit program 

* inservice inspection program 

0 torque activities 

& treated water systems piping inspection 

The applicant concluded that these programs would manage aging effects in such a way that the 

intended function of the components would be maintained consistent with the CLB, under all design 

loading conditions during the period of extended operation. 

3.2.3 Staff Evaluation 

The applicant described its AMR for the reactor assembly system, nuclear boiler system and RRS 

in Section 3.2 and Section C of the LRA. The staff reviewed these sections to determine whether 

the applicant has identified the aging effects for components in these systems and demonstrated 

that the effects of aging on the components systems will be adequately managed during the period 

of extended operation as required by 10 CFR 54.21 (a)(3). Each commodity group associated with 

these components was reviewed by the staff to determine the applicability of the aging effects to 

the system and its components. The staff reviewed each aging management program associated 

with these components to determine whether the effects of aging will be adequately managed by 

the program. 

3.2.3.1 Effects of Aging 

The aging effects for the reactor assembly system, nuclear boiler system, and RRS identified by the 

applicant are discussed in Section 3.2.2.1 of this SER. 

3.2.3.1.1 Effects of Aging on the Reactor Assembly System 

The aging effects for the reactor assembly system are as follows: 

* cracking 

* loss of fracture toughness of beltline materials

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Cracking

All components in the reactor assembly system which require aging management, except for the 

shell and closure head, are subject to cracking. Cracking of the vessel shell and closure head due 

to fatigue and stress corrosion cracking (SCC) was determined not to be an aging effect requiring 

management by BWRVIP-74, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines." The applicable fatigue usage factors for the vessel are very low in comparison to other 

RPV locations. As for SCC of the low-alloy steel vessel shells, BWRVIP-05, "BWR Reactor 

Pressure Vessel Shell Weld Inspection Recommendations," and BWRVIP-60, "Evaluation of Crack 

Growth in BWR Low Alloy Steel RPV Internals," indicate that even if cracks were to emanate from 

the vessel cladding, they are not expected to propagate into the low-alloy steel of the reactor vessel. 

BWRVIP-05 and BWRVIP-60 have been reviewed and approved by the staff. 

Loss of Material 

The closure studs in the reactor assembly system are not identified as being subject to loss of 

material or loss of preload. In response to RAI 3.2.3.1-1, the applicant indicated that closure studs 

are evaluated in BWRVIP-74. BWRVIP-74 does not identify closure studs as being subject to loss 

of material or loss of preload. The staff agrees with this conclusion because the closure studs are 

examined during each refueling outage and loss of material or loss of preload has not been 

identified as an aging effect in the BWR environment. 

Although components in the reactor assembly system are in a reactor water environment, the 

commodity groups in the reactor assembly system are not subject to loss of material. In response 

to RAI 3.2.3.1-1, the applicant indicates that evaluations performed with regard to vessel 

components utilized BWRVIP reports that are based on extensive research, testing, and industry experience. Based on the extensive research, testing, and industry experience, the applicant indicated that loss of material is not an aging effect for components in the reactor assembly system. Based on the applicant's response to this RAI, the staff agrees that commodity groups in the reactor 

assembly system are not susceptible to loss of material. 

Void Swelling 

According to EPRI technical report TR-107521, void swelling is defined as a gradual increase in 

dimension of an austenitic stainless steel part as a result of helium bubble nucleation and growth from nuclear transmutation reactions of nickel and boron in the material. EPRI TR-107521 cites 

sources with conflicting results on predicting the extent of possible void swelling for light-water 

reactor conditions. One source predicts swelling as great as 14 percent for PWR baffle-former 

assemblies over a 40-year plant lifetime, whereas results from another source indicate that swelling would be less than 3percent for the most highly irradiated sections of the internals at 60 years. The 

issue of concern to the staff is the impact of change of dimension due to void swelling on the ability of the reactor vessel internals to perform their intended functions. Swelling of the reactor vessel 

internals could potentially impact the ability to insert control element assemblies and to maintain 

proper coolant flow distribution characteristics. 

In response to RAI 3.2.3.1-2, the applicant indicated that BWR reactor vessel internals are a greater distance from the fuel than PWR reactor vessel internals and are expected to experience less 

neutron fluence. In addition, the lowest temperature for which this phenomenon is conjectured to 

occur is 572 OF, which is a temperature higher than the internals that either Plant Hatch unit will

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experience. Further, the BWRVIP for BWR internals addressed the key aspects of the internals 

components and provided inspection criteria, where appropriate, to manage aging. The BWRVIPs 

that are being implemented at Plant Hatch are adequate to address aging of the internals. Since 

BWR reactor vessel internals have relatively low neutron fluence and the applicant will perform inspections in accordance with the staff-approved BWRVIP reactor vessel internals programs, the 

staff concludes that void swelling is not a concern for Plant Hatch. 

Neutron and Thermal Embrittlement 

Cast austenitic stainless steel (CASS) components in the reactor assembly system may be subject 

to loss of fracture toughness due to the effects of thermal and neutron embrittlement. CASS 

components are susceptible to thermal embrittlement if they operate at temperatures greater than 

550°F (the threshold that the NRC has established as the point at which thermal aging of CASS 

components occurs). Also, as indicated in Appendix H to 10 CFR Part 50, neutron irradiation 

embrittlement becomes significant at neutron fluences greater than 101" n/cm2 (E>1 Mev). 

Table 2.3.1-1 of the LRA indicates that jet pump assemblies and fuel supports contain CASS 

components and are within the scope of license renewal. The Plant Hatch fuel supports support the 

weight of the fuel assemblies and distribute core flow into the fuel assemblies. Table 2.3.1-1 

indicates that the CASS fuel supports have no aging effects requiring management. However, due 

to the fuel supports' proximity to the core, the staff believes that the CASS fuel supports are likely 

to be susceptible to neutron embrittlement. 

In response to RAI 3.2.3.2-1, the applicant indicated that portions of the jet pump assemblies may experience fluence greater than 1017 n/cm2, but will not experience temperatures exceeding 5500 F. 

On the basis of this information, the staff concludes that jet pump assemblies fabricated from CASS 

will not be susceptible to thermal embrittlement; but may be susceptible to neutron embrittlement. 

The BWRVIP generic AMP for the jet pump assembly components is described in EPRI report TR

108728, "BWRVIP BWR Jet PumpAssembly Inspection and Flaw Evaluation Guidelines (BWRVIP 41)." The BWRVIP-41 report does not recommend an inspection of CASS jet pump assembly 

components because CASS components are considered not susceptible to IGSCC. However, the 

BWRVIP-41 report does not contain any data to indicate the threshold for neutron embrittlement of 

CASS and does not identify the neutron fluence experienced by the CASS jet pump assembly components. Because the BWRVIP-41 report does not provide data to support its conclusion that 

inspection of CASS components is not needed, the staff cannot conclude that the loss of fracture 

toughness resulting from irradiation embrittlement and cracking is not a plausible aging effect 

requiring aging management. However, the staff notes that irradiation embrittlement of CASS 

components becomes a concern only if cracks are present in the components. Therefore, if an 

applicant can show that cracks do not occur in the CASS components, then the staff can conclude 

that loss of fracture toughness resulting from neutron irradiation embrittlement will not be a 

significant aging effect. 

The staff notes that industry-wide experience shows that cracking has not been observed in CASS 

jet pump assembly components. Therefore, as part of its safety evaluation of the BWRVIP-41 

report, the staff has requested, and the BWRVIP is considering, the inclusion of a baseline 

inspection in the BWRVIP-41 report to ensure that cracking is not present in the components. Similarly, the staff requested that the applicant propose a one-time inspection of the CASS jet pump assembly components and fuel supports to confirm that the CASS components have not

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experienced cracking. The inspection should be performed prior to the beginning of the extended 

period of operation. This was identified as Open Item 3.2.3.1.1-1. 

Since the development of this open item, the staff has reconsidered the safety basis for requiring the applicant to perform a one-time inspection of the CASS jet pump assemblies and fuel supports. 

Since neutron embrittlement becomes a concern only if cracking is present in the components, and 

because both industry and plant experience have not identified cracking in these components, the 

staff concludes that there is no-demonstrated safety issue regarding neutron embrittlement of the 

components. Further, the BWRVIP-41 report requires inspections of several jet pump assembly 

welds, which are more susceptible to cracking than the CASS components and will therefore serve 

as an indication of the potential need for more extensive inspections later in life. These welds are 

considered to be more susceptible than the CASS components, which are made in one piece and 

have no welds, since the BWR environment hasthe potential to promote IGSCC under normal water I 

chemistry conditions. Therefore, the staff finds that the welds to be inspected in accordance with 

the BWRVIP-41 report will provide adequate indication if additional inspections may be needed in 

the future. Therefore, the staff concludes that a one-time inspection of jet pump assemblies and 

fuel supports is not warranted at this time to support operation for the license renewal term. 

The BWRVIP and the NRC's Office of Nuclear Regulatory Research (RES) are considering joint 

confirmatory research to determine the effects of high levels of neutron fluence on BWR internals. 

Any future research results would help to determine whether additional inspections, or alternatives 

to inspections, are warranted. Should research results find that inspections of CASS jet pump assemblies and fuel supports are warranted, the results should be included in a staff-approved 

revision to the BWRVIP-41 report, or another staff-approved BWRVIP report. 

By letter dated June 5, 2001, the applicant committed to continued participation in BWRVIP 

activities, including the implementation of future BWRVIP documents. Further, the applicant has 

committed to implementing the guidelines of the BWRVIP-41 report, and any staff-approved 

revisions to the BWRVIP-41 report. 

On the basis that the industry has not observed cracking in CASS jet pump assemblies and fuel 

supports, the staff has determined that its request for the applicant to perform a one-time inspection 

to identify cracking in the CASS jet pump assemblies and fuel supports is not warranted at this time. 

In addition, the applicant's commitment to implement future staff-approved BWRVIP documents 

related to aging management of CASS jet pump assembly components and fuel supports, and staff

approved BWRVIP guidelines, provides additional assurance that the aging effects associated with 

these components will be adequately managed during the period of extended operation. 

On the basis of the information discussed above, the staff concludes that the loss of fracture 

toughness of CASS jet pump assemblies and fuel supports due to the effects of thermal and 

neutron embrittlement will be adequately managed for the period of extended operation. Open Item 

3.2.3.1.1-1 is closed.

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3.2.3.1.2 Effects of Aging on the Nuclear Boiler System 

The aging effects for the nuclear boiler system are as follows: 

0 cracking 

* loss of preload 

* loss of material 

* loss of fracture toughness in cast austenitic stainless steel valve bodies 

All components, except for bolting in the nuclear boiler system, are subject to cracking. In response 

to RAI 3.2.3.1-1, the applicant indicated that SCC and fatigue were considered potential 

mechanisms contributing to cracking of bolting in the nuclear boiler system. However, after 

considering the causes of SCC and the ASME Code fatigue analysis for bolting, the applicant 

concluded that these potential mechanisms did not result in aging effects that require aging 

management. A summary of the applicant's evaluation is provided below. 

Stress Corrosion Cracking of Bolting 

Stress corrosion crack initiation and propagation requires that the affected fastener be 

subjected to water or steam environments containing various contaminants. Significant 

wetting of fasteners due to mechanical joint leakage is not considered a normal operating 

condition. 

A common factor in fastener SCC failures involves the usage of lubricants containing MoS 2, 

or other lubricants that form contaminants that promote SCC when in contact with reactor 

water. At Plant Hatch, procedural controls prevent the use of these lubricants in safety

related fasteners, thereby further minimizing the potential for SCC to occur. 

The vast majority of bolting failures due to SCC have occurred at PWRs. Boric acid 

environments are the primary contributors to these SCC failures. Since Plant Hatch is a 

BWR, bolting does not experience conditions conducive to SCC initiation and propagation. 

Plant Hatch has implemented procedural processes to minimize the potential for excessive 

applied stresses due to improper preload. 

Cracking Resulting from Fatigue of Bolting 

Cracking due to fatigue is not considered by the applicant to be an aging effect requiring 

management for nuclear boiler system fasteners, since the effects of fatigue are generally seen in 

conjunction with SCC for high-strength fasteners. In addition, pressure bolting for flanged 

connections in Class 1 systems is designed to meet the requirements of ASME Section III, 

Paragraph NB-3232.3, which requires that an analysis be performed to evaluate the effect of fatigue 

(both thermal and vibration induced) on the component. 

On the basis of the information provided by the applicant supporting its conclusion that bolting in the 

nuclear boiler system is not subject to SCC or cracking due to fatigue, the staff concluded that the 

applicant had not provided sufficient information for the staff to conclude that bolting in the nuclear 

boiler system is not subject to cracking. The staff was concerned that bolting that is heat treated 

to a high hardness condition and exposed to a humid environment within containment could be

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susceptible to SCC. NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation 

or Failure in Nuclear Power Plants," indicates that the bolts' actual yield stress should be less than 

150 ksi to preclude SCC. In response to this issue, the staff identified Open Item 3.1.11-1. This 

open item and its resolution are discussed in Section 3.1.11 of this SER. Specifically, the applicant 

stated that it has no operating experience to indicate problems with the bolting, nor could they find 

any problems during an industry survey of operating experience. On the basis of the resolution of 

this open item, the staff concludes that SCC in high-strength bolting is not applicable to Plant Hatch. 

Loss of Material 

Class 1 bolting in the nuclear boiler system is identified as not being subject to loss of material. 

However, all fasteners within the Class 1 boundary are fabricated from low-alloy steels such as 

SA540, Grade B23 or SA1 93, Grade B7. The addition of alloy elements prevents general corrosion 

due to atmospheric contact. Since the normal environment does not include significant wetting, loss 

of material due to corrosion was not an aging effect requiring management for these fasteners. 

All non-stainless steel, non-Class 1 fasteners were evaluated together as a commodity. Many 

fastener applications at Plant Hatch utilize carbon steel fasteners. The applicant concluded that 

these fasteners could be potentially susceptible to loss of material. This conclusion was 

conservatively applied to all non-Class 1 carbon and low-alloy steel fasteners. 

The staff agrees that the applicant has identified all components in the nuclear boiler system that 

are susceptible to loss of material. 

3.2.3.1.3 Effects of Aging on the Reactor Recirculation System 

The aging effects for the reactor recirculation system are as follows: 

* cracking 

0 loss of preload 

* loss of material 

* loss of fracture toughness in cast austenitic stainless steel pump casing and covers and 

valve bodies 

On the basis of the review of the information provided in the LRA, the staff concludes that the 

applicant has adequately identified the plausible aging effects associated with components in the 

RRS. 

The staff concludes that all applicable aging effects have been identified for the reactor assembly 

system, nuclear boiler system, and RRS, consistent with published literature and industry 

experience.

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3.2.3.2 Aging Management Programs 

The aging management programs for the reactor assembly system, nuclear boiler system and RRS 

are identified in Section 3.2.2.2 of this SER. The aging management programs are reviewed by the 

staff in the following sections of the SER: 

* reactor water chemistry control program, Section 3.1.1 

* demineralized water and condensate storage tank chemistry control program, Section 3.1.6 

* suppression pool chemistry control program, Section 3.1.7 

* inservice inspection program, Section 3.1.9 

* torque activities, Section 3.1.11 

* component cyclic and transient limit program, Section 3.1.12 

• boiling water reactor vessel and internals program, Section 3.1.15 

* reactor pressure vessel monitoring program, Section 3.1.17 

* flow accelerated corrosion program, Section 3.1.19 

* protective coatings program, Section 3.1.20 

* galvanic susceptibility inspections, Section 3.1.23 

* treated water systems piping inspections, Section 3.1.24 

* gas systems component inspections, Section 3.1.25 

• passive components inspection activities, Section 3.1.27 

* torus submerged components inspection program, Section 3.1.29 

3.2.3.2.1 Aging Management Programs for Cast Austenitic Stainless Steel (CASS) Components 

This section provides the staff evaluation of the applicant's management of CASS components in 

the RCS systems. 

CASS Components within the Nuclear Boiler System and Reactor Recirculation System 

The industry position on CASS is described in the Electric Power Research Institute (EPRI) topical 

report (TR)-1 06092, "Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless Steel 

Components in LWR Reactor Coolant Systems," dated September 1997. This report provides a 

methodology for determining whether CASS components are potentially susceptible to significant 

thermal embrittlement that could lead to loss of structural integrity if cracks were in the component. 

The staff's evaluation of EPRI TR-1 06092 is contained in a letter from C.I. Grimes (NRC) to D.J. 

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Walters (NEI), dated May 19, 2000. The staff's evaluation indicates that the definition of 

components in EPRI TR-1 06092 that are potentially susceptible to significant thermal embrittlement 

are acceptable, with the exception that: (a) static casting with high molybdenum and greater than 

14percent ferrite content would be considered susceptible to significant thermal embrittlement; (b) 

components with Niobium would be considered susceptible to significant thermal embrittlement; (c) 

components with greater than 25 percent ferrite would be considered susceptible to significant 

thermal embrittlement; (d) the calculated ferrite must be determined using Hull's equivalent factors 

or a methodology producing an equivalent level of accuracy (6 percent deviation between measured 

and calculated values); and (e) the flaw evaluation procedures in IWB-3640 are applicable to 

thermally aged CASS with ferrite levels up to 25 percent. Evaluation of CASS components with 

ferrite levels greater than 25 percent should use fracture toughness data representative of the 

higher ferrite contents. 

The ASME Code ISl for valve bodies equal to or greater than 4 inches nominal pipe size (NPS) and 

for pump casings requires a volumetric examination of the welds and a visual (VT-3) of the inside 

surfaces. These examinations should be able to detect cracks in these valve bodies and pump casings before they reach a critical size, and these CASS components need only be examined to 

ASME Code ISI requirements. 

The ASME Code ISI program for valve bodies less than 4 inches NPS requires an outside surface 

examination, but does not require internal visual or volumetric examination. However, a staff 

evaluation of CASS valve bodies less than 4 inches NPS indicates that (1) there have been no 

reported instances of valve body cracking in these small valves, and (2) aged CASS valve bodies, 

even with extremely low fracture toughness, can withstand very large through-wall cracks. 

Therefore, valve bodies need only be examined to ASME Code ISI program requirements. 

The CASS components outside the reactor vessel are pump casings, valve bodies, and the main 

steam flow restriction venturi elements. The venturi elements have been determined to not be 

susceptible to thermal embrittlement based on the grade of CASS and the operating temperature. With the exception of the venturi elements, the applicant will manage cracking and any associated 

impact of thermal embrittlement should it occur in these components. The aging management will 

be accomplished through the ISI program, which includes the inspection requirements of Section 

Xl. This meets the position identified in the letter from C.I. Grimes to D.J. Walters dated May 19, 

2000. Since the venturi elements are not susceptible to thermal embrittlement and pump casings and valve bodies are inspected to ASME Code ISI requirements, the staff concludes that these 

components have adequate aging management programs 

CASS Components within the Reactor Assembly System 

The effect of neutron and thermal embrittlement on CASS components within the reactor assembly 

system is discussed in Section 3.2.3.1.1 of this SER. 

3.2.3.2.2 Aging Management Programs for Vessel Flange Leak Detection (VFLD) Line 

The staff was concerned that leakage around the reactor vessel seal rings could accumulate in the 

VFLD lines, cause an increase in the concentration of contaminants, and cause cracking in the 

VFLD line. The applicant indicated that the Plant Hatch Unit 1 VFLD line is subject to the AMP for 

Class 1 stainless steel piping in the nuclear boiler system. Cracking is identified as an aging effect 

for this commodity group. The ASME Code requires that the welds in Class 1 piping of the size of

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the VFLD line be inspected using a surface examination, and the pressure boundary to be VT-2

inspected following the system leakage test after each refueling outage. 

In the LRA, the applicant indicated that the Plant Hatch Unit 2 VELD line is stainless steel and 

contains portions that are classified as Class 1 piping and non-Class 1 piping. The Class 1 piping 

would be examined to ASME Code Section Xl requirements. The non-Class 1 stainless steel piping in the nuclear boiler system will be examined in accordance with the treated water systems piping 

inspections (TWSPI). The TWSPI provides for a one-time visual inspection of the sample set using the best available examination method. Inspections may utilize an examination similar to that 

described for VT-i in the ASME Code. 

The inspections implemented as part of the ISI program for Class 1 piping and the inspections implemented as part of the TWSPI for non-Class 1 piping should be able to detect cracking in the 

VFLD line. On the basis of the information provided by the applicant and summarized above, the 

staff concludes that the applicant can adequately manage cracking associated with the VFLD. 

3.2.3.2.3 Aging Management Programs for ASME Code Class 1 Small-Bore Piping 

NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems," identified 

cracking in an unisolable section of emergency core cooling system piping connected to the reactor 

coolant system. The cause of the cracking was high cycle thermal fatigue created by relatively cold 

water leaking through a closed valve. In addition, cracks in piping have also been attributed to 

vibratory fatigue and stress corrosion aging mechanisms. 

In response to RAI 3.2.3.2-8, the applicant indicated that the following systems contain ASME Code 

Class 1 small-bore piping that could be subject to cracking from thermal fatigue or stress corrosion 

aging mechanisms: 

B21 - nuclear boiler system 

B31 - RRS 

C41 - SLCS 

Ell - RHR system 

E21 - CS system 

E41 - HPCI system 

E51 - RCIC system 

G31 - RWCU system 

Since carbon steel and stainless steel components in these systems are subject to changes in 

temperature, cracking due to thermal fatigue is an aging effect requiring management. For pipe 

sizes above 1 inch, the AMP credited for managing aging of these components due to thermal 

fatigue is the component cyclic or transient limit program. Class 1 piping that is 1 inch and smaller 

was analyzed using ASME Class 2 methods. For such piping, cracking due to thermal fatigue is 

addressed as a TLAA in LRA Section 4.2.3, which demonstrates that the analyses remain valid 

throughout the extended period of operation. Cracking due to vibratory fatigue is not considered 

an aging effect requiring management since failure of these components due to vibration has been 

precluded by design. 

As described in Section C.1.2.1.2 of the LRA, for SCC to occur in components of the above 

systems, each of the following three conditions must simultaneously exist:

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1. The components must contain susceptible materials (in this case, stainless steel or nickel 

based alloys). 

2. The components must be subject to residual tensile stresses of sufficient magnitude. 

3. The components must be subject to a potentially corrosive environment. 

All three conditions exist simultaneously in the above systems, so cracking due to IGSCC is an 

aging effect requiring management. 

For these systems, the applicant defines the corrosive environment as high-temperature water 

where the electrochemical corrosion potential of alloys exposed to the coolant is increased due to 

the presence of radiolytically produced dissolved oxygen and hydrogen peroxide. Without the 

appropriate reactor water chemistry controls, this corrosive environment could exist. Therefore, to 

manage SCC in the above systems, the applicant has credited reactor water chemistry control, coupled with either the ISl program (for 2-inch and larger piping in these systems) or the TWSPI (for piping in these systems that is not included in the IS[ program). 

The staff was concerned that unanticipated high cycle thermal fatigue resulting from thermal 

stratification, turbulent penetration, or intergranular stress corrosion could result in cracking of small 

bore piping. These types of cracking are not evaluated as part of the component cyclic or transient 

limit program. The ASME Code Class 1 inspection requirements for small-bore piping include a 

surface examination, but not a volumetric examination. In order to detect cracking resulting from 

high cycle thermal fatigue or intergranular stress corrosion, a volumetric examination is required. Since the proposed program does not include a volumetric examination, it may not be capable of 

detecting high cycle thermal fatigue cracks resulting from thermal stratification, turbulent 

penetration, or intergranular stress corrosion. Therefore, the staff requested that the applicant supplement the existing programs with volumetric examination of the limiting locations in small-bore 

piping systems, excluding socket welds, which could have thermal stratification or turbulent 

penetration. 

By letter dated September 5, 2001, the applicant committed to including small-bore butt-welded 

stainless steel piping in the scope of the treated water systems piping inspection (TWSPI) program. TWPSI is a one-time condition monitoring program that provides for visual and volumetric 

inspections of a sample population intended to detect loss of material and cracking, and confirms 

the effectiveness of existing chemistry control programs. The staff's review of this aging management program is found in Section 3.1.24 of this SER. On the basis of the applicant's commitment to provide visual and volumetric examinations of the small-bore piping, Open Item 

3.2.3.2.3-1 is closed. 

3.2.4 Conclusion 

The staff has reviewed the information in Sections 3.0 and 3.2, and Section C of the LRA, as well 

as the applicant's responses to Open Items 3.2.3.1.1-1 and 3.2.3.2.3-1. On the basis of this review, 

the staff concludes that the applicant has demonstrated that the aging effects associated with the 

reactor and RCS will be adequately managed so that there is reasonable assurance that these 

systems will perform their intended functions in accordance with the CLB during the period of 

extended operation.

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3.3 Engineered Safety Features 

3.3.1 Introduction 

The applicant described its AMR for the engineered safety features (ESF) systems for license 

renewal in Section 3.2.3, "Engineered Safety Features (ESF) Systems," of the LRA. The staff 

reviewed this section of the LRA to determine whether the applicant has demonstrated that the 

effects of aging on the ESF systems will be adequately managed during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.3.2 Summary of Technical Information in the Application 

The applicant provided an AMR of eight ESF systems that are considered to be within scope of the 

license renewal rule. A brief description of each system is provided below. 

Core Spray System 

The CS system is one of the ECCS that protects the core from overheating in the event of a LOCA. 

The CS system is a low-pressure system. Actuation of the CS system results from low reactor 

vessel water level (level 1), high drywell pressure, or manual action. Injection valves to the reactor 

require a signal from the reactor's low-pressure permissive switches before opening to provide 

overpressure protection to the system. The pumps take suction from the suppression pool, and 

spray the top of the fuel assemblies to cool the core and limit the fuel cladding temperature. An 

alternate suction source for the CS system, the CST, is primarily used to provide RPV makeup and 

as an injection test supply during outages, and would not normally be used following an accident. 

The CS system works in conjunction with the LPCI system. 

The CS system has two independent loops. Each loop is a 100 percent capacity centrifugal pump driven by an electric motor, a sparger ring in the reactor vessel above the core, piping, valves, and 

associated controls and instrumentation. To enable the CS system to make a quick startup and to 

minimize the water hammer possibilities during startup, the CS system discharge lines are always maintained full of water by the jockey pump system, which consists of two centrifugal pumps in each 

of the two loops. The suction and discharge lines of these pumps are connected through piping and 

valves to the suction and discharge lines of the CS pumps, respectively. Continuous operation of 

the jockey pumps ensures that the ECCS discharge lines remain full. The jockey pump system also 

provides the same feature for the RHR system. 

High-Pressure Coolant Iniection System 

The HPCI system supplies makeup coolant into the reactor vessel from a fully pressurized to a 

preset depressurized condition. Demineralized makeup water is supplied from the CST or treated 

water from the suppression pool. The flow rate of the system will maintain the reactor vessel 

coolant inventory until the reactor pressure drops sufficiently to permit the low-pressure core cooling 

systems to automatically inject coolant into the vessel. 

The HPCI system consists of a turbine-driven pump train, piping, valves, and controls that provide 

a complete and independent emergency core cooling system. A test line permits functional testing of the system during normal plant operation. A minimum flow bypass line bypasses pump discharge flow to the suppression pool to protect the pump in the event of a stoppage in the main discharge

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line. Reactor vessel steam is supplied to the turbine. Turbine exhaust steam is then dumped to the 

suppression pool. 

Post-LOCA Hydrogen Recombiner System (Unit 2) 

The post-LOCA hydrogen recombiner system ensures that hydrogen does not accumulate within 

the primary containment in combustible concentrations following a LOCA. This is accomplished by drawing primary containment atmosphere from the drywell, and passing it through the recombiner 

where the hydrogen reacts with available oxygen to form water vapor. The recombiner discharges 

to the suppression pool (torus). 

The hydrogen recombiner system is part of the combustible gas control system and consists of two 

identical and independent 100 percent capacity trains. Each train consists of the recombiner skid, the control console, and the power panel. The recombiner skid consists of inlet piping, flow meters, flow control valve, an enclosed blower assembly, heater section, reaction chamber, direct contact 

water spray connected to the power panel, and the control console through instrument and power cables. Coolant for the water spray gas cooler is provided by the RHR system. 

Primary Containment Purge and Inerting System 

The primary containment purge and inerting system primarily provides and maintains an inert 

atmosphere in the primary containment for combustible gas control and fire protection. Plant 

Technical Specifications require that within 24 hours of reactor operation, the inerting system injects 

a sufficient amount of gaseous nitrogen into the drywell and torus so that the oxygen concentration 

falls below 4-percent by volume. 

Major equipment for the purge and inerting system include a purge air supply fan, liquid nitrogen 

storage tank, ambient vaporizer, steam vaporizer, vacuum breaker, valves, piping, controls, and 

instrumentation. The purge and inerting system provides containment vent paths to the standby gas treatment system, which provides a vent path to the main stack for containment vent and purge 

operations. 

Reactor Core Isolation Cooling System 

The RCIC system is a high-pressure coolant makeup system that supports reactor shutdown when 

the feedwater system is unavailable. The RCIC system provides the capability to maintain the 

reactor in a hot standby condition for an extended period. Normally, however, the RCIC system is 

used until the reactor pressure is sufficiently reduced to permit use of the shutdown cooling mode 

of the RHR system. 

The RCIC system consists of a turbine-driven pump, piping and valves, and the instrumentation 

necessary to maintain the water level in the reactor vessel above the top of the active fuel should 

the reactor vessel be isolated from normal feedwater flow. Also included in the design of the RCIC 

system is a barometric condenser, and vacuum and condensate pumps to prevent steam from 

leaking into the environment.

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Residual Heat Removal System

The RHR system is composed of several components and subsystems that are required to maintain 

the following functions: 

* Restore and maintain reactor vessel water level after a LOCA. 

0 Limit temperature and pressure inside the containment after a LOCA. 

* Remove heat from the suppression pool water. 

* Remove decay and residual heat from the reactor core to achieve and maintain a cold 

shutdown condition. 

The RHR system consists of four pumps and two heat exchangers divided into two loops of two 

pumps and one heat exchanger each, plus the associated instruments, valves, and piping. The 

RHR pumps take suction from the suppression pool or the reactor coolant recirculation loop. The 

pumps discharge into the recirculation loop, the suppression pool, the containment spray headers, 

and the spent-fuel pool cooling and cleanup system, depending upon the desired mode of system 

operation. The RHR system interfaces with the recirculation system to provide a flow-path in 

support of shutdown cooling and LPCI. The RHR system is part of the reactor coolant pressure 

boundary; therefore, it also maintains the pressure boundary during normal operation, transients, 

and accident scenarios to prevent the release of radioactive liquid and gas. 

The RHR system is cooled through the heat exchangers by the RHRSW system, which takes 

suction from the Altamaha River. There are four RHRSW pumps per unit. The RHRSW system 

also serves as a standby coolant supply system by providing a means of injecting makeup water 

from the river to the RHR system to keep the core covered during an extreme emergency. 

Standby Gas Treatment System 

The SGTS is an ESF system for ventilation and cleanup of the primary and secondary containment 

during certain postulated DBAs. As such, the SGTS meets the design, quality assurance, 

redundancy, energy source, and instrumentation requirements for ESF systems. The SGTS is also 

used as a normal means of venting the drywell. 

The major components of the SGTS are redundant filter trains, control valves, backdraft dampers, 

fans, and control instrumentation. Each of the filtration assemblies and their respective components 

are designed for 100 percent-capacity operation. 

Standby Liquid Control System 

The SLCS ensures reactor shutdown, from full power operation to cold subcritical, by mixing a 

neutron absorber with the primary reactor coolant. The system is designed for the condition when 

an insufficient number of control rods can be inserted from the full-power setting. The neutron 

absorber is injected within the core zone in sufficient quantity to provide a sufficient margin for 

leakage or imperfect mixing. The system is not a scram or a backup scram system for the reactor; 

rather, it is an independent backup system for the CRD system.

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The SLCS is located in the reactor building, and consists of a low-temperature sodium pentaborate 

solution storage tank; a test tank; a pair of full-capacity positive displacement pumps; two explosive 

actuated shear plug valves; two accumulators; the poison sparger; and the necessary piping, valves, 

and instrumentation. The SLCS is manually initiated from the control room by use of a 

three-position key-lock switch. 

3.3.2.1 Aging Effects and Aging Management Programs 

The applicant presented the aging effects and aging management programs for the subsystems in 

the ESF system in Sections C.1 and C.2 of the LRA. The applicable internal environments for the 

components in the ESF systems are: reactor water, demineralized water, suppression pool, borated 

water, river water, dry compressed gas, humid or wetted gases, and inside environments. Extemal 

environments are defined in Sections C.1.2.8, "Inside;" C.1.2.9, "Outside;" and C.1.2.10, "Buried or 

Embedded" of the LRA. "Inside" external environments are defined as environments where 

equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. 

Cracking due to thermal fatigue is an applicable aging effect for several ESF components. The 

applicant states that all non-Class 1 components are enveloped by a TLAA that adequately 

addresses this aging effect without regard to the individual component or system conditions. This 

analysis is presented in Section 4.2.3 of the application. The staff's evaluation of this analysis is 

presented in 4.2 of this SER. 

Reactor Water Environment 

Section C.2.2.1 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel and stainless steel. The reactor water is used in the power cycle, and 

is demineralized and maintained with low levels of impurities (halogens and sulfates) and minimal 

dissolved oxygen concentrations. 

Based on Tables 3.2.3-4 and 3.2.3-5 of the LRA, the HPCI system and the RCIC system contain 

piping, restricting orifices, valve bodies, and steam traps manufactured from carbon or stainless 

steels, and are exposed to the reactor water environment under normal conditions. 

The aging effects of carbon steel components exposed to the reactor water environment are loss 

of material and cracking. The management of these aging effects is achieved through the following 

aging management programs: 

* reactor water chemistry control 

* flow accelerated corrosion program 

• treated water systems piping inspections 

° galvanic susceptibility inspections 

The aging effects of stainless steel components exposed to the reactor water environment are loss 

of material and cracking. The management of these aging effects is achieved through the following 

aging management programs:

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* reactor water chemistry control 

* treated water systems piping inspections 

Demineralized Water Environment 

Section C.2.2.2 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel and stainless steel. The demineralized water is processed on site and 

stored in demineralized water storage tanks and condensate storage tanks. Detrimental impurities and conductivity are maintained at low levels, but dissolved oxygen concentrations are neither 

controlled nor monitored. 

Based on Tables 3.2.3-4 and 3.2.3-5 of the LRA, the HPCI system and the RCIC system contain 

piping, pump casings, restricting orifices, valve bodies, and thermowells manufactured from these 

materials and exposed to the demineralized water environment under normal conditions. 

The aging effects of carbon steel components exposed to the demineralized water environment are 

loss of material and cracking. The management of these aging effects is achieved through the 

following aging management programs: 

* demineralized water and condensate storage tank chemistry control 

• treated water systems piping inspections 

* galvanic susceptibility inspections 

The aging effects of stainless steel components exposed to the demineralized water environment 

are loss of material and cracking. The management of these aging effects is achieved through the 

following aging management programs: 

* demineralized water and condensate storage tank chemistry Control 

* treated water systems piping inspections 

Suppression Pool Environment 

Section C.2.2.3 of the LRA discusses the aging management of various materials in this commodity 

group, including carbon steel, cast austenitic stainless steel, and stainless steel. The suppression 

pool water is contained within the torus, and consists of demineralized water supplied from sources 

such as the condensate storage tanks. Detrimental impurities and conductivity are maintained at 

low levels, although allowable levels are well above those acceptable for demineralized water. 

Dissolved oxygen concentrations are neither controlled nor monitored. 

Based on Tables 3.2.3-2, 3.2.3-3, 3.2.3-4, 3.2.3-5, and 3.2.3-7 of the LRA, the RHR system, the 

CS system, the HPCI system, the RCIC system, and the primary containment purge and inerting 

system contain conductivity elements, piping, pump casings, restricting orifices, strainers, 

thermowells, and valve bodies that are manufactured from these materials and are exposed to the 

suppression pool water environment under normal conditions. 

The aging effects of carbon steel components exposed to the suppression pool water environment 

are loss of material and cracking. The management of these aging effects is achieved through the 

following aging management programs:

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• suppression pool chemistry control

0 protective coatings program (external surfaces of submerged carbon steel components in 

suppression pool) 

0 torus submerged components inspection program 

* treated water systems piping inspections 

* galvanic susceptibility inspections 

The aging effects of stainless steel and cast austenitic stainless steel components exposed to the 

suppression pool water environment are loss of material and cracking. The management of these 

aging effects is achieved through the following aging management programs: 

* suppression pool chemistry control 

• torus submerged components inspection program 

* treated water systems piping inspections 

Borated Water Environment 

Section C.2.2.4 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel and stainless steel. The borated water is contained within the SLCS 

and consists of demineralized water supplied from the demineralized water storage tank, with 

approximately 10 percent by weight sodium pentaborate added. Concentrations of anion species 

are quite low, thereby minimizing significant corrosion within the system. The SLCS storage tank 

is not regularly monitored for detrimental impurities. 

Based on Table 3.2.3-1 of the LRA, the SLCS contains piping, pump accumulators, pump casings, 

tanks, thermowells, and valve bodies that are manufactured from these materials and are exposed 

to the borated water environment under normal conditions. 

The aging effects of carbon steel components exposed to the borated water environment are loss 

of material and cracking. The management of these aging effects is achieved through the following 

aging management programs: 

• protective coatings program 

* demineralized water and condensate storage tank chemistry control 

The aging effects of stainless steel components exposed to the borated water environment are loss 

of material and cracking. The management of these aging effects is achieved through the following 

aging management programs: 

* demineralized water and condensate storage tank chemistry control 

* treated water systems piping inspections

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River (Raw) Water Environment

Section C.2.2.6 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel, stainless steel, cast austenitic stainless steel, and copper alloys. River water is supplied from the Altamaha River via a roughly screened intake structure. It is 

assumed that some debris, silt, and macroorganisms may be introduced into the plant service water 

(PSW) and RHR service water (RHRSW) systems. 

Based on Table 3.2.3-2 of the LRA, the RHRSW system contains piping, pump discharge heads, 

pump casings, restricting orifices, strainer bodies, tubing, and valve bodies that are manufactured 

from these materials and exposed to the river water environment under normal conditions. 

The aging effects of carbon steel components exposed to the river water environment are loss of 

material, cracking, and flow blockage. The management of these aging effects is achieved through 

the following aging management programs: 

* PSW and RHRSW chemistry control 

* PSW and RHRSW inspection program 

* galvanic susceptibility inspections 

The aging effects of stainless steel, cast austenitic stainless steel, and copper alloy components 

exposed to the river water environment are loss of material, cracking, and flow blockage. The 

management of these aging effects is achieved through the following aging management programs: 

* PSW and RHRSW chemistry control 

* PSW and RHRSW inspection program 

Dry Cominressed Gas Environment 

Section C.2.2.8 of the LRA discusses the aging management of various materials in this commodity 

group, including carbon steel and stainless steel. The dried gas environment includes any process 

gas including, but not limited to air, nitrogen (including cyrogenic), carbon dioxide, hydrogen, helium, 

and fluorocarbons supplied from a tank or bottle or is filtered and desicated to remove moisture prior 

to entering the system. 

Based on Tables 3.2.3-4 and 3.2.3-7 of the LRA, the HPCI system, and the primary containment 

purge and inerting system contain flexible connectors, piping, pressure buildup coils, rupture discs, 

storage tanks, valve bodies, and vaporizers that are manufactured from these materials and 

exposed to the dry compressed gas environment under normal conditions. 

The aging effect of all the above carbon steel and stainless steel components exposed to the dry compressed gas environment is cracking. The management of this aging effect is achieved through 

the TLAA on thermal fatigue, discussed in Section 4.2 of the LRA and reviewed by the staff in 

Section 4.2 of this SER. 

Humid and Wetted Gas Environment 

Section C.2.2.9 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel, gray cast iron, stainless steel, copper alloy, galvanized carbon steel,

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and aluminum. The non-dried gases included in the humid and wetted environment is air (nitrogen in the case of the inerted drywell) containing humidity or significant moisture. These gases are 

assumed to contain sufficient moisture and oxygen to enable pooling of the liquid at low or 

especially cool locations and promote corrosion. 

Based on Tables 3.2.3-2,3.2.3-4,3.2.3-5,3.2.3-6,3.2.3-7, and 3.2.3-8 of the LRA, the RHR system, the HPCI system, the RCIC system, the SGTS, the primary containment purge and inerting system, and the post-LOCA hydrogen recombiner system (Unit 2 only) contain piping, turbine casing, restricting orifice, valve bodies, steam trap, strainer-steam exhaust, filter housing, rupture disc, 

thermowell, flex hose, and nitrogen tank jacket that are manufactured from these materials and 

exposed to the humid and wetted gas environment under normal conditions. 

The aging effect of carbon steel and gray cast iron components exposed to the wetted gas environment is loss of material. The management of this aging effect is achieved through the 

following aging management programs: 

• gas systems component inspections 

• passive component inspection activities 

The aging effect of stainless steel, copper, and copper alloy components exposed to the wetted gas 

environment is loss of material. The management of this aging effect is achieved through the 

following aging management programs: 

* gas systems component inspections 

• passive component inspection activities 

The other aging effect of carbon steel and stainless steel components exposed to the wetted gas environment is cracking. Two aging mechanisms can lead to cracking: stress corrosion cracking in stainless steels (where the normal operating temperature exceeds 140 OF) and thermal fatigue. Stress corrosion cracking will also be managed through the gas systems component inspections and the passive components inspection activities. The management of cracking due to thermal 

fatigue is achieved through the TLAA on thermal fatigue, discussed in Section 4.2 of the LRA and 

reviewed by the staff in Section 4.2 of this SER. 

Inside Environment 

Section C.2.4.1 of the LRA, discusses the aging management of various materials in this commodity 

group, including carbon steel, cast iron, stainless steel, copper alloy, galvanized carbon steel, and 

cast iron. The normal inside environment is an environment where minimal wetting and wet/dry 

cycling is expected to occur. 

Based on Tables 3.2.3-2, 3.2.3-4, and 3.2.3-5 of the LRA, the RHR system, the HPCI system, and 

the RCIC system contain pump sub bases and pump base plates that are manufactured from 

carbon steel and exposed to the inside environment. 

The aging effect of the carbon steel components exposed to the inside environment is loss of 

material. The management of this aging effect is achieved through the protective coatings aging 

management program.

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Bolting Materials

Section C.2.2.10 of the LRA, discusses only the carbon steel and stainless steel bolting pertaining 

to piping connections that are exposed to inside and outside environments. 

Based on Tables 3.2.3-1 through 3.2.3-5,3.2.3-7, and 3.2.3-8 of the LRA, all ESF systems, contain 

these bolts which are subject to an AMR. 

The aging effects of carbon steel bolts exposed to an inside or outside environment are loss of 

material and loss of preload. The management of these aging effects is achieved through the 

following aging management programs: 

• torque activities 

• protective coatings program 

The aging effect of stainless steel bolts exposed to an inside or outside environment is loss of 

preload. The management of this aging effect is achieved through the torque activities. 

Residual Heat Removal Heat Exchangers 

Section C.2.2.11 of the LRA discusses the residual heat removal system heat exchangers, which 

are fabricated from several different materials and are exposed to multiple fluid environments. 

Based on Table 3.2.3-2 of the LRA, the RHR heat exchangers contain several components that are 

subject to an AMR, including stainless steel heat exchanger tubes; carbon steel shell, shell nozzles, 

and shell internals; carbon steel channel assembly; carbon steel tube sheet with stainless steel 

cladding on raw water surfaces only; and stainless steel impingement plates. 

The aging effects associated with these components are cracking, loss of material, and loss of heat 

exchanger performance. These aging effects are managed through the following programs: 

* RHR heat exchanger augmented inspection and testing program 

* Inservice inspection program 

* suppression pool chemistry control 

* plant service water and RHR service water chemistry control 

3.3.3 Staff Evaluation 

The applicant described its AMR of the SLCS, RHR system, CS system, HPCI system, RCIC 

system, SGTS, primary containment purge and inerting system, and post-LOCA hydrogen 

recombiners system (Unit 2 only), collectively called the ESF systems, in Section 3.2.3 and Sections 

A, B, and C of the LRA. In response to the staff's concerns regarding the aging management 

programs, the applicant provided Section B, "Response to Requests for Additional Information 

Related to Aging Management Programs Dated July 14, 2000 and July 28, 2000." The staff 

reviewed these sections of the LRA to determine whether the applicant has demonstrated that the 

effects of aging on the ESF systems will be adequately managed during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3).

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The staff's evaluation of the applicable aging effects for each ESF system and the aging 

management programs is presented in a manner similar to that provided in the LRA. The aging 

effects are discussed based on the environment, with a list of systems in which the environment is 

found. The aging management programs credited with managing these aging effects are also 

discussed. The aging effects for ESF components and the credited aging management programs 

discussed below are based on the stated internal environment, unless otherwise noted. Structures 

and components which perform their functions in external environments are, in general, discussed 

in Sections 3.2 through 3.7 of the LRA, and are evaluated in Sections 3.6 and 3.7 of this SER, 

unless otherwise noted. 

By letter dated June 5, 2001, the applicant provided additional information to address Open 

Item 2.3.3.2-1 regarding the post-LOCA hydrogen recombiner system. The applicant provided 

additional information for the hydrogen recombiner skid components, consistent with NRC guidance 

on the evaluation of skid-mounted assemblies. The applicant added the following mechanical 

components to the list provided in Table 2.3.3-8 of the LRA: carbon steel blower casing, carbon and 

stainless steel instrumentation, stainless steel piping, stainless steel reaction chamber, carbon steel 

water separator and stainless steel water spray cooler. In addition to listing these mechanical 

components in the scoping section of the LRA, the applicant provided supplementary information 

for Table 3.2.3-8, "Aging Effects Requiring Management for Components Supporting Post LOCA 

Hydrogen Recombiner System [T49] Intended Functions and Their Component Functions (Unit 2 

only)." 

The applicant stated that for the carbon and stainless steel instrumentation, piping, reaction 

chamber and water spray cooler in a wetted gas environment, the applicable aging effects are 

cracking due to thermal fatigue and loss of material. The gas systems component inspection 

program is credited for managing these aging effects. For the carbon steel blower casing and 

carbon steel water separator in a wetted gas environment, the applicant listed cracking due to 

thermal fatigue and loss of material as applicable aging effects. The passive component inspection 

activities program and the gas systems component inspection program are credited for managing 

these aging effects. The staff has reviewed the information discussed in the applicant's open item 

response and concludes that the applicable aging effects and aging management programs listed 

for the additional components are appropriate and acceptable. The programs credited for managing 

the aging effects are evaluated in Sections 3.1.25 (gas systems component inspection program) and 

3.1.27 (passive component inspection activities program) of the SER and is consistent with 

components made of similar materials exposed to the wetted gas environment. 

By letter dated June 5, 2001, the applicant also provided additional information to address Open 

Item 2.3.3.2-2 regarding the SGTS. The applicant provided additional information related to the 

identification and management of aging effects for those fans, dampers, and heating and cooling 

coil housings which are within the scope of license renewal. The applicant revised the first sentence 

of the second paragraph in LRA Section 2.3.3.6, "Standby Gas Treatment System [T46]," to state, 

"The major components of the SGTS include redundant filter trains, control valves, air-operated and 

backdraft dampers, fans and control instrumentation." In addition, the applicant added the carbon 

steel damper (frame only) and carbon steel fan housing to LRA Table 2.3.3-6 and Table 3.2.3-6, 

"Aging Effects Requiring Management for Components Supporting Standby Gas Treatment System 

[T46] Intended Functions and Their Component Functions." 

The applicant stated that for the carbon steel damper (frame only) and fan housing exposed to an 

air environment, the applicable aging effects are cracking and loss of material. The passive

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component inspection activities program and the gas systems component inspection program are 

credited for managing these aging effects. The staff has reviewed the information discussed in the 

applicant's open item response and concludes that the applicable aging effects and aging 

management programs listed for the additional components are appropriate and acceptable. 

The programs credited for managing the aging effects are evaluated in Sections 3.1.25 (gas 

systems component inspection program) and 3.1.27 (passive component inspection activities 

program) of the SER and is consistent with components made of similar materials exposed to the 

wetted gas environment. 

3.3.3.1 Aging Effects 

Reactor Water Environment 

The applicant lists carbon steel and stainless steel components exposed to the reactor water 

environment in the HPCI system and the RCIC system. The aging effects of carbon steel 

components exposed to the reactor water environment are loss of material due to general corrosion, 

galvanic corrosion, microbiologically influenced corrosion (MIC), crevice corrosion, pitting, and 

erosion corrosion; and cracking due to thermal fatigue. The aging effects of stainless steel 

components exposed to the reactor water environment are loss of material due to crevice corrosion, 

pitting, and MIC; and cracking due to SCC, IGA, and thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a reactor water environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects. 

Demineralized Water Environment 

The applicant lists carbon steel and stainless steel components that are exposed to the 

demineralized water environment in the HPCI system and the RCIC system. The aging effects of 

carbon steel components exposed to the demineralized water environment are loss of material due 

to general corrosion, galvanic corrosion, MIC, crevice corrosion, pitting, and erosion corrosion; and 

cracking due to thermal fatigue. The aging effects of stainless steel components exposed to the 

demineralized water environment are loss of material due to crevice corrosion, pitting, and MIC; and 

cracking due to thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a demineralized water environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects. 

Suppression Pool Environment 

The applicant lists carbon steel, stainless steel, and cast austenitic stainless steel components 

exposed to the suppression pool environment in the RHR system, the CS system, the HPCI system, 

the RCIC system, and the primary containment purge and inerting system. The aging effects of 

carbon steel components exposed to the suppression pool water environment are loss of material 

due to general corrosion, galvanic corrosion, MIC, crevice corrosion, pitting, and erosion corrosion; 

and cracking due to thermal fatigue. The aging effects of stainless steel components exposed to

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the suppression pool water environment are loss of material due to crevice corrosion, pitting, and 

MIC; and cracking due to thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging 

effects on materials in a suppression pool environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects. 

Borated Water Environment 

The applicant lists carbon steel and stainless steel components exposed to the borated water 

environment in the SLCS. The aging effects of carbon steel components exposed to the borated 

water environment are loss of material due to general corrosion, galvanic corrosion, MIC, crevice 

corrosion, and pitting; and cracking due to thermal fatigue. The aging effects of stainless steel 

components exposed to the borated water environment are loss of material due to crevice corrosion, 

pitting, and MIC; and cracking due to thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a borated water environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects. 

River Water Environment 

The applicant lists carbon steel, stainless steel, stainless steel-clad carbon steel, cast austenitic 

stainless steel, and copper alloy components exposed to river water in the RHRSW system. The 

aging effects of carbon steel components exposed to the river water environment are loss of 

material due to general corrosion, galvanic corrosion, MIC, crevice corrosion, fouling, erosion

corrosion and pitting; cracking due to thermal fatigue; and flow blockage due to fouling. The aging effects of stainless steel components exposed to the river water environment are loss of material 

due to crevice corrosion, pitting, MIC, and fouling; cracking due to thermal fatigue; and flow 

blockage due to fouling. The aging effects of copper alloy components exposed to the river water 

environment are loss of material due to selective leaching, galvanic corrosion, MIC, fouling and 

erosion corrosion; cracking due to thermal fatigue; and flow blockage due to fouling. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a river water environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects. 

Dry Compressed Gas Environment 

The applicant lists carbon steel and stainless steel components exposed to the dry compressed gas environment in the HPCI system and the primary containment purge and inerting system. The aging effect of carbon steel and stainless steel components exposed to the dry compressed gas 

environment is cracking due to thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a dry compressed gas environment, the staff concludes that the applicant has 

adequately identified the applicable aging effects.

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Humid and Wetted Gas Environment

The applicant lists carbon steel, cast iron, stainless steel, copper alloy, and galvanized carbon steel 

components exposed to the nondried (wetted) gases in the RHR system, the HPCI system, the 

RCIC system, the SGTS, the primary containment purge and inerting system, and the post-LOCA hydrogen recombiner system (Unit 2 only). The aging effects for carbon steel components exposed 

to the wetted gas environment are loss of material due to general corrosion, selective leaching, pitting, crevice corrosion, galvanic corrosion, and MIC; and cracking due to thermal fatigue. The 

aging effects of stainless steel components exposed to the wetted gas environment are loss of 

material due to pitting, crevice corrosion, and MIC; and cracking due to thermal fatigue, SCC, and 

IGA. The aging effects for copper alloy components exposed to a wetted gas environment are loss 

of material due to selective leaching, pitting, crevice corrosion, MIC, and galvanic corrosion, and 

cracking due to thermal fatigue. The aging effects for galvanized carbon steel exposed to the 

wetted gas environment are loss of material due to general corrosion, galvanic corrosion, crevice 

corrosion, pitting, and MIC, and cracking due to thermal fatigue. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on materials in a humid and wetted gas environment, the staff concludes that the applicant 

has adequately identified the applicable aging effects. 

Inside Environment 

The applicant lists carbon steel components exposed to a normal inside environment in the RHR 

system, the HPCI system, and the RCIC system. The aging effect of carbon steel components exposed to the inside environment is loss of material due to general corrosion in areas where the 

external surface is less than 2000F. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging 

effects on materials in an inside environment, the staff concludes that the applicant has adequately 

identified the applicable aging effects. 

Bolting Materials 

The applicant lists carbon steel and stainless steel bolting associated with piping connections that 

are exposed to inside and outside environments at Plant Hatch. These components are found in 

the SLCS, the RHR system, the CS system, the HPCI system, the RCIC system, the primary containment purge and inerting system, and the post-LOCA hydrogen recombiner system (Unit 2 

only). The aging effects of carbon steel bolts exposed to an inside or outside environment are loss 

of material due to general corrosion in the inside environment, and general corrosion, MIC, crevice 

corrosion, and pitting in the outside environment; and loss of preload due to embedment, gasket 

creep, thermal effects, and self-loosening. The aging effect of stainless steel bolts exposed to an 

inside or outside environment is loss of preload due to embedment, gasket creep, thermal effects, 

and self-loosening. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging 

effects on bolting materials in various environments, the staff concludes that the applicant has 

adequately identified the applicable aging effects.

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Residual Heat Removal Heat Exchangers

The applicant lists different components fabricated from several different materials that are exposed 

to multiple fluid environments. The aging effects associated with these components are cracking 

due to SCC and IGA of stainless steel components and vibration-induced fatigue; loss of material 

due to general corrosion, galvanic corrosion, crevice corrosion, pitting, MIC, and fouling; and loss 

of heat exchanger performance due to corrosion product buildup, silting, and macroorganism 

intrusion. 

On the basis of the staff's evaluation of the information provided in the LRA with regard to aging effects on RHR heat exchanger materials in various environments, the staff concludes that the 

applicant has adequately identified the applicable aging effects. 

Summary of the Review of Aging Effects Operating Experience 

The staff has reviewed the information provided by the applicant regarding plant-specific, as well 

as industry-wide experience to support its identification of applicable aging effects. This included 

the description of the internal and external environments, and materials of fabrication for these 

systems. On the basis of this review, the staff concludes that the applicant has included aging effects that are consistent with published literature and industry experience and, thus, are 

acceptable to the staff. 

3.3.3.2 Aging Management Programs 

Reactor Water Chemistry Control 

The reactor water chemistry control program is an existing program at Plant Hatch that includes 

regular sampling, results analysis, and when applicable, chemistry modification of reactor water. 

In addition, the collected data are regularly trended, tracked, and evaluated. This program is 

credited for managing the aging effects of components in the HPCI system and the RCIC system. The staff's detailed review of this program is described in Section 3.1.1 of this SER. Based on its 

evaluation, the staff concludes that this aging management program is acceptable in managing the 

aging effects associated with carbon and stainless steel components exposed to the reactor water 

environment. 

Flow-Accelerated Corrosion Program 

The FAC program is a condition monitoring program designed to monitor pipe wear in those 

systems that have been determined to be susceptible to FAC-related loss of material. This program includes prediction of susceptibility through modeling and testing to detect wall thinning, and is 

credited for managing the aging effects of carbon steel components in the HPCI system and the 

RCIC system. The staff's detailed review of this program is described in Section 3.1.19 of this SER. 

Based on its evaluation, the staff concludes that this aging management program is acceptable in 

managing the aging effects associated with carbon steel components exposed to the reactor water 

environment.

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Treated Water Systems Piping Inspection

The treated water systems piping inspection is a new activity at Plant Hatch that will provide for 

condition monitoring via one-time examinations intended to provide objective evidence that 

chemistry control is managing aging in piping that is not examined under another inspection 

program. This program is credited for managing the aging effects of components in the HPCI 

system, RCIC system, RHR system, CS system, primary containment purge and inerting system, 

and SLCS. The staff's detailed review of this program is described in Section 3.1.24 of this SER. 

Based on its evaluation, the staff concludes that this aging management program is acceptable in 

managing the aging effects associated with carbon steel, stainless steel, and cast austenitic 

stainless steel components exposed to the reactor water, demineralized water, and suppression 

pool water environments. In addition, the staff finds this aging management program acceptable 

in managing the aging effects associated with stainless steel components exposed to a borated 

water environment. 

Galvanic Susceptibility Inspections 

Galvanic susceptibility inspection is a new activity at Plant Hatch that will provide for condition 

monitoring via one-time inspections to objectively determine that galvanic susceptibility is being 

managed for specific components within the scope of license renewal. This program is credited for 

managing the aging effects of components in the HPCI system, RCIC system, RHR system, CS 

system, and primary containment purge and inerting system. The staff's detailed review of this 

program is described in Section 3.1.23 of this SER. Based on its evaluation, the staff concludes that 

this aging management program is acceptable in managing the aging effects associated with carbon 

steel components exposed to the reactor water, demineralized water, suppression pool water, and 

river water environments. 

Demineralized Water and Condensate Storage Tank Chemistry Control 

The demineralized water and condensate storage tank chemistry control activities mitigate aging 

by monitoring fluid purity and composition in the makeup water to multiple systems. These activities 

are regular sampling, results analysis, and when applicable, chemistry modification. This program is credited for managing the aging effects of components in the HPCI system, RCIC system, and 

SLCS. The staff's detailed review of this program is described in Section 3.1.6 of this SER. Based 

on its evaluation, the staff concludes that this aging management program is acceptable in 

managing the aging effects associated with carbon and stainless steel components exposed to the 

demineralized water and borated water environments. 

Suppression Pool Chemistry Control 

The suppression pool chemistry control activities mitigate aging in components exposed to the 

suppression pool water by controlling fluid purity and composition in the pool. This program is 

credited for managing the aging effects of components in the RHR system, CS system, HPCI 

system, RCIC system, and primary containment purge and inerting system. The staff's detailed 

review of this program is described in Section 3.1.7 of this SER. Based on its evaluation, the staff 

concludes that this aging management program is acceptable in managing the aging effects 

associated with carbon and stainless steel components exposed to the suppression pool 

environment. In addition, the staff finds these activities acceptable in managing the aging effects 

associated with the RHR heat exchangers.

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Protective Coatinas Proaram

The protective coatings program is a mitigation and condition monitoring program that provides a 

means of preventing or minimizing aging effects that would otherwise result from contact of the base 

metal with the associated environment. This program is credited for managing the aging effects of 

components in the RHR system, CS system, HPCI system, RCIC system, primary containment 

purge and inerting system, SLCS, and SGTS. The staff's detailed review of this program is 

described in Section 3.1.20 of this SER. Based on its evaluation, the staff concludes that this aging management program is acceptable in managing the aging effects associated with the external 

surfaces of carbon steel components exposed to the inside, outside, and buried environments. In 

addition, the staff finds these activities acceptable in managing the aging effects associated with 

bolting materials. 

Torus Submerged Components Inspection Program 

The torus submerged components inspection program is a condition monitoring activity that 

evaluates the effectiveness of the current suppression pool chemistry control in preventing loss of 

material and cracking. This program is credited for managing the aging effects of components in 

the RHR system, CS system, HPCI system, RCIC system, and primary containment purge and 

inerting system. The staff's detailed review of this program is described in Section 3.1.29 of this 

SER. Based on its evaluation, the staff concludes that this aging management program is 

acceptable in managing the aging effects associated with carbon steel and stainless steel 

components exposed to the suppression pool environment. 

Plant Service Water and RHR Service Water Chemistry Control 

The PSW and RHRSW chemistry control activities mitigate aging in system piping and components by controlling fluid composition. Chlorination and bromination are coordinated with periodic operation of the RHRSW to maximize chemical treatment. This program is credited for managing the aging effects of components in the PSW and RHRSW systems. The staff's detailed review of 

this program is described in Section 3.1.4 of this SER. Based on its evaluation, the staff concludes 

that this aging management program is acceptable in managing the aging effects associated with 

carbon steel, clad carbon steel, stainless steel, cast austenitic stainless steel, gray cast iron, and 

copper alloy components exposed to the river water environment. In addition, the staff finds these 

activities acceptable in managing the aging effects associated with the RHR heat exchangers. 

Plant Service Water and RHR Service Water Inspection Program 

The PSW and RHRSW inspection program is a condition monitoring program that is designed to 

detect wall thickness degradation or fouling in the PSW and RHRSW systems. This program is 

credited for managing the aging effects of components in the PSW and RHRSW systems. The 

staff's detailed review of this program is described in Section 3.1.13 of this SER. Based on its 

evaluation, the staff concludes that this aging management program is acceptable in managing the 

aging effects associated with carbon steel, stainless steel, cast austenitic stainless steel, gray cast 

iron, and copper alloy components exposed to the river water environment.

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Gas Systems Component Inspection

The gas system component inspection is a new activity that will provide for condition monitoring via 

a one-time condition monitoring aging management activity designed to provide objective evidence 

that the aging effects predicted for systems with gases as internal environments are adequately 

managed. This program is credited for managing the aging effects of components in HPCI system, primary containment purge and inerting system, RHR system, RCIC system, SGTS, and post-LOCA 

hydrogen recombiner system (Unit 2 only). The staff's detailed review of this program is described 

in Section 3.1.25 of this SER. Based on its evaluation, the staff concludes that this aging 

management program is acceptable in managing the aging effects associated with carbon steel, 

stainless steel, copper alloy, gray cast iron, and copper components exposed to a humid or wetted 

gas environment. 

Passive Component Inspection Activities 

The passive component inspection activities program comprises a new condition monitoring AMP 

that is designed to collect, report, and trend age-related data to determine the effectiveness of 

preventive or mitigative programs/activities credited for aging management. This activity is credited 

for managing the aging effects of components in the RHR system, HPCI system, RCIC system, SGTS, primary containment purge and inerting system, and post-LOCA recombiner system (Unit 

2 only). The staff's detailed review of this program is described in Section 3.1.27 of this SER. 

Based on its evaluation, the staff concludes that this aging management program is acceptable in 

managing the aging effects associated with carbon steel, stainless steel, cast austenitic stainless 

steel, and gray cast iron components exposed to a humid or wetted gas environment. 

Torque Activities 

The torque activities mitigate loss of preload through the use of proper torque techniques at Plant 

Hatch. Plant procedures specify techniques for maximizing the effectiveness of torque activities. 

This activity is credited for managing the aging effects of bolts in the ESF systems. The staff's 

detailed review of this program is described in Section 3. 1.11 of this SER. Based on its evaluation, the staff concludes that this aging management program is acceptable in managing the aging effects associated with carbon and stainless steel bolting materials. 

RHR Heat Exchanger Augmented Inspection and Testing Program 

The RHR heat exchanger augmented inspection and testing program will provide for condition 

monitoring of both the shell and tube sides of the Units 1 and 2 RHR heat exchangers. This 

program is credited for managing the aging effects of components in the RHR system. The staff's 

detailed review of this program is described in Section 3.1.28 of this SER. Based on its evaluation, 

the staff concludes that this aging management program is acceptable in managing the aging effects associated with the RHR heat exchangers. 

Inservice Inspection (ISI) Program 

The ISI program is a condition monitoring program that provides for the implementation of ASME 

Section Xl, in accordance with the provisions of 10 CFR 50.55a. This program also includes 

augmented examinations required to satisfy commitments made by the applicant, and is credited 

for managing the aging effects of components in the RHR system. The staff's detailed review of

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this program is described in Section 3.1.9 of this SER. Based on its evaluation, the staff concludes 

that this aging management program is acceptable in managing the aging effects associated with 

the RHR heat exchangers. 

3.3.4 Conclusions 

The staff has reviewed the information in Section 3.2.3, "Engineered Safety Features," of the LRA. 

On the basis of this review, the staff concludes that the applicant has adequately identified the aging 

effects, and has demonstrated that the aging effects associated with the ESF systems will be 

adequately managed so that there is reasonable assurance that these systems will perform their 

intended functions in accordance with the CLB during the period of extended operation. 

3.4 Auxiliary Systems 

3.4.1 Introduction 

The applicant provided the results of its AMR for the auxiliary systems for license renewal in Section 

3.2.4, "Auxiliary Systems," and Section C.2 of the LRA. The staff reviewed these sections of the 

LRA to determine whether the applicant has demonstrated that the effects of aging on the auxiliary 

systems will be adequately managed during the period of extended operation, as required by 10 

CFR 54.21 (a)(3). 

Section 3.2.4 of the LRA contains six-column tables for each auxiliary system, which represents an 

overview of the aging management review results. The tables list the in-scope components of each 

system, along with each component's in-scope function, materials of construction, working 

environment, aging effects, and the associated aging management programs that are credited with 

managing the aging effects. The tables also reference the commodity group associated with each 

component. The commodity groups are described in Section C.2 of the LRA. Each commodity 

group is associated with a common environment and group of materials. The commodity groups, 

in turn, reference Section C.1 of the LRA, which provides a detailed discussion of the environments, 

materials and associated aging effects. The commodity groups also reference Section A of the 

LRA, which describes the aging management programs that manage the specified aging effects. 

The applicant submitted a supplemental description of its aging management programs in Section 

B of the LRA on October 10, 2000. The staff reviewed these sections of the application to 

determine whether the applicant presented adequate information to meet the requirements set forth 

in 10 CFR 54.21 (a)(3). 

External environments are defined in Sections 3.1.2.8, "Inside;" 3.1.2.9, "Outside;" and 3.1.2.10, 

"Buried or Embedded" of the LRA. "Inside" external environments are defined as environments 

where equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. Structures 

and components which perform their functions in external environments are, in general, discussed 

in Sections 3.2, 3.3, 3.4, 3.5, 3.6, and 3.7 of the LRA, and are evaluated in Sections 3.6 and 3.7 of 

this SER, unless otherwise noted.

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3.4.2 Summary of Technical Information in the Application

The applicant provided an aging management review of 20 auxiliary systems that are considered 

to be within the scope of license renewal. A brief description of each system is presented below. 

Access Doors 

The secondary containment access doors provide access for personnel and equipment. In addition, 

the secondary containment, in conjunction with the primary containment and other engineering 

safeguards, provides the capability to limit the release of radioactive materials to the environment. 

Condensate Transfer and Storage System 

The condensate transfer and storage system provides the plant system makeup, receives reject 

flow, and provides condensate for any continuous service needs and intermittent batch-type 

services. A 500,000 gallon CST supplies the various unit requirements. The CST provides the 

preferred supply to the HPCI and RCIC systems. 

Control Building Heating Ventilation and Air Conditioning (HVAC) System 

Under normal and post-accident plant conditions, the control building HVAC system controls 

temperature and air movement, filters fresh-air supply for personnel comfort, removes heat from the 

plant equipment to optimize performance, minimizes the potential for exhaust air to enter the supply 

air, and detects and limits the introduction of radioactive material into the main control room. The 

control room HVAC system provides cooling and maintains a controlled environment for personnel 

safety and habitability in the control room during normal and accident conditions. The system also 

provides a controlled temperature to ensure the reliability of the main control room components. 

Control Rod Drive System 

The CRD hydraulic system provides pressurized, demineralized water for the cooling and 

manipulation of the CRD mechanisms. The CRD system also provides purge water for the reactor 

water cleanup pump and reactor recirculation pump seals. The alternate rod insertion system is a 

subsystem of the CRD system. It is a backup means of scramming the reactor by venting the scram 

air header. The alternate rod insertion system is independent of the reactor protection system, and 

was installed to reduce the probability of an anticipated transient without scram event. 

Cranes, Hoists, and Elevators System 

The reactor building crane is the only in-scope component for the cranes, hoists, and elevators 

system. The reactor building crane moves major components for refueling operations and 

maintenance. The Unit 1 reactor building crane provides service to both Unit 1 and Unit 2.

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Drywell Pneumatics System

The drywell pneumatics system supplies the motive gas to various valves inside the drywell. 

Emergency Diesel Generators System 

The emergency diesel generators provide emergency backup power to 4160-V ac emergency buses 

E, F, and G in the event of a loss of offsite power. 

Fire Protection System 

The fire protection system ensures, through a defense-in-depth design, that a fire will not prevent 

the necessary safe plant shutdown functions from occurring. The program also decreases the risk 

of radioactive releases to the environment during a fire. The program consists of detection and 

extinguishing systems, administrative controls and procedures, and trained personnel. The 

applicant gave the primary design consideration to locating redundant safe shutdown circuits and 

components in distinct areas separated by fire barriers to prevent the propagation of fire to adjacent 

areas. Fire barriers consist of fire-rated doors, dampers, and penetration seals. The barriers are 

designed to contain a design-basis fire. The fire protection program at Plant Hatch also includes 

an early warning fire detection system. Two 300,000-gallon dedicated storage tanks provide the 

water supply for the fire protection system inside the protected area. These tanks, in turn, are 

supplied by two deep wells with strained and filtered water supplies for normal makeup. The fire 

protection system also includes cardox fire suppression for the emergency diesel generators to 

provide an automatic gaseous total flooding fire suppression system for a diesel engine 

compartment fire to contain and control the level of fire damage, and an automatic gaseous fire 

suppression system for the computer room and the cable spreading room. This is a total flooding 

system actuated by ionization detection. 

With regard to the inspection frequency of the fire system components, the applicant lists in Section 

B.2.1 of the LRA, the different inspection intervals for the water-based fire protection systems, fire 

protection pump diesel fuel oil supply system, compressed gas-based fire suppression systems, fire 

penetration seals, cable tray enclosures, and fire doors. In addition to the systems listed above, the 

applicant describes a one-time inspection called the "Sprinkler Head Inspections," that will be 

performed at or before the start of the extended period of operation for closed sprinkler heads within 

the scope of license renewal. 

Fuel Oil System 

The fuel oil system receives, stores, and supplies fuel oil to other systems including the emergency 

diesel generator system. 

Instrument Air System 

The instrument air system provides dried and filtered air to all of the air-operated instruments and 

valves throughout the entire plant (with the exception of the equipment inside the drywell). This 

system is made up of two subsystems, one of which is non-interruptible, while the other is 

interruptible. The non-interruptible system provides instrument air for the operation of certain 

emergency system components. The interruptible system provides instrument air to all other

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components. The drywell pneumatic system (discussed in more detail below) supplies the motive 

gas for components within the drywell. 

Insulation System 

Insulation helps to retain heat in the process piping and equipment, to prevent moisture from 

condensing on cold surfaces, to protect equipment and personnel from high temperatures, to 

prevent piping from freezing if cold areas of the plant, and to protect heat tracing from damage. The 

applicant also credits insulation in heat load calculations for safety-related rooms. Failure of this 

insulation could allow the heat load of the room to exceed the capability of the HVAC system, thus 

exceeding the design temperature of the room. 

Outside Structures HVAC System 

This group includes the intake structure HVAC and the diesel generator building HVAC systems. 

The intake structure HVAC system protects the intake structure equipment from adverse 

temperature conditions that could affect the reliability of the equipment. The diesel generator 

building HVAC system protects diesel generator building equipment from adverse temperature 

conditions that could affect the reliability of the equipment. In addition, the emergency diesel 

generator battery room ventilation system exhausts hydrogen from the battery rooms, and the 

emergency diesel generator building oil storage room ventilation exhausts fumes from the oil 

storage room in the event of fire. 

Plant Service Water System 

The plant service water system removes the heat that is generated from various systems. This 

system provides circulating water system makeup from screened Altamaha River water and, after 

cooling heat exchangers, provides makeup water to the circulating water flume. This system is also 

available for fire-fighting, radwaste dilution, and emergency spent fuel pool makeup. 

Primary Containment Chilled Water System (Unit 2 Only) 

The primary containment chilled water system maintains the drywell area below a maximum 

volumetric average temperature of 150°F dry bulb during normal operation. This function is fulfilled 

by providing chilled water to the drywell fan coil units. Reactor building service water provides the 

chiller condenser cooling water, while demineralized water provides makeup for the system. 

Reactor Building Closed Cooling Water System 

The reactor building closed cooling water system provides cooling water to auxiliary equipment 

located in the reactor building. 

Reactor Building HVAC System 

The reactor building HVAC system performs many functions. It provides an environment with 

controlled temperature and airflow to ensure the comfort and safety of operating personnel and to 

optimize equipment performance by removing heat from the plant equipment. It promotes air 

movement from operating areas and areas of lower airborne radioactivity potential to areas of 

greater airborne radioactivity potential prior to final filtration and exhaust. It minimizes the release

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of potential airborne radioactivity to the environment during normal plant operation by exhausting air, through a filtration system, from the areas in which a significant potential for radioactive 

particulates and/or radioiodine contamination exists. It provides a source of cooling to support the 

operation of the emergency core cooling systems. Lastly, the system provides isolation capability 

to maintain secondary containment integrity and support operation of the standby gas treatment 

system. The reactor building HVAC system uses a combination of air conditioning, heating, and 

once-through ventilation. Heat removal is provided by ventilation air and chilled-water (Unit 2 only) and service-water cooling coils served bythe reactor and radwaste building chilled water system and 

the plant service water system, respectively. Hot water heating coils, served by the plant heating 

system, are supplied for heating. 

Refueling Equipment System 

The refueling platform equipment assembly handles and transports reactor core internals and 

service and handling equipment associated with the refueling operation. The refueling platform is 

a bridge structure that spans the refueling pool and the reactor well and travels on rails which extend 

the length of the fuel storage pool and the reactor well. The fuel grapple extends downward, below 

the underside of the refueling platform, into the pool or reactor well. 

Sampling System 

The primary containment hydrogen and oxygen sampling system monitors hydrogen and oxygen 

in the primary containment (drywell and torus). 

Tornado Vents System 

The tornado vents act as blowout panels for venting the reactor and turbine building roofs (1) against a wind velocity of 300 mph, (2) when the internal static pressure in the building is increased 

to 55 lb/ft2, or (3) when the temperature reaches approximately 212 OF. A rapid depressurization 

of air surrounding site structures can occur if a tornado funnel suddenly engulfs a structure. Venting is accomplished by placing blowout panels, designed to fail at a pressure lower than the safe 

building capability for internal pressure, to relieve excess pressure in all essential parts of such 

structures. 

Traveling Water Screens/Trash Racks System 

The intake structure is equipped with trash screens and rakes to keep debris out of the pump wells. 

The traveling water screens prevent debris from entering the portion of the intake structure from 

which the pumps take suction. Larger debris is prevented from reaching the screens by the trash 

racks. The debris is removed from the screens by the screen wash water. 

3.4.2.1 Aging Effects and Aging Management Programs 

The applicant discussed the aging effects and aging management programs for the various auxiliary 

system components and environments at Plant Hatch in Sections C.1 and C.2 of the LRA. The 

applicant approached its aging management review in a manner that the staff and industry 

commonly refer to as the commodity group approach. Commodities are groups of structures or 

components that have similar intended functions and materials of construction and operate in similar 

environments. Because they are similar in material and environment, they can experience common

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aging effects, and common aging management programs can be credited for managing those aging effects. This approach is intended to achieve efficiency in the aging management review process. There are more than 20 commodity groups related to auxiliary systems because of the wide variety of environments that exist in the auxiliary systems. Therefore, the staff chose to present the 

applicant's aging management review based on environment, rather than commodity group, in order 

to consolidate and streamline this SER. These environments include demineralized water, dried and 

wetted gases, inside (sheltered) and outside (nonsheltered), raw water (including submerged components), closed cooling water, concrete embedment, and fuel oil environments. Each of these 

environments, the materials exposed to these environments, and the associated aging effects and 

aging management programs identified by the applicant are summarized below. 

Demineralized Water 

Demineralized water at Plant Hatch contains no corrosion inhibiting chemical or biocide additions, 

and provides no control of dissolved oxygen concentrations. Acceptable levels for impurities vary 

among systems driven by the relative potential for any given system to supply water to the reactor 

pressure vessel. Three auxiliary systems (control rod drive system, condensate transfer and 

storage system, and emergency diesel generators system) contain stainless steel, cast austenitic 

stainless steel, carbon steel, galvanized steel, or aluminum alloy components exposed to a 

demineralized water environment. The applicant discussed the aging management review for the 

auxiliary system structures and components exposed to a demineralized water environment in 

Section C.2.2.2 of the LRA. The applicant identified several forms of corrosion that may result in 

loss of material (e.g., general corrosion, galvanic corrosion, crevice corrosion, MIC, pitting, and 

erosion corrosion). To manage this aging effect, the applicant relies on the following aging 

management programs: 

0 demineralized water and condensate storage tank chemistry control 

0 treated water systems piping inspections 

0 galvanic susceptibility inspections 

• condensate storage tank inspection 

Dried and Wetted Gases 

The applicant defined the gas environment as any line that contains noncondensable gases and 

includes both dried and nondried (wetted) gases. Dried gases describe any process gas including, 

but not limited to, air, nitrogen (including cryogenic), carbon dioxide, hydrogen, helium, and 

fluorocarbons supplied from a tank or bottle or filtered and desiccated to remove moisture prior to 

entering the system. Five auxiliary systems (control rod drive system, instrument air system, drywell pneumatics system, fire protection system, and the control building HVAC system) contain carbon 

steel, stainless steel, or copper/copper alloy components exposed to a dried gas environment. The 

applicant discussed the aging management review for the auxiliary system structures and 

components exposed to a dried gas environment in Section C.2.2.8 and section C.2.3.3 of the LRA. 

Because sufficient moisture to drive the various corrosion mechanisms is not present, there are no 

aging effects that require management and, therefore, no aging management programs were 

identified. 

Wetted gases include hydrogen, oxygen, air or nitrogen containing humidity or significant moisture. 

Wetted gas environments are found inside of buildings, inside the drywell, and outside of buildings. These gases are assumed to contain sufficient entrained moisture and oxygen to enable pooling

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of liquid at low or especially cool locations and promote corrosion. Eight auxiliary systems (control 

rod drive system, sampling system, emergency diesel generator system, reactor building HVAC 

system, outside structures HVAC system, fire protection system, fuel oil system, and control building 

HVAC system) contain carbon steel, stainless steel, galvanized steel, copper/copper alloy, 

aluminum, or cast iron components, as well as gasket materials exposed to a wetted gas (this includes air) environment. The applicant discussed the aging management review for the auxiliary 

system structures and components exposed to a wetted gas environment in Section C.2.2.9 Section 

C.2.3.3 and Section C.2.6.7 of the LRA. The applicant identified several forms of corrosion that may result in loss of material (e.g., general corrosion, selective leaching, galvanic corrosion, crevice 

corrosion, MIC, and pitting). The applicant also identified cracking of gasket materials due to 

compaction and settling, exposure to moisture, and thermal effects. To manage these aging effects, 

the applicant relies on the following aging management programs: 

• gas systems component inspections 

• passive component inspection activities 

• fire protection activities 

Inside and Outside Environments 

An inside environment indicates that the equipment is sheltered from the weather. The inside 

environment assumes 50-percent to 90-percent humidity, an ambient temperature less than 120OF 

(except for primary containment), and a maximum radiation level of 9.0 x 106 rads. The primary containment environment assumes 40-percent to 90-percent humidity, a maximum temperature of 

150OF defined by data obtained from RTDs, and a maximum radiation level of 9.17 x 107 rads 

outside the sacrificial shield wall. The applicant defines "outside" as any external environment found 

outside any structure that would protect it from the weather. The applicant assumes 0 percent to 

100 percent humidity, an ambient temperature less than 1200 F, and no radiation. 

Eighteen auxiliary systems (control rod drive system; refueling equipment system; insulation system; 

access doors; condensate transfer and storage system; plant service water system; reactor building 

closed cooling water system; instrument air system; primary containment chilled water system; 

drywell pneumatics system; cranes, hoists and elevators system; tornado vents system; reactor 

building HVAC system; traveling screen/trash rack system; outside structures HVAC system; fire 

protection system; fuel oil system; and control building HVAC system) contain carbon steel, 

aluminum, stainless steel, acrylic, galvanized steel, cast iron, ceramic, copper/copper alloy, or 

various insulating/gasket type materials or specialized fire protection materials exposed to an inside 

(sheltered) and/or outside (nonsheltered) environment. The applicant discussed the aging 

management review of these materials in these environments in Sections C.2.2.10, C.2.6.3, C.2.4.4, 

C.2.4.1, C.2.4.2., C.2.6.6, C.2.6.8, C.2.3.4, and C.2.6.7 of the LRA. The applicant identified several 

forms of corrosion that may result in loss of material (e.g., general corrosion, crevice corrosion, and 

pitting). The applicant identified loss of preload as an applicable aging effect for bolting due to 

embedment, gasket creep, thermal effects, or self loosening. The applicant identified cracking of 

acrylic due to weathering as well as cracking, and change in material properties for insulating/gasket 

type materials due to compaction and settling, exposure to moisture, and thermal effects. To 

manage these aging effects, the applicant relies on the following aging management programs: 

0 torque activities 

* protective coatings program 

• overhead crane and refueling platform inspections

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0 equipment and piping insulation monitoring program * fire protection activities 

* gas systems component inspections 

0 passive component inspection activities 

Raw Water 

Plant Hatch has two sources of raw water, including river water and well water. River water is 

supplied from the Altamaha River via the intake structure. The structure has rough screens in place 

to prevent clogging of the vertical turbine pumps and discharge strainers. Some debris, silt, and 

macroorganisms may be introduced into the plant service water and residual heat removal service 

water systems. Well water is supplied from deep draft wells located on site. The water is 

mechanically filtered using the demineralizing system filters to remove macroorganisms and silt. 

Well water is used for the fire protection system only. Three auxiliary systems (plant service water 

system, traveling water screens/trash rack system, and the fire protection system) contain stainless 

steel, carbon steel, cast austenitic stainless steel, cast iron, copper alloys, galvanized steel, or 

aluminum components exposed to a raw water environment. The applicant discussed the aging 

management review of these materials in this environment in Sections C.2.2.6, C.2.6.3, and C.2.3.1 

of the LRA. The applicant identified several forms of corrosion that may result in loss of material 

(e.g., general corrosion, galvanic corrosion, crevice corrosion, MIC, and pitting) and flow blockage due to fouling. To manage these aging effects, the applicant relies on the following aging 

management programs: 

0 plant service water and residual heat removal service water inspection program 

* plant service water and residual heat removal service water chemistry control 

0 structural monitoring program 

* galvanic susceptibility inspections 

0 protective coatings program 

* fire protection activities 

Closed Cooling Water 

Plant Hatch monitors the closed cooling water for detrimental impurities, although the parameters 

are less restrictive than those for reactor water or auxiliary system water environments. The 

applicant adds corrosion inhibitors to reduce the corrosion rate to an acceptable level. A basic pH is maintained to increase the effectiveness of the corrosion inhibitors and promote the development 

of protective corrosion films. Plant Hatch maintains biocide levels to prevent significant microorganism growth. Two auxiliary systems (the reactor building closed cooling water system and 

the primary containment chilled water system) have carbon steel, stainless steel, and copper alloy 

components exposed to a closed cooling water environment. The applicant discussed the aging 

management review of the materials in this environment in Section C.2.2.5 of the LRA. The 

applicant identified several forms of corrosion that may result in loss of material (e.g., general 

corrosion, galvanic corrosion, crevice corrosion, MIC, and pitting). To manage this aging effect, the 

applicant relies on the following aging management programs: 

• closed cooling water chemistry control 

• treated water systems piping inspections

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Embedded in Concrete

The fire protection system contains penetration seals embedded in concrete. The applicant discussed the aging management review in Section C.2.3.4 of the LRA. Aging effects that require 

management include loss of material due to corrosion (e.g., general corrosion, crevice corrosion, 

and pitting) orwear and fretting, cracking within concrete/fire barrier materials due to thermal effects 

and/or compaction and settling, and change in material properties of fire barrier materials due to 

thermal degradation. To manage these aging effects, the applicant relies on the fire protection 

activities program. 

Fuel Oil 

Fuel oil is any oil utilized to fuel an internal combustion engine. Two auxiliary systems (fire protection system and the fuel oil system) contain carbon steel, stainless steel, copper/copper alloy and cast iron components exposed to a fuel oil environment. The applicant discussed the aging 

management review of these materials in this environment in Section C.2.3.2 and Section C.2.2.7 

of the LRA. The applicant identified several forms of corrosion that may result in loss of material 

(e.g., general corrosion, galvanic corrosion, crevice corrosion, MIC, and pitting). To manage this 

aging effect, the applicant relies on the following aging management programs: 

* diesel fuel oil testing 

* fire protection activities 

External Environments 

The auxiliary system environments discussed above are based on the dominant operating 

environment of the components which, generally speaking, is the internal environment (e.g., raw 

water running through piping). The applicant discussed the aging effects due to external 

environments in Section C.2.4 of the LRA. These external environments include inside, outside, 

buried or embedded, and a special section for insulation commodities. The staff's evaluation of the 

applicant's treatment of aging effects caused by external environments can be found in Section 3.6 

of this SER, and are generally not discussed for the auxiliary system structures and components in this section. However, when the external environment is the dominant operating environment for 

the structure or component, the aging effects and associated aging management programs are 

included in this section of the SER. 

Thermal Fatigue 

The applicant identified cracking due to thermal fatigue as an aging effect for the auxiliary system 

components. The applicant stated that all non-Class 1 components are enveloped by a time-limited 

aging analysis that adequately addresses this aging effect without regard to individual component 

or system conditions. The applicant discusses this analysis in Section 4.2.3 of the LRA. The staff's 

evaluation of this analysis is in Section 4.2 of this SER. 

Operating Experience 

The applicant stated it collected industry operating experience from sources such as NRC generic letters, bulletins and information notices; General Electric service information letters; Institute for 

Nuclear Power Operations (INPO) significant operating event reports; and topical information from

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various industry working groups. The applicant obtained plant-specific information through plant 

walkdowns, interviews, and records searches of their condition reporting database that covers the 

last 5 years of operation. The applicant presented brief discussions of this operating experience, 

both plant-specific and industry-wide, in each commodity group. 

The applicant concluded that it identified the appropriate aging effects and associated aging 

management programs that would ensure that the intended function of the components of the 

auxiliary systems would be maintained consistent with the current licensing basis, under all design 

loading conditions during the period of extended operation. 

3.4.3 Staff Evaluation 

The applicant described its aging management review of the auxiliary systems for license renewal 

in Section 3.2.4 and Sections A, B (submitted October 10, 2000), and C of the LRA. The staff 

reviewed these sections of the application to determine whether the applicant presented adequate 

information to meet the requirements stated in 10 CFR 54.21(a)(3). In this section of the safety 

evaluation report, the staff provides its evaluation of the aging management review for the auxiliary 

systems. 

3.4.3.1 Aging Effects 

Access Doors 

Access doors consist of structural carbon steel exposed to inside and outside environments. The 

applicant identified loss of material as an applicable aging effect. The staff agrees with the 

applicant's identification of aging effects. 

Condensate Transfer and Storage System 

The condensate transfer and storage system contains components exposed to a demineralized 

water environment. The applicant identified loss of material as an applicable aging effect associated 

with component materials in a demineralized water environment. The condensate transfer and 

storage system also contains stainless steel bolting exposed to an outside environment. The 

applicant identified loss of preload as an applicable aging effect. The staff agrees with the 

applicant's identification of aging effects. 

Control Building HVAC System 

The control building HVAC system contains both metallic and nonmetallic components exposed to 

a air (potentially wetted), dried gas, inside, and raw water environments. In the air environment, the 

applicant identified the following applicable aging effects: 

* loss of material for metallic components; 

* matierial property changes for non-metallic. 

In the dried gas environment, the applicant identified no aging effects associated with component 

materials. 

In the inside environment, the applicant identified the following applicable aging effects:

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* loss of material for carbon steel bolting and the condensing unit shell; 

* loss of preload for carbon steel bolting. 

Lastly, the condensing unit shell in the control building HVAC is also exposed to a raw water 

environment. The applicant identified loss of material as the applicable aging effect for this 

environment. 

In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant provide the technical 

justification for not including SCC as an applicable aging effect for high-strength bolting materials. 

The applicant submitted a response to this RAI on October 10, 2000. A full discussion of this issue 

may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the control building HVAC 

system. 

Control Rod Drive System 

The CRD system contains components exposed to a demineralized water environment. The 

applicant identified loss of material as an applicable aging effect associated with component materials in a demineralized water environment. The CRD system also contains components exposed to a dried gas environment. The applicant identified no aging effects associated with CRD 

component materials in a dried gas environment. The CRD system also contains components exposed to a wetted gas environment. The applicant identified loss of material as an applicable aging effect. The CRD system contains carbon and low alloy carbon steel bolts exposed to an inside 

environment. The applicant identified loss of material and loss of preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant provide the technical justification for not including SCC as an applicable aging effect for high-strength bolting materials. The applicant submitted a response to this RAI on October 10, 2000. A full discussion 

of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the CRD system. 

Cranes, Hoists and Elevators System 

The reactor building crane is the only in-scope component for the cranes, hoists, and elevators 

system. The reactor building crane contains carbon steel components exposed to an inside 

environment. The applicant identified loss of material as an applicable aging effect. The staff 

agrees with the applicant's identification of aging effects. 

Drywell Pneumatics System 

The drywell pneumatics system contains components exposed to a dried gas environment. The 

applicant identified no aging effects associated with component materials in a dried gas environment. This system also contains carbon steel and stainless steel bolts exposed to an inside 

environment. The applicant identified loss of material and loss of preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant provide the technical justification for not including SCC as an applicable aging effect for high strength bolting

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materials. The applicant submitted a response to this RAI on October 10, 2000. A full discussion 

of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the drywell pneumatics system. 

Emergency Diesel Generators System 

The emergency diesel generator (EDG) system contains metallic components (alloy, carbon, and 

stainless steels, copper and copper alloy, and cast iron) exposed to moist air, lube oil, raw water, 

and demineralized water and ethylene glycol (antifreeze) environments. The applicant identified 

loss of material and cracking due to fatigue as aging effects. In addition, the applicant identified loss 

of preload in the moist air environment, and loss of heat exchanger performance in the raw water 

environment. In Table 3.2.4-12 of the LRA, the applicant did not identify loss of preload as an aging 

effect for bolting in the EDG system. In RAI 3.4-10(c), dated July 28, 2000, the staff requested that 

the applicant provide the basis for excluding loss of preload as an aging effect for bolting in the EDG 

system. The applicant responded to this RAI in its letter dated October 10, 2000, stating that bolting 

was not a separate mechanical component/commodity requiring aging management for the EDG 

system. However, as part of the resolution to Open Item 2.3.3.2-1(b), the applicant clarified that 

bolting will be managed by the torque activities AMP. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the EDG system. 

Fire Protection System 

The fire protection system contains many components fabricated from various materials and 

exposed to an inside environment. The applicant identified loss of material and cracking as 

applicable aging effects for the carbon steel, nonferrous metal, ceramic and organic components. 

The applicant also identified a change in material properties for insulating materials and penetration 

seals. The applicant did not identify any aging effects for fire doors constructed from materials other 

than carbon steel for which loss of material is an applicable aging effect. The fire protection system 

also has components exposed to raw water. The applicant identified loss of material, cracking, and 

flow blockage as applicable aging effects associated with component materials in a raw water 

environment. The fire protection system also has components exposed to fuel oil. The applicant 

identified loss of material and cracking as applicable aging effects associated with component 

materials in a fuel oil environment. Finally, the fire protection system has components exposed to 

either a dried gas or an air (potentially wetted) environment. The applicant identified no aging 

effects for components exposed to a dried gas environment. For those components exposed to an 

air environment, the applicant identified loss of material and cracking as applicable aging effects. 

The fire protection system also contains carbon steel bolting exposed to inside and outside 

environments. The applicant identified loss of material and loss of preload as applicable aging 

effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant provide 

the technical justification for not including SCC as an applicable aging effect for high-strength bolting 

materials. The applicant submitted a response to this RAI on October 10, 2000. A full discussion 

of this issue may be found in Section 3.1.11 of this SER.

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On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the fire protection system. 

Fuel Oil System 

The fuel oil system contains components exposed to a fuel oil environment. The applicant identified 

loss of material and cracking as applicable aging effects associated with component materials in 

a fuel oil environment. Lastly, the fuel oil system contains components exposed to an air (potentially 

wetted) environment. The applicant identified loss of material and cracking as applicable aging 

effects associated with component materials in an air (potentially wetted) environment. 

The fuel oil system also contains carbon steel bolts exposed to an inside environment. The 

applicant identified loss of material and loss of preload as applicable aging effects for bolting. In RAI 

3.4-1, dated July 28, 2000, the staff requested that the applicant provide the technical justification 

for not including SCC as an applicable aging effect for high-strength bolting materials. The applicant 

submitted a response to this RAI on October 10, 2000. A full discussion of this issue may be found 

in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the fuel oil system. 

Instrument Air System 

The instrument air system contains components exposed to a dried gas environment. The applicant 

identified no aging effects associated with component materials in a dried gas environment. The 

instrument air system also contains carbon and stainless steel bolts exposed to an inside 

environment. The applicant identified loss of material and loss of preload as applicable aging 

effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant provide 

the technical justification for not including SCC as an applicable aging effect for high-strength bolting 

materials. The applicant submitted a response to this RAI on October 10, 2000. A full discussion 

of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the instrument air system. 

Insulation System 

The insulation system contains metallic and insulating components exposed to inside and outside 

environments. The applicant identified loss of material and cracking as applicable aging effects for 

the metallic components in these environments. The applicant also identified, for the insulation, loss 

of material due to intrusion of water or wear, cracking due to thermal degradation or intrusion of 

water, and a change in material properties due to compaction or settling. The staff agrees with the 

applicant's identification of aging effects. 

Outside Structures HVAC System 

The outside structures HVAC system contains components exposed to air (potentially wetted), 

inside, and outside environments. The applicant identified loss of materials as an applicable aging 

effect associated with component materials in an air (potentially wetted) environment. The system

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also contains carbon steel bolts and unit heater housing exposed to inside and outside 

environments. In addition, the applicant identified loss of material and loss of preload as applicable 

aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff requested that the applicant 

provide the technical justification for not including SCC as an applicable aging effect for high

strength bolting materials. The applicant submitted a response to this RAI on October 10, 2000. 

A full discussion of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the outside structures HVAC 

system. 

Plant Service Water System 

The plant service water system contains a carbon steel pump sub-base exposed to an inside 

environment. The applicant identified loss of material as an applicable aging effect. 

The plant service water system contains components exposed to a raw water (river water) 

environment. The applicant identified loss of material and cracking as applicable aging effects 

associated with component materials in a raw water environment. The applicant also identified flow 

blockage as an applicable aging effect due to corrosion product buildup, biofouling, particulate 

fouling, or precipitation fouling. The plant service water system also contains carbon and low-alloy 

steel bolts exposed to inside and outside environments. The applicant identified loss of material and 

loss of preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff 

requested that the applicant provide the technical justification for not including SCC as an applicable 

aging effect for high-strength bolting materials. The applicant submitted a response to this RAI on 

October 10, 2000. A full discussion of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the plant service water system. 

Pdmary Containment Chilled Water System (Unit 2 Only) 

The primary containment chilled water (PCCW) system contains components exposed to the closed 

cooling water environment. The applicant identified loss of material as an applicable aging effect 

associated with component materials in a closed cooling water environment. The PCCW system also contains carbon steel bolts exposed to an inside environment. The applicant identified loss of 

material and loss of preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 

2000, the staff requested that the applicant provide the technical justification for not including SCC 

as an applicable aging effect for high-strength bolting materials. The applicant submitted a 

response to this RAI on October 10, 2000. A full discussion of this issue may be found in Section 

3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the primary containment chilled 

water system (Unit 2 only).

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Reactor Building Closed Cooling Water System

The reactor building closed cooling water system contains components exposed to a closed cooling water environment. The applicant identified loss of material and cracking as applicable aging effects 

associated with the component materials in a closed cooling water environment. This system also 

contains carbon and low-alloy carbon steel bolts exposed to inside environments. The applicant identified loss of material and loss of preload as applicable aging effects for bolting. In RAI 3.4-1, 

dated July 28, 2000, the staff requested that the applicant provide the technical justification for not 

including SCC as an applicable aging effect for high-strength bolting materials. The applicant submitted a response to this RAI on October 10, 2000. A full discussion of this issue may be found 

in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the reactor building closed 

cooling water system. 

Reactor Building HVAC System 

The reactor building HVAC system contains components exposed to an air (potentially wetted) environment. The applicant identified loss of material as an applicable aging effect associated with 

component materials in an air (potentially wetted) environment. This system also contains carbon 

steel bolts exposed to inside and outside environments. The applicant identified loss of material and 

loss of preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff 

requested that the applicant provide the technical justification for not including SCC as an applicable aging effect for high-strength bolting materials. The applicant submitted a response to this RAI on 

October 10, 2000. A full discussion of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the reactor building HVAC 

system. 

Refueling Equipment System 

The refueling equipment system contains components exposed to an inside environment. The 

applicant identified loss of material as an applicable aging effect associated with the component materials in an inside environment. The staff agrees with the applicant's identification of aging effects. 

Sampling System 

The sampling system contains components exposed to a wetted gas environment. The applicant identified loss of material and cracking as applicable aging effects associated with component materials in a wetted gas environment. The staff agrees with the applicant's identification of aging 

effects. 

Tornado Vents System 

The tornado relief vent assemblies contain metallic and acrylic components exposed to an inside 

and outside environment. The applicant identified no aging effects for the metallic components.

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The applicant identified cracking as an applicable aging effect for the acrylic components. The staff 

agrees with the applicant's identification of aging effects. 

Traveling Water Screens/Trash Racks System 

The traveling water screens/trash rack system contains components exposed to or submerged in 

rawwater. The applicant identified loss of material, cracking, and fouling as applicable aging effects 

associated with component materials in a rawwater environment. This system also contains carbon 

steel bolts exposed to an outside environment. The applicant identified loss of material and loss of 

preload as applicable aging effects for bolting. In RAI 3.4-1, dated July 28, 2000, the staff 

requested that the applicant provide the technical justification for not including SCC as an applicable 

aging effect for high-strength bolting materials. The applicant submitted a response to this RAI on 

October 10, 2000. A full discussion of this issue may be found in Section 3.1.11 of this SER. 

On the basis of the information provided by the applicant in the LRA, the staff concludes that the 

applicant has adequately identified the aging effects associated with the traveling water 

screens/trash racks system. 

Vibration Loading 

The applicant did not identify cracking due to vibration loading as an aging effect for the auxiliary 

system components. The staff is aware that some piping system degradation (e.g., loss of integrity 

of bolted closures, cracking of welds, and loosening of bolts) may be caused by vibration 

(mechanical or hydrodynamic) loading. In many tables in Section 3.2.4 of the LRA, the applicant 

identified loss of preload as an aging effect for bolting. In Section C.1 of the LRA, the applicant 

indicated that loss of preload included self-loosening of bolting that may be caused by vibration. 

Thus, the staff was not clear whether the applicant had considered cracking of auxiliary system 

components (in particular piping welds and HVAC ducting) that may be subjected to a high-vibration 

environment. In RAI 3.4-10(b), dated July 28, 2000, the staff requested that the applicant clarify 

whether it had considered these vibration related aging effects in the AMR for the auxiliary systems 

discussed in Section 3.2.4 of the LRA. The applicant responded to the staff's RAI in its letter dated 

October 10, 2000, stating that vibration- induced cracking in piping welds and HVAC ducting is 

indicative of an insufficient design or failure to follow good bolting practices following maintenance, 

neither of which is age-related. Therefore, the applicant concluded that vibration-induced cracking 

is not an applicable aging effect. It should be noted that the control building HVAC system includes 

elastomeric isolators. Elastomers may crack, harden, or lose strength due to relative motion 

between vibrating equipment, exposure to warm moist air, temperature changes, oxygen, and/or 

radiation. If these isolators degrade, vibration and subsequent dynamic loads applied to the 

ductwork and fasteners cannot be eliminated. The applicant considered the degradation of 

elastomeric isolators, including gaskets and flexible connectors, in the control building HVAC 

system. The isolators are shown in Table 3.2.4-20 of the LRA as "ductwork flex connectors," and 

the aging management review is presented in Section C.2.6.7 of the LRA. By including the isolators 

in the aging management review for this system, the staff finds that the applicant has adequately 

addressed the potential for vibration-related aging effects for the control building HVAC system. In 

RAI 3.4-12, the staff also requested that the applicant discuss how this potential aging effect is 

managed for the reactor building HVAC system. In its submittal dated October 10, 2000, the 

applicant clarified that the reactor building HVAC system design is such that isolators are not 

required. As this design has demonstrated acceptable operating experience, the staff concludes 

that vibration-related aging effects are not applicable to the reactor building HVAC system. The staff

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finds that the applicant's responses adequately address the vibration-related aging effects for 

auxiliary systems. 

External Environments 

The applicant discussed the aging effects due to external environments in Section C.2.4 of the LRA. 

These external environments include inside, outside, and buried or embedded environments, and 

a special section for insulation commodities. The staff's evaluation of the applicant's treatment of 

aging effects caused by external environments can be found in Section 3.6 of this SER, and are 

generally not discussed for the auxiliary system structures and components in this section. 

However, when the external environment is the dominant operating environment for the structure 

or component, the aging effects and associated aging management programs are included in this 

section of the SER. 

Thermal Fatigue 

The applicant identified cracking due to thermal fatigue as an aging effect for the auxiliary system 

components. The applicant stated that all non-Class 1 components (with the exception of the jacket 

water cooling subsystem of the emergency diesel generators) are enveloped by a time-limited aging 

analysis that adequately addresses this aging effect without regard to individual component or 

system conditions. The applicant discusses this analysis in Section 4.2.3 of the LRA. The staff's 

evaluation of this analysis is in Section 4.2 of this SER. For the jacket water cooling subsystem 

components, there is no TLAA under the control of the applicant to demonstrate that thermal fatigue is managed by design. Therefore, the applicant relies on diesel generator maintenance activities 

to manage cracking of the jacket water cooling subsystem. 

Summary of the Review of Aging Effects' Operating Experience 

The staff has reviewed the information presented by the applicant regarding plant-specific, as well 

as industry-wide, experience to support its identification of applicable aging effects. This included 

the description of the internal environments and materials of fabrication for these systems. On the 

basis of the information, the staff concludes that the applicant has identified the aging effects for 

the commodity groups in the auxiliary systems that are consistent with published literature and 

industry experience. 

3.4.3.2 Aging Management Programs 

Access Doors 

To manage aging effects for structural carbon steel components exposed to either an inside or 

outside environment, the applicant relies on the following aging management programs: 

* structural monitoring program 

* protective coatings program 

The structural monitoring program provides for visual inspection of structural components on a 

regular, periodic basis. In addition, the carbon steel access doors are coated with an inorganic zinc 

primer and epoxy topcoat or are galvanized steel. The protective coatings program provides for 

periodic inspection of component surfaces to ensure that this coating is intact and providing

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adequate protection. This program also provides for proper corrective actions to prevent significant degradation (e.g., replacement or coating of exposed surfaces). The staff's detailed review of these 

programs may be found in Sections 3.1.22 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Condensate Transfer and Storage System 

To manage aging effects for components exposed to a demineralized water environment, the 

applicant relies on the following aging management programs: 

* demineralized water and condensate storage tank chemistry control 

* treated water systems piping inspections 

The demineralized water and condensate storage tank chemistry control program serves to manage 

loss of material due to corrosion by limiting concentrations of impurities, total organic carbon, and 

conductivity. The treated water systems piping inspections is a one-time inspection program to 

validate the adequacy of the demineralized water and condensate storage tank chemistry control 

program in mitigating the loss of material within carbon steel and stainless piping. The staff's 

detailed review of these programs may be found in Sections 3.1.6 and 3.1.24 of this SER. 

To manage loss of preload for stainless bolting exposed to an outside environment, the applicant relies on the torque activities program, which provides detailed guidance on fastener torque 

requirements and proper installation methods, thereby preventing loss of preload within non-Class 

1 fasteners. The staff's detailed review of this program may be found in Section 3.1.11 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Control Building HVAC System 

To manage aging effects for components exposed to an air environment, the applicant relies on the 

following aging management programs: 

* gas systems component inspections 

* passive component inspection activities 

The applicant designed both of these programs to address corrosion-related aging degradation in 

gas-bearing systems. The gas systems component inspections program is a new, one-time 

inspection program that inspects a sample of components that are considered unlikely (e.g., 

stainless steel components) to suffer age-related degradation. In contrast, the passive component inspection activities provide for the inspection of normally inaccessible components during 

maintenance activities. This latter program is for those components considered more likely to suffer 

age-related degradation. The staff's detailed review of these programs may be found in Sections 

3.1.25 and 3.1.27 of this SER.

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To manage aging effects for carbon steel bolting exposed to an inside environment, the applicant 

relies on the following aging management programs: 

torque activities 

• protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

To manage aging effects for the condensing unit shell and tubing exposed to raw water, the 

applicant relies on the following aging management programs: 

PSW and RHRSW inspection program; 

PSW and RHR service water chemistry control program. 

The PSW and RHRSW inspection program is designed to detect wall thickness degradation or 

fouling in the PSW and RHRSW systems. This program focuses on locations that the applicant determines are prone to corrosion and prone to clogging such as small diameter piping and low 

point drains, respectively. The PSW and RHRSW chemistry control program is intended to mitigate aging in system piping and components by controlling fluid composition. The service water system is treated with sodium hypochlorite and sodium bromide. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Control Rod Drive System 

To manage aging effects for components exposed to a demineralized water environment, the 

applicant relies on the following aging management programs: 

• demineralized water and condensate storage tank chemistry control 

* treated water systems piping inspections 

• galvanic susceptibility inspections (for carbon steel components only) 

The demineralized water and condensate storage tank chemistry control program serves to manage loss of material due to corrosion by limiting concentrations of impurities, total organic carbon, and 

conductivity. The treated water systems piping inspections comprise a one-time inspection program 

to validate the adequacy of the demineralized water and condensate storage tank chemistry control 

program in mitigating loss of material within carbon steel and stainless steel piping. The galvanic 

susceptibility inspections comprise another one-time inspection program to examine carbon steel 

to stainless steel dissimilar metal welds to identify potential loss of material due to galvanic

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corrosion. The staff's detailed review of these programs may be found in Sections 3.1.6, 3.1.24, 

and 3.1.23 of this SER. 

To manage aging effects for carbon steel bolting exposed to an inside environment, the applicant 

relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program 

also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

To manage aging effects for components exposed to a wetted gas environment, the applicant relies 

on the following aging management programs: 

* gas systems component inspections 

* passive component inspection activities 

The applicant designed both of these programs to address corrosion-related aging degradation in 

gas-bearing systems. The gas systems component inspections program is a new, one-time 

inspection program that inspects a sample of components that are considered unlikely (e.g., 

stainless steel components) to suffer age-related degradation. In contrast, the passive component 

inspection activities provide for the inspection of normally inaccessible components during 

maintenance activities. This latter program is for those components considered more likely to suffer 

age-related degradation. The staff's detailed review of these programs may be found in Sections 

3.1.25 and 3.1.27 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Cranes, Hoists and Elevators Systems 

The reactor building crane is the only in-scope component for the cranes, hoists, and elevators 

system. To manage aging effects for carbon steel components exposed to an inside environment, 

the applicant relies on the following aging management programs: 

* overhead crane and refueling platform inspection 

* protective coatings program 

The overhead crane and refueling platform inspection provides for regular, periodic visual 

inspections of the reactor building crane. The protective coatings program provides for periodic 

visual inspections of component external surfaces. This program also provides for proper corrective 

actions to prevent significant degradation of the reactor building crane components due to general

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corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review of 

these programs may be found in Sections 3.1.10, and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Drywell Pneumatics System 

To manage aging effects for carbon steel and stainless steel bolting exposed to an inside 

environment, the applicant relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Emergency Diesel Generator System 

To manage aging effects for components exposed to a demineralized water environment, the 

applicant relies on the following aging management programs: 

• demineralized water and condensate storage tank chemistry control 

* treated water systems piping inspections 

• galvanic susceptibility inspections 

* diesel generator maintenance activities. 

The demineralized water and condensate storage tank chemistry control program serves to manage loss of material due to corrosion by limiting concentrations of impurities, total organic carbon, and 

conductivity. The treated water systems piping inspections comprise a one-time inspection program 

to validate the adequacy of the demineralized water and condensate storage tank chemistry control 

program in mitigating the loss of material within carbon steel and stainless steel piping. The 

galvanic susceptibility inspections comprise another one-time inspection program to examine carbon 

steel to stainless steel dissimilar metal welds to identify potential loss of material due to galvanic 

corrosion. The diesel generator maintenance activities are a collection of existing preventative maintenance and performance monitoring activities. These activities include inspections of 

emergency diesel generator components, and evaluations of the jacket water system fluid and the 

lubricating oil. These activities are designed to find evidence of corrosion and detect loss of heat

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exchanger performance. The staff's detailed review of these programs may be found in Sections 

3.1.6, 3.1.24, 3.1.23, and 3.1.31 of this SER. 

To manage aging effects for components in a wetted gas environment, the applicant relies on the 

following aging management programs: 

• gas systems component inspections; 

° passive component inspection activities; 

- diesel generator maintenance activities. 

The applicant designed both of these programs to address corrosion-related aging degradation in 

gas-bearing systems. The gas systems component inspections program is a new, one-time 

inspection program that inspects a sample of components that are considered unlikely (e.g., 

stainless steel components) to suffer age-related degradation. In contrast, the passive component 

inspection activities provide for the inspection of normally inaccessible components during 

maintenance activities. This latter program is for those components that are considered more likely 

to suffer age-related degradation. The diesel generator maintenance activities are a collection of 

existing preventative maintenance and performance monitoring activities. These activities include 

inspections of emergency diesel generator components, and evaluations of the jacket water system 

fluid and the lubricating oil. These activities are designed to find evidence of corrosion and detect 

loss of heat exchanger performance. The staff's detailed review of these programs may be found 

in Sections 3.1.25, 3.1.27, and 3.1.31 of this SER. 

To manage aging effects for components in a moist air environment, the applicant relies on the 

following aging management programs: 

* torque activities; 

* plant coatings program; 

* diesel generator maintenance activities. 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The diesel generator maintenance activities are a collection of existing preventative maintenance and performance 

monitoring activities. These activities include inspections of emergency diesel generator 

components, and evaluations of the jacket water system fluid and the lubricating oil. These activities 

are designed to find evidence of corrosion and detect loss of heat exchanger performance. The 

staff's detailed review of these programs may be found in Sections 3.1.11,3.1.20, and 3.1.31 of this 

SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

To manage aging effects for components in raw water and lubricating oil environments, the 

applicant relies on diesel generator maintenance activities. The diesel generator maintenance

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activities are a collection of existing preventative maintenance and performance monitoring activities. These activities include inspections of emergency diesel generator components, and 

evaluations of the jacket water system fluid and the lubricating oil. These activities are designed 

to find evidence of corrosion and detect loss of heat exchanger performance. The staff's detailed 

review of this program may be found in Section 3.1.31 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Fire Protection System 

To manage aging effects for carbon steel bolting exposed to inside and outside environments, the 

applicant relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11, and 3.1.20 of this SER. 

To manage aging effects for components exposed to the various environments (inside, raw water, 

air, fuel oil) that exist within the fire protection system, the applicant relies on the fire protection activities program, which consists of inspection, condition monitoring and performance monitoring activities. These activities are geared for the specific environment, be it an inside, raw water, air, 

or fuel oil environment. The staff's detailed review of this program may be found in Section 3.1.18 

of this SER. 

To manage aging effects for the carbon steel tank exposed to raw water, in addition to the fire 

protection activities, the applicant relies on the protective coatings program, which prevents corrosion within the fire water storage tank by maintaining sufficient coating on the internal surfaces 

of the storage tank. The staff's detailed review of this program may be found in Section 3.1.20 of 

this SER. 

In RAI 3.1.18-9, the staff requested that the applicant provide justification for the absence of 

enhanced inspection programs for the sprinkler heads, which do not have a design life that covers 

the period of extended operation. In response the applicant stated that, "in general, enhanced 

inspection programs are deemed unnecessary because the existing programs adequately manage the aging effects of concern," and that using the guidelines of the National Fire Protection Act 

(NFPA) Code 25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire 

Protection," a one-time sprinkler heads inspection is to be performed for in-scope sprinkler heads." 

The staff did not agree that a one-time inspection is sufficient for the sprinkler heads and 

recommended that the applicant expand the scope of its inspections to include the 10-year inspection intervals that are recommended in NFPA 25, Section 2.3.3.1, "Sprinklers."

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The applicant has previously addressed this issue in its responses to RAIs 2.3.4-FPS-10 and 

3.1.18-9. In the response to RAI 3.1.18-9 to include the 10-year inspection interval recommended 

in NFPA-25 for closed-head sprinklers, the applicant supplemented those earlier responses by 

expanding the scope of the inspections referenced. Thus, the revised commitment is to use the 

guidance of NFPA-25 to perform an inspection of closed head sprinklers after 50 years of service 

and at 10-year intervals thereafter. On the basis of the applicant's commitment, the staff finds that 

the applicant has adequately addressed the staff's concern and Open Item 3.1.18-1 (b) is closed. 

To manage aging effects for components exposed to fuel oil, in addition to fire protection activities, 

the applicant relies on the diesel fuel oil testing program, which samples and analyzes fuel oil 

deliveries for water and sediment contamination. Biocides are also added at this time in order to 

minimize the potential for MIC within components. Water and sediment contamination levels within 

storage tanks are checked on a regular basis to ensure that no significant buildup of contaminants 

exists. The staff's detailed review of this program may be found in Section 3.1.3 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Fuel Oil System 

To manage aging effects for carbon steel bolting exposed to an inside environment, the applicant 

relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program 

also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

To manage aging effects for components exposed to fuel oil, the applicant relies on the diesel fuel 

oil testing program, which samples and analzyes fuel oil deliveries for water and sediment 

contamination. Biocides are also added at this time in order to minimize the potential for MIC within 

components. The staff's detailed review of this program may be found in Section 3.1.3 of this SER. 

To manage aging effects for components exposed to an air environment, the applicant uses the 

following aging management programs: 

* gas systems component inspections 

• passive component inspection activities 

The applicant designed both of these programs to address corrosion-related aging degradation in 

gas-bearing systems. The gas systems component inspections program is a new, one-time 

inspection program that inspects a sample of components that are considered unlikely (e.g.,

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stainless steel components) to suffer age-related degradation. In contrast, the passive component 

inspection activities provide for the inspection of normally inaccessible components during 

maintenance activities. This latter program is for those components that are considered more likely 

to suffer age-related degradation. The staff's detailed review of these programs may be found in 

Sections 3.1.25 and 3.1.27 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Instrument Air System 

To manage aging effects for carbon steel and stainless steel bolting exposed to an inside 

environment, the applicant relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program 

also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Insulation System 

To manage aging effects for insulation system components exposed to either an inside or outside 

environment, the applicant relies on the equipment and piping insulation monitoring program, which 

consists of visual inspections of in-scope components exposed to either an inside or outside 

environment. The insulation inspection looks for holes, tears, compaction, material separation, 

wetting, missing insulation, and general deterioration. Jackets and fasteners will also be visually 

inspected for loss of material and cracking. The staff's detailed review of this program may be 

found in Section 3.1.21 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Outside Structures HVAC System 

To manage aging effects for components exposed to an air environment, the applicant relies on the 

following aging management programs:

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* gas systems component inspections 

* passive component inspection activities 

The applicant designed both of these programs to address corrosion-related aging degradation in 

gas-bearing systems. The gas systems component inspections program is a new, one-time 

inspection program that inspects a sample of components that are considered unlikely (e.g., stainless steel components) to suffer age-related degradation. In contrast, the passive component inspection activities provide for the inspection of normally inaccessible components during maintenance activities. This latter program is for those components that are considered more likely 

to suffer age-related degradation. The staff's detailed review of these programs may be found in 

Sections 3.1.25 and 3.1.27 of this SER. 

To manage aging effects for carbon and stainless steel bolting exposed to inside and outside 

environments, the applicant relies on the following aging management programs: 

* torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Plant Service Water System 

To manage aging effects for components exposed to a raw water environment, the applicant relies 

on the following aging management programs: 

* plant service water and residual heat removal service water inspection program * plant service water and residual heat removal service water chemistry control program 

* galvanic susceptibility inspections 

The plant service water and residual heat removal service water inspection program is a condition 

monitoring program designed to detect wall thickness degradation or fouling in the plant service 

water and residual heat removal service systems. The plant service water and residual heat 

removal service water chemistry control program mitigates aging in system piping and components 

by controlling fluid composition through treatment with sodium hypochlorite and sodium bromide. 

The aging effects of plant service water system carbon steel components in the river water 

environment are further managed by the galvanic susceptibility inspections. These are one-time 

inspections to provide objective evidence that galvanic susceptibility is being managed for specific 

components within the scope of license renewal. The staff's detailed review of these programs may be found in Sections 3.1.13, 3.1.4, 3.1.22, and 3.1.23 of this SER.

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To manage aging effects for carbon steel bolting exposed to an inside environment, the applicant 

relies on the following aging management programs: 

torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component extemal surfaces, including fasteners. This program will also provide for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

To manage aging effects for the carbon steel pump sub-base externally exposed to an inside 

environment, the applicant relies on the following aging management program: 

protective coatings program 

The protective coatings program provides for periodic inspection of component external surfaces, 

including the carbon steel pump sub-base. This program will also provide for proper corrective 

actions to prevent significant degradation of the sub-base due to general corrosion (such as 

replacement or coating of exposed surfaces). The staff's detailed review of this program may be 

found in Section 3.1.20 of this SER. 

The staff conducted a scoping inspection in the offices of SNC from September 11, 2000 through 

September 15,2000. The results of the inspection are documented in Inspection Report 50-321/00

09,50-366/00-09. During the inspection, the inspectors identified a guard pipe associated with the 

Division I plant service water piping in the diesel generator building. This guard pipe had not been 

considered for scoping and screening in the LRA. In response to this inspection finding, the 

applicant evaluated the guard pipe and concluded that it did not perform an intended function, and 

therefore was not within the scope of license renewal. The staff agreed with this conclusion. The 

staff's review of the applicant's evaluation of the guard pipe can be found in Section 2.3.4.13 of this 

SER. The internal surface of the PSW piping is exposed to raw water, and thus the aging effects 

and aging management programs are consistent with other piping sections in this system. However, 

the portion of the PSW piping surrounded by the guard pipe is welded to the guard pipe at both 

ends. Thus, the external surface of this section of plant service water piping is not easily accessible 

for inspection. The applicant plans to perform a one-time inspection to assess the material condition 

of the external surfaces of this piping section. The one-time inspection is discussed in Section 

3.1.13 of this SER. 

In RAI 3.4-9, dated July 28, 2000, the staff noted that the applicant stated in the LRA that selective 

leaching was a corrosion mechanism that may result in loss of material for brass and gray cast iron 

components exposed to a raw water environment in the plant service water and fire protection 

systems. Given that selective leaching may not be detectable through standard visual inspections, the staff asked the applicant to discuss how the various inspection and testing programs are 

adequate to manage the aging effect (loss of material) resulting from this aging mechanism. In its 

October 10, 2000 response, the applicant stated that no age-related failures were identified for 

these components in the plant's operating history. In addition, for susceptible components in the

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fire protection system, the components' functionality is closely linked to performance characteristics 

that are currently monitored though fire protection activities. The staff agrees that the fire protection 

activities provide reasonable assurance of component functionality. For susceptible components 

in the plant service water system, the applicant committed to additional activity. The applicant 

provided additional information regarding this activity in its letter dated January 31, 2001. The 

applicant will either perform a Brinell hardness test, or a metallurgical analysis, on one plant service 

water component from each commodity (brass and gray cast iron) in existence at Plant Hatch within 

the time frame of August 6, 2009 to August 6, 2014 for Unit 1, and June 13, 2013 and June 13, 

2018 for Unit 2. The results will be compared to the design code of record as well as available 

textbook and vendor data. The scope and timing of the activity appear to the staff to be reasonable, 

given that selective leaching has not been identified at Plant Hatch. Also, the staff agrees that 

Brinell hardness testing and metallurgical analysis are both widely acceptable means of determining 

if selective leaching is occurring. The acceptance criteria are reasonable and consistent with staff 

expectations and current industry practice. In summary, the staff finds the applicant's stated 

approach satisfactory to manage selective leaching for components in the plant service water 

system. The applicant incorporated a one-time inspection into the PSW and RHRSW inspection 

program. 

On the basis is the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Primary Containment Chilled Water System (Unit 2 Only) 

To manage aging effects for carbon steel, stainless steel, and copper alloy components exposed 

internally to the closed cooling water environment, the applicant relies on the following aging 

management programs: 

* closed cooling water chemistry control 

• treated water systems piping inspection 

The closed cooling water chemistry control program is a mitigating activity intended to maintain 

structural integrity of plant closed cooling water systems and components by controlling fluid purity 

and composition. The treated water systems piping inspections program supplements the chemistry 

control program. It is a new program consisting of a one-time inspection to provide direct evidence 

that the existing chemistry control program is managing aging in piping that is not examined under 

other inspection programs. The staff's detailed review of these programs may be found in Sections 

3.1.2 and 3.1.24 of this SER. 

To manage the aging effects of the carbon steel bolting exposed to an inside environment, the 

applicant relies on the following aging management programs: 

0 torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program

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also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Reactor Building Closed Cooling Water System 

To manage aging effects for carbon steel, stainless steel, and copper alloy components exposed 

internally to the closed cooling water environment, the applicant relies on the following aging 

management programs: 

• closed cooling water chemistry control 

• treated water systems piping inspection 

The closed cooling water chemistry control program is a mitigating activity that is intended to 

maintain the structural integrity of plant closed cooling water systems and components by controlling fluid purity and composition. The treated water systems piping inspections program supplements the chemistry control program. It is a new program consisting of a one-time inspection to provide 

direct evidence that the existing chemistry control program is managing aging in piping that is not 

examined under other inspection programs. The staff's detailed review of these programs may be 

found in Sections 3.1.2 and 3.1.24 of this SER. 

To manage aging effects for carbon steel bolting exposed to an inside environment, the applicant 

relies on the following aging management programs: 

• torque activities 

• protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program provides for periodic inspection of component external surfaces, including fasteners. This program also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Reactor Building HVAC System 

To manage aging effects for components exposed to an air environment, the applicant relies on the 

gas systems component inspections program, which is a new, one-time inspection program that 

visually inspects a sample of components that are considered unlikely to suffer age-related 

degradation. The staff's detailed review of this program may be found in Section 3.1.25 of this SER.

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To manage aging effects for carbon steel bolting exposed to inside and outside environments, the 

applicant relies on the following aging management programs: 

• torque activities 

* protective coatings program 

The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program 

also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Refueling Equipment System 

To manage aging effects for components exposed to an inside environment, the applicant relies on 

the following aging management programs: 

• protective coatings program 

• overhead crane and refueling platform inspection 

The protective coatings program provides for periodic inspection of component surfaces. This 

program also provides for proper corrective actions to prevent significant degradation (e.g., 

replacement or coating of exposed surfaces). The overhead and refueling platform crane inspection 

program provides for visual inspection and testing of the reactor building overhead cranes and crane 

rail supports and refueling platform to assure safe operation of the crane. The staff's detailed review 

of these programs may be found in Sections 3.1.20 and 3.1.10 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Sampling System 

To manage aging effects for components exposed to a wetted gas environment, the applicant relies 

on the gas systems component inspections program, which is a new, one-time inspection program 

that inspects a sample of components from several gas systems within the scope of license renewal 

to provide evidence that the aging effects predicted for systems with gases as internal environments 

are being adequately managed. The staff's detailed review of this program may be found in Section 

3.1.25 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system.

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Tornado Vents System

To manage aging effects for the acrylic components exposed to an inside and outside environment, 

the applicant relies on the structural monitoring program, which visually inspects structural 

components on a regular, periodic basis. The staff's detailed review of this program may be found 

in Section 3.1.22 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Traveling Water Screens/Trash Rack System 

To manage aging effects for the carbon and stainless steel components submerged in or exposed 

to a raw water environment, the applicant relies on the following aging management programs: 

* structural monitoring program 

* protective coatings program 

The structural monitoring program provides for visual inspection of structural components on a 

regular, periodic basis. The protective coatings program provides for periodic visual inspections of 

component external surfaces. This program also provides for proper corrective actions to prevent significant degradation of the traveling water screens and trash rack components due to general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review of 

these programs may be found in Sections 3.1.22 and 3.1.20 of this SER. 

To manage aging effects for carbon steel valve bodies exposed to raw water, the applicant identified 

the following aging management programs: 

• plant service water and residual heat removal service water inspection program * plant service water and residual heat removal service water chemistry control program 

* galvanic susceptibility inspections 

The plant service water and residual heat removal service water inspection program is a condition 

monitoring program designed to detect wall thickness degradation or fouling in the plant service 

water and residual heat removal service water systems. The plant service water and residual heat 

removal service water chemistry control program mitigates aging in system piping and components 

by controlling fluid composition through treatment with sodium hypochlorite and sodium bromide. 

The aging effects of plant service water system carbon steel components in the river water 

environment are further managed by the galvanic susceptibility inspections. These are one-time 

inspections to provide objective evidence that galvanic susceptibility is being managed for specific 

components within the scope of license renewal. The staff's detailed review of these programs may 

be found in Sections 3.1.13, 3.1.4, and 3.1.23 of this SER. 

To manage aging effects for carbon steel bolting exposed to an outside environment, the applicant 

relies on the following aging management programs: 

* torque activities 

• protective coatings program

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The applicant's torque activities provide detailed guidance on fastener torque requirements and 

proper installation methods, thereby preventing loss of preload within non-Class 1 fasteners. 

Because some fasteners may be susceptible to general corrosion, the protective coatings program 

provides for periodic inspection of component external surfaces, including fasteners. This program 

also provides for proper corrective actions to prevent significant degradation of fasteners due to 

general corrosion (such as replacement or coating of exposed surfaces). The staff's detailed review 

of these programs may be found in Sections 3.1.11 and 3.1.20 of this SER. 

On the basis of the above information, the staff concludes that the aging management programs 

identified above are adequate to manage the aging effects associated with the commodity groups 

in this system. 

Summary - Aging Management Programs 

The staff has reviewed the information presented by the applicant regarding aging management 

programs credited for managing the aging effects associated with the commodity groups within the 

auxiliary systems. On the basis of this information, the staff concludes that the applicant has aging 

management programs which will manage the aging effects for the commodity groups in the 

auxiliary systems for the period of extended operation. 

3.4.4 Conclusion 

The staff has reviewed the information for the auxiliary systems in Section 3.2.4, "Auxiliary 

Systems," Section C.1, "Evaluation of Aging Effects Requiring Management," Section C.2, "Aging 

Management Reviews," and Section A, "Final Safety Analysis Report Supplement" of the LRA, as 

supplemented by Section B of submittal dated October 10, 2000. On the basis of this review, the 

staff concludes that the applicant has identified the aging effects associated with the auxiliary 

systems and has demonstrated that the aging effects will be adequately managed so that there is 

reasonable assurance that these systems will perform their intended functions in accordance with 

the current licensing basis during the period of extended operation. 

3.5 Steam and Power Conversion Systems 

3.5.1 Introduction 

The applicant described its AMR for the steam and power conversion systems (SPCS) for license 

renewal in Sections 3.2.5 "Steam and Power Conversion" of the LRA. The staff reviewed this 

section of the LRA to determine whether the applicant has demonstrated that the effects of aging 

on the SPCSs will be adequately managed during the period of extended operation, as required by 

10 CFR 54.21 (a)(3). 

External environments are defined in Sections C.1.2.8, "Inside;" C.1.2.9, "Outside;" and C.1.2.10, 

"Buried or Embedded" of the LRA. "Inside" external environments are defined as environments 

where equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. Structures 

and components which perform their functions in external environments are, in general, discussed

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in Sections 3.2, 3.3, 3.4, 3.5, 3.6, and 3.7 of the LRA, and are evaluated in Sections 3.6 and 3.7 of 

this SER, unless otherwise noted. 

3.5.2 Summary of Technical Information in the Application 

The SPCSs included within the AMR scope comprise the electro-hydraulic control (EHC) system and 

the main condenser system (Unit 2 only). 

3.5.2.1 Aging Effects 

Electro-Hydraulic Control System 

The purpose of the EHC system is to provide control of reactor pressure during reactor startup, 

power operation, and shutdown. The EHC system also provides a means of controlling main turbine 

speed and acceleration during turbine startup, and protects the main turbine from undesirable 

operating conditions by initiating alarms, trips, and runbacks. As described in LRA Section 2.1.2, the initial scoping was performed on the basis of functions. The intended function is associated with 

the main turbine pressure regulators, whereby the turbine control valve position is controlled by adjusting EHC pressure based on main steam pressure. The EHC regulators that are within the 

scope of license renewal are 1 N11-N042ANB and 2N32-N301A/B. Technical specifications do not 

require the regulators to be operable; however, transient analysis takes credit for the backup 

pressure regulator to function to prevent fuel damage in the event of a downscale failure of the 

inservice regulator. 

Materials of construction for the components supporting the EHC intended function are stainless 

steel piping and stainless steel valve bodies in a reactor water environment. The aging effects 

associated with this commodity group are loss of material and cracking. 

Main Condenser System (Unit 2 Only) 

The main condenser provides a heat sink for turbine exhaust steam, turbine bypass steam, and 

other flows (such as cascading heater drains, air ejector condenser drains, exhaust from the feed 

pump turbines, gland seal condenser, feedwater heater shell operating vents, and condensate pump suction vents). The main condenser also deaerates and provides storage capacity for the 

condensate water to be reused. The main condenser system is a two-shell, single-pass, divided 

water box, deaerating type designed for condenser duty of 5.66 x 109 Btu/h, an inlet water 

temperature of 90 OF, and an average backpressure of 3.5 in. Hg absolute. During plant operation, 

steam from the last-stage, low-pressure turbine is exhausted directly downward into the condenser 

shells through exhaust openings in the bottom of the turbine casings. The condenser serves as a 

heat sink for several other flows, such as exhaust steam from the feed pump turbines, cascading heater drains, air ejector condenser drain, gland-seal condenser drain, feedwater heater shell 

operating vents, and condensate pump suction vents. Other flows occur periodically. These 

originate from condensate and reactor feed pump startup vents, reactor feed pump minimum 

recirculation flow, feedwater lines startup flushing, turbine equipment clean drains, low-point drains, 

extraction steam spills, makeup, and condensate. During abnormal conditions, the condenser is 

designed to receive (not simultaneously) turbine bypass steam, feedwater heater high-level dumps, and relief valve discharge from feedwater heater shells, steam-seal regulator, and various steam 

supply lines.

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As described in LRA Section 2.1.2, the initial scoping was performed on the basis of functions. Post

accident radioactive decay holdup is the intended function associated with this system. 

The post-accident radioactive decay holdup provides a method for MSIV leakage control. It uses 

the main steam drain lines to convey the MSIV leakage during post-accident conditions to the 

isolated main condenser. The main condenser provides holdup and allows "plate-out" of the fission 

products that may leak from the closed MSIV during post-accident conditions. MSIV leakage that 

enters the condenser is ultimately released to the turbine building as non-condensible gases through 

the low pressure turbine seal after significant plate-out of iodine. 

Materials of construction for the components supporting the intended functions of the main 

condenser are carbon steel for bolting, condenser shell, piping, preheater, strainer, and valve 

bodies, and stainless steel for piping, preheater, restricting orifices, thermowells, and valve bodies. 

All components, except bolting, are exposed to a reactor water environment. The aging effects 

associated with these commodity groups are loss of material and cracking. 

3.5.2.2 Aging Management Programs 

The LRA identified the following six aging management programs that will manage the aging effects 

associated with the steam and power conversion systems: 

* reactor water chemistry control 

a treated water systems piping inspections 

0 galvanic susceptibility inspections 

• flow-accelerated corrosion program 

* protective coating program 

* torque activities 

Detailed descriptions of these aging management programs are included in Section A of the LRA. 

Reactor water chemistry control is a major part of the overall chemical control strategy for Plant 

Hatch. It is a mitigating activity designed to maintain structural integrity of plant systems and 

components by controlling fluid purity and composition. Treated water systems piping inspections 

will provide for condition monitoring via one-time examinations intended to provide objective 

evidence that existing chemistry control is managing aging in piping that is not examined under 

another inspection program. Galvanic susceptibility inspections will provide for condition monitoring 

via one-time inspections that will provide objective evidence that galvanic susceptibility is being 

managed for specific components within the scope of license renewal. The FAC program is a 

condition monitoring program designed to monitor pipe wear in those systems that have been 

determined to be susceptible to FAC-related loss of material. The protective coatings program 

provides a means of preventing or minimizing aging effects that would otherwise result from contact 

of the base metal with the associated environment. It is a mitigation and condition monitoring 

program designed to provide base metal aging management through application, maintenance, and 

inspection of protective coatings in selected components and structures. Torque activities are 

intended to mitigate loss of preload through use of proper torque techniques.

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3.5.3 Staff Evaluation

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information included in Section 3.2.5 

of the LRA to determine whether the applicant has identified the aging effects associated with the 

SPCS, and has demonstrated that the effects of aging on the SPCS will be adequately managed 

during the period of extended operation. 

3.5.3.1 Effects of Aging 

The SPCS components are constructed from carbon steel and stainless steel. They are exposed 

to an external environment of air in the turbine building, which by itself will not cause any significant aging effects. Internally, the SPCS components are exposed to a treated water and/or steam 

environment. The material degradation effects that were identified in the systems carrying treated 

water and steam include loss of material, cracking, and loss of preload in bolting. Tables 3.2.5-1 and 

3.2.5-2 of the LRA list the components, component functions, materials, environments, applicable aging effects, and the applicable AMPs. 

The applicant supplied references to plant-specific and industry-wide experience to support its 

identification of applicable aging effects for steam and power conversion systems. On the basis of 

the description of the internal and external environments and materials of fabrication for these 

systems, the staff concludes that the applicant has identified aging effects that are consistent with 

published literature and industry experience and, thus, are acceptable to the staff. 

3.5.3.2 Aging Management Programs 

The applicant has identified six aging management programs for controlling the effects of aging in 

the SPCS: 

* reactor water chemistry control 

* treated water systems piping inspections 

o galvanic susceptibility inspections 

* flow accelerated corrosion program 

* protective coating program 

* torque activities 

The staff's evaluation of these aging management programs is discussed in Section 3.1 of this SER. 

The programs were developed from industry-wide data, industry-developed methodologies, NRC 

documents, and the applicant's own experience. The applicant concluded that these programs would manage the aging effects in such a way that the functions of the SPCS components will be 

maintained during the period of extended operation, in a manner that is consistent with the CLB, 

under all design conditions. 

In LRA Tables C.2.2.1-1 and C.2.2.1-2, the applicant lists the following 10 attributes that each aging 

management program and activity required to address: 

scope of programs, which includes the specific structure, component, or commodity for the 

identified aging effect

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preventive actions to mitigate or prevent aging degradation

* linkage of parameters monitored or inspected to the degradation of the particular intended 

function 

* description and timely performance of the method used to detect aging effects 

0 monitoring and trending for timely corrective actions 

* acceptance criteria 

* corrective actions, including root cause determination and prevention of recurrence 

0 confirmation process 

administrative controls, which provide a formal review and approval process 

consideration of operating experience from the AMP, including past corrective actions that 

resulted in program enhancements or additional programs 

The staff evaluated the applicant's aging management programs in order to determine if they are 

adequate to manage the aging of the SPCS components so that the components will perform their 

intended functions in accordance with the CLB during the period of extended operation. On the 

basis of the information provided in the LRA and the applicant's responses to the staff's RAIs, the 

staff concludes that the aging management programs that the applicant credits for managing the 

aging effects associated with the SPCS will manage the aging effects such that the SPCS 

components will perform their intended functions in accordance with the CLB during the period of 

extended operation. 

3.5.4 Conclusions 

The staff has reviewed the information in Section 3.2.5 of the LRA. On the basis of this review, the 

staff concludes that the applicant has identified the aging effects associated with the SPCS and has 

demonstrated that aging effects will be adequately managed so that there is a reasonable 

assurance that the SPCS components will perform their intended functions in accordance with the 

CLB during the period of extended operation. 

3.6 Structures and Structural Components 

3.6.1 Introduction 

The applicant described its AMR of the structures and structural components for license renewal 

in the following sections of the LRA: Section 2.4, "Structures Screening Results," Section 3.3.1, 

"Civil Structural Components," Section A.1, "Existing Programs and Activities," Section A.2, 

"Enhanced Programs and Activities," Section A.3, "New Programs and Activities," and Section C.2.6, 

"Aging Management Review for Civil Discipline Commodities." The staff reviewed these sections 

and appendices of the LRA to determine whether the applicant has demonstrated that the effects 

of aging on the structures and structural components will be adequately managed during the period 

of extended operation as required by 10 CFR 54.21 (a)(3).

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3.6.2 Summary of Technical Information in the Application

3.6.2.1 Effects of Aging 

Section 2.4 of the Plant Hatch LRA provides a list of the various civil/structural component groups 

that are subject to an aging management review. For each of the civil/structural component groups 

in Section 2.4 of the LRA, the applicant also provided a general description of the structure or 

system and intended functions associated with each structure or system. Section C.1 of the LRA 

describes the applicant's approach toward identifying, categorizing, and evaluating plant 

environments and materials and the resulting aging effects applicable to systems, structures, and 

components determined to require aging management reviews. The applicant has adopted a 

commodities approach to evaluating aging effects requiring management and aging management 

programs. Section 3.0 of the LRA provides a discussion of the process used to develop the 

commodity groups. Once systems, structures, and components were divided into commodity 

groups, an analysis of the aging effects requiring management was performed. 

Civil/structural component evaluations are discussed in Section C.2.6 of the LRA, and are based 

on material of construction. 

Environments, aging effects requiring management, and associated aging mechanisms are 

discussed in Section C.1.4 of the LRA under each material of construction. Determination of the 

aging effects requiring management for each of these groups is presented in sections C.1.4.1 

through C.1.4.4 of the LRA. 

External environments are defined in Sections C.1.2.8, "Inside;" C.1.2.9, "Outside;" and C.1.2.10, 

"Buried or Embedded" of the LRA. "Inside" external environments are defined as environments 

where equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. Structures 

and components which perform their functions in external environments are, in general, discussed 

in Sections 3.2, 3.3, and 3.4 of the LRA, and are evaluated in Sections 3.6 and 3.7 of this SER, 

unless otherwise noted. 

Summaries of aging effects, determined by the applicant as applicable to each of the civil/structural 

component groups listed in Section 3.6.2.1 of this SER, are provided in Tables 3.3.1-1 through 

3.3.1-13 of the LRA. 

A brief description of each of the civil/structural component groups and their applicable aging effects 

is provided in the following sections. 

Conduits, Raceways, and Trays 

The purpose of the conduits, raceways, and trays system is to provide support for a cable system 

with cables and penetrations selected, routed, and located to survive the design-basis events 

established for the plant and to prevent a loss of function of any system due to a cable failure. 

Additional information may be found in Unit 1 UFSAR Section 8.8 and Unit 2 UFSAR Section 8.3.

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The conduits, raceways, and trays that are mounted according to Seismic Category I criteria are 

considered safety-related. Seismic Category I conduits, raceways, and trays provide support for 

essential cable feeding power supplies and controls. 

The conduits, raceways, and trays that are neither mounted as Seismic Category I nor Seismic 

Category Il/I are considered non-safety-related. Non safety-related conduits, raceways, and trays 

provide support for non-essential cable feeding power supplies and controls. Also, some non

seismic raceways are included in safe shutdown pathways. 

The applicant identified loss of material as the applicable aging effect for cable trays and supports 

made of carbon steel. 

Control Building 

The purpose of the control building is to house the common control room for Units 1 and 2 and 

associated auxiliaries. The building is a reinforced concrete structure with steel framing, and 

consists of the following major structural components: 

0 reinforced concrete foundation mat 

• reinforced concrete floors with reinforced concrete beam and girder framing 

• reinforced concrete or concrete block interior walls and reinforced concrete columns 

* reinforced concrete exterior walls and prestressed exterior wall panels * reinforced concrete slab on metal roof deck system supported by steel framing 

Additional information may be found in Unit 1 UFSAR Section 12.3.3.1.1 and Unit 2 UFSAR 

Section 3.2.1. 

The control building includes the substructure, foundations, superstructure, walls, floors, and roof 

necessary to maintain equipment integrity and personnel habitability. The control building is 

designed as a Seismic Category I structure to protect vital equipment and systems both during and 

following the most severe natural phenomenon. 

The applicable aging effects for structural components in the control building are loss of material 

and cracking. 

Drywell Penetrations 

Table 3.3.1-3 of the LRA identifies the containment mechanical penetrations and steel bellows inside 

vent pipe as components requiring aging management. The function of the containment mechanical 

penetrations is that of a "fission product barrier," and that of the bellows is to provide a "pressure 

boundary and fission product barrier." Their environment is the inside atmosphere of containment. 

Table 3.3.1-3 refers to Section C.2.6.2 of the LRA for a description of the aging management 

review. Mechanical penetrations are discussed in Section 2.4.3 of the LRA. 

The purpose of the drywell electrical penetrations is to provide a path for cable currents/signals to 

pass through primary containment to support the various modes of operation of their associated 

systems while maintaining the integrity of the primary containment.

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Containment penetrations include electrical penetration assemblies in addition to the mechanical 

penetrations referenced above. Electrical penetrations are hermetically sealed penetrations, which 

are welded to the primary containment shell plate. They must maintain their primary containment 

pressure integrity function during all postulated operating and accident conditions. They are 

designed for the same pressure and temperature conditions as the drywell and pressure 

suppression chamber. 

The applicant identified loss of material as the applicable aging effect for drywell penetrations. 

Emergency Diesel Generator (EDG) Building 

The purpose of the EDG building is to house the emergency diesel generators and their accessories 

essential for safe plant shutdown for both Unit 1 and Unit 2. The EDG building is a reinforced 

concrete structure consisting of the following major structural components: 

* reinforced concrete foundation mat 

* reinforced concrete exterior walls and interior walls 

* reinforced concrete roof and parapet wall 

The EDG building houses EDGs and their accessories and the building has labyrinth access 

openings for protection against tornado missiles. The EDG building is designed as a Seismic 

Category I structure to protect vital equipment and systems both during and following the most 

severe natural phenomena. The EDG building provides support and equipment integrity for the 

EDGs, which provide essential ac supply. Additional information may be found in Unit 1 UFSAR 

Section 12.2.6 and Unit 2 UFSAR Section 9.4.5. 

The applicant identified loss of material as the applicable aging effect for structural components in 

the EDG building. 

Fuel Storage 

The fuel storage system provides specially designed underwater storage space for the spent-fuel 

assemblies, which require shielding and cooling during storage and handling. This system also 

provides specially designed dry, clean storage areas for the new fuel assemblies. The fuel storage facility is located inside the secondary containment on the refueling floor. 

The components included in the fuel storage facility are the spent fuel pool, concrete vault and 

stainless steel liner, fuel pool gates, fuel racks, and other equipment necessary to properly store 

irradiated fuel and components. 

The fuel storage system contains components fabricated from carbon steel, stainless steel, 

aluminum, and concrete, that are exposed to an inside and demin water environment. 

Additional information may be found in Sections 10.2 and 10.3 of the Unit 1 UFSAR, and Section 9.1 

of the Unit 2 UFSAR. 

The applicant identified loss of material as the applicable aging effect for fuel storage components.

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Intake Structure 

The purpose of the intake structure is to protect residual heat removal service water and plant 

service water equipment from the influence of environmental conditions such as flooding, 

earthquakes, and tornadoes. 

The intake structure is a concrete and steel structure consisting of the following major structural 

components: 

* reinforced concrete foundation mat 

* reinforced concrete exterior walls and internal walls 

* reinforced concrete floors and roof 

* structural steel framing and grating, steel water spray and internal missile shield barriers, 

stairs, and platforms 

Unit 1 shares the intake structure with Unit 2. The intake structure has labyrinth access openings 

for protection against tornado missiles. Additional information may be found in Unit 1 UFSAR 

Subsection 12.2.7 and Unit 2 UFSAR Subsection 3.8.4. 

The applicant identified loss of material as the applicable aging effect for structural components in 

the intake structure. 

Main Stack 

The purpose of the main stack is to support and protect monitoring equipment and provide for the 

monitoring and elevated release of gaseous effluents from the main stack system. 

The main stack is a concrete cylindrical shape, which consists of the following major components: 

* reinforced concrete foundation mat supported on steel "H" piles 

* reinforced concrete truncated conical cylinder 

* reinforced concrete internal floors 

0 reinforced concrete loading bay consisting of concrete base slab, external and internal walls, 

and roof 

Unit 1 shares a single main stack used to discharge gaseous waste with Unit 2. The main stack 

extends 120 meters above ground level. Additional information may be found in Unit 1 UFSAR 

subsection 5.3.4 and Unit 2 UFSAR Section 11.3. 

The applicant identified loss of material and cracking as the applicable aging effects for structural 

components of the main stack.

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Piping Specialties

The applicant stated that piping specialties provide support for essential piping systems. Essential 

piping systems are required to maintain the integrity of safety-related and non safety-related 

systems during normal operations and for transient/accident mitigation. The piping specialties 

consist of hangers and supports for ASME Class I piping; hangers and supports for non-ASME 

Class I piping, tubing, and ducts; and tube trays and covers. These piping specialties also include 

snubbers and pipe restraints, regardless of system affiliation, as well as non-ASME HVAC duct 

supports and tube trays. The applicant stated that pipe supports for the reactor coolant system and 

subsystems are provided to ensure pressure retaining capability of the piping systems against 

weight, seismic, and fluid dynamic loads. Pipe supports maintain the integrity of non safety functions 

during accident and seismic events. This includes all safety-related plant pipe supports, pipe 

restraints, and tubing supports. Pipe supports for non safety-related piping (non seismic category) 

located throughout the plant are included in this function. These supports are not designed to any 

seismic criteria, but are designed for dead weight and thermal loads only. Only those Seismic 

Category II supports required to support functions X43-04 (Plant Wide Fire Suppression With 

Water), W33-03 (Screen Wash Isolation), and N61-03 (Post-Accident Radioactive Decay Holdup) 

are included within the scope of license renewal. All other Seismic Category II supports are 

excluded from the scope of license renewal. 

In Table 3.3.1-1 of the LRA, the applicant listed the structural components, environments in which 

the components are located, materials of construction, applicable aging effects, and aging 

management programs for the components associated with piping specialties. The piping 

specialties consist of hangers and supports for ASME Class I piping, hangers and supports for non

ASME Class I piping, tubing, and ducts, as wellas tube trays and covers exposed to containment 

atmosphere, inside (sheltered), outside, and submerged environments. These components are 

made of carbon, galvanized, and stainless steels. 

Loss of material is identified as the applicable aging effect for piping specialty components. 

Primary Containment 

The purpose of the primary containment is to isolate and contain fission products released from the 

reactor primary system following a DBA and to confine the postulated release of radioactive 

material. 

The primary containment design employs a pressure suppression containment system, which 

houses the reactor vessel, the reactor coolant recirculating loops, and other branch connections of 

the reactor primary system. The pressure suppression system consists of a drywell; a pressure 

suppression chamber (torus), which stores a large volume of water; a connecting vent system 

between the drywell and the pressure suppression pool, isolation valves, vacuum relief system; 

containment cooling systems; and other service equipment. The pressure suppression chamber 

is a steel pressure vessel, in the shape of a torus located below and encircling the drywell, with a 

major diameter of approximately 107 ft and a cross-sectional diameter of approximately 28 ft. The 

pressure suppression chamber contains the suppression pool and the air space above the pool. The 

suppression chamber transmits seismic loading to the reinforced concrete foundation slab of the 

reactor building. Space is provided outside of the chamber for inspection. Additional information 

about this system may be found in Unit 1 UFSAR Subsection 5.1.2 and Unit 2 UFSAR Subsection 

6.2.1

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The primary containment system, in conjunction with other safeguard features, provides the 

capability to limit the release of fission products in the event of a postulated DBA so that offsite 

doses do no exceed 10 CFR Part 100 guidelines. The pressure suppression pool initially serves as 

a heat sink for any postulated transient or accident condition in which the normal heat sink (main 

condenser or shutdown cooling system) is unavailable. 

Loss of material and cracking are identified as the applicable aging effects for structural components 

in the primary containment. 

Reactor Building 

The purpose of the reactor building is to shelter and support the refueling and reactor servicing 

equipment, new and spent fuel storage facilities, and other reactor auxiliary and service equipment. 

The building is a reinforced concrete structure with a steel superstructure. The building consists of 

the following major structural components: 

* reinforced concrete foundation mat 

0 reinforced concrete exterior walls and precast exterior wall panels 

* reinforced concrete floors with reinforced concrete beams and girders framing 

0 reinforced concrete interior walls with some blockouts filled with concrete masonry 

* reinforced concrete roof slab on metal roof deck system supported by steel superstructure 

The reactor building completely encloses the reactor and its pressure suppression primary 

containment system. Also housed within the reactor building are the core standby cooling systems, 

RWCU demineralizer system, SLCS, CRD system, RPS, and electrical equipment components. The 

building is designed for minimum leakage so that the SGTS has the necessary capacity to reduce 

and hold the building at a subatmospheric pressure under normal wind conditions. Additional 

information may be found in Unit 1 UFSAR Subsection 12.2.1 and Unit 2 UFSAR Section 3.0. 

The reactor building provides primary containment during reactor refueling and maintenance 

operations when the primary containment is open. It also provides an additional barrier when the 

primary containment system is functional. Therefore, it is relied on to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposure comparable to the 10 CFR 

Part 100 guidelines. This evaluation includes the blowout panels in the pipe-chase between the 

reactor building and the turbine building. 

Loss of material, cracking, material property changes, and loss of adhesion are identified as the 

applicable aging effects for structural components in the reactor building. 

Reactor Building Penetrations 

The purpose of the reactor building penetrations is to allow mechanical and electrical equipment and 

personnel to pass through secondary containment and support the various modes of operation of 

their associated systems while maintaining the integrity of the secondary containment. The

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penetrations for piping and ducts are designed for leakage characteristics consistent with 

containment requirements for the entire building. Electrical cables and instrument leads pass 

through ducts sealed into the building wall. 

Table 3.3.1-7 of the LRA identifies the reactor building penetrations as components requiring aging 

management. The reactor building penetrations function as a "fission product barrier." The 

penetration materials are carbon steel and galvanized steel functioning in inside, outside, and 

embedded environments. Section C.2.6.3 of the LRA contains the aging management review for 

steel structures in seismic Category I buildings. Table 3.3.1-7 identifies the protective coating 

program and the structural monitoring program as the AMPs credited with managing the aging 

effects for reactor building penetration components. Additional information may be found in Unit 1 

UFSAR Section 5.3.3.2 and Unit 2 UFSAR Figure 8.3-11. 

The applicant identified loss of material as the applicable aging effect for reactor building penetration 

components. 

Turbine Building 

The purpose of the turbine building is to house the turbine-generator and associated auxiliaries, 

including the condensate and feedwater systems. 

The turbine building is a steel and concrete structure consisting of the following major structural 

components: 

* reinforced concrete foundation mat 

* reinforced concrete floors self-supporting or supported by structural steel framing * reinforced concrete or concrete block interior walls 

* reinforced concrete turbine pedestal resting on concrete mat foundation 

* reinforced concrete exterior walls 

0 reinforced concrete slab on metal roof deck system supported by steel framing 

Additional information may be found in Unit 1 UFSAR Section 12.2.2 and Unit 2 UFSAR 

Section 3.2. 

There is no equipment or instrumentation located in the turbine building proper that would preclude 

the ability to shut down the reactor safely if the turbine building were damaged from a high-energy 

line failure. The turbine building is designed and constructed to ensure that it will not damage 

Category I structures or equipment located inside or adjacent to it in the event of a design-basis 

event (DBE). The cable chase area below elevation 147 ft is designed to Seismic Category I 

criteria. The Seismic Category I barrier between the main steam and feedwater piping located above 

elevation 147 ft and the cable chase area below precludes any adverse direct effects of postulated 

failure of the main steam or feedwater piping in the turbine building. The cables in this area provide 

trip inputs for the recirculation pump trip and reactor scram following generator load rejection or a 

turbine trip originating in the turbine building. Based on these considerations, the portions of the Unit 

1 turbine building and the cable chase area below elevation 147 ft are included within the scope of 

license renewal. The portions of the Unit 2 turbine building and the cable chase area below 

elevation 147 ft are also in scope, as well as the supports over the radioactive release pathway for 

the main condenser.

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Loss of material is identified as the applicable aging effect for structural components in the turbine 

building. 

Yard Structures 

The purpose of the yard structures is to provide equipment integrity and personnel habitability for 

various structures on the plant site. These yard structures include: 

* concrete wall and foundation accommodating the condensate storage tank 

0 foundation of the nitrogen storage tank 

* service water valve pit boxes 

0 foundation for the fire pump house 

* foundations for the two fire protection water storage tanks 

* foundations for the two fire protection diesel pump fuel tanks 

* underground concrete duct runs and pull boxes between Class I structures 

Additional information about these structures may be found in Unit 1 UFSAR Section 5.2.3.9 and 

Unit 2 UFSAR Section 3.8.5.1. 

The intended function of the yard structures is to provide equipment integrity and personnel habitability for the various structures listed. This intended function is brought into scope because 

of the Seismic Category I foundation supporting the liquid nitrogen tank. The liquid nitrogen tank 

provides the safety-related backup supply of motive gas for the drywell inerting system and the 

drywell pneumatic system. The UFSAR discusses the reliance of the safety analysis upon the liquid nitrogen tank. In addition, Safe Shutdown Pathways 1 and 2 in the FHA rely upon the liquid nitrogen 

tank to achieve safe shutdown in the event of a fire. 

With respect to the enclosure around the CST, the wall and the CST foundation are seismically qualified to Category 1 requirements. The service water valve boxes are in scope as they contain 

in-scope piping for the plant service water system. The concrete duct runs and pull boxes that 

traverse the yard between various Class I structures as well as turbine building are included within 

the scope of AMR. These duct runs are used for routing safety-related circuits and provide 

protection to them. 

The foundations for the fire pump house, fire protection water storage tanks, and the fire protection 

diesel pump fuel tanks are also in scope. 

Loss of material is identified as the applicable aging effect for structural components in yard 

structures. 

3.6.2.2 Aging Management Programs 

The program and activity descriptions presented in Sections A and B of the LRA represent the 

commitments for managing aging of the in-scope systems, structures and components during the 

period of extended operation. Eleven aging management programs or activities are credited for 

managing the applicable aging effects for civil/structural components during the renewal term. In 

many cases, existing programs and activities were found adequate for managing aging in the 

renewal term. In some cases, aging management reviews revealed that programs or activities 

required some degree of enhancement to adequately manage aging. Lastly, a number of new

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inspection programs have been developed by the applicant to provide objective evidence that aging 

was, in fact, being adequately managed by the credited programs and activities. The scope of these 

programs and activities for license renewal is discussed in Sections A and B of the LRA. 

In Tables 3.3.1-1 through 3.3.1-13 of the LRA, the applicant identified the following aging 

management programs and activities required to manage aging effects for specific civil/structural 

component groups discussed in Section 3.6.2.1 of this SER: 

* protective coatings program 

* structural monitoring program 

& inservice inspection program 

0 suppression pool chemistry control program 

0 demineralized water and condensate storage tank chemistry control program 

0 treated water systems piping inspections 

* passive component inspection activities 

* gas systems component inspections 

* primary containment leakage rate testing program 

* component cyclic or transient limit program 

* fuel pool chemistry control program 

3.6.3 Staff Evaluation 

The staff reviewed the information provided in Section 2.4, "Structures Screening Results," and 

Section 3.3.1, "Civil/Structural Components," of the Plant Hatch LRA, and pertinent information 

provided in Sections A, B, and C of the LRA to determine whether the applicant has adequately 

identified the effects of aging on the structures and structural components listed in Section 3.6.2.1 

of this SER and whether the applicant has demonstrated that the associated components will be 

adequately managed during the period of extended operation as required by 10 CFR 54.21 (a)(3). 

After completing the initial review, the staff issued several requests for additional information that 

are discussed within the context of the staff evaluation below. 

3.6.3.1 Effects of Aging 

The applicant stated that the process to determine the aging effects applicable to structural 

components begins with a review of the aging effects identified in industry literature. Section C.1 of 

the LRA presented The applicant's systematic evaluation of environments and materials to identify 

those aging effects requiring management in the renewal term. This evaluation was performed 

using information developed based on available industry knowledge. A review of pertinent generic 

industry operating experience, as contained in NRC generic communications, was a part of the 

applicant's process for determining aging effects requiring management. Generic communications 

evaluated as part of this review are listed in Table C.1.5-1 of the LRA and the results are contained 

in the sections for various material and environment combinations at Plant Hatch. The staff finds 

this approach for reviewing industry operating experience acceptable. 

From this set of aging effects, the applicant considered Plant Hatch materials, operating 

environment (internal and external) and operating stresses to determine aging effects that need to 

be managed. Finally, the plant-specific operating experience, industry-wide operating experience 

and CLB are reviewed to identify any additional aging effects that require aging management. The 

applicant indicated that this process should provide reasonable assurance that the full set of aging

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effects was established for the aging management review. The staff concurs with this approach for 

identifying pertinent aging effects. 

GENERAL STRUCTURAL AGING EFFECTS 

In order to facilitate the identification of aging effects requiring management, the applicant 

categorized Plant Hatch structural components into the following groups: 

* structural steel and aluminum components 

* concrete components 

• structural sealants 

* acrylic 

A discussion of the aging effects requiring management for each of these groups follows. 

Structural Steel and Aluminum Components 

The applicant grouped structural steel and aluminum components into commodities to efficiently 

perform the aging management reviews. Details of these reviews are described in Section C.2.6 

of the LRA. The component types that make up the commodity groups were collectively reviewed 

by the applicant. Many of the component types included in these reviews are: 

primary containment steel component types such as the containment shell plate, headers 

and down comers, penetrations, bellows, bracing, supports, restraints, columns and saddles 

building and structural steel component types such as beams, girders, columns, bracing, 

hangers, plate, and liner plate 

miscellaneous structural steel and aluminum component types such as door frames, blowout 

panels, tornado vent supportframes, plate, sheet metal, penetrations, pipe, tubing, supports, 

grating, stairs, handrails, storage racks, seismic restraints, and various miscellaneous 

shapes 

bolts and anchors, such as structural bolts, cast-in-place bolts, and expansion and wedge 

anchors 

The component types are made from carbon steel, low alloy steel, galvanized steel, stainless steel 

and aluminum. The process for identifying aging effects considers the materials, operating 

environments and operating stresses. The service environments are discussed in Section C.1.1 of 

the LRA. In addition, Sections C.1.2.1 through C.1.2.4 of the LRA further discuss steel in various 

water environments. Applying the process, the applicant identified the following list of aging effects: 

loss of material due to general corrosion, pitting, crevice corrosion, galvanic corrosion, and 

MIC 

cracking due to fatigue 

Section C.1.4.1 of the LRA discusses these aging effects.

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The staff finds the applicant's approach for evaluating the applicable aging effects for structural steel 

and aluminum components to be reasonable and acceptable. The staff concludes that the 

applicable aging effects for the component group have been identified. 

Concrete Structural Components 

The concrete structural components are grouped by the applicant into a commodity to efficiently 

perform the aging management reviews described in Section C.2.6.1 of the LRA. The following 

component types that comprise the commodity group: 

* masonry block walls 

* equipment foundations 

0 floors, sumps and roofs 

* columns, slabs and beams 

* interior and exterior walls (above and below grade) 

The component types are composed of concrete, reinforcing steel and grout. The process 

considers the materials, operating environments, and operating stresses. The service environments 

are discussed in Section C.1.1 of the LRA. Applying the process, the applicant identified the 

following aging effects: 

* loss of material due to corrosion of embedded steel 

* cracking in masonry block walls due to expansion or contraction 

Section C.1.4.2 of the LRA discusses the above listed aging effects for concrete structural 

components. 

The staff finds the applicant's approach for evaluating the applicable aging effects for concrete 

structural components to be reasonable and acceptable. The staff concludes that the applicable 

aging effects for concrete structural components have been identified. 

Structural Sealants 

The structural sealants are grouped into a commodity by the applicant to efficiently perform the 

aging management reviews described in Section C.2.6.7 of the LRA. The following sealant types 

comprise the commodity group and are collectively reviewed: 

joint and caulking sealant in the joints between the exterior precast panels for the reactor 

buildings 

main control room environmental control system duct gaskets and flex connectors. 

The component types are composed of nonmetallic inorganic elastomers, elastomers, and non

asbestos synthetic fibers. The process for identifying the aging effects was applied to structural 

sealants. The process considers the materials, operating environments and operating stresses. 

Section C.1.1 of the LRA discusses the service environments. Applying the process, the applicant 

identified the following list of aging effects: 

0 material property changes and cracking due to thermal exposure

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o loss of adhesion due to exposure to excessive moisture 

Section C.1.4.3 of the LRA discusses the above listed aging effects for sealants. 

The staff finds the applicant's approach for evaluating the applicable aging effects for structural 

sealants to be reasonable and acceptable. The staff concludes that the applicable aging effects for 

structural sealants have been identified. 

Acrylic 

The tornado vent assembly domes are made of acrylic, and are evaluated in Section C.2.6.8 of the 

LRA. The acrylic is Plexiglas G cell cast acrylic polymer. The chemical name is polymethyl methacrylate and it is composed of carbon, hydrogen, and oxygen. No fillers are added as part of 

the forming process and the material contains no significant halogens or sulfur. The process for 

identifying the aging effects was applied to the acrylic. The process considers the materials and 

operating environments. The service environments are discussed in Section C.1.1 of the LRA. The 

applicant identified cracking as the applicable aging effect. 

Section C.1.4.4 of the LRA discusses the aging effect. 

The staff finds the applicant's approach for evaluating the applicable aging effects for the acrylic tornado vent assembly dome to be reasonable and acceptable. The staff concludes that the 

applicable aging effects for the tornado vent acrylic dome have been identified. 

STRUCTURE AND STRUCTURAL COMPONENT AGING EFFECTS 

In order to further facilitate the identification of aging effects requiring management, the applicant evaluated structural components for each structure. A discussion of the aging effects requiring management for each of these structures and structural components follows. 

Conduits, Raceways, and Trays 

The conduits, raceways, and trays are fabricated from carbon steel, galvanized steel, or aluminum, exposed to an inside or containment atmosphere environment. The applicant identified loss of 

material as the aging effect for carbon steel, and possibly galvanized steel. Loss of material due 

to general corrosion, crevice corrosion, pitting corrosion and MIC is considered. It was not clear if 

galvanized steel is included for loss of material. In its response to RAI 3.6-8, dated October 10, 

2000, the applicant stated that galvanized steel exposed to a containment environment is subjected to an inert nitrogen environment during plant operations. The inerted containment environment 

reduces the potential for corrosion of galvanized steel products. During outage periods, the 

environment is conditioned indoor air. 

The applicant further stated that Section C.1.4.1 of the LRA discusses loss of material as an aging effect for galvanized steel. For galvanized steel exposed to indoor air, loss of material may occur 

only in areas where crevices may collect moisture. Therefore, galvanized steel exposed to an inside 

containment environment can experience loss of material due to crevice corrosion, and crevice 

corrosion is an aging effect requiring management. The staff finds that the applicant's response is 

consistent with industry experience and, therefore, is acceptable. This response closes staff RAI 

3.6-8. The applicant did not identify any aging effects for aluminum exposed to an inside

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containment environment. The staff agrees that there are no credible aging effects for aluminum 

exposed to an inside containment environment. 

The applicant also did not consider self-loosening of bolted connections by vibration as an aging 

effect. The staff understands that proper design and installation practices should minimize the 

likelihood of bolt self-loosening by vibration. However, expansion and undercut anchors in concrete 

can become loose due to local degradation of surrounding concrete, as a result of vibratory loads. 

This concern is addressed and resolved in Section 3.6.3.2 of this SER as part of the closure of RAI 

3.6-9 (see Conduits, Raceways, and Trays in Section 3.6.3.2 of this SER). 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups for conduits, raceways, and trays. 

Control Building 

The control building contains various components (e.g., anchors and bolts, blowout panels, 

miscellaneous steel, reinforced concrete, and structural steel) fabricated from carbon steel, 

galvanized steel, aluminum, and reinforced concrete exposed to the embedded, inside, and outside 

environments. The applicant stated that the aging effect for all of these material and environment 

combinations is loss of material. The reinforced concrete may also be subject to cracking. The staff 

agrees with the applicant's position. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity component groups in the control building. 

Drywell Penetrations 

The drywell penetrations are fabricated from carbon steel that is exposed to the containment 

atmosphere environment and an embedded environment. The applicant identified loss of material 

as the aging effect in Table 3.3.1-6 of the LRA. The applicant evaluated the aging effect for this 

material and environment in Section C.2.6.2 of the LRA and identified several forms of corrosion that 

may result in loss of material (e.g., general corrosion, crevice corrosion, pitting, and MIC). 

As stated before, the applicant has considered loss of material for all containment penetrations and 

vent line bellows in Tables 3.3.1-3 and 3.3.1-6 of the LRA. In Section C.2.6.2 of the LRA, the 

applicant states two aging effects; (1) loss of material due to various types of corrosion, and (2) 

cracking due to fatigue in the localized areas. 

In response to RAI 3.6-36 related to the AMR for penetrations in the torus, the applicant points out 

that the penetrations are covered under primary containment penetrations in Section C.2.6.2 of the 

LRA, together with the AMR for drywell penetrations. Many torus penetrations are submerged in 

torus water, an environment distinctly different from that of the penetrations in the drywell, and they 

require different ISI, coating, and leak-testing procedures. In a letter dated January 5, 2001, the 

staff asked the applicant to provide justification why the torus penetrations should not be placed in 

a commodity group other than that for other components in the primary containment (i.e. drywell). 

By letter date January 31, 2001, the applicant provided a drawing showing a section through the 

torus and associated penetrations. The drawing also identified the AMPs associated with the 

penetrations above and below the water line. For torus penetrations above the water line, the 

applicant takes credit for implementing the inservice inspection program, the primary containment

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leakage testing program, the protective coating program, and the component cyclic or transient limit 

program. Additionally, for torus penetrations below the water line and in the splash zone of the torus 

shell, the applicant takes credit for implementing the suppression pool chemistry control program, the torus submerged component inspection program, and the protective coatings program. Moreover, the applicant states, "a review of torus inspection reports indicates that degradation of 

the torus coating, in the form of thinned coatings, and some pitting corrosion in the torus immersion 

area is general in nature and occurs primarily on the torus shell. No specific corrosion has been 

noted around penetrations welded to the shell. Corrosion is generally more evident near the torus 

waterline and at or near the bottom of the torus where sludge or small debris collects." The 

applicant also provides a listing of penetrations in the torus of each unit. This information 

adequately responds to the staff's concern regarding the AMPs for torus penetrations, and closes 

RAI 3.6-36. This explanation also provides an acceptable response to the staff's RAI 3.6-41 related 

to the separate AMP for torus corrosion, RAI 3.6-41 is also closed. 

In response to RAI 3.6-37 related to the specific environment around drywell and torus penetrations, the applicant referred to the programs enumerated in Section C.2 of the LRA as noted in Tables 

3.3.1-3 and 3.3.1-6 of the LRA. The staff specifically needs information for the environment (i.e., 

temperature, humidity, cumulative radiation, demineralized water) around groups of primary containment penetrations having similar operating histories in order to ascertain whether the AMPs 

are appropriate for the specific operating history/environment for individual groups of containment 

penetrations. By letter dated January 31, 2001, the applicant responded that two types of 

penetrations are considered: electrical and mechanical (piping). Each drywell electrical penetration is composed of the electrical feed-through assembly and the structural piping to which it is attached. 

Electrical penetrations are included in the EQ program and the electrical, non-metallic assemblies 

are evaluated and given a qualified life. The structural part of the penetration is managed by the 

ISI program. The environmental information below can be considered applicable to all drywell penetrations. The worst-case normal inside-containment environment for all drywell penetrations 

is as follows: 

Temperature: 150°F 

Radiation: 9.17 E7 Rads (gamma); 4.5 E16 NVT neutron fluence 

Humidity: 50 percent - 90 percent 

Moisture/wetting: None 

The environment for torus penetrations varies between the submerged and non-submerged penetrations. The worst-case environment for torus penetrations is as follows: 

Temperature: 105 0F 

Radiation: 1.4 E7 rads gamma 

Humidity: 50 percent - 90 percent Moisture/wetting: See visual aid (drawing as discussed above) for submerged penetrations 

This information justifies the applicant's focus on the exposure of drywell penetrations to varying environments though they are grouped into the same commodity group. The staff considers 

RAI 3.6-37 closed. 

In response to RAI 3.6-38 related to bellows in the penetrations (other than those in the vent pipes), the applicant referred to the response given to RAI 3.6-37. The staff was basically looking for the 

operating history of the bellows knowing that the two ply bellows, normally used in containments,

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undergo gradual degradations and leakage. However, in response to RAI 3.6-42, the applicant provided the following information. The applicant indicated that, upon the receipt of IN 92-20, 

"Inadequate Local Leak Rate Testing," it decided to select a sample of three bellows for augmented 

testing to evaluate the adequacy of local leak rate testing (LLRT) methods and procedures. A plate 

was welded inside containment to test the bellows in the proper direction. The tests confirmed that 

the testing methods and procedures were acceptable. Some of the two-ply bellows in Unit 2 were 

replaced because of bellow leakage detected during the LLRT. The bellows leakage was caused 

by the inadvertent exposure of the bellows to chloride during maintenance activities. This description confirms that the applicant has adequately considered the potential aging effects for monitoring leakage in primary containment bellows. RAls 3.6-38 and 3.6-42 are considered closed. 

On the basis of the above information, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups associated with the drywell penetrations. 

EDG BuildinM 

The EDG building contains various components (e.g., anchors and bolts, miscellaneous steel, 

reinforced concrete, and structural steel) fabricated from carbon steel, galvanized steel, and 

concrete exposed to the embedded, inside, and outside environments. The aging effect for all of 

these material and environment combinations is loss of material. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the EDG building. 

Fuel Storage 

The fuel storage system contains components fabricated from carbon steel, stainless steel, 

aluminum, and concrete exposed to an inside environment. The applicant identified loss of material 

as the aging effect for all components made of these materials, except for the aluminum storage racks, exposed to an inside environment. The applicant stated that an inside environment is a 

"sheltered" environment, which assumes 50 percent to 90 percent humidity, an ambient temperature less than 120°F and a maximum radiation level of 9.0 X 106 rads. The applicable aging effect due 

to exposure to an inside environment is loss of material due to general corrosion, crevice corrosion, pitting, and MIC of carbon steel and submerged stainless steel components, and due to corrosion 

of embedded steel for the reinforced concrete. 

For components fabricated from stainless steel or aluminum in a demineralized water environment, 

the applicant identified loss of material as the aging effect in Table 3.3.1-4 of the LRA. The 

demineralized water is processed on site and is stored in demineralized water storage tanks and 

condensate storage tanks where impurities and conductivity are maintained at low levels but 

dissolved oxygen concentrations are neither controlled nor monitored. The applicant stated that the 

applicable aging effect due to exposure to a demineralized water environment is loss of material due 

to crevice corrosion, pitting and MIC for stainless steel and galvanic corrosion for aluminum. 

According to Table 3.3.1-4, loss of material is an applicable aging effect for stainless steel 

components in an embedded environment. The fuel pool chemistry control program is the AMP 

credited with managing this aging effect

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On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups associated with fuel storage. 

Intake Structure 

The intake structure contains various components (e.g., anchors and bolts, miscellaneous steel, 

reinforced concrete, and structural steel) fabricated from carbon steel, galvanized steel, and 

concrete exposed to embedded, inside, outside, high humidity, submerged, buried, and wetting other-than-humidity environments. The aging effects for all of these materials and environment 

combinations is loss of material. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the intake structure. 

Main Stack 

The main stack contains various components (e.g., anchors and bolts, miscellaneous steel, 

reinforced concrete, and structural steel) fabricated from carbon steel, galvanized steel, copper alloy, and concrete exposed to the inside, embedded, and outside environments. The aging effect 

for all of these materials and environment combinations is loss of material and cracking. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the main stack. 

PiDing Specialties 

For the piping specialties, the applicant stated that hangers and supports for ASME Class I piping (made of carbon steel and galvanized steel) are exposed to a containment atmosphere or inside 

(sheltered) environment. As discussed in Sections C.1.2.8, C.1.2.9, and C.2.6.4 of the LRA, loss 

of material is identified as an applicable aging effect. The applicant also stated that hangers and 

supports for non-ASME Class I piping, tubing, and ducts (made of carbon, galvanized, and stainless 

steels) are exposed to a containment atmosphere, inside (sheltered), outside, or submerged environment. As discussed in Sections C.1.2.2, C.1.2.8, C1.2.9, and C.2.6.4 of the LRA, loss of 

material is identified as an applicable aging effect. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups associated with piping specialties. 

Primary Containment 

The applicant stated that the primary containment system contains various components (e.g., bolts 

and anchors, containment penetrations, miscellaneous steel) fabricated from carbon steel, galvanized steel, and stainless steel exposed to the containment atmosphere, inside, torus water, 

embedded, and high humidity environments. The applicant identified loss of material as the aging effect. The applicant evaluated the aging effects for these materials and environment in Sections 

C.2.6.2 and C.2.2.3.1 of the LRA and identified several forms of corrosion that may result in loss 

of material (e.g., general corrosion, crevice corrosion, pitting, and MIC).

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The applicant identified loss of material and cracking as the aging effects. According to Table 3.3.1 

3 of the LRA, the primary containment system contains various components (e.g., bolts and 

anchors, blind flange, containment isolation valves, miscellaneous steel) fabricated from carbon 

steel, possibly galvanized steel, and stainless steel exposed to torus water. The applicant evaluated 

the aging effects for these materials and environment in Sections C.2.6.1 and C.2.6.2 of the LRA 

and identified several forms of corrosion that may result in loss of material (e.g., general corrosion, 

crevice corrosion, galvanic corrosion, pitting, MIC, and erosion corrosion). RAI 3.6-14 requested 

the applicant to clarify whether any primary containment galvanized steel components are subject 

to the torus water environment and, as applicable, indicate the appropriate AMP. The applicant 

indicated that some galvanized carbon steel grating components that are part of the platforms inside 

the torus may be intermittently exposed to torus water at some time during operation if the torus 

water level rises high enough, or if sloshing of the water surface occurs during a safety relief valve 

(SRV) discharge. The applicant stated that galvanized carbon steel exposed to water may 

experience a loss of material due to corrosion, and corrosion of galvanized steel components inside 

the torus is managed by the protective coatings program and by suppression pool chemistry control, 

as discussed in LRA Section C.2.6.2. This response is sufficient in detail and acceptable. RAI 3.6

14 is considered resolved. 

The primary containment system also contains various components (e.g., containment isolation 

valves, and associated piping) fabricated from carbon steel and stainless steel exposed to 

demineralized water. The applicant identified loss of material and cracking as the aging effects. 

The applicant evaluated the aging effects for these materials and environment in Sections C.2.2.2.2 

and C.2.2.3.1 of the LRA and identified several forms of corrosion that may result in loss of material 

(e.g., general corrosion, crevice corrosion, galvanic corrosion, erosion-corrosion, pitting, and MIC). 

The applicant also identified cracking as an aging effect caused by thermal fatigue. 

The primary containment system contains containment isolation valves and piping fabricated from 

carbon steel exposed to raw water. The applicant identified loss of material and cracking as the 

aging effects. The applicant evaluated the aging effects for this material and environment in Section 

C.2.6.2 of the LRA and identified several forms of corrosion that may result in loss of material. 

The primary containment system contains various components (e.g., anchors and bolts, 

containment penetrations, miscellaneous steel) fabricated from carbon steel and possibly galvanized 

steel and stainless steel that is embedded. RAI 3.6-18 requested the applicant to clearly indicate 

the materials that are embedded. The applicant, after its review of screening records and 

supporting information, identified that only carbon steel components that are listed in Table 3.3.1-3 

as embedded are the ones that are embedded items. RAI 3.6-18 is closed. 

Staff RAI 3.6-19 requested the applicant to clarify a potential discrepancy between Table 3.3.1-3 

and Section C.2.6.2 of the LRA. The applicant stated that cracking identified as a detrimental aging 

effect in Section C.2.6.2 applies only to cracking due to fatigue of the torus. The applicant further 

asserted that anchors and bolts, and miscellaneous steel are not subjected to significant vibratory 

or cyclic loads, and are therefore not subject to cracking. Also, stainless steel bellows, used in some 

penetrations that are subject to thermal movement or longitudinal operational piping loadings, are 

designed to withstand the thermal and cyclic loadings to which they are subjected, and are not 

considered susceptible to cracking. This response resolves RAI 3.6-19. The applicant evaluated 

the aging effects for these materials and environment in Section C.2.6.2 and identified several forms 

of corrosion that may result in loss of material (e.g., general corrosion, crevice corrosion, pitting, and 

MIC).

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The primary containment system contains containment isolation valves, tubing, and piping fabricated 

from carbon steel and stainless steel exposed to wetted gas. The applicant identified loss of 

material and cracking as the aging effects. The applicant evaluated the aging effects for this 

material and environment in Sections C.2.2.9.1 and C.2.2.9.2 of the LRA and identified several 

forms of corrosion that may result in loss of material (e.g., general corrosion, pitting, crevice 

corrosion, galvanic corrosion, and MIC). Sections C.2.2.9.1 and C.2.2.9.2 also identified cracking 

caused by thermal fatigue as an aging effect for these components and this environment. 

In Table 3.3.1-3, the applicant identified fatigue cracking for blind flanges (commodity group 

C.2.2.3.1), containment isolation valves (commodity groups C.2.2.2.2 and C.2.2.3.1, C.2.6.2, 

C.2.2.9.1, and C.2.2.9.2), piping (commodity groups C.2.2.2.2, C.2.2.3.1, C.2.6.2, C.2.2.9.1, 

C.2.2.9.2), tubing (commodity group C.2.2.9.2) and vent pipes, vent headers and downcomers 

(commodity group C.2.6.2). In Section 4 of the LRA, the applicant included thermal fatigue as a 

TLAA (the staff's evaluation of this TLAA is discussed in Section 4.2 of this SER). 

Based on the staff's experience, degradation of piping systems (e.g., loss of integrity of bolted 

closures, cracking of welds and loosening bolts) may potentially be caused by vibration (mechanical 

or hydrodynamic) loading. In Table 3.3.1-3 of the LRA, the applicant did not identify loss of preload 

as an aging effect for bolting in the primary containment system. The applicant was requested via 

RAI 3.6-50 to clarify whether the vibration related aging effects including cracking of piping welds 

and loosening of bolts were considered in the aging review for the primary containment system, and 

if they were excluded, provide the basis. The applicant responded to this RAI in its letter dated 

October 10, 2000. The applicant stated that the loss of preload in bolted connections of primary 

containment piping was inadvertently omitted from Table 3.3.1-3. The applicant further stated that 

it has revised the table to include the aging effect of loss of preload by an electronic communication 

dated June 20,2000. The staff finds the applicant's response acceptable and RAI 3.6-50 is closed. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the primary containment. 

Reactor Building 

The reactor building contains various components (e.g., anchors and bolts, blowout panels, panel 

joint seals and sealants, miscellaneous steel, reinforced concrete, and structural steel) fabricated 

from either carbon steel, galvanized steel, aluminum, stainless steel, elastomers, concrete, and 

masonry block exposed to an inside, submerged, and outside environment. The applicant evaluated 

the aging effects for these materials and environments in Sections C.2.6.1, C.2.6.3, C.2.6.6, and 

C.2.6.7 of the LRA and identified several aging effects. These include loss of material, loss of 

adhesion, material property changes and cracking of elastomers, and cracking of concrete and 

masonry block. 

For the reactor building, the applicant stated that carbon steel anchors and bolts are exposed to 

inside (sheltered) and outside environments. As is discussed in Sections C.1.2.8, C.1.2.9 and 

C.2.6.3 of the LRA, loss of material is identified by the applicant as an applicable aging effect. The 

applicant stated that carbon and galvanized miscellaneous steels, as well as structural steels made 

of carbon, galvanized, and stainless steel are exposed to inside (sheltered), outside and submerged 

environments. As discussed in Sections C.1.2.2, C.1.2.8, C.1.2.9 and C.2.6.3 of the LRA, loss of 

material is an applicable aging effect for these structural components. The applicant stated that 

panel joint seals and sealants made of elastomers (nonmetallic and inorganic) are exposed to inside

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(sheltered) and outside environments. As discussed in Sections C.1.2.8, C.1.2.9, and C.2.6.7 of 

the LRA, material property changes, cracking, and loss of adhesion are listed by the applicant as 

applicable aging effects. The applicant also stated that reinforced concrete structures and 

components serving functions including structural support, fire barrier, flood barrier, fission 

product/missile barriers, component shelter/protection, radiation shielding and non-safety-related 

structural support are made of concrete or masonry blocks and carbon steel reinforcement. These 

structures and components are exposed to an inside (sheltered) and an outside environment. As 

discussed in Sections C.1.2.8, C.1.2.9, and C.2.6.1 of the LRA, loss of material and cracking are 

applicable aging effects for these structural components. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the reactor building. 

Reactor Building Penetrations 

The applicant indicated that the reactor building penetrations are fabricated from carbon steel and 

galvanized steel that is exposed to the inside and outside environment and an embedded 

environment. The applicant identified loss of material as the aging effect in Table 3.3.1-7 of the LRA. 

The applicant evaluated the aging effects for these materials and environment in Section C.2.6.3 

of the LRA and identified several forms of corrosion that may result in loss of material (e.g., general 

corrosion, crevice corrosion, pitting and MIC). 

Table 3.3.1-7 indicates that the aging effects of reactor building (RB) penetrations are managed by 

the structural monitoring program (SMP) and the protective coating program. However, Section 

A.2.5 of the LRA does not specifically list reactor building penetrations as part of the SMP. In RAI 

3.6-39, the staff requested the applicant to clarify if the RB penetrations are covered under the SMP, 

or provide information as to where the aging effects of reactor building penetrations are covered. 

In response to this request, the applicant stated that reactor building penetrations are included in 

the SMP. The applicant further indicated that Section C.2.6.3 of the LRA, which discusses steel as 

a commodity group, also explicitly identifies T-54 reactor building penetrations as included in the 

commodity and SMP is listed among the AMPs applicable to the reactor building penetrations. The 

applicant's response resolves the staff concern and the issue is closed. 

In response to RAI 3.6-39 related to the aging effects for reactor building penetration seals and 

gaskets and their inclusion of leak-tightness characteristics, the applicant stated that the secondary 

containment (including reactor building penetrations) is not designed to be leak-tight. Rather, it has 

controlled leakage characteristics, and is maintained at a negative pressure relative to the outside, 

so that the air flow is into the building. These characteristics are confirmed periodically by 

secondary containment leakage tests. The applicant further stated that, in order to manage aging 

of the reactor building penetrations, aging effects associated with the penetrations are managed 

prior to such a gross determination of degradation. The relevant AMRs have identified these "first 

line" aging effects requiring management in the renewal term. Reactor building penetrations are 

discussed in LRA Tables 3.2.4-18, 3.3.1-7 (described as structural steel), and 3.4.1-1 (as Nelson 

frames). AMRs are presented in LRA Sections C.2.3.4.1 (for fire penetration seals), C.2.6.3 (for 

reactor building penetrations structural steel), and C.2.5.2 (for Nelson frames). The AMR for the 

neoprene rubber inserts in Nelson Frames determined that there were no aging effects requiring 

management.

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The response to RAI 3.6-39 indicates that to serve as a fission product barrier, the reactor building 

penetrations should have an AMP related to the reactor building penetrations' leak-tightness. A 

review of the Plant Hatch Technical Specifications (TS Section B 3.6.4.1) indicates that the limiting 

condition for operation, its applicability, and action and surveillance requirements for secondary containment provide adequate assurance that the leak-tightness characteristics of these 

penetrations will be monitored and maintained periodically during the period of extended operation. By letter dated January 5, 2001, the staff asked the applicant to provide justification as to why the 

TS requirements should not be included as part of the total aging management program for reactor 

building penetrations. 

By letter dated January 31, 2001, the applicant stated that numerous penetrations are considered 

to be secondary containment penetrations. The principal types of penetrations are mechanical (for 

piping), electrical (for conduits and cable trays) and HVAC (for HVAC ducts). Mechanical 

penetrations are of all-welded construction, and have no seals or gaskets (see LRA Table 3.3.1-7). 

Also, there are no seals and gaskets in HVAC ducts credited for maintaining secondary containment. Fire penetration seals located in fire barrier penetrations are managed by fire 

protection activities as shown in LRA Table 3.2.4-18. The penetrations for electrical conduits and 

cable trays consist of Nelson frames. There are no aging effects for the polymers and the steel of 

the Nelson Frames per LRA Table 3.4.1-1. 

Moreover, the applicant states that any contribution of reactor building penetrations to secondary containment in-leakage is thus, extremely small. In addition, even if a mechanism were postulated that would result in degradation of penetrations leading to secondary containment in-leakage, the 

Plant Hatch Technical Specification Surveillance Requirements for secondary containment do not 

provide a useful tool for license renewal due to the relative magnitude of postulated reactor building 

penetration in-leakage as compared with other, dominant pathways. 

Additionally, the applicant states that other secondary containment in-leakage pathways include 

reactor building doors and caulked joints associated with the reactor building walls. Reactor building 

doors are not part of the reactor building penetrations. 

By letter dated January 31,2001, the applicant referenced a telephone conference on January 26, 

2001, in which the overall drawdown characteristics of the reactor building were discussed. The 

applicant pointed out that outside and apart from license renewal, as part of the numerous 

performance-based tests that are routinely performed by Plant Hatch as part of the Technical 

Specifications, a periodic test is performed which identifies the drawdown characteristics of the 

secondary containment. However, for license renewal, the applicant observes that aging 

degradation of each in-leakage pathway contributor is managed by programs credited in the LRA 

to maintain intended function. The various applicable sections of the LRA are noted in the above 

paragraphs. 

The response above did not address the staff's concern about managing the controlled leakage 

characteristics of the secondary containment system (including its penetrations). In Section 2.4.7 

of the LRA, the intended function of the reactor building penetrations (T54-01) is "maintain 

secondary containment leakage rates within design limits." In TS Section B 3.6.4.1, under "LCO," 

it is stated "For the secondary containment to be OPERABLE, it must have adequate leak tightness 

to ensure that the required (0.2 inch) vacuum can be established and maintained." Numerous 

penetrations associated with the reactor building could contribute towards violating the design limits 

established for secondary containment (i.e., reactor building). Thus, the applicant should have an

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AMP to demonstrate that the overall effect of numerous degradations has not violated the leakage 

characteristics of the reactor building. This was identified as Open Item 3.6.3.1-1. 

By letter dated June 5, 2001, the applicant responded to this open item. The applicant stated that 

it had revised the structural monitoring program to include the provisions of Surveillance 

Requirement 3.6.4.1.4 of the Unit 1 and 2 technical specifications. The draw-down test performed 

pursuant to the surveillance requirement will be credited for aging management as an additional 

detection measure that is capable of detecting gross changes in flow that may be indicative of age

related degradation. The applicant also revised the FSAR Supplement to reflect this change. 

On the basis of the applicant's inclusion of the secondary containment draw-down test as per the 

surveillance requirements of the TS, as a means to detect gross age-related degradation of 

secondary containment, the staff concludes that the applicant has an adequate AMP to demonstrate 

that the overall effect of numerous degradations will not violate the leakage characteristics of the 

reactor building. Open Item 3.6.3.1-1 is closed. 

In response to RAI 3.6-40, related to the benchmarking of the reactor building penetration coating, 

the applicant stated, "A baseline inspection program will be done for the penetrations prior to the 

start of the renewal period. The periodicity of future inspections will be determined by a plant 

coating specialist based on the findings of the initial inspection." The staff finds this response 

adequate and RAI 3.6-40 is closed. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups associated with the reactor building penetrations. 

Turbine Building 

The applicant stated that the turbine building has components that are fabricated from carbon steel 

and galvanized steel (e.g., anchors and bolts, miscellaneous steel, reinforced concrete, and 

structural steel) that are exposed to the inside, outside, wetting-other-than-humidity, buried, and 

embedded environments. The applicant identified loss of material as the aging effect in Table 3.3.1 

8 of the LRA. The applicant evaluated the aging effects for these materials and environment in 

Sections C.2.6.1 and C.2.6.3 of the LRA and identified several forms of corrosion that may result 

in loss of material (e.g., general corrosion, crevice corrosion, pitting and MIC for steel and corrosion 

of embedded steel in the concrete). The applicant identified cracking as an aging effect for concrete 

and masonry block walls in Section C.2.6.1, but did not identify cracking as an aging effect in Table 

3.3.1-8. In RAI 3.6-52, the staff requested The applicant to clarify this discrepancy. In its January 

31, 2001 response to the request, the applicant stated that there are masonry block walls in the 

turbine building, but none of these are in close proximity to, or have attachments from, safety related 

piping or equipment, and hence do not perform an intended function and are not in scope. 

Additionally, during a December 2000 meeting, the staff requested that the applicant address 

whether any block walls within the scope of A-46 evaluations are in the turbine buildings. The 

applicant responded that there were no A-46 block walls in the turbine buildings. The above 

responses resolve the staff concerns and the issues are judged as closed. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the turbine building.

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Yard Structures 

The yard structures contain various components (e.g., anchors and bolts, cover plates for pull 

boxes, miscellaneous steel, reinforced concrete, and structural steel) fabricated from carbon steel, 

galvanized steel, aluminum and concrete exposed to inside and outside environments. The 

applicant stated that the aging effects for all of these material and environment combinations is loss 

of material. 

On the basis of the above discussion, the staff finds that the applicant has identified all applicable 

aging effects for the commodity groups in the yard structures. 

3.6.3.2 Aging Management Programs 

Once the set of aging effects requiring management was identified for a particular commodity group, 

a list of aging management programs credited for managing aging of structures or components 

within the commodity group was produced. This list was compiled by examining the aspects of 

current programs in plant procedures and program documents. The staff concurs with this approach 

to identifying applicable aging management programs. 

A discussion of the aging management programs credited for managing the aging effects for 

commodity groups in structures and structural components follows. 

Conduits. Raceways, and Trays 

To manage corrosion-induced aging effects for carbon steel components and galvanized steel 

components that show signs of rust, exposed to an inside containment environment in the conduits, 

raceways, and trays, the applicant relies on the following aging management programs: 

* structural monitoring program 

* protective coatings program 

The SMP provides condition monitoring and appraisal of certain structures, including the conduits, 

raceways, and trays. The structural monitoring program is discussed in detail in Section 3.1.22 of 

this SER. The protective coatings program provides a means of preventing or minimizing aging 

effects that would otherwise result from contact of the base metal with the associated environment. 

It is a mitigation and condition monitoring program designed to provide base metal aging 

management through application, maintenance, and inspection of protective coatings on selected 

components and structures. The staff's detailed review of these programs may be found in Sections 

3.1.20 and 3.1.22 of this SER. 

In Table 3.3.1-2 of the LRA, the applicant identified loss of material due to corrosion of carbon steel 

and galvanized steel as a plausible aging effect. The applicant also discussed aging effects for the 

loss of materials in Section C.2.6.4 of the LRA and took credit for the SMP and the protective 

coatings program as applicable AMPs. However, the applicant did not identify self-loosening of 

bolted connections due to vibration as an aging effect. The staff believes that expansion and 

undercut anchors in concrete may become loose due to local degradation of the surrounding 

concrete as a result of vibratory loads. RAI 3.6-9 requested the applicant to provide the technical 

justification for not identifying loss of preload due to the effects of vibration on concrete surrounding 

expansion and undercut anchors.

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In its letter dated October 10, 2000, the applicant stated that structural supports, including hangers 

and cable trays, are passive structural components that are rarely subjected to high displacement 

vibration loading, or high stress vibration loading. Cable trays are isolated from rotating equipment 

or active equipment by the use of flexible conduits or cables. No gaskets are used in structural 

connections. For structural joints installed with proper torque, the initial loss of preload is limited, and 

sufficient preload remains to assure joint integrity. The applicant further stated that structural bolts 

and anchors at Plant Hatch were installed and inspected per vendor recommendations and in 

accordance with plant procedures. Per Electric Power Research Institute (EPRI) Bolting Procedures 

Reference Manual, NP5067, Vol. 1, "A Reference Manual for Nuclear Power Plant Maintenance 

Personnel, Large Bolt Manual," loss of preload over an extended period requires elevated 

temperatures, stress levels in proximity to the material yield stress, and cyclic loading. Structural 

supports, hangers, bolts and anchors are not subject to high temperatures, high displacement 

vibration loading, or high stress vibration loading. The applicant also indicated that a review of the 

plant operating history for the last 5 years did not identify any deficiencies resulting from loss of 

anchor or bolt preload and loss of preload in structural joints has not been identified as a widespread 

industry problem. Therefore, the Plant Hatch aging management review concluded that loss of 

preload due to vibratory loads is not an aging effect requiring management for bolts or anchors used 

by structural supports, hangers or cable trays. 

Additionally, the applicant stated that Class 1 seismic structures at Plant Hatch are designed in 

accordance with American Concrete Institute (ACI) 318-63, "Building Code Requirements for 

Reinforced Concrete." EPRI Report TR-1 03842, "Class 1 Structures Industry Report," Revision 1, 

dated July 1994, evaluated the effect of cyclic loads on concrete structures. The report concluded 

that cycle loading (fatigue) would not cause significant degradation of concrete structures designed in accordance with ACI 318. The design stress level is limited to less than 50 percent of the static 

strength, and the structures can resist extremely high cycles of loading in the low amplitude, low 

stress range, and actual stresses from any high cycle loading on concrete structures, such as those 

from machine vibration, are a small portion of the combined stresses resulting from static and 

dynamic loads. A review of the plant operating history for the last 5 years did not identify any 

deficiencies resulting from loss of anchor bolt, expansion bolt, or undercut anchor preload. 

Therefore, the aging management review concluded that local degradation of the concrete 

surrounding anchors, because of vibratory loads, is not an aging effect requiring management, and 

would not cause loss of preload for support anchors. 

The staff reviewed the above justification provided by the applicant, including Plant Hatch's past 5 

years of operating experience, and concurs with the above findings. RAI 3.6-9 is closed. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups associated with conduits, raceways, 

and trays will be adequately managed by the above listed AMPs. 

Control Building 

To manage corrosion-induced effects of aging for components fabricated from carbon steel, 

galvanized steel, aluminum, and concrete exposed to inside, embedded, and outside environments 

in the control building, the applicant relies on the following aging management programs: 

* protective coatings program 

• structural monitoring program

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Because some of these components may be susceptible to loss of material, the protective coatings 

program provides for periodic inspection of component external surfaces. This program will also 

provide for proper corrective actions (such as replacement or coating of exposed surfaces) to 

prevent significant degradation of these components due to loss of material. The structural 

monitoring program provides condition monitoring and appraisal of certain structures, including the 

control building. The staff's detailed review of these programs may be found in Sections 3.1.20 and 

3.1.22 of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the control building will be 

adequately managed by the above listed AMPs. 

Drvwell Penetrations 

Aging management programs determined by the applicant to manage aging effects requiring 

management for drywell penetrations are: 

* protective coatings program 

* inservice inspection program (ISI Program) 

• primary containment leakage rate testing program 

The protective coatings program provides for periodic inspection of structural component surfaces, 

including fasteners and associated coatings. This program also provides for proper corrective 

actions to prevent or repair significant degradation of structural materials and fasteners due to 

corrosion. 

The ISI Program provides for visual inspections of internal and external surfaces and fasteners, 

thereby providing assurance that the containment shell and internal structures have not degraded 

due to corrosion and/or cracking. Inspections are conducted in accordance with ASME Section Xl 

Table IWE-2500-1. 

Primary containment leak rate testing procedures provide for the scheduled periodic testing of the 

primary containment pressure boundary and pressure boundary penetrations to detect degradation 

of the pressure boundary. Inspections are conducted in accordance with 10 CFR Part 50, Appendix 

J. 

The staff's detailed review of these programs may be found in Sections 3.1.9, 3.1.14, and 3.1.20 

of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups associated with the drywell 

penetrations will be adequately managed by the above listed AMPs. 

EDG Building 

To manage corrosion induced effects of aging for components fabricated from carbon steel, 

galvanized steel, and concrete exposed to inside and outside environments in the EDG building, the 

applicant identified the following aging management programs:

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* protective coatings program 

* structural monitoring program 

Because some of these components may be susceptible to loss of material, the protective coatings 

program provides for periodic inspection of component external surfaces. This program will also 

provide for proper corrective actions (such as replacement or coating of exposed surfaces) to 

prevent significant degradation of these components due to loss of material. The structural 

monitoring program provides condition monitoring and appraisal of certain structures, including the 

EDG Building. The staff's detailed review of these programs may be found in Sections 3.1.20 and 

3.1.22 of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the EDG building will be 

adequately managed by the above listed AMPs. 

Fuel Storage 

To manage corrosion-induced aging effects for carbon steel, stainless steel, and concrete 

components exposed to an inside environment in the fuel storage areas the applicant relies on: 

* structural monitoring program 

* protective coatings program 

The structural monitoring program provides condition monitoring and appraisal of certain structures, including those associated with fuel storage. The protective coatings program provides a means 

of preventing or minimizing aging effects that would otherwise result from contact of the base metal 

with the associated environment. It is a mitigation and condition monitoring program designed to 

provide base metal aging management through application, maintenance and inspection of 

protective coatings on selected components and structures. The staff's detailed review of these 

programs may be found in Sections 3.1.20 and 3.1.22 of this SER. 

To manage the corrosion-induced aging effects for stainless steel and aluminum components exposed to a demineralized water environment, the applicant relies on the fuel pool chemistry control program. This program is intended to mitigate aging in the fuel pool liner and associated 

components by controlling fluid purity and composition. The related activities are discussed in detail 

in Section 3.1.5 of the SER. 

Table 3.3.1-4 of the LRA identifies loss of material as an aging effect for the aluminum restraints 

in the spent fuel pool (SFP) demineralized water. The applicant discussed the loss of material due 

to galvanic corrosion, crevice corrosion, pitting, and MIC in LRA Section C.2.6.6 and took credit for 

fuel pool chemistry control as an AMP; however, Table 3.3.1-4 and Section C.2.6.6 indicate that the 

aluminum racks do not require an AMP. RAI 3.6-20 asked the applicant to explain the discrepancy. The applicant stated that the aluminum racks, described as storage racks in LRA Table 3.3.1-4, are 

located in the new fuel storage vault. These aluminum racks are exposed to air only. There are no 

aging effects requiring management for aluminum exposed to air. A revised six-column table to re

label the new fuel racks is included in the response to RAI 3.6-24. The staff finds this justification 

adequate and acceptable. Thus, RAI 3.6-20 is closed.

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Section C.2.6.5 of the LRA stated that the applicant regularly checks SFP chemistry control activities 

under the fuel pool chemistry control program. RAI 3.6-21 requested the applicant to explain how 

this program manages cracking of stainless steel components (e.g., liner plate). To determine 

whether these inspections help to ensure that cracking does not occur, the staff needs to know 

whether these inspections check for cracking, the techniques used, and how many times such 

inspections of the spent fuel system stainless steel components have been performed to date. 

Additionally, the staff noted that LRA Table 3.3.1-4 does not list cracking of spent fuel pool stainless 

steel liners as an aging effect under the structural steel category. Therefore, RAI 3.6-31 asked the 

applicant to justify its exclusion of this aging effect from Table 3.3.1-4, or provide a plant-specific 

discussion of the aging effect and the appropriate AMP for managing the cracking of spent fuel pool 

stainless steel liners. The applicant stated that the water in the pool is demineralized water. 

Operating temperature data in the spent fuel pools was reviewed by the applicant, and the maximum 

recorded pool temperature did not exceed 115 OF. This temperature is less than the 1400 F 

threshold established in Section C.1.2.2.2 of the LRA for SCC, regardless of the dissolved oxygen 

content. Therefore, SCC for the spent fuel pool stainless steel liners and other stainless steel 

components is not an aging effect requiring management. The staff finds the applicant's justif ication 

acceptable and RAIs 3.6-21 and 3.6-31 are closed. The staff reviewed the fuel pool chemistry 

control program in Section 3.1.5 of this SER. 

The fuel storage system contains components fabricated from carbon steel, stainless steel, 

aluminum, and concrete exposed to an inside environment. Table 3.3.1-4 of the LRA does not 

clearly identify the environments for which the listed aging effects are managed by the 

corresponding AMPs. RAI 3.6-23 requested the applicant to clarify the environments for which the 

listed aging effect occurs and the AMP that manages the aging effect. Furthermore, according to 

Table 3.3.1-4, loss of material is an applicable aging effect for stainless steel components in an 

embedded environment. However, based on the information in the same table, there is no applicable AMP or activity identified. RAI 3.6-24 asked the applicant to specify the applicable AMP to manage 

loss of material for stainless steel components in an embedded environment or provide the basis 

for concluding that an AMP is not required. In its response, the applicant revised Table 3.3.1-4 to 

achieve needed clarity. The staff finds the applicant's table revision reasonable and RAIs 3.6-23 

and 3.6-24 are considered closed. 

Bolts, which are used in safety-related and non-safety-related structural support, are fuel storage 

system components in the anchors and bolts (C.2.6.5) commodity group, and these bolts are 

susceptible to a loss of pre-load (due to embedment, gasket creep, thermal effects, and self

loosening). RAIs 3.6-25 and 3.6-28 requested that the applicant provide the basis for not including 

this aging effect. The applicant resolved this RAI based on justifications provided in its response 

to staff RAI 3.6-9 included in its letter to the staff dated October 10, 2000 (see discussion under 

Conduits, Raceways, and Trays, above). RAIs 3.6-25 and 3.6-28 are closed. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups associated with fuel storage will be 

adequately managed by the above listed AMPs. 

Intake Structure 

To manage corrosion induced effects of aging for components fabricated from carbon steel, 

galvanized steel, and concrete exposed to the inside and outside environments in the intake 

structure, the applicant designated the following aging management programs:

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* protective coatings program 

* structural monitoring program 

Because some of these components may be susceptible to loss of material, the protective coatings 

program provides for periodic inspection of component external surfaces. This program will also 

provide for proper corrective actions to prevent significant degradation of these components due 

to loss of material (such as replacement or coating of exposed surfaces). The structural monitoring 

program provides condition monitoring and appraisal of certain structures, including the intake 

structure. The staff's detailed review of these programs may be found in Sections 3.1.20 and 3.1.22 

of this SER. 

RAI 3.6-34 asked if Plant Hatch has any earthen embankments as part of its ultimate heat sink 

system or intake structure and asked the applicant to discuss, as applicable, the aging effects of 

these structures due to loss of material from erosion and cracking due to settlement. The applicant 

stated that there is no earthen embankment included as part of the Plant Hatch ultimate heat sink. 

The river intake structure is located on the south bank of the Altamaha River. It is flanked by a 

circular steel sheet pile cell on each side near the front of the structure. The main river channel, 

where the water speeds are greatest, is located closer to the north bank of the river. Erosion has 

not been a problem on the south bank of the river near the intake structure. Settlement of the intake 

structure has been monitored since construction. Settlement has been within predicted values, and 

has leveled off. Therefore, erosion of the soil at the intake structure, and cracking due to settlement 

or differential settlement are not considered to be aging effects requiring management for the intake 

structure. This response is sufficient to resolve RAI 3.6-34. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the intake structure will be 

adequately managed by the above listed AMPs. 

Main Stack 

To manage corrosion-induced effects of aging for components fabricated from carbon steel, 

galvanized steel, and concrete exposed to inside and outside environments in the main stack, the 

applicant relies on the following aging management programs: 

* protective coatings program 

* structural monitoring program 

Because some of these components may be susceptible to loss of material, the protective coatings 

program provides for periodic inspection of component external surfaces. This program will also 

provide for proper corrective actions (such as replacement or coating of exposed surfaces) to 

prevent significant degradation of these components due to loss of material. The structural 

monitoring program provides condition monitoring and appraisal of certain structures, including the 

main stack. The staff's detailed review of these programs may be found in Sections 3.1.20 and 

3.1.22 of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the main stack will be adequately 

managed by the above listed AMPs.

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Piping Specialties

To manage aging effects for hangers and supports for ASME Class I piping, and hangers and 

supports for non-ASME Class I piping, tubing, and ducts, made of carbon, galvanized, and stainless 

steels, that are exposed to containment atmosphere, inside (sheltered), outside, and submerged 

environments associated with piping specialties, the applicant identified the following aging 

management programs for managing the aging effects: 

* protective coatings program 

* structural monitoring program 

The applicant cited the above programs to manage loss of material for the structural components 

exposed to the described environments. The staff has verified that these two programs are included 

in Section C.2.6.4 of the LRA as applicable aging management programs. The staff's detailed 

review of these programs may be found in Sections 3.1.20 and 3.1.22 of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups associated with piping specialties will 

be adequately managed by the above listed AMPs. 

Primary Containment 

AMPs determined by the applicant to manage aging effects requiring management in the primary 

containment are: 

* protective coatings program 

* ISI program 

• suppression pool chemistry control 

* primary containment leak rate testing program 

• demineralized water and condensate storage tank chemistry control 

* treated water systems piping inspections 

* gas systems component inspections 

* passive component inspection activities 

0 structural monitoring program 

* component cyclic or transient limit program 

The protective coatings program provides for periodic inspection of structural component surfaces, 

including fasteners and associated service level I coatings (service level I coatings are used in areas 

inside the reactor containment where coating failure could adversely affect the operation of post accident fluid systems and thereby impair safe shutdown). This program also provides for proper 

corrective actions to prevent or repair significant degradation of structural materials and fasteners 

due to corrosion. 

The ISI Program provides for visual inspection of internal and external surfaces and fasteners, 

thereby providing assurance that the containment shell and internal structures have not degraded due to corrosion and/or cracking. Inspections are conducted in accordance with ASME Section XI 

Table IWE-2500-1.

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Suppression pool chemistry control limits detrimental impurities and conductivity within the 

suppression pool and thereby mitigates aging. Suppression pool chemistry control implements the 

EPRI guidance on BWR water chemistry for auxiliary systems. 

Primary containment leak rate testing procedures provide for the scheduled periodic testing of the 

primary containment pressure boundary and pressure boundary penetrations to detect degradation 

of the pressure boundary. Inspections and testing are conducted in accordance with 10 CFR Part 

50, Appendix J. 

Demineralized water and condensate storage tank chemistry control serve to mitigate loss of 

material due to pitting, crevice corrosion, or MIC by limiting concentrations of detrimental impurities 

and conductivity. Demineralized water quality is monitored on a weekly basis and corrective actions 

are taken in the event that any limits are exceeded. 

Demineralized water and condensate storage tank chemistry control implement EPRI BWR water 

chemistry guidelines. 

The treated water systems piping inspections serve to validate the adequacy of demineralized water 

and condensate storage tank chemistry control in mitigating loss of material within stainless steels 

by performing appropriate examinations of a sample population of the susceptible locations. 

Aging effects due to corrosion will be detected for these components through gas systems 

component inspections. This activity will involve appropriate inspections of a representative sample 

of the most likely degradation locations. 

The passive component inspection activities serve to validate the adequacy of the drywell floor and 

equipment sump discharge piping sections to perform a primary containment function by performing 

inspections, similar to VT-1, of component internal surfaces any time an applicable component is 

opened for periodic maintenance or repair. This information is evaluated and trended to provide 

adequate assurance that any significant aging trends are identified and corrected. 

The SMP inspection process assesses the ongoing overall conditions of structures and identifies 

any ongoing degradation. The SMP will inspect the concrete commodities for loss of material, 

cracking, and spalling. The SMP will also visually inspect masonry block walls for cracking. 

Management of cracking due to fatigue of the torus is implemented via a component cyclic or 

transient limit program. The component cyclic or transient limit program is designed to track cyclic and transient occurrences, including the limiting location for the torus, to ensure that reactor coolant 

pressure boundary components will remain within the ASME Code Section III limits. 

The staff's detailed review of these programs may be found in Sections 3.1.6, 3.1.7, 3.1.9, 3.1.12, 

3.1.14, 3.1.20, 3.1.22, 3.1.24, 3.1.25, and 3.1.27 of this SER. 

In response to RAI 3.6-41 related to torus corrosion, the applicant provided a description of torus 

degradation found in both Plant Hatch units. However, the applicant emphasized that, in spite of 

the degradation, the actual shell thicknesses are well above the required minimum shell 

thicknesses. The applicant stated that it plans to continue to perform desludging, visual 

examination, and spot coating repairs periodically, based on the history of past inspection. The staff 

believed that operating experience at Plant Hatch and other industry operating experience related

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to torus corrosion indicated a need for a program to manage torus corrosion during the period of 

extended operation. In Open Item 3.6.3.2-1(a), the staff requested the applicant to provide justification as to why this program should not be a separate program in the LRA. 

By letter dated January 31, 2001, the applicant provided a drawing showing a section through the 

torus and associated penetrations. The drawing also identified the AMPs associated with the 

penetrations above and below the water line. For torus penetrations above the water line, the 

applicant takes credit for implementing the inservice inspection program, the primary containment 

leakage testing program, the protective coating program, and the component cyclic or transient limit 

program. Additionally, for torus penetrations below the water line and in the splash zone of the torus 

shell, the applicant takes credit for implementing the suppression pool chemistry control program, the torus submerged component inspection program, and the protective coatings program. Moreover, the applicant states, "a review of torus inspection reports indicates that degradation of 

the torus coating, in the form of thinned coatings, and some pitting corrosion in the torus immersion 

area is general in nature and occurs primarily on the torus shell. No specific corrosion has been 

noted around penetrations welded to the shell. Corrosion is generally more evident near the torus 

waterline and at or near the bottom of the torus where sludge or small debris collects." The 

applicant also provides a listing of penetrations in the torus of each unit. This information 

adequately responds to the staff's concern regarding the AMPs for torus degradation, and closes 

Open Item 3.6.3.2-1(a). 

Section C.2.6.2 of the LRA stated that the ISI program provides for visual inspection of the internal 

and external surfaces and fasteners, thereby providing assurance that the containment shell and internal structures have not degraded due to corrosion and/or cracking. 10 CFR 50.55a endorsed 

the ASME Section Xl, Subsection IWE Code with the condition that 10 CFR 50.55a(b)(2)(ix) provisions be complied with. The LRA is not clear regarding this requirement. RAI 3.6-11 asked the 

applicant to confirm that both the scope and the detail of the inspection implemented in accordance 

with ASME Section Xl Table IWE-2500-1 also comply with the requirements for 10 CFR 

50.55a(b)(2)(ix). The RAI also asked the applicant to discuss how it is implementing a staff position that applicants for license renewal need to evaluate, on a case-by-case basis, the acceptability of 

inaccessible areas even though conditions in accessible areas may not indicate the presence of 

degradation in inaccessible areas. The applicant stated that it complies with the inspection requirements of 10CFR50.55a(b)(2)(ix) with one exception. Details of this exception, which is 

identified as Plant Hatch's relief request MC-9, are contained in the applicant's submittal to the NRC 

dated July 19, 2000. By letter dated October 4, 2000, the staff concluded that the proposed alternative will provide an acceptable level of quality and safety. The applicant further stated that 

Section C.2.6.2 of the LRA identifies any applicable aging effects for steel commodities for primary containment and internal structures. Aging effects determined to require management are based 

on the environment present for the commodity. Each commodity was evaluated for the maximum 

expected conditions, such as maximum neutron exposure, elevated temperature and high humidity. The applicant maintained that neutron exposure and elevated temperature do not exceed the 

threshold limits where degradation could occur. Other environmental conditions do not result in 

different aging effects for inaccessible areas than are applicable to accessible areas. Therefore, for inaccessible areas, no aging effect has been identified that is different from those resulting from 

the environmental conditions in the accessible areas. On the basis of the review of the above 

information, the staff concludes that the applicant complies with the requirements for 10 CFR 

50.55a(b)(2)(ix).

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However, the applicant did not fully answer the second part of the question related to 

implementation of the staff position regarding how applicants for license renewal will evaluate the 

acceptability of inaccessible areas even though conditions in accessible areas may not indicate the 

presence of degradation in inaccessible areas. In a letter dated January 5, 2001, the staff 

requested the applicant to provide additional information regarding the staff position. 

In its response of January 31, 2001, the applicant stated that it's programmatic activities related to 

the above item are consistent with the draft GALL. In particular, the Plant Hatch inservice 

inspection program included requirements of the NRC Final Rule 10 CFR 50.55a [including 10 CFR 

50.55a(b)(2)(ix)] along with the ASME Section Xl Subsection IWE for examination of the Class MC 

components. The applicant further stated that at Plant Hatch, the designation "inaccessible areas" 

is limited to two specific areas: (a) Embedded containment shell and (b) containment basemat and 

buried external walls. Aging is an issue for the containment basemat and buried external walls if 

ground water or soil aggressive chemical limits per NUREG 1611, "Aging Management of Nuclear 

Power Plant Containments for License Renewal, are exceeded. The applicant stated that the 

groundwater and soil parameter at Plant Hatch are within the acceptable limits (pH>5.5, 

chloride<550 ppm, & sulfate<1500 ppm) specified in NUREG 1611. The soil chemistry at Plant 

Hatch should be essentially the same as it was before and after the plant was constructed. The soil 

in the vicinity of the seismic category I structures is compacted backfill with non-aggressive chemical 

characteristics. The soil in the remainder of the plant site area is generally undisturbed soil. Soil 

chemistry generally reflects the same chemical composition as the ground water and surface water 

to which it is exposed. The water chemistry in the Altamaha River is very nearly the same as it was 

when the plant was constructed. The chemistry of the soil in the vicinity of the plant buildings should 

also be very nearly the same as it was when the plant was constructed. Thus, the applicant 

concluded that ground water is not aggressive, and no special aging management program is 

required. However, the SMP document has been revised to include the following directrive: 

"Additional emphasis will be placed on the importance of inspecting and documenting the condition 

of normally inaccessible (underground or embedded) structures, whenever the inaccessible 

structural components are exposed or uncovered." 

The applicant also concluded that aging is not a concern for the embedded containment shell, since 

plant Hatch's concrete quality in contact with the embedded containment liner meets or exceeds the 

requirements of ACI 318 and ACI 201.2R; the concrete is subjected to periodic inspection to assure 

that it is free of penetrating cracks; the moisture barrier is subject to IWE Category E-D 

Examination; repair or replacement is performed based on inspection results, and boric acid is not 

used and other chemical spills or water ponding are not common in the containment. 

The staff concludes that the above discussion fully addresses the staff position and the issue is 

closed. 

Section A.1.9.4 of the LRA stated that loss of material, cracking, loss of pre-load, and loss of 

fracture toughness are the aging effects monitored by the Plant Hatch ISI Program. RAI 3.6-12 

requested that the applicant provide a discussion of past experience with respect to managing and 

monitoring these aging effects, including experience with the embedded shell and the sand pocket 

regions of the primary containment and the loss of pre-load for metal fasteners. The applicant 

stated that a general discussion of operating experience related to the ISI program is provided in 

Section B.1.9 of the LRA. The applicant further stated that visual examinations of the mastic seal 

between the concrete floor at elevation 114'-0" and the drywell shell inside the drywell are performed 

at every outage. The condition of the seal is carefully inspected to detect any cuts, tears, or

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observed degradation of the flexible covering over the seal. The mastic seal was replaced on Unit 

1 in the fall, 1994 refueling outage. Minor, localized surface pitting was detected but was not 

significant. The area was cleaned and recoated prior to installation of the new seal. The mastic 

seal was replaced on Unit 2 in the fall, 1995 refueling outage. There has been no evidence of 

significant moisture intrusion between the mastic seal and drywell shell or significant deterioration 

of the shell on either unit. Periodic inspections of the sand cushion and associated air gap drains 

have confirmed that there was no moisture present or any evidence of prior leakage into the area. 

The applicant further stated that inspections in the accessible area of the sand cushions have not 

shown any moisture buildup or corrosion. Visual inspections included associated bolted connections 

to confirm connection integrity, and no looseness of bolts or nuts has been detected that could be 

attributed to loss of preload. 

The staff finds the response to RAI 3.6-12 adequate and acceptable. RAI 3.6-12 is closed. 

Table 3.3.1-3 of the LRA does not list attachment welds to the containment shell elements as an 

item requiring aging management. Welds between integral attachments to the primary containment 

are included within the scope of ASME Section Xl, Subsection IWE. RAI 3.6-13 asked the applicant 

to discuss how aging effects of the attachment welds will be managed. The applicant indicated that 

attachment welds to the primary containment shell elements were considered to be a part of the 

component welded to the shell or the shell itself. The intended function does include pressure 

boundary and structural support. These intended functions are addressed in the structural steel 

component function column in Table 3.3.1-3 of the LRA. Therefore, welds were not singled out as 

a separate commodity or component and were not listed separately in Table 3.3.1-3. The applicant further indicated that the ISl program, described in Section B.1.9 of the LRA, complies with 

Subsection IWE of Section Xl of the ASME Code and that the ISI program is the aging management 

program that manages aging of attachment welds to the containment pressure boundary. This is 

discussed in Section C.2.6.2 and Table C.2.6.2-1 of the LRA. The staff finds this response 

adequate and acceptable. RAI 3.6-13 is resolved. 

Table 3.3.1-3 of the LRA did not provide any information regarding the aging management 

(including surveillance requirements) for gears, latches, and linkages of personnel hatches and 

penetrations. RAI 3.6-15 requested that the applicant identify where fretting and lockup of hinges, 

locks, and closure mechanisms for personnel hatches is discussed in the LRA, or provide a 

technical justification for not considering fretting and lockup as applicable aging effects for these 

components. The RAI also asked that the applicant provide a description of the AMP for the 

personnel hatches, consistent with the 10 elements in the SRP-LR, in sufficient detail to allow the 

staff to assess the adequacy of this program to manage the applicable aging effects. The applicant 

responded that locks and closure mechanisms are active components, and are not subject to an 

AMR. Therefore, fretting and lockup of hinges, locks, and closure mechanisms for personnel 

hatches and penetrations are not discussed in the LRA. However, aging management for personnel 

airlocks, hatches, equipment hatches, and penetrations are managed by the ISI program, protective 

coatings program, and primary leak rate testing program, as discussed in LRA Sections C.2.6.2, 

A.1.9, A.2.3, and A.1.14. This was identified as Open Item 3.6.3.2-1(b). 

The primary containment leakage testing program is described in Section 18.2.14 of the Plant Hatch 

FSAR Supplement. It states that the applicant has chosen to identify the performance-based 

requirements and criteria for pre-operational testing and subsequent periodic leakage rate testing. 

The program ensures that leakage through the primary containment, or through systems and 

components that penetrate the primary containment, does not exceed allowable leakage rates

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specified in the TS, and that the integrity of the containment structure is maintained during its 

service life. 

The staff notes that the applicant's approach conforms with the performance-based approach 

described in Section XI.S4 of the Generic Aging Lessons Learned (GALL) report that was reviewed 

and approved by the staff, and issued in July, 2001. As such, the staff concludes that aging 

management by the ISI program, protective coatings program, and primary leak rate testing 

program, for personnel airlocks, hatches, equipment hatches, and penetrations, is adequate to 

ensure that leakage through the primary containment, or through systems and components that 

penetrate the primary containment, does not exceed allowable leakage rates. Open Item 

3.6.3.2-1 (b) is closed. 

Table C.1.1-1 of the LRA shows expected measured temperatures at key plant locations. With 

respect to the primary containment, the table does not provide maximum temperatures within key 

containment locations. RAI 3.6-48 asked that the applicant provide maximum recorded or observed 

temperatures within the primary containment (both normal and abnormal temperatures) at the 

primary shield wall, reactor vessel supports, main steam line cubicle (or its equivalent) and the 

hottest regions of the SFP concrete wall locations, and as applicable, discuss the AMP for managing 

the aging effects of reinforced concrete components subject to a sustained high temperature 

environment (e.g., concrete temperature greater than 150 OF). The applicant provided the 

requested information in response to the RAI and summarized that general elevated air 

temperatures near the concrete structures do not exceed 150 OF on a sustained basis, except for 

the sacrificial shield wall surrounding the reactor vessel. The applicant also stated that local air 

temperatures are less than 200 OF, except for the upper elevations of the sacrificial shield wall, and 

the SMP will inspect the exposed and accessible concrete for loss of material, cracking and spalling. 

The applicant further indicated that its SMP inspection process should be able to assess the 

condition of the in-scope structures, and identify any ongoing degradation. 

The staff noted that Tables 3.3.1-3 through 3.3.1-5 and 3.3.1-8 through 3.3.1-13 of the LRA do not 

list cracking of equipment support concrete pads as an applicable aging effect requiring 

management. Staff experience with other LRAs indicates the frequent occurrence of such cracks 

around anchor bolt regions. RAI 3.6-49 requested that the applicant discuss the AMP for managing 

this aging effect or justify its exclusion from the tables listed above. The applicant stated that 

equipment support foundations, pads, and anchor bolts have been subjected to an AMR. Loss of 

material due to corrosion of embedded steel was identified as the plausible aging effect, and 

cracking and spalling were identified as the aging mechanisms (see Sections C.1.4.2 and C.2.6.1 

of the LRA). The SMP has been credited as the AMP, and Tables 3.3.1-3 through 3.3.1-5 and 3.3.1 

8 through 3.3.1-13 list loss of material as the aging effect requiring management. The applicant's 

responses to RAIs 3.6-48 and 3.6-49 are adequate to close the RAIs. 

The applicant identified several aging management programs to manage cracking for the primary 

containment system components. A complete discussion on the applicable aging management 

programs is provided in Section 3.1 of this SER. In Table 3.3.1-3 of the LRA, the applicant included 

anchors and bolts, structural steel, and miscellaneous steel in non safety-related structural supports. 

However, it is not clear whether the scope of the primary containment system discussed in Table 

3.3.1-3 of the LRA includes any spatially-related components and piping segments within the 

category of "Seismic II over I" (a non-seismic Category I system, structure, or component whose 

failure could cause loss of safety function of a seismic Category I system, structure, or component) 

piping. Through issuance of staff RAI 3.6-51, the applicant was requested to provide clarification.

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The applicant was also requested to clarify how the aging management programs for the non

safety-related piping segments and components have been addressed. Specifically, the applicant 

was requested to state whether the same aging management programs discussed in LRA Table 

3.3.1-3 also apply to those "Seismic II over I" piping components. 

The applicant responded to this RAI in its letter dated October 10, 2000. The applicant stated that 

the pipe supports for the seismic II over I piping systems are within the scope of license renewal and 

they are subjected to the same AMPs as the supports for safety-related piping systems. The 

applicant also stated that no AMPs are applied to out-of-scope piping segments supported by seismic II over I piping supports. In a telephone conversation on October 24, 2000, the applicant 

further clarified that within the context of the Plant Hatch CLB, the piping systems are postulated 

to fall in a seismic event if not seismically supported. Thus, as required for protection of safety

related piping, some non safety-related piping is seismically supported. Those supports are within 

the scope of license renewal, but the applicant stated that the seismic il over I piping segments are 

not within the scope of license renewal. The staff finds that the programs to manage aging for the 

pipe supports are acceptable. 

The staff did not agree with the applicant's scoping criteria for seismic II over I piping systems. The 

staff's position is that the seismic II over I piping segments, whose failure could prevent safety-related systems and structures from accomplishing their intended function should be within 

the scope of license renewal. Additional discussion of this issue is contained in Section 2.1.3.1 of 

this SER. 

A complete discussion of the applicable aging management programs may be found in Section 3.1 

of this SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the primary containment will be 

adequately managed by the above listed AMPs. 

Reactor Building 

Aging management programs cited bythe applicant to manage aging effects requiring management 

for the reactor building are: 

* protective coatings program 

• structural monitoring program 

To manage aging effects for carbon steel anchors and bolts exposed to inside (sheltered) and 

outside environments; and carbon and galvanized miscellaneous steels, and structural steels made 

of carbon, galvanized and stainless steel, which are exposed to inside (sheltered), outside, and 

submerged environments, the applicant identified the protective coatings program and the SMP as 

the applicable aging management programs. The protective coatings program also provides for 

proper corrective actions to prevent or repair significant degradation of structural materials and 

fasteners due to corrosion. The SMP inspection process assesses the overall conditions of the 

listed structures, and identifies any degradation. The SMP will inspect the concrete commodities 

for loss of material, cracking, and spalling. The SMP will also visually inspect masonry block walls 

for cracking.

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To manage aging effects for panel joint seals and sealants made of elastomers (nonmetallic and 

inorganic), which are exposed to an inside (sheltered) or outside environment, the applicant 

identified the protective coatings program and the SMP as the applicable aging management 

programs. 

To manage aging effects for concrete, masonry block, and carbon steel, which are exposed to an 

inside (sheltered) or outside environment, the applicant again identified the protective coatings 

program and the SMP as the applicable aging management programs. 

The staff's detailed review of these programs may be found in Sections 3.1.20, and 3.1.22 of this 

SER. 

The applicant cited the above programs to manage loss of material for the structural components 

exposed to the described environments. The staff has verified that the protective coatings program 

and SMP are included in Sections C.2.6.1 and C.2.6.3 of the LRA as applicable aging management 

programs. However, the staff noted a discrepancy between the information provided in Table 3.3.1 

5 and Section C.2.6.7 of the LRA. Table 3.3.1-5 lists the protective coatings program and structural 

monitoring program as the aging management programs for panel joint seals and sealants, 

however, Section C.2.6.7 of the application does not list protective coatings program as the aging 

management program for the components. In its submittal of October 10, 2000, responding to the 

staff's RAI 3.6-27, the applicant stated that Table 3.3.1-5 should not have credited the protective 

coatings program as an aging management program for the panel joint seals and sealants. The 

applicant stated that the SMP manages the aging of the panel joint seals and sealants. This is 

acceptable to the staff. 

Tables 3.3.1-3 through 3.3.1-5 and Tables 3.3.1-8 through 3.3.1-13 of the LRA do not list 

prestressed concrete structural components. RAI 3.6-30 asked the applicant to confirm that Plant 

Hatch has no prestressed concrete structural elements in its structures that are subject to an AMR. 

Otherwise, list the prestressed concrete elements subject to an AMR and discuss applicable AMPs 

for managing their aging effects. The applicant stated that the only prestressed elements in the 

plant are precast concrete wall panels on the outside of the reactor building, turbine building, and 

control building. The panels on the outside of the turbine building and control building are for 

architectural purposes. The precast concrete wall panels around the fuel-handling area of the 

refueling floor of the reactor building above elevation 228 ft.-0 in. are provided to protect the 

refueling floor from the outside environment. The panels outside the reactor building have concrete 

and embedded steel, which are listed in the tables mentioned in the RAI. The SMP is the AMP 

applicable to the precast panels. This clarification closes RAI 3.6-30. 

The tables in Section 3.3.1 of the LRA do not list masonry walls as structural components requiring 

aging management review, although Section C.1.4.2 of the LRA identifies cracking of masonry block 

walls as an applicable aging effect for block walls within the reactor building, control building, and 

main stack. RAI 3.6-47 asked the applicant to discuss in detail its intent to manage the aging 

effects of these masonry walls and describe how the AMP for periodic inspection and surveillance 

of these masonry walls incorporates the insights provided in NRC IN 87-65, "Lessons Learned from 

Regional Inspection of Applicant Actions in Response to IE Bulletin 80-11 ." The applicant stated 

that NRC IE Bulletin 80-11 "Masonry Wall Design," indicated that, in many instances, masonry block 

walls had inadequate structural strength to resist pipe support, equipment, and seismic loads. This 

bulletin required (1) identification of masonry walls, which are in close proximity to, or have 

attachments from, safety-related piping or equipment, and (2) a re-evaluation of the design

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adequacy and construction practices. According to the IE bulletin, the masonry block wall problems resulted primarily from design and construction deficiencies, rather than from potential long-term aging degradation mechanisms. In responding to the bulletin, the applicant evaluated the as-built 

conditions of the subject masonry block walls. Walls were prioritized by considering the relative 

potential for wall failure based on wall configuration loading magnitudes and span lengths. Detailed 

re-evaluations were performed for the worst case walls. A relatively large number of the lesser-case 

walls were also re-evaluated in detail to assure the structural adequacy of each, and to assure that 

a sufficiently large sample was selected to include all walls requiring a detailed re-evaluation. The 

remainder of the lesser-case walls in each priority were re-evaluated by comparison with the worst

case walls. This assured that the most critical walls were considered for prompt, detailed re

evaluation. The NRC concluded that SNC had appropriately complied with the requirements of the 

bulletin, and no further action was required beyond the normal inspections and evaluations 

committed to in response to the bulletin. NRC also revisited Plant Hatch to assure proper maintenance of the block walls per the requirements of IE Bulletin 80-11. The applicant stated that 

masonry block wall cracks may be caused by age-related degradation mechanisms. During one 

walkdown, performed as part of the SMP, cracking was observed in concrete masonry block walls. 

The applicant considered the observed cracks to be minor and insignificant, and were noted for 

comparison in future walkdowns. 

The applicant also indicated that its SMP is intended to manage the aging effects of the block walls 

discussed above during the period of extended operation. Although the applicant's response did 

not specifically describe how the SMP incorporated the insights provided in NRC IN 87-65, the staff 

considers that by describing the past masonry wall walkdown experience and disposition of 

walkdown findings, the applicant has adequately responded to the intent of RAI 3.6-47. Thus, the 

staff considers the RAI resolved. 

With the applicant's clarification that the SMP will be used to manage aging effects of block walls 

during the period of extended operation, and with the information provided by the applicant 

concerning its experience in using the SMP to identify age-related degradation of the block walls, 

the staff concludes that the SMP will be adequate to identify age-related degradation of block walls 

during the period of extended operation. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the reactor building will be 

adequately managed by the above listed AMPs. 

Reactor Building Penetrations 

Aging management programs determined by the applicant to manage aging effects requiring 

management for reactor building penetrations are: 

* protective coatings program 

* structural monitoring program 

The protective coatings program provides for periodic inspection of structural component surfaces, 

including fasteners and associated coatings. This program also provides for proper corrective 

actions to prevent or repair significant degradation of structural materials and fasteners due to 

corrosion.

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The structural monitoring program provides for the visual inspection of structural components on 

a scheduled basis. The SMP will inspect structural components for loss of material due to general 

corrosion. 

The staff's detailed review of these programs may be found in Sections 3.1.20 and 3.1.22 of this 

SER. 

A complete discussion of the applicable aging management programs may be found in Section 3.1 

of this SER. 

The applicant has identified the above listed programs for managing the aging of reactor building 

penetrations. 

Tables 3.3.1-1 through 3.3.1-13 of the LRA do not list fire barrier penetration seals as 

components subject to an AMR. The staff views these fire barrier penetration seals as within scope 

and subject to an AMR. RAI 3.6-35 asked the applicant to describe how the aging effects for fire 

barrier penetration seals are evaluated, and to discuss the AMP used to adequately manage the 

effect. The applicant stated that fire barrier penetration seals are addressed in LRA Table 3.2.4-18. 

Aging effects requiring management are listed as loss of material, change in material properties, 

and cracking in LRA Section C.2.3.4.1 and fire protection activities is designated as the AMP to 

manage these aging effects. The staff finds this response acceptable. RAI 3.6-35 is closed. 

In response to RAI 3.6-45 related to the five-operating-cycle inspection period in the SMP, the 

applicant stated that the baseline inspection was conducted in 1998, and the next inspection is due 

in 2003. Thereafter the inspection period will be every five operating cycles. The SMP has criteria 

and guidance for adjusting the inspection interval based on the results of inspection. Considering 

the LCO and surveillance requirements related to secondary containments in TS Section 3.6.4.1, 

the staff finds the above inspection interval criteria for reactor building penetrations acceptable and 

RAI 3.6-45 is closed. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups associated with the reactor building 

penetrations will be adequately managed by the above listed AMPs. 

Turbine Building 

The applicant stated that the aging management programs determined to manage aging effects 

requiring management for the turbine building are: 

* protective coatings program 

* structural monitoring program 

The SMP inspection process assesses the overall conditions of the listed structures, and identifies 

any degradation. The SMP will inspect the concrete commodities for loss of material, cracking, and 

spalling. The SMP will also visually inspect masonry block walls for cracking. 

The protective coatings program provides for periodic inspection of structural component surfaces, 

including fasteners and associated coatings. This program also provides for proper corrective

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actions to prevent or repair significant degradation of structural materials and fasteners due to 

corrosion. 

The staff's detailed review of these programs may be found in Sections 3.1.20 and 3.1.22 of this 

SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the turbine building will be 

adequately managed by the above listed AMPs. 

Yard Structures 

The applicant stated that the aging management programs determined to manage aging effects 

requiring management are as follows: 

* protective coatings program 

• structural monitoring program 

The SMP inspection process assesses the overall conditions of the listed structures, and identifies 

any degradation. The SMP will inspect the concrete commodities for loss of material. 

The protective coatings program provides for the prevention and mitigation of corrosion of 

embedded steel at the surface of the concrete. 

The staff's detailed review of these programs may be found in Sections 3.1.20 and 3.1.22 of this 

SER. 

On the basis of the information discussed above, the staff concludes that the applicant has 

demonstrated that the aging effects for the commodity groups for the yard structures will be 

adequately managed by the above listed AMPs. 

3.6.4 Conclusion 

The staff has reviewed the information in Section 2.4, "Structures Screening Results"; Section 3.3.1, 

"Civil Structural Components"; A.1, "Existing Programs and Activities"; A.2, "Enhanced Programs 

and Activities"; A.3, "New Programs and Activities"; B.1, "Existing Programs and Activities"; B.2, 

"Enhanced Programs and Activities"; B.3, "New Programs and Activities"; and C.2.6, "Aging 

Management Review for Civil Discipline Commodities" of the LRA. On the basis of this review, the 

staff concludes that the applicant has adequately identified the aging effects associated with 

structures and structural components and has demonstrated that the aging effects associated with 

the structures and structural components will be adequately managed so that there is reasonable 

assurance that these structures and structural components will perform their intended functions in 

accordance with the CLB during the period of extended operation. 

3.7 Electrical and Instrumentation and Controls 

The applicant described its AMR for electrical components at Plant Hatch in Section C.2.5, "Aging 

Management Reviews For Electrical Discipline Commodities" of the LRA. The staff reviewed this 

section of the application to determine whether the applicant has demonstrated that the effects of

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aging on the electrical components will be adequately managed during the period of extended 

operation, as required by 10 CFR 54.21 (a)(3). 

3.7.1 Summary of Technical Information in the Application 

Section C.1.3 of the LRA identified the applicable aging effects for electrical components. The 

process to determine aging effects applicable to electrical components began with an understanding 

of the aging effects identified in the industry literature. The components that require aging 

management were determined by examining the component materials, service environments, and 

operating stresses for each component type. In addition to the industry literature review, plant

specific operating experience was reviewed to provide reasonable assurance that all aging effects 

were identified for the AMR. 

External environments are defined in Sections C.1.2.8, "Inside;" C.1.2.9, "Outside;" and C.1.2.10, 

"Buried or Embedded" of the LRA. "Inside" external environments are defined as environments 

where equipment is sheltered from the weather. "Outside" external environments are defined as 

environments found outside a structure where equipment would not be sheltered from the weather. 

"Buried or embedded" external environments are defined as environments beneath the surface of 

the ground (in some cases with controlled backfill) or embedded in structural concrete. Structures 

and components which perform their functions in external environments are, in general, discussed 

in Sections C.2.1, C.2.2, C.2.3, C.2.4, C.2.5, and C.2.6 of the LRA, and are evaluated in Sections 

3.6 and 3.7 of this SER, unless otherwise noted. 

3.7.1.1 Effects of Aging 

Electrical cables, connectors, splices, terminal blocks, Nelson frames, and phase bussing are the 

electrical component types that are subject to an AMR. Based on available industry literature, the 

following aging effects have been identified for these electrical components requiring aging 

management: 

* loss of material 

• cracking/embrittlement 

• loss of conductivity 

* change in insulation resistance 

* change in material properties 

Depending upon the environmental conditions that are present, the above aging effects can be 

expected to occur due to the following aging mechanisms: 

thermal degradation of organic materials 

- loss of material 

- cracking/embrittlement 

- change in material properties 

- change in insulation resistance

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0 thermoxidative degradation

- loss of material 

- cracking/embrittlement 

- change in material properties 

- change in insulation resistance 

radiolysis of organic materials 

- cracking/embrittlement 

- change in insulation resistance - change in material properties 

water treeing 

- change in insulation resistance 

The aging effects associated with nonmetallic materials used in electrical components at Plant 

Hatch were assessed by evaluating the environmental conditions associated with high temperature, radiation, and moisture. High temperature can result in thermal degradation and thermoxidative 

degradation of electrical components. A radiation environment can result in radiolysis of organic materials. Water penetration into electrical cable insulation can result in reduced dielectric strength due to increased conductivity of the insulation caused by increased ion mobility and concentration. 

3.7.1.2 Aging Management Programs 

On the basis of the review of industry literature and plant-specific operating experience, the 

applicant maintains that, with the exception of the 4-kV power and transformer feeder cables and 

insulated cables, connectors, splices, and terminal blocks, the aging effects identified above for 

Nelson frames and phase bussing do not require an aging management program. 

3.7.2 Staff Evaluation 

In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in Sections 3.4, A.1.16, C.1.3, and C.2.5 of the LRA regarding the applicant's demonstration that aging effects will be 

adequately managed so that the intended functions will be maintained consistent with the CLB for 

the period of extended operation for the electrical components. After completing the initial review, the staff issued requests for additional information on July 14 and July 28, 2000. The responses 

were received on October 10, 2000 and January 31, 2001. 

3.7.2.1 Effects of Aging 

The applicant identified potential aging effects for license renewal by reviewing available industry literature and plant-specific operating experience. These effects include loss of material, cracking/embrittlement, change in material properties, and change in insulation resistance. The 

staff evaluated the applicant's identification of these potential aging effects for the phase bussing, Nelson frames, cables, splices, connectors, and terminal blocks.

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3.7.2.1.1 Aging Effects on Phase Bussing Caused by High Temperature and Radiation 

The materials associated with the phase bussing include various polymers, galvanized and stainless 

steel, and tinned and bare copper. Phase bussing is subjected to an internal environment due to "self heating," and an external environment of "inside" (excluding containment). Inside environments 

are defined in Section C.1.2.8 of the LRA as environments where equipment is sheltered from the 

weather. The phase bussing inside environment is associated with the electrical bus between the 

4160/600 volt station auxiliary transformer CD and 600v buses C and D. 

A review of operating experience based on the condition reporting database identified that 

approximately 122 deficiencies had been written on the power transformer system associated with 

phase bussing. The applicant screened these deficiencies to determine which ones might be 

potentially age-related. No age-related failures of the in-scope phase bussing components were 

found. 

The materials of construction for the portion of phase bussing that is in scope were evaluated for 

60-year temperatures and radiation doses based on industry material databases. The 60-year 

temperatures and allowable doses were greater than the expected temperatures and radiation 

doses in all cases. Therefore, no aging effects associated with temperature and radiation require 

aging management for in-scope electrical phase bussing. 

The staff agrees with the applicant's assessment and conclusion that, on the basis of the review of 

industry information, plant-specific operating experience, and evaluation of the materials of 

construction for 60-year expected temperatures and radiation doses, no aging effects that would 

lead to a loss of intended function are applicable for phase bussing, and no AMP is necessary. 

3.7.2.1.2 Aging Effects on Nelson Frames 

The materials associated with Nelson frames consist of various polymers and galvanized and 

painted steel. Nelson frames are located in the walls and floors of the reactor building with an 

external environment of "inside" (excluding containment). Nelson frames are located in the wall 

between the reactor building and turbine building, in the wall between the reactor building and the 

control building, and between floors of the reactor building. Reactor building electrical penetrations 

allow cables to penetrate the secondary containment boundary and maintain secondary containment 

leakage rates within design limits. 

A review of the condition reporting database did not identify any deficiencies of the reactor building 

penetration system, which contains the Nelson frames. The materials of construction for the Nelson 

frames were evaluated for 60-year temperatures and radiation doses based on industry material 

databases. The 60-year temperatures and allowable doses were greater than the expected 

temperatures and radiation doses in all cases. Therefore, no aging effects associated with 

temperature and radiation require aging management for Nelson frames. 

The staff agrees with the applicant's assessment and conclusion that, on the basis of the review of 

industry information, plant-specific operating experience, and evaluation of the materials of 

construction based on 60-year expected temperatures and radiation doses, no aging effects that 

would lead to a loss of intended function are applicable for Nelson frames, and no AMP is 

necessary.

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3.7.2.1.3 Aging Effects on Cables, Connectors, Splices, and Terminal Blocks 

The aging effects discussed in this subsection are associated with cables, connectors, splices, and 

terminal blocks that are not managed by the applicant's environmental qualification program. The 

applicant's aging management of environmentally qualified cables, connectors, splices, and terminal 

blocks is considered a TLAA and is discussed in Section 4.4 of the LRA. The staff's evaluation of 

this section can be found in Section 4.4 of this SER. 

The materials associated with cables, connectors, splices, and terminal blocks consist of various 

polymers, tinned and bare copper, and galvanized and stainless steel. Insulated electrical cable at Plant Hatch is located in an external environment of "inside" and "outside." Some cables could be 

exposed to submergence. Electrical splices, connectors, and terminal blocks are located in an 

external environment of "inside" and "outside," and are installed throughout the plant, in the drywell, 

and in outdoor pits. 

The effects of moisture on medium-voltage cables can result in water trees when the insulating materials are exposed to long-term, continuous-voltage stress and moisture, eventually resulting in breakdown of the dielectric and failure. The growth and propagation of water trees are somewhat 

unpredictable, and few occurrences have been discovered for cables operated below 15 kV. Water 

treeing has been documented for medium-voltage electrical cables with cross-linked-polyethylene (XLPE) or high-molecular-weight polyethylene (HMWPE) insulation. Recently, medium-voltage cables with ethylene propylene rubber insulation have failed after being exposed to long-term, continuous-voltage stress and significant moisture. Plant Hatch wetted cable activities provide for mitigating activities as well as condition monitoring activities for 4-kV power cables and transformer 

feeder cables that are within the scope of license renewal. Wetted cables activities are discussed 

in Section B.1.16 of the LRA. The staff's review of wetted cables activities can be found in Section 

3.1.16 of this SER. 

Radiation-induced degradation in cable jacket and insulation materials produces changes in organic material properties, including reduced elongation, and changes in tensile strength. Visual 

indications of radiative aging may include embrittlement, cracking, discoloration, and swelling of the 

jacket and insulation. For cables, connectors, splices, and terminal blocks, the applicant has provided an "Insulated Cables and Connections Aging Management Program," by letter dated January 31, 2001. The staff's evaluation of this AMP can be found in Section 3.1.30 of this SER. 

Thermal-induced degradation in cable jacket and insulation materials can result in reduced 

elongation and changes in tensile strength. Visible indications of thermal aging may include 

embrittlement, cracking, discoloration, and swelling of the jacket and insulation. The Arrhenius 

methodology was used by the applicant for temperatures corresponding to a 60-year service life for 

cables, connectors, splices, and terminal blocks. These temperatures were compared to the 

maximum bounding temperatures of the various plant areas. For cables, connectors, splices, and terminal blocks, the applicant has provided an "Insulated Cables and Connections Aging Management Program," by letter dated January 31, 2001. 

The staff agrees with the applicant's assessment regarding the wetted cable activities for moisture 

for the 4-kV power cables and transformer feeder cables and with the applicant's assessment 

associated with temperature and radiation for cables, connectors, splices, and terminal blocks.

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3.7.2.2 Aging Management Programs

3.7.2.2.1 Aging Management Program for Wetted Cables 

T'he wetted cable activities at Plant Hatch provide for mitigating activities as well as condition 

monitoring activities. Plant Hatch wetted cables activities include monitoring for and removing water, 

along with testing to detect changes in insulation resistance. Several 4-kV power cables and 

transformer feeder cables within the scope of license renewal are routed through the underground 

duct bank system consisting of outdoor pull boxes containing underground conduits routed between 

in-scope buildings. Change in insulation resistance is the aging effect that is mitigated and 

monitored by the wetted cable activities. 

The water level is measured, recorded, and the pull boxes drained where these in-scope 4-kV power 

and transformer cables are routed. Megger and polarization index testing are periodically 

performed. When new terminations are made, the cables are hipot tested to provide additional 

assurance that the cable insulation integrity is sound. In addition, the pull boxes are drained 

quarterly and testing is performed on in-scope 4-kV motor windings and the associated feeder 

cables during regular motor and pump maintenance tasks. 

The wetted cable activities meet the intent of IEEE 43-1974, "Recommended Practice for Testing 

Insulation Resistance of Rotating Machinery"; and IEEE 95-1977," Recommended Practice for 

Insulation Testing of Large AC Rotating Machinery with High Direct Voltage." Pull boxes found to 

contain water are drained to 1 inch of water or less. Cables and loads must successfully pass 

megger and polarization index testing. Corrective actions are taken if testing results are 

unacceptable. Plant specific operating experience did not identify any in-scope age-related cable 

failures due to moisture intrusion. 

The staff finds that the Plant Hatch wetted cable activities manage the effects of cable aging due 

to moisture intrusion so that the intended functions will be maintained consistent with the CLB for 

the period of extended operation (see Section 3.1.16 of this SER). 

3.7.2.2.2 Aging Management Program for Cable, Connectors, Splices, and Terminal Blocks 

Sections 3.4, C.1.3, and C.2.5 of the LRA conclude that no aging effects associated with high 

temperature and radiation require aging management for cables, connectors, splices, and terminal 

blocks. On July 14, 2000, the staff issued RAI 2.5 requesting that the applicant provide a 

description of the following: 

an aging management program for accessible and inaccessible electrical cables and 

connections that may be exposed to an adverse localized environment caused by heat or 

radiation 

an aging management program for accessible and inaccessible electrical cables used in 

instrumentation circuits that are sensitive to a reduction in conductor insulation resistance 

exposed to an adverse localized environment caused by heat or radiation 

By letter dated October 10, 2000, the applicant acknowledged that industry information exists 

regarding the effects of temperature and radiation on electrical cables and connections, including 

the information on cable aging in the staff's Generic Aging Lessons Learned (GALL) Report. By

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letter dated January 31, 2001, the applicant provided a description of an "Insulated Cables and 

Connections Aging Management Program." The insulated cables and connections AMP is a 

condition monitoring program designed to confirm that age-related degradation is not inhibiting 

component function of insulated cables and connections within the scope of license renewal during 

the period of extended operation. The staff evaluation of this AMP is found in Section 3.1.30 of this 

SER. 

The staff finds that the Plant Hatch insulated cables and connections AMP manages the effects of 

aging due to radiation and temperature so that the intended functions will be maintained consistent 

with the CLB for the period of extended operation. 

3.7.3 Conclusion 

The staff has reviewed the information in Sections 3.4, A.1.16, C.1.3, and C.2.5 of the LRA as well 

as the additional information provided by the applicant in RAI response dated October 10, 2000, and 

by letter dated January 31,2001. On the basis of this review, the staff concludes that the applicant 

has adequately identified the aging affects associated with electrical components, and has 

demonstrated that the aging effects associated with electrical systems and components at Plant 

Hatch will be adequately managed so that there is reasonable assurance that these systems and 

components will perform their intended functions in accordance with the CLB during the period of 

extended operation, as required by 10 CFR 54.21 (a)(3).

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4 TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses 

4.1.1 Introduction 

The applicant described its identification of time-limited aging analyses (TLAA) in Se~ction 4.1.1, 

"Identification and Evaluation of Time-Limited Aging Analyses," of the LRA. The staff reviewed this 

section of the LRA to determine whether the applicant has identified the TLAAs as required by 10 

CFR 54.21 (c). 

4.1.2 Summary of Technical Information in the Application 

The applicant evaluated calculations for Plant Hatch against the six criteria specified in 10 CFR 54.3 

to identify the TLAAs. As a result of this evaluation, the applicant identified the following TLAAs: 

a piping stress analyses that consider thermal fatigue cycles defined by the life of the plant 

0 fatigue/stress analyses for the torus structure and nozzle connections 

0 piping wall thickness calculations that develop acceptable as-measured criteria for pipe walls 

on the basis of an anticipated corrosion rate that, in turn, is founded upon the life of the plant 

* calculation of the corrosion allowance assumed for the reactor vessel 

* environmental equipment qualification calculations that qualify electrical components for 40 

years 

a containment penetration structural analysis that assumes a number of pressurization 

cycles over the 40-year life of the plant 

0 calculation of the reference temperature for nil-ductility for critical core region vessel 

materials accounting for radiation embrittlement (as required by 10 CFR Part 50, Appendix 

G) 

* calculation of the end-of-life equivalent Charpy Upper-Shelf Energy margin (as required by 10 CFR Part 50, Appendix G) associated with the extended operating term 

0 analyses performed to demonstrate the acceptability of a technical alternative to the Code 

requirement for inspection of reactor pressure vessel circumferential welds 

0 change in the anticipated operating cycles of the MSIVs from the number of cycles assumed 

for 40 years in the Plant Hatch UFSAR 

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it had not identified any exemptions 

granted under 10 CFR 50.12 that were based on a TLAA. The applicant did identify that a technical 

alternative (as defined in 10 CFR 50.55a(a)(3)(i)) to requirements to inspect circumferential welds

4-1
on the reactor pressure vessel had been approved. This TLAA is discussed in Section 4.6 of this 

SER. 

4.1.3 Staff Evaluation 

As indicated by the applicant, TLAAs are defined in 10 CFR 54.3 as analyses that meet the following 

six criteria: I 

* Involve systems, structures, and components within the scope of license renewal, as 

delineated in Section 54.4(a). 

* Consider the effects of aging. 

* Involve time-limited assumptions defined by the current operating term, for example, 

40 years. 

* Make a safety determination by determining which TLAAs are relevant. 

* Involve conclusions or provide the basis for conclusions related to the capability of the 

system, structure, and component to perform its intended functions, as delineated in Section 

54.4(b). 

* Ensure that the relevant TLAAs are contained or incorporated by reference in the CLB. 

Table 4.1.1-1 of the LRA did not identify flaw growth analysis as a TLAA. Flaws in Class 1 

components that exceed the size of allowable flaws defined in IWB-3500 of the ASME Code need 

not be repaired if they are analytically evaluated to the criteria in IWB-3600 of the ASME Code. The 

analytic evaluation requires that the applicant project the amount of flaw growth attributable to 

fatigue and stress corrosion cracking mechanisms, or both, where applicable, during a specified 

evaluation period. In RAI 4.1-1, the staff asked the applicant to identify all Class 1 components that 

have flaws that exceed the allowable flaw limits defined in IWB-3500 and that have been analytically 

evaluated to IWB-3600 of the ASME Code, and provide the results of the analyses that indicate 

whether the flaws will satisfy the criteria in IWB-3600 throughout the period of extended operation. In response, the applicant stated that the review of flaw growth analyses for Plant Hatch did not 

identify any that meet the definition of a TLAA per the criteria of 10 CFR 54.3. The applicant further 

indicated that most flaw evaluations were performed for a 40-month period, and no flaw evaluations 

were performed for a 40-year period. The staff agrees that evaluations for 40-month time periods 

do not constitute TLAAs per the definition in 10 CFR 54.3. 

Table 4.1.1-1 of the LRA identifies piping stress analyses that consider thermal fatigue cycles as 

a TLAA. The table does not identify the fatigue analyses of other reactor coolant pressure boundary 

components or the reactor vessel internals as TLAAs. Section 4.2 of the LRA does address the 

reactor pressure vessel. In RAI 4.1-2, the staff asked the applicant to identify other components of 

the reactor coolant pressure boundary that have fatigue analyses. The staff also asked the 

applicant to describe the TLAAs that were performed to address fatigue for the reactor coolant 

pressure boundary components, except for the reactor vessel, that were not included in Table 4.1.1 

1, and to describe the TLAA performed for the reactor vessel internals. The staff also requested 

that the applicant indicate how these TLAAs meet the requirements of 10 CFR 54.21(c). In 

response, the applicant stated that the criteria of BWRVIP-74 were used to determine which fatigue

4-2
analyses were sufficiently significant to constitute a TLAA. As indicated in the RAI, the applicant discussed the fatigue analysis of the reactor vessel internals in the UFSAR. In the SER issued in 

February, 2001, the staff requested that the applicant explain how the fatigue analysis of the vessel 

internals was found to be acceptable for the 60-year period. The staff also requested that the 

applicant identify any other components of the reactor coolant pressure boundary that had fatigue analyses, and explain how these analyses were found to be acceptable for the 60-year period. This 

was identified as part of Open Item 4.1.3-1 [4.1.3-1 (a)]. 

The applicant provided a response to this open item by letter dated June 5, 2001. In the letter, the 

applicant indicated that the initial Plant Hatch vessel internals AMR noted that cracking due to 

fatigue was an aging effect requiring management and that the fatigue cumulative usage factor 

(CUF) calculation was a TLAA. The applicant's response also indicated that, subsequent to the 

development of the initial AMR, the end-of-life CUF was determined to be substantially less than 0.5. 

The applicant stated that since the end-of-life CUF was low, the fatigue calculation did not represent 

a TLAA. The staff disagrees with the applicant's premise that, because the calculated CUF was 

low, the fatigue calculation did not represent a TLAA. The applicant should have identified the 

vessel internals fatigue analysis as a TLAA in the LRA and described the disposition of the TLAA 

per the requirements of 10 CFR 54.21 (c)(1). However, the applicant's current fatigue analysis of 

the vessel internals, which projects that the CUF will remain below 1.0 for the period of extended 

operation, provides an acceptable TLAA evaluation in accordance with the requirements of 10 CFR 

54.21 (c)(1)(ii). The applicant did not identify any other components of the reactor coolant pressure boundary that had fatigue analyses. Therefore, this part of Open Item 4.1.3-1 [4.1.3-1 (a)] is closed. 

Section 4.2.2 of the LRA contains a discussion of the Plant Hatch licensing-basis pipe break criteria. 

Part of the Plant Hatch pipe break criteria involves postulating pipe breaks at locations where the 

calculated fatigue usage exceeds a specified value. Although the applicant identified the fatigue cumulative usage factor (CUF) calculation as a TLAA, the applicant concluded that the pipe break 

criteria were only a screening mechanism and not a TLAA. The usage factor calculation used to 

identify postulated pipe break locations meets the definition of a TLAA, as specified in 10 CFR 54.3. 

In RAI 4.2-1, the staff asked the applicant to provide a description of a TLAA for the pipe break 

criteria at Plant Hatch, and describe how the TLAA meets the requirements of 10 CFR 54.21 (c). 

In response, the applicant stated that it views the pipe break criteria to be selection criteria that 

establish a bounding set of locations for line break consideration. Although the staff agreed with 

the applicant's statement, the staff still considered pipe break postulations to be a TLAA because 

the fatigue calculation is a TLAA. Additionally, the NRC previously identified high-energy line break 

postulation founded on the fatigue CUF as a TLAA in accordance with 10 CFR 54.3 (60 FR 22480, 

May 8, 1995). Therefore, the staff requested that the applicant include pipe break postulations founded on the fatigue usage factor as a TLAA. This was identified as part of Open Item 4.1.3-1 

[4.1.3-1(b)]. 

By letter dated September 5, 2001, the applicant responded to this open item. In the response to 

the open item, the applicant revised its LRA discussion of pipe break criteria to classify pipe break 

postulations based on fatigue CUF as TLAAs. The TLAA evaluation is discussed in Section 4.2.5 

of the revised LRA. The licensing basis pipe break criteria required that breaks be postulated at 

piping locations where the calculated CUF exceeded 0.1. The applicant identified additional piping locations where the CUF criterion may be exceeded during the period of extended operation. The 

applicant proposed to monitor three bounding locations during the period of extended operation using its Component Cyclic or Transient Limit Program to address the TLAA. The applicant's proposed program, which involves monitoring a sample of bounding locations during the period of

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extended operation, is an acceptable method to address the pipe break postulation TLAA in 

accordance with the requirements of 54.21 (c)(1). If the CCTLP identifies a location where the usage criterion may be exceeded, then the applicant must take corrective action in accordance with the 

corrective action program. As part of the corrective action, other potential locations must be 

addressed. This part of Open Item 4.1.3-1 [4.1.3-1(b)] is closed. 

4.1.4 Conclusions 

The staff has reviewed the information in Section 4.1.1, "Identification and Evaluation of Time

Limited Aging Analyses," of the LRA. On the basis of that review, the staff concludes that the 

applicant has adequately identified the TLAAs as required by 10 CFR 54.21(c), and that no 10 CFR 

50.12 exemptions have been granted on the basis of a TLAA, as defined in 10 CFR 54.3. 

4.2 Pipe Stress 

4.2.1 Introduction 

The applicant described its evaluation of pipe stress TLAAs in Section 4.2, "Pipe Stress Time

Limited Aging Analyses" of the LRA. The staff reviewed this section of the LRA to determine whether 

the applicant has adequately evaluated the TLAAs as required by 10 CFR 54.21 (c). 

A metal component subjected to cyclic loads may fail at a load magnitude less than its ultimate load 

capacity as a result of metal fatigue, which initiates and propagates cracks in the material. The 

fatigue life of a component is a function of its material, its environment, and the number and 

magnitude of the applied cyclic loads. Fatigue was a design consideration for piping and 

components and, consequently, fatigue is part of the CLB for Plant Hatch. The applicant identified 

fatigue as TLAAs for piping stress analyses that consider thermal cycles defined by the life of the 

plant and fatigue/stress analyses for the torus structure and nozzle connections. The staff reviewed 

Section 4.2 of the LRA, which discusses thermal fatigue of piping and fatigue of the torus structure. 

4.2.2 Summary of Technical Information in the Application 

The applicant discusses the design criteria for thermal fatigue in Section 4.2.1 of the LRA. Class 1 

piping was explicitly evaluated for thermal transients specified in the UFSAR. As indicated in Table 

4.2.2-1 of the LRA, the Class 1 (RCS) piping at Unit 1 was designed to the United States of America 

Standard (USAS) B31.7 Class 1 criteria, and Unit 2 was designed to the criteria of ASME Code 

Section III, Subsection NB. The criteria of both codes require that the calculated fatigue CUF 

resulting from the thermal transients not exceed the specified code limit of 1.0. As indicated in 

Table 4.2.3-1 of the LRA, Non-Class 1 piping was designed to the criteria of either USAS B31.1, 

USAS B31.7 Class 2 and 3, or ASME Subsection NC and ND. The criteria of these codes specify 

a stress reduction factor to be applied to the allowable thermal bending stress range if the number 

of cycles exceeds 7,000. 

The applicant discusses the evaluation of Class 1 components in Section 4.2.2 of the LRA. The 

applicant indicated that Class 1 fatigue TLAAs would be addressed by an aging management 

program, which is described in Section A.1.12 of the LRA. This aging management program 

monitors the CUF of specific bounding locations at Plant Hatch. Specifically, these locations include 

four components of the RPV; closure studs, the shell, the recirculation inlet nozzles, and the 

feedwater nozzles. In addition, the following Class 1 piping locations are monitored:

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0 Unit 1 RPV equalizer piping

* Unit 1 core spray piping (for replaced piping outside of the RPV) 

o Unit 1 standby liquid control piping 

0 Unit 1 feedwater, HPCI, RCIC, and RWCU system piping 

• Unit 1 main steam piping (loop B) 

* Unit 2 main steam piping (loop D) 

• Unit 2 feedwater piping 

* Unit 2 steam condensate drainage piping 

The applicant monitors these locations using its CCTL, which is discussed in Sections A.1.12 and 

B.1.12 of the LRA. The staff's evaluation of this program in contained in Section 3.1.12 of this SER. 

The applicant also discusses the design criteria to postulate pipe break scenarios and Generic 

Safety Issue (GSI)-190, "Fatigue Evaluation of Metal Components for 60-Year Plant Life." The 

applicant states that the pipe break criteria are not a TLAA. The applicant relies on generic industry 

studies to address the environmental fatigue concerns identified in GSI-1 90. 

The applicant discusses the evaluation of Non-Class 1 piping in Section 4.2.3 of the LRA. For Non

Class 1 piping, a stress reduction factor would have been applied if the number of equivalent full

temperature cycles exceeded 7,000. The applicant indicated that its review of the UFSAR, 

operations manual, and operating history indicated that the estimated number of full-temperature 

cycles that the Non-Class 1 piping would experience over 60 years is substantially less than the 

number assumed in the analyses. 

The applicant discusses the evaluation of the torus structure in Section 4.2.4 of the LRA. 

Specifically, the applicant indicated that several calculations related to the torus structure constituted 

fatigue TLAAs. The applicant also indicated that a new analysis of the torus was performed to 

address fatigue for the period of extended operation. 

4.2.3 Staff Evaluation 

Components of the RCS were designed to codes that contained explicit criteria for the fatigue analysis. Consequently, the applicant identified fatigue analyses of some RCS components as 

TLAAs. In Section 4.1 of this SER, the staff questioned whether the applicant has identified all of 

the TLAAs. The staff reviewed the applicant's evaluation of the identified RCS components for 

compliance with the provisions of 10 CFR 54.21 (c)(1). 

The applicant monitors limiting locations in the RPV and RCS piping for fatigue usage through the 

use of its CCTLP. The applicant indicated that actual operating history was used to project a 60

year CUF for each unit. The applicant further indicated that all monitored locations are projected 

to have a CUF less than 1.0 after 60 years of operation. Even though the applicant projects that

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the CUF of the limiting locations will not exceed 1.0 during the period of extended operation, the 

applicant relies on the CCTLP to monitor the CUF and manage fatigue in accordance with the 

provisions of 10 CFR 54.21 (c)(1)(iii). The staff's evaluation of the CCTLP is contained in Section 

3.1.12 of this SER. 

The applicant's CCTLP tracks transients and cycles of RCS components that have explicit design 

basis transient cycles to ensure that these components stay within their design basis. Generic 

Safety Issue (GSI)-166, "Adequacy of the Fatigue Life of Metal Components," raised concerns 

regarding the conservatism of the fatigue curves used in the design of these components. Although 

GSI-166 was resolved for the current 40-year design life of operating plants, the staff initiated 

GSI-1 90 to address license renewal. The resolution of GSI-1 66 for the 40-year design life relied, 

in part, on conservatism in the existing CLB analyses. This conservatism included the number and 

magnitude of the cyclic loads postulated in the initial component design. A detailed discussion of 

the GSI-1 66 evaluation is contained in SECY-95-245, "Completion of the Fatigue Action Plan." 

The staff's assessment for GSI-166 provides a basis for the current 40-year plant design life. 

However, the staff's assessment took credit for the conservatism in the CLB fatigue analyses for 

the 40-year plant life. The staff further indicated that its assessment could not be extrapolated 

beyond the current facility design life (40 years). Therefore, the GSI-1 66 resolution only applies to 

the fatigue accumulation for a 40-year design life. 

The applicant's CCTLP tracks fatigue cycles of RCS components, and compares the cycles to those 

used in the CLB evaluation. GSI-166 and GSI-190 identified a concern regarding the conservatism 

of the CLB fatigue design curves. In SECY 95-245, the staff recommended not to backfit new 

fatigue criteria to current operating nuclear power plants. The recommendation was founded, in 

part, on an assessment of the conservatism in existing fatigue analyses of components at operating 

plants for the 40-year design life. The staff did recommend that a sample of components with high 

fatigue usage factors be evaluated for any period of extended operation. 

By letter dated February 9, 1998, the Electric Power Research Institute (EPRI) submitted two 

technical reports dealing with the fatigue issue. EPRI Reports TR-1 07515, "Evaluation of Thermal 

Fatigue Effects on Systems Requiring Aging Management Review for License Renewal for the 

Calvert Cliffs Nuclear Power Plant," and TR-1 05759, "An Environmental Factor Approach to Account 

for Reactor Water Effects in Light Water Reactor Pressure Vessel and Piping Evaluations" were part 

of an industry attempt to resolve GSI-1 90. As recommended in SECY 95-245, the EPRI analyzed 

components with high usage factors, using environmental fatigue data. The staff has open technical 

concerns regarding the EPRI reports. The staff's technical concerns were transmitted to the 

Nuclear Energy Institute (NEI) by letter dated November 2, 1998. The NEI responded to the staff's 

concerns in a letter dated April 8, 1999. The staff submitted its assessment of the response in a 

letter to the NEI, dated August 6, 1999. As indicated in the staff's letter, the NEI response did not 

resolve all of the staff's technical concerns regarding the EPRI reports. 

The applicant indicated that EPRI license renewal fatigue studies have demonstrated that sufficient 

conservatism exists in the design transient definitions to compensate for potential reactor water 

environmental effects for Plant Hatch. As discussed above, the staff does not agree with the 

contention that the EPRI fatigue studies have demonstrated that sufficient conservatism exists in 

the design transient definitions to compensate for potential reactor water environmental effects. 

Although the letter dated August 6, 1999 identified the staff's concerns regarding the EPRI 

procedure and its application to PWRs, the technical concerns regarding the application of the

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Argonne National Laboratory (ANL) statistical correlations and strain threshold values are also 

relevant to BWRs. In addition to the concerns referenced above, the staff has additional concerns 

regarding the applicability of the EPRI BWR studies to Plant Hatch. EPRI Report TR-107943, 

"Environmental Fatigue Evaluations of Representative BWR Components," addressed a BWR-6 

plant, and EPRI Report TR-1 10356, "Evaluation of Environmental Thermal Fatigue Effects on 

Selected Components in a Boiling Water Reactor Plant," used plant transient data from a newer 

vintage BWR-4 plant. In RAI 4.2-2, the staff requested that the applicant provide additional 

information regarding the use of the EPRI license renewal fatigue studies to resolve the 

environmental fatigue issue at Plant Hatch. 

In response to the RAI, the applicant discussed its assessment of the impact of the environmental 

correction factors for carbon and low-alloy steels contained in NUREG/CR-6583, "Effects of LWR 

Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," and those for 

austenitic stainless steels contained in NUREG/CR-5704, "Effects of LWR Coolant Environments 

on Fatigue Design of Austenitic Stainless Steels," on the results of the EPRI studies. As a result 

of its assessment, the applicant concluded that the correlations have been adequately accounted 

for via the conservatism of the design-basis transients. 

The applicant indicated that EPRI Report TR-1 10356 contained studies that are directly applicable 

to Plant Hatch because they involved a BWR-4 that is identical to the Plant Hatch design. The only 

components evaluated in TR-1 10356 are the feedwater nozzle and the control rod drive penetration 

locations. However, the applicant indicated that both Plant Hatch units employ hydrogen water 

chemistry, whereas the plant in the EPRI study did not consider hydrogen water chemistry, which 

affects the level of dissolved oxygen in the primary system. Dissolved oxygen is an important factor 

in the environmental fatigue effects. The applicant stated that this issue was adequately addressed 

by its evaluation of the feedwater nozzle contained in EPRI Report TR-1 05759. It is not clear to the 

staff how the issue of hydrogen water chemistry was addressed in EPRI Report TR-1 05759. The 

applicant's response did not resolved the staff's concerns regarding the environmental fatigue issue 

at Plant Hatch. 

The staff requested that the applicant provide an assessment of the six locations identified in 

NUREG/CR-6260, "Application of NUREG/CR-5999, 'Interim Fatigue Curves to Selected Nuclear 

Power Plant Components'," dated March 1995, for an older vintage BWR (BWR-4) considering the 

applicable environmental fatigue correlations provided in NUREG/CR-6583 and NUREG/CR-5704 

reports for Plant Hatch Units 1 and 2. The applicant indicated that these locations are monitored 

by the CCTLP, and that the environmental factors have been adequately accounted for by the 

conservatism in the design basis transient definitions. On the basis of the above discussion, the 

staff did not agree with the applicant that environmental fatigue concerns regarding the six locations 

identified in NUREG/CR-6260 have been adequatelyaddressed at Plant Hatch. The staff, therefore, 

requested that the applicant assess these six locations, considering applicable environmental fatigue 

correlations provided in NUREG/CR-6583 and NUREG/CR-5704, as applicable. This was identified 

as Open Item 4.2.3-1. 

By letter dated September 5,2001, the applicant provided a revised response to Open Item 4.2.3-1. 

The applicant committed to evaluate the locations identified in NUREG/CR-6260 using the 

applicable environmental fatigue correlations provided in NUREG/CR-6583 and NUREG/CR-5704. 

These locations are: 

0 Reactor Vessel (Lower Head to Shell Transition)

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0 Feedwater Nozzle 

0 Recirculation System (RHR Return Line Tee) 

0 Core Spray System (Nozzle and Safe End) 

0 Residual Heat Removal Line (Tapered Transition) 

* Feedwater Line (RCIC Tee) 

The applicant indicated that usage factor multipliers would be developed at each location to account 

for the environmental effects. The applicant further indicated that these environmental multipliers 

would be incorporated in the Hatch CCTLP. The applicant's CCTLP will monitor the CUF, which 

includes the environmental multipliers, at the six locations for comparison with the allowable CUF. 

The applicant's proposal adequately addresses the staff concern regarding environmental effects 

on fatigue usage and, therefore, Open Item 4.2.3-1 is considered closed. 

The applicant discusses the TLAA for non-Class 1 piping in Section 4.2.3 of the LRA. The design 

code for non-Class 1 piping and tubing controls fatigue by limiting the allowable range of bending 

stresses resulting from the restraint of free-end expansion. The code provides for a reduction of 

the allowable stress range if the number of cycles exceeds 7000 full-range stress cycles. The 

applicant indicated that it estimated that the number of thermal cycles that non-Class 1 piping and 

tubing would encounter in 60 years of operation is substantially less than the number assumed in 

the original design. The applicant indicated that the current design basis for some piping and tubing 

is 14,000 cycles. In RAI 4.2-3, the staff requested that the applicant identify the piping and tubing 

that were designed for 14,000 cycles, and provide the basis for this specified number of cycles. In 

response, the applicant indicated that 14,000 cycles was assumed in design guides for 

instrumentation tubing and supports on the basis of a designer's rule-of-thumb approach. The 

applicant further indicated that the assumption is very conservative in that it implies a thermal cycle 

every 1.5 days over a 60-year operational life. The staff agrees with the applicant's assessment that 

the number of assumed cycles is conservative. The staff finds that the applicant's assessment 

satisfies the provisions of 10 CFR 54.21 (c)(1 )(i) by demonstrating that the analysis remains valid 

throughout the period of extended operation. 

The applicant discusses its evaluation of the torus structure in Section 4.2.4 of the LRA. According 

to the applicant, several calculations that addressed fatigue of the torus structure met the criteria 

for a TLAA. The applicant indicated that a new analysis was necessary to address fatigue in the 

torus for the period of extended operation. The applicant indicated that the critical event leading to 

fatigue damage of the torus is the lifting of one or more main steam system safety relief valves 

(SRVs). The applicant proposed to manage fatigue of the torus by monitoring the number of SRV 

lifts in its CCTLP. The staff's evaluation of the CCTLP is contained in Section 3.1.12 of this SER. 

4.2.4 Conclusion 

The staff has reviewed the information in Section 4.2, "Pipe Stress Time-Limited Aging Analyses" 

of the LRA. On the basis of its review, the staff concludes that the applicant has adequately 

evaluated the pipe stress TLAAs, as required by 10 CFR 54.21 (c)(1).

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4.3 Corrosion Allowance

4.3.1 Introduction 

The applicant described its evaluation of the corrosion allowance TLAA in Section 4.3, "Corrosion 

Allowance," of the LRA. The staff reviewed this section of the LRA to determine whether the 

applicant has adequately evaluated the TLAA as required by 10 CFR 54.21 (c). 

An allowance for corrosion was made in determining the appropriate thickness for pressure retaining 

components in the design of Plant Hatch. Only those analyses containing an assumption of a 

corrosion allowance that also tied the allowance to a 40-year operating life meet 10 CFR 54.3 

Criterion 3. In the review of the Plant Hatch analyses, two scopes of supply are important. 

Specifically, these are the equipment designed and supplied by Bechtel, and the equipment 

designed and supplied by General Electric (GE). 

4.3.2 Summary of the Technical Information in the Application 

Bechtel Power Corporation Scope of Supply 

The assumption of a corrosion allowance appears in calculations that confirm the pressure rating 

of piping and components. The piping specifications for both Plant Hatch units specify corrosion 

allowances for types of piping on the basis of material and environment. In most of the calculations 

reviewed, the corrosion allowance assumed was not tied to a 40-year life of the component. 

Additionally, corrosion rates were not identified (with specific exceptions discussed below). Many 

of the calculations used standard values from Table A104.2 of ASME B31.1. Once a required minimum wall thickness was calculated, the design often chose the next thicker component size 

(e.g., the next higher pipe schedule). For these reasons, calculations covering components in the 

Bechtel scope of supply generally do not meet the definition of a TLAA. 

There is a subset of analyses that are the exception to the above paragraph. In the course of 

evaluating the residual heat removal service water system piping and the plant service water system piping in accordance with the NRC's Generic Letters 89-13, "Service Water System Problems 

Affecting Safety-Related Equipment," and 90-05, "Guidance for Performing Temporary Non-Code 

Repair of ASME Code Class 1, 2, and 3 Piping," Bechtel performed calculations to develop 

evaluation levels for measurements on the piping. These levels were founded, in part, on the 

expected thickness of a pipe and upon the predicted wear of that pipe for the remaining service life. 

In these analyses, the corrosion allowance from the pipe specification was assumed to be the 

maximum allowed for the 40-year service life of the piping. The corrosion rate thus defined is used 

in the calculations to predict the expected pipe thickness, and to develop the minimum acceptable 

as-found thickness of the pipe. 

These calculations were instrumental in developing the inspection program for the residual heat 

removal and primary service water piping, much of which is within the scope of license renewal. The 

formulae used in the calculations have been retained in the inspection program procedure used at 

Plant Hatch. 

Therefore, the plant service water and RHR service water inspection program uses one of two 

corrosion rates to predict the minimum acceptable measured pipe wall thickness. The first rate is 

defined by dividing the specified corrosion allowance by 40 years. The second rate is an observed

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corrosion rate based upon several measurements of the pipe wall. The greater of the two corrosion 

rates is used to predict the acceptable minimum wall thickness. The action levels of the procedure 

are also based, in part, on the corrosion rate determined by the corrosion allowance. 

The impact of an extended operating period on the inspection program is minimal. A change to the 

specification-based corrosion rate would not be conservative and is not necessary. Decreasing the 

corrosion rate (by dividing the current allowance by 60 rather than 40 years) is not appropriate, 

because a rate thus calculated would not be conservative. 

The plant service water and RHR service water piping inspection program establishes screening 

levels for the piping. Therefore, the calculations are conservative for the extended term, and do not 

require revision. The plant service water and RHR service water inspection program will continue 

to manage the effects of aging (corrosion) for the extended license term, as required by 10 CFR 

54.21 (c)(1)(i) and (iii). 

General Electric Scope of Supply 

In reviewing the documents within the design records database, the applicant found no GE 

calculation or analysis that explicitly defined the corrosion allowance as a function of 40 years. 

An extended operating period has a minimal impact on the inspection program. A change to the 

specification-based corrosion rate would not be conservative, and is not necessary. Decreasing the 

corrosion rate (by dividing the current allowance by 60 rather than 40 years) is not appropriate, 

because a rate thus calculated would not be conservative. Therefore, the applicant contracted GE 

to make a further determination within its scope of supply. The GE review developed the following 

conclusions about the stainless steel components, general piping, and reactor vessel. For austenitic 

stainless steel components in the Plant Hatch reactor system, the corrosion allowance was not 

explicitly calculated using a 40-year assumption. The corrosion rate for stainless steel under BWR 

conditions is very low, and the corrosion allowance will be adequate through the end of the renewal 

term. With respect to the reactor vessel, GE reviewed its internal communications, reports, and 

open literature to determine the method for calculating the Plant Hatch Unit 1 and 2 corrosion 

allowances. The GE review determined that, in one analysis, a time-dependent corrosion rate was 

used, and that the corrosion allowance was founded on a 40-year assumption for the service life of 

the vessel. Since this corrosion allowance was determined to meet all six criteria, the corrosion 

allowance is a TLAA. GE has evaluated the analysis in question and has determined that corrosion 

allowance assumed is adequate for operation through the end of the renewed license term, as 

required by 10 CFR 54.21 (c)(1)(ii). 

4.3.3 Staff Evaluation 

Bechtel Power Corporation Scope of Supply 

The staff has reviewed the applicant's discussion of the Bechtel Power Corporation scope of supply. 

Bechtel calculated the corrosion allowances on the basis of the type of piping and the environment, 

which the staff agrees is appropriate. The applicant reviewed the calculations, and generally found 

that standard values from Table Al 04.2 of ASME B31.1 were used. After calculating a minimum 

wall thickness, the next higher pipe schedule was selected. The staff agrees that this is standard 

practice. The applicant determined that the calculations in the Bechtel scope of supply generally 

do not meet the definition of a TLAA, and the staff agrees.

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For the plant service water piping and residual heat removal service water piping, the applicant conducted TLAAs on the basis of a 40-year lifetime. The applicant divided the corrosion allowance 

by 40 years to develop a corrosion rate. This corrosion rate is used to determine the minimum pipe wall thickness at any time from the present to the end-of-life. On the basis of this calculation, the applicant developed an inspection plan for the residual heat removal and plant service water piping. Actual pipe wall thickness is measured and compared to the calculated wall thickness. The actual 

corrosion rate is calculated from the measured wall thickness and the time of service. The higher corrosion rate of the calculated value and the measured rate is used to predict the wall thickness 

at end-of-life. Since the corrosion allowance is somewhat arbitrary, the calculated corrosion rate is also arbitrary, and is not a particularly accurate predictor of future wall thickness. However, supplementing the calculated rate with measured rates gives credibility to the program. Therefore, 

the staff finds that this program is acceptable. 

General Electric Scope of Supply 

For the GE scope of supply, the only TLAA was for the service life of the vessel. GE has 

determined that the corrosion allowance is adequate for the extended period of operation. Since 

this conclusion is consistent with industry operating experience, the staff finds that the TLAA for the 

vessel is acceptable. 

4.3.4 Conclusion 

The staff has reviewed the information in Section 4.3, "Corrosion Allowance" of the LRA. On the 

basis of that review, the staff concludes that the applicant has adequately evaluated the corrosion 

allowance TLAA as required by 10 CFR 54.21 (c)(1). 

4.4 Environmental Qualification of Electrical Equipment 

The Plant Hatch 10 CFR 50.49 Environmental Qualification (EQ) Program has been identified as 

a TLAA for the purposes of license renewal. The TLAA aspect of EQ encompasses all long-lived equipment whether active or passive, and each equipment qualification file for a long-lived 

component documents a TLAA. 

The applicant described its TLAA for Environmental Qualification of Electrical Equipment in Section 

4.4, "Environmental Qualification of Electrical Equipment," of the LRA. The staff reviewed this section of the LRA to determine whether the applicant provided adequate information to meet the requirements set forth in 10 CFR 54.21 (c)(1) regarding an evaluation of EQ. The staff also reviewed 

Section 4.4.1 of the LRA to consider the applicant's resolution of Generic Safety Issue (GSI) 168, "Environmental Qualification of Electrical Components." 

4.4.1 Summary of Technical Information in the Application 

The Plant Hatch EQ TLAA evaluation implements 10 CFR 54.21 (c)(1) to demonstrate that (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. Following is a summary 

description of the EQ TLAA.

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Scope of EQ Equipment

Based on a review of the Plant Hatch EQ documentation, the applicant identified electrical 

equipment important to safety that has a qualified life of at least 40 years, during which the electrical 

equipment can perform its intended functions during a LOCA or a high-energy line break (HELB) 

in the harsh environments of the containment and reactor building. The scope of equipment in the 

Plant Hatch EQ program is as follows: 

* Safety-related (in accordance with the definition in 10 CFR 50.49(b), consistent with the 

Plant Hatch CLB) electrical equipment in a postulated harsh environment that is required to 

mitigate the consequences of the accident causing the harsh environment or whose 

subsequent failure can degrade safety systems or mislead the plant operator. 

* Non-safety-related electrical equipment in a postulated harsh environment whose failure 

could impede a safetyfunction or mislead the operator. The impact on emergency operation 

procedures should be considered in the failure analysis. 

* Certain post-accident monitoring equipment located in a postulated harsh environment and 

designated as requiring qualification in the Regulatory Guide 1.97 section of Plant Hatch's 

response to Supplement 1 of NUREG-0737, "Clarification of TMI Action Plan Requirements." 

EQ Process 

The EQ process is controlled by the EQ Master List and the EQ procedures. The EQ Master List 

provides the following equipment information: 

* plant tag number of the equipment 

* the manufacturer and model or series number of the equipment 

• the building, floor elevation, and specific location of the equipment 

* the Qualification Data Package (QDP) which addresses qualification and maintaining 

qualification of equipment 

The EQ Installation/Maintenance Procedure Outline (I/MPO) specifically addresses the following: 

* maintenance required to maintain equipment qualification 

• qualified life of the equipment, any component part to be replaced, and the replacement 

interval (e.g., replace cover o-ring every 18 months) 

0 sealing of the equipment cable entrance to prevent moisture intrusion, as required 

* installation and mounting configurations required to maintain qualification 

* shelf life or storage requirements 

• information on procuring and reordering equipment

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Replacement Equipment

Prior to the expiration of the qualified life of a piece of EQ equipment, the Plant Hatch work 

management system generates a maintenance work order to alert plant personnel that the 

equipment is scheduled for replacement in the near future with the following available options: 

replace the existing component with an identical component 

replace the equipment with different equipment which is already evaluated under the 

EQ program 

replace the equipment with different equipment which is not currently evaluated under the 

EQ program (this option requires an equipment review, a function review, and an EQ review) 

reanalyze qualified life calculations to extend the qualified life if excess conservatism exists 

in the original qualified life calculation. Conservatism may exist in parameters such as the 

assumed ambient temperature of the equipment, an unrealistically low activation energy, or 

in the application of the equipment. The reanalysis is documented in the EQ central file. The 

guidelines in EPRI TR-1 04873, "Methodologies and Procedures to Optimize Environmental 

Qualification Replacement Intervals," are followed. Reanalysis is performed at Plant Hatch 

as follows: 

Analytical Methods - The Arrhenius methodology is the thermal model used to 

reanalyze qualified life calculations. During normal operations, equipment is only 

subjected to ambient humidity levels (20-90 percent). Environmentally qualified 

equipment is typically sealed and cable insulation is protected from occasional 

inadvertent spray. Exposure to moisture from leaks is investigated on a case-by-case 

basis. The analytical method used for radiation reanalysis identified the 40-year 

radiation dose from the EQ criteria manual for the area where the equipment is 

installed, multiplied that value by the ratio of the evaluation period divided by 

40 years (e.g., for license renewal 60 years/40 years, or 1.5), and added the 

applicable accident radiation dose to obtain the total integrated dose for the 

equipment. Plant Hatch has specifically assessed the impact of life extension from 

40 to 60 years on the EQ radiation exposures for both units. 

Data Collection and Reduction Methods - Reducing excess conservatism in the 

equipment service temperatures used in existing analyses is the chief purpose of 

reanalysis. Temperature data for a reanalysis is obtained from actual temperature 

measurements in the area around the equipment being reanalyzed. Temperature 

measurements can be obtained from monitors used for technical specification 

compliance, from other installed monitors, or from temperature sensors on specific 

components. The measurements can also be taken by plant operators during 

surveillance rounds. A representative number of temperature measurements is 

mathematically reduced to arrive at a temperature for the reanalysis. A reanalysis 

may use the actual calculated temperature, or may use the calculated temperature 

to show conservatism in the design temperature.

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Underlying Assumptions - Conservatism in the EQ equipment qualification analyses 

has been maintained sufficiently to absorb environmental changes due to plant 

modifications and events. Major plant modifications or events of sufficient duration 

(such as power uprates) to change temperature, pressure, and/or radiation values 

used in the underlying assumptions or in the EQ calculations are addressed in the 

design phase, prior to implementation of the plant modification, or operational 

change (the process by which changes to the underlying assumptions are made is 

discussed below under "Plant Environmental Changes.") 

Acceptance Criteria and Corrective Actions -Adequate margin as described in IEEE 

Std. 323-1974 and the Division of Operating Reactor Guidelines, is maintained in all 

reanalyses, or adequate justification reducing margin is provided. If the reanalysis 

does not maintain adequate margin and less margin cannot be justified, the 

equipment qualification is not extended and the equipment is replaced as scheduled 

prior to the expiration of the existing qualification. 

Refurbishment of Environmentally Qualified Electrical Equipment 

Equipment in need of refurbishment is typically replaced with new equipment or previously 

refurbished equipment taken out of storage. The removed equipment is then discarded or 

refurbished and placed in storage. Qualified equipment is required to be refurbished before it can 

be put back in storage. Refurbishment is performed in a manner that preserves the equipment's 

qualification. "Soft" items, such as gaskets, seals, and wires, which have a limited life, are typically 

replaced. 

The manufacturer and model of replacement parts with an EQ-limited life are identified in the I/MPO, 

EQ maintenance procedures, and vendor manuals for environmentally qualified equipment. The 

documentation includes guidance on the shelf life of refurbished equipment. 

Procurement of EQ Equipment 

Procurement policies and criteria for environmentally qualified equipment are controlled by site 

procedures and the Nuclear Quality Assurance Program. Procurement of like-for-like replacement 

of environmentally qualified equipment is controlled so that the procured equipment is as good as, 

or better than, the original equipment. The procurement process also assures that applicable 

performance requirements and qualification criteria are met. The component's QDP contains 

procurement information such as the manufacturer or vendor, test reports to be referenced on the 

requisition, and equipment specifications. 

Specifications for procurement are reviewed, and test plans are reviewed and approved prior to 

testing to assure compliance with the specifications. New test reports are evaluated and inserted 

into the QDP, and the EQ Master List is updated. 

Plant Environmental Changes 

Engineering Specification SS-2102-238, documents plant environmental conditions for both normal 

and accident conditions. The harsh environment areas of the plant for LOCAs, HELBs, and 

radiation are identified in accordance with the CLB. The Plant Hatch EQ central file contains 

temperature and pressure profiles for the various accident scenarios, including worst-case

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composite accident profiles for the harsh environments of the containment and reactor building. The 

central file also contains the supporting calculations for these accident profiles and total integrated radiation doses. All specifications, calculations, and other central file documents are controlled 

documents. 

Measurements of critical parameters, such as containment temperatures for technical specifications, 

are taken on an ongoing basis. Changes in environmental parameters are reviewed when found or 

anticipated as a result of an impending design change. When a significant environmental change is identified, a review of the qualification of affected environmentally qualified equipment is 

performed and applicable changes are made to the equipment's qualified life and QDP documentation. The EQ calculations, specifications, and accident profiles are revised, as 

appropriate, to reflect the new operating conditions. 

EQ Generic Safety Issue 

GSI-168 was developed to address environmental qualification of electrical equipment. The staff 

guidance to the industry (letter dated June 2, 1998 from NRC (Grimes) to NEI (Walters)) states: 

GSI-1 68 issues have not been identified to a point that a license renewal applicant can be 

reasonably expected to address these issues, specifically at this time; and 

An acceptable approach is to provide a technical rationale demonstrating that the CLB for 

EQ will be maintained in the period of extended operation. 

For the purpose of license renewal, as discussed in the SOC (60 FR 22484, May 8, 1995), there are 

three options for addressing issues associated with a GSI: 

If the issue is resolved before the renewal application is submitted, the applicant can 

incorporate the resolution into the application. 

An applicant can submit a technical rationale that demonstrates that the CLB will be 

maintained through the period of extended operation until one or more reasonable options become available to adequately manage the effects of aging. 

An applicant can develop a plant-specific aging management program that incorporates a 

resolution to the aging issue. 

To address issues associated with GSI-1 68, the applicant has chosen to pursue the second 

approach. The applicant will continue to manage the effects of aging in accordance with the CLB 

and considers the evaluation of the EQ TLAA in Section 4.4 of the LRA to be the technical rationale 

that demonstrates that the CLB will be maintained until some later point in the period of extended 

operation, when one or more reasonable options become available to adequately manage the 

effects of aging. 

4.4.2 Staff Evaluation 

In accordance with 10 CFR 54.21(c)(1), the staff reviewed Section 4.4 of the LRA to determine 

whether the applicant provided adequate information to meet the requirements that (i) the analyses remain valid for the period of extended operation; (ii) the analyses have been projected to the end

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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. The staff also reviewed the treatment 

of GSI-168 in Section 4.4 of the LRA. After completing the initial review, the staff issued RAIs on 

July 28, 2000, and met with the applicant on August 23, 2000, to discuss RAIs 4.4-1 and 4.4-2 in 

the EQ TLAA area. The staff received the applicant's responses to the RAIs by letter dated October 

10, 2000. 

The applicant is using standard approved EQ methodologies and acceptance criteria, as defined 

by NRC Bulletin 79-01B, "Guidelines for Evaluating Environmental Qualification of Class 1E 

Electrical Equipment in Operating Reactors" (DOR Guidelines), including Supplements 1, 2, and 3; 

NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical 

Equipment," Revision 1; 10 CFR 50.49, "Environmental Qualification of Electric Equipment 

Important to Safety for Nuclear Power Plants"; RG 1.89, " Environmental Qualification of Certain 

Electric Equipment Important to Safety for Nuclear Power Plants," Revision 1; various NRC generic 

letters and information notices; and NRC safety evaluation reports on EQ. The current actions for 

short-lived environmentally qualified equipment are also acceptable for long-lived EQ equipment. 

As discussed below, the staff concurs with the applicant's EQ methodology. 

The applicant is implementing 10 CFR 54.21 (c)(1)(i), (ii), and (iii) for evaluating the EQ TLAA. The 

staff reviewed the following aspects of the applicant's EQ TLAA methodology: 

* Scope of EQ program 

* EQ process 

0 Original qualification basis 

* EQ master list 

* EQ maintenance 

0 Replacement of equipment 

* Replace the existing equipment with identical equipment 

0 Replace the equipment with different equipment currently evaluated under the EQ 

program 

0 Replace the equipment with different equipment not currently evaluated under the 

EQ program 

0 Reanalyze the qualified life calculation 

* Refurbishment of environmentally qualified equipment 

0 Procurement of environmentally qualified equipment 

* Plant environmental changes

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TLAA Demonstration for Option 10 CFR 54.21 (c)(1)(i)

Section 4.4.5 of the LRA lists various commodity types based on Option (i) of 10 CFR 54.21 (c)(1) 

whose analyses remain valid for the period of extended operation. In its response to RAI 4.4-1, the 

applicant provided thermal and radiation summaries for 38 commodity types that are based on 

Option (i). The staff reviewed the analyses and finds the demonstration of 10 CFR 54.21 (c)(1)(i) 

for these commodity types to be acceptable for the period of extended operation. 

TLAA Demonstration for Option 10 CFR 54.21 (c)(1)(ii) 

Section 4.4.5 of the LRA lists various commodity types based on Option (ii) of 10 CFR 54.21 (c)(1) 

whose analyses have been projected to the end of the period of extended operation. During a 

meeting on August 23, 2000, the staff reviewed the EQ calculations for projecting the qualified lives 

of the following sample of commodity types to the end of the period of extended operation: 

* Limitorque SB, SMB Actuators, AC Service 

* General Electric F01 Electrical Penetration Assemblies 

* Amphenol Type HN Plug Connectors 

* States ZWM and NT Series Terminal Blocks 

* Raychem Breakout/Scotchcast 9 Potting Compound 

0 AMP Special Ind. Insulated/Uninsulated Terminals and Splices 

• Okonite Low/Medium Voltage Instrumentation, Control, and Power Cables 

* Okonite T-95 Insulating and No. 35 Jacketing Tapes/Cement 

* Anaconda Low Voltage Instrumentation, Control, and Power Cables 

• GE RHR and Core Spray Pump Motors 

* Brand-Rex Low Voltage Instrumentation, Control, and Power Cables and Internal Panel 

Wiring 

* Conax Buffalo Electrical Penetration Assemblies 

* Eaton (Samuel Moore) Instrumentation and Thermocouple Cables 

* Reliance Motors FNA-6856 and 6857 

Based on the staff's review of the applicant's thermal and radiation summaries and the EQ 

calculations that were reviewed during the August 23, 2000, meeting, the staff finds the 

demonstration of 10 CFR 54.21 (c)(1)(ii) to be acceptable for the Option (ii) commodity types listed 

in Section 4.4.5 of the LRA.

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TLAA Demonstration for the 10 CFR 54.21 (c)(1)(iii) Option

Section 4.4.5 of the LRA lists various commodity types based on Option (iii) of 10 CFR 54.21 (c)(1) 

on which the effects of aging on the intended function(s) will be adequately managed for the period 

of extended operation. For Option (iii) commodity types whose qualified lives could not be extended 

significantly, the Plant Hatch EQ program and the associated site administrative controls have the 

necessary elements to ensure that the effects of aging on the intended function(s) of the qualified 

equipment will be adequately managed for the period of extended operation. For EQ components 

that cannot be qualified to the end of the period of extended operation, aging effects will continue 

to be managed in accordance with the current licensing basis, which requires that equipment be 

replaced or refurbished at the end of its qualified life unless ongoing qualification demonstrates that 

the item has additional life. The staff finds this approach to be an acceptable demonstration of 10 

CFR 54.21 (c)(1)(iii) for managing the effects of aging on environmentally qualified components for 

the period of extended operation. 

GSI-168 Finding 

The staff finds that the applicant's approach to resolving GSI-168 for license renewal (i.e., 

continuing to manage the effects of aging in accordance with the CLB until one or more reasonable 

options become available to adequately manage the effects of aging) is consistent with the June 

2, 1998, staff guidance to industry. 

4.4.3 Conclusion 

The staff has reviewed the EQ TLAA information in Section 4.4 of the Plant Hatch LRA, the 

additional information provided in the August 23, 2000, meeting on EQ between the staff and the 

applicant, and the October 10, 2000, response to the staff's RAIs. On the basis of this review, the 

staff concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21 (c)(1), that, for 

TLAAs related to environmental qualification of electrical equipment, (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. In addition, the staff finds the applicant's approach 

to resolving GSI-168 acceptable. 

4.5 Containment Penetration Pressurization Cycles 

In Section 4.5 of the LRA, the applicant described the time-limited effect of pressurization cycles on 

the design of containment penetrations. The staff reviewed this section of the LRA to determine 

whether the applicant has demonstrated that the effects of aging on the containment penetrations 

will be adequately managed during the period of extended operation, pursuant to10 CFR 

54.21 (c)(1). 

4.5.1 Summary of Technical Information in the Application 

The applicant identified one containment penetration structural analysis for Plant Hatch that 

assumed a number of pressurization cycles over a 40-year period. This calculation was determined 

to meet the definition of a TLAA, as stated in 10 CFR 54.3 and Section 4.1 of this SER. The 

applicant also stated that the architect-engineer performed a structural analysis to determine the 

acceptability of certain types of pipe-to-penetration welds using backing rings. The effects of the

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pressurization cycles on these calculations were stated as being minimal. The applicant also stated 

that the calculation had been extended to 60 years of operation without a change to plant 

equipment, on the basis of Criterion (ii) of 10 CFR 54.21 (c)(1). 

4.5.2 Staff Evaluation 

The staff reviewed the information provided in Section 4.5 of the LRA regarding fatigue analyses 

of containment penetrations, and concluded that additional information was needed to complete its 

review. The staff issued RAIs by letter dated July 28, 2000. By letter dated October 10, 2000, the 

applicant provided responses to the RAIs. The staff has evaluated the applicant's responses, as 

described in the following paragraphs. 

In RAI 4.5-1, the staff requested that the applicant identify the containment penetration for which 

the structural analysis assumed a number of pressurization cycles for 40 years. The RAI requested 

that the applicant provide the location of each penetration, the number of pressurization cycles that 

each was assumed to undergo during the current licensing term, the actual cycles that have been 

experienced, and the number of cycles that are expected until the end of the extended period of 

operation. Since containment penetrations also experience thermal cycling as a result of plant 

operation, the staff also requested that the applicant provide the number of thermal cycles for which 

each penetration had been evaluated. In addition, the staff requested that the applicant provide a 

summary of the structural analysis that was performed to demonstrate the acceptability of the pipe

to-penetration welds using backing rings. 

In its response, the applicant states that the calculation applies to the Class B weld of the main 

steam penetration assembly to the containment, and justifies the use of a backing ring for that type 

and location of weld. In the original calculation, the applicant assumed 40 pressurization cycles to 

full design pressure, and that number was later revised to consider 60 pressurization cycles to full 

design pressure. The applicant stated that this assumption is conservative, and that it had therefore 

demonstrated the acceptability of the analysis in accordance with 10 CFR 54.21(c)(1)(ii). In 

addition, the response indicated that the calculation applies to a Class B weld that is referenced in 

ASME Section III, N-415.1, 1968 Edition, 'Vessels Not Requiring Analysis for Cyclic Operation." Reference to N-415.1 indicates that the stresses attributable to the pressurization cycles were found 

to meet the limiting stress criterion, which does not require a fatigue analysis under the provisions of this section. By letter dated January 24, 2001, the applicant submitted additional (proprietary) 

information, which provided justification for concluding that thermal cycling of the penetration 

assembly does not represent a significant loading condition, which would require a fatigue analysis under the provisions of ASME Section III, N-415.1. The staff reviewed this information and 

concluded that the applicant has demonstrated that this TLAA for the containment penetrations will 

remain valid for the period of extended operation. The staff therefore finds the response to RAI 4.5-1 

acceptable and considers this concern resolved. 

In RAI 4.5-2, the staff requested that the applicant provide information regarding the effect of 

thermal cycling on the drywell and torus vent line penetrations and penetration bellows (including 

vent line bellows), and dissimilar metal welds resulting from reactor mode changes and other 

transients, pressurization pulses during SRV discharges, and pressure cycles during leak testing. 

In its response, the applicant stated that the information requested in this RAI pertaining to 

containment torus penetrations is summarized in the design analysis addressing fatigue in the torus 

for the license renewal period ("Hatch Units 1 and 2 Torus Fatigue Analysis Report, REA HT-98674 

Response", Revision 0, Southern Company Services, Inc., Nuclear Engineering and Regulatory

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Support, April 1999). In Section 4.2.4 of the LRA, the applicant stated that the CLB fatigue 

calculations for the torus structure were reviewed and, on this basis, the applicant determined that 

a new analysis was necessary to address fatigue in the torus for the extended license term. The 

analysis required an extensive and detailed review of pressure and thermal transients for the torus. 

By letter dated January 24, 2001, the applicant provided a (proprietary) summary of this analysis. 

The staff has reviewed this information and concludes that the applicant has demonstrated 

satisfactorily that the fatigue adequacy of the Unit 1 and Unit 2 torus penetrations under the CLB 

transient operating conditions will be maintained during the period of extended operation. The 

applicant also addressed the fatigue adequacy of the drywell penetrations by referencing EPRI 

report TR-1 03840 "BWR Containments License Renewal Industry Report; Revision 1" July 1994, 

which indicates that fatigue of these penetrations subject to the CLB transient operating conditions 

will be minimal for the period of extended operation. The staff finds the response to RAI 4.5-2 

acceptable, and considers this concern resolved. 

In RAI 4.5-3 the staff requested that the applicant provide a list of the containment penetrations with 

pipe-to-penetration welds. In RAI 4.5-4, the staff requested that the applicant provide justification 

for not performing fatigue TLAAs on containment penetrations with pipe-to-penetration welds that 

are susceptible to combined pressurization cycles and plant operational thermal expansion cycles. 

In its response, the applicant stated that the Unit 1 and 2 current licensing bases were reviewed, 

and that no specific analyses on this subject were found that met the criteria of 10 CFR 54.3 for a 

fatigue TLAA. However, the applicant indicated that fatigue of the ASME Code Class 1 welds is 

bounded by the locations monitored in the component cycle and transient limit program. The 

applicant further stated that the fatigue of the Non-Class 1 welds is bounded by the number of 

cycles assumed in the original analysis. The staff concurs with the applicant's response, and 

considers the concerns stated in RAIs 4.5-3 and 4.5-4 resolved. 

4.5.3 Conclusion 

The staff has reviewed the information in Section 4.5 "Containment Penetration Pressurization 

Cycles" of the LRA, the applicant's responses to the staff's RAIs, and the information provided to 

the staff by letter dated January 24, 2001. On the basis of this review, and pursuant to 10 CFR 

54.21 (c)(1), the staff concludes that the applicant has adequately evaluated the containment 

penetration pressurization cycles TLAA. 

4.6 Time-Limited Aging Analyses for the Reactor Vessel 

4.6.1 Summary of Technical Information in the Application 

Neutron Irradiation Embrittlement 

Neutron irradiation causes a decrease in the Charpy upper-shelf energy (USE) and an increase in 

the adjusted reference temperature (ART) of the RPV beltline materials. The ART impacts the 

plant's pressure-temperature (P-T) limits and RPV integrity evaluations. BWRVIP-74 has performed 

integrity evaluations of BWR RPV circumferentially oriented welds and BWR RPV axially oriented 

welds. Therefore, in order to demonstrate that neutron embrittlement does not significantly impact 

RPV integrity during the license renewal term, BWRs must evaluate the impact of neutron irradiation 

on the Charpy USE, ART, RPV circumferential welds, and RPV axial welds.

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Charpy (USE)

By letter dated April 30, 1993, the Boiling Water Reactor Owner's Group (BWROG) submitted a 

topical report entitled "10 CFR Part 50 Appendix G Equivalent Margins Analysis for Low Upper Shelf 

Energy in BWR/2 Through BWR/6 Vessels," to document that BWR RPVs could meet the margins 

of safety against fracture equivalent to those required by Appendix G of the ASME Code for Charpy USE values less than 50 ft-lb. GE performed an update to the USE equivalent margins analysis, 

which is documented in EPRI TR-1 13596, "BWR Vessel and Internals Project BWR Reactor 

Pressure Vessel Inspection and Flaw Evaluation Guidelines," BWRVIP-74, dated September 1999. 

This updated analysis incorporates the effects of irradiation for 54 effective full-power years (EFPY), 

which corresponds to 60 years of operation at 90-percent power. The updated analysis determined 

that the generic materials considered will maintain the margins for USE required by Appendix G of 

10 CFR Part 50. GE reviewed the updated generic analyses with respect to applicability for the Plant 

Hatch license renewal term. This review is documented in an evaluation performed by GE in GENE 

B13-00827-00-01, "Plant Hatch Units 1 and 2 Reactor Pressure Vessel Pressure/Temperature 

Limits License Renewal Evaluation," General Electric Company, dated March 1999. GE determined 

that the generic analyses are applicable and that, for 54 EFPY, the critical materials would retain 

sufficient USE to satisfy the requirements to 10 CFR Part 50 Appendix G. 

Reference Temperature Adiustments 

GE performed a plant-specific analysis of the ARTfor Plant Hatch in GENE B1 1-00827-00-01, using the criteria defined in EPRI TR-1 13596. The GE analysis for Plant Hatch considers the effect of 

neutron embrittlement for 54 EFPY. The analysis includes new sets of reactor operating pressure 

and temperature curves. The results of the analysis indicate that for both units, the ART will be less 

than 200 °F. 

Circumferential RPV Weld Inspection Relief 

The BWRVIP provided the technical bases supporting the elimination of RPV circumferential welds 

from the inservice inspection programs for BWRs in EPRI TR-1 13596. These technical bases are 

approved for the current license term, and are applicable to Plant Hatch. 

Appendix E to the NRC's "Final Safety Evaluation of the BWR Vessel and Internals Project BWRVIP-05 Report (TAC No. M93925)," USNRC, dated July 28, 1998, documents an evaluation 

of the impact of license renewal from 32 EFPY to 64 EFPY on the conditional probability of vessel 

failure. That SER reports that the frequency of cold overpressurization events results in a total 

vessel failure probability of approximately 5 x 10"7. The SER conservatively evaluates an operating 

period of 10 EFPY greater than what is realistically expected for a 20-year license renewal term (i.e. 

48 to 54 EFPY.) Therefore, this analysis provides a basis for BWRVIP-05 to be approved as a 

technical alternative to the current inservice inspection requirements of ASME Section Xl for 

volumetric examination of the circumferential welds as they may apply in the license renewal period. 

Axially Oriented RPV Welds 

The staff's SER, contained in a letter dated March 7, 2000, to Carl Terry, BWRVIP Chairman, 

discusses the staff's concern related to the RPV failure frequency of axial welds, and the BWRVIP's 

analysis of the failure frequency. The SER indicates that the RPV failure frequency attributable to 

failure of the limiting axial welds in the BWR fleet at the end of 40 years of operation is below 5 x

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10-6 per reactor year, given the assumptions regarding flaw density, distribution, and location 

described in the SER. Since the BWRVI P analysis was generic, the applicant provided plant-specific 

information in response to RAI 4.6-2 to demonstrate that the Plant Hatch beltline materials meet the 

criteria specified in the report. 

4.6.2 Staff Evaluation 

Neutron Irradiation Embrittlement 

Appendix G to 10 CFR Part 50 specifies fracture toughness requirements for ferritic materials of the 

pressure-retaining components of the reactor coolant pressure boundary of light-water nuclear 

power reactors. It also provides adequate margins of safety during any condition of normal 

operation, including anticipated operational occurrences and system hydrostatic tests, to which the 

pressure boundary may be subjected over its service lifetime. For the RPV, this appendix requires 

an evaluation of the Charpy USE and ART to determine pressure-temperature limits for the RPV. 

Neutron irradiation causes a decrease in the Charpy USE and an increase in the adjusted reference 

temperature of the RPV beltline materials. The staff's evaluation of the impact of irradiation on the 

Charpy USE, adjusted reference temperature, RPV circumferential weld, and RPV axial weld 

integrity analysis is discussed in this section. Since each of these evaluations are dependent upon 

the neutron fluence received by the RPV, neutron fluence is also discussed in this section. 

Charpy (USE) 

Section IV.A.1 a. of Appendix G to 10 CFR Part 50 requires, in part, that RPV beltline materials must 

have Charpy USE in the transverse direction for base metal, and along the weld for weld material 

of no less than 50 ft-lb (68J), unless it is demonstrated in a manner approved bythe Director, Office 

of Nuclear Reactor Regulation, that lower values of Charpy USE will provide margins of safety 

against fracture equivalent to those required by Appendix G to Section XI of the ASME Code. 

By letter dated April 30, 1993, the BWROG submitted a topical report entitled "10 CFR Part 50 

Appendix G Equivalent Margins Analysis for Low Upper-Shelf Energy in BWR/2 Through BWR/6 

Vessels," to document that BWR RPVs could meet the margins of safety against fracture equivalent 

to those required by Appendix G to the ASME Code for Charpy USE values less than 50 ft-lb. In 

a letter dated December 8, 1993, the staff concluded that the topical report demonstrates that the 

evaluated materials have the margins of safety against fracture equivalent to Appendix G to the 

ASME Code, in accordance with Appendix G to 10 CFR Part 50. In this report, the BWROG derived 

through statistical analysis the initial USE values for materials that originally did not have 

documented Charpy USE values. Using these statistically derived Charpy USE values, the BWROG 

predicted the end-of life (40 years of operation) USE values in accordance with Regulatory Guide 

(RG) 1.99, Revision 2. According to this RG, the decrease in USE is dependent upon the amount 

of copper in the material and the neutron fluence predicted for the material. The BWROG analysis 

determined that the minimum allowable Charpy USE in the transverse direction for base metal and 

along the weld for weld metal was 35 ft-lb. 

GE performed an update to the USE equivalent margins analysis, which is documented in EPRI TR

113596, "BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection and Flaw 

Evaluation Guidelines," BWRVIP-74, dated September 1999. EPRI TR-1 13596 provides a bounding 

Charpy USE for BWR plants for 54 effective full-power years (EFPY). Specifically, the bounding 

analysis for Plant Hatch-type plants (BWR/4) indicates that at 54 EFPY, the Charpy USE in the

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transverse direction for plates would be at least 45 ft-lb, and the Charpy USE for the non-Linde 80 

submerged arc welds (SAWs) would be at least 43 ft-lb. Since these values are greater than the 

minimum allowable Charpy USE of 35 ft-lb, these materials would have margins of safety against fracture equivalent to Appendix G to the ASME Code. Since this was a generic analysis, the 

applicant should provide plant-specific information to demonstrate that the Plant Hatch beltline 

materials meet the criteria specified in the report. 

The analysis in EPRI TR-1 13596 utilized an unirradiated Charpy USE in the longitudinal direction 

of 91 ft-lb for BWR/3-6 plates, and 70.5 ft-lb for non-Linde 80 submerged arc welds. The value for 

the plates is the lowest value from the database, and is less than the lower 95/95 confidence value. 

The value for the non-Linde 80 submerged arc welds is the value corresponding to the lower 95/95 

confidence value. Since these values are statistically determined with at least 95/95 confidence, 

the values may be used in the evaluation of Charpy USE. 

The analysis in EPRI TR-1 13596 determined the reduction in the unirradiated Charpy USE resulting from neutron radiation using the methodology in RG 1.99, Revision 2. Using this methodology with 

a correction factor of 65 percent for conversion of the longitudinal properties to transverse 

properties, the lowest irradiated Charpy USE at 54 EFPY for all BWR/3-6 plates is projected to be 

45 ft-lb. The correction factor for specimen orientation in plates is predicated on NRC Branch 

Technical Position MTEB 5-2, "Fracture Toughness Requirements." July 1981. Using the RG 

methodology, the lowest irradiated Charpy USE at 54 EFPY for BWR non-Linde 80 submerged arc 

welds is projected to be 43 ft-lb. EPRI TR-1 13596 indicates that the percent reduction in Charpy USE for the limiting BWR/3-6 plates and BWR non-Linde 80 submerged arc welds is 23.5 percent and 39 percent, respectively. To demonstrate that the Plant Hatch beltline materials meet the 

criteria specified in the report, the applicant should demonstrate that the percent reduction in Charpy USE for its beltline materials is less than those specified for the limiting BWR/3-6 plates and the 

non-Linde 80 submerged arc welds, and that the percent reduction in Charpy USE for its 

surveillance weld and plate are less than or equal to the values projected using the methodology 

in RG 1.99, Revision 2. 

In its response to RAI 4.6-3 and in Section E of the LRA, the applicant provided plant-specific information necessary to demonstrate that the Plant Hatch beltline materials meet the criteria 

specified in the report. The applicant indicates that the predicted reduction in Charpy USE at 

54 EFPY for the limiting plates in Units 1 and 2 is 19 percent and 15 percent, respectively. The 

predicted reduction in Charpy USE at 54 EFPY for the limiting welds in Units 1 and 2 is 33 percent and 24 percent, respectively. The applicant indicates that the percent reduction in Charpy USE for 

its surveillance weld and plate is less than the values projected using the methodology in RG 1.99, 

Revision 2. The staff has reviewed the information provided by the applicant, and has determined 

that the percent reduction in Charpy USE for the beltline materials and the surveillance materials 

meet the criteria specified in EPRI TR-1 13596. In addition, the staff has also determined that the 

materials and surveillance data reported by the applicant are consistent with data contained in the 

Reactor Vessel Integrity Database (RVID). The RVID is a database maintained by the staff, which 

contains a summary of all of the relevant materials data submitted by all applicants in their 

evaluations of reactor vessel integrity. Since the Plant Hatch beltline material and surveillance weld 

and plate meet the specified criteria, the Plant Hatch beltline materials will meet the margins of 

safety against fracture equivalent to those required by Appendix G to the ASME Code and, 

therefore, will meet the Charpy USE requirements of Appendix G to 10 CFR Part 50 at 54 EFPY.

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ART

The staff evaluated the P-T limit curves prepared on the basis of NRC regulations and guidance, 

including Appendix G to 10 CFR Part 50; GL 88-11, "NRC Position on Radiation Embrittlement of 

Reactor Vessel Materials and Its Impact on Plant Operations"; GL 92-01, "Reactor Vessel Structural 

Integrity," Revision 1; GL 92-01, Revision 1, Supplement 1; and RG 1.99, Rev. 2. GL 88-11 advised 

applicants that the staff would use RG 1.99, Rev. 2, to review P-T limit curves. RG 1.99, Rev. 2, 

contains methodologies for determining the increase in transition temperature and the decrease in 

upper-shelf energy resulting from neutron radiation. GL 92-01, Rev. 1, requested that applicants 

submit their RPV data for their plants to the staff for review. GL 92-01, Rev. 1, Supplement 1, 

requested that applicants provide and assess data from other applicants that could affect their RPV 

integrity evaluations. These data are used by the staff as the basis for the staff's review of P-T limit 

curves. Appendix G to 10 CFR Part 50 requires that P-T limit curves for the RPV be at least as 

conservative as those obtained by applying the methodology of Appendix G to Section Xl of the 

ASME Code. 

SRP Section 5.3.2 provides an acceptable method to determine the P-T limit curves for ferritic 

materials in the beltline of the RPV on the basis of the linear elastic fracture mechanics (LEFM) 

methodology specified in Appendix G to Section Xl of the ASME Code. The basic parameter of this 

methodology is the stress intensity factor K, which is a function of the stress state and flaw 

configuration. Appendix G requires a safety factor of 2.0 on stress intensities resulting from reactor 

pressure during normal and transient operating conditions, and a safety factor of 1.5 for hydrostatic 

testing curves. The methodology specified in Appendix G postulates the existence of a sharp 

surface flaw in the RPV that is normal to the direction of the maximum stress. This flaw is 

postulated to have a depth that is equal to one-quarter thickness (1/4T) of the RPV beltline and a 

length equal to 1.5 times the RPV beltline thickness. The critical locations in the RPV beltline region 

for calculating heatup and cooldown P-T curves are the 1/4T and 3/4 thickness (3/4T) locations, 

which correspond to the maximum depth of the postulated inside and outside surface defects, 

respectively. 

The Appendix G to the ASME Code methodology requires that applicants determine the adjusted 

reference temperature (ART or adjusted RTNDT). The ART is defined as the sum of the initial 

(unirradiated) reference temperature (initial RTNDT), the mean value of the adjustment in reference 

temperature caused by irradiation (ARTNDT), and a margin (M) term. 

The ARTNDT is a product of a chemistry factor and a fluence factor. The chemistry factor is 

dependent upon the amount of copper and nickel in the material, and may be determined from 

tables in RG 1.99, Rev. 2, or from surveillance data. The fluence factor is dependent upon the 

neutron fluence at the maximum postulated flaw depth. The margin term is dependent upon 

whether the initial RTNDT is a plant-specific or generic value, and whether the chemistry factor (CF) 

was determined using the tables in RG 1.99, Rev. 2, or surveillance data. The margin term is used 

to account for uncertainties in the values of the initial RTNDT, the copper and nickel contents, the 

fluence and the calculational procedures. RG 1.99, Rev. 2, describes the methodology to be used 

in calculating the margin term. 

Tables 3-1 and 3-2 in Enclosure 3 to Section E contains the applicant's evaluation of the ART for 

all RPV beltline materials in Plant Hatch Units 1 and 2 at 54 EFPY.

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The material with the highest ART at 54 EFPY in the RPV beltlines of Unit 1 is plate G-4804-2. This 

plate contains 0.13 percent copper and 0.70 percent nickel, which, according to RG 1.99, Revision 

2, corresponds to a chemistry factor of 93.5. This chemistry factor was increased by a factor of 

2.62 on the basis of the test results from the reactor vessel materials surveillance program. This 

results in a chemistry factor for this plate of 245 (93.5 x 2.62). The neutron fluence at the 1/4T 

location for this plate at 54 EFPY is 2.51 El 8 n/cm2 , which corresponds to a fluence factor of 0.625. 

The product of this fluence factor and a chemistry factor of 245 results in a ARTNDT at 54 EFPY of 

153.2 OF. Since the initial RTND-r for this plate is -200 F and the margin term is 34 OF, the ART for this 

plate at 54 EFPY is 167.2 OF. 

The material with the highest ART at 54 EFPY in the RPV beltline of Unit 2 is plate G-6603-2. This 

plate contains 0.083 percent copper and 0.58 percent nickel, which, according to RG 1.99, Revision 

2, corresponds to a chemistry factor of 51. This chemistry factor was determined using Table 2 of 

RG 1.99, Revision 2, since no surveillance data exist for this material. The neutron fluence at the 

1/4T location for this plate at 54 EFPY is 1.67E18 n/cm2 , which corresponds to a fluence factor of 

0.527. The product of this fluence factor and a chemistry factor of 51 results in a ARTNDT at 54 

EFPY of 26.90 F. Since the initial RTNDT for this plate is 240 F and the margin term is 26.90 F, the 

ART for this plate at 54 EFPY is 77.80 F. 

Since the current Plant Hatch P-T limit curves at 54 EFPY meet the requirements of Appendix G to 

10 CFR Part 50, the applicant has demonstrated that the Plant Hatch RPV can operate during the 

license renewal period and satisfy the requirements of Appendix G to 10 CFR Part 50. In the LRA, 

the applicant provided Section E, which proposed a change to the Unit 1 and 2 technical 

specifications in support of extended plant operation. Pressure-temperature operating limits 

predicated on the effects of irradiation on the core beltline up to 32 EFPY were incorporated at the 

time of submittal of the LRA. Subsequently, the applicant submitted its annual update to the LRA, 

dated December 15, 2000. In that update, the applicant removed the proposed change to the 

technical specifications because the applicant has separately requested and received amendments 

to the technical specifications that incorporate changes to the pressure-temperature operating limits. 

However, Enclosure 3 to LRA Section E is retained since it supports certain reactor vessel TLAA 

issues. Those portions of Enclosure 3 that specifically address the pressure-temperature limits are 

superseded by the separate licensing action taken by the NRC in issuing Amendments 222 and 163 

to the Unit 1 and Unit 2 operating licenses, respectively. 

Circumferential RPV Weld Inspection 

Sections 4.6.3 and A.1.17.1 of the LRA discuss ultrasonic inspection of the Plant Hatch RPV 

circumferential welds. Section A.1.17.1 of the LRA indicates that Plant Hatch will use an approved 

technical alternative in lieu of ultrasonic testing of RPV circumferential shell welds. The technical 

alternative is discussed in the staff's final SER of the BWR Vessel and Internals Project BWRVIP-05 

Report, which is contained in a letter dated July 28, 1998 to Carl Terry, BWRVIP Chairman. In that 

letter, the staff concludes that, since the failure frequency for circumferential welds in BWR plants 

is significantly below the criteria specified in RG 1.154, "Format and Content of Plant-Specific 

Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors," and the core 

damage frequency (CDF) of any BWR plant, and since continued inspection would result in a 

negligible decrease in an already acceptably lowvalue, elimination of the ISI for RPV circumferential 

welds is justified. The staff's letter indicates that BWR applicants may request relief from the 

inservice inspection requirements of 10 CFR 50.55a(g) for volumetric examination of circumferential 

RPV welds by demonstrating (1) at the expiration of the license, the circumferential welds satisfy

4-25
the limiting conditional failure probability for circumferential welds in the evaluation, and (2) they 

have implemented operator training and established procedures that limit the frequency of cold 

overpressure events to the amount specified in the report. The letter indicated that the requirements 

for inspection of circumferential RPV welds during an additional 20-year license renewal period will 

be reassessed, on a plant-specific basis, as part of any BWR license renewal application. 

Section A.4.5 of Report BWRVIP-74 indicates that the staff's SER conservatively evaluated BWR 

RPVs to 64 effective full-power years (EFPY), which is 10 EFPY greater than what is realistically 

expected for the end of the license renewal period. Since this was a generic analysis, the applicant 

must provide plant-specific information to demonstrate that the Plant Hatch beltline materials meet 

the criteria specified in the report. 

In response to RAI 4.6-1, the applicant indicates that procedures and training used to limit cold 

overpressure events during the license renewal period will be the same as those approved by the 

NRC when Plant Hatch requested that the BWRVIP-05 technical alternative be used for the current 

term. In addition, the applicant compared the mean RTNDT for Combustion Engineering fabricated 

welds from the staff's SER dated July 28, 1998, to the mean RTNDT of the circumferential welds in 

Plant Hatch Units 1 and 2 at 54 EFPY. The mean RTNDT values in the staff's SER were determined 

for the limiting BWR RPVs that were fabricated by Combustion Engineering, Babcock and Wilcox, 

and Chicago Bridge and Iron. Since the Plant Hatch RPVs were fabricated by Combustion 

Engineering, the results from the staff's SER are applicable to Plant Hatch. However, the mean 

RTNDT values projected for the circumferential welds at Plant Hatch were calculated using the 

neutron fluence at the 1/4T location, and included a margin term. The mean RTNDT in the staff's 

SER was determined using the neutron fluence at the clad/weld metal interface, and did not include 

a margin term. In a letter dated January 31, 2001, the applicant revised its analysis on the basis 

of the projected neutron fluence at the clad/weld interface, and did not include a margin term when 

calculating the mean RTNDT. The mean RTNDT of the circumferential welds in Hatch at 54 EFPY is 

less than the values for Combustion Engineering vessel (using Combustion Engineering Owners 

Group chemistries) at 32 EFPY and 64 EFPY, which indicates that the Plant Hatch circumferential 

welds will be less embrittled than the Combustion Engineering vessel in the NRC staff analysis at 

32 EFPY and 64 EFPY. The staff SER indicates that the conditional failure probabilities for the 

Combustion Engineering vessel at 32 EFPY and 64 EFPY were 6.34E-5 and 4.38.34E-4, 

respectively. Since the Hatch circumferential welds will be less embrittled than the Combustion 

Engineering vessel analyzed in the staff's SER, the conditional failure probability for the Hatch RPVs 

will be less than the values specified in the staff's SER for circumferential welds. Therefore, the 

applicant has demonstrated compliance with the criteria in the letter dated July 28, 1998, to Carl 

Terry, and has justified relief from the inservice inspection requirements of 10 CFR 50.55a(g) for 

volumetric examination of circumferential RPV welds during the license renewal period. 

Axially Oriented RPV Welds 

In its letter dated July 28,1998, to Carl Terry, BWRVIP Chairman, the staff also identified a concern 

about the failure frequency of axially oriented welds in BWR RPVs. In its response to this concern, 

the BWRVIP provided evaluations of axial weld failure frequency in letters dated December 15,1998 

and November 12, 1999. The staff's evaluation of these analyses is contained in a letter dated 

March 7, 2000, to Carl Terry. The SER that is enclosed in that letter indicates that the RPV failure 

frequency as a result of the failure of the limiting axial welds in the BWR fleet at the end of 40 years 

of operation is below 5 x 106 per reactor year, given the assumptions regarding flaw density, 

distribution, and location described in the SER. Since the results apply only for the initial 40-year

4-26
license period of BWR plants, applicants for license renewal must provide plant-specific information 

applicable to 60 years of operation. 

The BWRVIP identified Clinton and Pilgrim as the reactor vessels with the highest mean RTNDT in 

the BWR fleet. The staff confirmed this conclusion in its SER by comparing the information 

contained in the BWRVIP analysis and the information contained the RVID for all BWR RPV axial 

welds. The staff performed analyses of the Clinton and Pilgrim plants. The results from the staff's 

calculations are provided in Table 1. The staff's calculations used the basic input information for 

Pilgrim, with three different assumptions for the initial RTNDT. The calculations of the actual Pilgrim 

condition used the docketed initial RTNDT of -480F and a mean RTNDT of 680F. A second calculation, 

listed as "Mod 1" in Table 1, is consistent with the BWRVIP calculations, with an initial RTNDT of 0°F 

and a mean RTNDT of 116 0F. A third calculation, with an initial RTNDT of -2°F and a mean RTNDT of 

1140F, was chosen to identify the mean value of RTNDT required to provide a result that closely 

matches the RPV failure frequency of 5 x 10"6 per reactor-year. 

Table 1: Comparison of Results from Staff and BWRVIP 

Initial Mean Vessel Failure Freq. 

Plant RTNDT RTNDT 

(OF) (OF) Staff BWRVIP 

Clinton -30 91 2.73E-6 1.52E-6 

Pilgrim -48 68 2.24E-7 

Mod 1 * 0 116 5.51E-6 1.55E-6 

Mod 2* -2 114 5.02E-6 

* A variant of Pilgrim input data, with initial RTNDT = 0°F 

•* A variant of Pilgrim input data, with initial RTNDT = -20F 

The applicant provided plant-specific information in response to RAI 4.6-2 to demonstrate that the 

Plant Hatch beltline materials meet the criteria specified in the SER. The mean RTNDT for the Plant 

Hatch axial welds were not compared to the mean RTNDT in Table 1. Instead, the mean RTNDT was 

compared to the mean RTNDT for axial welds in the staff's SER dated July 28, 1998. The SER in the 

letter dated March 7, 2000, supersedes the analysis in the letter dated July 28, 1998. In a letter 

dated January 31,2001, the applicant revised its analysis to compare the mean RTNDT for the Plant 

Hatch axial welds to the mean RTNDT for Pilgrim Mod 2 in Table 1, above. The mean RTNDT of the 

axial welds at Hatch at 54 EFPY was less than 114 0 F for both units. This value is less than the 

value for Pilgrim Mod 2 in Table 1, which indicates that the Hatch axial welds at 54 EFPY will be less 

embrittled than the axial welds for the Pilgrim Mod 2 analysis performed by the staff in its letter 

dated March 7, 2000. Since the Plant Hatch axial welds will be less embrittled than the axial welds 

for the Pilgrim Mod 2 analysis performed by the staff in its letter dated March 7, 2000, the conditional 

failure probability for the Plant Hatch RPVs will be less than 5 x 10.6 per reactor-year at 54 EFPY. 

Therefore, the applicant has demonstrated compliance with the criteria in the staff's letter dated 

March 7, 2000.

4-27
Neutron Fluence of the RPV

The Charpy USE, ART, circumferential weld, and axial weld RPV integrity evaluations are all 

dependent upon the neutron fluence. The neutron fluences for the Plant Hatch units were 

calculated using the General Electric methodology documented in surveillance capsule reports GE

NE-B1 100691-01 R1 (March 1997) and SASR 90-104 (May 1991). These neutron fluences were 

determined by taking the fluence at 32 EFPY associated with the approved extended power uprate, 

and adding to it the fluence that would accumulate during an additional 22 EFPY of operation at the 

flux associated with the extended power uprate conditions. The extended power uprate was 

approved in a letter to HL Sumner, Jr., dated October 22, 1998; therefore, the neutron fluences 

documented in the LRA are acceptable at this time. 

4.6.3 Conclusions 

The staff has reviewed the information in Section 4.6, "Reactor Vessel TLAAs" of the LRA and the 

applicant's responses to the staff's RAIs. On the basis of this review, the staff concludes that the 

applicant has adequately evaluated the reactor vessel TLAA as required by 10 CFR 54.21 (c)(1). 

4.7 Main Steam Isolation Valves Operating Cycles 

4.7.1 Introduction 

The applicant described its evaluation related to main steam isolation valve operating cycles in 

Section 4.7, "Main Steam Isolation Valves Operating Cycles," of the LRA. The staff reviewed this 

section of the LRA to determine whether the applicant has adequately evaluated the TLAA as 

required by 10 CFR 54.21(c). 

4.7.2 Summary of Technical Information in Application 

The Plant Hatch UFSARs contain statements with regard to the design of the MSIVs for the current 

license term. Section 5.5.5.1of the Unit 2 UFSAR, states the following (with a similar reference in 

Section 4.6.3 of the Unit 1 UFSAR): 

"The design objective for the valve is a minimum 40-year service at the specified operating 

conditions. Operating cycles are estimated to be 100 cycles per year during the first year and 

50 cycles per year thereafter." 

The applicant further stated that the UFSAR statement refers to mechanical cycles of the valve. 

Cycling of the valve will lead to wear of the valve disc and valve seat. The wear will accumulate over 

time, (2050 cycles are assumed in the UFSAR statement for 40 years.) The statement, therefore, 

meets the criteria of a TLAA. However, this type of wear as a result of valve operation will lead to 

performance degradation that can be discovered through normal leakage monitoring testing. 

Excessive leakage would lead to refurbishment or repair of the valve set and disc, as necessary. 

Once the maintenance is performed, the service life of the valve would be restored. Since the aging 

effects can be readily discovered through normal Technical Specification surveillance testing and 

repairable maintenance, the TLAA is demonstrated through Criterion (iii) of 10 CFR 54.21 (c)(1).

4-28
4.7.3 Staff Evaluation

As described above, the applicant dispositioned this TLAA through Criterion (iii) of 10 CFR 

54.21(c)(1). Under this disposition option, the applicant should demonstrate that the effects of aging 

on the components' intended functions will be adequately managed in a manner that is consistent 

with the CLB throughout the period of extended operation. In addition, the FSAR Supplement for 

the facility should contain a summary description of the programs and activities for managing the 

effects of aging and the evaluation of the TLAA throughout the period of extended operation. 

In RAI 4.7-1, dated July 28, 2000, the staff requested that the applicant provide information as 

described in 10 CFR 54.21 (c)(1 )(iii). The applicant responded to this RAI in its letters dated October 

10, 2000, and January 31,2001. The applicant stated that at the time of the LRA submittal, GE had 

been unable to fully determine the basis for the MSIV cycles in the UFSAR. Therefore, as a 

conservative measure, the applicant identified the MSIV cycles in the UFSAR as a TLAA. Since that 

time, GE has determined that the number is derived from a specification, not from a calculation or 

analysis, as discussed in the Rule. On the basis of this confirmation from GE, the applicant has now 

determined that the MSIV cycles do not constitute a TLAA. The applicant also noted that, outside 

the scope of license renewal, the MSIVs are extensively tested as part of existing Technical 

Specification requirements because the valves are within the purview of that rule, and are being maintained in a manner that is consistent with the requirements of the maintenance rule. The 

applicant noted that the MSIVs have extensive testing programs that implement containment 

isolation testing and valve stroking requirements contained in Technical Specification 3.6.1.3. There 

are also inspection procedures to address the wear of the stellite faces. The MSIVs are periodically 

disassembled and refurbished. The solenoid valves and limit switches on the valves are also 

routinely replaced or completely refurbished to address environmental qualification requirements. 

In addition, there are other repetitive tasks, such as replacing the actuator hydraulic fluid every 54 

months, and inspecting the wiring every 36 months. In addition, the applicant stated that because 

these valves are periodically tested and refurbished, as necessary, GE has indicated that it is 

appropriate to restore the valve service life when valve internals are refurbished. 

On the basis of this supporting information, even if the assumption were made that the UFSAR text 

constituted a de facto TLAA that is not directly supported by a calculation or analysis, the periodic restoration of the valve service life results in the supposed TLAA failing the criterion that the 

calculation or analysis must be relevant to making a safety-related determination. The applicant 

further noted that although the MSIV cycles do not constitute a TLAA as presented in the LRA, the 

MSIV valve bodies are within the scope of license renewal and are subject to an AMR. 

4.7.4 Conclusion 

The staff has reviewed the information in Section 4.7, "Main Steam Isolation Valves Operating 

Cycles" of the LRA and the applicant's responses to the staff's RAI. On the basis of this review, 

the staff concludes that the applicant's responses are reasonable and sufficient for concluding that 

MSIV operating cycles do not constitute a TLAA and, therefore, are acceptable.

4-29
5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 

During the 481 meeting of the Advisory Committee on Reactor Safeguards (ACRS) on April 5, 

2001, the ACRS reviewed the NRC staff's safety evaluation report (SER) related to the license 

renewal application (LRA) for the Edwin I. Hatch Nuclear Plant, Units 1 and 2 (Plant Hatch). The 

ACRS Subcommittee on Plant License Renewal initially reviewed the SER prior to its meeting with 

the NRC staff and the applicant on March 28, 2001, and presented its findings during the April 5, 

2001 ACRS Full committee meeting. On April 16,2001, the ACRS Full committee issued an interim 

letter on its review of the Plant Hatch license renewal SER with open items. 

The staff issued its final SER related to the LRA for Plant Hatch, with the resolution of the open items, on October 5,2001. The staff briefed the ACRS License Renewal Subcommittee on October 

25, 2001. During the 487' meeting of the ACRS Full committee on November 8, 2001, the ACRS 

completed its review of the Plant Hatch LRA and the staff's SER, and documented its findings in a 

letter dated November 16, 2001. A copy of that letter is provided.

5-1
November 16, 2001

The Honorable Richard A. Meserve 

Chairman 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

Dear Chairman Meserve: 

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION FOR THE EDWIN I. HATCH NUCLEAR PLANT, UNITS 1 AND 2 

During the 4 8 7 th meeting of the Advisory Committee on Reactor Safeguards, November 8-10, 

2001, we completed our review of the Southern Nuclear Operating Company's (SNC's) 

application for license renewal of the Edwin I. Hatch Nuclear Plant, Units 1 and 2, and the 

related final Safety Evaluation Report (SER). We issued an interim letter concerning this 

application and the SER with open items on April 16, 2001, and our Plant License Renewal 

Subcommittee held discussions with representatives of the staff and SNC on October 25, 2001. 

We also had the benefit of the documents referenced. 

Conclusions and Recommendations 

1. The SNC application for renewal of the operating licenses for Hatch, Units 1 and 2, should be 

approved. 

2. The programs instituted to manage aging-related degradation are appropriate and provide 

reasonable assurance that Hatch, Units 1 and 2, can be operated safely in accordance with 

their licensing bases for the period of extended operation without undue risk to the health and 

safety of the public. 

3. The staff has performed a comprehensive review of SNC's application. The open items 

identified in the February 2001 draft SER have been resolved satisfactorily. 

4. The SER clarifies staff positions on non-safety-related seismic Il-over-I piping systems, long

lived passive components of skid-mounted complex assemblies, fan housings, and damper 

frames. These clarifications provide significant guidance that could prevent these issues from 

becoming open items in future applications. They should be incorporated into the generic 

license renewal guidance documents.

5-2
Background and Discussion

This report fulfills the requirement of 10 CFR 54.25 that the ACRS review and report on license 

renewal applications. SNC requested renewal of the operating licenses for Hatch, Units 1 and 2, 

for a period of 20 years beyond the current license terms, which expire on August 6, 2014, for 

Unit 1, and June 13, 2018, for Unit 2. The final SER documents the results of the staff's review 

of information submitted by SNC, including those commitments that were necessary to resolve 

open items identified by the staff in its February 2001 draft SER. The staff's review included the 

verification of the completeness of structures, systems, and components (SSCs) identified in the 

application, the validation of the integrated plant assessment process, the identification of the 

possible aging effects associated with each passive long-lived component, and the verification of 

the adequacy of the aging management programs. The staff also conducted site inspections to 

verify the adequacy of the implementation of the methodology described in the application. 

As noted in our April 16, 2001 interim letter, the SNC's approach to identifying SSCs that are 

within the scope of the License Renewal Rule is function-based, rather than the system-based 

approach used in previous applications. This approach was adequate, but made it difficult for 

the reviewers to ascertain which SSCs were in scope and which were not. The staff's review 

relied heavily on supporting documents located at the site and on requests for additional 

information. In addition, the staff performed a "walk-through" of the process for three systems 

that are within scope. On the basis of its extensive review, the staff identified some additional 

components that the applicant should have included within the scope of license renewal, and 

classified them as open items. These open items have been resolved by including the additional 

components in scope. We concur with the staff that the applicant has now properly identified 

SSCs requiring an aging management review. 

Components brought into scope through the resolution of open items include non-safety-related 

seismic Il-over-I piping systems, long-lived passive components of skid-mounted complex assemblies, fan housings, and damper frames. The inclusion of these components was 

contested in previous license renewal applications. The issue of seismic Il-over-I piping is an 

open item in an application that is currently under review. The Hatch SER includes effective 

clarifications of why these components need to be included within scope. The guidance 

provided by these clarifications could prevent these issues from becoming open items in future 

applications. Consequently, these clarifications should be incorporated into the generic license 

renewal guidance documents. 

SNC has conducted a comprehensive aging management review of SSCs that are within scope. Aging effects were identified on the basis of component material, operating environment, and 

operating stresses using plant-specific and industry-wide operating experience. Topical reports developed by the Boiling Water Reactor Vessel and Internals Project (BWRVIP) were also used 

to identify aging effects and to develop aging management programs that support the Hatch 

application. We reviewed a number of BWRVIP topical reports and commented on their 

effectiveness in supporting license renewal in our April 16, 2001 letter. 

Appendix A to the Hatch application describes 17 existing programs, 5 modified programs, and 7 

new programs that SNC has implemented to manage aging effects during the period of 

extended operation. The resolution of open items has resulted in added commitments to these 

programs, including a one-time inspection of plant service water piping in the diesel generator building and a one-time inspection of small-bore butt-welded stainless steel piping.

5-3
One of the added commitments resulting from resolution of open items involves periodic testing of fire-protection system sprinkler heads that are within the scope of license renewal. SNC had 

proposed a one-time test of such sprinkler heads at or before the start of the period of extended 

operation. The staff did not agree with the one-time test, because the design life (50 years) of 

the sprinkler heads does not cover the period of extended operation. As recommended by the 

staff, SNC has committed to perform the sprinkler head tests as specified in the National Fire 

Protection Association (NFPA) Standard 25, Section 2.3.3.1, "Sprinklers." The application of this 

Standard will result in periodic testing of the sprinkler heads at 10-year intervals, with the first 

test taking place during the third year of the renewal period. This program is acceptable because it confirms the effectiveness of the periodic inspections to which the sprinkler heads are 

subjected and ensures testing of the sprinkler heads early in the renewal period. 

The staff requested that SNC perform a one-time inspection of the four buried emergency diesel 

generator (EDG) fuel oil storage tanks. SNC responded by performing visual inspections and 

ultrasonic testing of one of the four tanks. Ultrasonic testing of 144 locations along the lower 

shell of the tank indicated that there was no thinning of the wall. Visual inspections of the 

internal surface revealed very little corrosion. SNC and the staff concluded that the one-time 

inspection demonstrated that loss of material of the diesel fuel oil storage tanks was not an 

aging effect requiring management during the period of extended operation. 

We also considered the possibility that the external coating of a tank could be damaged at some 

location during installation and result in localized fuel oil leakage. Such damage would be of 

concern during the current license term and, thus, would not be specific to the period of 

extended operation. The safety consequences would not be significant because the potential leakage would not cause substantial depletion of the fuel oil inventory before it would be 

detected. We concur with the staff's determination that loss of material of the diesel fuel oil 

storage tanks is not an aging effect requiring management during the period of extended 

operation. 

Jet pump assemblies and fuel supports contain cast austenitic stainless steel (CASS) 

components that are within the scope of license renewal. These components may be exposed 

to neutron fluence levels that would make them susceptible to neutron irradiation embrittlement 

and loss of fracture toughness. Since neutron embrittlement becomes a concern when cracks 

are present in the components, the staff requested that SNC propose a one-time inspection of 

the jet pump assemblies and fuel supports to confirm that these CASS components have not 

experienced cracking. Following this request, the staff recognized that cracking of CASS 

components has not been observed to date. Furthermore, BWRVIP-41, "BWR Jet Pump 

Assembly Inspection and Flaw Evaluation Guidelines," requires inspections of jet pump assembly welds that are generally believed to be more susceptible to cracking than the CASS 

components and, therefore, provide a leading indicator for inspection of CASS components. 

SNC has committed to perform the weld inspection required by BWRVIP-41. In addition, the 

BWRVIP and the NRC's Office of Nuclear Regulatory Research plan to conduct confirmatory research to determine the effects of high levels of neutron fluence on BWR internals. SNC has 

committed to implement any requirements resulting from this research. Given the above, the 

staff concluded that the requested one-time inspection is not warranted at this time. We agree 

with the staff's conclusion. 

Time-limited aging analyses (TLAA) have shown that neutron irradiation embrittlement during 

the extended period of operation will have no significant impact on the integrity of the Hatch

5-4
reactor vessels. At the end of the renewal period, the vessels will still have margin over 

applicable regulatory limits. In order to monitor time-dependent parameters used in the TLAA, 

SNC plans to implement the provisions of the integrated surveillance program (ISP) described in 

BWRVIP-78, "BWR integrated surveillance program plan," and BWRVIP-86, "BWR integrated 

surveillance program implementation plan. "Since these topical reports have not yet been 

approved by the staff, SNC committed to implement either a staff-approved ISP or a plant specific program that meets specific staff requirements on periodic removal of capsules to 

monitor neutron fluence and the impact of irradiation on the reactor vessels. SNC committed to 

provide the staff with program details prior to the period of extended operation. The staff made 

this commitment a license condition. 

The staff has performed a comprehensive review of SNC's application. The applicant and the 

staff have identified plausible aging effects associated with passive and long-lived components. Adequate programs have been established to manage the effects of aging so that Hatch, Units 1 

and 2, can be operated safely in accordance with their current licensing bases for the period of 

extended operation. 

Sincerely, 

George E. Apostolakis 

Chairman 

References: 

1. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License 

Renewal of the Edwin I. Hatch Nuclear Plant, Units 1 and 2," issued October 2001. 

2. U. S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License 

Renewal of the Edwin I. Hatch Nuclear Plant, Units 1 and 2," issued February 2001. 

3. Letter dated February 29, 2000, from H. L. Sumner, SNC, to the U.S. Nuclear Regulatory 

Commission, "Edwin I. Hatch Nuclear Plant Application for Renewed Operating Licenses." 

4. Letter dated April 16, 2001, from George E. Apostolakis, Chairman ACRS, to William D. 

Travers, Executive Director for Operations, NRC, Subject: Interim Letter Related to the 

License Renewal of Edwin I. Hatch Nuclear Station, Units 1 and 2. 

5. Topical Report BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation 

Guidelines," October 1997. 

6. Topical Report BWRVIP-78, "BWR Integrated Surveillance Program - Unirradiated Charpy 

Reference Curves for Surveillance Material," December 1999. 

7. Topical Report BWRVIP-86, "BWR Vessel and Internals Project, BWR Integrated 

Surveillance Program Implementation Plan."

5-5
6 CONCLUSIONS

The staff reviewed the Edwin I. Hatch Nuclear Plant, Units 1 and 2, license renewal application in accordance with Commission regulations and the NRC draft "Standard Review Plan for the 

Review of License Renewal Applications for Nuclear Power Plants," dated September 1997. In 

10 CFR 54.29, the staff identifies the standards for issuance of a renewed license. 

On the basis of its evaluation of the application as discussed above, the staff has determined 

that the requirements of 10 CFR 54.29(a) have been met. 

The staff notes that the requirements of subpart A of 10 CFR Part 51 are documented in the 

final plant-specific supplement to the Generic Environmental Impact Statement, dated May, 

2001.

6-1
APPENDIX A

CHRONOLOGY 

This appendix contains a chronological listing of routine licensing correspondence between the 

U.S. Nuclear Regulatory Commission (NRC) staff and Southern Nuclear Operating Company, 

Inc. (the applicant) regarding the staff's review of the Edwin I. Hatch Nuclear Plant, Units 1 and 

2, Hatch, application for license renewal (Docket Nos. 50-321 and 50-366.)

October 27, 1997 

January 15, 1998 

April 13, 1998 

April 13, 1998 

May 3, 1998 

January 7, 1999 

January 25, 1999 

May 14,1999

In a letter (signed by H. L. Sumner) SNC indicated its intention to 

proceed forward with preparing a license renewal application for 

Plant Hatch Units 1 and 2 and requested a waiver of review fees 

(ACN 9711040157) 

In a letter (signed by H. L. Sumner) SNC informed NRC of its plans for product submittals for 1998 (ACN 9801230066) 

In a letter (signed by H. L. Sumner) SNC informed NRC of its 

support for Baltimore Gas & Electric Company's License Renewal 

Application for Calvert Cliffs Nuclear Power Plant. 

In a letter (signed by H. L. Sumner) SNC submitted its License 

Renewal Process Methodology Document for Plant Hatch (ACN 

9804220149) 

In a letter (signed by S. Collins) NRC acknowledged SNC's interest 

in license renewal for Plant Hatch (ACN 9805060036) 

In a letter (signed by H. L. Sumner) SNC submitted the Hatch, 

Intake Structure Licensing Report as an example of the technical 

content and level of detail that Plant Hatch is planning for its 

application for license renewal (ACN 9901130111) 

In a letter (signed by W. G. Hairston) SNC informing the NRC of its 

support for the Commission's recent initiatives to streamline the 

hearing process (ACN 9903160142) 

In a letter (signed by H. L. Sumner) SNC submitted the attached 

Recirculation System Pressure Boundary Licensing Report to 

provide the NRC with an example of the technical content and level 

of detail that Plant Hatch is planning for its application for License 

Renewal (ML003704042)

A-1
November 12, 1999

January 24, 2000 

February 29, 2000 

February 29, 2000 

March 3, 2000 

March 24, 2000 

April 4, 2000 

April 4, 2000 

April 6, 2000 

April 12, 2000

In a letter (signed by H. L. Sumner) SNC requested exemption 

from 10 CFR 50.30(a)(2), 51.55(a), and 2.101 (a)(3), and requested 

exception to 10 CFR 50,4(b) and 50.4(c): written submittal 

requirements (ML993270222) 

In a letter (signed by B. Shelton) NRC responded to SNC's request 

for exemption from 10 CFR 50.30(a)(2), 51.55(a), and 2.101 (a)(3), 

and request for exception to 10 CFR 50.4(b) and 50.4(c): written 

submittal requirements (ML003677239) 

In a letter (signed by H. L. Sumner) SNC submitted its License 

Renewal Application (LRA) for Edwin I. Hatch Nuclear Plant, 

Units 1 and 2, (Hatch) (ML003688151) 

In a letter (signed by H. L. Sumner) SNC submitted its associated 

evaluation boundary drawings for the Plant Hatch Application for 

Renewed Operating Licenses (ML003688222) 

In a letter (signed by C. Grimes) NRC informed SNC of the receipt 

of the Edwin I. Hatch, Units 1 and 2, LRA and Assignment of a 

Project Manager (ML00368881 1) 

In a letter (signed by C. Grimes) NRC informed SNC of the 

determination of acceptability and sufficiency for docketing, 

proposed review schedule, and opportunity for a hearing regarding 

an application from SNC for renewal of the operating licenses for 

Units 1 and 2 of the Edwin I. Hatch Nuclear Plant (ML003695605) 

In a letter (signed by D. Matthews) NRC informed SNC of the 

preparation of a notice of intent that advises the public that the 

NRC intends to gather information necessary to prepare a plant

specific supplement to the Commission's "Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants," 

(NUREG-1437) in support of the review of the application for the 

renewal of the Hatch operating license. 

In an electronic correspondence (signed by R. Baker) SNC 

provided the expanded matrix of programs/activities and 

commodity groups with a "system" column added. 

In a memorandum (signed by W. Burton) NRC issued a public 

meeting notice to the stakeholders and the public and informed 

them of a meeting to be held on April 12, 2000, with SNC to 

familiarize the staff reviewers with Hatch scoping methodology and 

boundary drawings (ML0037000062) 

Federal Register Notice announcing environmental scoping 

meeting

A-2
April 14, 2000 

April 28, 2000 

May 1, 2000 

May 4, 2000 

May 23, 2000 

May 24, 2000 

May 24, 2000 

May 30, 2000 

May 31, 2000 

June 1,2000

In a memorandum (signed by W. Burton) NRC provided SNC with 

a summary of the April 19, 2000, teleconference with SNC 

regarding aging management program A.3.7 of the Hatch LRA, 

"Torus Submerged Components Inspection Program." 

In a memorandum (signed by R. K. Anand) NRC issued a public 

meeting notice to stakeholders and the public and informed them 

of a meeting to be held on May 8, 2000, with SNC to discuss 

progress of aging management program review of SNC's LRA for 

Hatch. 

In a memorandum (signed by W. Burton) NRC provided SNC with 

a summary of the working meeting on April 12, 2000, with SNC, 

regarding scoping review for Hatch LRA. 

In a memorandum (signed by S. Hoffman) NRC issued a public 

meeting notice to stakeholders and the public and informed them 

on a meeting to be held on May 17, 2000, between the NRC's 

License Renewal Steering Committee with the Nuclear Energy 

Institute's (NEI's) License Renewal Working Group to discuss NRC 

and industry generic license renewal activities 

In an electronic correspondence (signed by R. Baker) SNC 

provided the requested recent board changes in Oglethorpe Power 

Corporation. 

Changes to Oglethorpe Power's principal officers (ML003718346) 

In an electronic correspondence (signed by R. Baker) SNC 

submitted a database sort of unctions on a system-by-system 

basis and another sort of present systems on a function-by

function basis (ML003718384) 

In a letter (signed by J. H. Wilson) NRC requested additional 

information related to the staff's review of Severe Accident 

Mitigation Alternatives for Hatch (ML003719228) 

In a letter (signed by H. L. Sumner) SNC provided additional 

information supporting license renewal environmental report and 

submitted a copy of a matrix developed during SNC's review of 

Category 1 items for new and significant information 

(ML003719941) 

In a memorandum (signed by R. Prato and W. Burton) NRC 

provided SNC with a summary of the May 17, 2000, meeting with 

Entergy and SNC regarding license renewal activities for Arkansas 

Nuclear One - Unit 1 (ANO-1) and Hatch (ML003720297)

A-3
June 4, 2000 

June 16, 2000 

June 20, 2000 

June 20, 2000 

June 23, 2000 

June 27, 2000 

June 27, 2000 

July 14, 2000 

July 26, 2000 

July 26, 2000 

July 28, 2000 

August 11, 2000

Supplement to May 10, 2000 testimony and additional statement 

(ML003722562) 

In an electronic correspondence (signed by R. Baker) SNC 

provided a revised function to system matrix to replace the version 

provided on May 24, 2000. 

In a letter (signed by C. A. Casto) NRC informed SNC of the 

license renewal inspection schedule for Hatch. 

In an electronic correspondence (signed by R. Baker) SNC 

submitted a matrix mapping the cracking aging mechanisms 

discussed in the various C.2 commodity groups. 

In a letter (signed by J. H. Wilson) NRC requested additional 

information related to the staff's review of the License Renewal 

Environmental Report for Hatch (ML003726207) 

In a letter (signed by W. Burton) NRC informed SNC of the 

schedule revision for the review of the Hatch LRA (ML003726800) 

In a letter (signed by L. N. Olshan) NRC requested additional 

information concerning the Liquid and Gaseous Radwaste System 

at Hatch (ML003727407) 

In a letter (signed by W. Burton) NRC requested additional 

information (RAI) on LRA Sections 2.1, 2.2, 2.3.1, (SER Section 

2.3.2), 2.3.2, 2.3.3, 2.3.4, 2.3.5, 2.4, 2.5, 3.2.3 (SER Section 3.3), 

and 3.2.5 (SER Section 3.5) (ML003732558) 

In a letter (signed by H. L. Sumner) SNC provided its response to 

the NRC RAIs related to the review of severe accident mitigation 

alternatives for Hatch. 

In an electronic correspondence (signed by H. L. Sumner) SNC 

provided its response to the NRC RAIs concerning the Liquid and 

Gaseous Radwaste System at Hatch (ML003736984) 

In a letter (signed by W. Burton) NRC request SNC to provide 

additional information (RAI) on LRA Sections 2.3.3, 2.3.4 

(ML003736523) 

In a memorandum (signed by W. Burton) NRC issued a non-public 

meeting notice to stakeholders informed them on a meeting to be 

held on August 23, 2000, to review samples of Hatch 

environmental qualification calculations to verify calculation 

methods as applies in the Hatch LRA (ML003740331)

A-4
August 11, 2000 

August 21, 2000 

August 23, 2000 

August 29, 2000 

August 29, 2000 

August 29, 2000 

August 31, 2000 

September 25, 2000 

October 1, 2000 

October 6, 2000 

October 10, 2000 

October 13, 2000

In a letter (signed by H. L. Sumner) SNC provided its response to 

the NRC RAIs on the renewal environmental report of the Hatch 

LRA requested on June 23, 2000. 

In a letter (signed by H. L. Sumner) SNC provided its response to 

the NRC RAIs on the scoping and screening (Section 2 of the 

LRA) and aging management issues (Section 3 or 4 of the LRA) by 

providing a proposed schedule for response to these requests for 

additional information. 

In a memorandum (signed by W. Burton) NRC provided SNC with 

a summary of the August 23, 2000, meeting with SNC regarding 

environmental qualification calculations for Hatch. 

In an electronic correspondence (signed by R. Baker) SNC 

submitted drawing HL-1 6040 in response to RAI2.3.4-CBHVAC-4. 

In a memorandum (signed by B. Boger and C. Casto) NRC 

informed SNC of the final Hatch License Renewal Inspection Plan 

(ML003745955) 

In a letter (signed by H. L. Sumner) SNC provided its response to 

the NRC RAIs on the scoping and screening (Section 2) requested 

on July 14, 2000, and July 28, 2000 (ML003746406) 

In a letter (signed by H. L. Sumner) SNC provided clarification on 

the requested additional information (RAI) related to the review of 

severe accident mitigation alternative dated May 30, 2000. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a correction to RAI 3.1.5-6 and a summary of 

the staff position on complex assemblies. 

In an electronic correspondence (signed by R. Baker) SNC provide 

NRC with the Hatch License Renewal Scoping Inspection follow-up 

items that remained outstanding following the technical debrief on 

September 15, 2000. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with the revision to the first part of RAI 3.1.18-10. 

In a letter (signed by H. L. Sumner) SNC provided its response to 

the NRC remaining RAIs on aging management programs 

requested on June 23, 2000, that were not covered in the SNC 

response dated August 29, 2000 (ML003759631) 

In an electronic correspondence (signed by R. Baker) SNC 

provided NRC with the scoping/screening RAI follow-ups on fire 

protection.

A-5
October 19, 2000 

October 19, 2000 

October 20, 2000 

October 20, 2000 

October 20, 2000 

October 20, 2000 

October 25, 2000 

November 1, 2000 

November 3, 2000 

November 8, 2000 

December 13, 2000

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a revision of the August 23, 2000, meeting 

summary for the EQ calculations. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the September 13, 2000, and 

September 28, 2000, telecon related to fire protection. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the September 13, 2000, and 

September 28, 2000, telecon related to HR, P&I, AD, COND, DPS, 

EDG, IA, and EHC. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the September 13, 2000, and 

September 28, 2000, telecon related to RC, SLC, RHR, and CRD. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the June 27, 2000, telecon 

related to plant service water and traveling water screens/trash 

racks. 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the June 29, 2000, telecon 

related to RCS, SLC, and BWRVIP. 

In a letter (signed by A. Kugler) NRC requested comment on the 

draft plant-specific supplement to the "Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants [GEIS]" 

(NUREG-1437) regarding Hatch (ML003767639) 

In a letter (signed by C. Casto) NRC provided SNC with the 

scoping inspection report of the results of the inspection at the 

Birmingham, Alabama offices regarding SNC's Hatch LRA 

(ML003773009) 

Draft Supplemental Environmental Impact Statement 

(ML003766660) 

In an electronic correspondence (signed by W. Burton) NRC 

provided SNC with a summary of the October 24, 2000, telecon 

related to RHR heat exchangers and treatment of seismic Il/I 

piping 

In a letter (signed by H. L. Sumner) SNC requested a partial fee 

waiver of 40 percent and that the staff take appropriate measures 

to account for its time so that such a waiver is realized 

(ML003779256)

A-6
December 15, 2000

January 5, 2001 

January 16, 2001 

January 31, 2001 

February 7, 2001 

February 9, 2001 

February 9, 2001 

March 19, 2001 

April 16, 2001 

May 31, 2001 

June 5, 2001 

June 14, 2001 

July 26, 2001 

September 5, 2001 

September 28, 2001 

October 5, 2001 

October 18, 2001

In a letter (signed by H. L. Sumner) SNC submitted the required 

amendment (annual update) to the LRA originally submitted 

February 29, 2000 (ML003781913) 

In a letter (signed by W. Burton) NRC provided SNC with a draft of 

open items from the review of the Hatch LRA (ML01 0050321) 

In a letter (signed by W. Burton) NRC provided SNC with a 

schedule revision for the review of the Hatch LRA (ML01 0170351) 

Responses to draft open items provided to SNC by letter dated 

January 5, 2001 (ML01 0430244) 

License Renewal Safety Evaluation Report for the Edwin I. Hatch 

Nuclear Plant (ML01 039007) 

Transmittal of Calculational Summary (Non-Proprietary) 

(ML010470127) 

Schedule Revision (ML010430024) 

Additional Information for GElS (ML010730246) 

ACRS Interim Letter on Hatch License Renewal Review 

(ML011080806) 

Final Supplemental Environmental Impact Statement 

(ML011420037) 

Response to Open Items (ML01 1620187) 

Summary of Meeting with Southern Nuclear Corp. on Seismic Il/I 

(ML011660023) 

Summary of Appeal Meeting (ML01 2070311) 

Supplemental Response to Open Items (ML01 2600021) 

3rd Inspection Report (ML012730003) 

Final Safety Evaluation Report (ML01 2780458/ML01 2780459) 

Regional Administrator's Letter (ML01 2920057)

A-7

I I 

I
APPENDIX B 

REFERENCES 

This appendix contains a listing of references used in the preparation of the Safety Evaluation 

Report prepared during the review of the license renewal application for Edwin I. Hatch Nuclear 

Plant Units 1 and 2 under Docket Numbers 50-321 and 50-366). 

AMERICAN CONCRETE INSTITUTE (ACI) 

ACI 301, "Specifications for Structural Concrete for Buildings." 

ACI 318-63, "Building Code Requirements for Reinforced Concrete." 

AMERICAN NATIONAL STANDARDS INSTITUTEIAMERICAN NUCLEAR SOCIETY 

ANSI N5.12-1972, "Protective Coatings (Paints) for the Nuclear Industry." 

ANSI N101.2-1972, "Protective Coatings (Paints) for Light Water Nuclear Reactor Containment 

Facilities." 

ANSI/ANS 56.8-1994, "American National Standard for Containment System Leakage Testing 

Requirements," 1994. 

AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) 

ASME Boiler and Pressure Vessel Code, July 1989. 

ASME Boiler and Pressure Vessel Code, Section III, Rules for Construction of Nuclear Power 

Plant Components through Summer 1979. 

ASME Boiler and Pressure Vessel Code, Section XI, Rules for Inservice Inspection of Nuclear 

Power Plant Components. 

ASME Boiler and Pressure Vessel Code, Section XI, Appendix G, 1995 Edition through 1996 

Addenda. 

AMERICAN SOCIETY FOR TESTING AND MATERIALS (ASTM) 

ASTM A307, "Standard Specification for Carbon Steel Bolts and Steels, 60,000 psi Tensile 

Strength." 

ASTM A325, "Standard Specification for Structural Bolts, Steel, Heat-Treated, 120 ksi and 105 

ksi Minimum Tensile Strength."

B-1
ASTM A490, "Standard Specification for Heat-Treated Steel Structural Bolts, 150ksi Minimum 

Tensile Strength." 

ASTM D975-1981, "Standard Specification for Diesel Fuel Oils." 

ASTM, Section 6, Volume 06.02, "Paints-Products and Applications, Protective Coatings, 

Pipeline Coatings." 

AMERICAN WATER WORKS ASSOCIATION (AWWA) 

AWWA C203, "AWWA Standard for Coal-Tar Protective Coatings and Linings for Steel Water 

Pipelines - Enamel and Tape - Hot Applied," 1966. 

AWWA C209, "Cold Applied Tape Coatings for the Exterior of Special Sections, Connections, 

and Fittings for Steel Water Pipelines," 1995 

BABCOCK AND WILCOX (BAW) 

BAW-2270, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," 

December 1997. 

BOILING WATER REACTOR VESSEL AND INTERNALS PROJECT (BWRVIP) 

BWRVIP-05, "BWR RPV Shell Weld Inspection Recommendations," September 1995 

BWRVIP-06, "Safety Assessment of BWR Reactor Internals," October 1995 

BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," July 1996 

BWRVIP-26, 'Top Guide Inspection and Flaw Evaluation Guidelines," December 1996 

BWRVIP-27, "Standby Liquid Control System/Core Plate &P Inspection and Flaw Evaluation 

Guidelines," April 1997 

BWRVIP-38, "Shroud Support Inspection and Flaw Evaluation Guidelines," September 1997 

BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," October 

1997 

BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," December 1997 

BWRVIP-48, 'Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," March 

1998 

BWRVIP-60, "Evaluation of Crack Growth in BWR Low Alloy Steel RPV Internals," March 1999

B-2
BWRVIP-62, 'Technical Basis for Inspection Relief for BWR Internal Components with Hydrogen 

Injection," December 1998 

BWRVIP-74, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," 

September 1999. 

BWRVIP-75, 'Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules 

(NUREG-0313)," October 1999 

BWRVIP-76, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," December 1999. 

BWRVIP-78, "BWR Integrated Surveillance Program - Unirradiated Charpy Reference Curves 

for Surveillance Material," December 1999 

BULLETINS (BL) 

NRC BL 79-01 B, "Guidelines for Evaluating Environmental Qualification of Class 1 E Electrical 

Equipment in Operating Reactors," October, 1980. 

NRC BL 80-11, "Masonry Wall Design," May 1980. 

NRC BL 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems," April, 

1988 

CODE OF FEDERAL REGULATIONS 

10 CFR Part 50.34, "Contents of application; technical information," Section (a)(1). 

10 CFR Part 50.48, "Fire Protection" 

10 CFR Part 50.49, "Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants." 

10 CFR Part 50.55a, "Codes and Standards." 

10 CFR Part 50.60, "Acceptance Criteria for Fracture Prevention Measures for Light water 

Nuclear Power Reactors for Normal Operation." 

10 CFR Part 50.61, "Fracture Toughness Requirements for Protection Against Pressurized 

Thermal Shock Events." 

10 CFR Part 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without 

Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." 

10 CFR Part 50.63, "Loss of All Alternating Current Power."

B-3
10 CFR Part 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants." 

10 CFR Part 50.Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel 

Reprocessing Plants." 

10 CFR Part 50.Appendix G, "Fracture Toughness Requirements." 

10 CFR Part 50.Appendix H, "Reactor Vessel Material Surveillance Program Requirements." 

10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants." 

10 CFR Part 100, "Reactor Site Criteria." 

CORRESPONDENCE 

Letter from T. Martin (NRC) to T. Tipton (NEI), dated October 1, 1996. 

Letter from C.I. Grimes (NRC) to D. Walters (NEI), "Guidance on Addressing GSI 168 for license 

Renewal," Project 690, dated June 2, 1998. 

Letter from H. L. Sumner (SNC) to NRC, "Reactor Pressure Vessel Shell Welds Examination," 

dated December 2, 1998. 

Letter from B. D. Frew to C. R. Pierce, "Corrosion Allowance for Hatch 1 and 2 VesseVPiping 

Systems," dated September 15, 1999, DF 9912, DRF B1 1-00827. 

Letter from C.I. Grimes to D.J. Walters, dated May 19, 2000. 

Letter from C. Grimes (NRC) to H. L. Sumner (SNC), "Request for Additional Information for the 

Review of the License Renewal Application of Plant Hatch," dated July 14, 2000. 

Letter from C. Grimes (NRC) to H. L. Sumner (SNC), "Request for Additional Information for the 

Review of the License Renewal Application of Plant Hatch," dated July 28, 2000. 

Letter from H. L. Sumner (SNC) to NRC, "Edwin I. Hatch Nuclear Plant - Response To License 

Renewal Requests for Additional Information," dated August 29, 2000. 

Letter from R. L. Emch (NRC) to H. L. Sumner (SNC), "Edwin I. Hatch Nuclear Plant, Units 1 

and 2 RE: Evaluation of Relief Requests RR-MC-9 and RR-12: Implementation of Subsections 

IWE and IWL of ASME Section XI for Containment Inspection," dated October 4, 2000 

Letter from H. L. Sumner (SNC) to NRC, "Edwin I. Hatch Nuclear Plant - Response To License 

Renewal Requests for Additional Information," dated October 10, 2000.

B-4
Memorandum from T. Quay (NRC) to C. Grimes (NRC), "Edwin I. Hatch Nuclear Plant License 

Renewal Application - Scoping and Screening/Corrective Action Process Audit Report," dated 

October 10, 2000. 

Letter from H.L. Sumner to NRC - Transmittal of Responses to License Renewal Draft SER 

Open Items - June 5, 2001. 

Letter from H.L. Sumner to NRC - Transmittal of Additional information for License Renewal 

Draft Safety Evaluation Report Open Items, September 5, 2001 

ELECTRIC POWER RESEARCH INSTITUTE (EPRI) 

EPRI NP-5067, "A Reference Manual for Nuclear Power Plant Maintenance Personnel, Volume 

1 - Large Bolt Manual," 1987 

EPRI NP-5461, "Component Life Estimation: LWR Structural Materials Degradation 

Mechanisms," September 1987. 

EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," Vols. 1 and 2, 

Project 2520-7, 1998. 

EPRI NSAC/202-L, "Recommendations for an Effective Flow-Accelerated Corrosion Program," 

Revision 2, April 1999. 

EPRI TR-103515, "BWR Water Chemistry Guidelines," BWRVIP-29, Revision 1, December 

1996. 

EPRI report TR-1 03840 "BWR Containments License Renewal Industry Report; Revision 1" July 

1994 

EPRI TR-103842, "Class I Structures Industry Report," July 1994 

EPRI TR-104873, "Methodologies and Processes to Optimize Environmental Qualification 

Replacement Internals," February 1996. 

EPRI TR-105747, "Guidelines for Reinspection of BWR Core Shrouds," BWRVIP-07, February 

1996. 

EPRI TR-1 05759, "An Environmental Factor Approach to Account for Reactor Water Effects in 

Light Water Reactor Pressure Vessel and Piping Evaluations," December, 1995. 

EPRI TR-1 06092, "Evaluation of Thermal Aging Embrittlement for Cast Austenitic Stainless 

Steel Components in LWR Coolant Systems, " September 1997. 

EPRI TR-1 06740, "BWR Core Spray Internals and Flaw Evaluation Guidelines," BWRIVP-1 8, 

July 1996.

B-5
EPRI TR-107079, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," Revision 2, 

BWRVIP-01, October 1996. 

EPRI TR-107285, "BWR Top Guide Inspection and Flaw Evaluation Guidelines," BWRVIP-26, 

December 1996. 

EPRI TR-107286, "BWR Standby Liquid Control System/Core Plate ,P Inspection and Flaw 

Evaluation Guidelines," BWRVIP-27, April 1997. 

EPRI TR- 107396, "Closed Cooling Water Chemistry Guidelines," October 1997. 

EPRI TR-1 07515, "Evaluation of Thermal Fatigue Effects on Systems Requiring Aging 

Management Review for License Renewal for the Calvert Cliffs Nuclear Power Plant," 

December, 1997. 

EPRI TR-107521, "Generic License Renewal Technical Issues Summary," April, 1988. 

EPRI TR-107943, "Environmental Fatigue Evaluations of Representative BWR Components," 

June, 1998. 

EPRI TR-1 08705, "BWR Vessel and Internals Project, Technical Basis for Inspection Relief for 

BWR Internal Components with Hydrogen Injection," December, 1998 (BWRVIP-62). 

EPRI TR-1 08727, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines," 

BWRVIP-47, December 1997. 

EPRI TR-1 08728, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines," 

BWRVIP-41, October 1997. 

EPRI TR-108823, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines," 

BWRVIP-38, September 1997. 

EPRI TR-108724, "Bessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines," 

BWRVIP-48, February 1998. 

EPRI TR-1 10356, "Evaluation of Environmental Thermal Fatigue Effects on Selected 

Components in a Boiling Water Reactor Plant," April, 1998. 

EPRI TR-112214, "BWR Vessel and Internals Project, Proceedings: BWRVIP Symposium, 

November 12-13, 1998." 

EPRI TR-1 13596, "BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection 

and Flaw Evaluation Guidelines," September, 1999 (BWRVIP-74). 

EPRI TR-1 14232, "BWR Core Shroud Inspection and Flaw Evaluation Guidelines," BWRVIP-76, 

November 1999. 

EPRI TR-1 13596, "BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection 

and Flaw Evaluation Guidelines," BWRVIP-74, September 1999. 

B-6
EPRI TR-107396, "Closed Cooling Water Chemistry Guidelines," October, 1997. 

FIRST ENERGY 

CR-1 99901648, Davis-Besse Nuclear Generating Station, "Root Cause Analysis Report, #2 

CCW Pump Trip," October 2,1999. 

GENERAL ELECTRIC COMPANY 

GENE B131-00827-00-01, "Plant Hatch Units 1 and 2 Reactor Pressure Vessel 

Pressure/Temperature Limits License Renewal Evaluation," General Electric Company, March 

1999. 

GENERIC LETTERS 

NRC GL 79-20, "Information Requested on PVR Feedwater Lines," May, 1979 

NRC GL 85-20, "Resolution of Generic Issue 69: High Pressure Injection/Makeup Nozzle 

Cracking in Babcock and Wilcox Plants," November 11,1985. 

NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping," 1989. 

NRC GL 88-11, "NRC Position on Radiation Embrittlement of Reactor Vessel Materials and Its 

Impact on Plant Operations," July, 1988. 

NRC GL 88-14, "Instrument Air Supply System Problems Affecting Safety-Related Equipment," 

August, 1988. 

NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," April, 

1989. 

NRC GL 90-05, "Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 

2, and 3 Piping," June 19990. 

NRC GL 91-17, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in 

Nuclear Power Plants," October 1991. 

NRC GL 92-01, Revision 1, Supplement 1, "Reactor Vessel Structural Integrity," May 18, 1995. 

NRC GL 92-08, 'Thermo-Lag 330-1 Fire Barriers," December 1992. 

NRC GL 96-04, "Boraflex Degradation in Spent Fuel Pool Storage Racks," June 1996.

B-7
GENERIC SAFETY ISSUES 

GSI-1 66, "Adequacy of the Fatigue Life of Metal Components." See SECY 95-245, "Completion 

of the Fatigue Action Plan," September, 1995. 

GSI-168, "Environmental Qualification of Electrical Components" 

GSI-190: Memo from Ashok Thadani to William Travers, "Closeout of Generic Safety Issue 190, 

'Fatigue Evaluation of Metal Components for 60-year Plant Life'," dated December 26, 1999. 

INFORMATION NOTICES (IN) 

NRC IN 87-67, "Lesson Learned from Regional Inspection of Applicant Actions in response to IE 

Bulletin 80-11, 'Masonry Wall Design," December, 1987. 

NRC IN 91-46, "Degradation of Emergency Diesel Generator Fuel Oil Deliver Systems," July 

1991. 

NRC IN 91-85, "Potential Failures of Thermostatic Control Valves for Diesel Generator Jacket 

Cooling Water," December, 1991. 

NRC IN 92-20, "Inadequate Local Leak Rate Testing," March 1992. 

NRC IN 97-72, "Potential for Failure of the Omega Series Sprinkler Heads," September, 1997. 

NRC IN 01-10, "Failure of Central Sprinkler Company Model GB Series Fire Sprinkler Heads," 

June, 2001 

NRC IN 99-28, "Recall of Star Brand Fire Protection Sprinkler Head," September, 1999. 

INSPECTION AND AUDIT REPORTS 

Edwin I. Hatch Nuclear Plant License Renewal Application - Scoping and Screening/Corrective 

Action Process Audit Report, October 10, 2000 

Edwin I. Hatch Nuclear Power Plant - NRC Inspection Report Nos. 50-321/00-09, 50-366/00-09, 

November 1, 2000 

Edwin I. Hatch Nuclear Power Plant - NRC Inspection Report Nos. 50-321/00-10, 50-366/00-10, 

April 30, 2001 

Edwin I. Hatch Nuclear Power Plant - NRC License Renewal Inspection Report 50-321/01-10 

and 50-366/01 -10, September 28, 2001

B-8
INSTITUTE OF ELECTRICAL AND ELECTRONICS ENGINEERS (IEEE) 

ANS/IEEE Std. 450-1980, "IEEE Recommended Practice for Maintenance, Testing, and 

Replacement of Large Storage Batteries for Generating Stations and Substations." 

IEEE Std. 323-1974, "Qualifying Class 1 E Equipment for Nuclear Power Generating Stations," 

1974. 

IEEE 43-1974, "Recommended Practice for Testing Insulation Resistance of Rotating 

Machinery" 

IEEE 95-1977, "Recommended Practice for Insulation Testing of Large AC Rotating Machinery 

with High Direct Voltage" 

NATIONAL FIRE PROTECTION ASSOCIATION (NFPA) 

NFPA-25, uStandard for the Inspection, Testing, and Maintenance of Water-Based Fire 

Protection Systems" 

NUCLEAR ENERGY INSTITUTE/NUCLEAR MANAGEMENT RESOURCE COUNCIL 

(NEIVNUMARC) 

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, 

Appendix J," July 26, 1995. 

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

License Renewal Rule," Revision 0, March 1996. 

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

License Renewal Rule," Revision 1, January 2000. 

NEI 96-03, "Guideline for Monitoring the Condition of Structures at Nuclear Power Plants," 

March, 1996. 

NEI/NRC License Renewal Work Shop, Reference Documents, October 29, 1997. 

NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear 

Power Plants," April, 1996. 

NUREG REPORTS 

NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical 

Equipment," July, 1981. 

NUREG-0612, "Control of Heavy Loads at Nuclear Power Plant," July, 1980. 

B-9
NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, 

Resolution of Generic Technical Activity A 10," November 1980. 

NUREG-0737, "Clarification of TMI Action Plan Requirements," November, 1980. 

NUREG-1275, Volume 3, "Operating Experience Feedback Report - Service Water System 

Failure and Degradations," November, 1988. 

NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear 

Power Plants," 1990. 

NUREG-1526, "Lessons Learned from Early Implementation of Maintenance Rule at Nine 

Nuclear Power Plants," June, 1995. 

NUREG-1568, "License Renewal Demonstration Program: NRC Observations and Lessons 

Learned," December 1996. 

NUREG/CR-5704, "Effects of LWR Coolant Environment on Fatigue Design Curves of Austenitic 

Stainless Steels," April 1999. 

NUREG/CR-5999, "Interim Fatigue Curves to Selected Nuclear Power Plant Compnents," March 

1995. 

NUREG/CR-6260, "Application of NUREG/CR-5999, 'Interim Fatigue Curves to Selected 

Nuclear Power Plant Components'," March, 1995. 

NUREG/CR-6335, "Fatigue Strain-Life Behavior of Carbon and Low-Alloy Steels, Austenitic 

Stainless Steels, and Alloy 600 in LRA Environments," August 1995. 

NUREG/CR-6384, "Literature Review of Environmental Qualification of Safety-Related Electric 

Cables," Vol. 1, April 1996, Brookhaven National Laboratory, Prepared for U. S. Nuclear 

Regulatory Commission. 

NUREG/CR-6583, "Effects of LWR Coolant Environments in Fatigue Design Curves of Carbon 

and Low-Alloy Steels," March, 1998. 

REGULATORY GUIDES (RG) 

NRC Regulatory Guide 1.154, "Format and Content of Plant-Specific Pressurized Thermal 

Shock Safety Analysis Reports for Pressurized Water Reactors," January, 1987. 

NRC Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power 

Plants," March, 1997. 

NRC Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," 

September, 1995.

B-10
NRC Regulatory Guide 1.46, Revision 0, "Protection Against Pipe Whip Inside Containment," 

Withdrawn August 11, 1985. 

NRC Regulatory Guide 1.89, "Environmental Qualification of Certain Electric Equipment 

Important to Safety for Nuclear Power Plants," June, 1984. 

NRC Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to 

Assess Plant and Environs Conditions During and Following an Accident" May, 1983. 

NRC Regulatory Guide 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," 

May 1988. 

REPORTS 

A-44985, "Structural Monitoring Program for the Maintenance Rule, Edwin I. Hatch Nuclear 

Plant," Units 1 and 2, Revision 4, December 30, 1998. 

Edwin I. Hatch Final Safety Analysis Report Unit 1, Rev. 18A, January, 2000. 

Edwin I. Hatch Final Safety Analysis Report Unit 2, Rev. 18A, January, 2000. 

Edwin I. Hatch Nuclear Plan, Units 1 and 2, Final Hazards Analysis and Fire Protection Program, 

Rev. 14B, July, 1999. 

Edwin I. Hatch Nuclear Pant Units 1 and 2, Environmental Qualification Central File. 

"Flow-Accelerated Corrosion (FAC) Program, Hatch Nuclear Plant Units 1 and 2," Volumes 1 

and 2, Southern Company Services Inc., Vol. 1 - September 1, 1995, Vol. 2 - February 8, 2000. 

"Hatch Units 1 and 2 Torus Fatigue Analysis Report, REA HT-98674 Response," Revision 0, 

Southern Company Services, Inc., Nuclear Engineering and Regulatory Support, April 1999. 

HL-882, "Georgia Power Company Response to Generic Letter 89-13," January 23, 1992. 

"Initial Actions Summary Report," Edwin I. Hatch Nuclear Plant Units 1 and 2, Generic 

Letter 89-13, May 1992. 

Safety Evaluation with letter from NRC to SNC, "Issuance of Amendments - Edwin I. Hatch 

Nuclear Plant Units 1 and 2," October 22, 1998. 

Southern Nuclear Operating Company, Plant Hatch, Unit 1 and 2, Third 10-Year Interval 

Inservice Inspection Program, Rev. 5, April 30, 1998. 

License Renewal Safety Evaluation Report for the Edwin I. Hatch Nuclear Plant, February 7, 

2001.

B-11
SECY 

SECY 95-245, "Completion of the Fatigue Action Plan," September, 1995. 

STANDARD REVIEW PLAN - LICENSE RENEWAL 

"Standard Review Plan for the Review of License Renewal Applications for Nuclear Power 

Plants," Working Draft, September 1997. 

STEEL STRUCTURES PAINTING COUNCIL 

SSPC-SP1 1, "Power Tool Cleaning to Bare Metal," November, 1987. 

SSPC-VIS3, "Visual Standard for Power- and Hand-Tool Cleaned Steel," October, 1993. 

STRUCTURAL INTEGRITY ASSOCIATES 

SIR-99-078, Revision A, "Development of Class 1 Piping Fatigue Formulas and Fatigue Usage 

Estimates for the Hatch Nuclear Power Plant, Units 1 and 2," June 1999. 

U.S. DEPARTMENT OF ENERGY (DOE) 

SAND 93-7070.UC-523, "Aging Management Guideline for Commercial Nuclear Power Plants 

Heat Exchangers" (July 1984). 

SAND 96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants - Electrical 

Cables and Terminations," United States Department of Energy, September, 1996. 

USA STANDARDS INSTITUTE (USAS) 

ANSI USAS B31.1.0, "USA Standard Code for Pressure Piping," 1968. 

ANSI USAS B31.7, "USA Standard Code for Pressure Piping, Nuclear Power Piping," 1968. 

USAS B31.7, "Nuclear Power Piping," 1969.

B - 12
PROPRIETARY SOURCES OF INFORMATION

GENE B131-00833-00-01, "Plant Hatch Reactor Pressure Vessel Aging Management Report," 

General Electric Company, November 1999 (GE Proprietary).

B - 13
APPENDIX C

ABBREVIATIONS 

A/C air conditioning 

ACl American Concrete Institute 

ACRS Advisory Committee on Reactor Safeguards 

AD access doors system 

AHU air handling unit 

AMP aging management program 

AMR aging management review 

ANL Argonne National Laboratory 

ANSI American National Standard Institute 

ART adjusted reference temperature 

ASME American Society of Mechnacal Engineers 

ASTM American Society for Testing and Materials 

ATWS anticipated transient without scram 

AWWA American Water Works Association 

BDP boundary description packages 

BOP balance of plant 

BTP branch technical position 

BWR boiling water reactor 

BWROG BWR Owner's Group 

BWRVIP Boiling Water Reactor Vessel and Internals Project 

CAP corrective actions program 

CBHVAC control building HVAC 

CCTLP component cyclic or transient limit program 

CCW closed cooling water 

CDF core damage frequency 

CF chemistry factor 

CFR Code of Federal Regulations 

CLB current licensing basis 

CRD control rod drive 

CS core spray 

CST condensate storage tank 

CUF cumulative usage factor 

DBA design basis accident 

DBE design basis event 

DGMA diesel generator maintenance activities 

DOR Division of Operating Reactors 

DWST demineralized water storage tank 

ECCS emergency core cooling system 

ECP electrochemical potential 

EDG emergency diesel generator

C-i
EFPY effective full power years 

EHC electro-hydraulic control 

ELI equipment location index 

EPRI Electric Power Research Institute 

EQ environmental qualification 

EQML environmental qualification master list 

ESF engineered safety features 

FAC flow accelerated corrosion 

FAO free available oxidant 

FHA fire hazards analysis 

FP fire protection 

FR Federal Register 

FSAR final safety analysis report 

GALL generic aging lessons learned 

GE General Electric 

GElS generic environmental impact statement 

GL generic letter 

GSI generic safety issue 

HE/ME high energy/moderate energy 

HELB high energy line break 

HMWPE high-molecular-weight polyethylene 

HNP Edwin I. Hatch Nuclear Plant 

HPCI high-pressure coolant injection 

HVAC heating, ventilation, and air conditioning 

HWC hydrogen water chemistry 

I&E Inspection and Enforcement 

I&E inspection and evaluation 

I/MPO installation/maintenance procedure manual 

IASCC irradiation assisted stress corrosion cracking 

IEEE Institute of Electrical and Electronic Engineers 

IGA intergranular attack 

IGSCC intergranular stress corrosion cracking 

ILRT integrated leak rate test 

IN information notice 

INPO Institute for Nuclear Power Operations 

IPA integrated plant assessment 

ISI inservice inspection 

ISP integrated surveillance program 

LEFM linear elastic fracture mechanics 

LOCA loss of coolant accident 

LOSP loss of offsite power 

LPCI low-pressure coolant injection 

LR license renewal

C-2
LRA license renewal application 

LRT leak-rate test 

LWR light-water reactor 

MC main condenser 

MCR main control room 

MCRE main control room envelope 

MCRECS main control room environmental control system 

MIC microbiologically-influenced corrosion 

MSIV main steam isolation valve 

MSL main steam line 

NDT nil-ductility transition temperature 

NEI Nuclear Energy Institute 

NFPA National Fire Protection Association 

NMCA noble metal chemical addition 

NPAR nuclear plant aging research 

NPDES national pollutant discharge elimination system 

NPS nominal pipe size 

NRC United States Nuclear Regulatory Commission 

NSAC Nuclear Safety Analysis Center 

NSOA nuclear safety operational analysis 

NUMARC Nuclear Management and Resources Council (now NEI) 

OSHVAC outside structures heating, ventilation, and air conditioning system 

P-T pressure-temperature limits 

P&I primary containment purge and inerting 

PCCW primary containment chilled water 

PSW plant service water 

PT liquid penetrant 

QA quality assurance 

QDP qualification data package 

RAI request for additional information 

RB reactor building 

RBCCW reactor building closed cooling water 

RBHVAC reactor building heating, ventilation, and air conditioning system 

RCIC reactor core isolation cooling 

RCS reactor coolant system 

RE refueling equipment system 

RG regulatory Guide 

RHR residual heat removal 

RHRSW RHR service water 

RPS reactor protection system 

RPT recirculating pump trip 

RPV reactor pressure vessel 

RRS reactor recirculation system

C-3
RSP remote shutdown panel 

RT reference temperature 

RT radiographic test 

RVID reactor vessel integrity database 

RWCU reactor water cleanup 

SAW submerged arc weld 

SC structures and components 

SCC stress corrosion cracking 

SCFM standard cubic feet per minute 

SE safety evaluation 

SECY Office of the Secretary of the Commission 

SED system evaluation document 

SER safety evaluation report 

SFP spent fuel pool 

SGTS standby gas treatment system 

SLCS standby liquid control system 

SMP structural monitoring program 

SNC Southern Nuclear Operating Company, Inc. 

SOC statement of consideration 

SPCS steam and power conversion system 

SRP standard review plan 

SRP-LR standard review plan - license renewal 

SRV safety relief valve 

SSCs systems, structures, and components 

SSPC Steel Structures Paint Council 

TGSCC transgranular stress corrosion cracking 

TLAA time-limited aging analysis 

TMI Three Mile Island 

TR technical report 

TS technical specifications 

TTA tolytriazole 

TV tornado vents 

TWSPI treated water systems piping inspection 

UFSAR updated Final Safety Analysis Report 

USAS United States of America Standard 

USE upper shelf energy 

UT ultrasonic test 

VFLD vessel flange leak detection 

WG water gage 

XLPE cross-linked polyethylene

C-4
APPENDIX D

PRINCIPAL CONTRIBUTORS

LICENSE RENEWAL AND STANDARDIZATION BRANCH

NAME

Chris Grimes 

William Burton 

Raj Anand 

Tamara Bloomer 

Sonary Chey 

Sharon Green 

Steve Hoffman 

Robert Prato 

Kimberley Rico 

Omid Tabatabai-Yazdi 

Hai-Boh Wang

RESPONSIBILITY 

Branch Chief 

Project manager 

Project Manager 

Technical Support 

Clerical Support 

Clerical Support 

Technical Support 

Technical Support 

Technical Support 

Technical Support 

Technical Support

PRINCIPAL CONTRIBUTORS

NAME

Hans Ashar 

Goutam Bagchi 

William Bateman 

Carl Berlinger 

Ramona Bouling 

Jose Calvo 

Gene Carpenter 

Ralph Caruso 

Stephanie Coffin 

Billy Crowley 

James Davis 

David Diec 

Tanya Eaton 

Barry Elliot 

Robert Elliott 

John Fair 

Greg Galletti 

George Georgiev 

Chris Gratton 

John Hannon 

Toni Harris 

Mark Hartzman 

Richard Hoefling

Civil Engineering 

Division of Engineering 

Materials/Chemical Engineering 

Division of Systems Safety and Analysis 

Clerical Support 

Electrical Engineering 

Materials Engineering 

Reactor Systems Engineering 

Materials Engineering 

Regional Inspector 

Materials Engineering 

Plant Systems Engineering 

Fire Protection Engineering 

Materials Engineering 

Plant Systems Engineering 

Mechanical Engineering 

Quality Assurance 

Materials Engineering 

Plant Systems Engineering 

Plant Systems Engineering 

Clerical Support 

Mechanical Engineering 

Legal Counsel

D-1

RESPONSIBILITY
Gary Holahan 

Cornelius Holden 

George Hubbard 

Gene Imbro 

B.P. Jain 

David Jeng 

Caudle Julian 

Kerri Kavanaugh 

Andrea Keim 

Meena Khanna 

Yong Kim 

William Koo 

Carolyn Lauron 

Arnold Lee 

Chang Li 

Rene Li 

Louise Lund 

John Ma 

Kamal Manoly 

David Matthews 

Timir Misra 

Matthew Mitchell 

Janice Moore 

Cliff Munson 

Scott Newberry 

Kris Parczewski 

Pat Patnaik 

J. Peralta 

Jai Rajan 

Janak Raval 

Muhammad Razzaque 

Mike Scott 

April Smith 

Paul Shemanski 

Jack Strosnider 

Ted Sullivan 

Beverly Sweeney 

Kim VanDoorn 

Eric Weiss 

Jared Wermiel 

Richard Wessman 

Keith Wichman 

Cheng Wu 

Ronald Young

Director, Division of Systems Safety and Analysis 

Electrical Engineering 

Plant Systems Engineering 

Mechanical/Civil Engineering 

Mechanical Engineering 

Civil Engineering 

Regional Inspector 

Plant Systems Engineering 

Materials Engineering 

Materials Engineering 

Mechanical Engineering 

Chemical Engineering 

Materials Engineering 

Mechanical Engineering 

Plant Systems Engineering 

Mechanical Engineering 

Materials Engineering 

Mechanical Engineering 

Civil Engineering 

Director, Division of Regulatory Improvement 

Programs 

Materials Engineering 

Materials Engineering 

Legal Counsel 

Mechanical Engineering 

Deputy Director, Division of Regulatory 

Improvement Programs 

Chemical Engineering 

Chemical Engineering 

Quality Assurance 

Mechanical Engineering 

Plant Systems Engineering 

Reactor Systems Engineering 

Regional Inspector 

Materials Engineering 

Electrical Engineering 

Director, Division of Engineering 

Materials Engineering 

Clerical Support 

Regional Inspector 

Plant Systems Engineering 

Reactor Systems Engineering 

Deputy Director, Division of Engineering 

Materials Engineering 

Mechanical Engineering 

Plant Systems Engineering

D-2
APPENDIX E 

REQUESTS FOR ADDITIONAL INFORMATION

RAI ISSUANCE DATE RESPONSE DATE SUBJECT 

2.1 -SSM-1 July 14, 2000 August 29, 2000 Scoping and 

Screening 

Methodology 

2.1-SSM-2 July 14, 2000 August 29, 2000 Scoping and 

Screening 

Methodology 

2.2-SR-1 July 14, 2000 August 29, 2000 Scoping Results 

2.2-SR-2 July 14, 2000 August 29, 2000 Scoping Results 

2.2-SR-3 July 14, 2000 August 29, 2000 Scoping Results 

2.2-SR-4 July 14, 2000 August 29, 2000 Scoping Results 

2.3.2-NBS-1 July 14, 2000 August 29, 2000 Nuclear Boiler 

System 

2.3.2-NBS-2 July 14, 2000 August 29, 2000 Nuclear Boiler 

System 

2.3.2-RA-1 July 14, 2000 August 29, 2000 Reactor Assembly 

System 

2.3.2-RA-2 July 14, 2000 August 29, 2000 Reactor Assembly 

System 

2.3.2-RA-3 July 14, 2000 August 29, 2000 Reactor Assembly 

System 

2.3.2-RA-4 July 14, 2000 August 29, 2000 Reactor Assembly 

System 

2.3.3-ESF-1 July 14, 2000 August 29, 2000 Engineered Safety 

Features 

2.3.3-ESF-2 July 14, 2000 August 29, 2000 Engineered Safety 

Features 

2.3.3-HR-1 July 14, 2000 August 29, 2000 Post-LOCA 

Hydrogen 

Recombiners

E-1
2.3.3-HR-2 July 14, 2000 August 29, 2000 Post-LOCA 

Hydrogen 

Recombiners 

2.3.3-HR-3 July 14, 2000 August 29, 2000 Post-LOCA 

Hydrogen 

Recombiners 

2.3.3-HR-4 July 14, 2000 August 29, 2000 Post-LOCA 

Hydrogen 

Recombiners 

2.3.3-P&1-1 July 14, 2000 August 29, 2000 Primary Containment 

Purge and Inerting 

System 

2.3.3-P&1-2 July 14, 2000 August 29, 2000 Primary Containment 

Purge and Inerting 

System 

2.3.3-P&l-3 July 14, 2000 August 29, 2000 Primary Containment 

Purge and Inerting 

System 

2.3.3-RHR-1 July 14, 2000 August 29, 2000 Residual Heat 

Removal System 

2.3.3-SGTS-1 July 14, 2000 August 29, 2000 Standby Gas 

Treatment System 

2.3.3-SGTS-2 July 14, 2000 August 29, 2000 Standby Gas 

Treatment System 

2.3.3-SGTS-3 July 14, 2000 August 29, 2000 Standby Gas 

Treatment System 

2.3.3-SLCS-1 July 14, 2000 August 29, 2000 Standby Liquid 

Control System 

2.3.3-SLCS-2 July 14, 2000 August 29, 2000 Standby Liquid 

Control System 

2.3.4-AD-1 July 14, 2000 August 29, 2000 Access Doors 

2.3.4-CBHVAC-1 July 14, 2000 August 29, 2000 Control Building 

HVAC 

2.3.4-CBHVAC-2 July 14, 2000 August 29, 2000 Control Building 

HVAC 

2.3.4-CBHVAC-3 July 14, 2000 August 29, 2000 Control Building 

HVAC

E-2
2.3.4-CBHVAC-4 July 14, 2000 August 29, 2000 Control Building 

HVAC 

2.3.4-COND-1 July 14, 2000 August 29, 2000 Condensate Transfer 

and Storage 

2.3.4-COND-2 July 14, 2000 August 29, 2000 Condensate Transfer 

and Storage 

2.3.4-COND-3 July 14, 2000 August 29, 2000 Condensate Transfer 

and Storage 

2.3.4-CRD-1 July 14, 2000 August 29, 2000 Control Rod Drive 

System 

2.3.4-DPS-1 July 14, 2000 August 29, 2000 Drywell Pneumatics 

System 

2.3.4-DPS-2 July 14, 2000 August 29, 2000 Drywell Pneumatics 

System 

2.3.4-DPS-3 July 14, 2000 August 29, 2000 Drywell Pneumatics 

System 

2.3.4-EDG-1 July 14, 2000 August 29, 2000 Emergency Diesel 

Generators System 

2.3.4-EDG-2 July 14, 2000 August 29, 2000 Emergency Diesel 

Generators System 

2.3.4-EDG-3 July 14, 2000 August 29, 2000 Emergency Diesel 

Generators System 

2.3.4-FPS-1 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-2 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-3 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-4 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-5 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-6 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-7 July 14, 2000 August 29, 2000 Fire Protection 

SSystem 

E-3
2.3.4-FPS-8 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-9 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-FPS-1 0 July 14, 2000 August 29, 2000 Fire Protection 

System 

2.3.4-IA-1 July 14, 2000 August 29, 2000 Instrument Air 

System 

2.3.4-IA-2 July 14, 2000 August 29, 2000 Instrument Air 

System 

2.3.4-IN-1 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-2 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-3 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-4 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-5 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-6 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-7 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-IN-8 July 14, 2000 August 29, 2000 Insulation System 

2.3.4-OSHVAC-1 July 14, 2000 August 29, 2000 Outside Structures 

HVAC 

2.3.4-PCCW-1 July 14, 2000 August 29, 2000 Primary Containment 

Chilled Water 

System 

2.3.4-PCCW-2 July 14, 2000 August 29, 2000 Primary Containment 

Chilled Water 

System 

2.3.4-PSW-1 July 14, 2000 August 29, 2000 Plant Service Water 

System 

2.3.4-PSW-2 July 14, 2000 August 29, 2000 Plant Service Water 

System 

2.3.4-PSW-3 July 14, 2000 August 29, 2000 Plant Service Water 

System 

2.3.4-PSW-4 July 14, 2000 August 29, 2000 Plant Service Water 

I_ I System

E-4
2.3.4-PSW-5 July 14, 2000 August 29, 2000 Plant Service Water 

System 

2.3.4-RBHVAC-1 July 14, 2000 August 29, 2000 Reactor Building 

HVAC 

2.3.4-RBHVAC-2 July 14, 2000 August 29, 2000 Reactor Building 

HVAC 

2.3.4-RBHVAC-3 July 14, 2000 August 29, 2000 Reactor Building 

HVAC 

2.3.4-RW-1 July 14, 2000 August 29, 2000 Radwaste System 

2.3.4-TSR-1 July 14, 2000 August 29, 2000 Traveling Water 

Screens/Trash Racks 

2.3.4-TV-1 July 14, 2000 August 29, 2000 Tornado Vents 

2.3.5-EHC-1 July 14, 2000 August 29, 2000 Electro-Hydraulic 

Control System 

2.3.5-EHC-2 July 14, 2000 August 29, 2000 Electro-Hydraulic 

Control System 

2.3.5-MC-1 July 14, 2000 August 29, 2000 Main Condenser 

2.3.5-SPCS-1 July 14, 2000 August 29, 2000 Steam and Power 

Conversion Systems 

2.4-1 July 14, 2000 August 29, 2000 Structures - General 

2.4-2 July 14, 2000 August 29, 2000 Structures - General 

2.4-3 July 14, 2000 August 29, 2000 Structures - General 

2.4-4 July 14, 2000 August 29, 2000 Structures - General 

2.4-CRT-1 July 14, 2000 August 29, 2000 Conduits, Raceways, 

and Trays 

2.4-EDGB-1 July 14, 2000 August 29, 2000 EDG Building 

2.4-FS-1 July 14, 2000 August 29, 2000 Fuel Storage 

2.4-FS-2 July 14, 2000 August 29, 2000 Fuel Storage 

2.4-FS-3 July 14, 2000 August 29, 2000 Fuel Storage 

2.4-IS-1 July 14, 2000 August 29, 2000 Intake Structure 

2.4-IS-2 July 14, 2000 August 29, 2000 Intake Structure 

2.4-IS-3 July 14, 2000 August 29, 2000 Intake Structure

E-5
2.4-1S-4 July 14, 2000 August 29, 2000 Intake Structure 

2.4-PC-1 July 14, 2000 August 29, 2000 Primary Containment 

2.4-PC-2 July 14, 2000 August 29, 2000 Primary Containment 

2.4-PS-1 July 14, 2000 August 29, 2000 Piping Specialties 

2.4-PS-2 July 14, 2000 August 29, 2000 Piping Specialties 

2.4-PS-3 July 14, 2000 August 29, 2000 Piping Specialties 

2.4-RB-1 July 14, 2000 August 29, 2000 Reactor Building 

2.4-RB-2 July 14, 2000 August 29, 2000 Reactor Building 

2.4-RB-3 July 14, 2000 August 29, 2000 Reactor Building 

2.4-TB-1 July 14, 2000 August 29, 2000 Turbine Building 

2.5-ELEC-1 July 28, 2000 October 10, 2000 Electrical 

3.1-1 July 28, 2000 October 10, 2000 AMPs - General 

3.1-2 July 28, 2000 October 10, 2000 AMPs - General 

3.1-3 July 28, 2000 October 10, 2000 AMPs - General 

3.1-4 July 28, 2000 October 10, 2000 AMPs - General 

3.1-5 July 28, 2000 October 10, 2000 AMPs - General 

3.1-6 July 28, 2000 October 10, 2000 AMPs - General 

3.1-7 July 28, 2000 October 10, 2000 AMPs - General 

3.1.1-1 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-2 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-3 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-4 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-5 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-6 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control

E-6
3.1.1-7 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-8 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-9 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-10 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-11 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.1-12 July 28, 2000 October 10, 2000 Reactor Water 

Chemistry Control 

3.1.2-1 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-2 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-3 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-4 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-5 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-6 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.2-7 July 28, 2000 October 10, 2000 CCW Chemistry 

Control 

3.1.3-1 July 28, 2000 October 10, 2000 Diesel Fuel Oil 

Testing 

3.1.3-2 July 28, 2000 October 10, 2000 Diesel Fuel Oil 

Testing 

3.1.3-3 July 28, 2000 October 10, 2000 Diesel Fuel Oil 

Testing 

3.1.3-4 July 28, 2000 October 10, 2000 Diesel Fuel Oil 

Testing 

3.1.4-1 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control

E-7
3.1.4-2 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-3 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-4 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-5 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-6 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-7 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.4-8 July 28, 2000 October 10, 2000 PSW and RHRSW 

Chemistry Control 

3.1.5-1 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.5-2 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.5-3 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.5-4 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.5-5 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.5-6 July 28, 2000 October 10, 2000 Fuel Pool Chemistry 

Control 

3.1.6-1 July 28, 2000 October 10, 2000 Demineralized Water 

and CST Chemistry 

Control 

3.1.7-1 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-2 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-3 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control

E-8
3.1.7-4 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-5 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-6 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-7 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-8 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control. 

3.1.7-9 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.7-10 July 28, 2000 October 10, 2000 Suppression Pool 

Chemistry Control 

3.1.8-1 July 28, 2000 October 10, 2000 CAP 

3.1.8-2 July 28, 2000 October 10, 2000 CAP 

3.1.9-1 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-2 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-3 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-4 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-5 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-6 July 28, 2000 October 10, 2000 ISI Program 

3.1.9-7 July 28, 2000 October 10, 2000 ISI Program 

3.1.10-1 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform 

Inspections 

3.1.10-2 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform 

Inspections 

3.1.10-3 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform 

Inspections 

3.1.10-4 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform Inspections

E-9
3.1.10-5 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform 

Inspections 

3.1.10-6 July 28, 2000 October 10, 2000 Overhead Crane and 

Refueling Platform 

Inspections 

3.1.11-1 July 28, 2000 October 10, 2000 Torque Activities 

3.1.11-2 July 28, 2000 October 10, 2000 Torque Activities 

3.1.11-3 July 28, 2000 October 10, 2000 Torque Activities 

3.1.11-4 July 28, 2000 October 10, 2000 Torque Activities 

3.1.11-5 July 28, 2000 October 10, 2000 Torque Activities 

3.1.12-1 July 28, 2000 October 10, 2000 CCTLP 

3.1.12-2 July 28, 2000 October 10, 2000 CCTLP 

3.1.12-3 July 28, 2000 October 10, 2000 CCTLP 

3.1.12-4 July 28, 2000 October 10, 2000 CCTLP 

3.1.12-5 July 28, 2000 October 10, 2000 CCTLP 

3.1.12-6 July 28, 2000 October 10, 2000 CCTLP 

3.1.13-1 July 28, 2000 October 10, 2000 PSW and RHRSW 

Inspection Program 

3.1.13-2 July 28, 2000 October 10, 2000 PSW and RHRSW 

Inspection Program 

3.1.13-3 July 28, 2000 October 10, 2000 PSW and RHRSW 

Inspection Program 

3.1.13-4 July 28, 2000 October 10, 2000 PSW and RHRSW 

Inspection Program 

3.1.13-5 July 28, 2000 October 10, 2000 PSW and RHRSW 

Inspection Program 

3.1.14-1 July 28, 2000 October 10, 2000 Primary Containment 

Leakage Rate 

Testing Program 

3.1.14-2 July 28, 2000 October 10, 2000 Primary Containment 

Leakage Rate 

Testing Program 

3.1.15-1 July 28, 2000 October 10, 2000 BWRVIP

E-10
3.1.15-2 July 28, 2000 October 10, 2000 BWRVIP 

3.1.15-3 July 28, 2000 October 10, 2000 BWRVIP 

3.1.15-4 July 28, 2000 October 10, 2000 BWRVIP 

3.1.15-5 July 28, 2000 October 10, 2000 BWRVIP 

3.1.16-1 July 28, 2000 October 10, 2000 Wetted Cable 

Activities 

3.1.16-2 July 28, 2000 October 10, 2000 Wetted Cable 

Activities 

3.1.16-3 July 28, 2000 October 10, 2000 Wetted Cable 

Activities 

3.1.16-4 July 28, 2000 October 10, 2000 Wetted Cable 

Activities 

3.1.16-5 July 28, 2000 October 10, 2000 Wetted Cable 

Activities 

3.1.17-1 July 28, 2000 October 10, 2000 RPV Monitoring 

Program 

3.1.18-1 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-2 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-3 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-4 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-5 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-6 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-7 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-8 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.18-9 July 28, 2000 October 10, 2000 Fire Protection 

Activities

E-11
3.1.18-10 July 28, 2000 October 10, 2000 Fire Protection 

Activities 

3.1.19-1 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-2 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-3 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-4 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-5 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-6 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-7 July 28, 2000 October 10, 2000 FAC Program 

3.1.19-8 July 28, 2000 October 10, 2000 FAC Program 

3.1.20-1 July 28, 2000 October 10, 2000 Protective Coatings 

Program 

3.1.20-2 July 28, 2000 October 10, 2000 Protective Coatings 

Program 

3.1.20-3 July 28, 2000 October 10, 2000 Protective Coatings 

Program 

3.1.21-1 July 28, 2000 October 10, 2000 Equipment and 

Piping Insulation 

Monitoring Program 

3.1.21-2 July 28, 2000 October 10, 2000 Equipment and 

Piping Insulation 

Monitoring Program 

3.1.21-3 July 28, 2000 October 10, 2000 Equipment and 

Piping Insulation 

Monitoring Program 

3.1.21-4 July 28, 2000 October 10, 2000 Equipment and 

Piping Insulation 

Monitoring Program 

3.1.21-5 July 28, 2000 October 10, 2000 Equipment and 

Piping Insulation 

Monitoring Program 

3.1.22-1 July 28, 2000 October 10, 2000 Structural Monitoring 

Program 

3.1.22-2 July 28, 2000 October 10, 2000 Structural Monitoring 

Program

E - 12
3.1.22-3 July 28, 2000 October 10, 2000 Structural Monitoring 

Program 

3.1.22-4 July 28, 2000 October 10, 2000 Structural Monitoring 

Program 

3.1.22-5 July 28, 2000 October 10, 2000 Structural Monitoring 

Program 

3.1.23-1 July 28, 2000 October 10, 2000 Galvanic 

Susceptibility 

Inspections 

3.1.23-2 July 28, 2000 October 10, 2000 Galvanic 

Susceptibility 

Inspections 

3.1.23-3 July 28, 2000 October 10, 2000 Galvanic 

Susceptibility 

Inspections 

3.1.23-4 July 28, 2000 October 10, 2000 Galvanic 

Susceptibility 

Inspections 

3.1.23-5 July 28, 2000 October 10, 2000 Galvanic 

Susceptibility 

Inspections 

3.1.24-1 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping 

Inspections 

3.1.24-2 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping 

Inspections 

3.1.24-3 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping 

Inspections 

3.1.24-4 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping 

Inspections 

3.1.24-5 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping 

Inspections 

3.1.24-6 July 28, 2000 October 10, 2000 Treated Water 

Systems Piping Inspections

E-13
3.1.25-1 July 28, 2000 October 10, 2000 Gas Systems 

Components 

Inspections 

3.1.25-2 July 28, 2000 October 10, 2000 Gas Systems 

Components 

Inspections 

3.1.25-3 July 28, 2000 October 10, 2000 Gas Systems 

Components 

Inspections 

3.1.25-4 July 28, 2000 October 10, 2000 Gas Systems 

Components 

Inspections 

3.1.26-1 July 28, 2000 October 10, 2000 CST Inspections 

3.1.26-2 July 28, 2000 October 10, 2000 CST Inspections 

3.1.26-3 July 28, 2000 October 10, 2000 CST Inspections 

3.1.27-1 July 28, 2000 October 10, 2000 Passive Components Inspection Activities 

3.1.27-2 July 28, 2000 October 10, 2000 Passive Components 

Inspection Activities 

3.1.28-1 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.28-2 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.28-3 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.28-4 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.28-5 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program

E - 14
3.1.28-6 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.28-7 July 28, 2000 October 10, 2000 RHR Heat Exchanger 

Augmented 

Inspection and 

Testing Program 

3.1.29-1 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-2 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-3 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-4 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-5 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-6 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-7 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-8 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-9 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-10 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program

E-15
3.1.29-11 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-12 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.1.29-13 July 28, 2000 October 10, 2000 Torus Submerged 

Components 

Inspection Program 

3.2.3.1-1 July 28, 2000 October 10, 2000 RCS 

3.2.3.1-2 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-1 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-2 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-3 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-4 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-5 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-6 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-7 July 28, 2000 October 10, 2000 RCS 

3.2.3.2-8 July 28, 2000 October 10, 2000 RCS 

3.3-CS-1 July 28, 2000 October 10, 2000 Core Spray 

3.3-HPCI-1 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-2 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-3 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-4 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-5 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-6 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-7 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-8 July 28, 2000 October 10, 2000 HPCI 

3.3-HPCI-9 July 28, 2000 October 10, 2000 HPCI 

3.3-HR-1 July 28, 2000 October 10, 2000 Post-LOCA 

Hydrogen 

Recombiner System

E -16
3.3-P&1-1 July 28, 2000 October 10, 2000 Primary Containment 

Purge & Inerting System 

3.3-P&I-2 July 28, 2000 October 10, 2000 Primary Containment 

Purge & Inerting 

System 

3.3-RCIC-1 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-2 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-3 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-4 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-5 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-6 July 28, 2000 October 10, 2000 RCIC System 

3.3-RCIC-7 July 28, 2000 October 10, 2000 RCIC System 

3.3-SGTS-1 July 28, 2000 October 10, 2000 Standby Gas 

Treatment System 

3.3-SGTS-2 July 28, 2000 October 10, 2000 Standby Gas 

Treatment System 

3.4-1 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-2 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-3 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-4 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-5 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-6 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-7 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-8 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-9 July 28, 2000 October 10, 2000 Auxiliary Systems 

General

E - 17
3.4-10 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-11 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-12 July 28, 2000 October 10, 2000 Auxiliary Systems 

General 

3.4-CBHVAC-1 July 28, 2000 October 10, 2000 Control Building 

HVAC 

3.4-CHE-1 July 28, 2000 October 10, 2000 Cranes, Hoists, and 

Elevators 

3.4-COND-1 July 28, 2000 October 10, 2000 Condensate Transfer 

and Storage System 

3.4-CRD-1 July 28, 2000 October 10, 2000 Control Rod Drive 

System 

3.4-CRD-2 July 28, 2000 October 10, 2000 Control Rod Drive 

System 

3.4-DPS-1 July 28, 2000 October 10, 2000 Drywell Pneumatic 

Systems 

3.4-FPS-1 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-2 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-3 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-4 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-5 July 28, 2000 October 10, 2000 

3.4-FPS-6 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-7 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-8 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-9 July 28, 2000 October 10, 2000 Fire Protection 

System

E -18
3.4-FPS-1 0 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-1 1 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-12 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-FPS-13 July 28, 2000 October 10, 2000 Fire Protection 

System 

3.4-IA-1 July 28, 2000 October 10, 2000 Instrument Air 

System 

3.4-IN-1 July 28, 2000 October 10, 2000 Insulation System 

3.4-PSW-1 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-PSW-2 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-PSW-3 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-PSW-4 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-PSW-5 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-PSW-6 July 28, 2000 October 10, 2000 Plant Service Water 

System 

3.4-RBHVAC-1 July 28, 2000 October 10, 2000 Reactor Building HVAC 

3.4-RE-1 July 28, 2000 October 10, 2000 Refueling Equipment 

3.4-RE-2 July 28, 2000 October 10, 2000 Refueling Equipment 

3.4-RE-3 July 28, 2000 October 10, 2000 Refueling Equipment 

3.4-SS-1 July 28, 2000 October 10, 2000 Sampling System 

3.4-TSR-1 July 28, 2000 October 10, 2000 Traveling Water 

Screens/Trash Racks 

System 

3.4-TSR-2 July 28, 2000 October 10, 2000 Traveling Water 

Screens/Trash Racks 

System

E-19
3.5-EHC-1 July 28, 2000 October 10, 2000 Electro-Hydraulic 

Control System 

3.5-MC-1 July 28, 2000 October 10, 2000 Main Condenser 

3.5-MC-2 July 28, 2000 October 10, 2000 Main Condenser 

3.6-1 July 28, 2000 October 10, 2000 Structures 

3.6-2 July 28, 2000 October 10, 2000 Structures 

3.6-3 July 28, 2000 October 10, 2000 Structures 

3.6-4 July 28, 2000 October 10, 2000 Structures 

3.6-5 July 28, 2000 October 10, 2000 Structures 

3.6-6 July 28, 2000 October 10, 2000 Structures 

3.6-7 July 28, 2000 October 10, 2000 Structures 

3.6-8 July 28, 2000 October 10, 2000 Structures 

3.6-9 July 28, 2000 October 10, 2000 Structures 

3.6-10 July 28, 2000 October 10, 2000 Structures 

3.6-11 July 28, 2000 October 10, 2000 Structures 

3.6-12 July 28, 2000 October 10, 2000 Structures 

3.6-13 July 28, 2000 October 10, 2000 Structures 

3.6-14 July 28, 2000 October 10, 2000 Structures 

3.6-15 July 28, 2000 October 10, 2000 Structures 

3.6-16 July 28, 2000 October 10, 2000 Structures 

3.6-17 July 28, 2000 October 10, 2000 Structures 

3.6-18 July 28, 2000 October 10, 2000 Structures 

3.6-19 July 28, 2000 October 10, 2000 Structures 

3.6-20 July 28, 2000 October 10, 2000 Structures 

3.6-21 July 28, 2000 October 10, 2000 Structures 

3.6-22 July 28, 2000 October 10, 2000 Structures 

3.6-23 July 28, 2000 October 10, 2000 Structures 

3.6-24 July 28, 2000 October 10, 2000 Structures 

3.6-25 July 28, 2000 October 10, 2000 Structures

E - 20
3.6-26 July 28, 2000 October 10, 2000 Structures 

3.6-27 July 28, 2000 October 10, 2000 Structures 

3.6-28 July 28, 2000 October 10, 2000 Structures 

3.6-29 July 28, 2000 October 10, 2000 Structures 

3.6-30 July 28, 2000 October 10, 2000 Structures 

3.6-31 July 28, 2000 October 10, 2000 Structures 

3.6-32 July 28, 2000 October 10, 2000 Structures 

3.6-33 July 28, 2000 October 10, 2000 Structures 

3.6-34 July 28, 2000 October 10, 2000 Structures 

3.6-35 July 28, 2000 October 10, 2000 Structures 

3.6-36 July 28, 2000 October 10, 2000 Structures 

3.6-37 July 28, 2000 October 10, 2000 Structures 

3.6-38 July 28, 2000 October 10, 2000 Structures 

3.6-39 July 28, 2000 October 10, 2000 Structures 

3.6-40 July 28, 2000 October 10, 2000 Structures 

3.6-41 July 28, 2000 October 10, 2000 Structures 

3.6-42 July 28, 2000 October 10, 2000 Structures 

3.6-43 July 28, 2000 October 10, 2000 Structures 

3.6-44 July 28, 2000 October 10, 2000 Structures 

3.6-45 July 28, 2000 October 10, 2000 Structures 

3.6-46 July 28, 2000 October 10, 2000 Structures 

3.6-47 July 28, 2000 October 10, 2000 Structures 

3.6-48 July 28, 2000 October 10, 2000 Structures 

3.6-49 July 28, 2000 October 10, 2000 Structures 

3.6-50 July 28, 2000 October 10, 2000 Structures 

3.6-51 July 28, 2000 October 10, 2000 Structures 

3.6-52 July 28, 2000 October 10, 2000 Structures 

3.6-53 July 28, 2000 October 10, 2000 Structures

E - 21
3.6-54 July 28, 2000 October 10, 2000 Structures 

3.6-55 July 28, 2000 October 10, 2000 Structures 

4.1-1 July 28, 2000 October 10, 2000 TLAA 

4.1-2 July 28, 2000 October 10, 2000 TLAA 

4.2-1 July 28, 2000 October 10, 2000 TLAA 

4.2-2 July 28, 2000 October 10, 2000 TLAA 

4.2-3 July 28, 2000 October 10, 2000 TLAA 

4.2-4 July 28, 2000 October 10, 2000 TLAA 

4.4-1 July 28, 2000 October 10, 2000 TLAA 

4.4-2 July 28, 2000 October 10, 2000 TLAA 

4.5-1 July 28, 2000 October 10, 2000 TLAA 

4.5-2 July 28, 2000 October 10, 2000 TLAA 

4.5-3 July 28, 2000 October 10, 2000 TLAA 

4.5-4 July 28, 2000 October 10, 2000 TLAA 

4.6-1 July 28, 2000 October 10, 2000 TLAA 

4.6-2 July 28, 2000 October 10, 2000 TLAA 

4.6-3 July 28, 2000 October 10, 2000 TLAA 

4.6-4 July 28, 2000 October 10, 2000 TLAA 

4.7-1 July 28, 2000 October 10, 2000 TLAA

E - 22
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER 

(2-89) (Assigned by NRC, Add Vol., Supp., Rev., 

NRCM 1102, and Addendum Numbers, if any.) 

3201, 3202 BIBLIOGRAPHIC DATA SHEET 

(See instructions on the reverse) 

2. TITLE AND SUBTITLE NUREG-1803 

Safety Evaluation Report 

Related to the License Renewal of the Edwin I. Hatch Nuclear Plant, Units 1 and 2 3. DATE REPORT PUBLISHED 

MONTH YEAR 

Docket Nos. 50-321 and 50-366 December 2001 

4. FIN OR GRANT NUMBER 

5. AUTHOR(S) 6. TYPE OF REPORT 

Technical 

7. PERIOD COVERED (Inclusive Dates) 

February 2000 - October 2001 

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address: if contractor, 

provide name and mailing address.) 

Division of Regulatory Improvement Programs 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001'

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type 'Same as above'; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission, 

and mailing address.)

10. SUPPLEMENTARY NOTES 

Docket Numbers 50-321 and 50-366

11. ABSTRACT (200 words or less) 

This document is a safety evaluation report regarding the application to renew the operating licenses for the Edwin I. Hatch 

Nuclear Plants, Units 1 and 2 (Plant Hatch), which was filed by the Southern Nuclear Operating Company, Inc. by letter dated 

February 29, 2000. The Office of Nuclear Reactor Regulation has reviewed the Plant Hatch license renewal application for 

compliance with the requirements of Title 10 of the Code of Federal Regulations, Part 54, "Requirements for Renewal of 

Operating Licenses for Nuclear Power Plants," and prepared this report to document its findings. 

In its submittal of February 29, 2000, Southern Nuclear Operating Company requested renewal of the operating licenses 

(License Nos. DPR-57 and NPF-5) for Units 1 and 2, respectively. These licenses were issued under Sections 104 and 103 

respectively, of the Atomic Energy Act of 1954, as amended, for a period of 20 years beyond the current license expiration 

dates of August 6, 2014 for Unit 1, and June 13, 2018 for Unit 2. Plant Hatch is located in Appling County, Georgia, and 

consists of two General Electric (GE) boiling-water reactor (BWR) nuclear steam supply systems designed to generate 2763 

MW-thermal, or approximately 900 MW-electric. 

The NRC Plant Hatch license renewal project manager is William F. Burton. Mr. Burton may be contacted by calling (301) 

415-2853 or by writing to the License Renewal and Standardization Branch, U.S. Nuclear Regulatory Commission, Washington, 

DC 20555-0001.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT 

License Renewal unlimited 

Edwin I. Hatch Nuclear Plant 14. SECURITY CLASSIFICATION 

license renewal application (This Page) 

Plant Hatch unclassified 

Safety Evaluation Report (This Report) 

NUREG-1803 unclassified 

15. NUMBER OF PAGES 

16. PRICE

NRC FORM 335 (2-89) This form was electronically produced by Elite Federal Forms, Inc.
kpPrinted 

pan recycled 

Federal Recycling Program
UNITED STATES 

NUCLEAR REGULATORY COMMISSION 

WASHINGTON, DC 20555-0001 

OFFICIAL BUSINESS 

PENALTY FOR PRIVATE USE, $300