NUREG-1865

Safety Evaluation Report

Related to the License Renewal of

the Monticello Nuclear

Generating Plant

Docket No. 50-263

Nuclear Management Company, LLC

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001
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NUREG-1865

Safety Evaluation Report

Related to the License Renewal of

the Monticello Nuclear

Generating Plant

Docket No. 50-263

Nuclear Management Company, LLC

Manuscript Completed: October 2006

Date Published: October 2006

Division of License Renewal

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 Monticello Nuclear

Generating Plant (MNGP) license renewal application (LRA) by the staff of the U.S. Nuclear

Regulatory Commission (NRC or the staff). By letter dated March 16, 2005, Nuclear

Management Company, LLC (NMC or the applicant), submitted the LRA for MNGP in

accordance with Title 10, Part 54, "Requirements for Renewal of Operating Licenses for

Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). NMC is

requesting renewal of the operating license for MNGP (Facility Operating License Number

DPR-22) for a period of 20 years beyond the current expiration date of midnight September 8,

2010.

MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issued

the construction permit for MNGP on June 19, 1967. The NRC issued the operating license for

MNGP on January 9, 1981. MNGP is a single-cycle, forced circulation, General Electric BWR-3,

a boiling-water reactor producing steam for direct use in a steam turbine. General Electric

Corporation supplied the nuclear steam supply system and Bechtel Corporation originally

designed and constructed the balance of the plant. MNGP operates at a licensed power output

of 1775 megawatt thermal (MWt), with a gross electrical output of approximately 600 megawatt

electric (MWe).

The staff reviewed the MNGP LRA in accordance with Commission regulations and NUREG1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power

Plants," dated July 2001. Section 6 of this SER provides the staff's conclusion of its review of

the MNGP LRA.

The NRC license renewal project manager is Mr. Daniel Merzke. Mr. Merzke may be reached at

(301) 415-3777. Written correspondence should be addressed to the Division of License

Renewal, Mail Stop 0-11 F1, U.S. Nuclear Regulatory Commission, Washington, DC 20555-

0001.

iii

TABLE OF CONTENTS

A bstract ................ ................................................... iii

Table of Contents ........................................................... v.

Abbreviations ..... ......................................................... xiv

1 Introduction and General Discussion ......................................... 1-1

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

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

1.2.1 Safety Review ................................................. 1-3

1.2.2 Environmental Review ........................................... 1-4

1.3 Principal Review Matters .............................................. 1-5

1.4 Interim Staff G uidance ................................................. 1-6

1.5 Summary of Open Items .............................................. 1-8

1.6 Summary of Confirmatory Items ........................................ 1-8

1.7 Summary of Proposed License Conditions ................................ 1-8

2 Structures and Components Subject to 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 Scoping Methodology ..................................... 2-2

2.1.2.2 Screening Methodology ................................... 2-7

2.1.3 Staff Evaluation ................................................ 2-8

2.1.3.1 Scoping Methodology ..................................... 2-9

2.1.3.2 Screening Methodology ......... ......................... 2-20

2.1.3.3 QA Controls Applied to LRA Development .................... 2-24

2.1.3.4 Training ............................................ 2-24

2.1.4 Conclusion . . ................................................ 2-25

2.2 Plant-Level Scoping Results ........................................... 2-25

2.2.1 Introduction .................................................. 2-25

2.2.2 Summary of Technical Information in the Application .................. 2-25

2.2.3 Staff Evaluation ........... ........................... 2-25

2.2.4 Conclusion ................................................ 2-27

2.3 Scoping and Screening Results: Mechanical Systems ...................... 2-27

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ................ 2-28

2.3.1.1 Reactor Head Vent System ............................... 2-29

2.3.1.2 Reactor Pressure Vessel ................................ 2-30

2.3.1.3 Reactor Pressure Vessel Internals .......................... 2-32

2.3.1.4 Reactor Recirculation System .............................. 2-34

2.3.1.5 Reactor Vessel Instrumentation ............................ 2-37

2.3.2 Engineered Safety Features ..................................... 2-38

2.3.2.1 Automatic Pressure Relief System .......................... 2-39

2.3.2.2 Combustible Gas Control System ............................. 2-40

2.3.2.3 Core Spray System ...................................... 2-40

2.3.2.4 High-Pressure Coolant Injection System ..................... 2-42

v
2.3.2.5 Primary Containment Mechanical System ... 9 q 9 1 Panrtnr C'nro lnlnfinn r.nnlinn Ri-.Qftm

.................

2.3.2.7 Residual Heat Removal System ............................

2.3.2.8 Secondary Containment System .........................

2.3.3 Auxiliary System s .............................................

2.3.3.1 Alternate Nitrogen System .................................

2.3.3.2 Chemistry Sampling System ............................

2.3.3.3 Circulating Water System ..............................

2.3.3.4 Control Rod Drive System .... .............................

2.3.3.5 Demineralized Water System ...........................

2.3.3.6 Emergency Diesel Generators System .......................

2.3.3.7 Emergency Filtration Train System ........................

2.3.3.8 Emergency Service Water System .........................

2.3.3.9 Fire System ..................... ......................

2.3.3.10 Fuel Pool Cooling and Cleanup System .....................

2.3.3.11 Heating and Ventilation System ...........................

2.3.3.12 Instrument and Service Air System .......................

2.3.3.13 Radwaste Solid and Liquid System .........................

2.3.3.14 Reactor Building Closed Cooling Water System ...............

2.3.3.15 Reactor Water Cleanup System ............................

2.3.3.16 Service and Seal Water System ...........................

2.3.3.17 Standby Liquid Control System ............................

2.3.3.18 Wells and Domestic Water System ........................

2.3.4 Steam and Power Conversion System ...........................

2.3.4.1 Condensate Storage System ..............................

2.3.4.2 Condensate and Feedwater System .........................

2-43

2-45

2-46

2-48

2-49

2-50

2-51

2-52

2-54

2-55

2-56

2-59

2-61

2-63

2-71

2-74

2-77

2-79

2-85

2-86

2-89

2-91

2-92

2-93

2-93

2-96

2.3.4.3 Main Condenser System .......................

2.3.4.4 Main Steam System .........................

2.3.4.5 Turbine Generator System ....................

2.4 Scoping and Screening Results: Containments, Structures, and

Component Supports . .

2.4.1 Cranes, Heavy Loads, Rigging .........................

2.4.1.1 Summary of Technical Information in the Application ..

2.4.1.2 Staff Evaluation ............................

2.4.1.3 Conclusion ....... .............................

2.4.2 Diesel Fuel Oil Transfer House .........................

2.4.2.1 Summary of Technical Information in the Application ..

2.4.2.2 Staff Evaluation ...............................

2.4.2.3 Conclusion ...............................

2.4.3 Emergency Diesel Generator Building ....................

2.4.3.1 Summary of Technical Information in the Application ..

2.4.3.2 Staff Evaluation ..............................

2.4.3.3 Conclusion ...........

2.4.4 Emergency Filtration Train Building . ....................

2.4.4.1 Summary of Technical Information in the Application ..

2.4.4.2 Staff Evaluation ..............................

2.4.4.3 Conclusion ..................................

.......... 2-99

......... 2-103

.......... 2-105

. .......... 2-108

......... 2-109

......... 2-109

......... 2-110

......... 2-110

.......... 2-110

......... 2-110

......... 2-111

......... 2-112

.......... 2-113

2-113

2-114

2-114

2-114

2-114

2-115

2-116

2.4.5 Fire Protection Barriers Commodity Group .....................

2.4.5.1 Summary of Technical Information in the Application .......

.... 2-116

.... 2-116

vi
2.4.5.2 Staff Evaluation ....................................... 2-117

2.4.5.3 Conclusion ......................................... 2-118

2.4.6 Hangers and Supports Commodity Group .......................... 2-118

2.4.6.1 Summary of Technical Information in the Application ............ 2-118

2.4.6.2 Staff Evaluation ..................................... 2-122

2.4.6.3 Conclusion ......................................... 2-124

2.4.7 HPCI Building ............................................... 2-124

2.4.7.1 Summary of Technical Information in the Application ........... 2-124

2.4.7.2 Staff Evaluation ....................................... 2-125

2.4.7.3 Conclusion ......................................... 2-125

2.4.8 Intake Structure ................... ........................ 2-125

2.4.8.1 Summary of Technical Information in the Application ........... 2-125

2.4.8.2 Staff Evaluation ....................................... 2-127

2.4.8.3 Conclusion ......................................... .. 2-127

2.4.9 Miscellaneous SBO Yard Structures ............................. 2-127

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

2.4.9.2 Staff Evaluation ..................................... 2-128

2.4.9.3 Conclusion ........................................... 2-129

2.4.10 Offgas Stack ............................................... 2-129

2.4.10.1 Summary of Technical Information in the Application .......... 2-129

2.4.10.2 Staff Evaluation ...................................... 2-130

2.4.10.3 Conclusion ........................................ 2-130

2.4.11 Offgas Storage and Compressor Building ......................... 2-131

2.4.11.1 Summary of Technical Information in the Application .......... 2-131

2.4.11.2 Staff Evaluation .................................... 2-131

2.4.11.3 Conclusion ................................. '....2-132

2.4.12 Plant Control and Cable Spreading Structure ....................... 2-132

2.4.12.1 Summary of Technical Information in the Application .......... 2-132

2.4.12.2 S taff Evaluation ...................................... 2-133

2.4.12.3 Conclusion .......................................... 2-133

2.4.13 Primary Containment ...................................... 2-134

2.4.13.1 Summary of Technical Information in the Application .......... 2-134

2.4.13.2 Staff Evaluation ...................................... 2-136

2.4.13.3 Conclusion ........................................ 2-138

2.4.14 Radioactive W aste Building .................................... 2-138

2.4.14.1 Summary of Technical Information in the Application .......... 2-138

2.4.14.2 Staff Evaluation ...................................... 2-139

2.4.14.3 Conclusion .......................................... 2-140

2.4.15 Reactor Building ............................................ 2-140

2.4.15.1 Summary of Technical Information in the Application .......... 2-140

2.4.15.2 Staff Evaluation ...................................... 2-142

2.4.15.3 Conclusion .......................................... 2-142

2.4.16 Structures Affecting Safety .................................... 2-143

2.4.16.1 Summary of Technical Information in the Application .......... 2-143

2.4.16.2 Staff Evaluation ...................................... 2-144

2.4.16.3 Conclusion ........................................... 2-144

2.4.17 Turbine Building .......................................... 2-144

2.4.17.1 Summary of Technical' Information in the Application .......... 2-144

2.4.17.2 Staff Evaluation .................................... 2-146

vii
2.4.17.3 Conclusion .......................................... 2-147

2.4.18 Underground Duct Bank ...................................... 2-147

2.4.18.1 Summary of Technical Information in the Application .......... 2-147

2.4.18.2 Staff Evaluation ...................................... 2-148

2.4.18.3 Conclusion .......................................... 2-148

2.5 Scoping and Screening Results: Electrical and Instrumentation and

C ontrols ........... ............................................. 2-148

2.5.1 Electrical and Instrumentation and Controls Systems ................. 2-149

2.5.1.1 480-V Station Auxiliary ................................ 2-150

2.5.1.2 4.16-kV Station Auxiliary .................................. 2-151

2.5.1.3 Alternate Shutdown .................................... 2-152

2.5.1.4 Annunciators ........................ ........ ..... 2-153

2.5.1.5 Communications ....................................... 2-154

2.5.1.6 DC Battery ........................................ 2-155

2.5.1.7 Lighting ............... ............................ 2-157

2.5.1.8 Neutron Monitoring ...................................... 2-158

2.5.1.9 Qffsite Power .......................................... 2-159

2.5.1.10 Plant Protection ..................................... 2-159

2.5.1.11 Radiation Monitoring .................................... 2-160

2.5.1.12 Reactor Level Control ...... ............................ 2-161

2.5.1.13 Uninterruptible AC .................................... 2-162

2.5.2 Electrical Commodities ........................................ 2-163

2.5.2.1 Electrical Penetrations ................................ 2-164

2.5.2.2 Fuse Holders .......................................... 2-165

2.5.2.3 Non-EQ Cables and Connections .......... ................ 2-166

2.5.2.4 Offsite Power/SBO Recovery Path ......................... 2-167

2.6 Conclusion for Scoping and Screening .................................. 2-168

3 Aging Management Review Results ......................................... 3-1

3.0 Applicant's Use of the Generic Aging Lessons Learned Report ................. 3-1

3.0.1 Format of the License Renewal Application ........................... 3-2

3.0.1.1 Overview of Table 1 ...................................... 3-2

3.0.1.2 Overview of Table 2 ...................................... 3-3

3.0.2 Staff's Review Process .......................................... 3-4

3.0.2.1 Review of AMPs ......................................... 3-4

3.0.2.2 Review of AMR Results ................................... 3-5

3.0.2.3 USAR Supplement ....................................... 3-6

3.0.2.4 Documentation and Documents Reviewed ..................... 3-6

3.0.3 Aging Management Programs ................................... 3-6

3.0.3.1 AMPs That Are Consistent with the GALL Report ............... 3-10

3.0.3.2 AMPs That Are Consistent with the GALL Report with

Exceptions or Enhancements .............................. 3-30

3.0.3.3 AMPs That.Are Not Consistent with or Not Addressed

in the GALL Report ..................................... 3-128

3.0.4 Quality Assurance Program Attributes Integral to Aging

Management Programs .................. ......... ... 3.0.4.1 Summary of Technical Information in the Application .

3.0.4.2 Staff Evaluation ..............................

3.0.4.3 Conclusion .... .............................

3-139

3-140

3-141

3-141

viii
3.1 Aging Management of Reactor Coolant System ........................... 3-141

3.1.1 Summary of Technical Information in the Application .................. 3-141

3.1.2 Staff Evaluation ........................................... 3-142

3.1.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-149

3.1.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-153

3.1.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ............................ 3-161

3.1.3 Conclusion ......... ...................................... 3-165

3.2 Aging Management of Engineered Safety Features ........................ 3-165

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

3.2.2 Staff Evaluation ........................................... 3-166

3.2.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-170

3.2.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-172

3.2.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ............................ 3-181

3.2.3 Conclusion .................................................. 3-190

3.3 Aging Management of Auxiliary Systems ................................ 3-190

3.3.1 Summary of Technical Information in the Application ................. 3-191

3.3.2 Staff Evaluation .............................................. 3-191

3.3.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-197

3.3.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-200

3.3.2.3 AMR Results That Are.Not Consistent with or Not

Addressed in the GALL Report ............................ 3-211

3.3.3 Conclusion ................................................... 3-240

3.4 Aging Management of Steam and Power Conversion System ............... 3-240

3.4.1 Summary of Technical Information in the Application ................. 3-240

3.4.2 Staff Evaluation .................... ...... 3-240

3.4.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-243

3.4.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-246

3.4.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report .......................... 3-250

3.4.3 Conclusion .................................................... 3-258

.3.5 Aging Management of Containments, Structures, and Component Supports

................................................... 3-258

3.5.1 Summary of Technical Information in the Application ................. 3-258

3.5.2 Staff Evaluation .............................................. 3-259

3.5.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-266

3.5.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-268

3.5.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ............................ 3-281

3.5.3 Conclusion ........ ...................................... 3-305

3.6 Aging Management of Electrical and Instrumentation and Controls ............ 3-305

3.6.1 Summary of Technical Information in the Application ................. 3-305

3.6.2 Staff Evaluation ............................................... 3-306

ix
3.6.2.1 AMR Results That Are Consistent with the GALL Report ........ 3-308

3.6.2.2 AMR Results That Are Consistent with the GALL Report,

for Which Further Evaluation is Recommended ............... 3-310

3.6.2.3 AMR Results That Are Not Consistent with or Not

Addressed in the GALL Report ............................. 3-311

3.6.3 Conclusion ............................................... 3-319

3.7 Conclusion for Aging Management Review Results ....................... 3-320

4 Time-Limited Aging Analyses 4-1

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

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

4.1.2 Staff Evaluation ................................................ 4-2

4.1.3 Conclusion .................................................... 4-2

4.2 Neutron Embrittlement of the Reactor Vessel and Internals .................... 4-2

4.2.1 RPV Materials USE Reduction Due to Neutron Embrittlemenrt............. 4-3

4.2.1.1 Summary of Technical Information in the Application ............. 4-3

4.2.1.2 Staff Evaluation ....................................... 4-4

4.2.1.3 USAR Supplement ..................................... 4-9

4.2.1.4 Conclusion ....... 4-9

4.2.2 Adjusted Reference Temperature (ART) for RPV Materials Due

to Neutron Embrittlement .......................................... 4-9

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

4.2.2.2 Staff Evaluation .......................................... 4-9

4.2.2.3 USAR Supplement ....................................... 4-10

4.2.2.4 Conclusion ................................. 4-10

4.2.3 Reflood Thermal Shock Analysis of the RPV ......................... 4-10

4.2.3.1 Summary of Technical Information in the Application ............ 4-10

4.2.3.2 Staff Evaluation ......................................... 4-10

4.2.3.3 USAR Supplement .............................. ...... 4-12

4.2.3.4 Conclusion .......................................... 4-12

4.2.4 Reflood Thermal Shock Analysis of the RPV Core Shroud .............. 4-12.

4.2.4.1 Summary of Technical Information in the Application ............ 4-12

4.2.4.2 Staff Evaluation ...................................... 4-12

4.2.4.3 .USAR Supplement ...................................... 4-13

4.2.4.4 Conclusion ............................................ 4-13

4.2.5 RPV Thermal Limit Analysis: Operating Pressure-Temperature

Limits ................................................... 4-13

4.2.5.1 Summary of Technical Information in the Application ............ 4-13

4.2.5.2 Staff Evaluation . ....................................... 4-14

4.2.5.3 USAR Supplement ...................................... 4-14

4.2.5.4 Conclusion ............................................ 4-14

4.2.6 RPV Circumferential Weld Examination Relief ...................... 4-15

4.2.6.1 Summary of Technical Information in the Application............ 4-15

4.2.6.2 Staff Evaluation ...................................... 4-15

4.2.6.3 USAR Supplement .................................... 4-17

4.2.6.4 Conclusion .......................................... 4-17

4.2.7 RPV Axial W eld Failure Probability ................................ 4-17

4.2.7.1 Summary of Technical Information in the Application ............ 4-17

4.2.7.2 Staff Evaluation ...................................... 4-17

x
4.2.7.3 USAR Supplement ............................. I.......... 4-18

4.2.7.4 Conclusion ......................................... 4-18

4.3 Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure

Boundary Piping and Components ..................................... 4-19

4.3.1 RPV Fatigue Analyses .......................................... 4-19

4.3.1.1 Summary of Technical Information in the Application ............. 4-19

4.3.1.2 Staff Evaluation ........................................ 4-19

4.3.1.3 USAR Supplement ...................................... 4-20

4.3.1.4 Conclusion ......................................... 4-20

4.3.2 Fatigue Analysis of RPV Internals ................................. 4-21

4.3.2.1 Summary of Technical Information in the Application ............ 4-21

4.3.2.2 Staff Evaluation ......................................... 4-21

4.3.2.3 USAR Supplement ....................................... 4-22

4.3.2.4 Conclusion ............................................ 4-22

4.3.3 ASME Section III Class 1 Reactor Coolant Pressure Boundary

(RCPB) Piping and Fatigue Analysis ............................... 4-22

4.3.3.1 Summary of Technical Information in the Application ............ 4-22

4.3.3.2 Staff Evaluation ........................................ 4-22

4.3.3.3 USAR Supplement ........... ........................... 4-23

4.3.3.4 Conclusion ......................................... 4-24

4.3.4 RCPB Section III Class 2 and 3, Piping and Components ............... 4-24

4.3.4.1 Summary of Technical Information in the Application ............ 4-24

4.3.4.2 Staff Evaluation .................................. ...... 4-24

4.3.4.3 USAR Supplement ............... ....................... 4-25

4.3.4.4 Conclusion .................. ....................... 4-25

4.4 Irradiation-Assisted Stress-Corrosion Cracking (IASCC) .................... 4-25

4.4.1 Summary of Technical Information in the Application .................. 4-25

4.4.2 Staff Evaluation ............................................... 4-25

4.4.3 USAR Supplement ............................................ 4-27

4.4.4 Conclusion ............................. ..................... 4-27

4.5 Effects of Reactor Coolant Environment ................................. 4-27

4.5.1 Summary of Technical Information in the Application .................. 4-27

4.5.2 Staff Evaluation ........................................ -. 4-28

4.5.3 USAR Supplement ............................................ 4-30

4.5.4 Conclusion ................................................... 4-30

4.6 Fatigue Analyses of the Primary Containment, Attached Piping, and

Components ..................... ........ 4-30

4.6.1 Fatigue Analysis of the Suppression Chamber, Vents, and

Downcom ers ................................................. 4-31

4.6.1.1 Summary of Technical Information in the Application ............ 4-31

4.6.1.2 Staff Evaluation ........................................ 4-31

4.6.1.3 USAR Supplement ...................................... 4-31

4.6.1.4 Conclusion ............................................ 4-31

4.6.2 Fatigue Analysis of the SRV Piping Inside the Suppression

Chamber and Internal Structures ................................... 4-32

4.6.2.1 Summary of Technical Information in the Application ............ 4-32

4.6.2.2 Staff Evaluation ....................................... 4-32

4.6.2.3 USAR Supplement ...................................... 4-32

4.6.2.4 Conclusion ............................................ 4-33

xi
4.6.3 Fatigue Analysis of Suppression Chamber External Piping and Penetrations

4.6.3.1 Summary of Technical Information in the Application ............

4.6.3.2 Staff Evaluation ........................................

4.6.3.3 USAR Supplement ........................................

4-33

4-33

4-33

4-34

4.6.3.4 Conclusion ..................................

4.6.4 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue

Analysis .......................................

4.6.4.1 Summary of Technical Information in the Application ..

4.6.4.2 Staff Evaluation ............................

4.6.4.3 USAR Supplement ............................

4.6.4.4 Conclusion ..................................

4.6.5 Primary Containment Process Penetration Bellows Fatigue

A nalysis ...........................................

4.6.5.1 Summary of Technical Information in the Application ..

4.6.5.2 Staff Evaluation ..............................

4.6.5.3 USAR Supplement ............................

4.6.5.4 .Conclusion ..................................

4.7 Environmental Qualification of Electrical Equipment (EQ) .......... 4.7.1 Summary of Technical Information in the Application ........

4.7.2 Staff Evaluation .....................................

4.7.3 USAR Supplement ..................................

.......... 4-34

.......... 4-34

.......... 4-34

.......... 4-34

.......... 4-35

.......... 4-35

. . . . . . . . . .

. . . . . . . . . .

4-35

4-35

4-35

4-36

4-36

4-36

4-36

4-36

4-39

4.7.4 Conclusion.. ...................... 4-39

4.8 Stress Relaxation of Rim Holddown Bolts .............................

4.8.1 Summary of Technical Information in the Application ..................

4.8.2 Staff Evaluation ............................. .................

4.8.3 USAR Supplement .................... ........................

4.8.4 Conclusion ...................................................

4.9 Reactor Building Crane Load Cycles .................................

4.9.1 Summary of Technical Information in the Application ..................

4.9.2 Staff Evaluation ................................................

4.9.3 USAR Supplement .........................................

4.9.4 C onclusion ............................................ .......

4.10 Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations ...........

4.10.1 Summary of Technical Information in the Application .................

4.10.2 Staff Evaluation ..............................................

4.10.3 USAR Supplement ........... .................................

4.10.4 Conclusion ......................................... ........

4.11 Conclusion for Time-Limited Aging Analyses .............................

4-39

4-39

4-39

4-42

4-43

4-43

4-43

4-43

4-44

4-45

4-45

4-45

4-45

4-46

4-46

4-46

5 Review by the Advisory Committee on Reactor Safeguards ...................... 5-1

6 C onclusion ............................................................ 6-1

xii
Appendices

Appendix A: Commitments for License Renewal ................................. A-1

Appendix B: Chronology ................................................... B-1

Appendix C: Principal Contributors ........................................... C-1

Appendix D: References ................................................... D-1

Tables

Table 3.0.3-1 MNGP's Aging Management Programs ............................... 3-6

Table 3.1-1 Staff Evaluation for Reactor Coolant System Components in the GALL

R eport ................................................................ 3-143

Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the

G ALL Report ............................................................ 3-167

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report ... 3-192

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components

in the GALL Report ...................................................... 3-241

Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports in the

G ALL Report ........................................................... 3-260

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls

Components in the GALL Report ........................................... 3-307

Table 4.2.1-1 Reactor Vessel Upper Shelf Energy Analysis Summary ................. 4-8

Table 4.2.6-1 Effects of Irradiation on RPV Circumferential Weld Properties for MNGP .. 4-16

Table 4.2.7-1 Effects of Irradiation on RPV Axial Weld Properties for MNGP .......... 4-18

xiii
ABBREVIATIONS

AC alternating current

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Document Access and Management System

ADS automatic depressurization system

AERM aging effect requiring management

AFW auxiliary feedwater

SAIR instrument and service air

AMAs aging management activities

AMG aging management guideline

AMP aging management program

AMR aging management review

AN2 alternate nitrogen system

ANSI American National Standards Institute

APR automatic pressure relief

APRM average power range monitor

AR action request

ARM area radiation monitor

ART adjusted reference temperature

ASA American Standards Association

ASD alternate shutdown

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

AWl administrative work instruction

B&W Babcock and Wilcox

BWR boiling-water reactor

BWROG Boiling Water Reactor Owners Group

BWRVIP Boiling Water Reactor Vessel and Internals Project

CAP Corrective Action Program

CASS cast austenitic stainless steel

CB&I Chicago Bridge & Iron

CCCW closed-cycle cooling water

CCW closed cooling water or component cooling water

CDR main condenser

CE Combustion Engineering

CFR Code of Federal Regulations

CFW condensate and feedwater

CGC combustible gas control

CI confirmatory item

CLB current licensing basis

CMAA Crahe Manufacturers Association of America

CR condition report

xiv
CRD control rod drive

CRDA control rod drop accident

CRDM control rod drive mechanism

CRGT control rod guide tube

CS containment spray

CSP core spray

CST condensate storage tank

CUF cumulative usage factor

CVCS chemical and volume control system

CW circulating water

DBA design-basis accident

DBD design-basis document

DBE design-basis event

DC direct current

DG diesel generator

DGN EDG system

DOE Department of Energy

DOL diesel oil

DWS demineralized water system

ECCS emergency core cooling system

ECP electrochemical potential

EDG emergency diesel generator

EFB emergency filtration train building

EFPY effective full-power years

EFT emergency filtration train

EMA equivalent margin analysis

EOCI Electric Overhead Crane Institute

EOL end of license

EPRI Electric Power Research Institute

EQ environmental qualification

ESF engineered safety feature

ESW emergency service water

FAC flow-accelerated corrosion

FERC Federal Energy Commission, U.S.

Fen environmental fatigue factor

FHA fire hazards analysis

FIR fire system

FP fire protection

FPC fuel pool cooling and cleanup

FR Federal Register

ft-lb foot-pound

FPP fire protection plan

FSAR final safety analysis report

FSD functional system description

FW feedwater

xv
GALL generic aging lessons learned

GE General Electric

GElS Generic Environmental Impact Statement

GL generic letter

GSI generic safety issue

HCU hydraulic accumulator

HELB high-energy line break

HP horsepower

HE/ME high energy/moderate energy

HEPA high efficiency particulate filter

HGR hangers and supports

HJTC heated junction thermocouple

HPB HPCI building

HPC high pressure coolant injection

HPCI high-pressure coolant injection

HTV heating and ventilation

HVAC heating, ventilation, and air conditioning

HWC hydrogen water chemistry

I&C instrumentation and controls

IASCC irradiation assisted stress-corrosion cracking

ID inside diameter

IEB Inspection and Enforcement Bulletin

IEEE Institute of Electrical and Electronics Engineers

IF intended function

IGA intergranular attack

IGSCC intergranular stress-corrosion cracking

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

IR insulation resistance

IRM intermediate range monitor

ISA Instrument Society of America

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

IWB requirements for Class 1 components of light-water cooled power plants

IWC requirements for Class 2 components of light-water cooled power plants

IWD requirements for Class 3 components of light-water cooled power plants

IWE requirements for Class MC and metallic liners of Class CC components of

light-water cooled power plants

IWF requirements for, Class 1, 2,'3, and MC component supports of light-water cooled

power plants

IWL requirements for Class CC concrete components of light-water cooled power

plants

ksi one KIP per square inch, 1000 psi

ksi-in" 2 kilopound per square inch times square root of inches

xvi
kV 1000 volts or 1 kilovolt

Ib/ft 2 pound(s) per square foot

LIS Licensing Information Service

LLC limited liability company

LO lubricating oil

LLRT local leak-rate test

LOCA loss-of-coolant accident

LOOP loss of offsite power

LP low pressure

LPCI low-pressure coolant injection

LPRM local power range monitor

LR license renewal

LRA license renewal application

MCC motor control center

MCR main control room

MEAP material, environment, aging effects, and aging management program

MeV million electron volts

MIC microbiologically influenced corrosion

MNGP Monticello Nuclear Generating Plant

MOD motor-operated disconnect

MR maintenance rule

MSIV main steam isolation valve

MST main steam

MTEB NOT DEFINED

.MUD makeup demineralizer

MVP mechanical vacuum pump -MW megawatts

MWe megawatt electric

MWh megawatt hour

MWt megawatt thermal

n/cm 2 neutrons per square centimeter

NDE nondestructive examination

NEI Nuclear Energy Institute

NEPA National Environmental Policy Act of 1969

NFPA National Fire Protection Association

NMC Nuclear Management Company, LLC

NMS neutron monitoring system

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

NSR nonsafety-related

NSSS nuclear -steam supply system

NUMARC Nuclear Utility Management and Resource Council

NUREG designation of publication prepared by NRC staff

OBE operating-basis earthquake

xvii
OCCW open-cycle cooling water program

ODSCC outside-diameter stress-corrosion cracking

OE operating experience

OGB off gas storage and compressor building

OGS off gas stack

01 open item

P&ID piping and instrumentation diagram

PA public address system

PAB plant administration building

PASS post-accident sampling system

PBD program-basis document

PBX private branch exchange

PCIS primary containment isolation system

PCM primary containment mechanical

PCS process computer system

PCT primary containment

pH concentration of hydrogen ions

PM preventive maintenance

ppb parts per billion

ppm parts per million

PPS plant protection system

PRM process radiation monitor

psi pounds per square inch

psig pounds per square inch gauge

P-T pressure temperature

PT penetrant testing

PVC polyvinyl chloride (plastic)

PWR pressurized-water reactor

PWSCC primary water stress-corrosion cracking

QA quality assurance

QC quality control

Q-List quality list

RAD radwaste solid and Dquid

RAI request for additional information

RBC reactor building closed cooling water

RBM rod block monitor

RCI reactor core isolation cooling

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

REC reactor recirculation

RG regulatory guide

RHR residual heat removal

RI-ISI risk-informed inservice inspection

xviii
RIT reactor internals

RLC reactor level control

RPV reactor pressure vessel

RSW residual heat removal service water

RTNDT reference temperature nil ductility transition

RVI reactor vessel instrumentation

RVID Reactor Vessel Integrity Database

RWB radioactive waste building

RWC reactor water cleanup

SBO station blackout

SC structure and component

SCBA self-contained breathing apparatus

SCC stress-corrosion cracking

SCT secondary containment

SE safety evaluation

SER safety evaluation report

SFP spent fuel pool

SI safety injection

SIL service information letter

SJAE steam jet air ejector

SLC standby liquid control

SMAW shield metal arc weld

SOER significant operating event report

SPC steam and power conversion

SPDS safety parameter display system

SR safety-related

SRM source range monitor

SRP Standard Review Plan

SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants

SRV safety relief valve

SSC system, structure, or component

SSW service & seal water

SW service water

TAC technical assignment control (internal NRC work management tool)

TAP torus attached piping

TASCS thermal stratification, cycling, and striping

TGSCC transgranular stress-corrosion cracking

TLAA time-limited aging analysis

TR topical report

TS technical specification

TT thermal transient

UAC uninterruptible alternating current

Pm micrometer

UDB underground duct bank

UPS uninterruptible power supply

xix
USAR Updated Safety Analysis Report

USAS United States of America Standards

USE upper-shelf energy

UT ultrasonic testing

UV ultraviolet

VAC volts-alternating current

VDC volts-direct current

VT visual examination.

WDW well and domestic water

WO work order

XLPE cross-linked polyethylene

Xx
SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a safety evaluation report (SER) on the application for license renewal (LR)

for the Monticello Nuclear Generating Plant (MNGP), as filed by the Nuclear Management

Company, LLC (NMC or the applicant). By letter dated March 16, 2005, NMC submitted its

application to the U.S. Nuclear Regulatory Commission (NRC or the Commission) for renewal

of the MNGP operating license for an additional 20 years. The NRC staff (the staff) prepared

this report, which summarizes the results of its safety review of the renewal application for

compliance with the requirements of Title 10, Part 54, "Requirements for Renewal of Operating

Licenses for Nuclear Power Plants," of the Code of FederalRegulations (10 CFR Part 54). The

NRC license renewal project manager for the MNGP license renewal review is Daniel Merzke.

Mr. Merzke can be contacted by telephone at 301-415-3777 or by electronic mail at

DXM2 @ nrc.qov. Alternatively, written correspondence may be sent to the following address:

Division of License Renewal

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: Daniel Merzke, Mail Stop 0-11 F1

In its March 16, 2005, submittal letter, the applicant requested renewal of the operating license

issued under Section 104b (Operating License No. DPR-22) of the Atomic Energy Act of 1954,

as amended, for MNGP, for a period of 20 years beyond the current license expiration date of

midnight September 8, 2010. MNGP is located approximately 30 miles northwest of

Minneapolis, Minnesota. The NRC issued the construction permit for MNGP on June 19, 1967.

The NRC issued the operating license for MNGP on January 9, 1981. MNGP is a single-cycle,

forced circulation, General Electric BWR-3, boiling-water reactor producing steam for direct use

in a steam turbine. General Electric Corporation supplied the nuclear steam supply system and

Bechtel Corporation originally designed and constructed the balance of the plant. MNGP

operates at a licensed power output of 1775 megawatt thermal (MWt), with a gross electrical

output of approximately 600 megawatt electric (MWe). The Updated Safety Analysis Report

(USAR) contains details concerning the plant and the site.

The license renewal process consists of two concurrent reviews-a technical review of safety

issues and an environmental review. The NRC regulations found in 10 CFR Part 54 and 10

CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related

Regulatory Functions," respectively, set forth the requirements for these reviews. The safety

review for the MNGP license renewal is based on the applicant's license renewal application

(LRA) and on its responses to the staff's requests for additional information (RAIs). The

applicant supplemented and clarified its responses to the LRA and RAIs in audits, meetings,

and docketed correspondence. The staff reviewed and considered all information submitted in

support of the LRA. The public may view the LRA and all pertinent information and materials,

including the USAR mentioned above, at the NRC Public Document Room, located in One

White Flint North, 11555 Rockville Pike (first floor), Rockville, MD 20852-2738

(301-415-4737/800-397-4209), and at the Monticello Public Library, 200 West 6th Street,

1-1
Monticello, MN 55362. In addition, the public may find the MNGP LRA, as well as materials

related to the license renewal review, on the NRC Web site at http://www.nrc.gov.

This SER summarizes the results of the staff's safety review of the MNGP LRA and describes

the technical details considered in evaluating the safety aspects of the unit's proposed

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

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

NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants" (SRP-LR), dated July 2001.

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

issues that it considered during the review of the application. Section 5 is reserved for the report

of the Advisory Committee on Reactor Safeguards (ACRS). Section 6 provides the conclusions

of this report.

Appendix A to this SER is a table that identifies the applicant's commitments associated with

the renewal of the operating license. Appendix B provides a chronology of the principal

correspondence between the NRC and the applicant related to the review of the application.

Appendix C is a list of principal contributors to the SER. Appendix D is a bibliography of the

references used in support of the review.

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

Generic Environmental Impact Statement (GELS). This supplement discusses the

environmental considerations related to renewing the license for MNGP. The staff issued draft

Supplement 26 to NUREG-1 437,"Generic Environmental Impact Statement for License

Renewal of Nuclear Plants Regarding Monticello Nuclear Generating Plant (NUREG-1437,

Supplement 26) Draft Report for Comment," on January 23, 2006.

1.2 License Renewal Background

Pursuant to Section 1 03c of the Atomic Energy Act of 1954, as amended, and NRC regulations

(10 CFR 50.51(a)), operating licenses for commercial power reactors are issued for 40 years.

Pursuant to 10 CFR 54.31 (b), 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, rather than on 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 anticipated interest in license renewal and held a workshop on nuclear power

plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear

plant aging research. 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 license renewal for nuclear power plants.

In 1991, the NRC published the license renewal rule in 10 CFR Part 54 (the Rule) (Volume 56,

page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The NRC

participated in an industry-sponsored demonstration program to apply the Rule to a pilot plant

1-2
and to gain experience necessary to develop 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, the NRC amended the Rule in 1995. As published in 60 FR 22461, dated May 8,1995,

the amended 10 CFR Part 54 establishes a regulatory process that is simpler, more stable, and

more predictable than the previous Rule. In particular, the NRC amended 10 CFR Part 54 to

focus on managing the adverse effects of aging, rather than on identifying age-related

degradation unique to license renewal. The NRC initiated these rule changes to ensure that

important systems, structures, and components (SSCs) will continue to perform their intended

functions during the period of extended operation. In addition, the revised Rule clarified and

simplified the integrated plant assessment (IPA) process to be consistent with the revised focus

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

In parallel with these initiatives, the NRC pursued a separate rulemaking effort (61 FR 28467,

dated June 5, 1996) and developed an amendment to 10 CFR Part 51 to focus the scope of the

review of environmental impacts of license renewal and to fulfill the NRC's responsibilities under

the National Environmental Policy Act of 1969 (NEPA).

1.2.1 Safety Review

License renewal requirements for power reactors are based on two key principles:

(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 SSCs, as well

as a few other safety-related (SR) issues, 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, 10 CFR 54.4, "Scope," defines the scope of license

renewal as including those SSCs (1) that are SR, (2) whose failure could affect SR functions,

and (3) that are relied on to demonstrate compliance with the NRC's regulations for fire

protection (FP), environmental qualification (EQ), pressurized thermal shock (PTS), anticipated

transient without scram (ATWS), and station blackout (SBO).

Pursuant to 10 CFR 54.21 (a), an applicant for a renewed license must review all SSCs that are

within the scope of the Rule to identify SCs that are subject to an aging management review

(AMR). Those SCs that are subject to an AMR perform an intended function without moving

parts, or without a change in configuration or properties, and are not subject to replacement

based on qualified life or specified time period. As required by 10 CFR 54.21 (a), an applicant

for a renewed license must demonstrate 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 (CLB), for the period of extended operation; however, active equipment

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

the detrimental effects of aging that may affect active equipment are more readily detectable

1-3
and can be identified and corrected through routine surveillance, performance monitoring, and

maintenance activities. The surveillance and maintenance activities programs for active

equipment, as well as other aspects of maintaining the plant's design and licensing basis, are

required throughout the period of extended operation.

Pursuant to 10 CFR 54.21 (d), each LRA is required to include a supplement to the USAR. This

supplement must contain a summary description of the applicant's programs and activities for

managing the effects of aging and the evaluation of time-limited aging analyses (TLAAs) for the

period of extended operation.

License renewal also requires the identification and updating of the TLAAs. During the design

phase for a plant, certain assumptions are made about the length of time the plant can operate.

These assumptions are incorporated into design calculations for several of the plant's SSCs. In

accordance with 10 CFR 54.21 (c)(1), the applicant must either show that these calculations will

remain valid for the period of extended operation, project the analyses to the end of the period

of extended operation, or demonstrate that the effects of aging on these SSCs can be

adequately managed for the period of extended operation.

In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format and

Content for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses

NEI 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR

Part 54-The License Renewal Rule," which the Nuclear Energy Institute (NEI) issued in March

2001. NEI 95-10 details an acceptable method of implementing the license renewal rule. The

NRC also used the SRP-LR to review this application.

In the LRA, MNGP fully utilizes the process defined in NUREG-1 801, "Generic Aging Lessons

Learned (GALL) Report," issued in July 2001. The GALL Report provides a summary of

staff-approved aging management programs (AMPs) for the aging of many SCs that are

subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the

time, effort, and resources used to review an applicant's LRA can be greatly reduced, thereby

improving the efficiency and effectiveness of the license renewal review process. The GALL

Report summarizes the aging management evaluations, programs, and activities credited for

managing aging for most of the SCs used throughout the industry. The report also serves as a

reference for both applicants and staff reviewers to quickly identify those AMPs and activities

that the staff has determined can provide adequate aging management during the period of

extended operation.

1.2.2 Environmental Review

In December 1996, the staff revised the environmental protection regulations to facilitate the

environmental review for license renewal. The staff prepared NUREG-1437, Revision 1,

"Generic Environmental Impact Statement for License Renewal of Nuclear Plants," to

document its evaluation of 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 codified in Appendix B, "Environmental Effect of Renewing the Operating License

of a Nuclear Power Plant," to Subpart A, "National Environmental Policy Act-Regulations

Implementing Section 102(2)," of 10 CFR Part 51. Pursuant to 10 CFR 51.53(c)(3)(i), an

1-4
applicant for license renewal may incorporate these generic findings in its environmental report.

In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses

of those environmental impacts that.must be evaluated on a plant-specific basis (i.e.,

Category 2 issues).

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

plant-specific review of the environmental impacts of license renewal, including whether new

and significant information existed that the GElS did not consider. As part of its scoping

process, the NRC held a public meeting on June 30, 2005, in Monticello, Minnesota, to identify

environmental issues specific to the plant. The NRC's draft plant-specific Supplement 26 to the

GElS regarding MNGP documents the results of the environmental review and includes a

preliminary recommendation with respect to the license renewal action. The NRC held. another

public meeting on March 22, 2006, in Monticello, Minnesota, to discuss the draft plant-specific

Supplement 26 to the GElS regarding MNGP. After considering comments on the draft, the

NRC will prepare and publish a final, plant-specific supplement to the GElS separately from this

report.

1.3 Principal Review Matters

Title 10, Part 54, of the Code of Federal Regulations describes the requirements for renewing

operating licenses for nuclear power plants. The staff performed its technical review of the

MNGP LRA in accordance with NRC guidance and the requirements of 10 CFR Part 54.

.Title 10, Section 54.29, "Standards for Issuance of a Renewed License," of the Code of Federal

Regulations sets forth the standards for renewing a license. This SER describes the results of

the staff's safety review.

In 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general

information. The applicant provided this general information in Section 1 of its LRA for MNGP,

which it submitted to the NRC by letter dated March 16, 2005. The staff reviewed Section 1 and

found that the applicant had submitted the information required by 10 CFR 54.19(a).

In 10 CFR 54.19(b), the NRC requires that each LRA 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 stated the following in the LRA regarding this

issue:

The current indemnity agreement No. B-42 for the Monticello Nuclear Generating

Plant states that the agreement shall terminate at the time of expiration of the

license.

The indemnity agreement lists DPR-22 as the applicable license number. Should

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

requests that conforming changes be made to the indemnity agreement as

appropriate.

The staff intends to maintain the original license number upon issuance of the renewed license.

Therefore, conforming changes to the indemnity agreement do not need to be made, and the

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

1-5
In 10 CFR 54.21, "Contents of Application-Technical Information," the NRC requires that each

LRA must contain (a) an IPA, (b) a description of any CLB changes that occurred during the

staff review of the LRA, (c) an evaluation of TLAAs, and (d) an FSAR (Final Safety Analysis

Report) supplement. Sections 3 and 4 and Appendix B to the LRA address the license renewal

requirements of 10 CFR 54.21 (a), (b), and (c). Appendix A to the LRA contains the USAR

supplement required by 10 CFR 54.21 (d).

In 10 CFR 54.21 (b), the NRC requires that each year following submission of the LRA, and at

least 3 months before the scheduled completion of the staff's review, the applicant must submit

an amendment to the renewal application that identifies any changes to the CLB of the facility

that materially affect the contents of the LRA, including the USAR supplement. The applicant

submitted an update to the LRA by letter dated March 15, 2006, which summarized the

changes to the CLB that had occurred at MNGP during the staff's review of the LRA. This

submission satisfies the requirements of 10 CFR 54.21 (b) and is still under staff review.

In accordance with 10 CFR 54.22, "Contents of Application-Technical Specifications," an

applicant's LRA must include changes or additions to the technical specifications (TSs) that are

necessary to manage the effects of aging during the period of extended operation. In

Appendix D to the LRA, the applicant stated that it had not identified any TS changes necessary

to support issuance of the renewed operating license for MNGP. This adequately addresses the

requirement specified in 10 CFR 54.22.

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

accordance with NRC regulations and the guidance provided by the SRP-LR. Sections 2, 3, and

4 of this SER document the staff's evaluation of the technical information contained in the LRA.

As required by 10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards," the

ACRS will issue a report to document its evaluation of the staff's LRA review and associated

SER. SER Section 5 will incorporate the ACRS report once it is issued. SER Section 6 will

document the findings required by 10 CFR 54.29, "Standards for Issuance of a Renewed

License."

The final plant-specific supplement to the GElS will document the staff's evaluation of the

environmental information required by 10 CFR 54.23, "Contents of Application-Environmental

Information," and will specify the considerations related to renewing the license for MNGP. The

staff will prepare this supplement separately from this SER.

1.4 Interim Staff Guidance

The license renewal program is a living program. The NRC staff, industry, and other interested

stakeholders gain experience and develop lessons learned with each renewed license. The

lessons learned address the NRC's performance goals of safety, openness, and effectiveness.

Interim staff guidance (ISG) is documented for use by the NRC staff, industry, and other

interested stakeholders until it is incorporated into license renewal guidance documents, such

as the SRP-LR and the GALL Report.

Table 1.4-1 provides the current set of ISGs issued by the staff, as well as the SER sections in

which the staff addresses them.

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Table 1.4-1 Current Interim Staff Guidance

ISG Issue 1•Purpose I SER Section

(ApprovedISG No.) J._ _ _...._ _ _ _

GALL Report presents one This ISG clarifies that the GALL N/A

acceptable way to manage aging Report contains one acceptable

effects way, but not the only way, to

(ISG-1) manage aging for license renewal.

SBO Scoping The license renewal rule 2.5.2.4

(ISG-2) 10 CFR 54.4(a)(3) includes

10 CFR 50.63(a)(1)-SBO.

The SBO rule requires that a plant

must withstand and recover from

an SBO event. The recovery time

for offsite power is much faster

than that of EDGs.

The offsite power system should be

included within the scope of license

renewal.

Concrete AMP Lessons learned from the GALL 3.5.2.2

(ISG-3) demonstration project indicate that 3.5.2.3

GALL is not clear on whether

concrete requires an AMP.

FP System Piping This ISG clarifies the staff position 3.0.3.2.16

(ISG-4) for wall-thinning of the FP piping 3.3.2.3.9

system in GALL AMPs XI.M26 and

Xl.M27.

The staff's new position is that

there is no need to disassemble FP

piping, as disassembly can

introduce oxygen to FP piping,

which can accelerate corrosion.

Instead, a nonintrusive method,

such as volumetric inspection, can

be used.

Testing of sprinkler heads should

be performed at year 50 of

sprinkler system service life, and

every 10 years thereafter.

This ISG eliminates the

halon/carbondioxide system

inspections for charging pressure,

valve lineups, and the automatic

mode of operation test from GALL;

the staff considers these test

verifications to be operational

activities.

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ISG Issue Purpose SER Section

(Approved ISG No.)__.....

Identification and Treatment of This ISG includes electrical fuse 3.6.2.3.2

Electrical Fuse Holders holders AMR and AMP (i.e., same

(ISG-5) as terminal blocks and other

electrical connections).

The position includes only fuse

holders that are not inside the

enclosure of active components

(e.g., inside of switchgears and

inverters).

Operating experience finds that

metallic clamps (spring-loaded

clips) have a history of age-related

failures from aging stressors such

as vibration, thermal cycling,

mechanical stress, corrosion, and

chemical contamination.

The staff finds that visual

inspection of fuse clips is not

sufficient to detect the aging effects

from fatigue, mechanical stress,

and vibration.

The ISG Process This ISG clarifies and updates the N/A

(ISG-8) ISG process on improved license

renewal guidance documents.

Standardized Format for License This ISG provides a standardized N/A

Renewal Applications LRA format for applicants.

(ISG-10)

1.5 Summary of Open Items

An open item (01) is an issue that, in the staff's judgment, has not been resolved in a manner

that meets all applicable regulatory requirements. The NRC issued the initial SER on April 26,

2006, with no Ols. The staff did not identify any subsequent open items in preparing the final

SER.

1.6 Summary of Confirmatory Items

A confirmatory item (CI) is an issue that the applicant and the staff have resolved, but for which

the applicant has not yet formally submitted the resolution. The NRC issued the initial SER on

April 26, 2006, with no CIs. The staff did not identify any subsequent CIs in preparing the final

SER.

1.7 Summary of Proposed License Conditions

As a result of the staff's review of the LRA for MNGP, including subsequent information and

clarifications provided by the applicant, the staff identified three proposed license conditions.

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The first license condition requires the applicant to include the USAR supplement required by

10 CFR 54.21 (d) in the next USAR update, as required by 10 CFR 50.71 (e), following the

issuance of the renewed license.

The second license condition requires that the list of commitments identified in Appendix A to

this SER be completed in accordance with the schedule in Appendix A.

The third license condition requires that all capsules placed in storage must be maintained for

future insertion. Any changes to storage requirements must be approved by the NRC, as

required by 10 CFR Part 50, Appendix H.

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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10, Section 54.21, "Contents of Application-Technical Information," of the Code of

Federal Regulations (10 CFR 54.21) requires that each license renewal application (LRA)

contain an integrated plant assessment (IPA). Furthermore, the IPA must list and identify

structures and components (SCs) subject to an aging management review (AMR) from all of

the systems, structures, and components (SSCs) within the scope of license renewal in

accordance with 10 CFR 54.4, "Scope."

In LRA Section 2.1, "Scoping and Screening Methodology," the applicant described the scoping

and screening methodology used to identify SSCs at the Monticello Nuclear Generating

Plant (MNGP) within the scope of license renewal and the SCs subject to an AMR. The staff

reviewed the applicant's scoping and screening methodology to determine whether it meets the

scoping requirements stated in 10 CFR 54.4(a) and the screening requirements stated in

10 CFR 54.21.

In developing the scoping and screening methodology for the MNGP LRA, the applicant

considered the requirements of 10 CFR Part 54, "Requirements for Renewal of Operating

Licenses for Nuclear Power Plants," (the Rule), the Statements of Consideration for the Rule,

and the guidance presented by the Nuclear Energy Institute. (NEI), in NEI 95-10, Revision 4,

"Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License

Renewal Rule." In developing this methodology, the applicant also considered the

correspondence between the U.S. Nuclear Regulatory Commission (NRC or the staff) and other

applicants or NEI.

2.1.2 Summary of Technical Information In the Application

In LRA Sections 2 and 3, the applicant provided the technical information required by

10 CFR 54.21 (a). In LRA Section 2.1, the applicant described the process used to identify

SSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a), as well as the

process used to identify SCs subject to an AMR, pursuant to 10 CFR 54.21 (a)(1).

Additionally, LRA Sections 2.2, "Plant Level Scoping Results," 2.3, "System Scoping and

Screening Results: Mechanical Systems," 2.4, "Scoping and Screening Results: Containments,

Structures, and Component Supports," and 2.5, "Scoping and Screening Results: Electrical and

Instrumentation and Controls Systems,", amplify the process the applicant used to identify SCs

subject to an AMR. LRA Section 3, "Aging Management Review Results," contains the following

information:

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• - Section 3.1, "Aging Management of Reactor Coolant System"

" Section 3.2, "Aging Management of Engineered Safety Features"

" Section 3.3, "Aging Management of Auxiliary Systems"

" Section 3.4, "Aging Management of Steam and Power Conversion System"

" Section 3.5, "Aging Management of Containments, Structures, and Component

Supports"

* Section 3.6, "Aging Management of Electrical and Instrumentation and Controls"

LRA Section 4, "Time-Limited Aging Analyses," contains the applicant's identification and

evaluation of time-limited aging analyses.

2.1.2.1 Scoping Methodology

In LRA Section 2.1, the applicant described the methodology used to scope SSCs, pursuant to

the 10 CFR 54.4(a) scoping criteria. The following sections present the applicant's scoping

methodology, as described in the LRA.

2.1.2.1.1 Application of the Scoping Criteria in 10 CFR 54.4(a)

The applicant described the general approach to scoping safety-related (SR) and

nonsafety-related (NSR) SSCs and SSCs credited with demonstrating compliance with certain

regulated events in LRA Section 2.1.2, "Application of Scoping Criteria in 10 CFR 54.4(a)." The

following sections describe the scoping approaches specific to each of the three

10 CFR 54.4(a) scoping criteria.

Application of the Scoping Criterion in 10 CFR 54.4(a)(1 )

In LRA Section 2.1.4.2.1, "Scoping Criterion 1 -Safety Related SSCs," the applicant presented

its scoping methodology as it pertains to SR criteria pursuant to 10 CFR 54.4(a)(1). The

applicant used MNGP 0-List and Q-List Extension color-coded drawings to code items as SR in

the MNGP plant equipment electronic database (CHAMPS), which also served as one of a

number of information sources in the current licensing basis (CLB) used to identify SSCs

meeting Scoping Criterion 1. For example, information from the Updated Safety Analysis

Report (USAR), technical specifications (TSs), and design documents was reviewed to ensure

all major system and structure functions had been identified properly. These functions were

compared to Scoping Criterion 1 to identify SSCs within the scope of license renewal which are

relied upon to remain functional during and following design-basis events (DBEs).

CHAMPS and controlled drawings were used to identify components required to support

system-level and structure-level functions within the scope of license renewal. Those

components included within the scope of license renewal generally matched information in

CHAMPS. Differences noted were documented and resolved.

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ApDlication of the ScoDina Criterion in 10 CFR 54.4(a)(2)

In LRA Section 2.1.4.2.2, "Non-Safety Related Affecting Safety Related," the applicant

presented the scoping methodology as it related to the NSR criteria pursuant to

10 CFR 54.4(a)(2). The applicant stated that MNGP SSCs meeting Scoping Criterion 2 were

grouped into three categories, (1) CLB topics, (2) NSR SSCs directly connected to Scoping

Criterion 1 SSCs (typically piping systems), or (3) NSR SSCs not directly connected to Scoping

Criterion 1 SSCs, but whose failure could prevent, as a result of spatial proximity, the

satisfactory accomplishment of a Scoping Criterion 1 function. SSCs meeting Scoping Criterion

2 in the first two categories typically were identified during document reviews, including the

MNGP USAR, plant drawings, design documents, piping analyses, CHAMPS, and other CLB

documents. SSCs in the third category typically were identified by both document reviews and

extensive plant walkdowns to identify spatial interactions meeting broader criteria for license

renewal.

CLB Topics

A review of the MNGP CLB identified NSR SSCs with preventive or mitigative functions

supporting safe shutdown, the failure of which could prevent satisfactory accomplishment of a

Scoping Criterion 1 function. High-energy line breaks (HELB), internal and external flooding

events, internal and external missile hazards, overhead handling systems, and seismic

interactions were evaluated. NSR SSCs were placed within the scope of license renewal as a

result of this review if their failure could adversely affect an SR SSC.

NSR SSCs Directly Connected to Scoping Criterion 1 SSCs

NSR SSCs directly connected to Scoping Criterion 1 SSCs (typically piping systems) and

component supports required to prevent NSR SSCs from physical interaction with SR SSCs are

within the scope of license renewal. All piping supports in buildings with Scoping Criterion 1

components are within the scope of license renewal. The LRA describes the applicable

supports as those that must remain in place so they do not prevent equipment required to

perform intended functions from performing them. SCs within the scope of license renewal

extend into the NSR portion of the piping and supports up to and including the first equivalent

anchor beyond the safety/nonsafety interface, that point beyond which failure of the piping

system will not prevent satisfactory performance of Scoping Criterion 1 functions of connected

SSCs. The piping components and supports up to and including the first equivalent anchor are

within the scope of license renewal.

NSR structures attached or next to Scoping Criterion 1 structures are within the scope of

license renewal if their failure could prevent a Scoping Criterion 1 SSC from performing its

intended function.

NSR SSCs Not Directly Connected to Scoping Criterion 1 SSCs

NSR SSCs not directly connected, but in spatial proximity, to Criterion 1 SSCs whose failure

could prevent the satisfactory accomplishment of a Criterion 1 function are within the scope of

license renewal. The LRA states that both spray (pressurized liquid or steamlines) .and leaks

(nonpressurized liquid lines) were evaluated for their impact on Scoping Criterion 1 components

without regard to whether the Scoping Criterion 1 components were active or passive and

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without regard to the duration of the spray or leak. All pressurized liquid systems in the general

area of Scoping Criterion 1 components are within the scope of license renewal and assumed

to leak anywhere around the circumference or along the length of the pipe. All nonpressurized

liquid systems directly above Scoping Criterion 1 components are also within the scope of

license renewal. Leaks were assumed to occur anywhere along the length of the piping system.

Air and gas systems are not included within the scope of license renewal because they do not

contain NSR components whose failure could prevent satisfactory accomplishment of Scoping

Criterion 1 functions. Site-specific operating experience was reviewed to verify that MNGP

air/gas systems have not affected other plant equipment negatively. The applicant's review of

industry operating experience also revealed no events of this nature. Because none of the

air/gas lines are high-energy lines and all supports in buildings with Scoping Criterion 1

components are within the scope of license renewal, air/gas systems are not Scoping

Criterion 2 items.

NSR conduits, cable trays, junction boxes, or lighting fixtures may contain or be routed near

Scoping Criterion 1 cables or other components; therefore, all NSR conduits, trays, junction

boxes, and lighting fixtures and their supports located within structures housing SR equipment

are within the scope of license renewal. Additionally, conduits, trays, junction boxes, and

lighting fixtures and their supports required for regulated events located in structures not

housing Scoping Criterion 1 equipment are within the scope of license renewal.

Though most heating, ventilation, and air conditioning (HVAC) ducts and their supports are

NSR, they are located throughout the plant, typically along ceilings, and thus above many

Scoping Criterion 1 SSCs. Like air/gas pipe systems, HVAC ducts are not hazards to other

plant equipment. Falling is a concern; therefore, all HVAC duct supports located within

structures housing Scoping Criterion 1 components are within the scope of license renewal.

Application of the Scopina Criterion in 10 CFR 54.4(a)(3)

In LRA Section 2.1.4.2.3, "Scoping Criterion 3-Other Regulations Identified in 10 CFR

Part 54," the applicant discussed the methodology used to identify SSCs credited with functions

that demonstrate compliance with regulations for fire protection (FP), environmental

qualification (EQ), anticipated transients without scram (ATWS), and station blackout (SBO),

pursuant to the, 10 CFR 54.4(a)(3) license renewal scoping criteria. The applicant did not

evaluate pressurized thermal shock because it is not applicable to boiling-water

reactors (BWRs).

Fire Protection

In LRA Section 2.1 .4.2.4, "Fire Protection," the applicant described the scoping of SSCs relied

on to perform functions that demonstrate compliance with 10 CFR 50.48, "Fire Protection";

Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1,

1979," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities"; and

commitments made in response to Appendix A to NRC Branch Technical Position APCSB 9.5-

1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The

applicant stated that a detailed evaluation of the CLB, including CHAMPS, the safe-shutdown

analysis, the fire hazards analysis, plant drawings, the USAR, and the operations manual was

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performed for FP, and SSCs supporting either FP design features or safe shutdown following

postulated fires are within the scope of license renewal.

Environmental Qualification

In LRA Section 2.1.4.2.5, "Environmental Qualification," the applicant described the scoping of

SSCs relied on to perform functions that demonstrate compliance with 10 CFR 50.49,

"Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power

Plants," which defines electric equipment important to safety that is required to be

environmentally qualified to mitigate certain accidents that would result in harsh environmental

plant conditions. The applicant stated that components that meet the requirements of

10 CFR 50.49 are identified on the EQ Master List. All equipment identified on the EQ Master

List supporting the MNGP CLB was included within the scope of license renewal as

components or commodities, pursuant to 10 CFR 54.4(a)(3).

Anticipated Transients without Scram (ATWS)

In LRA Section 2.1.4.2.7, "Anticipated Transients without Scram," the applicant described the

scoping of SSCs relied on to perform functions that demonstrate compliance with the ATWS

requirements of 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated

Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." The

applicant stated that the MNGP design features related to ATWS are within the scope of license

renewal because they are relied on to meet 10 CFR 50.62 requirements. The applicant stated

that ATWS mitigation is accomplished by the use of three systems, (1) the alternate rod

injection subsystem, (2) the standby liquid control system, and (3) the recirculation pump trip

system. Based on a review of the CLB, plant and vendor drawings, the USAR, docketed

correspondence, modifications, and CHAMPS, the components relied upon to mitigate ATWS

events were determined to be within the scope of license renewal.

Station Blackout

In LRA Section 2.1.4.2.8, "Station Blackout," the applicant described the scoping of SSCs relied

on to perform functions that demonstrate compliance with the requirements of 10 CFR 50.63,

"Loss of Alternating Current Power." The applicant stated that, based on the review of

plant-specific SBO calculations, the USAR, plant drawings, modifications, and CHAMPS, the

components relied upon to mitigate SBO were determined to be within the scope of license

renewal.

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In LRA Section 2.1.3, "Plant Information Sources," the applicant, stated that it had evaluated

information from the following sources during the license renewal scoping and screening

process:

* USAR

• CLB information including TSs and docketed licensing correspondence

• design-basis documents (DBDs)

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• Q-List and Q-List Extension

• controlled drawing file

* industry codes, standards, and regulations

* technical correspondence, analyses, and reports

* calculations

• plant modifications and alterations

* nuclear steam supply system supplier; architect-engineer; and vendor reports,

specifications, and drawings

* Maintenance Rule documents

* CHAMPS

The applicant stated that it reviewed these documents to identify the major SSCs and their

respective functions. Functions of SSCs that were determined to be within the scope of license

renewal were identified as intended functions, pursuant to 10 CFR 54.4(b). CHAMPS and

controlled drawings were used to identify components required to support system-level and

structure-level functions within the scope of license renewal. These sources also were used to

develop the list of SCs subject to an AMR.

2.1.2.1.3 Plant and System-Level Scoping

LRA Section 2.1.4 states that the scoping process categorizes the entire plant according to

major SSCs and commodity groups. The applicant identified and evaluated SSC and

commodity group functions against criteria in 10 CFR 54.4(a) to determine whether the function

was an intended function. The SSC or commodity was deemed within the scope of license

renewal and received further screening if a portion of the SSC or commodity fulfilled a scoping

criterion.

2.1.2.1.4 Component-Level Scoping

After identifying the intended functions of systems and structures, the applicant identified

components that support intended functions. The applicant considered components supporting

intended functions as within the scope of license renewal and screened them to determine

whether an AMR'was required.

Commodity groups were used when component evaluations were by component type rather

than by system or structure. Components constructed from similar materials, exposed to similar

environments, and performing similar intended functions form the commodity groups.

Commodity group components were not associated with specific systems or structures during

the evaluation, but with their assigned commodity groups. An AMR of each commodity group

took place as if it were a separate, individual system. Electrical components, component

supports, and fire stops and seals were placed in separate commodity groups.

CHAMPS does not uniquely identify all components installed in the plant. For example,

CHAMPS does not typically include such items as cables, raceways, piping, conduits,

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

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fuel, resins). Components not uniquely identified in CHAMPS that are within the scope of

license renewal are identified as commodities or generic assets (e.g., pipe, structural steel) in

their respective system or structure in the license renewal database to ensure proper coverage

and evaluation.

2.1.2.1.5 Structure Scoping

LRA Section 2.1.4.1 states that CHAMPS includes a category for structures that comprise all of

the MNGP buildings and structures. Buildings were categorized as individual or grouped license

renewal structures. The applicant electronically searched other information sources, like CLB

documentation, using several keywords (e.g., "structure," "new structure," "building

modification") to ensure evaluation of all plant structures for license renewal intended functions,

regardless of their coverage in CHAMPS.

2.1.2.2 Screening Methodology

After identifying the SSCs within the scope of license renewal, the applicant implemented a

process for determining which SSCs would be subject to an AMR, pursuant to

10 CFR 54.21 (a)(1). In LRA Section 2.1.5, "Screening Process," the applicant discussed the

screening of SSCs within the scope of license renewal.

System, Structure, and Commodity Group Component Screening

LRA Section 2.1.5.2, "General Screening Methodology," states that the screening process

identifies the components from the systems, structures, and commodity groups within the scope

of license renewal that are subject to an AMR. These components perform or support a

component-level intended function without moving parts or a change in configuration or

properties and are not subject to replacement based on a qualified life or specified time period.

Component-level intended functions support system-level intended functions. The plant

systems, structures, and commodity groups within the scope of license renewal and their

system-level intended functions were identified previously in the scoping process. The

screening process consists of the following distinctive steps:

* identification of components subject to an AMR (passive and long-lived) for each

system, structure, or commodity within the scope of license renewal

* identification of the component-level intended functions of all components subject to

AMRs

* identification of applicable references for making these determinations

The applicant identified SCs within the scope of license renewal performing intended functions

without moving parts or a change in configuration or properties (10 CFR 54.21 (a)(1)(1)

screening criterion). Active/passive screening determinations were based on the guidance in

Appendix B to NEI 95-10. Passive SCs within the scope of license renewal not subject to

replacement based on a qualified life or specified time period (10 CFR 54.21 (a)(1)(ii) screening

criterion) were identified as requiring AMRs. Component .supports and fire stops and seals were

binned in separate structural commodity groupings.

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Electrical/Instrumentation and Control (l&C) Component Screenina

In LRA Section 2.1.5.4, "Scoping and Screening of Electrical Equipment," the applicant

described the methodology for screening electrical and I&C components. Component-level

screening was performed for "in-scope" components associated with electrical systems.

Components identified as within the scope of license renewal were evaluated pursuant to NEI

95-10, Appendix B guidance to determine whether they were considered "active." Components

were either screened out as active or included in a commodity group. Long-lived, passive

components were divided into four commodity groups, (1) Non-EQ Cables and Connections, (2)

Fuse Holders, (3) Electrical Penetrations, and (4) Offsite Power/SBO Recovery Path

components. Aging management was performed on only these four commodity groups.

2.1.3 Staff Evaluation

The staff evaluated the LRA scoping and screening methodology in accordance with the

guidance in Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, "Standard

Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR).

The following regulations form the basis for the acceptance criteria for the scoping and

screening methodology review:

10 CFR 54.4(a) relating to the identification of plant SSCs within the scope of license

renewal

10 CFR 54.4(b) relating to the identification of intended functions of plant SSCs within

the scope of license renewal

10 CFR 54.21 (a)(1) and 10 CFR 54.21 (a)(2) relating to the applicant's methods for

identifying plant SCs subject to an AMR

As part of the review of the applicant's scoping and screening methodology, the staff reviewed

the activities described in the following sections of the LRA using the guidance in the SRP-LR:

* Section 2.1 to ensure that the applicant described a process for identifying SSCs within

the scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a)

" Sections 2.2, 2.3, 2.4, and 2.5 to ensure that the applicant described a process for

identifying structural, mechanical, and electrical components subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1) and 10 CFR 54.21 (a)(2)

In addition, the staff conducted a scoping and screening methodology audit at the MNGP facility

in Minnesota during the week of June 20-24, 2005. The audit focused on ensuring that the

applicant had developed and implemented adequate guidance to conduct the scoping and

screening of SSCs in accordance with the LRA methodologies and the requirements of the

Rule..The staff reviewed implementation procedures and technical reports describing the

applicant's scoping and screening methodologies. In addition, the staff conducted detailed

discussions with the applicant on the implementation and control of the license renewal

program and reviewed administrative control documentation and selected design

documentation used by the applicant during the scoping and screening process. The staff

reviewed the applicant's processes for quality assurance (QA) related to the development of the

applicant's LRA and training and qualification of the LRA development team. The staff also

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reviewed a sample of system scoping and screening results reports for the control rod

drive (CRD) system and intake structure (flood control) to ensure that the applicant

appropriately implemented the methodology outlined in the administrative controls and that the

results were consistent with the CLB. The staff documented its review in an audit report issued

July 18, 2005, identifying several issues requiring additional information from the applicant

before completion of the review. Each of those issues is identified and addressed in detail in

SER Sections 2.1.3.1.2 and 2.1.3.1.4.

2.1.3.1 Scoping Methodology

The applicant's license renewal project personnel and contractors performed the scoping

evaluations for the LRA. The staff had detailed discussions with the applicant's license renewal

project personnel and reviewed documentation of the scoping process. The staff assessed

whether the scoping methodology described in the LRA and implementation procedures had

been implemented appropriately and whether the scoping results were consistent with CLB

requirements. The staff also reviewed a sample of system scoping results for the CRD system

and intake structure (flood control).

2.1.3.1.1 Implementation Procedures and Documentation Sources Used for Scoping and

Screening

The staff reviewed the applicant's scoping and screening implementation procedures to verify

that the process used to identify SCs subject to an AMR was consistent with the LRA and

SRP-LR, and that the applicant appropriately implemented the procedural guidance. The staff

also reviewed the scope of CLB documentation sources supporting the LRA and the process

used by the applicant to ensure that CLB commitments were considered appropriately in

scoping and screening.

Scopina and Screening Implementation Procedures

The staff reviewed the scoping and screening methodology implementation procedures and

engineering reports, as documented in the audit report dated July 18, 2005.

In reviewing these procedures, the staff focused on the consistency of the detailed proicedural

guidance with the LRA and the staff positions documented in the SRP-LR and interim staff

guidance documents. The staff found that the scoping and screening methodology instructions

were consistent with LRA Section 2.1 and were of sufficient detail to guide the applicant on the

scoping and screening implementation process followed during LRA activities.

In addition to the implementing procedures, the staff reviewed supplemental design information

including DBDs, system drawings, and selected licensing documentation on which the applicant

relied during scoping and screening. The staff found these design documentation sources

useful in ensuring that the initial scope of SSCs identified by the applicant was consistent with

the CLB.

Sources of Current Licensing Basis Information

The staff reviewed the scope and depth of the applicant's CLB evaluation to verify that the

methodology was sufficiently comprehensive to identify SSCs within the scope of license

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renewal and SCs requiring an AMR. As defined in 10 CFR 54.3(a), the CLB is the set of NRC

requirements applicable to a specific plant and a licensee's written commitments for ensuring

compliance with and operation within such requirements and the plant-specific design-basis

docketed and in effect. The CLB includes NRC regulations, orders, license conditions,

exemptions, TSs, design-basis information docketed in the USAR, and licensee commitments

remaining in effect that were made in such docketed licensing correspondence as licensee

responses to NRC bulletins, generic letters, and enforcement actions, as well as licensee

commitments documented in NRC safety evaluations or licensee event reports.

LRA Section 2.1.3 provides a description of the CLB and related documents used during the

scoping and screening process that is consistent with the guidance in the SRP-LR and

NEI 95-10. Specifically, LRA Section 2.1.3 identified the USAR, TSs, docketed licensing

correspondence, the Q-List, controlled plant drawings, industry codes, and plant design

records. Additionally, in the scoping and screening implementation procedure, the applicant

provided a comprehensive listing of documents that could be used to support scoping and

screening evaluations. The applicant noted that system descriptions and system intended

functions were identified based on the review of the applicable sections of the USAR,

operations manual, Maintenance Rule scoping document, design- and licensing-basis

documents, and license renewal project technical reports.

During the audit, the staff reviewed the applicant's technical report, which specifically addresses

DBEs. The report addressed in detail various sections of the USAR related to design-basis

accidents (DBAs) and bounding transients and evaluated natural phenomena and external

events applicable to MNGP. Supplemental information used to verify complete identification of

DBEs included selected DBDs covering a number of support and accident mitigation systems,

as well as selected topical reports developed to support the license renewal evaluation. Design

descriptions for each system described in the USAR were reviewed to identify DBE mitigation

functions credited in the CLB. The applicant identified these event mitigation functions and

confirmed that the SSCs credited with performing those functions were evaluated adequately in

the scoping and screening process.

CHAMPS is the applicant's primary repository for component safety classification information.

During the audit, the staff reviewed the applicant's administrative controls for CHAMPS safety

classification data and concluded that the applicant had adequate measures to control the

integrity and reliability of CHAMPS safety classification data. Therefore, the staff concluded that

CHAMPS provides a sufficiently controlled source of component data to support scoping and

screening evaluations.

The applicant identified topical reports as a source of information supporting identification of

systems and structures relied upon to demonstrate compliance with events within the scope of

10 CFR 54.4(a)(3), as well as documenting evaluation of special topics like scoping and

screening of thermal insulation, treatment of consumables, and intended functions of heat

exchangers. These reports were developed in accordance with MNGP directives that describe

the requirements for preparation of such topical reports. The topical reports contain a listing of

CLB references used for their development that was consistent with LRA Section 2.1.3. The

staff reviewed these reports and concluded that the preparation of the topical reports according

to applicant requirements reasonably ensured adequate summaries of CLB information for

scoping purposes. The staff further verified the adequacy of the technical information in a

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sample of the reports by reviewing selected CLB source documents used to develop the

technical reports.

Conclusion

As part of the audit, the staff evaluated the scope and depth of the applicant's CLB evaluation

for assurance that the scoping methodology considered all SSC intended functions. In

reviewing the LRA, scoping and screening implementation procedures, and license renewal

technical reports, the staff determined that the applicant had developed and reviewed an

adequately broad set of documents encompassing its CLB that is consistent with the guidance

in the SRP-LR and NEI 95-10. The applicant's document review process adequately identified

and documented system description and intended function evaluations performed during the

scoping phase of the review. Therefore, the staff concluded that the applicant's methodology for

the identification, review, and documentation of CLB information to support the scoping of

SSCs is adequate.

2.1.3.1.2 Application of the.Scoping Criteria in 10 CFR 54.4(a)

Application of the Scopina Criterion in 10 CFR 54.4(a)(1 )

In part, 10 CFR 54.4(a)(1) provides that, to identify SSCs within the scope of license renewal,

the applicant must include all SR SSCs relied upon to remain functional during and following

DBEs to ensure the following functions:

" the integrity of the reactor coolant pressure boundary

" the ability to shut down the reactor and maintain it in a safe-shutdown condition

* the capability to prevent or mitigate the consequences of accidents that could result in

potential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),

10 CFR 50.67(b)(2), or 10 CFR 100.11, "Determination of Exclusion Area, Low

Population Zone, and Population Center Distance"

As to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR states the

following:

The set of DBEs as defined in the rule is not limited to Chapter 15 (or equivalent)

of the Updated Final Safety Analyses Report (UFSAR). Examples of DBEs that

may not be described in this chapter include external events, such as floods,

storms, earthquakes, tornadoes, or hurricanes, and internal events, such as a

high-energy-line break. Information regarding DBEs as defined in

10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the

Commission's regulations, NRC orders, exemptions, or license conditions within

the CLB. These sources should also be reviewed to identify SSCs that are relied

upon to remain functional during and following DBEs (as defined in

10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1).

The applicant's program for satisfying the scoping requirements of 10 CFR 54.4(a) requires

identification of all major SR and NSR SSCs and the function or functions that each major SSC

is required to perform. The applicant used a number of information sources, the CLB, DBEs,

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and quality classifications to identify the major SSCs and their respective functions. USAR

Chapters 12 and 14 address DBEs. The applicant also used its DBDs to identify SR SSCs

relied upon to remain functional during and following DBEs. The Q-List of the Operational QA

Plan and the Q-List Extension drawings (color-coded piping &instrumentation drawings (P&ID))

specify the QA program boundaries for SSCs. These documents define the SSCs subject to the

requirements of Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel

Reprocessing Plants," to 10 CFR Part 50, and were used to code items as SR in CHAMPS.

The applicant's review of these documents identified the major SSCs and their respective

functions, which were compared to the scoping criteria of 10 CFR 54.4(a) to identify functions

within the scope of license renewal. SSC functions that meet 10 CFR 54.4(a) scoping criteria

requirements are identified as intended functions in the Advanced License Extension

Management System (ALEX) license renewal database. SSC intended functions support one or

more of the 10 CFR 54.4(a) scoping criteria.

CHAMPS electronically stores component information used to prepare work orders and other

uses. CHAMPS provides seismic and quality classification. The applicant used CHAMPS and

controlled drawings to identify components required to support system-level and structure-level

intended functions. Such components were included within the scope of license renewal.

The applicant scoped SSCs in accordance with its implementing procedures. For additional

assurance that the applicant adequately implemented its SR scoping methodology, the staff

reviewed a sample of the license renewal scoping report results for the CRD system and

discussed the methodology and results with the applicant's personnel responsible for these

evaluations. The staff verified that the applicant had identified and used pertinent engineering

and licensing information to identify the SSCs within the scope of license renewal, in

accordance with the 10 CFR 54.4(a)(1) criteria.

Conclusion

On the basis of this sample review, discussions with the applicant, and review of the applicant's

scoping process, the staff concluded that the applicant's methodology for identifying systems

and structures meets the 10 CFR 54.4(a)(1) scoping criteria.

Application of the Scopina Criterion in 10 CFR 54.4(a)(2)

In part, 10 CFR 54.4(a)(2) requires that the applicant consider all NSR SSCs whose failure

could prevent satisfactory accomplishment of any of the functions identified in

10 CFR 54.4(a)(1)(1), 10 CFR 54.4(a)(1)(ii), or 10 CFR 54.4(a)(1)(iii) as within the scope of

license renewal. By letters dated December 3, 2001, and March 15, 2002, the NRC issued a

staff position to the NEI which provided staff expectations for determining which SSCs meet the

10 CFR 54.4(a)(2) criterion. The December 3, 2001, letter provides specific examples of

operating experience which identified pipe failure events (summarized in Information Notice (IN)

2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping

Inside the Containment of a Pressurized Water Reactor," and the approaches the staff

considers acceptable for determining which piping systems should be within the scope of

license renewal based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter further

describes the staff's expectations for the evaluation of nonpiping SSCs to identify additional

NSR SSCs within the scope of license renewal. The position states that applicants should not

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consider, hypothetical failures, but rather the plant's CLB, engineering judgment and analyses,

and relevant operating experience. The paper further describes operating experience as all

documented plant-specific and industry-wide experience useful in determining the plausibility of

a failure. Documentation would include NRC generic communications and event reports,

plant-specific condition reports, industry reports, such as significant operating event

reports (SOERs), and engineering evaluations.

In its scoping implementation procedures, the applicant documented its methodology for

performing 10 CFR 54.4(a)(2) scoping of NSR SSCs and described the general methodology

for identifying those NSR SSCs whose failure could affect the ability to maintain intended

functions of SR SSCs within the scope of license renewal. The procedure provides general

guidance consistent with that of Appendix F to NEI 95-10, Revision 4, regarding the use of

mitigative and preventive approaches to identify SSCs within the scope of license renewal to

meet the 10 CFR 54.4(a)(2) criterion. The procedure further describes the process for

identifying the SSCs within the scope of license renewal and includes guidance for each

discipline review (mechanical, structural, and electrical).

In addition, the applicant developed a technical report, as documented in the audit report, to

further define the methodology used for the 10 CFR 54.4(a)(2) evaluation. This technical report

describes the current regulation and the interim staff position on scoping of SSCs according to

the 10 CFR 54.4(a)(2) criterion; the applicant's evaluation of licensing-basis topics, including

HELB, internal and external missiles, internal and external flooding, and heavy loads; evaluation

of NSR SSCs attached directly to SR SSCs; and NSR SSCs within close spatial proximity to SR

SSCs. Section 4.0 of the report addresses in detail the results of the 10 CFR 54.4(a)(2)

evaluation.

With respect to the CLB topics, including HELB, internal and external missiles, internal and

external flooding, and heavy loads, the applicant's methodology evaluated information for each

to identify NSR SSCs of interest. To ensure a complete and extensive evaluation of the existing

CLB, the applicant developed a process which included searching CHAMPS to identify relevant

references to the TS-bases documents, USAR sections, DBDs, licensing correspondence, plant

drawings, plant modification packages, technical reports, and operations manuals for each

topic. These documents were reviewed and an evaluation for each topic was performed to

identify design features relied on for these events as within the scope of license renewal.

The staff reviewed the applicant's methodology in evaluating these CLB topics, discussed the

evaluation process with the applicant's staff responsible for performing these reviews, and

evaluated a sample of the results of this evaluation to ensure that implementation of written

instructions and the results are consistent with those evaluations. The staff determined that the

applicant's documented methodology was consistent with the 10 CFR 54.4(a)(2) requirements

and that the applicant's evaluation was consistent with that methodology. The staff reviewed a

sample of the CLB information used for the applicant's evaluations and confirmed its

consistency with that design information.

The applicant's evaluation of NSR SSCs attached directly and those within close spatial

proximity to SR SSCs considered current industry guidance on the subject as a result of recent

staff license renewal evaluations, taking into account that all active as well as passive SR SSCs

could be affected adversely by spray or wetting from an NSR pressurized system in the same

general location of the plant, regardless of the duration of that exposure. Specifically, the

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applicant used a "spaces" approach to identify SR SSCs and NSR SSCs within the same "'general area," which is defined as a location sharing a common floor and common walls. This

definition was expanded during plant walkdowns in the 10 CFR 54.4(a)(2) evaluation to include

adjacent areas (i.e., those separated by a wall or barrier), if there could be communication

between the two areas. In those instances, the adjacent area was considered part of the

general area.

As part of this evaluation, the applicant first listed the SR components and their locations within

the plant. Review of plant-controlled documents like P&IDs, DBDs, and CHAMPS identified

plant areas where NSR and SR SSCs were located. The applicant performed walkdowns of all

accessible locations to identify NSR SSCs within these areas and the types of potential

interactions that could occur (i.e., leaking, spraying, physical impact). For inaccessible areas,

the applicant relied on controlled plant piping layout drawings and operator knowledge of the

plant design and operation to identify potential component interactions. The inaccessible areas

included the drywell/suppression chamber, steam chase, reactor water cleanup (RWCU) and

traversing incore probe rooms, condenser room, and steam jet air ejector (SJAE) room. Where

the applicant identified potential interactions between the NSR SSCs and SR SSCs within a

general area, it included those NSR SSCs within the scope of license renewal. The applicant

further documented the results on marked-up P&IDs, which highlighted the NSR SCs identified

and described the general area, as well as SR SCs that could be affected by the NSR line

failure. The staff reviewed a sample of the marked-up P&IDs for the CRD system and reviewed

the applicant's determination of areas of no potential interactions between NSR and SR SSCs.

The staff determined that the applicant had evaluated the 10 CFR 54.4(a)(2) scoping criterion

consistently with the applicant's written instructions for such an evaluation and that the results

had been documented with technical supporting justifications. The staff did not identify any

specific concerns regarding the implementation of the 10 CFR 54.4(a)(2) scoping methodology

for the system sample reviewed.

The applicant also discussed its 10 CFR 54.4(a)(2) scoping evaluation process for NSR SSCs

directly attached to SR SSCs to determine equivalent anchor locations required to establish

system boundaries for the evaluation. With respect to the equivalent anchor criteria, the

applicant identified locations in each relevant system where support and attachment are such

that failure of the piping system beyond the boundary point would not adversely affect the SR

functions of connected SR components. The applicant relied on its piping stress analysis of

record to determine equivalent anchor locations. In most cases, this boundary encompassed at

least two levels of supports in each orthogonal direction, and for those few cases where such

support was not available, the applicant evaluated the piping stress analysis to determine

alternate anchorage locations. The alternate anchorage locations included (1) selected wall

penetrations, (2) large pieces of plant equipment, (3) transition points between the piping

systems and flexible connections like tubing and ducting, and (4) locations where the piping

system moment of inertia ratio exceeds 40:1 between the main and branch lines. In each case,

the applicant provided a technical justification for the use of the equivalent anchorage location

based on CLB information related to the piping stress analysis of record. The staff reviewed the

methodology for a selected sample of mechanical systems and confirmed that the applicant's

evaluation was consistent with the guidance and that results had been documented adequately

and justified technically.

In addition to reviewing the implementation procedures associated with the applicant's

10 CFR 54.4(a)(2) evaluations, the staff discussed the review process with the applicant's

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personnel responsible for performing the review and evaluated a sample of systems and

structures to ensure that the methodology was implemented in accordance with the written

instructions and that the results were consistent with those evaluations.

The applicant's implementing procedures provided guidance for establishing system boundaries

for NSR piping systems connected directly to SR piping systems. The guidance states, in part,

that for NSR SSCs connected to SR SSCs, the NSR SSCs should be included up to the first

seismic anchor past the SR-NSR interface, and the boundary drawings should also identify the

anchor. A review of piping analyses provided information to extend the piping system to the first

anchor. Where there was no true anchor, the piping analysis was extended far enough to

ensure that the NSR portion would have no effect on the SR portion. Typically, the extension

encompassed at least two restraints in each orthogonal direction. Where there were no such

restraints in each orthogonal direction, the boundary was extended to an equivalent anchor

such as a wall. As an example, the applicant stated that in certain cases of small-bore piping

(i.e., 2 inches or less), grouted wall penetrations served as equivalent anchor locations.

The staff's review of LRA Section 2.1 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening methodology.

The applicant responded to the staff's RAI as discussed below.

In RAI 2.1-2, dated July 20, 2005, the staff requested that the applicant provide the technical

basis for establishing the grouted wall penetrations as equivalent anchor locations for NSR

piping systems connected to SR piping systems and confirm that nongrouted wall penetrations

were not used as equivalent anchor locations for NSR piping systems connected to SR piping

systems.

In its response, by letters dated August 16, 2005, and November 17, 2005, the applicant stated

that 10 grouted wall/floor NSR piping penetrations were considered equivalent anchors. The

CLB piping analysis addressed 9 of the 10 grouted penetrations, while 1 of the 10 was not

addressed. In its response, the applicant provided an acceptable technical justification for

crediting this one grouted wall/floor piping penetration not addressed as an equivalent anchor.

The applicant additionally stated that, in five instances, NSR underground piping was used as

an equivalent anchor. In three of the five instances, the CLB piping analysis addressed the use

of NSR underground piping as an equivalent anchor. The remaining two instances were not

addressed. The applicant provided an acceptable technical justification for crediting the two

instances in which underground piping was used as an equivalent anchor. The applicant also

stated that it had added NSR underground piping to the scope of license renewal, which was

subject to an AMR when credited as an equivalent anchor.

Based on its review, the staff found the applicant's response to RAI 2.1-2 acceptable because

the applicant adequately described its process for establishing the use of grouted wall

penetrations and underground piping as an equivalent anchor termination point. Therefore, the

applicant resolved the staff concern described in RAI 2.1-2.

Conclusion

On the basis of the additional information supplied by the applicant, which provides technical

justification for identification of certain equivalent anchor locations, and as a result of the NRC

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inspection and audit activities, the staff concluded that the applicant has supplied sufficient

information to demonstrate that the methodology for identifying systems and structures meeting

the scoping criteria of 10 CFR 54(a)(2) is adequate.

Application of the Scopinq Criterion in 10 CFR 54.4(a)(3)

In part, 10 CFR 54.4(a)(3) requires applicants to consider in safety analyses or plant

evaluations all SSCs relied on to perform functions demonstrating compliance with the

Commission's regulations for FP (10 CFR 50.48), EQ (10 CFR 50.49), pressurized thermal

shock (10 CFR 50.61, "Fracture Toughness Requirements for Protection against Pressurized

Thermal Shock Events"), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be within the

scope of license renewal. Pressurized thermal shock is not applicable to BWRs and, therefore,

the applicant did not evaluate it. SRP-LR.Section 2.1.3.1.3, "Regulated Events," states that all

SSCs relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant-specific operating

experience, industry-wide operating experience (as appropriate), and safety analyses or plant

evaluations to perform functions demonstrating compliance with NRC regulations under

10 CFR 54.4(a)(3) must be included within the scope of license renewal; however,

consideration is not required of hypothetical failures from system interdependencies not part of,

the CLB and not previously experienced.

The staff reviewed the applicant's approach to identifying SSCs relied upon to perform

functions related to the four regulated events, as described in 10 CFR 54.4(a)(3). As part of this

review, the staff discussed the methodology with the applicant's LRA team, reviewed supporting

documentation, and evaluated a sample of the SSCs identified as within scope, pursuant to the

10 CFR 54.4(a)(3) criterion.

The applicant documented its methodology for scoping SSCs in accordance with

10 CFR 54.4(a)(3) in implementation procedures, as described in the audit report. The

applicant's initial scoping for regulated events evaluated relevant CLB information to determine

whether the structure or system met the scoping criterion of 10 CFR 54.4(a)(3). For the four

regulated events, the applicant developed technical reports describing the relevant rule

requirements, implementation of the requirements, specific information about systems and

components credited for the event, the process to identify the scoping boundaries of the

systems credited, a list of CLB information sources for the analysis, and systems and

components within the scope of license renewal for the given regulated event. Systems or

structures with one or more components credited for demonstrating compliance with one of the

regulated events are within the scope of license renewal, pursuant to the 10 CFR 54.4(a)(3)

criterion. In addition, the staff determined that identification of SSCs within the scope of license

renewal to support 10 CFR 50.63 had been in accordance with the guidance of ISG-02, "Station

Blackout Scoping." in summary, the applicant included within the scope of license renewal the

SSCs relied upon in safety analyses or plant evaluations to perform intended functions

demonstrating compliance with NRC regulations for FP, EQ, ATWS, and SBO, in accordance

with the 10 CFR 54.4(a)(3) criterion.

The staff's review of the applicant's scoping methodology included the set of scoping

calculations for each regulated event, a sample of the supporting analyses and documentation,

discussion of the methodology and results with the applicant's personnel responsible for these

evaluations, and a review of ALEX. The staff verified that the applicant had identified and used

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pertinent engineering and licensing information to determine the SSCs within the scope of

license renewal, in accordance with the 10 CFR 54.4(a)(3) criterion.

Conclusion

Based on this sampling review, discussions with the applicant, and review of the applicant's

scoping process, the staff determined that the applicant's methodology for identifying systems

and structures meeting the 10 CFR 54.4(a)(3) scoping criterion is adequate.

2.1.3.1.3 Plant-Level Scoping of Systems

The applicant documented its methodology for scoping systems in accordance with

10 CFR 54.4(a) in its implementing procedures. The applicant's approach to scoping systems

was consistent with the methodology described in LRA Section 2.1.4. Specifically, the

implementing procedure specified that personnel scoping for license renewal use CLB and DBE

documents to describe systems, including lists of all functions that the system is required to

accomplish. Sources of information included the USAR, DBDs, Q-List and 0-List Extension

drawings, CHAMPS, the Maintenance Rule documents, P&IDs, and docketed correspondence.

The applicant then compared system function lists to the scoping criteria to determine whether

the system functions met the 10 CFR 54.4(a) scoping criteria. The applicant documented the

scoping results in ALEX, which included a description of the system, a list of functions

performed by the system, identification of intended functions, the 10 CFR 54.4(a) scoping

criteria met by the system, references, and a list of components performing intended functions.

During the scoping methodology audit, the staff reviewed a sampling of ALEX scoping reports

and concluded that they contain an appropriate level of detail to document the scoping process.

The applicant established color-coded boundary P&IDs for each mechanical system within the

scope of license renewal. A preparer and an independent reviewer comprehensively evaluated

the license renewal color-coded P&IDs for completeness and accuracy of the review results.

The staff reviewed several license renewal color-coded boundary P&IDs and verified that ALEX

did identify the systems within license renewal boundaries.

Conclusion

On the basis of a review of the LRA, ALEX, scopind and screening implementation procedures,

license renewal color-coded P&IDs, and a sampling review of system scoping results, the staff

concluded that the applicant's scoping methodology for systems is adequate. In particular, the

staff determined that the applicant's methodology reasonably identified systems within the

scope of license renewal and their associated intended functions.

2.1.3.1.4 Mechanical Component-Level Scoping

After the applicant had identified systems within the scope of license renewal and their

associated intended functions, it identified the components of each system within the scope of

license renewal that supported an intended function. As described in LRA Section 2.1.4, the

applicant considered a component to be within the scope of license renewal if needed for

performance of a system intended function.

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The applicant described the methodology used for component scoping in LRA Section 2.1.4,

and its implementing procedures, as documented in the audit report. The applicant evaluated

CHAMPS, the USAR, DBDs, DBEs, plant walkdowns, training materials, license renewal

color-coded boundary P&IDs, specifications, codes/standards, design changes, plant

procedures, and CLB documentation to identify components credited with compliance to

10 CFR 54.4(a). Components meeting the requirements of 10 CFR 54.4(a) were considered

within the scope of license renewal and the applicant entered this information into ALEX.

The staff reviewed the results of the ALEX scoping reports and discussed the scoping process

in detail with the applicant's license renewal project personnel. The staff assessed whether the

applicant appropriately applied the LRA scoping methodology and implementation procedures

and whether the scoping results were consistent with CLB requirements. The staff determined

that the applicant's proceduralized methodology was consistent with the description in LRA

Section 2.1.4 and the guidance in SRP-LR Section 2.1 and was adequately implemented.

The staff reviewed the scoping process for the CRD system. The staff verified that the applicant

had developed color-coded system boundary P&IDs that identified license renewal CRD system

boundaries in accordance with the procedural guidance. The staff verified that CRD system

components meeting 10 CFR 54.4(a) requirements were within the scope of license renewal.

The staff found the applicant knowledgeable about the process and conventions for

establishing boundaries as defined in the license renewal implementation procedures.

Conclusion

On the basis of the applicant'sdetailed scoping implementation procedures and a sampling

review of CRD system mechanical components scoping results, the staff concluded that the

applicant's methodology for identifying mechanical components within the scope of license

renewal meets 10 CFR 54.4(a) requirements.

Structural Component Scopinq

The applicant described the methodology used for structural scoping in LRA Section 2.1.4, and

its implementing procedures, as documented in the audit report. The applicant developed a list

of SSCs using CHAMPS information. The applicant's technical reports listed all civil/structural

SCs within the scope of license renewal. The applicant evaluated CHAMPS, the USAR, DBDs,

training materials, drawings, specifications, codes/standards, design changes, plant

procedures, and CLB documentation to identify structures credited with compliance to

10 CFR 54.4(a). In addition, the applicant performed walkdowns of plant buildings. Systems

which contained components determined to meet 10 CFR 54.4(a) requirements were

considered within the scope of license renewal and the applicant entered this information into

ALEX. The scope of license renewal included all SR structures and structural components. SR

items within the scope of license renewal include walls, piping and equipment supports, conduit,

cable trays, electrical enclosures, and instrument panels relied upon in the CLB. The NSR

structures and structural components that perform functions required for compliance with FP,

ATWS, and SBO regulations were included within the scope of license renewal. NSR structural

items within the scope of license renewal include missile shields that protect SR equipment;

overhead handling systems that could affect SR equipment; permanently installed walls, curbs,

and doors that provide flood protection for SR equipment; and jet impingement shields and

blowout panels that protect SR equipment from the effects of an HELB. The staff reviewed the

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LRA, procedures, drawings, and the ALEX database. The staff reviewed the results of the

scoping methodology for select structures that included the diesel fuel oil transfer house, offgas

stack, and the intake structure (flood control).

The audit team reviewed plant procedures which provide instructions for the response of MNGP

personnel to extreme natural conditions. These procedures address tornados, external flooding,

high river water temperature, low river water flow/level, high-wind conditions, heavy snowfall,

and high ambient (outside) air temperature. Plant procedures also provide instructions for

protecting structures from flooding in the event that Mississippi River flood waters are predicted

to exceed specific elevations. For example, steel plates required to be bolted over specific

structure openings are stored on site to accomplish this task. Another example of an action to

prevent flooding is the removal of the intakestructure Amertap hatch covers and installation of

the original floor hatches. The staff noted that equipment stored for use, such as steel plates

and floor hatches, was not included within the scope of license renewal.

The staff's review of LRA Section 2.1.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening methodology.

The applicant responded to the staff's RAI as discussed below.

In' RAI 2.1-1, dated July 20, 2005, the staff requested that the applicant provide the technical

basis for not including, within the scope of license renewal, equipment stored on site that station

procedures require to be installed during emergency or abnormal conditions, in accordance with

the CLB, or describe the methodology for ensuring that the license renewal scoping addressed

all such equipment.

In its response, by letter dated August 16, 2005, the applicant stated that it had added steel

plates stored outside, which are dedicated for use during postulated external events, and steel

hatch covers stored in the warehouse, which are dedicated for external flood use to the scope

of license renewal and this equipment was subject to an AMR.

Based on its review, the staff found the applicant's response to RAI 2.1-1 acceptable, because

the applicant revised its scoping and screening methodology to include the appropriate

equipment stored on site that the station procedures require to be installed during emergency

or abnormal condition in accordance with the CLB. Therefore, the applicant resolved the staff

concern described in RAI 2.1-1.

Conclusion

The staff determined that the applicant's methodology is consistent with the description in LRA

Section 2.1.4 and the guidance in SRP-LR Section 2.1. Based on review of information in the

LRA, the applicant's detailed scoping implementation procedures, the additional information

from the applicant on scoping and screening methodology for equipment stored on site, and a

sampling review of structural scoping results, the staff concluded that the applicant's

methodology for identification of structural SSCs within the scope of license renewal meets

10 CFR 54.4(a) requirements.

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Electrical and I&C ComDonent ScoDina

The applicant described the methodology for electrical and I&C scoping in LRA Section 2.1.5.4,

and its implementing procedures, as documented in the audit report. The applicant performed

electrical and I&C scoping at a system level. The applicant developed information from

numerous sources including CHAMPS, the USAR, and the Maintenance Rule program system

basis documents. The applicant entered the system description, the applicable design-basis

reference, and system functions into ALEX. The applicant evaluated the system functions in

accordance with the 10 CFR 54.4(a) criteria to determine whether the system was within the

scope of license renewal. Following evaluation of the system functions, the applicant added the

reference identifying the system function which placed the system within the scope of license

renewal to ALEX. The applicant added systems to the license renewal database which were

created to include electrical and I&C components not already specifically identified within an

existing system (such as cables) in CHAMPS. The System/Structure Scoping and Screening

Output Reports document these activities.

Conclusion

The staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of the

application of the scoping methodology for select systems. The staff found the applicant's

methodology consistent with the description in LRA Section 2.1.5.4 and with the applicant's

implementing procedures. Based on review of information in the LRA, the applicant's detailed

scoping implementation procedures, and a sampling review of electrical and I&C scoping

results, the staff concluded that the applicant's methodology for identifying electrical and I&C

components within the scope of license renewal meets 10 CFR 54.4(a) requirements.

2.1.3.2 Screening Methodology

The applicant described its screening process in LRA Section 2.1.5. In general, the applicant's

screening consistedof evaluations to determine which SCs within the scope of license renewal

were passive and long-lived. Passive and long-lived SCs were then subject to further AMR. The

staff reviewed the methodology used by the applicant to determine whether mechanical,

structural, and electrical and I&C components within the scope of license renewal would be

subject to further AMR. The applicant provided the staff with a detailed discussion of the

processes for each discipline and provided administrative documentation that described the

screening methodology. The staff also reviewed the screening results report for the CRD

system. The staff noted that the applicant's screening process was performed in accordance

with its written requirements and was consistent with the guidance of the SRP-LR and NEI

95-10, Revision 4. The staff determined that the screening methodology was consistent with the

requirements of the Rule and that the screening methodology identified SCs meeting the

10 CFR 54.21 (a)(1) screening criterion.

The staff evaluated the applicant's screening methodology against the 10 CFR 54.21 (a)(1)

criterion using the review guidance of SRP-LR, Section 2.1.3.2, "Screening." Pursuant to

10 CFR 54.21 (a)(1), the applicant's IPA must identify and list SCs subject to an AMR. Further,

10 CFR 54.21 (a)(1) requires that SCs subject to an AMR encompass those SCs that (1)

perform an intended function, as described in 10 CFR 54.4, without moving parts or changes in

configurations or properties and (2) are not subject to replacement based on a qualified life or

specified time period. Pursuant to 10 CFR 54.21 (a)(2), the applicant must describe and justify

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the methods used to meet 10 CFR 54.21 (a)(1) requirements. In the LRA, the applicant

described screening methodologies unique to the mechanical, structural, and electrical

disciplines. The following sections describe the staff's evaluation of the applicant's screening

approach for each of these disciplines.

Mechanical Component Screeninq

The staff reviewed the methodology used by the applicant to determine whether mechanical

components within the scope of license renewal would be subject to further AMR. The applicant

applied a screening process to each mechanical component in ALEX. Implementing procedures

require that each component in ALEX be identified as periodically replaced, no intended

function, active, or requiring an AMR. CHAMPS was used to determine whether components

are periodically replaced. The applicant had previously entered component intended functions

into ALEX. The audit team reviewed technical reports which provided specific guidance for

determining whether components were active or passive. Technical reports also referred to

Appendix B to NEI 95-10 for component types generally considered active or passive. The

applicant provided the staff with a detailed discussion of the process and provided ALEX

screening report information describing the screening methodology, as well as a sample of the

screening result reports for a selected group of SR and NSR systems.

During the audit, the staff reviewed the methodology used by the applicant to identify and list

the mechanical components subject to an AMR, as well as the applicant's technical justification

for this methodology. The staff also examined the applicant's results from the implementation of

this methodology by reviewing the CRD system. The review included the license renewal

color-coded boundary P&lDs and resultant components within the scope of license renewal, the

corresponding component-level intended functions, and the resulting list of mechanical

components subject to an AMR. The staff reviewed several summary screening reports

breaking down the mechanical components within the scope of license renewal into several

categories, including component type, AMR requirement, and material, and a comment section.

The staff also discussed the process and results with the cognizant engineers who performed

the review. The staff did not identify any discrepancies between the methodology documented

and the implementation results.

Conclusion

On the basis of a review of the LRA, the scoping and screening implementation procedures,

and a sampling review of system and screening results, the staff determined that the applicant's

mechanical component screening methodology is consistent with the guidance of the SRP-LR

and is adequate for identifying passive, long-lived components within the scope of license

renewal subject to an AMR. Therefore, the staff concluded that the applicant's methodology for

identification of mechanical components subject to an AMR meets 10 CFR 54.21 (a)(1)

requirements.

Structural Component Screening

After determining which structural SSCs were within the scope of license renewal, the applicant

implemented a process for determining which SSCs would be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1). LRA Section 2.1.5 discusses the

screening of SSCs within the scope of license renewal. Screening activities identified passive

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components, long-lived components, component intended functions, consumables, and

component replacement based on performance or condition. The applicant relied on the

guidance of NEI 95-10 to develop the plant-specific listing of passive components of interest

during the review.

Conclusion

The staff reviewed the LRA, procedures, drawings, and the ALEX database. The staff also

reviewed the results of the scoping and screening methodology for select structures, including

the diesel fuel oil transfer house, offgas stack, and intake structure (flood control). The staff

found the applicant's methodology consistent with the description in LRA Sections 2.1.4 and

2.1.5 and the guidance of SRP-LR Section 2.1. Based on review of information contained in the

LRA, the applicant's detailed scoping implementation procedures, and a sampling review of

structural scoping and screening results, the staff concluded that the applicant's methodology

for identification of structural SSCs subject to an AMR meets 10 CFR 54.21 (a)(1) requirements.

Electrical and I&C Component Screening

The applicant described the electrical and I&C screening methodology in LRA Section 2.1.5.4,

and its implementing procedures, as documented in the audit report. The applicant identified

evaluation boundaries for the electrical and I&C systems previously determined to be within the

scope of license renewal. The applicant also reviewed components within the evaluation

boundary to identify SCs performing intended functions, and compiled such SCs into ALEX.

The applicant reviewed ALEX to identify the passive and long-lived components subject to an

AMR in accordance with 10 CFR 54.21. In addition, the applicant identified and reviewed fuse

holders, in accordance with the guidance contained in ISG-05, "Electrical Fuse Holders." The

applicant documented the results of these activities in four technical reports, "Electrical

Penetrations," "Non-EQ Cables and Connections," "Fuse Holders," and "Offsite Power/SBO

Recovery Path."

Conclusion

The staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of the

screening methodology. The staff found the applicant's methodology consistent with the

description in LRA Section 2.1.5.4 and the applicant's implementing procedures. Based on

review of information in the LRA, the applicant's detailed screening implementation procedures,

and a sampling review of electrical and I&C screening results, the staff concluded that the

applicant's methodology for identification of electrical and I&C SCs subject to an AMR meets

10 CFR 54.21 (a)(1) requirements.

Insulation

LRA Table 2.1-1 describes the intended function of thermal insulation to "limit heat transfer to

maintain temperature within design limits." During the audit, the staff reviewed technical reports,

as documented in the audit report, which described how thermal insulation was scoped and

screened at MNGP. No insulation at MNGP is classified as SR, so insulation can be within the

scope of license renewal only for environment control or seismic Il/I intended functions. The

applicant stated that thermal insulation to limit room heat-up was within the scope of license

renewal in two areas: high pressure coolant injection (HPCI) room piping insulation and residual

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heat removal (RHR) room heat exchanger insulation. Therefore, this specific thermal insulation

was subject to an AMR.

Conclusion

The staff reviewed the LRA, technical report, and the results of the scoping and screening

methodology for thermal insulation. The staff found the applicant's methodology consistent with

the description in LRA Table 2.1-1 and the applicant's implementing procedures. Based on

review of information in the LRA and the applicant's detailed technical report, the staff

determined that the applicant's methodology for identification of insulation subject to an AMR

meets 10 CFR 54.21 (a)(1) requirements.

Consumables

During the audit, the applicant described the screening review for certain consumable

commodities in LRA Section 2.1.5.3, "Component Classification (Passive, long-lived)."

Section 2.1.5.3 states that evaluation of items to determine whether they are consumables

followed the NRC screening guidance of SRP-LR Table 2.1-3, "Specific Staff Guidance on

Screening," for determining whether consumable items are subject to an AMR. For

consumables periodically replaced, SRP-LR Table 2.1-3 states that the applicant should identify

the standards that are relied on for replacement as part of the methodology description.

The table states that consumables like packing, gaskets, component seals, and O-rings may be

excluded from an AMR using a clear basis. Consistent with SRP-LR Table 2.1-3, the applicant

divided consumables into four basic categories, (1) packing, gaskets, component seals, and

O-rings, (2) structural sealants, (3) oil, grease, and filters (system and component filters), and

(4) fire extinguishers, fire hoses, and air packs. The applicant's guidance for performing

screening reviews for commodity groups states that, regardless of how consumables

associated with components or structures are screened for an AMR, the bases for the

determinations made are presented in the respective AMR reports.

The staff selected various AMR reports and verified that each contained a discussion of the

treatment of consumables. The staff reviewed several AMRs during its scoping and screening

audit and verified that they contained components subject to short-lived/replaceable

determinations.

Conclusion

The staff reviewed the LRA, technical report, a sample of the screening methodology results,

and AMRs. The staff found the applicant's methodology consistent with the description in LRA

Section 2.1.5.3 and the applicant's implementing procedures. Based on review of information

contained in the LRA, the applicant's detailed screening implementation procedures and

technical report, a sampling review of consumable screening results, and AMRs, the staff

concluded that the applicant's methodology for identification of consumables subject to an AMR

meets 10 CFR 54.21 (a)(1) requirements.

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2.1.3.3 QA Controls Applied to LRA Development

The staff reviewed the QA controls used by the applicant for reasonable confidence that the

LRA scoping and screening methodologies were adequately implemented. Although the

applicant did not develop the LRA under a 10 CFR Part 50, Appendix B QA program, the staff

determined that the applicant utilized the following QA processes during the LRA development:

* Written procedures and guidelines governed implementation of the scoping and

screening methodology.

* The Offsite Review Committee and the Plant Operations Review Committee reviewed

and approved the LRA before its submission to the staff.

The applicant planned to retain certain license renewal documents as quality records or

controlled documents.

* The applicant performed an industry peer review of license renewal activities.

* The applicant's Nuclear Oversight Department performed a self-assessment in the area

of implementation of license renewal procedures.

Conclusion

On the basis of review of pertinent LRA development guidance, discussion with the applicant's

license renewal personnel, and review of the Nuclear Oversight quality audit report, the staff

concluded that such QA activities provide reasonable assurance that LRA development

activities were consistent with LRA descriptions.

2.1.3.4 Training

The staff reviewed the applicant's training process to ensure that guidelines and methodology

for scoping and screening activities were consistent and appropriate. The applicant had

developed 10 license renewal lesson plans to train all technical leads and site personnel in

license renewal activities. The applicant developed and used implementing procedures to train

contract personnel supporting the license renewal effort. The applicant also required contract

personnel to review the applicable regulations, NEI 95-10, the applicable administrative work

instruction, and the License Renewal Project Plans. In addition, the applicant created

"Documentation of Information Sharing" on specific license renewal topics as they were

developed and conducted periodic training sessions for all license renewal personnel.

Conclusion

On the basis of discussions with the applicant's license renewal project team responsible for the

scoping and screening process and a review of selected documentation in support of the

process, the staff concluded that the applicant's personnel understood the requirements and

guidance and adequately implemented the scoping and-screening methodology documented in

the LRA. The staff concluded that license renewal personnel were adequately trained and

qualified to perform the applicable license renewal activities.

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2.1.4 Conclusion

The staff reviewed the information in LRA Section 2.1, the supporting information in the scoping

and screening implementation procedures and reports, and the information presented during

the scoping and screening methodology audit. The staff verified that the applicant's scoping

and screening methodology is consistent with the requirements of the Rule. On the basis of this

review, the staff concluded that, with the exceptions noted above, the applicant's methodology

for identifying SSCs within the scope of license renewal and the SCs requiring an AMR is

consistent with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a)(1).

2.2 Plant-Level Scoping Results

2.2.1 Introduction

In LRA Section 2.1, the applicant described the methodology for identifying the SSCs within the

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to

determine which SSCs are required to be included within the scope of license renewal. The

staff reviewed the plant-level scoping results to determine whether the applicant had properly

identified all plant-level systems and structures relied upon to remain functional during and

following DBEs, as required by 10 CFR 54.4(a)(1), or whose failure could prevent satisfactory

accomplishment of any of the SR functions of SSCs within the scope of license renewal, as

required by 10 CFR 54.4(a)(2), as well as the systems and structures relied on in safety

analyses or plant evaluations to perform a function that demonstrates compliance with one of

the regulations referenced in 10 CFR 54.4(a)(3).

2.2.2 Summary of Technical Information In the Application

In LRA Table 2.2-1, the applicant provided a list of the plant-level scoping results, identifying

those systems, structures, and commodities that are within the scope of license renewal. Based

on the DBEs considered in the plant's CLB, other CLB information relating to NSR systems and

structures, and certain regulated events referenced in 10 CFR 54.4(a)(3), the applicant

identified those plant-level systems and structures that are within the scope of license renewal,

as defined by 10 CFR 54.4.

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying the systems and

structures that are within the scope of license renewal and subject to an AMR. The staff

reviewed the scoping and screening methodology and provided its evaluation in Section 2.1 of

this SER. To verify that the applicant properly implemented its methodology, the staff focused

its review on the implementation results, as shown in LRA Table 2.2-1, to confirm that no

plant-level systems and structures were omitted from the scope of license renewal.

The staff determined whether the applicant properly identified the systems and structures within

the scope of license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected

systems and structures that the applicant did not identify as falling within the scope of license

renewal to verify whether the systems and structures have any intended functions that would

require their inclusion within the scope of license renewal. The staff conducted its review of the

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applicant's implementation in accordance with the guidance described in SRP-LR Section 2.2,

"Plant-Level Scoping Results."

In reviewing LRA Section 2.2, the staff identified areas for which it needed additional

information to complete its evaluation of the applicant's plant-level scoping results. Therefore,

the staff issued RAIs concerning each specific issue to determine whether the applicant

properly applied the scoping criteria of 10 CFR 54.4. The following paragraphs describe the

staff's RAIs and the applicant's related responses.

In RAI 2.2-1, dated June 21, 2005, the staff noted that the control rod velocity limiters described

in USAR Section 6.4 are integral parts of each control rod providing hydraulic damping to

reduce the freefall velocity of the rod and reduce consequences if the control rod becomes

detached from its drive and drops from the core. The LRA does not mention this component,

nor does it appear to refer to USAR Section 6.4; therefore, the staff requested that the applicant

clarify whether these components are included within the scope of license renewal or state the

basis for their exclusion.

In its response, by letter dated July 21, 2005, the applicant stated that control rod velocity

limiters are plant-engineered safety features (ESFs), as described in USAR Chapter 6. Control

rod velocity limiters are provided as an integral part of each control rod. They provide hydraulic

damping to reduce the freefall velocity of the rod and thereby reduce the consequences if the

control rod becomes detached from its drive and drops from the core. Since the control rod

velocity limiters are an integral part of each control rod, the velocity limiters are within the scope

of license renewal; however, the control rods (including the velocity limiters) are screened out of

the AMR process since they are replaced periodically.

Based on its review, the staff found the applicant's response to RAI 2.2-1 acceptable. The

applicant stated that all ESFs are within the scope of license renewal and are in addition to the

safety features included in the design of the reactor, reactor primary system, plant and reactor

control systems, and other instrumentation or process systems. Most of the ESFs serve no

function during normal plant operation, but are included for the sole purpose of reducing the

consequences of DBAs described in USAR Section 14. The applicant stated that LRA Section

2.3.3.4 includes a discussion of the control rod velocity limiters. Therefore, the applicant

resolved the staff concern described in RAI 2.2-1.

In RAI 2.2-2, dated June 21, 2002, the staff noted that the safety parameter display

system (SPDS) is described in USAR Section 7.13. The .SPDS provides a concise display of

critical plant variables to control room operators to aid them in rapidly and reliably determining

the safety status of the plant. The LRA does not mention this system, nor does it appear to

refer to USAR Section 7.13 in the text; therefore, the staff requested that the applicant clarify

whether this system is within the scope of license renewal or state the basis for its exclusion.

In its response, by letter dated July 21, 2005, the applicant stated that it included the process

computer system (PCS) in the license renewal system under "Computer." The LRA lists the

computer system in Table 2.2-1, "Plant Level Scoping Results," page 2-47, which states that

the system is not within the scope of license renewal. The PCS provides input to the SPDS and

the SPDS is considered a PCS subsystem.

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The applicant further stated that the purpose of the PCS system is to aid the operator in timely

determination of the plant's operability status during all' plant conditions by providing a real-time

presentation of operational data, including input-to the SPDS, pertaining to the reactor core and

other plant equipment. USAR Section 7.13 states that the SPDS is not essential to safe

operation of the plant, prevention of events that endanger public health and safety, or mitigation

of the consequences of an accident. The PCS also records plant operational data, which can be

recalled for evaluation of abnormal and unusual events.

The applicant stated that the USAR discusses the PCS in relation to such topics as the rod

worth minimizer, accident monitoring instrumentation, and the SPDS. The process computer is

not SR and its failure will not cause an SR function to fail (USAR Section 7.8.3). SR isolation

devices between the PCS, neutron monitoring, and the plant protection system (PPS) signal

inputs' are parts of these other systems for purposes of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.2-2 acceptable. The

applicant stated that the process computer is not on the MNGP Q-list. The process computer is

not required for any of the regulated events referenced in 10 CFR 54.4(a)(3). The 250-

volts-direct current (VDC) system battery that powers the process computer is not required to

function during an SBO event. The FP system does not rely on the computer to process fire

detection and alarm signals. The required ATWS monitoring instrumentation does not rely on

the PCS; thus, the PCS, including the SPDS, was determined to be outside the scope of license

renewal. Therefore, the staff's concern described in RAI 2.2-2 is resolved.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2, the RAI responses described above, and the supporting

information in the MNGP USAR to determine whether the applicant had failed to identify any

systems and structures that should be within the scope of license renewal. The staff's review

did not identify any omissions. On the basis of this review, the staff concluded that the applicant

properly identified the systems and structures that are within the scope of license renewal in

accordance with 10 CFR 54.4.

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff's review of the applicant's scoping and screening results for

mechanical systems. Specifically, this section discusses the following mechanical systems:

" reactor vessel, internals, and reactor coolant system (RCS)

* ESFs

" auxiliary systems

" steam and power conversion system

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must identify and list

passive, long-lived mechanical SSCs that are within the scope of license renewal and subject to

an AMR. To verify that the applicant properly implemented its methodology, the staff focused its

review on the implementation results. This approach allowed the staff to confirm that no

mechanical system components that meet the scoping criteria and are subject to an AMR were

omitted.

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Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRA

in the same manner for all mechanical systems. The objective of the review was to determine

whether the applicant had identified the components and supporting structures for a specific

mechanical system, that appeared to meet the scoping criteria specified in the Rule, as within

the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the

applicant's screening results to verify that all long-lived, passive components were subject to an

AMR, in accordance with 10 CFR 54.21(a)(1).

ScoDina. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of license renewal. The staff reviewed relevant licensing-basis

documents, including the USAR, for each mechanical system to determine whether the

applicant had omitted components with intended functions delineated under 10 CFR 54.4(a)

from the scope of license renewal. The staff also reviewed the licensing-basis documents to

determine whether the LRA specified all intended functions delineated under 10 CFR 54.4(a). If

omissions were identified, the staff requested additional information to resolve the

discrepancies.

Screening. Once the staff completed its review of the scoping results, the staff evaluated the

applicant's screening results. For those systems and components with intended functions, the

staff sought to determine (1) if the functions are performed with moving parts or a change in

configuration or properties or (2) if the components are subject to replacement based on a

qualified life or specified time period, as described in 10 CFR 54.21 (a)(1). For those systems

and components that did not meet either of these criteria, the staff sought to confirm that these

mechanical systems and components were subject to an AMR, as required by

10 CFR 54.21 (a)(1). If discrepancies were identified, the staff requested additional information

to resolve them.

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System

In LRA Section 2.3.1, the applicant identified the SCs of the reactor vessel, internals, and RCS

that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the reactor vessel, internals, and RCS in the

following sections of the LRA:

* 2.3.1.1 reactor head vent system

* 2.3.1.2 reactor pressure vessel

* 2.3.1.3 reactor pressure vessel internals

" 2.3.1.4 reactor recirculation system

" 2.3.1.5 reactor vessel instrumentation

SER Sections 2.3.1.1-2.3.1.5 present the staff's review findings regarding LRA

Sections 2.3.1.1-2.3.1.5, respectively.

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2.3.1.1 Reactor Head Vent System

2.3.1.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.1, the applicant described the reactor head vent system. The reactor head

vent system maintains the reactor pressure boundary. The reactor head vent system provides a

means to (1) permit venting the RPV during filling for hydrostatic test, (2) permit remote venting

of noncondensable gases which may accumulate in the vessel head space during reactor

cooldown after the main steamlines have been flooded, and (3) permit venting of

noncondensable disassociated gases which might accumulate in the vessel head space during

reactor operation to one of the main steamlines.

The reactor head vent system contains SR components that are relied upon to remain

functional during and following DBEs.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.1-1, the applicant identified the following reactor head vent system component

types that are within the scope of license renewal and subject to an AMR:

• fasteners/bolting 0 piping and fittings

valve bodies

2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.1.1.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the reactor head vent system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the reactor head vent system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.3.1.2 Reactor Pressure Vessel

2.3.1.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.2, the applicant described the RPV system. The RPV system consists of

the RPV top head enclosure, vessel shell, nozzles, nozzle safe ends, penetrations, bottom

head, and support skirt and attachment welds. RPV internals are included in the reactor

internals system. The RPV serves as a high-integrity barrier against leakage of radioactive

materials to the drywell.

The RPV system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the RPV system performs functions that support FP, ATWS, and

SBO.

The intended functions within the scope of license renewal include the following:

* provide a pressure-retaining boundary

" provide structural support to SR components (vessel internals)

In LRA Table 2.3.1-2, the applicant identified the •following RPV system component types that

are within the scope of license renewal and subject to an AMR:

* bottom head components-bottom head dollar plate, bottom head torus

" nozzle safe ends-control rod drive return line cap

" nozzle safe ends-core spray

• nozzle safe ends-feedwater (FW) nozzle

* nozzle safe ends-instrument and standby liquid control (SLC)

" nozzle safe ends--jet pump instrument

" nozzle safe ends-main steam

* nozzle safe ends-recirculating water

* nozzle safe ends and flanges-instrument

• nozzles-OCRD return line

• nozzles-FW

* nozzles-main steam

* nozzles-recirculation outlet, recirculation inlet, core spray, jet pump instrument,

instrument and SLC

* penetration-bottom head drainline

" penetration--CRD stub tubes

* penetration-flux monitor

• penetration-instrument

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RPV external surface

" support skirt and attachment welds

" top head enclosure-closure studs and nuts

* top head enclosure-head spray cap

* top head enclosure-instrument nozzle (head spare)

* top head enclosure-instrument nozzle flange (head spare)

" top head enclosure-top head dollar plate

* top head enclosure-top head flange

* top head enclosure-top head torus

" top head enclosure-vent nozzle

" vessel shell attachment welds

* vessel shell-upper intermediate shell, lower intermediate shell, lower shell, beltline

welds

* vessel shell-vessel flange, upper shell

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.1.2.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs that

should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RPV system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RPV

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.1.3 Reactor Pressure Vessel Internals

2.3.1.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.3, the applicant described the RPV internals. The RPV internals consist of

all the SCs within the reactor vessel that provide support for the core, control rod system

support, instrumentation support, and steam quality enhancement and that direct coolant flow.

The RPV internals contain SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RPV internals could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RPV internals perform functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide a pressure-retaining boundary * provide structural support to SR components (vessel internals)

• provide adequate flow in a specified distribution spray pattern

In LRA Table 2.3.1-3, the applicant identified the following RPV internals component types that

are within the scope of license renewal and subject to an AMR:

* access hole covers

* control rod drive housing

* control rod guide tube (CRGT)

* CRGT base

• core plate

* core plate bolts

* core shroud (upper, central, lower)

* core spray lines and spargers, piping supports, clamp modification, core spray lines

(headers), spray rings, spray nozzles, thermal sleeves

" intermediate-range monitor dry tubes, source range monitor dry tubes, incore flux

monitor guide tubes, low-power range monitor (LPRM) dry tubes

* jet pump assembly-riser pipe

" jet pump assemblies--castings (elbow, collar, flare, flange, transition piece)

* jet pump assemblies-diffuser

* jet pump assemblies-holddown beams

• jet pump assemblies-inlet header

• jet pump assemblies-inlet elbow

* jet pump assemblies-mixing assembly

" jet pump assemblies-riser brace arm

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* jet pump assemblies-thermal sleeves

" LPRM dry tubes

" orificed fuel support

* shroud support structure (shroud support cylinder, shroud support plate, shroud support

legs)

* standby liquid control distribution pipe

* steam dryer

* top guide

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive, long-lived components that should be subject to an AMR, in accordance

with the requirements of 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.1.3 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.1-1, dated September 15, 2005, the staff noted that LRA Section 3.1.2.2.4.2 states

the jet pump sensing lines internal to the reactor vessel are not within the scope of license

renewal; however, it is unclear whether the portion of the jet pump sensing line external to the

reactor vessel that can provide a pressure boundary and structural support is within the scope

of license renewal. The staff requested that the applicant indicate whether it had included the

external jet pump sensing line piping within the scope of license renewal and identify the LRA

table and subcomponent group including the subject component or justify the exclusion.

In its response, by letter dated October 14, 2005, the applicant stated the following:

Jet Pump Sensing Lines external to the vessel are in scope for license renewal.

The sentence on page 3-30 of the LRA was intended to indicate that only internal

lines are outside scope. The sensing lines are 1-inch stainless steel pipes in the

Reactor Vessel Instrumentation (RVI) system. The aging management for the

internal (Treated Water) environment is shown in LRA Table 3.1.2-5 Reactor

Coolant System-Reactor Vessel Instrumentation, on Page 3-82. The applicable

aging effects are cracking and loss of material which are managed by American

Society of Mechanical Engineers (ASME) Section XI Subsections IWB, IWC, and

IWD, the Plant Chemistry Program, and the One-Time Inspection Program. No

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aging management is required for the external surfaces of the stainless steel

sensing lines exposed to primary containment and plant indoor air.

Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable based

on the inclusion of the subject component; therefore, the applicant resolved the staff concern

described in RAI 2.3.1-1.

In RAI 2.3.1-2, dated September 15, 2005, the staff noted that in LRA Table 2.3.1-3, "Reactor

Pressure Vessel Internals," core spray (CSP) lines and spargers have been identified as a

component type within the scope of license renewal; however, for these components, pressure

boundary was identified as the only intended function requiring aging management. and not their

function of providing adequate flow in a properly distributed spray pattern. The staff requested

that the applicant clarify why it had not identified the spray pattern function, in addition to

pressure boundary function, as an intended function needing maintenance during the extended

period of operation.

In its response, dated October 14, 2005, the applicant stated the USAR Section 3.6.2.10, "Core

Spray Spargers," states, 'The supply line pairs terminate at a common vessel nozzle. Each half

has distribution nozzles pointed radially inward and downward at a slight angle to achieve a

specified distribution pattern." Therefore, an intended function of 'spray pattern' is assigned to

the CSP lines and spargers by revision to LRA Tables 2.3.1-3, "Reactor Pressure Vessel

Internals," and 3.1.2-3, "Reactor Coolant System-Reactor Pressure Vessel Internals." There are

no changes to the aging effects or the aging management programs (AMPs). The applicant

added the component intended function, "spray pattern-to provide adequate flow in a specified

distribution spray pattern," by revising LRA Table 2.1-1, "Intended Function Definitions."

Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable based

on the inclusion of the spray pattern intended function for the above component; therefore, the

applicant resolved the staff concern described in RAI 2.3.1-2.

2.3.1.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant had adequately identified the RPV internals

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RPV internals components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.4 Reactor Recirculation System

2.3.1.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.4, the applicant described the reactor recirculation (REC) system. The

REC system includes the recirculation flow control (RFC) subsystem for license renewal

purposes. The REC system forces water through the reactor core to provide forced convection

cooling of the reactor core. The system consists of two recirculation pump loops outside the

vessel and twenty jet pumps inside.the vessel. The jet pumps are part of the reactor internals

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system. Each REC system loop outside the vessel consists of a motor-driven recirculation

pump, two motor-operated gate valves for pump isolation, piping, and required recirculation flow

measurement devices. Jet pump flow instrumentation outside the reactor vessel is included

within the license renewal boundary of the REC system. The REC system (via the recirculation

flow control subsystem) also functions as a method of controlling the reactor power level. The

REC system pumps, motors, and loop piping are located in the drywell outside the biological

shield.

The REC system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the REC system could potentially prevent the

satisfactory accomplishment of an, SR function of SSCs within the scope of license renewal. In

addition, the REC system performs functions that support EQ and ATWS.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.1-4, the applicant identified the following REC system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

• filters/strainers

" heat exchangers

* •manifolds

* piping and fittings

* pump casings

* restricting orifices

* tanks

* thermowells

* valve bodies

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.3.1.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

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In RAI 2.3.1-3, dated September 15, 2005, the staff noted that, in LRA Table 2.3.1-4, "Reactor

Recirculation System," and for a few other systems (for example the CSP and CRD systems),

heat exchangers were identified as a componeht type within the scope of license renewal;

however, for these heat exchangers, pressure boundary was identified as the only intended

function requiring aging management and not their heat transfer function. Therefore, the staff

requested that the applicant clarify why it did not identify the heat transfer function, in addition

to the pressure boundary function, as an intended function needing maintenance during the

extended period of operation.

In its response, by letter dated October 14, 2005, the applicant stated the following:

The heat exchangers in scope for the Reactor Recirculation (REC) system are:

The No. 11 and No.12 REC Motor/Generator Set Oil Coolers - These

heat exchangers are shown on License Renewal (LR) drawing LR-36041

and are in scope for non-safety related components that could adversely

affect safety related systems, structures, and components (SSCs) and

are only required to maintain a pressure boundary. Therefore, no heat

transfer function is required for these components to meet their intended

functions.

The REC Pump Lower Seal Cooler and REC Pump Upper Seal Cooler -

These heat exchangers are shown on drawing LR-36243-1. The heat

exchanger tubes serve as a reactor coolant pressure boundary, whereas

the shells are in scope for non-safety related components that could

adversely affect safety related SSCs and are only required to maintain a

pressure boundary. Therefore, no heat transfer function is required for

these components to meet their intended functions.

The heat exchangers in scope for the Core Spray (CSP) System are:

The CSP Pump Motor Oil Coolers - The heat exchangers are shown on

drawing LR-36664. An analysis concluded that the core spray motors are

operable if motor cooling water is reduced to zero under worst case room

temperatures. Therefore the heat exchanger does not have an intended

function of providing heat transfer. The heat exchanger serves only a

pressure boundary function.

The heat exchangers in scope for the Control Rod Drive (CRD) system are:

The CRD Pump Thrust Bearing Cooler and the Lube Oil Cooler for the

CRD Pump Speed Increaser Assemblies - These heat exchangers are

shown on drawing LR-36244. The heat exchangers are in scope as

non-safety related components that could adversely affect safety related

SSCs. They are only required to maintain a pressure boundary.

Therefore, no heat transfer function is required for these components to

meet their intended safety functions.

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Based on its review, the staff found the applicant's response to RAI 2.3.1-3 acceptable. Heat

transfer is not an intended function for the REC system heat exchangers; therefore, the

applicant resolved the staff concern described in RAI 2.3.1-3.

2.3.1.4.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs that

should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant failed to identify any components

that should be subject to an AMR. No omissions were identified. On the basis of its review, the

staff concluded that the applicant adequately identified the REC system components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and the REC system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.5 Reactor Vessel Instrumentation

2.3.1.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.1.5, the applicant described the RVI system. The RVI system is designed to

fulfill a number of requirements pertaining to the vessel itself or the reactor core. The

instrumentation must (1) provide the operator with sufficient information in the control room to

protect the vessel from undue stresses, (2) provide information which can be used to assure

that the reactor core remains covered with water and that the steam separators are not flooded,

(3) provide redundant, reliable inputs to the reactor protection system to shut the reactor down

when fuel damage limits are approached, and (4) provide a method of detecting leakage from

the reactor vessel head flange. The RVI system also includes the reference leg backfill

subsystem. This subsystem provides a constant backfill of water from the CRD system's

charging water header to the safeguards and FW reference legs to flush any gas-laden water

through the condensate chambers and back to the reactor vessel to eliminate level errors

resulting from the degassing phenomenon.

The RVI system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RVI system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RVI system performs functions that support FP, EQ, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

,, provide a pressure-retaining boundary

• provide flow restriction

In LRA Table 2.3.1-5, the applicant identified the following RVI system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* . manifolds

* piping and fittings

* restricting orifices

* thermowells

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a valve bodies

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.5 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.1.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RVI system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RVI

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2 Engineered Safety Features

In LRA'Section 2.3.2, the applicant identified the SCs of the ESFs that are subject to an AMR

for license renewal.

The applicant described the supporting SCs of the ESFs in the following sections of the LRA:

* 2.3.2.1 automatic pressure relief system

* 2.3.2.2 combustible gas control system

* 2.3.2.3 core spray system

* 2.3.2.4 high pressure coolant injection system

* 2.3.2.5 primary containment mechanical system

* 2.3.2.6 reactor core isolation cooling system

* 2.3.2.7 residual heat removal system

* 2.3.2.8 secondary containment system

SER Sections 2.3.2.1-2.3.1.8 present the staff's review findings regarding LRA

Sections 2.3.2.1-2.3.1.8, respectively.

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2.3.2.1 Automatic Pressure Relief System

2.3.2.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.1, the applicant described the automatic pressure relief (APR) system.

The APR system is designed to prevent overpressurization and provide depressurization of the

reactor vessel during DBEs. Two safety relief valves (SRVs) on each of the four steamlines are

equipped to operate by automatic or manual initiation to blow down the reactor. Steam is

passed through the valves, down a tailpipe, and through the torus vent headers to discharge.

underwater through T-quenchers in the event of SRV activation. The automatic

depressurization system (ADS) is an APR subsystem that provides backup to the high pressure

coolant injection (HPC) system and is designed to reduce reactor vessel pressure to a range

suitable for low-pressure emergency core cooling pumps to operate. The low-low set system is

an APR subsystem designed to control post-shutdown overpressure with progressive SRV

pressure release setpoints. The alternate shutdown (ASD) system panel provides for manual

operation of four APR system SRVs. The APR system is also used to implement the ASD

cooling method. To use the ASD cooling method, the reactor is depressurized using the

automatic depressurization subsystem of the APR system.

The APR system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the APR system performs functions that support FP, EQ, and SBO.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.2-1, the applicant identified the following APR system component types that

are within the scope of license renewal and subject to an AMR:

* accumulators

• fasteners/bolting

" manifolds

* piping and fittings

" thermowells

* valve bodies

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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2.3.2.1.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the APR system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the APR

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.2 Combustible Gas Control System

2.3.2.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.2, the applicant described the combustible gas control (CGC) system. In

its letter, dated March 15, 2006, the applicant stated that the CGC system was deactivated by

cutting and capping process lines connecting to interfacing systems during the 2005 refueling

outage, in accordance with the NRC's approval of License Amendment 138, which eliminated

the requirements for hydrogen recombiners and relaxed the requirements for hydrogen and

oxygen monitoring. Therefore, the system has been removed from the scope of license

renewal.

2.3.2.2.2 Conclusion

On the basis of the isolation and capping of the CGC system due to License Amendment 138,

the staff concluded that the applicant appropriately characterized the system as outside the

scope of license renewal.

2.3.2.3 Core Spray System

2.3.2.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.3, the applicant described the CSP system. The CSP system restores and

maintains the coolant in the RPV in combination with other emergency core cooling

systems (ECCS) such that the core is adequately cooled to preclude fuel damage. Two

independent CSP system loops are provided for use under loss-of-coolant accident (LOCA)

conditions associated with large pipe breaks and reactor vessel depressurization. Suction water

is normally supplied from the suppression pool, but can also be supplied by the condensate

storage tank (CST). The CSP system provides adequate cooling along with low-pressure

coolant injection (LPCI) for intermediate and large line break sizes up to and including the

design-basis, double-ended recirculation line break, without assistance from any other ECCS.

In conjunction with the LPCI mode of the RHR system, the HPC system, and the APR, the CSP

system can act automatically (in response to signals indicative of a LOCA) to reflood the reactor

core and maintain core cooling following a LOCA event. Initiation of the CSP system occurs on

signals indicating (1) reactor low-low water level coincident with low reactor pressure, or

(2) sustained reactor low-low water level, or (3) high drywell pressure. The reactor low-low

water level signal or the high drywell pressure signal also initiate the emergency diesel

generators (EDGs). Cooling water to the CSP system pump motor coolers is supplied by the

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emergency service water (ESW) system. The power source for each CSP system is located on

separate emergency buses. The EDGs can supply power for these emergency buses.

The CSP system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the CSP system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the CSP system performs functions that support FP, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

" provide flow restriction

* provide a pressure-retaining boundary

In LRA Table 2.3.2-3, the applicant identified the following CSP system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* gauges (flow, level, and sight)

* heat exchangers

" manifolds

* piping and fittings

" pump casings

" restricting orifices

* thermowells

* valve bodies

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified, On the basis of its

review, the staff concluded that the applicant had adequately identified the CSP system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CSP system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.2.4 High Pressure Coolant Injection System

2.3.2.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.4, the applicant described the HPC system. The HPC system is part of the

ECCS. The ECCS provides for continuity of reactor core cooling over the entire range of

postulated breaks in the reactor primary system. The HPC system provides adequate core

cooling for all break sizes less than those sizes for which the LPCI subsystem or CSP system

can adequately protect the core, without assistance from other safeguards systems. The HPC

system performs this function without reliance on offsite power or a water source for the

injection. The HPC system can pump water into the RPV under LOCA conditions that do not

result in rapid depressurization of the RPV. The HPC system is a high-head, low-flow system

that pumps water into the RPV when the reactor primary system is at high pressure. If the HPC

system fails to deliver the required flow of cooling water to the RPV, the automatic

depressurization feature of the reactor APR system functions to reduce system pressure so that

the LPCl subsystem can operate to inject water into the RPV. The HPC turbine trips when the

turbine steam supply pressure has decreased to the isolation setpoint. All these operations are

performed automatically.

The HPC system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the HPC system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the HPC system performs functions that support EQ and SBO.

The intended functions within the scope of license renewal include the following:

* provide filtration

* provide flow restriction

* provide for heat transfer

* provide a pressure-retaining boundary

" limit heat transfer to maintain temperature

In LRA Table 2.3.2-4, the applicant identified the following HPC system component types that

are within the scope of license renewal and subject to an AMR:

* fan/blower/housings

0 fasteners/bolting

* filters/housings

* gauges (flow, level, and sight)

* .heat exchangers

* manifolds

• piping and fittings

* pump casings

* restricting orifices

* steam traps

* tanks

" thermowells

* turbines

" valve bodies

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2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.4.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the HPC system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the HPC system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.5 Primary Containment Mechanical System

2.3.2.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.5, the applicant described the primary containment mechanical (PCM)

system. The PCM system includes the containment atmosphere control and nitrogen control

components, the hydrogen-oxygen analyzing, the post-accident sampling (PAS), and the hard

pipe vent subsystems. The PCM system was created to separate out the mechanical

components of the primary containment (PCT) system for license renewal evaluation purposes.

The mechanical components, and the associated electrical and I&C components, were

transferred from the PCT system to the PCM system. The resulting PCT system contains only

the structural components of the primary containment system. For license renewal evaluations,

the PCM system also includes the portions of the mechanical containment penetration

assemblies that are extensions of the mechanical piping. These are the flued heads and guard

pipes of the mechanical containment penetration assemblies. The other components of the

containment penetration assemblies (e.g., the sleeves) are evaluated in the PCT system. The

PAS subsystem consists of a liquid and gas sample station located outside the secondary

containment in the turbine building near the control room access door. The system is designed

to provide samples under all conditions ranging from normal shutdown and power operation to

the design-basis LOCA. The hard pipe vent subsystem provides a vent path from the pressure

suppression chamber (wetwell) vapor space to a release point above the reactor building.

The PCM system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the PCM system could potentially prevent the

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satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the PCM system performs functions that support FP, EQ, and SBO.

The intended functions within the scope of license renewal include the following:

• provide filtration

" provide a pressure-retaining boundary

• provide pressure boundary or fission product retention

In LRA Table 2.3.2-5, the applicant identified the following PCM system component types that

are within the scope of license renewal and subject to an AMR:

• accumulators

• fasteners/bolting

* filters/strainers

* flow element

* manifolds

• piping and fittings

* rupture disks

* thermowells

* valve bodies

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 and USAR Sections 5.2.1.3, 5.2.2.3, 5.2.2.7, 5.2.3.10,

5.2.3.11, and 10.3.10.1 using the evaluation methodology described in SER Section 2.3. The

staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the PCM system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the PCM system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.2.6 Reactor Core Isolation Cooling System

2.3.2.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.6, the applicant described the reactor core isolation cooling (RCI) system.

The MNGP licensing basis does not include the RCI system as an ESF system The RCl

system is included within this section, and the related aging management section, for

consistency with the SRP-LR and NUREG-1 801, "Generic Aging Lessons Leaned (GALL)

Report," issued July 2001. The RCl system uses a steam-driven turbine to drive a pump to

inject water into the reactor vessel so that the core is not uncovered in the event of a loss of

FW. While the system is not credited in the SBO analysis for mitigating loss of offsite

power (LOOP) events, the system Miay be used to cope with such events. The RCI pump is

supplied demineralized makeup water from the CST and can use the suppression pool as an

alternate SR source of water. All components necessary for the initiation and operation of the

RCl system are completely independent of any auxiliary alternating current (AC) power, plant

service air, and external cooling water systems, requiring only direct current (DC) control and

instrument power from the plant batteries. The RCI system also provides for primary

containment isolation. The pumping capacity of the RCI system is sufficient to maintain the

water level above the core without any other makeup water system in operation.

The RCl system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RCl system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RCI system performs functions that support EQ.

The intended functions within the scope of license renewal include the following:

" provide filtration

" provide flow restriction

" provide for heat transfer

" provide a pressure-retaining boundary

In LRA Table 2.3.2-6, the applicant identified the following RCI system component types that

are within the scope of license renewal and subject to an AMR:

" fasteners/bolting

* filters/strainers

* heat exchangers

* manifolds

* piping and fittings

* pump casings

* restricting orifices

* steam traps

" tanks

* thermowells

* turbines

" valve bodies

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2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.6.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RCI system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RCI

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2:7 Residual Heat Removal System

2.3.2.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.7, the applicant described the RHR system. The RHR system restores

and maintains the reactor coolant inventory in the reactor core so that the reactor core is

adequately cooled after depressurization during a LOCA. The RHR system also provides

cooling for the suppression pool to ensure condensation of the steam resulting from the

blowdown from the design-basis LOCA. The RHR system further extends the redundancy of the

ECCS by providing for primary containment spray/cooling. In addition, the RHR system

provides for primary containment isolation. The RHR system is designed for essentially three

modes of operation, (1) LPCI, (2) containment spray/cooling, and (3) reactor shutdown cooling.

The shutdown cooling subsystem is used for routine operations. The LPCI subsystem is an

integral part of the RHR system. It operates to restore and maintain the reactor coolant

inventory in the reactor core after a LOCA so that the core is sufficiently cooled. The LPCI

subsystem operates in conjunction with the HPC system, the APR system, and the CSP system

to achieve this goal. The RHR system provides a means to remove decay heat and residual

heat from the reactor so that refueling and reactor systems servicing can be performed. In

addition, the RHR system provides the means to supplement the spent fuel pool cooling system

when necessary to provide additional cooling capacity.

The RHR system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RHR system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RHR system performs functions that support FP, EQ, and SBO.

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The intended functions within the scope of license renewal include the following:

" provide filtration

* provide for heat transfer

* provide a pressure-retaining boundary " limit heat transfer to maintain temperature

In LRA Table 2.3.2-7, the applicant identified the following RHR system component types that

are within the scope of license renewal 'and subject to an AMR:

* accumulators

" fasteners/bolting

* filters/strainers

* heat exchangers

* manifolds

* nozzles

* piping and fittings

" pump casings

" restricting orifices

thermowells

valve bodies

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.7 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.7.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RHR system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RHR system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.2.8 Secondary Containment System

2.3.2.8.1 Summary of Technical Information in the Application

In LRA Section 2.3.2.8, the applicant described the secondary containment (SCT) system. The

SCT system completely encloses the reactor and its pressure suppression primary

containment. The secondary containment enclosure structure provides secondary containment

when the primary containment is closed and in service and primary containment when the

primary containment is open, as during refueling. The reactor building houses the refueling and

reactor servicing equipment, new and spent fuel storage facilities, and other reactor auxiliary

systems or service equipment. The primary purposes for the secondary containment are to

minimize ground-level release of airborne radioactive materials to the environs and to provide

means for a controlled, elevated release of the building atmosphere, if an accident should

occur. The standby gas treatment system (SGTS) is a subsystem of the SCT system and is

provided to maintain, whenever secondary containment isolation conditions exist, a small

negative pressure to minimize ground-level escape of airborne radioactivity. Filters are in the

system to remove radioactive particulates, and charcoal adsorbers are provided to remove

radioactive halogens. All flow from the standby gas treatment system is released through the

elevated offgas vent stack and continuously monitored by the stack gas monitoring system.

The SCT system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the SCT system performs functions that support EQ.

The intended functions within the scope of license renewal include the following:

* provide flow restriction

* provide a pressure-retaining boundary

In LRA Table 2.3.2-8, the applicant identified the following SCT system component types that

are within the scope of license renewal and subject to an AMR:

" damper housings

* ductwork

* fan/blower/housings

" fasteners/bolting

* filters/housings

* flow element

* manifolds

* piping and fittings

* restricting orifices

* thermowells

" valve bodies

* ventilation seal

2.3.2.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.8 and USAR Section 5.3 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.8.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the SCT system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SCT

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3 Auxiliary Systems

In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems that are subject

to an AMR for license renewal.

The applicant described the supporting SCs of the auxiliary systems in the following sections of

the LRA:

* 2.3.3.1

" 2.3.3.2

* 2.3.3.3

" 2.3.3.4

" 2.3.3.5

* 2.3.3.6

* 2.3.3.7

• 2.3.3.8

* 2.3.3.9

* 2.3.3.10

* 2.3.3.11

* 2.3.3.12

* 2.3.3.13

* 2.3.3.14

* 2.3.3.15

* 2.3.3.16

" 2.3.3.17

" 2.3.3.18

alternate nitrogen system

chemistry sampling system

circulating water system

control rod drive system

demineralized water system

emergency diesel generators system

emergency filtration train system

emergency service water system

fire system

fuel pool cooling and cleanup system

heating and ventilation system

instrument and service air system

radwaste solid and liquid system

reactor building closed cooling water system

reactor water cleanup system

service and seal water system

standby liquid control system

wells and domestic water system

SER Sections 2.3.3.1-2.3.3.18 present the staff's review findings regarding LRA

Sections 2.3.3.1-2.3.3.18, respectively.

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2.3.3.1 Alternate Nitrogen System

2.3.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.1, the applicant described the alternate nitrogen system (AN2). The AN2

system consists of two separate SR trains providing an SR backup pneumatic source from

nitrogen bottle racks located in the turbine building. The AN2 system interfaces with the

instrument and service air (AIR) system through a check valve, with the nitrogen side held at a

slightly lower pressure to allow the AIR system to be used during normal operation. In the event

of an accident, which also disables the AIR system, the AN2 system would automatically supply

the required pneumatic loads. Manifold and system pressures of each train are monitored by

pressure switches, which give control room annunciation on low pressure. The nitrogen supply

bottles connected to the distribution rack are not long-lived components, and therefore, are not

subject to an AMR.

The AN2 system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the AN2 system performs functions that support FP, EQ, and SBO.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-1, the applicant identified the following AN2 system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting * flexible connections

* piping and fittings

" valve bodies

2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section-2.3.3.1 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.1-1, dated September 16, 2005, the staff noted that the license renewal drawing

LR-36049-1 0 at location B-8 and C-8 shows the nitrogen supply bottles as within the scope of

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license renewal; however, LRA Table 2.3.3-1 does not list these nitrogen supply bottles as a

component type subject to an AMR. These nitrogen supply bottles provide a pressure boundary

intended function and are passive and long-lived; therefore, the staff requested that the

applicant clarify whether these nitrogen supply bottles are included with another component

type (i.e., tanks) and if not, the applicant should justify why they are not listed in Table 2.3.3-1

or update the table to include these components.

In its response, by letter dated October 14, 2005, the applicant stated that nitrogen supply

bottles are periodically replaced and therefore are not long-lived and are not subject to an AMR,

pursuant to the requirements of 10 CFR 54.21 (a).

Based on its review, the staff found the applicant's response to RAI 2.3.3.1-1 acceptable

because the nitrogen supply bottles are periodically replaced and thus are not subject to AMR;

therefore, the applicant resolved the staff concern described in RAI 2.3.3.1-1.

2.3.3.1.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the AN2 system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the AN2

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.2 Chemistry Sampling System

2.3.3.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.2, the applicant described the chemistry sampling (CHM) system. The

CHM system provides for sampling the process fluid of various systems to obtain representative

data to evaluate the performance of the plant systems and equipment. The sampling locations

are chosen to ensure that representative samples can be obtained. The sample streams are

routed by the shortest route to a common sample collection area. There is a collective sample

station for each building in the plant-radwaste building sample station, located in the radwaste

building; reactor building sample station, located in the reactor building; and turbine building

sample station, located in the turbine building. The stations are provided with closed-loop

process lines that discharge to the equipment drain tanks and then to the waste collector tank

for reprocessing. Each sample station typically consists of a sample rack with sample shutoff

valves; sample coolers; sample chillers; sample modules; instrumentation for conductivity, pH,

dissolved oxygen, dissolved hydrogen, and total organic carbon, as well as a local data

acquisition system panel. There is a ventilated fume hood for collection of grab samples

adjacent to the sample rack.

The failure of NSR SSCs in the CHM system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

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In LRA Table 2.3.3-2, the applicant identified the following CHM system component types that

are within the scope of license renewal and subject to an AMR:

* chillers

* fasteners/bolting

* filters/housings

" flow element

* heat exchangers

* manifolds

piping and fittings

thermowells * valve bodies

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted- any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.2.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CHM system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CHM system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.3 Circulating Water System

2.3.3.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.3, the applicant described the circulating water (CWT) system. The CWT

system removes the heat from the main condenser that is rejected by the turbine or turbine

bypass system over the full range of operating loads. The CWT system is a flexible multi-cycle

system with the capability of once-through circulation of river water, recirculation in a closed

cycle with cooling towers, and several variations of these basic modes. Selection of the

operating mode will be determined by the prevailing river flow rate and river temperature to

provide economic plant operation and conformance with restrictions on river water use. The

system is equipped with two half-capacity CWT pumps located at the intake structure. The

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pumps are designed to circulate cooling water through the main condenser. Two half-capacity

cooling tower pumps, located at the discharge structure, are used during cooling tower

operation. The pumps are designed to operate in series with the CWT pumps, discharging flow

to each of two induced-draft cooling towers.

The failure of NSR SSCs in the CWT system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-3, the applicant identified the following CWT system component types that

are within the scope of license renewal and subject to an AMR:

* condenser water box

* expansion joints

* fasteners/bolting

* filters/strainers

* gauges (flow, level, and sight)

* manifolds

* piping and fittings " pump casings

* tanks

" thermowells

" valve bodies

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CWT system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CWT system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.4 Control Rod Drive System

2.3.3.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.4, the applicant described the CRD system. The CRD system is designed

to allow control rod withdrawal or insertion at a limited rate, one control rod at a time, for powerlevel control and flux shaping during reactor operation. Stored energy available from

gas-charged accumulators and/or from reactor pressure provides hydraulic power for rapid

simultaneous insertion of all control rods for rapid (scram) reactor shutdown. Each control rod

has its own separate drive mechanism, control, and scram devices. The CRD system is

designed so that sufficient energy is available to force the control rods into the core under

conditions associated with abnormal operational transients and accidents. Control rod insertion

speed is sufficient to prevent fuel damage as a result of any abnormal operational transient.

The CRD system also supplies water to the RVI reference-leg backfill subsystem. This

subsystem provides a constant backfill of water from the CRD system's charging water header

to the safeguards and FW reference legs to flush any gas-laden water through the condensate

chambers and back to the reactor vessel to eliminate level errors from the degassing

phenomenon.

The CRD system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the CRD system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the CRD system performs functions that support FP, EQ, ATWS, and SBO.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-4, the applicant identified the following CRD system component types that

are within the scope of license renewal and subject to an AMR:

* accumulators

* fasteners/bolting

" filters/strainers

* flow element

* gauges (flow, level, and sight)

• heat exchangers

* manifolds

• piping and fittings

* pump casings

* restricting orifices

" speed increaser assembly

* tanks

0 thermowells

* valve bodies

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2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.4.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CRD system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CRD system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.5 Demineralized Water System

2.3.3.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.5, the applicant described the demineralized water system (DWS). The

DWS provides for storage and distribution of high-quality, nonradioactive demineralized water

for use as makeup to the CST system and other systems requiring high-quality demineralized

water. The DWS is NSR and is not required during or following DBEs. The DWS includes the

makeup demineralizer (MUD) subsystem. The MUD subsystem is a double-pass,

reverse-osmosis system used to purify and demineralize well water. This demineralized water is

used for various plant services which require quality water to (1) minimize damage to.

components because of chemical and corrosive attack, (2) minimize the fouling of heat transfer

surfaces and mechanical parts, and (3) minimize impurities available for activation in neutron

flux zones. The MUD subsystem is also NSR and is not required during or following DBEs. The

DWS provides for primary containment isolation.

The DWS contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the DWS could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-5, the applicant identified the following DWS component types that are

within the scope of license renewal and subject to an AMR:

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* fasteners/bolting

" filters/housings

* flow element

" heat exchangers

* manifolds

" piping and fittings

* pump casings

" restricting orifices

* tanks

* thermowells

* ultraviolet light housings

* valve bodies

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No-omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the DWS components that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and the DWS

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.6 Emergency Diesel Generators System

2.3.3.6.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.6, the applicant described the EDG system (DGN). The DGN system

provides a dependable, onsite power source capable of automatically starting and supplying the

loads necessary to safely shut down the plant and maintain it in a safe-shutdown condition upon

the loss of offsite power simultaneous with a DBA. The EDGs are normally in the standby mode

of operation and remain in this mode unless called upon to start by receipt of appropriate

automatic signals or by a manual start. The DGN system contains two identical electromotive,

turbocharged, 20-cylinder EDGs, each supplying 4160 volts-alternating current (VAC) to its

respective emergency bus. The following subsystems within the DGN system support operation

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of the EDGs-(1) an engine fuel oil system, (2) an engine lubricating oil system, (3) a starting

air system, (4) a closed-cycle engine cooling water system, and (5) anair intake and exhaust

system. The engine fuel oil system provides clean, water-free fuel oil to the diesel cylinders.

The engine lubricating oil system provides filtered lubricating oil to the diesel engine to ensure

adequate lubrication during engine startup and operation. The starting air system consists of

two independent air-starting systems for each diesel that provide the motive force to initially put

the diesel engine in motion and begin the diesel cycle. The closed-cycle engine cooling water

system provides cooling to the diesel cylinders and heads and the aftercooler of the

turbocharger via two engine-driven centrifugal pumps. The EDG air intake and exhaust system

removes exhaust gases from the diesel cylinders and supplies fresh air for the combustion

process. The DGN system includes the diesel oil (DOL) system as a subsystem for license

renewal purposes. The DOL subsystem provides for the storage and distribution of fuel oil used

in the operation of the plant EDGs, diesel fire pump, and heating boiler.

The DGN system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the DGN system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the DGN system performs functions that support FP.

The intended functions within the scope of license renewal include the following:

* provide filtration

* provide for heat transfer

* provide a pressure-retaining boundary

In LRA Table 2.3.3-6, the applicant identified the following DGN system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* filters/housings

a filters/strainers

* flame arrestors

* flow element

• gauges (flow, level, and sight)

• heat exchangers

* heaters/coolers

" manifolds

" piping and fittings

* pump casings

" silencer

• tanks

* thermowells

* valve bodies

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive. and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.6 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant'responded to the staff's RAI as discussed below.

In RAI 2.3.3.6-1, dated September 16, 2005, the staff noted that the DGN system includes a

DOL subsystem which stores and supplies diesel fuel oil for the operation of the plant diesel

generators, diesel fire pump, and heating boiler. The DOL subsystem (except such portions as

the heating boiler oil storage tank and its day tank) is SR and within the scope of license

renewal; however, license renewal drawing LR-36051 sheet 1 shows the truck fill connection at

location B-5 and the diesel oil receiving tank (T-83) subsystem (including pump, piping, and

other components) at location A-7 as outside the scope of license renewal. Therefore, the staff

requested that the applicant clarify whether these components are within the scope of license

renewal and subject to an AMR, in accordance with the applicable requirements of

10 CFR 54.4(a) and 10 CFR 54.21 (a), respectively, or justify their exclusion.

In its response, by letter dated October 14, 2005, the applicant stated that the diesel oil

receiving tank (T-83) and truck fill connection are utilized for receiving, storing, and sampling

diesel fuel oil before transfer of the fuel oil to the diesel oil storage tank (T-44) and that these

components are not SR. The applicant explained that failure of the truck fill connection and the

diesel oil receiving tank (T-83) and connecting piping outside the diesel fuel oil transfer

house (pump house) would not impact the intended function of any SR SCs. The applicant,

therefore, concluded that the NSR fill connection, diesel oil receiving tank, and connecting

piping outside the pump house performed no license renewal function as defined by

10 CFR 54.4(a) and, therefore, were not within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.3.6-1 acceptable

because the applicant provided a satisfactory explanation as to why the components are

outside the scope of license renewal; therefore, the applicant resolved the staff concern

described in RAI 2.3.3.6-1.

The staff's review of LRA Section 2.3.3.6 identified an area in which information provided in the

LRA needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.6-1

LRA Section 2.3.3.6 states that DGN air-starting subsystem components within the scope of

license renewal are located between the air compressor discharge check valves and the diesel

engine air start motors; however, license renewal drawing LR-36051 shows, at locations A-3,

B-3, C-3, and D-3,.that the license renewal boundaries terminate in the middle of those pipes

connected between the compressor air dryers and discharge check valves (GSA-32-2,

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GSA-32-1, GSA-32-4, and GSA-32-3). The actual locations of the license renewal scope

boundaries for these components are not clear. The NRC Regional Inspection Team performed

an inspection to ensure that the license renewal scope boundaries for these components satisfy

the 10 CFR 54.4(a)(2) criterion.

The inspection team determined that the scope boundaries are just upstream of the respective

check valves, as indicated. The actual boundaries are where the carbon steel pipe connects to

the copper alloy tubing at the nipple to the air dryers. Because of the relative flexibility between

the piping and tubing, the boundary is the tubing transition point. The boundary drawing depicts

this transition point between the check valve and the air dryer. The inspectors determined that

the license renewal boundaries satisfy the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's

concern described in Inspection Item 2.3.3.6-1 is resolved.

2.3.3.6.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant had adequately identified the DGN system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant had adequately identified the DGN system components that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.7 Emergency Filtration Train System

2.3.3.7.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.7, the applicant described the emergency filtration train (EFT) system. The

MNGP licensing basis considers the EFT system as an ESF system. This section includes the

EFT system, and the related aging management section, for consistency with the SRP-LR and

GALL Report. The heating, ventilation, and air conditioning system that serves the main control

room (MCR) and the EFT building is designed to provide cool air in the summer and warm air

for heating in the winter. Ductwork is used to distribute air. The airflow in the MCR and portions

of the EFT building is normally recirculated with return air arranged to pass back to the air

conditioning unit, while supplemental outside air is drawn through filtration units. The EFT

system will serve the MCR and EFT building during normal or emergency conditions. An

emergency condition is defined as a condition caused by a high radiation level or detection of

toxic chemical vapors in the outside air. The air handling units are self-contained package units

complete with electric coils for heating and cooling coils for air conditioning. In the normal

operating mode, the MCR and EFT building's first and second floors, excluding the battery

room, are served by one of the redundant seismic Class 1 air conditioning units. Filtered

outside air from an EFT is available on demand. The EFT system operates in the recirculation

mode from offsite AC power. If offsite power is not available, the diesel generators will

automatically supply the system.

The EFT system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the EFT system performs functions that support FP.

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The intended functions within the scope of license renewal include the following:

* provide structural support to SR components (all other systems)

* provide for heat transfer

" provide a pressure-retaining boundary

In LRA Table 2.3.3-7, the applicant identified the following EFT system component types that

are within the scope of license renewal and subject to an AMR:

" chillers

* damper housings

" ductwork

* fan/blower/housings

* fasteners/bolting

* filters/housings

* heat exchangers

" piping and fittings

" valve bodies

* ventilation seal

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and USAR Section 6.7 using the evaluation

methodology described in SER Section 2.3. The staff conducted its review in accordance with

the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.7.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the EFT system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the EFT

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.8 Emergency Service Water System

2.3.3.8.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.8, the applicant described the ESW system, which includes the following

three plant subsystems-(1) EDG-ESW subsystem, (2) ESW subsystem, and (3) RHR service

water subsystem. These subsystems are combined into the ESW system for license renewal

purposes. The EDG-ESW subsystem consists of two separate and independent emergency

cooling water loops that provide cooling water to the EDGs. The loops are capable of providing

cooling water during a loss of offsite power and during accident conditions. Each, loop contains

one full capacity pump that supplies strained cooling water to one of the EDGs. The ESW

subsystem consists of two separate and independent emergency cooling water loops that

provide cooling water to the ECCS pump motor coolers, ECCS room coolers, and the EFT.

Each loop is capable of providing cooling water during a loss of offsite power and/or a loss of

normal service water. Each loop contains one full capacity pump that supplies strained cooling

water to the cooling loads. The RHR service water subsystem (RSW) consists of two separate

and independent emergency cooling water loops that provide cooling water to the RHR heat

exchangers. Each loop is capable of providing cooling water during a loss of offsite power and

during accident conditions. The RHR auxiliary air compressors are included in the RHR service

water subsystem. The RHR auxiliary air compressors provide an SR backup air supply to the

RHR heat exchanger residual heat removal service water (RSW) outlet control valves and the

CGC system isolation valves upon occurrence of low pressure in the AIR system. The RHR

auxiliary air compressors are normally in standby mode of operation.

The ESW system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the ESW system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the ESW system performs functions that support FP and EQ.

The intended functions within the scope of license renewal include the following:

* provide filtration

* provide flow restriction

* provide for heat transfer

* provide a pressure-retaining boundary

In LRA Table 2.3.3-8, the applicant identified the following ESW component types that are

within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* filters/housings

* filters/strainers

* flow element

* heat exchangers

* manifolds

* piping and fittings

* pump casings * restricting orifices

* tanks

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* thermowells

• valve bodies

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.8 identified an area in which information provided in the

LRA needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.8-1

License renewal drawing LR-36665 at location C-5 shows a continuation of NSR ESW piping

within the scope of license renewal from the valve (ESW-12-4"-JBD-GT) tothe desilting line on

LR-36665 at location A-5; however, the continuation desilting line at location A-5 is designated

as SW28-4"-JF and not identified as within the scope of license renewal. Consequently, the

actual location of the license renewal boundary for this pipe is not clear. The NRC Regional

Inspection Team performed an, inspection to ensure that the license renewal scope boundary

for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.

The inspection team determined that the continuation of NSR ESW piping from the valve

ESW-12 to the desilting line on LR-36665 at location A-5 should have been shown within the

scope of license renewal. The applicant will revise license renewal drawing LR-36665 to show

line SW28-4"-JF, the continuation to the desilting line, within the scope of license renewal, up to

where the line enters the column in the intake structure. The inspectors confirmed through

walkdowns that the scoping boundary is where this line passes into the column shown at

coordinates A-5 on the drawing. The inspectors determined that the license renewal boundary

satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.3.8-1 is resolved.

2.3.3.8.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the ESW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

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that the applicant adequately identified the ESW system components that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.9 Fire System

2.3.3.9.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.9, the applicant described the fire system. The fire system provides

assurance, through defense-in-depth design, that a fire will not prevent the performance of

necessary safe-shutdown functions or significantly increase the risk of radioactive release to the

environment during a postulated fire. The fire system provides fire suppression by fixed water

spray and sprinkler systems, fixed gas (Halon 1301) systems, hose stations, and portable

extinguishers located in various areas of the MNGP site. MNGP has a fire detection and alarm

system that alarms locally in selected areas of the plant and transmits various alarm,

supervisory, and trouble signals to the control room. The fire system ensures compliance with

the regulated event for FP. The Mississippi River supplies the water for the fire system. The fire

system also provides alternate sources of water to other plant systems.

The failure of NSR SSCs in the fire system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal. The fire system

also performs functions that support FP.

The intended functions within the scope of license renewal include the following:

* provide filtration

* provide flow restriction

* provide for heat transfer

* provide a pressure-retaining boundary

In LRA Table 2.3.3-9, the applicant identified the following fire system component types that are

within the scope of license renewal and subject to an AMR:

• fasteners/bolting

* filters/strainers

" fire hydrants

* flexible connections

* gauges (flow, level, and sight)

* heat exchangers

* manifolds

* nozzles

" piping and fittings

• pump casings

* restricting orifices

• sprinkler heads

* tanks

• valve bodies

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2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff also reviewed the approved FP SERs, dated

August 29, 1979, February 12, 1981, and October 2, 1985. These reports are referenced

directly in the MNGP FP CLB and summarize the FP program and commitments to

10 CFR 50.48 using the guidance of Appendix A to Branch Technical Position (BTP) Chemical

and Mechanical Engineering Branch (CMEB) 9.5-1, "Guidelines for Fire Protection for Nuclear

Power Plants." The staff then reviewed those components that the applicant had identified as

being within the scope of license renewal to verify that the applicant had not omitted any

passive and long-lived components that should be subject to an AMR, in accordance with the

requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.9 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.9-1, dated. August 18, 2005, the staff noted that license renewal drawing LR-36051

highlights the diesel fire pump, diesel fire pump day tank, and interconnecting piping as within

the scope of license renewal; however, the diesel fire pump day tank fill line is not highlighted.

The staff requested that the applicant clarify whether the diesel fire pump day tank fill line is

within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR,

in accordance with 10 CFR 54.21 (a)(1), or justify its exclusion.

In its response, by letter dated September 16, 2005, the applicant stated the following:

The diesel fire pump day tank fill line is not within the scope of license renewal

and is not subject to an AMR. The diesel fire pump day tank (T-1 00) is a

120-gallon capacity tank. The tank conservatively provides about ten hours of

operation of the diesel-driven fire pump before makeup is required. This satisfies

the requirements of NFPA-20, 'Standard for the Installation of Centrifugal Fire

Pumps,' which states that the day tank capacity '...shall be sufficient to operate

the engine for at least eight hours.' In accordance with the Operations Manual for

the diesel oil subsystem, the nominal fuel oil consumption of the diesel-driven fire

pump is eight (8) gallons per hour. An alternate method of transferring fuel oil

from the Diesel Oil Storage Tank (T-44) to the Diesel Fire Pump Day Tank is

provided during emergencies and is governed by abnormal procedures in

accordance with the MNGP Operations Manual. Under these situations, the

Portable Gasoline Engine Powered Fuel Oil Pump (P-229) that is normally stored

in Warehouse 2 is utilized. This portable pump is within the scope of license

renewal and is subject to AMR. P-229 is evaluated in AMR-DGN, Emergency

Diesel Generators System, since the diesel oil subsystem including fuel oil to the

diesel-driven fire pump, is evaluated within this AMR. Under these emergency

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situations, P-229 is connected to the Diesel Oil Storage Tank using portable

hoses. T-100 is filled by removing the 8" manhole cover from this tank and

inserting the discharge hose from P-229. Consequently, utilizing the Portable

Gasoline Engine Powered Fuel Oil Pump provides an alternate method of filling

the Diesel Fire Pump Day Tank and the Diesel Fire Pump Day Tank fill line is

excluded from the scope of license renewal and is not subject to AMR.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptable

because the diesel fire pump day tank can be filled using an alternate method (i.e., the portable

gasoline engine powered fuel oil pump) which is within the scope of license renewal and subject

to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-1 is resolved.

In RAI 2.3.3.9-2, dated August 18, 2005, the staff identified that license renewal

drawing LR-36664 (coordinates C-7) shows the KB/GB boundary and the system boundary

break (Fire Protection ESW) at opposite ends of valve RHRSW-46, which is the only valve on

the drawing at which they are at opposite ends. The staff requested that the applicant verify

whether this depiction is correct.

In its response, by letter dated September 16, 2005, the applicant stated, "This is correct due to

the fact that valve RHRSW-46 is within scope in the Fire Protection (FIR) System. There is

typically no correlation between License Renewal system boundary breaks and piping

classifications."

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-2 acceptable

because it adequately explains the scoping of valve RHRSW-46; therefore, the staff's concern

described in RAI 2.3.3.9-2 is resolved.

In RAI 2.3.3.9-3, dated August 18, 2005, the staff identified that on, license renewal

drawing LR-36664 the piping on the KB side (outlet) of valve RHRSW-46 (coordinates C-7) is

highlighted as within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). On

the continuation license renewal drawing LR-36048, the same piping is shown highlighted as

within the scope of license renewal pursuant to 10 CFR 54.4(a)(1) and (a)(3). The staff

requested that the applicant clarify which paragraph of 10 CFR 54.4 applies to this piping for

the LRA.

In its response, by letter dated September 16, 2005, the applicant stated the following:

The piping on the 'KB' side of valve RHRSW-46 on LRA drawing LR-36664 is

highlighted in 'green' since it is in the scope of license renewal in accordance

with 10 CFR 54.4(a)(2) for non-safety connected to safety (FIR to ESW) and,

non-safety affecting safety (NSAS) with respect to potential leakage/spray. It is

also in the scope of license renewal in accordance with 10 CFR 54.4(aX3) for the

fire protection regulated event. The continuation of this piping is highlighted on

LRA drawing LR-36048 in 'red' and is in the scope of license renewal per

10 CFR 54.4(a)(3) due to the Fire Protection regulated event. The color-coding

was performed in this manner to indicate these two separate criteria yet provide

differentiation between the two criteria due to this particular piping segment in

the FIR System being identified on two separate LR drawings.

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Based on its review, the staff found the applicant's response to RAI 2.3.3.9-3 acceptable

because it adequately explains that the piping on the KB side of valve RHRSW-46 is within the

scope of license renewal, pursuant to 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3); therefore, the

staff's concern described in RAI 2.3.3.9-3 is resolved.

In RAI 2.3.3.9-4, dated August 18, 2005, the staff identified that GALL Report Section XI.27,

"Fire Water System," describes the requirement for aging management of the FP water system

and recommends that an AMP be established to evaluate the aging effects of corrosion,

microbiologically influenced corrosion (MIC), and biofouling of carbon steel and cast iron

components in the FP systems exposed to water.

LRA Section 2.3.3.9 addresses requirements for the Fire Detection and Protection Program, but

does not mention trash racks and traveling screens for the fire pump suction water supply.

Neither LRA Section 2.3.3.3, "Circulating Water System," nor Section 2.4.8, "Intake Structure,"

mention trash racks and traveling screens.

The USAR states, in part, the following:

River water is turned through an angle of 81 0 to approach the plantalong a

channel excavated to elevation 898 feet. It enters the Intake Structure through a

trash rack before dividing into two separate streams to the circulating water

pump chambers. Each stream passes through two parallel automatically

operated traveling screens, the service water pump bay and two parallel

motor-operated sluice gates before reaching a circulating water pump. The

center dividing wall permits dewatering of either pump bay. A normally closed

gate in the wall can be manually opened during normal operation if a traveling

screen is out of service for maintenance. Taking suction from the service pump

bay are two 14,000 gpm make-up pumps and pumps for the station cooling,

screen wash, and fire protection.

Trash racks and traveling screens are necessary to remove debris and prevent clogging for the

FP water supply system. Trash racks and traveling screens are typically considered passive,

long-lived components. Trash racks are located in a freshwater environment. Traveling screens

are located in a freshwater/air environment. Although not specifically addressed in the USAR or

LRA, trash racks and traveling screens are typically constructed of carbon steel material.

Carbon steel in a freshwater environment or a freshwater/air environment is subject to

corrosion; therefore, the staff requested that the applicant explain the apparent exclusion of the

trash racks and traveling screens located upstream of the fire pump suctions from the scope of

license renewal and an AMR.

In its response, by letter dated September 16, 2005, the applicant stated the following:

The trash racks are installed to remove large debris from entering the Intake

Structure. Since the trash racks are an integral part of the Intake Structure, they

were included within the scope of license renewal and are subject to an AMR as

part of the Intake Structure, for conservatism. They are identified in Table 3.5.2-8

(Structures and Component Supports-Intake Structure) of the LRA as carbon

steel (Component Type) in both an atmosphere/weather and raw water

environment and are subject to an AMR due to loss of material. The Structures

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Monitoring Program manages the aging effect of loss of material for this

component. The traveling screens are part of the non-safety related Circulating

Water System that supports normal plant operation. The traveling screens are

provided for trash, fish, and vegetation removal to minimize the fouling and

clogging of the Circulating Water System water box tube sheets and piping.

However, for both the trash racks and the traveling water screens, build-up of

debris is considered event-driven and not age-related. Both the trash racks and

traveling screens are non-safety related, non-QA, and non-seismic components.

During normal plant operation, the Circulating Water pumps (two pumps in

operation) draw a significant flow of cooling water (292,000 gpm) through the

bays of the Intake Structure to support the main condenser cooling

requirements. This high flow rate (not including the normal Service Water flow

rate that equates to an additional 10,000 gpm with two pumps in operation)

creates the potential for debris and sediment to enter the bays. During

emergency operation, when the Circulating Water pumps are not in operation,

the Fire Pumps draw a small flow (1500 gpm/pump) of water through the bays

with a corresponding low velocity. The low flow velocity creates an insignificant

amount of debris and sediment to accumulate and the traveling water screens

are able to pass a sufficient amount of water to support operation of the Fire

Pumps. Additionally, the Fire Pumps themselves are equipped with suction

strainers. Basket strainers are provided in the main fire pump discharge headers.

Any significant degradation or failure of the traveling screens during normal

power operation would be evident and detected by plant operators far in advance

of a complete failure. Even in the case of total failure, floating or heavy debris

would not affect the operation of the Fire pumps due to the low velocities at the

suction of these pumps. The screens are subject to periodic maintenance and

replacement and are continuously monitored through main control room

annunciation. Additionally, the river and atmospheric environments for these

components are relatively non-aggressive. The traveling screens and trash racks

are not required to perform a function during or following a design basis event,

and therefore do not meet the scoping criteria of 10 CFR 54.4(a)(1 )(i), (ii), or (iii).

There is no credible failure mode of the traveling screens and trash racks that

could prevent satisfactory accomplishment of any of the functions identified in

paragraphs 10 CFR 54.4(a)(1 )(i), (ii), or (iii). Therefore, the traveling screens and

trash racks do not meet the scoping criteria of 10 CFR 54.4(a)(2). The traveling

screens and trash racks are not required to perform a function in support of the

regulated events of 10 CFR 54.4(a)(3).

Based on the above, the traveling screens and trash racks are not considered to

meet the scoping criteria of 10 CFR 54.4(a) and do not perform a license

renewal intended function per 10 CFR 54.4(b). Consequently, although the trash

racks are within the scope of license renewal and are subject to AMR since they

are an integral part of the Intake Structure and were included for conservatism,

the traveling screens are not within the scope of license renewal and are not

subject to AMR.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-4 acceptable

because the trash racks are integral parts of the intake structure and were included within the

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scope of license renewal and are subject to an AMR for conservatism. The traveling screens

are subject to periodic maintenance and replacement and are continuously monitored through

main control room annunciation. Even in the case of total failure, floating or heavy debris would

not affect the operation of the fire pumps because of the low velocities (compared to the

velocities of the flow for the CWT pumps) at the suction of these pumps; therefore, the staff's

concern described in RAI 2.3.3.9-4 is resolved.

In RAI 2.3.3.9-5, dated August 18, 2005, the staff noted that Section 3.1.2(3) of the NRC "Fire

Protection Safety Evaluation Report," dated August 29, 1979, states that "a sprinkler system will

be installed to provide a means to cool hot gases that enter the cable tray area in the water

treatment and ESF motor control center area." This sprinkler system is not shown on the

license renewal boundary drawings; therefore, the staff requested that the applicant verify that

this sprinkler system is within the scope of license renewal pursuant to 10 CFR 54.4(a)(3).

In its response, by letter dated September 16, 2005, the applicant stated the following:

The sprinkler system installed to provide a means to cool the hot gases that

enter the cable tray area in the water treatment and ESF motor control center

areas as addressed in the Fire Protection Safety Evaluation Report dated

August 29, 1979, Section 3.1.2(3), is not shown in the Fire System LR boundary

drawings (P&IDs). However, the isolation valves to this sprinkler system are

shown on License Renewal Boundary Drawing LR-36048, Fire Protection

System (coordinates C, 7). Valve FP-142 is located at the Turbine Building 951'

elevation and valve FP-1 45 is located at the Turbine Building 911' elevation.

These locked-open valves are noted on the drawing as 'FIREWALL SPRINKLER

ABOVE LUBE OIL STORAGE TANKS.' These two valves and the remainder of

this sprinkler system (water curtain) are in the scope of license renewal per

10 CFR 54.4(a)(3) and are subject to AMR. These components are addressed in

Table 3.3.2-9, Auxiliary Systems - Fire System - Summary of Aging Management

Evaluation, of the MNGP LRA. The aging effects associated with these

components are managed by both the Fire Water System and System Condition

Monitoring (external environment) AMPs. However, in addition to the installation

of this sprinkler system and in compliance with Appendix R of 10 CFR 50,

Section III.G.2(c), the cable, equipment and associated non-safety circuits of the

redundant trains are separated by a fire barrier (wall) having a minimum

one-hour rating (two-hour barrier actually installed). This fire barrier (Walls T324

and T331) is addressed in Table 3.5.2-17, Structures and Component Supports -

Turbine Building - Summary of Aging Management Evaluation, of the MNGP

LRA. Both the Fire Protection and Structures Monitoring AMPs manage the

aging effects associated with this component.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-5 acceptable

because it adequately explains that the sprinkler system, installed as a means to cool the hot

gases that enter the cable tray area in the water treatment and ESF motor control center (MCC)

areas, is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3) and subject to an

AMR; therefore, the staff's concern described in RAI 2.3.3.9-5 is resolved.

In RAI 2.3.3.9-6, dated August 18, 2005, the staff noted that Section 4.3.1 (17) of the NRC's

"Fire Protection Safety Evaluation Report," dated August 29, 1979, states that, "The licensee'

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will provide foam application equipment for use in fighting potential lube oil fires in the turbine

building." The license renewal drawings do not show this foam application equipment;

therefore, the staff requested that the applicant clarify whether this foam application equipment

is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3).

In its response, dated September 16, 2005, the applicant stated the following:

The foam application equipment addressed in the Fire Protection Safety

Evaluation Report dated August 29, 1979, Section 4.3.1(7) concerns the two (2)

sets of portable foam applicators for use in fighting potential lube oil fires in the

Turbine Building. This portable equipment is not shown in the Fire System LR

boundary drawings (P&IDs) since it is portable equipment. This equipment is

within the scope of license renewal per 10 CFR 54.4(a)(3) and is stored in the

Fire Brigade Room in the Plant Administration Building basement at MNGP. This

equipment is not subject to AMR since it is inspected periodically (quarterly)

under the Fire Protection Program procedures for fire brigade equipment and

replaced on condition.

This issue is also addressed in Section 2.1.4.2.4, Fire Protection, of the MNGP

LRA that states:

Items such as fire extinguishers, fire hoses, portable lighting, and air

packs were subjected to the MNGP's scoping and screening process.

This process is consistent with the NRC Staff's guidance on consumables

provided in NUREG-1 800, Table 2.1-3.

This issue is further defined in Section 2.1.5.3, Component Classification

(Passive, long-lived), of the MNGP LRA that states:

C. Fire Extinguishers, Fire Hoses, and Air Packs

Components such as fire hoses, fire extinguishers, self-contained

breathing apparatus (SCBA), and SCBA cylinders are consumables that

are routinely tested or inspected. The Fire Protection Program complies

with the applicable NFPA safety standards, which specify performance

and condition monitoring programs for these specific components. They

are replaced as necessary. Therefore, while these consumables are in

the scope of license renewal, they do not require an AMR.

A component (or component commodity group) that was determined to

be active or short-lived is not subject to an AMR, and is screened out by

the process.

Consequently, this foam application equipment is within the scope of license

renewal per 10 CFR 54.4(a)(3) but is not subject to an AMR.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-6 acceptable

because it adequately explains that the foam application equipment is within the scope of

license renewal, pursuant to 10 CFR 54.4(a)(3), but is not subject to an AMR because it is

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inspected periodically (quarterly) under the Fire Protection Program's procedures for fire

brigade equipment and replaced as necessary. Therefore, the staff's concern described in

RAI 2.3.3.9-6 is resolved.

In RAI 2.3.3.9-7, dated August 18, 2005, the staff noted that Section 5.2.6 of the NRC's "Fire

Protection Safety Evaluation Report," dated August 29, 1979, states that the cable spreading

room '•will be provided with an automatic gas suppression system." The license renewal

drawings do not show this automatic gas suppression system; therefore, the staff requested

that the applicant clarify whether this automatic gas suppression system is within the scope of

license renewal, pursuant to 10 CFR 54.4(a)(3).

In its response, dated September 16, 2005, the applicant stated the following:

The Cable Spreading Room, addressed in the Fire Protection Safety Evaluation

Report dated August 29, 1979, Section 5.2.6.3, is provided with a total flooding

automatic gas suppression system consisting of cylinder storage units

pressurized with Halon 1301. Halon is discharged into the room through

wide-angle nozzles. As stated in Section 2.1.4.4 (Evaluation Boundaries -

License Renewal Boundary Drawings) of the MNGP LRA, the in-scope

boundaries are depicted in the License Renewal Boundary Drawings. 'The

drawings consist of simplified process and instrumentation drawings (for the

mechanical systems)' or P&IDs. The Halon gas suppression system does not

appear in any of the MNGP P&IDs for the Fire System but rather in individual

vendor drawings which are not included as part of the license renewal boundary

drawing submittal package. The Cable Spreading Room Halon automatic gas

suppression system is in the scope of license renewal. This is confirmed by and

discussed in Section 2.3.3.9 (Fire System), Table 3.0-1 Mechanical and Civil

Service Environments, Table 3.3.2-9, (Auxiliary Systems - Fire System -

Summary of Aging Management Evaluation), Appendix A2.1.17 (Fire Protection)

and Appendix B2.1.17 (Fire Protection) of the MNGP LRA. Therefore, the Cable

Spreading Room automatic gas suppression system is in the scope of license

renewal per 10 CFR 54.4(a)(3) and is subject to AMR.

Based on its review, the staff found the applicant's response to RAI 2.3.3.9-7 acceptable

because it adequately explains that the automatic gas suppression system is within the scope

of license renewal, pursuant to 10 CFR 54.4(a)(3), and is subject to an AMR; therefore, the

staff's concern described in RAI 2.3.3.9-7 is resolved.

2.3.3.9.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the fire system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the fire system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.10 Fuel Pool Cooling and Cleanup System

2.3.3.10.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.10, the applicant described the fuel pool cooling and cleanup (FPC)

system. The FPC system is designed to handle the spent fuel cooling load and to maintain pool

water purity and clarity. The system provides sufficient filtering capacity to filter the entire spent

fuel pool water volume every 12 hours. The fuel pool temperature is normally maintained at

125 OF or less to ensure a reasonable working environment in the pool area, to keep the

demineralizer at an operable temperature, and to maintain visual clarity of the air above the

pool; however, operation at temperatures up to 140 OF is acceptable to remove decay heat from

the spent fuel. The fuel pool cooling and cleanup system consists of circulating pumps, heat

exchangers, filter/demineralizers, piping, valves, and instrumentation. The pumps take suction

from the skimmer surge tank, located at the top of the spent fuel storage pool water level, which

continuously skims the water from the surface and circulates the water to the heat exchangers

and filter/demineralizers before discharging the water through the diffusers at the bottom of the

spent fuel pool. This arrangement of taking suction from the top and discharging to the-bottom

of the pool provides a crossflow which tends to sweep the pool and to carry off dirt and small

particles. This system may also be used to drain the steam-separator storage pool and the

reactor well after refueling.

The failure of NSR SSCs in the FPC system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-10, the applicant identified the following FPC system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

" heat exchangers

* manifolds

* piping and fittings

" pump casings

* tanks

* thermowells

• valve bodies

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

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had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

In reviewing LRA Section 2.3.3.10, the staff identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.10-1, dated September 16, 2005, the staff noted that LRA Section 2.3.3.10 states

that components in the FPC system are NSR and that their failure could affect the capability of

SR SSCs to perform their safety function; therefore, they are within the scope of license

renewal, in accordance with 10 CFR 54.4(a)(2}. License renewal drawing LR-36256, Note 2,

also states that the spent fuel pool liner is within the scope of license renewal as part of the

reactor building structure. This spent fuel pool liner interfaces with the weirs and their

associated connecting surface, FPC system, and fuel pool drains. License renewal drawing

LR-36256 at location D-2 shows the adjustable weir and associated connecting surfaces to the

south skimmer surge tank, T-48B, to be within the scope of license renewal. License renewal

drawing LR-36256 at location D-4 shows similar components, the adjustable weir and

connecting surfaces to the north skimmer surge tank, T-48A, as not within the scope of license

renewal. Therefore, the staff requested that the applicant clarify whether the adjustable weir

and associated connecting surfaces to the north skimmer surge tank, T-48A, at location D-4 are

within the scope of license renewal and subject to an AMR, in accordance with the applicable

requirements of 10 CFR 54.4(a) and 10 CFR 54.21 (a), respectively, or justify their exclusion.

In its response, by letter dated October 14, 2005, the applicant stated that only those portions

of skimmer surge tanks T-48A and T-48B not embedded in concrete are within the scope of

license renewal. The adjustable weir is an NSR component located inside the concrete wall

adjacent to the spent fuel pool. Its failure could not affect the intended function of SR SSCs.

The adjustable weir for the south skimmer surge tank T-48B was shown incorrectly as within

the scope of license renewal. In addition, the adjustable weir for the south skimmer surge tank

T-48B is not within the scope of license renewal; however, the connecting portion of skimmer

tank T-48A at location D-3 is within the scope of license renewal from the skimmer tank up to

the concrete wall.

Based on its review, the staff found the applicant's response to RAI 2.3.3.10-1 acceptable

because failure of the components embedded in concrete could not affect the intended function

of SR SSCs and therefore are outside the scope of license renewal. In addition, the applicant

added the connecting portion of skimmer tank T-48A from the skimmer tank up to the concrete

wall to the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.10-1

is resolved.

In RAI 2.3.3.10-2, dated September 16, 2005, the staff noted, as shown on license renewal

drawing LR-36256 at location D-4, that diffusers A and B serve as a distribution point for

returning cooling water for the FPC system to the fuel storage pool. Their failure could affect

the capability of SR SSCs to perform their safety function; therefore, the staff requested that

the applicant justify why these diffusers are not within the scope of license renewal.

In its response, by letter dated October 14, 2005, the applicant stated that the FPC system is

within the scope of license renewal only because it contains NSR components which must

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maintain sufficient integrity to prevent spray, leakage, or spatial interaction from affecting

intended functions of the SR SSCs adversely. The diffusers are located underwater (spent fuel

pool) and the failure of these NSR diffusers would not affect SR SSC intended functions. The

diffusers are, therefore, not within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.3.10-2 acceptable

because the diffusers are not FPC system components that could affect the capability of SR

SSCs to perform their safety function and, therefore, are not within the scope of license

renewal; therefore, the staff's concern described in RAI 2.3.3.10-2 is resolved.

In RAI 2.3.3.10-3, dated September 16, 2005, the staff determined that license renewal drawing

LR-36256 shows an unisolable pipe (FPW17B-3"-MR) between the fuel storage pool and the

skimmer surge tank, T-48B, as not within the scope of license renewal. All other piping and

components entering the skimmer tank within the same apparent area of the plant are shown

as within the scope of license renewal. Failure of this unisolable section of pipe could affect the

intended license renewal pressure boundary function for the skimmer tank; therefore, the staff

requested that the applicant justify why this pipe is not included within the scope of license

renewal.

In its response, by letter dated October 14, 2005, the applicant stated that only the connecting

portions of both of the skimmer surge tanks, T-48A and T-48B, not embedded in concrete are

within the scope of license renewal. Pipe FPW17B-3"-MR is located along side the spent fuel

pool and is embedded in concrete. It drains the wave suppression scupper into the portion of

the skimmer surge tank embedded in concrete. This NSR component could not impact the

intended function of SR SSCs and, therefore, is not within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.3.10-3 acceptable

because pipe FPW17B-3"-MR is embedded in concrete and the failure of this NSR component

could not impact the intended function of SR SSCs; therefore, the staff's concern described in

RAI 2.3.3.10-3 is resolved.

The staff's review of LRA Section 2.3.3.10 identified areas in which information provided in the

LRA needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.10-1

License renewal drawing LR-36256 at locations D-4 and D-2 does not clearly define the system

boundaries between the fuel storage pool and the FPC system and between the fuel storage

pool and the fuel pool drains and associated piping. The NRC Regional Inspection Team

performed an inspection to ensure that the license renewal scope boundaries for the above

cited systems satisfy the 10 CFR 54.4(a)(2) criterion.

The inspection team found that this item addresses the wave suppression scupper, which is

embedded in concrete. Detailed drawings for the reactor building and spent fuel pool provided

further definition. The applicant recently revised license renewal drawing LR-36256 as a result

of RAI 2.3.3.10-3 to better illustrate the wave suppression scupper drain piping. The inspectors

determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.

Therefore, the staff's concern described in Inspection Item 2.3.3.10-1 is resolved.

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Inspection Item 2.3.3.10-2

License renewal drawing LR-36256 at location B-3 shows the license renewal scope boundary

for the pipe FPW13-4"-HB terminating at a nonspecific location on the piping run (between the

pipe FPW13-6"-HB and the valve AO-4"-HB). The actual location of the license renewal scope

boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspection

to ensure that the license renewal scope boundary of this pipe satisfies the 10 CFR 54.4(a)(2)

criterion.

The inspection team confirmed that the license renewal boundary ends as the line enters the

985' pump room. There are no SR components within the 985' pump room. P&IDs do not

typically show walls and floors. The inspectors determined that the license renewal boundary

satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection

Item 2.3.3.10-2 is resolved.

2.3.3.10.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the FPC system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the FPC

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.11 Heating and Ventilation System

2.3.3.11.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.11, the applicant described the heating and ventilation (HTV) system. The

HTV system consists of the equipment required to affect and control the following space-air

processes-supply and exhaust, distribution and recirculation (where applicable), differential

and static pressure control, filtration, and cooling and heating. It also includes sampling and

fume hood exhausting and process tank venting. The applicant scoped the reactor building

isolation under the secondary containment system. The portion of the HTV system serving the

HPCI building and the RHR/CSP corner rooms is within the scope of license renewal; the

equipment is designed to provide cool air during normal operation and DBEs. General plant

heating is provided by a network of carbon steel pipes originating at the plant heating boiler and

extending throughout most of the plant to supply heated water and/or steam to various unit

heaters. Three notable locations not directly served are the drywell, offgas storage building, and

portions of the plant serviced by the EFT system.

The HTV system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the HTV system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the HTV system performs functions that support FP and EQ.

The intended functions within the scope of license renewal include the following:

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" provide filtration

* provide for heat transfer

0 provide a pressure-retaining boundary

In LRA Table 2.3.3-11, the applicant identified the following HTV system component types that

are within the scope of license renewal and subject to an AMR:

* chillers

* damper/housings

* ductwork

* fan/blower/housings

* fasteners/bolting

* filters/strainers

* gauges (flow, level, and sight) * heaters/coolers

a HVAC units

* instrumentation

* piping and fittings

* pump casings

* steam traps

* tanks

* -valve bodies

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and USAR Sections 5.3.4 and 10.3.1.3.2 using the

evaluation methodology described in SER Section 2.3. The staff conducted its review in

accordance with the guidance described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.11 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.11-1, dated September 15, 2005, the staff requested that the applicant clarify

whether all the associated components of "HVAC units," such as ductwork (equipment frames

and housing), filters (housing and supports), ventilation seals, cooling coils, and I&C, are within

the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1).

In its response, by letter dated October 14, 2005, the applicant stated the following:

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Certain components indicated on the LR boundary drawings for the HTV System

are in scope to license renewal in accordance with 10 CFR 54.4(a)(1). Certain air

conditioners and many of the unit heaters with their associated steam and/or hot

water supply lines are in scope to license renewal in accordance with

10 CFR 54.4(a)(2). In addition, certain air handling units and exhaust tans are in

scope to license renewal for the Fire Protection and Environmental Qualification

regulated events in accordance with 10 CFR 54.4(a)(3). Other components

within the HTV System are excluded from the scope of license renewal since

they do not perform any license renewal intended function(s).

Component groups such as ductwork, filters, instrumentation, etc, that are listed

in Table 2.3.3-11 include those associated with the HVAC units within scope for

license renewal in accordance with the scoping criteria listed above.

Based on its review, the staff found the applicant's response to RAI 2.3.3.11-1 acceptable

because all applicable associated components of "HVAC units" consisting of ductwork

(equipment frames and housing), filters (housing and supports), and instrumentation are within

the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in

accordance with 10 CFR 54.21 (a)(1); therefore, the staff's concern described in RAI 2.3.3.11-1

is resolved.

During the scoping inspection, the inspectors identified a 1-inch branch line from HS12-3"-JB to

V-RF-1 (including BH-323, ST-9027, and BH-328) that was outside the scope of license

renewal on license renewal drawing LR-36259-1. The applicant stated the line was contained

under the steel deck plating of the EDG room foyer, effectively isolated from the SR equipment

in the EDG room. However, the steam branch line entry point through the steel plating was not

a grouted or robust penetration. A break in the line under the deck plating could cause heating

steam to enter the EDG room, potentially challenging the room ambient temperature to stay

within the maximum allowable temperature for EDG operability. The applicant placed this

portion of piping, along with the two valves and the steam trap, within the scope of license

renewal, pursuant to 10 CFR 54.4(a)(2).

The inspectors also noted heating steamline HS5-6"-JB from valve BH-316-1 through BH-722

on license renewal drawing LR-36664 as outside the scope of license renewal. The inspectors

identified a seismic Class I support, SR-389, about 6 feet from BH-316-1 in the section of pipe

outside the scope of license renewal. The applicant stated this portion of pipe was determined

to be outside the scope of license renewal because it contained air/gas. However, guidance

described in NEI 95-10 requires NSR piping attached to SR piping to be within scope up to and

including the first equivalent anchor. Seismic Class I support SR-389 is the first equivalent

anchor in this line. Therefore, the applicant placed the section of heating steamline HS5-6u-JB

between valve BH-316-1 and up to and including support SR-389 within the scope of license

renewal, pursuant to 10 CFR 54.4(a)(2).

2.3.3.11.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

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review, the staff concluded that the applicant adequately identified the HTV system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the HTV

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.12 Instrument and Service Air System

2.3.3.12.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.12, the applicant described the AIR system. The AIR system is designed

to provide the plant with a continuous supply of oil-free compressed air. The instrument air

portion of the system supplies dried compressed air for most of the pneumatic instruments and

controls in the plant. The service air portion of the system supplies undried service air to plant

components that do not require dry air and to hose stations throughout the plant for

miscellaneous use by maintenance and operations personnel. The AIR system includes three

nonlubricated air compressors that discharge to air receivers through aftercoolers with moisture

separator/traps. The AIR system is normally in continuous operation during normal plant

operation and shutdown. In addition to the AIR system, the plant includes other pneumatic

systems. The other pneumatic systems comprise an outboard main steam isolation valve air

supply which is part of the MST system, an AN2 system which is a separate mechanical

system, an instrument nitrogen supply to containment which is part of the primary containment

mechanical system, and the control room breathing air system which is part of the EFT system.

The AN2 system interfaces with the AIR system through a check valve, with the nitrogen side

held at a slightly lower pressure to allow the AIR system to be used during normal operation. In

the event of an accident, which also disables the AIR system, the AN2 system would

automatically pick up the required pneumatic loads.

The AIR system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the AIR system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the AIR system performs functions that support EQ.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-12, the applicant identified the following AIR system component types that

are within the scope of license renewal and subject to an AMR:

" fasteners/bolting

* gauges (flow, level, and sight)

* piping and fittings

* pump casings

" tanks

" valve bodies

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.12 identified an area in which information provided in

the LRA needed to be verified by ihe NRC Regional Inspection Team to complete the review of

the applicant's scoping and screening results.

Inspection Item 2.3.3.12-1

License renewal drawing LR-36049-1 0 at locations D-6 and B-6 have line continuations (air

lines upstream of valves AI-704 and AI-715) outside the scope of license renewal to

LR-36049-12 at location B-6. The actual locations of the license renewal scope boundaries of

these components are not clear. The NRC Regional Inspection Team performed an inspection

to ensure that the license renewal scope boundaries of these components satisfy the

10 CFR 54.4(a)(2) criterion.

License renewal drawing LR-36049-1 0 shows stainless steel instrument air lines at locations

D-6 and B-6 (air lines upstream of valves AI-704 and AI-715). These lines continue to

LR-36049-12 at location B-6 where they join via a "T" to form one line and then continue to the

vertical header shown on the drawing. Between the "T' joining these lines and the connection to

the main vertical header, the line transitions from stainless steel to copper. This transition is the

license renewal scoping boundary. The applicant will revise license renewal drawing

LR-36049-12 to show the continuation text to license renewal drawing LR-36049-1 0 and the

piping up to the stainless steel/copper transition point (located between the "T' and the vertical

header) as being within the scope of license renewal. In addition, license renewal drawing

LR-36049-10 at locations D-6 and B-6 will be revised to show the continuation to license

renewal drawing LR-36049-12 as being within the scope of license renewal. The inspectors

determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.

Therefore, the staff's concern described in Inspection Item 2.3.3.12-1 is resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the AIR system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant adequately identified the AIR system components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

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2.3.3.13 Radwaste Solid and Liquid System

2.3.3.13.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.13, the applicant described the radwaste solid and liquid (RAD) system.

The RAD system contains the solid radwaste subsystem and the liquid radwaste subsystem.

The solid radwaste system is designed to process, package, store, monitor, and-provide

shielded storage facilities for solid radioactive wastes to allow for radioactive decay and/or

temporary storage before shipment for offsite disposal. The liquid radwaste subsystem is

designed to collect, process, and dispose of all radioactive liquid wastes generated during

operation of the plant. The system is designed to accommodate the radioactive input resulting

from the design-basis maximum fuel leakage condition. Either filtration or filtration followed by

mixed deep-bed demineralization is used to remove the radioactive and chemical contaminants

from the liquid waste streams. The filters remove insoluble particulate contaminants and the

demineralizer is used to remove soluble materials. The filter and demineralizer sludge are

backwashed into receiving tanks; dewatered, and packaged as solid waste for disposal off site

at NRC-approved sites.

The RAD system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RAD system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RAD system performs functions that support EQ.

The intended functions within the scope of license renewal include the following:

* provide flow restriction

* provide a pressure-retaining boundary

* provide structural support to NSR components (mechanical)

In LRA Table 2.3.3-13, the applicant identified the following RAD system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* heat exchangers

* piping and fittings

* pump casings

* restricting orifices

* tanks

" valve bodies

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

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delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.13 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

In RAI 2.3.3.13-1, dated September 16, 2005, the staff noted that the following cases represent

unisolable piping defined as outside the scope of license renewal; however, the piping is

attached or interfaces with components defined as within the scope of license renewal that

perform a pressure-boundary function. Failure of these components outside the scope of

license renewal could adversely impact the intended pressure-boundary function of components

within the scope of license renewal; therefore, the staff requested that the applicant justify the

exclusion of the following unisolable components from the scope of license renewal:

0 License renewal drawing LR-36043 at location C-6 shows a 3-inch vent line on the top

of machine shop drain tank T-103.

* License renewal drawing LR-36043 at location C-6 shows a 4-inch vent line on the top

of reactor building floor drain sump S-37.

License renewal drawing LR-36043 at location C-6 shows line RWN46-4'-MR entering

the reactor building floor drain sump S-37 from the equipment drain sump S-42

overflow.

License renewal drawing LR-36043 at location C-3 shows a 4-inch vent line on the top

of drywell floor drain sump S-38.

License renewal drawing LR-36044 at location C-2 shows a 4-inch vent line on the top

of drywell equipment drain sump S-43.

License renewal drawing LR-36044 at location. C-2 shows a 4-inch vent line on the top

of drywell equipment drain sump S-43.

License renewal drawing LR-36044 at location A-3 shows a 4-inch vent line on the top of

turbine building normal waste sump S-45.

License renewal drawing LR-36044 at location C-5 shows piping to an obsolete sensing

line on the top of reactor building equipment drain tank T-56.

License renewal drawing LR-36044 at location A-5 shows a 4-inch vent line and piping

to an obsolete sensing line on the top of the condensate drip tank T-22.

License renewal drawing LR-36044 at location A-7 shows 4-inch vent line and

RWN48-4"-MR exiting the turbine building equipment drain sump S-44.

License renewal drawing LR-36044 at location C-7 shows 4-inch vent line and

RWN46-4"-MR exiting the reactor building equipment drain sump S-42.

In its response, by letter dated October 14, 2005, the applicant stated that the vent lines for the

drain tanks, floor drain sumps, equipment drain tanks, normal waste sumps, drip tanks, and

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equipment drain sumps are NSR, open to the atmosphere, and not relied upon for a pressure boundary. Their failure would not adversely affect the intended function of SR SSCs.

Piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete and act as overflows

between sumps. This piping is NSR and its failure could not impact the intended function of SR

SSCs. The sensing lines located on top of the tanks for level indication are filled with air. These

sensing lines are NSR and their failure could not impact the intended function of SR SSCs.

Based on its review, the staff found the applicant's response to RAI 2.3.3.13-1 acceptable

because (1) the vent lines are open to the atmosphere and not relied upon for a pressure

boundary, (2) piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete, and (3) the

sensing lines located on top of the tanks for level indication are filled with air. The vent lines,

piping RWN46-4"-MR and RWN48-4"-MR, and sensing lines are all NSR. Their failure could not

impact the intended function of SR SSCs and, thus, are not within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.3.13-1 is resolved.

In RAI 2.3.3.13-2, dated September 16, 2005, the staff determined that license renewal drawing

LR-36044 at location D-7 identified a 10 CFR 54.4(a)(2) boundary for the RAD system as the

section of piping before a normally open isolation valve, CRW-1, which is outside the scope of

license renewal, from the CST overflow tank T-67. Failure of the unisolable piping could

adversely impact the license renewal pressure-boundary function for the radwaste solid and

liquid system; therefore, the staff requested that the applicant justify the location of the license

renewal scope boundary at valve CRW-1, in accordance with the requirements of

10 CFR 54.4(a).

In its response, by letter dated October 14, 2005, the applicant stated that NSR valve CRW-1 is

located outside the reactor building near the CST tanks. The piping connecting to valve CRW-1,

which is shown within the scope of license renewal, is located inside the HPCI building, which

houses SR components. Failure of this connecting piping could impact the intended function of

SR SSCs. Failure of valve CRW-1 located outside the building could not impact the intended

function of SR SSCs; therefore, valve CRW-1 and the connecting piping to the CST overflow

tank T-67 are not within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.3.13-2 acceptable

because CRW-1 and the connecting piping are located outside the building and could not

impact the intended function of SR SSCs, and as such, are not within the scope of license

renewal. Therefore, the staff's concern described in RAI 2.3.3.13-2 is resolved.

In RAI 2.3.3.13-3, dated September 16, 2005, the staff noted that license renewal drawings

LR-36044 at locations A-7, C-7, C-3, and A-3 and LR-36043 at locations A-6, A-5, C-6, and C-3

show the turbine building equipment drain sump (S-44), reactor building equipment drain sump

(S-42), drywell equipment drain sump (S-43), turbine building normal waste sump (S-45),

condensate pump area sump (S-53), turbine building floor drain sump (S-40), reactor floor drain

sump (S-37), and drywell floor drain sump (S-38) as not within the scope of license renewal.

LRA Section 2.3.3.13 states that all radwaste solid and liquid system components in either the

turbine or reactor buildings, and constituting a liquid pressure boundary, are within the scope of

license renewal. Failure of the liners for these sumps can negatively impact the intended liquid

pressure-boundary functions of the components; therefore, the staff requested that the

applicant clarify whether the sumps and their associated liners are within the scope of license

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renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and

10 CFR 54.21 (a), respectively, or justify their exclusion.

In its response, by letter dated October 14, 2005, the applicant stated that the nonlined sumps

are NSR, embedded in concrete, and at the lowest elevations of the turbine and reactor

buildings. Their failure could not impact the intended function of SR SSCs and they are not

within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.3.13-3 acceptable

because the nonlined sumps embedded in concrete are NSR, located at the lowest elevations

of the turbine and reactor buildings, and their failure could not impact the intended function of

SR SSCs. As such, they are not within the-scope of license renewal; therefore, the staff's

concern described in RAI 2.3.3.13-3 is resolved.

The staff's review of LRA Section 2.3.3.13 identified areas in which information provided in the

LRA needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.13-1

License renewal drawing LR-36043 shows a 1.5-inch line at location B-1 within the scope of

license renewal for the RAD system. The drawing specifies the line continues at location E-3,

but license renewal drawing LR-36043 has no location E-3. Consequently, the actual location of

the license renewal scope boundary for this line is not clear. The NRC Regional Inspection

Team performed an inspection to ensure that the license renewal scope boundary for this line

satisfies the 10 CFR 54.4(a)(2) criterion.

The applicant determined license renewal drawing LR-36043 requires revision to change the

continuation of this line from coordinates E-3 to D-4. The NRC Regional Inspection Team

verified the accuracy of the corresponding plant P&ID (M-137) as currently drawn. The

inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2)

criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-1 is resolved.

Inspection Item 2.3.3.13-2

License renewal drawing LR-36043 shows piping RWN12-4"-HC at location C-4 as within the

scope of license renewal continuing to an undefined location. The actual location of the license

renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Team

performed an inspection to ensure that the license renewal scope boundary for this pipe

satisfies the 10 CFR 54.4(a)(2) criterion.

The applicant will revise license renewal drawing LR-36043 to show the continuation of the

drainline, RWN12-4"-HC, to license renewal drawing LR-36044, reactor building equipment

drain sump, S-42. The applicant will revise license renewal drawing LR-36044 to show the

drains from the reactor building floor drain tank, T-55, as one of the lines discharging into the

reactor building equipment drain sump, S-42. The drainline is within the scope of license

renewal, pursuant to 10 CFR 54.4(a)(2). The inspectors determined that the license renewal

boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in

Inspection Item 2.3.3.13-2 is resolved.

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Inspection Item 2.3.3.13-3

License renewal drawing LR-36044 at location B-1 shows the boundary for license renewal

terminating at the unisolable junction of piping from the EDG room 11 floor drain to the flow

controller just downstream of check valve NW-7. Failure of the unisolable piping can adversely

impact the license renewal pressure-boundary function for the RAD system. The NRC Regional

Inspection Team performed an inspection to ensure that the license renewal scope boundary

for this component satisfies the 10 CFR 54.4(a)(2) criterion.

The inspection team determined that valves NW-7, 8, and 9 are FP-related, with each pipe

connection buried in concrete, although not shown on the drawing. The buried pipe acts as the'

anchor, therefore the boundary terminates at that point. The inspectors determined that the

license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's

concern described in Inspection Item 2.3.3.13-3 is resolved.

Inspection Item 2.3.3.13-4

License renewal drawing LR-36045 shows several lines entering the drawing from other sheets,

RWN20-4"-HC (at location D-8), RWN5-3"-HC (at location D-8), RWN36-3"-HC (at

location D-8), FPW1 3-4"-HP (at location B-8), TW37-4"-HC (at location B-8), SC1 5-3"-HB (at

location D-7), and SC25-3"-HB (at location C-5) as within the scope of license renewal;

however, for each of these lines, the boundary terminates at a nonspecific location on license

renewal drawing LR-36045. The NRC Regional Inspection Team performed an inspection to

ensure that the license renewal scope boundaries for the cited components satisfy the

10 CFR 54.4(a)(2) criterion.

During walkdowns, the inspection team verified that the NSR piping enters the radwaste

building or the 985' pump room and is, therefore, not within the scope of license renewal. There

are no SR components in the radwaste building or the 985' pump room, and P&IDs do not

typically depict walls. The applicant will revise license renewal drawing LR-36045 to change line

numbers RWN20-4"-HC (at location D-8), RWN5-3".-HC (at location D-8), FPW1 3-4"-HP (at

location B-8), SC1 5-3"-HB (at location D-7), and SC25-2"-HB (at location C-5) from within the

scope of license renewal to outside the scope of license renewal. The continuation drawings

already show the transition into the radwaste building or the 985' pump room.

The applicant will revise license renewal drawing LR-36044 to extend the wall at location B-1 to

encompass line RWN5-3"-HC and to show the transition into the 985' pump room at the wall.

The license renewal boundary ends as the piping enters the 985' pump room.

Line number TW37-4u-HC (at location B-8) on license renewal drawing LR-36045 has been

verified by walkdown and shows the transition to be where the line enters the radwaste building

wall. The applicant will revise license renewal drawing LR-36045 to change the portion of this

line to outside the scope of license renewal. The applicant will also revise license renewal

drawing LR-36247 (at location C-4) to show the transition of this line through the radwaste

building wall. The inspectors determined that the license renewal boundary satisfies the

10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection

Item 2.3.3.13-4 is resolved.

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Inspection Item 2.3.3.13-5

License renewal drawing LR-36046 shows several lines entering the drawing from other sheets,

turbine building floor sump drain (at location D-8), drywell and reactor building floor drain sump

(at location D-8), machine shop drain (at location B-8), laboratory drain (at location B-8),

laundry drain waste (at location B-4), and machine shop drain (at location B-4), as within the

scope of license renewal; however, for each of these lines, the license renewal scope boundary

terminates at a nonspecific location on license renewal drawing LR-36046. The NRC Regional

Inspection Team performed an inspection to ensure that the license renewal scope boundaries

for the cited components satisfy the 10 CFR 54.4(a)(2) criterion.

The inspection team determined that the boundaries end as the lines enter the radwaste

building wall (locations B-8-& D-8) or 985' pump room wall (location B-4). There are no SR

components in the radwaste building or the 985' pump room. P&IDs at MNGP do not typically

depict walls. The applicant will revise license renewal drawing LR-36046 (at location D-8) to

show lines RWN1 9-4"-HC and RWN8-3"-HC outside the scope of license renewal since the

scoping boundary ends as the pipes enter the wall, which is already shown on LR-36043 (at

location B-i). The inspectors determined that the license renewal boundary satisfies the

10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.3.13-5 is resolved.

Inspection Item 2.3.3.13-6

License renewal drawing LR-36241 at location D-7 shows a 1" line, V1 5-1 "-HB, within the scope

of license renewal exiting to license renewal drawing LR-36049-12 at location D-5. Continuation

of V1 5-1 "-HB is not shown on license renewal drawing LR-36049-12 at the location specified.

The NRC Regional InspectionTeam performed an inspection to ensure that the license renewal

scope boundary for this line satisfies the 10 CFR 54.4(a)(2) criterion.

The inspection team determined the continuation to license renewal drawing LR-36049-12,

shown on license renewal drawing LR-36241, is for the instrument air system and should be

shown as outside the scope of license renewal. The applicant will revise license renewal

drawing LR-36241 to change the continuation to license renewal drawing LR-36049-12 from

within scope to outside the scope of license renewal.

In addition, the applicant will revise license renewal drawing LR-36241 to show that line

V1 5-1 "-HB discharges to the drywell equipment drain sump, S- 43, on license renewal drawing

LR-36044. The applicant will also revise license renewal drawing LR-36044 to show the

"Reactor Head Vent" as one of the drains discharging into the drywell equipment drain sump,

S-43. The inspectors determined that the license renewal boundary satisfies the

10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.3.13-6 is resolved.

Inspection Item 2.3.3.13-7

Treated/processed and sampled liquid wastes collected in sumps and drain tanks in various

buildings may be returned to the CSTs via the appropriate waste sample pump (P-36A or

P-36B) and effluent transfer line C1 9-3"-HS. A portion of this line is shown as within the scope

of license renewal on the license renewal drawings LR-36039 at location A-3 and LR-36045 at

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location B-1; however, the license renewal scope boundaries terminate in the middle of the pipe

runs (at the junctions of lines C19-3"-HS and DW17-"3"-HS and Cl 9-3"-HS and SCl 6-10"-HB).

The actual locations of the license renewal scope boundaries for these components are not

clear. The NRC Regional Inspection Team performed an inspection to ensure that the license

renewal scope boundaries for these components satisfy the 10 CFR 54.4(a)(2) criterion.

The inspection team determined that this line is within the scope of license renewal, pursuant to

the 10 CFR 54.4(a)(2) criteria, as an equivalent anchor (buried piping). The in-scope boundary

begins where the pipe connects to line SC16-1 0"-HK on LR-36039 (at location B-4) and

extends to the radwaste building floor. There are no SR components in the radwaste building.

All P&IDs do not typically depict walls. The inspectors determined that the license renewal

boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in

Inspection Item 2.3.3.13-7 is resolved.

2.3.3.13.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RAD system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant adequately identified the RAD system components that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.14 Reactor Building Closed Cooling Water System

2.3.3.14.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.14, the applicant described the reactor building closed cooling

water (RBC) system. The RBC system is a treated water system designed to remove heat from

the reactor auxiliary systems' equipment. The RBC system consists of a closed cooling water

loop containing two pumps and three heat exchangers in parallel, and the associated piping,

valves, and instrumentation. The system temperature is maintained by heat rejection from the

RBC system heat exchangers to the service and seal water system. The RBC system is

monitored continuously for radioactivity by a process radiation monitor (PRM). An increase in

the radiation level would indicate leakage of contaminated water into the RBC system. Leakage

may also be indicated by a level change in the RBC system surge tank with no associated

reactor power change, equipment change, or makeup water addition. Any potential leakage

from the reactor auxiliary systems' equipment is to the RBC system closed loop where 'it is

confined or isolated.

The RBC system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RBC system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RBC system performs functions that support EQ.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

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In LRA Table 2.3.3-14, the applicant identified the following RBC system component types that

are within the scope of license renewal and subject to an AMR:

" fasteners/bolting

" flexible connections

* flow element

* gauges (flow, level, and sight) * heat exchangers

" manifolds

* piping and fittings

* pump casings

* tanks

" thermowells

" valve bodies

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.14.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs that

should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the RBC system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the RBC system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.15 Reactor Water Cleanup System

2.3.3.15.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.15, the applicant described the reactor water cleanup (RWC) system. The

RWC system is a filtering and ion exchange system that maintains water purity in the reactor

and recirculation lines during all modes of plant operation. This minimizes changes in the core

heat transfer characteristics by reducing the deposition of impurities on fuel surfaces by

reducing the amount of waterborne impurities in the reactor primary system. It also reduces

sources of beta and gamma radiation by removing corrosion products, fission products, and

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impurities in the reactor primary system. The RWC system provides for primary containment

isolation and is also isolated on initiation of the SLC system. The RWC system provides for

continuous purification of a portion of the REC system flow with a minimum of heat loss and

water loss from the cycle.

The RWC system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the RWC system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the RWC system performs functions that support EQ and ATWS.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-15, the applicant identified the following RWC system component types that

are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* flow element

* heat exchangers

* manifolds

* piping and fittings

* pump casings

* restricting orifices

* thermowells

* valve bodies

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.13 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.15-1, dated September 16, 2005, the staff noted that license renewal drawing

LR-36254 at location C-8 contained two references (line REW3-4" EBD from REC loop B and

line REW31-2"-ED from reactor vessel drain) to license renewal drawing LR-36243 at location

C-5; however, license renewal drawing LR-36243 only shows one reference (line REW31-2"-ED

which is also capped) to license renewal drawing LR-36254. Therefore, the staff requested that

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the applicant clarify this discrepancy and confirm which portions of the piping 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), respectively, or justify their exclusion.

In its response, by letter dated October 14, 2005, the applicant clarified the drawing annotations

showing the convergence of the two lines REW3-4"-EBD and REW31-2"-ED on license renewal

drawing LR-36243 grid location C-6. The extension of line REW3-4"-EBD is shown as a dashed

line on license renewal drawing LR-36243, instructing the reviewer to look at license renewal

drawing LR-36254 for the details on that pipe. The applicant confirmed that the drawings were

correct and that both lines 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), respectively.

Based on its review, the staff found the applicant's response to RAI 2.3.3.15-1 acceptable

because the applicant confirmed that the lines are within the scope of license renewal;

therefore, the staff's concern discussed in RAI 2.3.3.15-1 is resolved.

The staff's review of LRA Section 2.3.3.15 identified an area in which information in the LRA

needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.15-1

License renewal drawing LR-36254 at location B-8 shows two RWN36-3"-HC lines as within the

scope of license renewal. One continues to waste collector tank, T-24, shown in license renewal

drawing LR-36045, and one continues to waste surge tank, T-23, also shown in license renewal

drawing LR-36045; however, the license renewal scope boundaries for these lines terminate in

the middle of the pipe runs. The actual locations of the license renewal scope boundaries for

these lines are not clear. The NRC Regional Inspection Team performed an inspection to

ensure that the license renewal scope boundaries for these lines satisfy the 10 CFR 54.4(a)(2)

criterion.

The inspection team conducted walkdowns, which confirmed that the two RWN36-3"-HC lines

pass into the 985' pump room and the radwaste building. There are no SR components in the

985' pump room or the radwaste building. The applicant will revise license renewal drawing

LR-36045 to change the two RWN36-3"-HC lines (at location D-8) to outside the scope of

license renewal. The continuation license renewal drawing LR-36254 will show the transition

into the 985' pump room. The inspectors determined that the license renewal boundaries satisfy

the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.3.15-1 is resolved.

2.3.3.15.3 Conclusion

The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs that

should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant failed to identify any components

that should be subject to an AMR. No omissions were identified. On the basis of its review, the

staff concluded that the applicant adequately identified the RWC system components that are

within the scope of license renewal, .as required by 10 CFR 54.4(a), and the RWC system

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.16 Service and Seal Water System

2.3.3.16.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.16, the applicant described the service and seal water (SSW) system. The

.SSW system supplies screened and strained cooling water (raw water from the Mississippi

River) to various nonessential plant heat loads and services during all modes of operation. The

service water portion of the SSW system consists of three 50-percent capacity service water

pumps, an auto strainer, a bypass basket strainer and associated valves, piping, and

instrumentation. Normally two service water pumps are in operation and one service water

pump is in auto-standby; however, during cold winter months, only one service water pump is

required. The seal water portion of the SSW system provides filtered well water (service water

serves as backup to the well water) to the shaft seals for various pumps, including the service

water pumps, RSW pumps, and the CWT pumps. The seal water portion consists of two

pumps, two filters, and associated valves, piping, and instrumentation. The service water

pumps take suction from the pump suction bay in the intake structure and discharge to the

turbine building through the intake structure access tunnel. Service water is used to remove

heat from various heat exchangers and coolers located in the reactor building and turbine

building. The SSW system also supplies water to the sodium hypochlorite subsystem (part of

the CWT system) and the fire system jockey pump. Service water flow is returned to the river.

The SSW system is normally in service during plant operation and shutdown.

The failure of NSR SSCs in the SSW system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal. The SSW

system also performs functions that support FP.

The intended functions within the scope of license renewal include the following:

" provide flow restriction

" provide a pressure-retaining boundary

In LRA Table 2.3.3-16, the applicant identified the following SSW system component types that

are within the scope of license renewal and subject to an AMR:

* expansion joints

" fasteners/bolting

. filters/strainers

* gauges (flow, level, and sight)

4 heat exchangers

" manifolds

* piping and fittings

" pump casings

* restricting orifices

" thermowells

* valve bodies

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2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.16 identified an area in which information in the LRA

needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.3.16-1

License renewal drawing LR-36665 at location D-7 shows the line SW21-6"-JF, which continues

to the sodium hypochlorite system shown in license renewal drawing LR-36666, as within the

scope of license renewal with the license renewal scope boundary terminating in the middle of

the pipe run (downstream of the valve SW-10-6"-54); however, license renewal

drawing LR-36666 at location C-6 shows the continuation of the line SW21-6"-JF as within the

scope of license renewal and defines the boundary for license renewal at check valve SHC-26.

The actual location of the license renewal scope boundary for this pipe is not clear. The NRC

Regional Inspection Team performed an inspection to ensure that the license renewal scope

boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.

The inspection team confirmed through a walkdown that the line SW21-6"-JF passes through a

concrete ceiling in the intake structure, which acts as the scoping boundary. All P&IDs do not

typically depict ceilings. The inspectors determined that the license renewal boundary satisfies

the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.3.16-1 is resolved.

2.3.3.16.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the SSW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the SSW system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.17 Standby Liquid Control System

2.3.3.17.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.17, the applicant described the SLC system. The MNGP licensing basis

includes the SLC system as an ESF system. This section, as well as the related aging

management section, includes the SLC system for consistency with the SRP-LR and GALL

Report. The SLC system provides a means of inserting negative reactivity into the reactor core

by the injection of neutron-absorbing boron in the form of liquid sodium pentaborate. A key lock

switch that starts the SLC system pumps and opens the squib-operated valves provides control

of injection. The boron solution is capable of shutting down the reactor and providing a

sufficient shutdown margin to overcome void and temperature coefficients, as well as the

effects of xenon, assuming that none of the withdrawn control rods can be inserted. Service air

and demineralized water are provided to the SLC tank for mixing of the boron solution, as well

as instrument air to various instrumentation.

The SLC system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the SLC system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the SLC system performs functions that support ATWS.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-17, the applicant identified the following SLC system component types that

are within the scope of license renewal and subject to an AMR:

" accumulators

* fasteners/bolting

* manifolds

• piping and fittings

* pump casings

• tanks

* thermowells

• valve bodies

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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2.3.3.17.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the SLC system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SLC

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.18 Wells and Domestic Water System

2.3.3.18.1 Summary of Technical Information in the Application

In LRA Section 2.3.3.18, the applicant described the wells and domestic water (WDW) system.

The WDW system includes the domestic water, sanitary sewer, acid drain, storm drain, and

turbine building normal drain subsystems as described below. The domestic water subsystem

supplies well water to the demineralized water system, the service and seal water system, hot

and/or cold water to lavatories, the laundry, and showers throughout the plant's protected area.

The sanitary sewer subsystem removes wastewater from lavatories, showers, and sinks in the

protected area, site administration building, and warehouse No. 5. It carries the wastewater to

the city of Monticello sewage system. The acid drain subsystem removes water from such

things as the demineralized water system area drain and heating boiler blowdown, which is unfit

for direct discharge to the river. Drainage from these sources is carried to the discharge

retention basin where it is treated and monitored before release to the river. The storm drain

subsystem carries water from building roofs and normal surface drainage to the river. The

turbine building normal drain subsystem removes water from areas in the turbine building where

there is no potential for radioactive contamination and transports it to the river.

The failure of NSR SSCs in the WDW system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal. The WDW

system also performs functions that support FP.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.3-18, the applicant identified the following WDW system component types

that are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* piping and fittings

P pump casings

* valve bodies

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

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In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.18.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the WDW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the WDW system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4 Steam and Power Conversion System

In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversion

system that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the steam and power conversion system in the

following sections of the LRA:

* 2.3.4.1 condensate storage system

• 2.3.4.2 condensate and feedwater system

" 2.3.4.3 main condenser system

* 2.3.4.4 main steam system

* 2.3.4.5 turbine generator system

SER Section 2.3.4.1-2.3.4.5 present the staff's review findings regarding LRA

Sections 2.3.4.1-2.3.4.5, respectively.

2.3.4.1 Condensate Storage System

2.3.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.1, the applicant described the condensate storage (CST) system. The

condensate storage system provides a large storage capacity of reactor quality water. The

normal plant uses for condensate storage water include (1) hotwell makeup and reject, (2) CRD

supply, (3) fuel storage pool makeup, (4) demineralizer and radwaste processing, (5) filling the

refueling wells, (6) miscellaneous plant flushing and decontamination services, (7) pressurizing

RHR and CSP piping, and (8) normal suction supply for HPC and RCl systems. In addition to

the above, the condensate storage system provides storage for reclaimed water from the

radwaste system. The suppression pool is the SR source of water for HPCI.

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The condensate storage system contains SR components that are relied upon to remain

functional during and following DBEs. The failure of NSR SSCs in the condensate storage

system could potentially prevent the satisfactory accomplishment of an SR function of SSCs

within the scope of license renewal. In addition, the condensate storage system performs

functions that support EQ and SBO.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.4-1, the, applicant identified the following condensate storage system

component types that are within the scope of license renewal and subject to an AMR:

* fasteners/bolting

* filters/housings

" flow element

• gauges (flow, level, and sight)

* heat exchangers

" instrumentation

* manifolds

* piping and fittings

• pump casings

* restricting orifices

* thermowells

• valve bodies

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.1 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.4.1-1, dated September 16, 2005, the staff noted that the HPCI pump normally is

lined up to the CSTs and the suction is switched to the suppression pool when the level in either

CST falls to the TS low level or when a high water level is sensed in the suppression pool. LRA

Section 2.3.4.1 states that the portion of the condensate storage system within the scope of

license renewal consists of piping and valves which supply the fuel storage pool, HPCI, RCI,

RHR, CRD, condensate, FW, CSP, main condenser, and radwaste systems. In addition, the

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instrumentation associated with the automatic transfer from the CST to the suppression pool is

SR and the components are within the scope of license renewal, in accordance with

10 CFR 54.4(a)(1). LRA Table 2.3.4-1 shows that the intended function of all condensate

storage system component groups is "pressure boundary."

License renewal drawing LR-36039 shows the piping within the scope of license renewal,

associated with the SR level instrumentation for the north and south CSTs, at locations B-3 and

B-6. For each CST, the portion within the scope of license renewal includes the portion of the

CST connection piping C22-4"-HJ and C23-4"-HJ between the reactor building and the CSTlevel instruments. This license renewal drawing does not show the remaining portion of these

lines from the reactor building to the CST as within the scope of license renewal. Failure of the

piping outside the scope of license renewal would have the same effect as a pressure boundary

failure of the portion within the scope of license renewal. Therefore, the staff requested that the

applicant justify why it did not include the portion of lines C22-4"-HJ and C23-4"-HJ between the

reactor building and the CST within the scope of license renewal.

In its response, by letter dated October 14, 2005, the applicant stated the following:

Line segments C22-4"-HJ and C23-4"-HJ, shown on license renewal boundary

drawing LR-36039, include the level switches for the north and south condensate

storage tanks (CSTs). The level instrumentation is safety-related because of the

automatic transfer feature from the nonsafety-related condensate storage tanks

to the safety-related suppression pool.

Portions of the line segments connecting to lines C22-4"-HJ and C23-4"-HJ

located between the Reactor Building wall and just prior to valves CST-1 -1 and

CST-1-2 on LR drawing LR-36039 are buried and are in scope for license

renewal. The buried piping is in scope for the reason that it serves as an

equivalent anchor for the attached safety related piping. For the purposes of

clarification of LR drawing LR-36039, this in scope buried piping is now-included

in the highlighted segments for C22-4"-HJ/HK and C23-4"-HJ/HK.

The remaining line segments which include valves CST-1 -1 and CST-1 -2 and

continue to the CSTs between the Reactor Building and the CSTs are above

ground and outside the Reactor Building. This piping is considered non-safety

related and its failure would only cause the level instrumentation to fail in a safe

position by switching suction to the safety-related suppression pool. Therefore,

this portion of the CST piping is not in the scope of license renewal.

Based on its review, the staff found the applicant's response acceptable because it addresses

equivalent seismic restraint and identifies the portions of the system 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), respectively. The staff reviewed the applicant's use of underground piping as

a seismic restraint in SER Section 2.1.3.1.2. Therefore, the staff's concern described in

RAI 2.3.4.1 -1 is resolved.

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2.3.4.1.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CST system components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CST

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.2 Condensate and Feedwater System

2.3.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.2, the applicant described the condensate and feedwater (CFW) system.

The CFW system supplies condensate from the main condenser to the reactor vessel at an

elevated temperature and pressure. The CFW system includes the condensate demineralizer,

the reactor FW pump seal, and zinc injection passivation subsystems. Two motor-driven

condensate pumps pump condensate through the SJAE intercondensers and the steampacking exhauster. After leaving the steam-packing exhauster, condensate passes through the

full-flow condensate demineralizer subsystem to ensure a supply of high-purity water to the

reactor. Demineralizer effluent is then split into two parallel paths, each with three stages of

low-pressure FW heating, to the suction of the reactor FW pumps. The condensate

demineralizer subsystem consists of five demineralizer vessels operating in parallel and sized

for full-condensate flow at reactor-rated conditions. The demineralizer vessels are located in

shielded cells. Wastes from an exhausted unit are transferred to the RAD system for disposal.

The zinc injection passivation subsystem provides a zinc oxide suspension from a continuously

stirred supply tank, which is diluted with demineralized water, and fed to one of two zinc

injection pumps. The diluted suspension is continuously injected into the suction of the reactor

feed pump just downstream of the reactor feed pump suction valves. Small concentrations of

zinc in the reactor water result in a reduction in the amount of cobalt incorporated into the oxide

film established on stainless steel piping. This reduction in cobalt-60 incorporation provides

substantial reductions in dose rates, particularly in primary containment.

The CFW system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the CFW system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the CFW system performs functions that support SBO.

The intended functions within the scope of license renewal include the following:

• provide flow restriction

* provide a pressure-retaining boundary

In LRA Table 2.3.4-2, the applicant identified the following CFW system component types that

are within the scope of license renewal and subject to an AMR:

* expansion joints

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* fasteners/bolting

* filters/strainers

flow element

* gauges (flow, level, and sight)

* heat exchangers

* manifolds

• piping and fittings " pump casings * restricting orifices

" tanks

* thermowells

* valve bodies

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.2 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.4.2-1, dated September 16, 2005, the staff noted that LRA Table 2.3.4-2 identifies

"Pressure Boundary" as the intended function of all the heat exchangers within the scope of

license renewal in the CFW system. License renewal drawings LR-36034 and LR-36035 show

that the shells for FW heaters E-1 1A, E-11 B, E-12A, and E-12B are NSR and included within

the scope of license renewal, in accordance with the 10 CFR 54.4(a)(2) criterion; however,

several turbine and extraction steamlines connected to the heat exchanger shell pressure

boundary are not shown within the scope of license renewal. These lines include the following:

* lines E9-26"-HCD, E10-26"-HCD, E11-26"-HCD, and E12-26"-HCD for L.P. heater

E-1 1 A on LR-36034 (quadrant 84)

* lines E1-20"-HCD and E2-20"-HCD for L.I.P. heater E-12A on LR-36034 (quadrant B4)

* lines E13-26"-HCD, E14-26"-HCD, E15-26"-HCD, and E16-26"-HCD for L.P. heater

E-1 1 B on LR-36035 (quadrant B-6)

lines E2-20"-HCD and E4-20"-HCD for L.I.P. heater E-12B on LR-36035 (quadrant C-6)

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Therefore, the staff requested that the applicant justify why it did not include the turbine

generator system piping connected to the CFW system heaters within the scope of license

renewal, considering the component's intended function as defined in LRA Table 2.3.4-2 and

the scoping criterion specified in 10 CFR 54.4(a)(2).

In its response, by letter dated October 14, 2005, the applicant stated the following:

The shells for feedwater heaters E-1 1A, E-1 1 B, E-12A and E-12B are non-safety

related and are included within the scope of license renewal in accordance with

10 CFR 54.4(a)(2). These heaters are mounted in the 'neck' of the condenser

with only a portion of the heater protruding from the condenser. It is only the

ends of the feedwater heater shells which protrude outside of the condenser and

have the capability of impacting the intended function of safety-related SSCs due

to potential leakage or spray that are of concern. The turbine extraction steam

lines connected to these heat exchanger shells are located inside the condenser

and, therefore, do not pose a potential leak or spray hazard. The failure of these

non-safety related components could not impact safety-related SSCs per the

criteria specified in 10 CFR 54.4(a)(2) and, therefore, are not included in the

scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.4.2-1 acceptable

because the main condenser shell should preclude leakage or spray impacts on SR SSCs from

the failure of NSR extraction steamlines inside the main condenser; therefore, the staff's

concern described in RAI 2.3.4.2-1 is resolved.

In RAI 2.3.4.2-2, dated September 16, 2005, the staff noted that license renewal drawing

LR-36036 at locations C-5, C-6, D-5, and D-6 identifies the shells for FW heaters E-1 1A,

E-1 1 B, E-1 2A, and E-1 2B as NSR and within the scope of license renewal, in accordance with

the 10 CFR 54.4(a)(2) criteria; however, the drawing also shows a connecting steamline to

each heater shell as being outside the scope of license renewal with references to license

renewal drawings LR-36035 (C-5), LR-36035 (B-5), LR-36034 (B-4), and LR-36034 (C-4),

which could not be found on the indicated license renewal drawings. Therefore, the staff

requested that the applicant identify the correct drawings and locations for these references. In

addition, the staff requested that the applicant justify the determination that the steam piping

connected to the CFW system heaters is not within the scope of license renewal, considering

the component's intended function as defined in LRA Table 2.3.4-2 and the scoping criteria

specified in 10 CFR 54.4(a)(2).

In its response, by letter dated October 14, 2005, the applicant stated that, for the FW heaters,

license renewal drawings LR-36034 and LR-36035 show the extraction steam details and

license renewal drawing LR-36036 shows the condensate and FW details. The applicant stated

that the continuation between the drawings is shown only for information and refers to the

general area where the extraction steam piping connects to the heaters. Consistent with the

extraction steamline noted in RAI 2.3.4.2-1, the applicant stated that the turbine extraction

steamlines identified in RAI 2.3.4.2-2 are inside the condenser and pose no potential leak or

spray hazard. The applicant concluded that failure of these NSR extraction steamlines would

not impact SR SSCs pursuant to the 10 CFR 54.4(a)(2) criteria and, therefore, are not included

within the scope of license renewal.

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Based on its review, the staff found the applicant's response to RAI 2.3.4.2-2 acceptable,

because the main condenser shell should prevent leakage or spray impacts on SR SSCs from

the failure of NSR extraction steamlines inside the main condenser; therefore, the applicant

resolved the staff concern described in RAI 2.3.4.2-2.

The staff's review of LRA Section 2.3.4.2 identified areas in which information in the LRA

needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

Inspection Item 2.3.4.2-1

LRA Section 2.3.4.2 states that the portion of the CFW system within the scope of license

renewal consists of pumps, condensate demineralizers, heat exchangers, tanks, and

associated piping, valves, and instrumentation from the condensate pump suction to the FW

injection nozzles. LRA Table 2.3.4-2 identifies "Pressure Boundary" as the intended function for

all piping and fittings in the CFW system within the scope of license renewal. License renewal

drawing LR-36038-2 shows the CFW system piping associated with the condensate

demineralizer subsystem as NSR and included within the scope of license renewal, in

accordance with the 10 CFR 54.4(a)(2) criterion. Accordingly, license renewal drawing

LR-36038-2 at location A-6 identifies a portion of line CH5-3"-HC to the chemical waste tank as

within the scope of license renewal. Because the license renewal scope boundary for this line

terminates in the middle of the pipe run, the actual location of the license renewal scope

boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspection

to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2)

criterion.

The inspection team conducted a walkdown and confirmed that the license renewal boundary

ends as line CH5-30-HC enters the 985' pump room. There are no SR components in the 985'

pump room. All P&IDs do not typically show walls and floors. The inspectors determined that

the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's

concern described in Inspection Item 2.3.4.2-1 is resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CFW system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CFW system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.3 Main Condenser System

2.3.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.3, the applicant described the main condenser (CDR) system. The CDR

system provides a heat sink for the steam cycle, removes noncondensable gases, and serves

as a central collection point for system drains. The system is NSR, but is credited for post2-99
accident plateout and holdup of radioactive iodine in the LOCA and control rod drop

accident analyses conducted pursuant to USAR Sections 14.7.2.4.1 and 14.7.1.6, respectively.

Also included in the nonsafety affecting safety function is the automatic closure of mechanical

vacuum pump suction valves that isolate the condenser lines to the mechanical vacuum pump

on primary containment isolation system (PCIS) Division 1 logic, which includes detection of

high activity in the main steamlines. The CDR system consists principally of the CDR, which

condenses steam exhausted from the turbine and turbine bypass system (TGS system). The

CDR is a twin-shell, dual-pressure surface condenser. Each of the two low-pressure turbines

exhausts into a condenser shell. Condenser structural integrity is continuously demonstrated

during normal operation when the condenser is required to maintain vacuum. Following a DBA,

when the condenser is required to perform its intended function, the main steam isolation

valves will be closed and vacuum will be lost. The condenser will not be required to perform a

pressure-boundary function because atmospheric conditions will exist inside the condenser.

The failure of NSR SSCs in the CDR system could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal.

The intended functions within the scope of license renewal include the following:

* provide plateout and holdup of radioactive material

" provide a pressure-retaining boundary

In LRA Table 2.3.4-3, the applicant identified the following CDR system component types that

are within the scope of license renewal and subject to an AMR:

* condenser complex

0 expansion joints

0 fasteners/bolting

0 filters/strainers

* gauges (flow, level, and sight)

0 heat exchangers

* LP turbine hood

* piping and fittings

0 pump casings

* tanks

• thermowells

* valve bodies

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

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omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.3 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.4.3-1, dated September 16, 2005, the staff noted that on license renewal drawing

LR-36035-2 at location B-2, pipe section line number OG6-8"-HC at separator T-72 and

downstream piping are not within the scope of license renewal. All other piping and components

within the apparent plant area are within the scope of license renewal. Failure of this unisolable

section of pipe could affect the license renewal intended pressure-boundary function for the

CDR system; therefore, the staff requested that the applicant justify why it did not include these

sections of unisolable piping and components within the scope of license renewal.

In its response, by letter dated October 14, 2005, the applicant stated that pipe line number

OG6-8-HC at separator T-72 and the downstream piping have an internal environment of air.

The failure of these NSR components could not impact the intended function of SR SSCs and

therefore, are not included within the scope of license renewal. All other piping and components

within the plant area are within the scope of license renewal because they contain water and

have the ability to impact the intended function of SR SSCs because of the potential for leakage

or spray.

Based on its review, thestaff found the applicant's response to RAI 2.3.4.3-1 acceptable,

because pipe line number OG6-8-HC and the downstream piping have an internal environment

of air, which does not have the ability to impact the intended function of SR SSCs, and as such,

are not within the scope of license renewal; therefore, the staff's concern described in

RAI 2.3.4.3-1 is resolved.

In RAI 2.3.4.3-2, dated September 16, 2005, the staff noted that license renewal drawing

LR-54817-4 at location A-7 is not listed in LRA Section 2.3.4.3 as a license renewal drawing for

the CDR system; therefore, the staff requested that the applicant clarify why it did not include

LR-54817-4 in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system.

In its response, by letter dated October 14, 2005, the applicant stated that license renewal

drawing LR-54817-4 shows the flow diagram for the recombiner building. There are no CDR

components within the scope of license renewal inside the recombiner building. Consequently,

license renewal drawing LR-54817-4 is not included in LRA Section 2.3.4.3 as a license renewal

drawing for the CDR system.

Based on its review, the staff found the applicant's response to RAI 2.3.4.3-2 acceptable

because license renewal drawing LR-54817-4 shows no CDR components within the scope of

license renewal; therefore, the staff's concern described in RAI 2.3.4.3-2 is resolved.

The staff's review of LRA Section 2.3.4.3 identified areas in which information in the LRA

needed to be verified by the NRC Regional Inspection Team to complete the review of the

applicant's scoping and screening results.

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Inspection Item 2.3.4.3-1

The CDR system is NSR, but is credited for post-accident plateout and holdup of radioactive

iodine in the LOCA and control rod drop accident analyses, per USAR Sections 14.7.2.4.1 and

14.7.1.6, respectively. License renewal drawing LR-36035-2 at locations C-6 and B-6 has piping

outside the scope of license renewal with continuations to condenser E-1 B connection 29 on

license renewal drawing LR-36035 at location D-6. The portion of piping on LR-36035 is within

the scope of license renewal. Consequently, the actual locations of the license renewal

boundary for these pipes are not clear. The NRC Regional Inspection Team performed an

inspection to ensure that the license renewal scope boundary for these pipes satisfies the

10 CFR 54.4(a)(2) criterion.

Lines RV34-6"-HB and RV33-6"-HB connect to condenser E-1 B at connection 29 on LR-36035.

The intended function of the piping is not for post-accident plateout and holdup of radioactive

iodine, but for pressure boundary for NSR affecting SR components, as shown in LRA Table

2.3.4-3, "Main Condenser System." Lines RV34-6"-HB and RV33-6"-HB shown on LR-36035-2

are in the SJAE room. There are no SR components in the SJAE room and, therefore, this

piping is not required to be within the scope of license renewal.

Piping PS9-2"-ED, shown on LR-36035-2, is also in the SJAE room; however, this piping is a

HELB line and, therefore, is within the scope of license renewal. The boundary for the HELB

line ends at the valves, as stated in USAR Appendix I, Table 1.2-1, page 8.

The applicant will revise license renewal drawing LR-36035-2 to depict a wall that lines

RV34-6"-HB and RV33-6"-HB pass through into the SJAE room. The lines will be shown within

the scope of license renewal as they continue from license renewal drawing LR-36035 and

condenser E-1 B connection 29, and -outside the scope of license renewal after they pass

through the wall into the SJAE room. The inspectors determined that the license renewal

boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in

Inspection Item 2.3.4.3-1 is resolved.

Inspection Item 2.3.4.3-2

License renewal drawing LR-36035 at location A-8 has a piping continuation, pipe line number

CN-125-4"-EN1 C, from the recombiner, license renewal drawing LR-54817-4 at location A-7,

that is within the scope of license renewal. The continuation on license renewal drawing

LR-54817-4 at location A-7 is outside the scope of license renewal. Consequently, the actual

location of the license renewal boundary for this pipe is not clear. The NRC Regional Inspection

Team performed an inspection to ensure that the license renewal scope boundary for this pipe

satisfies the 10 CFR 54.4(a)(2) criterion.

The inspection team confirmed through walkdown that the license renewal boundary ends as

the line, CN-125-4"-EN1C, enters the recombiner building on license renewal drawing

LR-54817-4. There are no SR components in the recombiner building; therefore, license

renewal drawing LR-54817-4 does not depict any componentswithin the scope of license

renewal in that building.

The applicant will revise license renewal drawing LR-54817-4 (at location A-7) to show the

continuation of line CN-1 25-4"-EN1 C to license renewal drawing LR-36035 as being within the

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scope of license renewal, with the scoping boundary at the wall labeled turbine building. No

components shown to the right of the turbine building wall are within scope, as these are all in

the recombiner building. The inspectors determined that the license renewal boundary satisfies

the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection

Item 2.3.4.3-2 is resolved.

2.3.4.3.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the CDR system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the CDR system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.4 Main Steam System

2.3.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.4, the applicant described the main steam (MST) system. The MST

system transports steam produced in the reactor to the main turbine for the production of

electricity. This steam is supplied to the high-pressure section of the turbine. Steam leaving the

high-pressure turbine is divided, the bulk of it passing through moisture separators before its

admission to the low-pressure sections. A portion of the steam is extracted and is condensed

as it is cascaded through FW heaters en route to the CDR. Normally, the turbine uses all the

steam being generated by the reactor; however, automatic, pressure-controlled, bypass valves

are supplied, which can discharge excess steam directly to the condenser. The MST system

also supplies steam to the HPCI and RCI turbines. The MST system includes an inline flow

restrictor for each of the four main steamlines. These flow restrictors minimize water losses and

protect the fuel barrier before main steam isolation valve closure for steamline ruptures outside

of primary containment. Drains are provided to remove condensate from the steamlines. The

majority of the components for the MST system are located in the turbine building and reactor

building steam chase, with additional piping and valves located in the primary containment. The

majority of the system components are made of stainless steel and carbon steel, although

some cast austenitic stainless steel and copper alloy material is used.

The MST system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the MST system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the MST system performs functions that support FP and EQ.

The intended functions within the scope of license renewal include the following:

* provide filtration

" provide flow restriction

* provide a pressure-retaining boundary

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In LRA Table 2.3.4-4, the applicant identified the following MST system component types that

are within the scope of license renewal and subject to an AMR:

" fasteners/bolting

" filters/strainers

" flow element

* manifolds

* piping and fittings

* restricting orifices

* thermowells

* valve bodies

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

* had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.4.4-1, dated September 16, 2005, the staff noted that license renewal drawing

LR-36035-2 at locations D-7 and B-7 indicates that pipe line numbers D1 09-1 "-EF and

D 108-1 "-EF (steam supply lines to Air Ejectors E-2B and E-2A) are not within the scope of

license renewal. Table 2.3.4-4 states that piping, fittings, and valves are within the scope of

license renewal with intended pressure-boundary function. Failure of this section of pipe could

affect the license renewal intended pressure-boundary function for the MST system piping;

therefore, the staff requested that the applicant justify why it did not include these sections of

unisolable piping and components within the scope of license renewal.

In its response, by letter dated October 14, 2005, the applicant stated that lines D1 09-1 "-EF

and D 108-1 "-EF are inside the SJAE room. These 1-inch pipes are not considered high-energy

lines and there are no SR components inside the SJAE room whose intended function could be

impacted by this NSR piping; therefore, line numbers D1 09-1 "-EF and D1 08-1 "-EF are not

within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.4.4-1 acceptable

because NSR lines D1 09-1 "-EF and D 108-1 "-EF are inside the SJAE, are not considered

high-energy lines, and as such, are not within the scope of license renewal; therefore, the

staff's concern described in RAI 2.3.4.4-1 is resolved.

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2.3.4.4.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its.

review, the staff concludedthat the applicant adequately identified the MST system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the MST system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.5 Turbine Generator System

2.3.4.5.1 Summary of Technical Information in the Application

In LRA Section 2.3.4.5, the applicant described the turbine generator system. The turbine

generator system includes the turbine generator unit and the steam sealing, turbine lube oil,

hydrogen cooling, hydrogen seal oil, and stator cooling subsystems. The function of the turbine

is to convert the thermodynamic energy of the steam from the nuclear reactor into mechanical

energy that drives the generator. The generator in turn converts that energy to an electrical

output to the power grid. The'turbine consists of one single-flow, high-pressure section with two

double-flow, low-pressure sections of the non-reheat design on a single shaft. The generator

consists of three major parts-the rotor, stator, and exciter. The rotor is turned by the turbine

shaft and is the source of the moving magnetic field. The stator consists of windings which form

a conductive path for the current induced by the rotating magnetic field of the rotor. The exciter

is a separate and smaller generator driven by the turbine to provide power for the main

generator rotor magnetic field. The steam sealing subsystem prevents steam leakage past the

turbine shaft seals into the turbine building and limits air in-leakage to the turbine casings. The

turbine generator shaft is supported by 10 journal bearings. All bearing oil is supplied by the

turbine lube oil subsystem, which also provides high-pressure oil to the hydraulic turbine control

mechanisms. The hydrogen gas of the hydrogen cooling subsystem is contained within the

generator casing. The hydrogen cooling subsystem is designed to reduce the heat generated

from windage resistance and provide a good heat transfer medium for generator cooling. The

hydrogen seal oil subsystem supplies vacuum treated oil between the rotor shaft and the

generator end housing hydrogen seals to prevent hydrogen from escaping into the turbine

building. The stator cooling subsystem removes heat from the generator stator by circulating

low-conductivity water through the hollow metal bars forming the stator windings. The

subsystem also supplies cooling water to the generator exciter rectifier banks. The stator

cooling subsystem consists of a storage tank feeding two parallel pumps, two heat exchangers,

a filter, and connecting piping with the generator stator.

The failure of NSR SSCs in the turbine generator system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

The intended function, within the scope of license renewal, is to provide a pressure-retaining

boundary.

In LRA Table 2.3.4-5, the applicant identified the following turbine generator system component

types that are within the scope of license renewal and subject to an AMR:

2-105
" expansion joints * fasteners/bolting

* filters/housings

* filters/strainers

* gauges (flow, level and sight)

* heat exchangers

* manifolds

" piping and fittings

" pump casings

" restricting orifices

* steam traps

" tanks

* thermowells

* turbines

* valve bodies

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and the USAR using the evaluation methodology

described in SER Section 2.3. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.3.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.5 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.4.5-1, dated September 16, 2005, the staff noted that license renewal drawing

LR-36034 at location.B-4 shows a portion of the sensing line to PT-1217 attached to pipe

E2-20"-HCD as within the scope of license renewal; however, the remaining portion of the

sensing line and pressure transmitter is shown as outside the scope of license renewal. In

addition, license renewal drawing LR-36035 at location D-7 shows pressure transmitters

PT-1 222 and PT-1 223 and portions of the sensing lines to these transmitters as within the

scope of license renewal; however, the remaining portions of the sensing line to pipes

E3-20"-HCD and E16-26"-HCD are shown as outside the scope of license renewal. LRA

Section 2.3.4.5 states that the license renewal function for turbine generator piping and gauges

is to maintain a pressure boundary and that NSR structures and/or components of the turbine

generator system that could affect SR SSCs must maintain sufficient integrity so that the

intended function of the SR SSCs is not adversely affected. Failure of the sensing lines noted

above could affect the license renewal intended pressure-boundary function of this turbine

generator piping and have a negative impact on the SR SSCs; therefore, the staff requested

2-106
that the applicant justify why it did not include portions of the sensing lines and associated

pressure transmitters within the scope of license renewal.

In its response, by letter dated October 14, 2005, the applicant stated that the portion of the

sensing line to PT-1 217 attached to pipe E2-20"-HCD is inside the condenser and should not

have been shown as within the scope of license renewal. PT-1 222 and PT-1 223 and portions of

the sensing lines to these transmitters are within the scope of license renewal because they are

on the exterior of the condenser. The sensing lines inside the condenser to pipes E3-20"-HCD

and El 6-26"-HCD are not within the scope of license renewal. The failure of these NSR lines

could not impact the intended function of SR SSCs, and therefore, the applicant did not include

them within the scope of license renewal. During its review, the applicant found that it should

have shown the portions of the sensing lines from condenser penetration No. 60 to PT-1 216

and PT-1217 on the exterior of the condenser as within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.3.4.5-1 acceptable

because failure of those NSR portions of sensing lines within the condenser could not impact

the intended function of SR SSCs, and consequently, those portions are not within the scope of

license renewal; therefore, the staff's concern described in RAI 2.3.4.5-1 is resolved.

In RAI 2.3.4.5-2, dated September 16, 2005, the staff noted that LRA Section 2.3.4.5 states

that the license renewal function for turbine generator piping is to maintain a pressure boundary

and that NSR structures and/or components of the turbine generator system that could affect

SR SSCs must maintain sufficient integrity so that the intended function of the SR SSCs is not

adversely affected.

License renewal drawings LR-36034 at location B-4 and LR-36035 at locations B-6, B-7, and

C-7 show piping to LIP Heater 12-A&B and LP Heater 11-A & B (E9-26"-HCD, E10-26"-HCD,

El 1-26"-HCD, El 2-26"-HCD, El -20"-HCD, E2-20"-HCD, El 4-26"-HCD, El 3-26"-HCD,

E15-26"-HCD, E16-26"-HCD, E4-20"-HCD, E3-20"-HCD) as outside the scope of license

renewal; however, the sensing lines to pressure transmitters attached to these pipes are shown

as within the scope of license renewal. Failure of the cited pipes could affect the license

renewal intended function of pressure boundary for the turbine generator piping and have a

negative impact on the SR SSCs. Therefore, the staff requested that the applicant justify why it

did not include the above cited pipes within the scope of license renewal.

In its response, dated October 14, 2005, the applicant stated that portions of the sensing lines

to these transmitters are within the scope of license renewal because they are on the exterior of

the condenser and could impact the intended function of SR SSCs. The remaining portions of

the sensing lines and heater piping to which they are attached are located in the condenser and

are not within the scope of license renewal. The failure of this NSR piping could not impact the

intended function of SR SSCs. During its review, the applicant found that the portions of the

sensing lines from condenser penetration No. 25 to piping E4-20"-HCD and E3-20"-HCD on

license renewal drawing LR-36035 (at location C-7) and condenser penetration No. 31 to piping

El-20"-HCD and E2-20"-HCD should not have been shown within the scope of license renewal

because they are within the condenser.

Based on its review,' the staff found the applicant's response to RAI 2.3.4.5-2 acceptable,

because those portions of sensing lines within the condenser are not within the scope of license

2-107
renewal. The failure of these NSR lines could not impact the intended function of SR SSCs;

therefore, the staff's concern described in RAI 2.3.4.5-2 is resolved.

2.3.4.5.3 Conclusion

The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the turbine generator system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the turbine generator system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.4 Scoping and Screening Results: Containments, Structures, and Component

Supports

This section documents the staff's review of the applicant's scoping and screening results for

containments, structures, and component supports. Specifically, this section discusses the

following containments, structures, and component supports:

* cranes, heavy loads, rigging

0 diesel fuel oil transfer-house

0 emergency diesel generator building

0 emergency filtration train building

• fire protection barriers commodity group

• hangers and supports commodity group

* HPCI building

* intake structure

• •miscellaneous SBO yard structures

• offgas stack

• off gas storage and compressor building

• plant control and cable spreading structure

* primary containment

• radioactive waste building

• reactor building

• structures affecting safety

• turbine building

* underground duct bank

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must identify and list

passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To

verify that the applicant properly implemented its methodology, the staff focused its review on

the implementation results. This approach allowed the staff to confirm that there were no

omissions of containments, structures, and component supports components that meet the

scoping criteria and are subject to an AMR.

2-108
Staff Evaluation Methodoloqy. The staff performed its evaluation of the information in the LRA

in the same manner for all containments, structures, and component supports. The objective of

the review was to determine whether the applicant had identified the components and

supporting structures for a specific containment, structure, or component support, that

appeared to meet the scoping criteria specified in the Rule, as within the scope of license

renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's

screening results to verify that all long-lived, passive components were subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

Scoping. To perform its evaluation, the staff reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of license renewal. The staff reviewed relevant licensing-basis

documents, including the USAR, for each containment, structure, and component support to

determine whether the applicant had omitted components with intended functions delineated

under 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensingbasis documents to determine whether the LRA specified all intended functions delineated

under 10 CFR 54.4(a). If omissions were identified, the staff requested additional information to

resolve the discrepancies.

Screening. Once the staff completed its review of the scoping results, it evaluated the

applicant's screening results. For those containments, structures, and components supports

with intended functions, the staff sought to determine (1) if the functions are performed with

moving parts or a change in configuration or properties or (2) if they are subject to replacement

based on a qualified life or specified time period, as described in 10 CFR 54.21 (a)(1). For those

that did not meet either of these criteria, the staff sought to confirm that these containments,

structures, and components supports and components were subject to an AMR, as required by

10 CFR 54.21 (a)(1). If discrepancies were identified, the staff requested additional information

to resolve them.

2.4.1 Cranes, Heavy Loads, Rigging

2.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.1, the applicant described the cranes, heavy loads, and rigging system. The

cranes, heavy loads, and rigging system consists of the reactor building and turbine building

cranes, numerous hoists, lifting fixtures and devices, and other miscellaneous smaller cranes.

Included in this system are the reactor, components' handling equipment, such as the refueling

bridge, various tools, controls, lifting devices, and fixtures. The refueling rod block interlocks are

also included under the reactor manual control system.

The failure of NSR SSCs in the cranes, heavy loads, and rigging system could potentially

prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license

renewal.

The intended function, within the scope of license renewal, is to provide structural support to

NSR components (civil and structural).

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In LRA Table 2.4.1-1, the applicant identified the following cranes, heavy loads, and rigging

system component types that are within the scope of license renewal and subject to an AMR:

* aluminum in air/gas (fuel preparation machine aluminum frame)

* aluminum in treated water (fuel preparation machine aluminum frame)

* carbon steel, low-alloy steel in air/gas (reactor building crane rails, turbine building crane

rails, refueling platform rails)

* carbon steel, low-alloy steel in air/gas (reactor building crane, turbine building crane,

refueling platform, reactor vessel head lifting device, dryer and steam separator sling

lifting device, and hook box)

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordande with the requirements of 10 CFR 54.21 (a)(1).

2.4.1.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the cranes, heavy loads, and rigging system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the cranes, heavy loads, and rigging

system components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.2 Diesel Fuel Oil Transfer House

2.4.2. 1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant described the diesel fuel oil transfer house. The diesel fuel

oil transfer house, located north of the diesel generator building and west of the intake

structure, is a reinforced concrete building on a mat foundation that provides protective

enclosure to the SR diesel oil transfer pump and the diesel oil service pump.

The diesel fuel oil transfer house contains SR components that are relied upon to remain

functional during and following DBEs. The failure of NSR SSCs in the diesel fuel oil transfer

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house could potentially prevent the satisfactory accomplishment of an SR function of SSCs

within the scope of license renewal. In addition, the diesel fuel oil transfer house performs

functions that support FP.

The intended functions within the scope of license renewal include the following:

" provide flood protection barrier

" provide missile barrier

" provide structural support to NSR components (civil and structural)

" provide structural support to SR components (civil and structural)

" provide shelter/protection to SR components

In LRA Table 2.4.2-1, the applicant identified the following diesel fuel oil transfer house

component types that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

• carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (door)

" concrete in air/gas (foundation, walls, slabs)

" concrete in air/gas (foundation, walls, slabs, grout)

* concrete in atmosphere/weather (walls, slab)

* concrete in below grade (foundation, walls)

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.2 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4.2-1, dated September 28, 2005, the staff noted that two component groups, (1)

concrete in air/gas (foundation, walls, slabs) and (2) concrete in air/gas (foundation, walls,

slabs, grout), have identical intended functions in Tables 2.4.2-1, 2.4.3-1, 2.4.4-1, 2.4.7-1,

2.4.8-1, 2.4.11-1, 2.4.12-1, 2.4.14-1, 2.4.15-1, 2.4.16-1, and 2.4.17-1. Therefore, the staff

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requested that the applicant explain the need for the first component group since it appeared to

be contained in the second component group. The staff also noted that, in addition to those two

component groups, concrete in air/gas (walls, slabs) is listed in Tables 2.4.3-1, 2.4.4-1, 2.4.8-1,

2.4.12-1, and 2.4.17-1 as a component group with the same intended function for which the

staff requested a similar explanation.

In its response, by letter dated October 28, 2005, the applicant stated the following:

To explain the difference between component groups, first an explanation of how

Table 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the License

Renewal Application (LRA) were assembled by copying the component group

and intended functions for each 3.5.2-x Table line entry into the 2.4.x-1 Table.

This format was consistently used throughout the LRA. Many line entry

component group descriptions appear similar but there are subtle differences

that are evident upon review of the 3.5.2-x Table aging management

program (AMP), aging effects/mechanisms, material, etc.

For this specific question, Table 2.4.x-1 component groups, 'concrete in air/gas

(foundation, walls, slabs)' and 'concrete in air/gas (foundation, walls, slabs,

grout)' have different component group descriptions (one component group

includes grout and the other did not). Review of Table 3.5.2-x reveals that the

component group without grout is evaluated for the aging effect, 'cracking, loss

of bond, loss of material due to corrosion of embedded steel.' The mechanism of

corrosion of embedded steel is not applicable to grout but is applicable to

reinforced concrete.

For part two of this question, the Table 2.4.x-1 component groups, 'concrete in

air/gas (walls, slabs),' 'concrete in air/gas (foundation, walls, slabs),' and

'concrete in air/gas (foundation, walls, slabs, grout)' have different component

group descriptions. The same rationale discussed above is applicable here as

well.

Based on its review, the staff found the applicant's response to RAI 2.4.2-1 acceptable. The

applicant explained that (1) tables in Section 2.4 were copied from the component group and

intended function from tables in Section 3.5, (2) one component group includes grout and the

other does not, and (3) the mechanism of corrosion of embedded steel is applicable to

reinforced concrete but not to grout. Because of these minor differences, tables in Section 2.4

appear repetitious. Therefore, the staff's concern described in RAI 2.4.2-1 is resolved.

2.4.2.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether any SSCs

that should be within the scope of license renewal. No omissions were identified. In addition, the

staff performed a review to determine whether the applicant had failed to identify any

components that should be subject to an AMR. No omissions were identified. On the basis of its

review, the staff concluded that the applicant adequately identified the diesel fuel oil transfer

house components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and the diesel fuel oil transfer house components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.4.3 Emergency Diesel Generator Building

2.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.3, the applicant described the EDG building. The principal function of the

EDG building is to provide a safe enclosure and protection for the standby diesel generators

and portions of the power distribution systems enclosed therein. The building is primarily a

single-story structure of reinforced concrete construction. A partial second story extends over a

portion of the structure. The ground floor consists of a concrete slab which is independent of

the building structure and placed on compacted select fill. Exterior walls are of reinforced

concrete and support the lower roof and second story framing. The roof over the single-story

portion of the structure and over the penthouse consists of a thick, reinforced concrete slab

supported by structural steel framing. A north-south interior wall of reinforced concrete extends

the full height of the structure providing physical separation of the diesel generator systems.

The exterior and interior walls extend 6 feet below grade to form a continuous wall footing

supported on select fill. The standby diesel generators are located at grade and are supported

on a 3-foot thick reinforced concrete mat which is physically independent of the ground floor

slab and building structure.

The EDG building contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the EDG building could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the EDG building performs functions that support FP.

The intended functions within the scope of license renewal include the following:

~ provide rated fire barrier

~ provide flood protection barrier

~ provide missile barrier

~ provide structural support to NSR components (civil and structural)

* provide structural support to SR components (civil and structural)

~ provide shelter/protection to SR components

In LRA Table 2.4.3-1, the applicant identified the following EDG building component types that

are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (fire-rated doors)

" carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (doors, ventilation assemblies)

" concrete in air/gas (foundation, walls, slabs)

" concrete in air/gas (foundation, walls, slabs, grout)

" concrete in air/gas (walls, slabs)

" concrete in atmosphere/weather (walls, slab)

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0 concrete in below grade (foundation, walls)

* masonry walls in air/gas

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.3.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the -basis of its review, the staff concluded that the applicant adequately

identified the EDG building components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the EDG building components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.4.4 Emergency Filtration Train Building

2.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.4, the applicant described the EFT building. The function of the EFT building

is to provide safe enclosure and protection for the main components of the MCR air

conditioning system (including the EFT units for the MCR air conditioning system) and for other

SR equipment as necessary. The EFT building is an L-shaped reinforced concrete structure

supported by a mat foundation. The west section is supported by two reinforced concrete

caissons. The east section is three stories high, and the west section is two stories high.

The EFT building contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the EFT building could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the EFT building performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

" provide rated fire barrier

" provide flood protection barrier

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* provide missile barrier

* provide structural support to NSR components (civil and structural)

" provide structural support toSR components (civil and structural)

* provide shelter/protection to SR components

In LRA Table 2.4.4-1, the applicant identified the following EFT building component types that

are within the scope of license renewal and subject to an AMR:

• carbon steel, low-alloy steel in air/gas (fire-rated doors)

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

" concrete in air/gas (foundation, walls, slabs)

* concrete in air/gas (foundation, walls, slabs, grout)

" concrete in air/gas (walls, slabs)

" concrete in atmosphere/weather (walls, slab)

" concrete in below grade (foundation, walls)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (EFT control volume

seals)

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4.4-1, dated September 28, 2005, the staff noted that Table 2.4.4-1 lists two identical

component groups, "concrete in atmosphere/weather (walls, slab)," with identical intended

functions; therefore, the staff requested that the applicant explain the need to list the same

component group twice.

In its response, by letter dated October 28, 2005, the applicant stated the following:

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Due to page format/spacing limitations, Table 3.5.2-4 was unable to include all

the component information on the same page, and therefore it became

necessary to repeat the component group, intended functions, etc. on the

following page. Table 2.4.4-1 could have omitted this duplication but a decision

was made not to interfere with the process used to assemble the 2.4.x-1 Table.

Based on its review, the staff found the applicant's response to RAI 2.4.4-1 acceptable.

Although repetitious, the duplicate component groups have no effect on scoping or screening.

Therefore, the staff's concern described in RAI 2.4.4-1 is resolved

2.4.4.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the EFT building components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and the EFT building components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.4.5 Fire Protection Barriers Commodity Group

2.4.5.1 Summary of Technical Information in the Application

In LRA Section 2.4.5, the applicant described the FP barriers commodity group. The FP barriers

commodity group includes fire stop sealants, fireproofing, and metallics such as aluminum and

carbon steel credited in the FP evaluation report. Fire stop sealants, fireproofing, and metallics

can be used as FP barriers to stop the spread of fire to adjacent fire areas and can also be

used to encapsulate structural steel or other metallic and nonmetallic components located

within a fire area to protect them from the effects of a fire. Fire stop sealants, fireproofing,

metallics, and combinations thereof provide a fire resistance equivalent to the rating of the

primary fire barrier to prevent the spread of fire to adjacent areas. Fire stop sealants,

fireproofing, and metallics are used to close openings in ceilings, floors, and walls. These

openings may be for penetrating electrical (e.g., cables, cable trays, conduits) or mechanical

(e.g., pipes, instrument lines, ventilation ducts) components. Cable tray FP barriers are a type

of barrier that prevents the propagation of fire along the length of the cables. Ventilation duct

fire barrier housings, located between adjacent fire areas, are an integral part of the FP barrier

and therefore are included with the FP barriers. Fire doors, curbs, dikes, concrete, and masonry

block walls are evaluated as part of the structure where they are located. Fire and alarm (e.g.,

smoke detectors), and fire suppression (e.g., automatic sprinklers, automatic halon systems)

are evaluated in the FIR system. The diesel-driven fire pump is evaluated in both the FIR and

the ESW systems.

The FP barriers commodity group performs functions that support FP.

The intended function, within the scope of license renewal, is to provide a rated fire barrier.

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In LRA Table 2.4.5-1, the applicant identified the following FP barriers commodity group

component types that are within the scope of license renewal and subject to an AMR:

* aluminum in air/gas (cable tray cover)

* carbon steel, low-alloy steel in air/gas (access tunnel FP guard pipe, fire damper

housings)

* nonmetallic fireproofing in air/gas (cementitious fireproofing for coating structural steel

and miscellaneous components)

" nonmetallic fireproofing in air/gas (fibrous fire wraps, cementitious fireproofing (i.e.,

pyrocrete, etc.))

* nonmetallic fire proofing in air/gas (fibrous. fire wraps, cementitious fireproofing (i.e.,

pyrocrete, etc.), rigid board (i.e., gypsum board, etc.))

" nonmetallic fire stop sealants in air/gas (fire stop sealants for EDG building)

• nonmetallic fire stop sealants in air/gas (fire stop sealants for intake structure)

* nonmetallic fire stop sealants in air/gas (fire stop sealants for reactor building, EFT

building, plant control, and cable spreading structure)

nonmetallic fire stop sealants in air/gas (fire stop sealants for turbine building)

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that theý

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.5 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4.5-1, dated September 28, 2005, the staff noted that Table 2.4.5-1 lists three identical

component groups, "Non-metallic fire proofing in air/gas (...cementitious fireproofing, ... )," with

identical intended functions; therefore, the staff requested that the applicant explain the need to

list the same component group three times.

In its response, by letter dated October 28, 2005, the applicant stated the following:

To explain the difference between component groups, first an explanation of how

Table 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the LRA were

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assembled by copying the component group and intended functions for each

3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently used

throughout the LRA. Many line entry component group descriptions appear

similar but there are subtle differences that are evident upon review of the

3.5.2-x Table AMP, aging effects/mechanisms, material, etc.

Table 2.4.5-1 component groups, 'non-metallic fire proofing in air/gas

(cementitious fireproofing for coating structural steel and miscellaneous

components),' 'non-metallic fire proofing in air/gas (fibrous fire wraps,

cementitious fireproofing (i.e., pyrocrete, etc.)),' and 'non-metallic fire proofing in

air/gas (fibrous fire wraps, cementitious fireproofing (i.e., pyrocrete, etc.), rigid

board (i.e., gypsum board, etc.))' have different component group descriptions.

Review of Table 3.5.2-5 reveals that component groups were evaluated for aging

effects/mechanisms that were not applicable to all component groups.

Based on its review, the staff found the applicant's response to RAI 2.4.5-1 acceptable. The

applicant explained that (1) the component groups and intended functions in Section 2.4 tables

were copied from tables in Section 3.5 and (2) the aging effects/mechanisms listed in Table

3.5.2-5 were not applicable to all three components groups; therefore, the staff's concern

described in RAI 2.4.5-1 is resolved.

2.4.5.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the FP barriers commodity group components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the FP barriers commodity group components that

are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.6 Hangers and Supports Commodity Group

2.4.6.1 ,Summary of Technical Information in the Application

In LRA Section 2.4.6, the applicant described the hangers and supports commodity group. The

hangers and supports commodity group contains component and equipment supports, pipe

restraints, junction boxes, control panels, electrical raceways, and electrical conduit associated

with plant systems and equipment that are within the scope of license renewal or are located

within structures containing SR components. This commodity group includes the grout under

the baseplate and fasteners used with the support or equipment anchorage. Generally,

supports provide the connection between a system's equipment or component and a plant

structural member (e.g., wall, floor, ceiling, column, beam). They provide support for distributed

Joads (e.g., piping, tubing, HVAC ducting, conduit, cable trays) and localized loads (e.g.,

individual equipment). Specific types of equipment and components evaluated as part of this

commodity group include: (1) pipe supports/restraints-includes all items used to support

and/or restrain piping, (2) equipment supports-includes structural steel, fasteners (e.g., bolts,

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studs, nuts), and vibration mounts that secure equipment to structures, (3) HVAC duct

supports-includes structural steel and fasteners (e.g., bolts, studs, nuts) that support/attach

ventilation duct to structures, (4) raceways-generic component type that is designed

specifically for holding electrical wires and cables (e.g., cable trays, exposed and concealed

metallic conduit or wireways), and (5) electrical enclosures-generic component type that

contains electrical components (e.g., conduit, panels, boxes, cabinets, consoles, and bus

ducts).

The hangers and supports commodity group contains SR components that are relied upon to

remain functional during and following DBEs. The failure of NSR SSCs in the hangers and

supports commodity group could potentially prevent the satisfactory accomplishment of an SR

function of SSCs within the scope of license renewal. In addition, the hangers and supports

commodity group performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide structural support to NSR components (civil and structural)

" provide structural support to SR components (civil and structural)

In LRA Table 2.4.6-1, the applicant identified the following hangers and supports commodity

group component types that are within the scope of license renewal and subject to an AMR:

* aluminum in air/gas (electrical junction boxes)

" carbon steel, low-alloy steel in air/gas (anchorages of lighting fixtures and junction

boxes inside torus, includes support members, welds, bolted connections)

* carbon steel, low-alloy steel in air/gas (anchorages of racks, panels, cabinets, and

enclosures for electrical equipment and instrumentation; includes lighting fixtures,

junction boxes, racks, panels, and cabinets outside torus, includes support members,

welds, bolted connections, and support anchorage)

* carbon steel, low-alloy steel in air/gas (cable trays, conduit, tube track outside torus)

* carbon steel, low-alloy steel in air/gas (conduit, located inside torus)

* carbon steel, low-alloy steel in air/gas (lighting fixtures and junction boxes inside torus)

* carbon steel, low-alloy steel in air/gas (racks, panels, cabinets, lighting fixtures, junction

boxes outside torus)

carbon steel, low-alloy steel in air/gas (supports for American Society of Mechanical

Engineers (ASME) Class 1 piping and components including RPV stabilizers (i.e.,

constant and variable spring hangers, guides, stops, etc.))

carbon steel, low-alloy steel in air/gas (supports for ASME Class 1 piping and

components including RPV stabilizers, includes support members, welds, bolted

connections, and support anchorage)

carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping and

components (i.e., constant and variable spring hangers, guides, stops, etc.))

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" carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping and

components, includes support members, welds, bolted connections, and support

anchorage)

* carbon steel, low-alloy steel in air/gas (supports for ASME Class MC components,

includes torus seismic restraints, drywell male and female stabilizers, shield stabilizers,

torus columns, torus saddles, vent system supports, downcomer bracing, includes

support members, welds, bolted connections and anchorages)

* carbon steel, low-alloy steel in air/gas (supports for cable trays, conduit, HVAC ducts,

tube track, instrument tubing, and non-ASME piping outside torus, includes support

members, welds, bolted connections, and support anchorage)

a carbon steel, low-alloy steel in air/gas (supports for mechanical equipment such as the

EDG, HVAC components, pumps, fans, motors, turbines, etc., includes the splash

hoods for the ESW pumps and the gas bottle racks, includes support members, welds,

bolted connections, and support anchorage)

* carbon steel, low-alloy steel in air/gas (supports for non-ASME piping, conduit, and

components located inside the torus, includes support members, welds, bolted

connections)

* carbon steel, low-alloy steel in atmosphere/weather (conduit for miscellaneous SBO

yard structures, etc.)

" carbon steel, low-alloy steel in atmosphere/weather (supports for conduit for

miscellaneous SBO yard structures, etc., includes support members, welds, bolted

connections, and support anchorage)

* carbon steel, low-alloy steel in atmosphere/weather (supports for EFT tornado dampers

and other miscellaneous mechanical equipment, includes support members, welds,

bolted connections, and anchorage)

" carbon steel, low-alloy steel in atmosphere/weather (supports for non-ASME piping,

includes support members, welds, bolted connections, and support anchorage)

* carbon steel, low-alloy steel in below grade (conduit for miscellaneous SBO 'yard

structures, etc.)

* carbon steel, low-alloy steel in below grade (diesel fuel oil storage tank flood tie-downs)

" carbon steel, low-alloy steel embedded in concrete (drywell support skirt anchorage,

RPV.female stabilizers)

* carbon steel, low-alloy steel embedded in concrete (embedded conduit)

" carbon steel, low-alloy steel in treated water (supports for ASME Class MC components

(i.e., vent system supports, downcomer bracing) includes support members, welds)

" carbon steel, low-alloy steel in treated water (supports for non-ASME piping and

components (i.e., HPC, RCI sparger supports, SRV T-quencher support, ECCS suction

strainer supports, etc.) includes support members, welds, bolted connections)

* concrete in air/gas (anchorage of racks, panels, cabinets, enclosures for electrical

equipment and instrumentation, building concrete, grout pads)

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* concrete in air/gas (supports for ASME Class 1 piping and components, building

concrete, and grout pads)

* concrete in air/gas (supports for ASME Class 2 and 3 piping and components, building

concrete, grout pads)

* concrete in air/gas (supports for ASME Class MC components, building concrete, grout

pads)

" concrete in air/gas (supports for cable trays, conduit, HVAC ducts, tube track,

instrument tubing, non-ASME piping and components, building concrete, grout pads)

" concrete in air/gas (supports for EDG, HVAC system components, and other

miscellaneous mechanical equipment, building concrete, grout pads)

" concrete in atmosphere/weather (supports for conduit for miscellaneous SBO yard

structures, etc.; building concrete, grout pads)

* concrete in atmosphere/weather (supports for EFT tornado dampers and other

miscellaneous mechanical equipment, building concrete, grout pads)

" concrete in atmosphere/weather (supports for non-ASME piping and components,

building concrete, grout pads)

* concrete in below grade (diesel fuel oil storage tank deadmen)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (vibration isolation

elements for ASME Class 1 piping and components)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (vibration isolation

elements for ASME Class 2 and 3 piping and components)

" elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (vibration isolation

elements for ASME Class MC components)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (vibration isolation

elements for EDG, HVAC system components, and other miscellaneous mechanical

equipment)

" fiberglass in air/gas (electrical junction boxes)

" lubrite in air/gas (sliding surfaces for ASME Class 1 piping and components)

" lubrite in air/gas (sliding surfaces for ASME Class 2 and 3 piping and components)

" lubrite in air/gas (sliding surfaces for torus saddles)

* plastic in air/gas (electrical junction boxes)

" stainless steel in air/gas (supports for ASME Class 1 piping and components including

RPV stabilizers, clamps etc.)

* stainless steel in air/gas (supports for ASME Class 2 and 3 piping and components,

clamps, etc.)

" stainless steel in air/gas (supports for ASME Class MC components (i.e., vent header

column support pins))

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stainless steel in air/gas (supports for tube track, instrument tubing, non-ASME piping

and components; clamps, etc.)

stainless steel in treated water (supports for ASME Class MC components (i.e., vent

header column support pins))

2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.6 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.4.6-1, dated September 28, 2005, the staff noted that after the "System Function

Listing," the applicant referred to Sections 12.2.1.2 and 12.2.1.3 of the USAR for additional

hangers and supports commodity group details. The staff's review of the USAR sections

indicates that the SSCs are classified as Class I and Class II with definitions noticeably different

from Criteria 1, 2, and 3 in 10 CFR 54.4(a); therefore, the staff requested that the applicant

clarify how it reconciled the CLB classification in the system function listing in LRA

Section 2.4.6.

In its response, dated October 28, 2005, the applicant stated that LRA Section 2.1.4.2 and the

additional comment clarify how the CLB classification of SSCs was reconciled. LRA

Section 2.1.4.2 states the following:

Numerous sources, including the MNGP USAR, docketed correspondence with

the NRC, Maintenance Rule documents, and DBDs provided system and

structure-level function information. Documentation of references used in this

process was included for each system function as appropriate.

The process used at the MNGP identified all system-level and structure-level

functions. If the functions met any of the criteria specified in

10 CFR Part 54.4(a)(1), (2), or (3), then the system or structure was in-scope for

LR...

The applicant further stated that even though USAR Class I and II designations are significantly

different from 10 CFR 54.4 designations, SSCs were still within the scope of license renewal, in

accordance with the criteria in 10 CFR 54.4(a).

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Based on its review, the staff found the applicant's response to RAI 2.4.6-1 acceptable. With

the applicant's clarification, the staff recognized the methods used to reconcile SR SSCs and

found the applicant's method of compliance with the requirements of 10 CFR 50.54 acceptable;

therefore, the staff's concern described in RAI 2.4.6-1 is resolved.

In RAI 2.4.6-2, dated September 28, 2005, the staff noted that Table 2.4.6-1 line item "carbon

steel, low-alloy steel in air/gas," identifies a number of supports/anchorages as ASME Class MC

supports and some are identified as non-ASME support components; therefore, the staff

requested that the applicant clarify the classification of component supports inside and outside

the torus (some may be non-ASME) and specifically, the classification of the support system for

the torus. The staff assumed that the torus support system is classified as Class MC supports

and that all its components are inspected by the requirements of ASME Section Xl,

Subsection IWF. After reviewing. LRA Table 3.5.2-6, it was not obvious how the applicant had

treated these supports; therefore, the staff requested that the applicant provide clarifications.

In its response, by letter dated October 28, 2005, the applicant stated that the torus supports

include torus columns, torus saddles, and torus seismic restraints and pointed out that LRA

Table 3.5.2-6, page 3-675, indicates that these supports located on the outside of the torus are

classified as ASME Class MC and will be managed by the ASME Section Xl, Subsection IWF

Program. For the remaining torus system support components, the applicant provided an

abridged list extracted from Table 3.5.2-6 which provided classifications and locations of these

supports.

Based on its review, the staff found the applicant's response to RAI 2.4.6-2 acceptable. The

response asserted the staff's assumption that all torus supports on the outside of the torus are

classified as Class MC supports and are inspected in accordance with the requirements of

Section Xl, Subsection IWF, of the ASME code. The applicant also clarified that either the

Primary Containment In-Service Inspection Program (i.e., ASME Code Section XI,

Subsection IWE) or ASME Code Section XI, Subsection NF provides aging management of the

remaining supports. The staff considered the applicant's approach logical and acceptable;

therefore, the staff's concern described in RAI 2.6.4-2 is resolved.

In RAI 2.4.6-3, dated September 28, 2005, the staff noted that Table 2.4.6-1 lists "Carbon steel,

low-alloy steel in atmosphere/weather (bolted connections and anchorage)" as a component

group and "Carbon steel, low-alloy steel in atmosphere/weather (bolted connections And

support anchorage)" as another. The only difference between the two component groups is that

one group lists "anchorage" and the other "support anchorage." Therefore, the staff requested

that the applicant explain the difference between "anchorage" and "support anchorage" and

provide examples of each.

In its response, by letter dated October 28, 2005, the applicant explained that the line entry in

LRA Table 2.4.6-1 containing the word "anchorage" also could have included the word "support"

before "anchorage" in the description to be consistent with similar entries. The word,

"anchorage" alone, however, is sufficient to convey the intent. The applicant further explained

that "anchorage" and "support anchorage" refer to components used to secure (i.e., anchor) the

support to the concrete'surf ace and include concrete anchors of various types and associated

components like nuts and washers.

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Based on its review, the staff found the applicant's response to RAI 2.4.6-3 acceptable because

the applicant adequately explained that the two terms are defined the same and their intended

functions are the same. Therefore, the staff's concern described in RAI 2.4.6-3 is resolved.

2.4.6.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the hangers and supports commodity group components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the hangers and supports commodity

group components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.7 HPCI Building

2.4.7. 1 Summary of Technical Information in the Application

In LRA Section 2.4.7, the applicant described the HPCI building. The principal functions of the

HPCI building are to enclose the HPCI turbine and pumps and protect the equipment from

weather, tornado, and seismic effects. The building is a Class 1 structure and is part of the

secondary containment of the reactor building. The HPCI building is a reinforced concrete

structure constructed monolithically with the reactor building. The structure is supported by a

reinforced concrete mat which is an extension of the reactor building mat,

The HPCI building contains SR components that are relied upon to remain functional during

and following DBEs. The failure of NSR SSCs in the HPCI building could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the HPCI building performs functions that support SBO.

The intended functions within the scope of license renewal include the following:

" provide flood protection barrier

" provide missile barrier

" provide structural support to NSR components (civil and structural)

* provide pressure boundary of essentially leaktight barrier (civil and structural)

* provide shielding against radiation

" provide structural support to SR components (civil and structural)

* provide shelter/protection to SR components

In LRA Table 2.4.7-1, the applicant identified the following HPCI building component types that

are within the scope of license renewal and subject to an AMR:

* aluminum in air/gas (platforms)

" carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

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* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (roof hatch)

* carbon steel, low-alloy steel in below grade (piping penetration seal plates)

* concrete in air/gas (foundation, walls, slab)

* concrete in air/gas (foundation, walls, slab, grout)

" concrete in atmosphere/weather (slab, roof hatch)

* concrete in below grade (foundation, walls)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (roof hatch seals)

* elastomer sealants (rubber, neoprene, silicone, etc.) in atmosphere/weather (roof hatch

seals)

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA.and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21(a)(1).

2.4.7.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the HPCI building components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the HPCI building components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.4.8 Intake Structure

2.4.8. 1 Summary of Technical Information in the Application

In LRA Section 2.4.8, the applicant described the intake structure. The intake structure is

basically a chambered box of reinforced concrete construction. Essentially, the intake structure

consists of four 13-foot 8-inch bays with an invert at the intake end which converges to a two2-125
section suction chamber at the discharge end. A CWT pump is mounted over each suction

chamber. The roof of the structure is approximately 4 feet 3 inches above grade and consists of

reinforced concrete beam and slab framing. The intake structure contains an operating floor on

which the EDG-ESW, ESW, and RHR service water subsystem pumps are mounted. Exterior

and interior walls and slabs are constructed of reinforced concrete and provide support for the

operating floor and roof framing. The structure is supported on a mat foundation 3 feet 6 inches

in thickness that was placed on a lean concrete fill which overlays a layer of cemented

sandstone. The intake structure also includes the access tunnel between the turbine building

and the intake structure, as well as the diesel fire pump house which sits on top of the intake

structure at the east end. The diesel fire pump house contains the diesel fire pump and the

diesel fire pump day tank. The diesel fire pump house is constructed of concrete masonry block

walls with an insulated steel deck roof supported by structural steel beams.

The intake structure contains SR components that are relied upon to remain functional during

and following DBEs. The failure of NSR SSCs in the intake structure could potentially prevent

the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

In addition, the intake structure performs functions that support FP.

The intended functions within the scope of license renewal include the following:

* provide source of cooling water for plant shutdown

" provide rated fire barrier

" provide flood protection barrier

* provide missile barrier

" provide structural support to NSR components (civil and structural)

* provide structural support to SR components (civil and structural)

" provide shelter/protection to SR components

In LRA Table 2.4.8-1, the applicant identified the following intake structure component types

that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (doors, structural steel, steel embeds, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

carbon steel, low-alloy steel in atmosphere/weather (structural steel, sheet piles,

ventilation assemblies)

* carbon steel, low-alloy steel in below grade (sheet piles)

* carbon steel, low-alloy steel in raw water (structural steel, sheet piles)

" carbon steel, low-alloy steel in raw water (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

" concrete in air/gas (foundation, walls, slabs)

* concrete in air/gas (foundation, walls, slabs, grout)

* concrete in air/gas (walls, slabs)

" concrete in atmosphere/weather (intake structure and access tunnel roof slabs)

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* concrete in atmosphere/weather (walls, slabs)

* concrete in below grade (foundation, walls, lean concrete)

* concrete in raw water (foundation, walls, slabs)

* masonry walls in air/gas

* masonry walls in atmosphere/weather

2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.8.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the intake structure components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the intake structure components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

2.4.9 Miscellaneous SBO Yard Structures

2.4.9.1 Summary of Technical Information in the Application

In LRA Section 2.4.9, the applicant described the miscellaneous SBO yard structures. The

miscellaneous SBO yard structures are those yard structures that provide support for

equipment relied upon for recovery from an SBO. These structures are listed below:

• the foundations and transformer structures for 1 R, 2R, 1AR, and 2RS transformers

" the 345-kV control house

" the towers/foundation for the 1 N2, 1 N6, 5N5, 5N7, 8N4, and 8N1 1 breakers

* the towers/foundations for the bus bars between the 2RS transformer and the 8N4 and

8N1 1 breakers, this includes the tower/foundation for the 3N4 breaker, 3N5 fused

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disconnect, the current limiting protector, and the towers/foundations to the 1ARS

motor-operated disconnect

• the towers/foundations for the bus bars for the 5N5 and 5N7 breakers, including the

west four rows of columns and the beams that connect them together.

• the Trenwa trenches connecting the control house to the 11 5-kV ring bus

• the Trenwa trenches connecting the control house to the 345-kV ring bus

• the electrical duct bank from the 1 N2 breaker to the 1 AR transformer

• the tower/foundation for the bus 1, 115-kV potential transformer

* the three 115- kV transmission towers along the west owner-controlled area fence

between the switchyard and the 1 R transformer and the first transmission tower

northwest of the plant

• the block walls surrounding the 1 R and 2R transformers

The miscellaneous SBO yard structures perform functions that support SBO.

The intended function, within the scope of license renewal, is to provide structural support to

NSR components (civil and structural).

In LRA Table 2.4.9-1, the applicant identified the following miscellaneous SBO yard structures

component types that are within the scope of license renewal and subject to an AMR:

• carbon steel, low-alloy steel in air/gas (345-kV house structural steel)

• carbon steel, low-alloy steel in air/gas (supports for 345-kV house miscellaneous steel

(i.e., members, welds, bolted connections, support anchorage))

• carbon steel, low-alloy steel in atmosphere/weather (anchorages)

• carbon steel, low-alloy steel in atmosphere/weather (structural steel for 345-kV house,

switchyard, and transmission towers, etc.)

• concrete in air/gas (345-kV house concrete)

• concrete in atmosphere/weather (345-kV house concrete, foundations)

• concrete in atmosphere/weather (345-kV house, foundations, trenches, duct bank,

grout)

* concrete in below grade (345-kV house, foundations, trenches, duct bank)

• masonry walls in atmosphere/weather

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

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In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21(a)(1).

2.4.9.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the miscellaneous SBO yard structures components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the miscellaneous SBO yard structures

components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.10 Offgas Stack

2.4.10. 1 Summary of Technical Information in the Application

In LRA Section 2.4.10, the applicant described the offgas stack. The function of the offgas

stack is to provide for controlled release and dispersal of gaseous radioactive wastes. The

stack is a free-standing, tapered, reinforced concrete structure which encloses and supports an

independent gas flue. The overall height of the stack above adjacent grade is 328 feet. The

internal diameter of the concrete shell is 7 feet at the top and 32 feet at the 946-foot 6-inch

elevation, with thickness varying from 7 inches at the top to 10 inches at the 946-foot 6-inch

elevation. Below the 946-foot 6-inch elevation to the top of the foundation at the 932-foot 6-inch

elevation, the stack shell is a polygon having a maximum inscribed diameter of 34 feet. The wall

thickness varies in accordance with radiation shielding requirements. The stack shell is

supported on a 4-foot-thick octagonal spread footing with a 1-foot 6-inch pedestal. The

independent gas flue is 18 inches in diameter reducing to 14 inches in diameter at the top.

The offgas stack contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the offgas stack could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

The intended functions within the scope of license renewal include the following:

" provide flood protection barrier

" provide path for release of filtered and unfiltered gaseous discharge

* provide structural support to NSR components (civil and structural)

" provide shielding against radiation

* provide structural support to SR components (civil and structural)

* provide shelter/protection to SR components

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In LRA Table 2.4.10-1, the applicant identified the following offgas stack component types that

are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (doors)

* concrete in air/gas (pedestal, walls, slabs)

" concrete in air/gas (pedestal, walls,, ýlabs, grout)

* concrete in atmosphere/weather (pedestal, walls)

concrete in below grade (pedestal)

* masonry walls in air/gas

* stainless steel in air/gas (cap)

* stainless steel in atmosphere/weather (cap)

2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the" scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.10.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the offgas stack components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and the offgas stack components that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

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2.4.11 Offgas Storage and Compressor Building

2.4. 11.1 Summary of Technical Information in the Application

In LRA Section 2.4.11, the applicant described the offgas storage and compressor building. The

offgas storage building, except for the fan and foyer room portions, was designed for Class 1

seismic conditions and flood conditions, as well as for tornado wind loads and missiles. The

only portion of the offgas storage system which currently has seismic design requirements are

the storage tanks and the attached piping up to the first isolation valve. The building meets all

Federal, State, and local codes applicable to industrial process buildings. The building is

constructed of reinforced concrete on a suitable foundation and is situated near the base of the

offgas stack. The fan and foyer room portions of the offgas storage building provide Class 1-

level protection for all external events in which the enclosed equipment is required to perform

an SR function. This includes Class 1 dead, live (snow and floor), and wind loads. It does not

include seismic or tornado loads or tornado-generated missiles.

The offgas storage and compressor building contains SR components that are relied upon to

remain functional during and following DBEs. The failure of NSR SSCs in the off gas storage

and compressor building could potentially prevent the satisfactory accomplishment of an SR

function of SSCs within the scope of license renewal.

The intended functions within the scope of license renewal include the following:

* provide structural support to NSR components (civil and structural)

* provide structural support to SR components (civil and structural)

In LRA Table 2.4.11-1, the applicant identified the following offgas storage and compressor

building component types that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (structural steel)

• concrete in air/gas (foundation, walls, slabs)

• concrete in air/gas (foundation, walls, slabs, grout)

* concrete in atmosphere/weather (walls, slabs)

0 concrete in below grade (foundation, walls)

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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2.4.11.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the offgas storage and compressor building components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and the offgas storage and compressor

building components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.12 Plant Control and Cable Spreading Structure

2.4.12.1 Summary of Technical Information in the Application

In LRA Section 2.4.12, the applicant described the plant control and cable spreading structure.

The primary functions of this structure are to provide, under all operating or postulated accident

conditions, safe enclosure for those portions of the standby electrical power systems and I&C

systems vital to overall plant operation and safety which are located therein, as well as an

environment satisfactory for continuous occupancy by operating personnel. The plant control

and cable spreading structure is located at the north end of the original office and control

building and includes the MCR, cable spreading room, and battery room. The administration

building is located adjacent to the east side of the original office and control building. The

original office and control building, as well as the administration building, constitute the plant

control and cable spreading structure. The administration building provides a records storage

area to meet the requirements of American National Standards Institute(ANSI) N45.2.9,

training space, lockers and restroom facilities, an instrument shop, library space, a meeting

room, shift supervisor's office, open office space, and private offices. Modifications to the shift

supervisor's office have been made so that the office is part of the MCR for the purpose of

meeting the NRC's requirement for the presence of a senior licensed operator in the control

room at all times. The shift supervisor's office is located immediately adjacent to the MCR, but

outside the previously defined control room boundary.

The plant control and cable spreading structure contains SR components that are relied upon to

remain functional during and following DBEs. The failure of NSR SSCs in the plant control and

cable spreading structure could potentially prevent the satisfactory accomplishment of an SR

function of SSCs within the scope of license renewal. In addition, the plant control and cable

spreading structure performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide rated fire barrier

• provide flood protection barrier

* provide missile barrier

* provide structural support to NSR components (civil and structural)

• provide structural support to SR components (civil and structural)

* provide shelter/protection to SR components

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In LRA Table 2.4.12-1, the applicant identified the following plant control and cable spreading

structure component types that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (fire-rated doors)

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

" carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* concrete in air/gas (foundation, walls, slabs)

• concrete in air/gas (foundation, walls, slabs, grout)

" concrete in air/gas (walls, slabs)

" concrete in atmosphere/weather (walls, slabs)

* concrete in below grade (foundation, walls)

" elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (control room seals)

" masonry walls in.air/gas

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.12.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant had adequately

identified the plant control and cable spreading structure components that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and the plant control and cable spreading

structure components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.13 Primary Containment

2.4.13.1 Summary of Technical Information in the Application

In LRA Section 2.4.13, the applicant described the primary containment (PCT) system. The

PCT system includes the drywell, the wetwell (torus), the primary containment penetrations, the

bioshield wall, the RPV support pedestal, the drywell/torus internal platforms, and the torus

external catwalk. The mechanical portion of the primary containment system is included in the

PCM system. The PCT system provides a barrier to the release of fission products to the SCT

and rapidly reduces the pressure in primary containment after a LOCA. The system consists

of a light-bulb-shaped drywell, a torus-shaped wetwell, and a connecting vent system between

the drywell and the wetwell. The system encloses the reactor vessel, the reactor coolant

recirculation loops, and various branch connections of the reactor primary system. The drywell

is a steel pressure vessel with a spherical lower portion and a cylindrical upper portion. The

personnel airlock provides an entrance to the drywell measuring 6 feet by 2.5 feet. The wetwell

is a steel pressure vessel in the shape of a torus located below and encircling the drywell.

Penetrations through the drywell and wetwell walls provide for passage of fluid piping and

electrical cables. These penetrations are designed to withstand environmental conditions

present during a LOCA and to maintain primary containment integrity for extended periods of

time in a post-accident environment. Piping penetrations consist of pipe segments welded into

structurally enhanced containment shell plates. Piping penetrations are of two general

types-sleeved, those for which the process flow is not in contact with the original penetration

pipe segments, and Unsleeved, those for which-the process flow is in contact with-the original

penetration pipe segments.

The PCT system contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the PCT system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In

addition, the PCT system performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide source of cooling water for plant shutdown

* provide flood protection barrier

* provide heat sink during DBAs

* provide shielding against HELBs

* provide missile barrier

* provide structural support to NSR components (civil and structural)

* provide pressure boundary of essentially leaktight barrier (civil and structural)

* provide shielding against radiation

* provide structural support to SR components (civil and structural)

* provide pipe whip restraint

In LRA Table 2.4.13-1, the applicant identified the following PCT system component types that

are within the scope of license renewal and subject to an AMR:

carbon steel, low-alloy steel in air/gas (drywell penetration sleeves, drywell penetration

bellows assemblies, drywell penetrations, torus penetrations)

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* carbon steel, low-alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts,

torus ring girder, downcomers, vent lines, vent header, bellows assemblies, vent header

deflectors, ECCS suction header)

* carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,

seismic restraint, inspection ports)

* carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,

seismic restraint, inspection ports, including locks, hinges, and closure mechanisms)

carbon steel, low-alloy steel in air/gas (structural steel (i.e., torus external catwalk,

drywell interior platforms, bioshield wall liners, etc.))

" carbon steel, low-alloy steel in air/gas (structural steel inside torus (i.e., torus internal

catwalk, etc.))

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures, including

platforms, stairs, and whip restraints, etc. (i.e., members, welds, bolted connections,

support anchorage to building structure))

* carbon steel, low-alloy steel embedded in concrete (drywell support skirt, embedded

shell)

" carbon steel, low-alloy steel in treated water (structural steel)

* carbon steel, low-alloy steel in treated water (support members, welds, bolted

connections (i.e., torus internal catwalk support columns))

* carbon steel, low-alloy steel in treated water (torus penetrations)

* carbon steel, low-alloy steel in treated water (torus, torus ring girder, downcomers,

ECCS suction header)

" carbon steel, low-alloy steel, stainless steel in air/gas (drywell penetration sleeves,

drywell penetrations)

* concrete in air/gas (bioshield wall, drywell equipment foundation, RPV pedestal)

* elastomer sealants (rubber, neoprene, silicone, etc.) in, air/gas (moisture barriers)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (seals and gaskets)

* inconel in air/gas (drywell penetration X-1 6B bellows)

* lubrite in air/gas (drywell head, downcomers)

" lubrite in air/gas (drywell interior platform sliding plates)

* lubrite in treated water (downcomers)

" stainless steel in air/gas (drywell penetration sleeves, drywell penetration bellows)

" stainless steel in air/gas (RPV to drywell refueling seal)

* stainless steel in air/gas (vent line bellows)

* stainless steel in treated water (thermowells)

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2.4.13.2 Staff Evaluation

The staff reviewed LRA Section 2.4.13 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.13 identified areas for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.4.13-1, dated September 28, 2005, the staff requested that the applicant clarify

whether the supports and components included in Code PCT-04 of the system function listing

are within the scope of license renewal. The staff requested that the applicant provide a

summary listing of these supports and components and a confirmation that their failure under

earthquake-induced loads would not affect the functioning of SR SSCs.

In its response, by letter dated October 28, 2005, the applicant explained the following:

System function Primary Containment (PCT)-04 referred only to non-safety

related components that could not affect safety related SSCs. Components

associated with this function are not in scope of license renewal. The function for

non-safety related components that could affect safety related components is

Primary Containment-Non-Safety Affecting Safety (PCT-NSAS), evaluated on

page 2-225 of the LRA. Functions associated with component supports are

further addressed in Section 2.4.6, 'Hangers and Supports Commodity Group.'

The PCT-04 function was evaluated against the criteria of 10 CFR 54.4(a) and

found not to meet any of its requirements. Consequently, the function was

provided for information and completeness only, since it did not form a basis for

including the primary containment structure within the scope of the Rule. This

scoping methodology was consistently used through Section 2 of the LRA.

Based on its review, the staff found the applicant's response to RAI 2.4.13-1 acceptable. The

clarification asserts that the components included in the PCT-04 group are not SR and would

not affect the integrity of SR SSCs under postulated seismic events; therefore, the staff's

concern described in RAI 2.4.13-1 is resolved.

In RAI 2.4.13-2, dated September 28, 2005, the staff noted that the second and third

component groups in Table 2.4.13-1 list almost identical components (drywell, torus, drywell

head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows

assembly, ECCS suction header) with the same material-environment combination (carbon

steel/low-alloy steel in air/gas) and intended functions. A similar redundancy was noted on the

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first two component groups on page 2-257 (personnel airlock, equipment hatch, CRD hatch,

seismic restraint, and inspection ports). Therefore, the staff requested that the applicant clarify

these redundancies.

In its response, by letter dated October 28, 2005, the applicant stated the following:

To explain the apparent redundancies between components, first an explanation

of how Table 2.4.13-1 was assembled is needed to explain the apparent

redundancies between components. Tables in Section 2.4 of the LRA were

assembled by copying the component group and intended functions for each

3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently used

throughout the LRA. Many line entry component group descriptions appear

similar but there are subtle differences that are evident upon review of the

3.5.2-x Table AMP, aging effects/mechanisms, material, etc.

For this specific question, Table 2.4.13-1 component groups, 'carbon steel, low

alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts, torus ring

girder, downcomers, vent lines, vent header, bellows assemblies, ECCS suction

header)' and 'carbon steel, low alloy steel in air/gas (drywell, torus, drywell head,

drywell head bolts, torus ring girder, downcomers, vent lines, vent header,

bellows assemblies, vent header deflectors, ECCS suction header)' have

different component group descriptions (one component group includes vent

header deflectors and the other does not). Review of Table 3.5.2-13 reveals that

the component group without vent header deflectors is managed by 10 CFR 50,

Appendix J while the group with vent header deflectors is managed by the

Primary Containment In-Service Inspection Program. This is because the vent

header deflectors do not perform a pressure retaining function associated with

an Appendix J test.

For part two of this question, Table 2.4.13-1 component groups, 'carbon steel,

low alloy steel in air/gas (personnel airlock, equipment hatch, [Control Rod Drive]

CRD hatch, seismic restraint inspection ports)' and 'carbon steel, low alloy steel

in air/gas (personnel airlock, equipment hatch, CRD hatch, seismic restraint

inspection ports, including locks, hinges and closure mechanisms)' have different

component group descriptions. Review of Table 3.5.2-13 reveals that the

component group with locks, hinges, and closure mechanisms is managed for a

different aging effect, 'loss of leak tightness in closed position' in accordance

with NUREG-1 801 line item 11.B4.2-b.

Based on its review, the staff found the applicant's response to RAI 2.4.13-2 acceptable. The

purpose of scoping is to ensure that all SSCs that are within the scope of license renewal

pursuant to 10 CFR 54.4 first be identified clearly and then, while performing an AMR, the

applicant identifies the relevant material and environment. In this application, the applicant used

the reverse method; however, the explanation ensures that the applicant has not missed any

important SSCs from the scope of license renewal. After reviewing the applicant's approach,

the staff understood the reason for the redundancies and found the approach acceptable;

therefore, the staff's concern described in RAI 2.4.13-2 is resolved.

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In RAI 2.4.13-3, dated September 28, 2005, the staff also noted that Table 2.4.13-1 lists the

component group, "lubrite in air/gas," with the drywell head included as a component. In the

description of drywell head, the applicant stated, "The head is held in place by bolts and sealed

with a double gasket arrangement." Therefore, the staff requested that the applicant clarify

where the lubrite bearings are used in the drywell head.

In its response, by letter dated October 28, 2005, the applicant provided the following

information:

Lubrite type material is not used for the drywell head or downcomers.

Table 2.4.13-1, page 2-260 included this component group, 'lubrite in air/gas

(drywell head and downcomers)' because tables in Section 2.4 of the LRA were

assembled by copying the component group and intended functions for each

Table 3.5.2-13 line entry into Table 2.4.13-1. Table 3.5.2-13 included this entry

to demonstrate that NUREG-1 801 line item II.B13.1.1 -e was evaluated for

applicability. The evaluation provided in Table 3.5.2-13 stated that, 'The drywell

head and downcomer pipes are carbon steel material. Graphite plate material is

not used for these components and therefore the aging effect is not applicable'

(see LRA note 556). Therefore the description of the drywell head in the LRA,

page 2-251 is consistent with note 556 in Table 3.5.2-13.

Based on its review, the staff found the applicant's response to RAI 2.4.13-3 acceptable. The

staff found that the applicant's approach covers all the components subject to AMR; therefore,

the staff's concern described in RAI 2.4.13-3 is resolved.

2.4.13.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the PCT system components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and the PCT system components that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2.4.14 Radioactive Waste Building

2.4,14.1 Summary of Technical Information in the Application

In LRA Section 2.4.14, the applicant described the radioactive waste building. The radioactive

waste building is located adjacent to the south side of the reactor building. The building is used

for storage of contaminated materials, such as spent ion exchange resins, filters, anti-C

clothing, and contaminated materials. The railroad car airlock and the airlock between the

reactor building and the radioactive waste building are part of secondary containment. The

radioactive waste building is a reinforced concrete structure supported on a concrete slab. The

radioactive waste building was designed such that it would not fail during an earthquake. It is

also designed to protect the reactor building from external floods.

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The radioactive waste building contains SR components that are relied upon to remain

functional during and following DBEs. The failure of NSR SSCs in the radioactive waste building

could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the

scope of license renewal.

The intended functions within the scope of license renewal include the following:

* provide flood protection barrier

* provide shielding against HELBs

* provide structural support to NSR components (civil and structural)

* provide pressure boundary of essentially leaktight barrier (civil and structural)

* provide shielding against radiation

* provide structural support to SR components (civil and structural)

* provide shelter/protection to SR components

In LRA Table 2.4.14-1, the applicant identified the following radioactive waste building

component types that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (air lock and railroad doors)

* carbon steel, low-alloy steel in air/gas (structural steel)

* carbon steel, low-alloy steel in atmosphere/weather (railroad door)

* concrete in air/gas (foundation, walls, slabs)

* concrete in air/gas (foundation, walls, slabs, grout)

* concrete in atmosphere/weather (walls, slabs)

" concrete in below grade (foundation, walls)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (secondary containment

seals)

* elastomer sealants (rubber, neoprene, silicone, etc.) in atmosphere/weather (secondary

containment seals)

" glass in air/gas (railroad bay door view port)

* glass in atmosphere/weather (railroad bay door view port)

" masonry walls in air/gas

" roofing in atmosphere/weather (railroad bay built-up roofing)

2.4.14.2 Staff Evaluation

The staff reviewed LRA Section 2.4.14 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

2-139
functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.14.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the radioactive waste building components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the radioactive waste building components that

are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.15 Reactor Building

2.4.15.1 Summary of Technical Information in the Application

In LRA Section 2.4.15, the applicant described the reactor building. The principal functions of

the reactor building are to support and protect enclosed systems and components and to

provide secondary containment limiting the offsite radiological consequences of accidents. The

building provides necessary space for the equipment in a planned arrangement and provides

for layout space for the equipment to be removed and replaced if necessary. Reactor internals

and fuel can be moved and conveniently stored within the building.-The reactor building serves

as the secondary containment. The secondary containment, in conjunction with other

engineered safeguards and nuclear safety systems, limits the release of radioactive materials

from a postulated DBA. The reactor building also provides secondary containment when the

primary containment is in service and provides primary containment during reactor refueling

and maintenance operations when the primary containment system is open. A major

substructure within the reactor building is a reinforced concrete biological shield that surrounds

the reactor and drywell portion of the primary containment.

The reactor building contains SR components that are relied upon to remain functional during

and following DBEs. The failure of NSR SSCs in the reactor building could potentially prevent

the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

In addition, the reactor building performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide shielding against neutron radiation

" provide rated fire barrier

* provide flood protection barrier

* provide shielding against HELBs

* provide missile barrier

* provide structural support to NSR components (civil and structural)

* provide pressure boundary of essentially leaktight barrier (civil and structural)

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• provide shielding against radiation

* provide structural support to SR components (civil and structural)

• provide shelter/protection to SR components

• provide pipe whip restraint

In LRA Table 2.4.15-1, the applicant identified the following reactor building component types

.that are within the scope of license renewal and subject to an AMR:

• aluminum in air/gas (new fuel storage racks)

• aluminum in air/gas (siding)

* aluminum in atmosphere/weather (siding, ventilation assemblies)

• aluminum in treated water (spent fuel storage racks)

* boral in treated water (spent fuel storage racks neutron-absorbing sheets)

• carbon steel, low-alloy steel in air/gas (drywell to reactor building refueling seal plates)

" carbon steel, low-alloy steel in air/gas (fire-rated doors)

" carbon steel, low-alloy steel in air/gas (fire-rated, HELB, and secondary containment

doors)

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, blowout panels,

etc.)

" carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, whip

restraints, masonry wall supports, etc.))

" carbon steel, low-alloy steel in atmosphere/weather (structural steel, ventilation

assemblies)

" carbon steel, low-alloy steel in treated water (drywell to reactor building refueling seal

plates)

• concrete in air/gas (foundation, walls, slabs)

• concrete in air/gas (foundation, walls, slabs, ,grout)

* concrete in air/gas (walls, slabs)

* concrete in atmosphere/weather (walls, slabs)

• concrete in below grade (foundation, walls)

* elastomer sealants (rubber, neoprene, silicone, etc.) in air/gas (secondary containment

seals, spent fuel pool gate seals, and hatch seals)

* elastomer sealants (rubber, neoprene, silicone, etc.) in atmosphere/weather (secondary

containment seals)

a elastomer sealants (rubber, neoprene, silicone, etc.) in treated water (spent fuel pool

.gate seals)

* glass in air/gas (railroad door view port)

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" masonry walls in air/gas

" nonmetallic fireproofing in air/gas (gypsum board walls)

* roofing in atmosphere/weather

* stainless steel in air/gas (metal siding screws, upper portion of spent fuel pool,

dryer/separator storage pool, reactor well liners, and drywell to reactor building refueling.

seal bellows)

0 stainless steel in atmosphere/weather (metal siding screws)

" stainless steel in treated water (dryer/separator storage pool and reactor well liners)

" stainless steel in treated water (drywell to reactor building refueling seal bellows)

" stainless steel in treated water (spent fuel pool, dryer/separator storage pool, and

reactor well liners)

" stainless steel in treated water (spent fuel pool liner)

* stainless steel in treated water (spent fuel storage racks)

2.4.15.2 Staff Evaluation

The staff reviewed LRA Section 2.4.15 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified asbeing within the scope of license renewal to verify that the applicaht

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.15.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

.omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the reactor building components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and' the reactor building components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

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2.4.16 Structures Affecting Safety

2.4.16. 1 Summary of Technical Information in the Application

In LRA Section 2.4.16, the applicant described the structures affecting safety system. The

structures affecting safety system pertains to plant structures that, perform no safety function o'r

regulated event function (except for the heating boiler building), but could, under certain failure

scenarios, adversely affect buildings or equipment having such functions. These structures are

listed below:

* The heating boiler building is located along the east side of the turbine building. The

heating boiler building is a structural steel frame building with insulated metal siding and

a steel deck roof. The structural steel columns sit on a reinforced concrete footing. The

foundation walls are also of reinforced concrete. The floor consists of a reinforced

concrete slab on grade.

" The non-1 E electrical equipment room is located just east of the turbine building. The

structure contains transformers and switchgear for NSR portions of the 480-VAC power

system. In addition, the NSR No. 17 250-VDC battery is located in the non-1 E electrical

equipment room.

* The hot machine shop is located along side the turbine building at the east end of the

north wall. The hot machine shop is a structural steel frame building with insulated metal

siding with a steel deck roof. The structural steel columns sit on a reinforced concrete

footing. The foundation walls are also of reinforced concrete. The floor consists of a

reinforced concrete slab on grade.

* The turbine building addition is a Class 2 structure and does not contain any Class 1

equipment. The structure was designed in accordance with the uniform building code.

The primary function of the turbine building addition is to provide a controlled

environment for the condenser retubing effort..

The recombiner building is a reinforced concrete structure utilizing heavy shear walls as

a lateral force-resisting system resting on a mat foundation. The building consists of two

equipment bays, a shielded tunnel which houses the interconnecting piping, an

instrument room, and a pump room. There is also an enclosed walkway and access

areas constructed of structural steel with insulated metal siding and insulated builtup

roofing.

A radwaste storage building is provided for the solid radwaste truck-loading area. This

sheet metal building is provided with shield walls, floor drains, heating, and FP systems.

An overhead crane is located in the building. The building is designed to enclose the

radwaste shipping truck and to facilitate loading of the truck.

The failure of NSR SSCs in the structures affecting safety system could potentially prevent the

satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

The structures affecting safety system also performs functions that support FP.

The intended functions within the scope of license renewal include the following:

a provide rated fire barrier

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0 provide structural support to NSR components (civil and structural)

In LRA Table 2.4.16-1, the applicant identified the following structures affecting safety system

component types that are within the scope of license renewal and subject to an AMR:

* carbon steel, low-alloy steel in air/gas (fire-rated doors)

* carbon steel, low-alloy steel in air/gas (structural steel)

* concrete in air/gas (foundations, walls, slabs)

* concrete in air/gas (foundations, walls, slabs, grout)

* concrete in atmosphere/weather (foundations, walls, slabs)

• concrete in below grade (foundations, walls)

2.4.16.2 Staff Evaluation

The staff reviewed LRA Section 2.4.16 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.16.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the structures affecting safety system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and the structures affecting safety system components

that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.17 Turbine Building

2.4.17.1 Summary of Technical Information in the Application

In LRA Section 2.4.17, the applicant described the turbine building (TGB). The TGB is a

Class 2 structure; however, the portions that support and protect electrical controls and

instrumentation for Class 1 equipment were designed in accordance with the criteria for the

design of portions of Class 2 structures enclosing and/or supporting Class 1 equipment. The

primary function of the TGB is to provide the necessary environment required for safe operation

and maintenance of the turbine generator and other components of the power conversion

system. The TGB is a combination of reinforced concrete and structural steel construction. The

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foundation is a reinforced concrete mat of variable thickness supported on undisturbed soil. The

foundation supports the reinforced concrete turbine generator pedestal, as well as the building

superstructure. The reinforced concrete portion of the superstructure extends from the top of

the mat foundation to the turbine deck. Structural steel beam and girded framing support the

reinforced concrete floor slabs. Interior reinforced concrete walls extending from the top of the

mat up to the operating floor are oriented to protect personnel against radiation emanating from

the turbine and auxiliary systems. A structural steel-framed superstructure is based at the

turbine deck on reinforced concrete columns located within the exterior walls. The

superstructure encloses' the operating floor and also provides support and closure for a

traveling bridge crane. A 5-ply tar and felt insulated roof is supported by a metal roof deck

which also acts as a diaphragm to transmit lateral forces to vertically braced end walls or shear

frames.

The TGB contains SR components that are relied upon to remain functional during and

following DBEs. The failure of NSR SSCs in the TGB could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the

TGB performs functions that support FP, ATWS, and SBO.

The intended functions within the scope of license renewal include the following:

* provide rated fire barrier

* provide flood protection barrier

* provide shielding against HELBs

* provide missile barrier

* provide structural support to NSR components (civil and structural)

* provide shielding against radiation

* provide structural support to SR components (civil and structural)

" provide shelter/protection to SR components

* provide pipe whip restraint

In LRA Table 2.4.17-1, the applicant identified the following TGB component types that are

within the scope of license renewal and subject to an AMR:

0 carbon steel, low-alloy steel in air/gas (fire-rated doors)

* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, doors, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, whip

restraints, masonry wall supports, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (doors)

* concrete in air/gas (foundation, walls, slabs)

* concrete in air/gas (foundation, walls, slabs, grout)

• concrete in air/gas (walls, slabs)

* concrete in atmosphere/weather (walls near recombiner building)

* concrete in atmosphere/weather (walls, slabs)

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* concrete in below grade (foundation, walls)

" masonry walls in air/gas

" nonmetallic fireproofing in air/gas (cementitious fireproofing, pyrocrete walls)

* nonmetallic fireproofing in air/gas (gypsum board walls)

2.4.17.2 Staff Evaluation

The staff reviewed LRA Section 2.4.17 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.17 identified an area for which it needed additional

information to complete its evaluation of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4.17-1, dated September 28, 2005, the staff noted that Table 2.4.17-1 lists "Carbon

steel, low-alloy steel in air/gas (fire rated doors)" as a component group with the intended

function being fire barrier, and "Carbon steel, low-alloy steel in air/gas (...doors,...)" as another

component group with one of the intended functions also being fire barrier. Therefore, the staff

requested that the applicant explain the difference between the doors listed in the two

component groups.

In its response, by letter dated October 28, 2005, the applicant provided the following response:

Table 2.4.17-1 component group, 'carbon steel, low alloy steel in air/gas (fire

rated doors)' refers to doors that provide a fire barrier intended function and are

managed for aging by the Fire Protection Program. Table 2.4.17-1 component

group, 'carbon steel, low alloy steel in air/gas (structural steel, steel embeds,

doors, etc.)' refers to those doors that were assigned a fire barrier function as

discussed above, but also perform at least one other intended function such as

high energy line break (HELB) barrier and/or flood barrier. Consequently doors

with a fire barrier intended function that also perform additional functions are

managed by the Structures Monitoring Program in addition to the Fire Protection

Program in accordance with NUREG-1 801.

Based on its review, the staff found the applicant's response to RAI 2.4.17-1 acceptable,

because the applicant adequately explained that the doors have different intended functions.

Therefore, the staff's concern described in RAI 2.4.17-1 is resolved.

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2.4.17.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the TGB components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the TGB components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.4.18 Underground Duct Bank

2.4.18.1 Summary of Technical Information in the Application

In LRA Section 2.4.18, the applicant described the underground duct bank. The underground

duct bank runs between the third floor of the EFT building and the reactor building. The primary

function of the duct bank is to carry Division 2 safe-shutdown cables outside of areas where fire

damage could occur. The duct bank includes risers at each end with an underground section in

between. The underground portion of the duct bank is 700 feet in length and is rectangular in

cross section. It is constructed of reinforced concrete and contains sixteen 4-inch diameter

raceways. Access to the duct bank is provided by four reinforced concrete manholes. Seismic

joints occur at the manhole to duct bank interface and the riser to duct bank interface.

The underground duct bank contains SR components that are relied upon to remain functional

during and following DBEs. In addition, the underground duct bank performs functions that

support FP and SBO.

The intended functions within the scope of license renewal include the following:

* provide flood protection barrier

* provide structural support to NSR components (civil and structural)

* provide structural support to SR components (civil and structural)

" provide shelter/protection to SR components

In LRA Table 2.4.18-1, the applicant identified the following underground duct bank component

types that are within the scope of license renewal and subject to an AMR:

• carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,

members, welds, bolted connections, support anchorage for platforms, stairs, etc.))

* carbon steel, low-alloy steel in atmosphere/weather (manhole covers/supports)

* *carbon steel, low-alloy steel in below grade (manhole covers/supports)

* concrete in air/gas (foundation, walls, slabs)

• concrete in atmosphere/weather (walls, slabs)

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a concrete in below grade (foundation, walls, slabs, grout)

2.4.18.2 Staff Evaluation

The staff reviewed LRA Section 2.4.18 and the USAR using the evaluation methodology

described in SER Section 2.4. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.4.

In conducting its review, the staff evaluated the structural component functions described in the

LRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the

applicant had not omitted from the scope of license renewal any components with intended

functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the

applicant had identified as being within the scope of license renewal to verify that the applicant

had not omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.4.18.3 Conclusion

The staff reviewed the LRA and related structural components to determine whether the

applicant had failed to identify any SSCs that should be within the scope of license renewal. No

omissions were identified. In addition, the staff performed a review to determine whether the

applicant had failed to identify any components that should be subject to an AMR. No omissions

were identified. On the basis of its review, the staff concluded that the applicant adequately

identified the underground duct bank components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and the underground duct bank components that are subject to

an AMR, as required by 10 CFR 54.21 (a)(1).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

This section documents the staff's review of the applicant's scoping and screening results for

electrical and I&C systems. Specifically, this section. discusses the following:

* electrical and I&C systems

* electrical commodities

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must identify and list

passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To

verify that the applicant properly implemented its methodology, the staff focused its review on

the implementation results. This approach allowed the staff to confirm that there were no

omissions of electrical and I&C system components that meet-the scoping criteria and are

subject to an AMR.

Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRA

in the same manner for all electrical and I&C systems. The objective of the review was to

determine whether the applicant had identified the components and supporting structures for a

specific electrical and I&C system, that appeared to meet the scoping criteria specified in the

Rule, as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the

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staff evaluated the applicant's screening results to verify that all long-lived, passive components

were subject to an AMR, in accordance with 10 CFR 54.21(a)(1).

Scoping. To perform its evaluation, the staff, reviewed the applicable LRA section and

associated component drawings, focusing its review on components that had not been

identified as within the scope of license renewal. The staff reviewed relevant licensing-basis

documents, including the USAR, for each electrical and I&C system component to determine

whether the applicant had omitted components with intended functions delineated under

10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing-basis

documents to determine whether the LRA specified all intended functions delineated under

10 CFR 54.4(a). If omissions were identified, the staff requested additional information to

resolve the discrepancies.

Screening. Once the staff completed its review of the scoping results, the staff evaluated the

applicant's screening results. For those systems and components with intended functions, the

staff sought to determine (1) if the functions are performed with moving parts or a change in

configuration or properties or (2) if they are subject to replacement based on a qualified life or

specified time period, as described in 10 CFR 54.21 (a)(1). For those electrical and I&C systems

and components that did not meet either of these criteria, the staff sought to confirm that they

were subject to an AMR, as required by 10 CFR 54.21 (a)(1). If discrepancies were identified,

the staff requested additional information to resolve them.

2.5.1 Electrical and Instrumentation and Controls Systems

In LRA Section 2.5.1, the applicant identified the SCs of the electrical and I&C systems that are

subject to an AMR for license renewal.

The applicant described the supporting SCs of the electrical and I&C systems in the following

sections of the LRA:

" 2.5.1.1 480-V station auxiliary system

* 2.5.1.2 4.16-kV station auxiliary

" 2.5.1.3 alternate shutdown

* 2.5.1.4 annunciators

* 2.5.1.5 communications

* 2.5.1.6 DC battery

" 2.5.1.7 lighting

* 2.5.1.8 neutron monitoring

* 2.5.1.9 offsite power

* 2.5.1.10 plant protection

* 2.5.1.11 radiation monitoring

* 2.5.1.12 reactor level control (RLC)

* 2.5.1.13 uninterruptible AC

SER Sections 2.5.1.1-2.5.1.13 present the staff's review findings regarding LRA

Sections 2.5.1.1-2.5.1.13, respectively.

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2.5.1.1 480-V Station Auxiliary

2.5.1.1.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.1, the applicant described the 480-V station auxiliary system. The 480-V

station auxiliary system consists of transformers, breakers, load centers, and MCCs. Power is

typically supplied to motors less than 250 horsepower (HP) and lighting transformers. The

system receives power from the 4.16-kV station auxiliary system through load center

transformers. It distributes power through load center buses and MCCs.

The 480-V station auxiliary system contains SR components that are relied upon to remain

functional during and following DBEs. The failure of NSR SSCs in the 480-V station auxiliary

system could potentially prevent the satisfactory accomplishment of an SR function of SSCs

within the scope of license renewal. In addition, the 480-V station auxiliary system performs

functions that support FP, ATWS, and SBO.

The applicant identified the 480-V station auxiliary system SCs that are within the scope of

license renewal. LRA Section 2.5.2 evaluates electrical commodities for this system that are

subject to AMR. LRA Section 2.4.6 evaluates supports for electrical components.

2.5.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.1 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.5.1.1 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In RAI 2.5.1-1, the staff noted that LRA Section 2.5.1.1, under the system function listing 480-

V station auxiliary, states that MCCs 132, 133A, and 142A are credited with supporting an

ATWS event; however, license renewal drawing LR-36298, does not include MCC 132 as within

the scope of license renewal; therefore, the staff requested that the applicant resolve the

discrepancy.

In its response, by letter dated September 16, 2005, the applicant provided the following

response:

MCC 132 Breaker B3230 supplies power to the tank heater for Standby Liquid

Control (SLC) Tank T-200. The SLC System mitigates an ATWS event. The

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drawing is in error. Drawing LR-36298 will be revised to show MCC 132 as being

within the scope of License Renewal.

Based on its review, the staff found the applicant's response to RAI 2.5.1-1 acceptable because

the applicant will revise its boundary drawing to indicate MCC 132 as being within the scope of

license renewal. Therefore, the staff's concern described in RAI 2.5.1-1 is resolved.

During the scoping inspection, the inspectors identified discrepancies between the scoping and

screening report and license renewal drawing LR-36298. Specifically, the license renewal

classification of breakers fed from several 480-V load centers was not consistent with the

license renewal scoping and screening document. The applicant also identified several other

load center cubicles which were not previously shown as being within the scope of license

renewal, but which should have been included. The applicant determined that the additional

components brought into scope of license renewal were all active components, and therefore,

screened out and did not require aging management. On the basis of its review, the staff

concluded that the breakers are active components, and therefore not subject to an AMR.

2.5.1.1.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the 480-V

station auxiliary system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the 480-V station auxiliary system components that are subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.5.1.2 4.16-kV Station Auxiliary

2.5.1.2.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.2, the applicant described the 4.16-kV station auxiliary system. All station

power is supplied from the 4.16-kV station auxiliary system (4 kV) through distribution buses to

various motors and stepdown transformers. The 4.16-kV system is a three-phase, grounded

neutral distribution system. The system uses eight 4.16-kV bus sections, each housed in metal

clad assemblies. Six buses, 11, 12, 13, 14, 15, and 16, are located in the turbine building.

Buses 17 and 18 are located at the discharge structure to serve the cooling tower pumps. The

plant's 4.16-kV buses may be supplied from either of two sources. The normal source is the 2R

transformer supplied from the 345-kV substation. The alternate source is the 1 R transformer

supplied from the 115-kV substation. Protective relaying, if activated, deenergizes the 2R

transformer and initiates an open circuit transfer to the 1 R transformer. Air circuit

breakers (ACBs) connect sources and loads to the buses. Two 125-V station batteries supply

control power to control the opening and closing of the plant breakers in the 4.16-kV system.

The 4.16-kV station auxiliary system contains SR components that are relied upon to remain

functional during and following DBEs. In addition, the 4.16-kV station auxiliary system performs

functions that support FP, ATWS, and SBO.

The applicant identified the 4.16-kV station auxiliary system component types that are within the

scope of license renewal. Section 2.5.2 evaluates electrical commodities for this system that

are subject to AMR. Section 2.4.6 evaluates supports for electrical components.

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2.5.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.2 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.2.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the 4.16-

kV station auxiliary system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and the 4.16-kV station auxiliary system components that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5.1.3 Alternate Shutdown

2.5.1.3.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.3, the applicant described the ASD system, which is designed to provide

alternative shutdown capability, as required by 10 CFR 50.48 and Appendix R to 10 CFR

Part 50. This system assures safe shutdown in the event of a fire in the control room, cable

spreading room, or both. The ASD system performs the above by providing for a remote

centralized location at which existing plant systems can be manually controlled. The system

uses existing Division II systems and equipment. The ASD control panel is located on the third

floor of the emergency filtration building. This area is adjacent to the turbine building and the

control room.

The ASD system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the ASD system performs functions that support FP and SBO.

The applicant identified the ASD system component types that are within the scope of license

renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to an

AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.3 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

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not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.3.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the ASD

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the ASD system components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.5.1.4 Annunciators

2.5.1.4.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.4, the applicant described the plant annunciators. The plant annunciators

consist of MCC panels and local panels for selected systems and associated plant

instrumentation. They alert operators to off-normal conditions for monitored variables.

The failure of 'NSR SCs in the plant annunciators could potentially prevent the satisfactory

accomplishment of an SR function of SSCs within the scope of license renewal. The plant

annunciators also perform functions that support FP and SBO.

The applicant identified the plant annunciators component types that are within the scope of

license renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject

to an AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.4 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.4.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the plant

annunciators components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the plant annunciators components that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

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2.5.1.5 Communications

2.5.1.5.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.5, the applicant described the communications system. The

communications system consists of the following five subsystems-(1) telephone system, (2)

site public address (PA) system, (3) sound-powered system, (4) intercom system, and (5) plant

radio system. The plant telephone system is the most widely used method of communication at

MNGP and is centered around an AT&T programmable solid-state private branch exchange

(PBX) switch. There is also a set of telephones located in the control room, technical support

center, and training center which are used solely to perform NRC notification. This system is

called the FTS 2000 and uses dedicated circuits leased from commercial carriers to make

direct connections to various branches/offices of the NRC. The design of this system provides

independence from the normal telephone system and guarantees availability of commercial

circuits in the event of heavy telephone use by the local community. The site PA system is

designed to provide general plant paging capability and also provides a single-party line

channel between paging stations. The sound powered system is a series of hard-wired

telephone jacks located at various places throughout the plant that can be used for

maintenance and calibration activities. The intercom system is a multichannel system with

push-button channel selection at the master stations located in the control room and cable

spreading room. The plant radio system is a Motorola repeater-based system with six separate

channels.

The communications system performs functions that support FP.

The applicant identified the communications system component types that are within the scope

of license renewal. Section 2.5.2 evaluates electrical commodities for this system that are

subject to an AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.5 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.5.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the

communications system components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and the communications system components that are subject to an AMR,

as required by 10 CFR 54.21 (a)(1).

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2.5.1.6 DC Battery

2.5.1.6.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.6, the applicant described the DC battery. Two independent divisions of

24-VDC batteries are provided. They include two battery systems which feed separate DC

buses and two battery chargers per division fed from different AC feeders and distribution

panels. These 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and

H2J0 2 analyzer isolation valve position indication. Two independent divisions of 125-VDC

batteries are provided. They include two battery systems which feed separate DC buses and

distribution panels. The 250-VDC system consists of essential and nonessential subsystems.

The essential system consists of two independent divisions of 250-VDC batteries with center

taps for 125 VDC. The 250-VDC system supplies highly reliable power to large loads, such as

motor-driven pumps, valves, and uninterruptible power supplies (UPSs). The nonessential

system consists of one division of 250-VDC batteries. It includes one battery system which is

charged by rectifiers in the UPS and distribution panels.

The DC battery contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the DC battery performs functions that support FP, ATWS, and

SBO. This system contains equipment that is required to be qualified in accordance with

10 CFR 50.49.

The applicant identified the DC battery component types that are within the scope of license

renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to an

AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.6.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.6 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21(a)(1).

The staff's review of LRA Section 2.5.1.6 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In RAI 2.5.1-2, the staff noted that LRA Section 2.5.1.6, under the description of DC battery,

states that the 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and

H,/0 2 analyzer isolation valve position indication. This section further states, under the system

function listing, that the 24-VDC system continuously provides DC electrical power to the SR

and NSR loads. However, the 24-VDC system is not considered SR because the system is not

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required to provide the SR function of these loads; therefore, the staff requested that the

applicant indicate specific safety loads powered by the 24-VDC system and explain how these

loads would perform the SR function if the 24-VDC NSR power supply were to fail.

In its response, by letter dated September 16, 2005, the applicant responded:

The 24 VDC system provides power to the Source Range Monitors (SRMs) and

the Intermediate Range Monitors (IRMs) in the Neutron Monitoring

System (NMS). With the mode switch in SHUTDOWN and RUN, SRMs and

IRMs are not required to be operable. Per the Technical Specifications, the

SRMs and IRMs are only required to be operable when the mode switch is in

REFUEL and STARTUP. The 24 VDC system provides power to the SRMs and

IRMs, but is not required for them to provide their Safety Related function.

Failure of 24 VDC power will initiate the safety functions (rod block and scram).

The Division I 24 VDC system provides power for the output trip relaying (not the

radiation monitors) for the Off-Gas Pretreatments monitors. In the event of a 24

VDC failure for this relaying, offgas trip timers will conservatively trip the

operating recombiner train after a 30-minute delay. Operability of the monitors

themselves is not affected.

The Division I 24 VDC system also provides power for the Flux-Tilt monitor. This

monitor is classified as non-safety related and is not required for normal

operation.

The Division II 24 VDC system provides power for the Discharge Canal, Service

Water, Radwaste Effluent, and Reactor Building Closed Cooling Water process

liquid radiation monitors. These monitors are all classified as non-safety related.

In the event of loss of Division 1124 VDC, compensatory measures would be

implemented for these radiation monitors in accordance with the applicable

MNGP site procedures.

Finally, each divisions of 24 VDC supplies power for the corresponding division

of containment atmosphere monitoring system isolation valve position indication.

Control power for the valves is provided by other sources. The valve position

indication function does not meet the criteria of 10 CFR 54.4(a)(I), (ii), or (iii) for

being within the scope of license renewal.

Based on its review, the staff found the applicant's response to RAI 2.5.1-2 acceptable because

the applicant adequately described the safety loads powered by the system and how those

loads perform if the power supply were to fail. Therefore, the staff's concern described in

RAI 2.5.1-2 is resolved.

2.5.1.6.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the DC

battery components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the DC battery components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

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2.5.1.7 Lighting

2.5.1.7.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.7, the applicant described the lighting system. The lighting system

provides light in all areas for safe, efficient operation of the plant. Normal lighting is supplied by

normal AC power. Several locations in the plant are supplied by normal lighting which is

supplied from an essential lighting source. Essential lighting is supplied by a normal AC source,

or by the diesel generators, or by the 1AR transformer during a loss of the normal AC source.

The emergency lighting system is independent of the AC system. 8-hour, battery-powered

emergency lighting units are also located throughout the plant. These units have individual

batteries that are continuously charged from normal AC power sources. In the event normal AC

power is lost, these units will illuminate. Appendix R to 10 CFR Part 50 requires 8-hour lighting

units to be located in the MCR, at the ASD panel, along the pathway in between, in the 11

diesel generator room, and in the warehouse/cold shop equipment bay.

The lighting system contains SR components that are relied upon to remain functional during

and following DBEs. In addition, the lighting system performs functions that support FP andSBO.

The applicant identified the lighting system component types that are within the scope of license

renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to an

AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.7.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.7 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with, the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified 'as being within the scope of license renewal to verify that the applicant had not.

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.7.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the

lighting system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the lighting system components that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

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2.5.1.8 Neutron Monitoring

2.5.1.8.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.8, the applicant described neutron monitoring systems. The local power

range monitor (LPRM) subsystem is designed to continuously monitor the neutron flux level in

the reactor while in the power range. The LPRM subsystem signals must be available to permit

demonstration of compliance with the critical power ratio limits. The individual LPRM output

signals serve as input signals to the average power range monitors (APRMs) and rod block

monitor (RBM). The APRM subsystem is designed to provide a continuous, accurate indication

of the average core power. The RBM is an operational aid designed to prevent violation of the

fuel integrity safety criteria during withdrawal of a single control blade. The RBM also provides a

local relative power signal for operator evaluation during control blade movement. The startup

range monitors consist of 12 neutron flux monitoring channels. They include four SRMs and

eight IRMs. The source range monitoring system is used to provide neutron flux information

from subcritical to an intermediate flux level. The intermediate range monitoring system is used

to provide neutron flux information from the upper limit of the source range monitors to the

lower limit of the power range monitors.

The neutron monitoring systems contain SR components that are relied upon to remain

functional during and following DBEs.

The applicant identified the neutron monitoring component types that are within the scope of

license renewal. Section 2.5.2 evaluates the electrical commodities for this system that are

subject to an AMR. Section 2.4.6 evaluates the supports for electrical components.

2.5.1.8.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.8 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.8.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the

neutron monitoring components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the neutron monitoring components that are subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

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2.5.1.9 Offsite Power

2.5.1.9.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.9, the applicant described the offsite power system. The 11 5-kV

substation contains buses, breakers, transformers, and associated equipment necessary to

connect the MNGP 345-kV system to the Xcel Energy 115-kV transmission system. The 115-kV

substation supplies power to the 1 R and 1 AR transformers. The 230-kV substation contains

buses, breakers, transformers, and associated equipment. It connects the Xcel 345-kV

transmission system to the Great River Energy 230-kV transmission system. The 230-kV

substation system includesthe No. 6 transformer. The 345-kV substation contains the buses,

breakers, and associated equipment necessary to connect the Xcel 345-kV transmission

system to the 2RS and 1 ARS transformers.

The offsite power system performs functions that support SBO.

The applicant identified the offsite power system component types that are within the scope of.

license renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject

to an AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.9.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.9 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

* omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.9.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the offsite

power components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and the offsite power components that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.5.1.10 Plant Protection

2.5.1.10.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.10, the applicant described the PPS. The PPS consists of the reactor

protection system, the ATWS system, and the, primary containment isolation system (PCIS).

The reactor protection system includes the motor-generator power supplies' associated control

and indicating equipment, sensors, relays, bypass circuitry, and switches that cause rapid

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insertion of control rods (scram) to shutdown the reactor. The ATWS system consists of two

separately powered trip systems, each made up of two subchannels. Each subchannel receives

an input from an independent sensor monitoring each of the ATWS trip parameters. A trip

occurring in both subchannels will cause an ATWS trip which opens both recirculating motor

generator set generator field breakers and causes control rod insertion by venting the scram air

header. The PCIS provides protection against the onset and consequences of accidents

involving the gross release of radioactive materials from the primary containment. This

protection is the automatic isolation of appropriate pipelines which penetrate the primary

containment whenever certain monitored variables exceed their preselected operational limit.

The PPS contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the PPS performs functions that support FP, ATWS, and SBO. This

system contains components required to be qualified in accordance with 10 CFR 50.49.

The applicant identified the PPS component types that are within the scope of license renewal.

Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR.

Section 2.4.6 evaluates supports for electrical components.

2.5.1.10.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.10 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.10.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the PPS

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the PPS components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5.1.11 Radiation Monitoring

2.5.1.11.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.11, the applicant described the area radiation monitors (ARMs). There are

numerous ARMs located throughout the plant, recombiner building, and offgas storage building.

Each consists of a detector coupled to an indicator located either on control room panels C-11

or C-252D. The indicators for the containment high-range monitors are located on panels C-257

and C-258 in the control room. The PAS system indicators are on PAS system panel C-261.

Two multipoint recorders, NR-18-55 and RR-7573, located on panel C-02 and panel C-252D,

respectively, record the readings of all channels, except the high-range channel (RI-7774) from

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the offgas storage building, the drywell monitors, and the PAS system monitor. All of the ARMs

use Geiger-Mueller detectors, except for the containment high-range monitors which are ion

chambers. These units are X-ray and gamma sensing devices. The PRM system consists of

several subsystems that provide continuous monitoring of the radiation levels of liquid and

gaseous processes throughout the plant which can release activity directly to the environment.

These subsystems assist in controlling the release of radioactive byproducts within the legally

prescribed limits as set forth in the TSs. They also help provide for personnel safety by warning

of abnormal radiation release levels and, in some cases, automatically terminating these

releases.

The ARMs contain SR components that are relied upon to remain functional during and

following DBEs. In addition, the ARMs contain components which are part of the Environmental

Qualification Program.

The applicant identified the ARMs component types that are within the scope of license

renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to an

AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.11.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.11 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license-renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.11.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the ARM

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

the ARM components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5.1.12 Reactor Level Control

2.5.1.12.1 Summary-of Technical Information in the Application

In LRA Section 2.5.1.12, the applicant described the RLC system. The FW system consists of

two constant-speed, motor-driven FW pumps with throttling flow control that have a combined

capacity of the total required flow to the reactor. The RLC system automatically controls the

flow of FW into the reactor vessel to maintain the water level in the vessel within a

predetermined range during all modes of plant operations. The RLC system employs water

level, steam flow, and FW flow as a three-element control. Single-element control, which

employs water level only, is also available.

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The RLC system performs functions that support FP and SBO.

The applicant identified the RLC component types that are within the scope of license renewal.

Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR.

Section 2.4.6 evaluates supports for electrical components.

2.5.1.12.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.12 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.12.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the RLC

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the RLC system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.5.1.13 Uninterruptible AC

2.5.1.13.1 Summary of Technical Information in the Application

In LRA Section 2.5.1.13, the applicant described the uninterruptible AC (UAC) system. The

UAC system is composed of two Class 1 E inverters that provide a Division 1 and a Division 2

120-VAC UPS. The Division 1 inverter (Y-71) is supplied by Division 1 250-VDC distribution

panel Q-31, with an alternate AC source to the static switch from essential MCC-1 34 through a

stepdown transformer. The Division 2 inverter (Y-81) is supplied by Division 2 250-VDC

distribution panel D-100 with an alternate AC source to the static switch from essential

MCC-1 44 through a step-down transformer. The 480-Volt AC system is composed of one UPS

Y-91 which provides a reliable source of 480-Volt AC power. This system is not a Class 1 E

system. The normal source for Y-91 is from LC-108 through circuit breaker 52-804. The

alternate source is through circuit breaker 52-704 on LC-1 07. The backup DC source is 250-

VDC battery No. 17 via circuit breaker No. 1 on panel D-71. Y-91 rectifier section provides the

charging for No. 17 battery, as well as being the normal supply for Y-91 inverter section. The

instrument and control AC power provides AC power to plant AC instrument loads.

The UAC system contains SR components that are relied upon to remain functional during and

following DBEs. In addition, the UAC system performs functions that support FP, ATWS, and

SBO.

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The applicant identified the UAC system component types that are within the scope of license

renewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to an

AMR. Section 2.4.6 evaluates supports for electrical components.

2.5.1.13.2 Staff Evaluation

The staff reviewed LRA Section 2.5.1.13 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

In conducting its review, the staff evaluated the system functions described in the LRA and

USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had

not omitted from the scope of license renewal any components with intended functions

delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant

had identified as being within the scope of license renewal to verify that the applicant had not

omitted any passive and long-lived components that should be subject to an AMR, in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.5.1.13.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the UAC

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the UAC system components that are subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.5.2 Electrical Commodities

In LRA Section 2.5.2, the applicant presented the results of the screening process for electrical

components evaluated as commodities subject to an AMR for license renewal. The applicant

explained in LRA Section 2.1.5.4 that the scoping and screening process for electrical

equipment was unique in several aspects. All electrical systems were evaluated to determine

whether the system intended functions met 10 CFR 54.4(a)(1) through (a)(3) requirements.

SSCs supporting intended functions were considered within the scope of license renewal. The

applicant performed component-level screening for electrical and mechanical systems within

the scope of license renewal. Most component-level screening was performed and documented

in the license renewal database on a commodity basis. Components were either screened out

as active or included in a commodity group.

The applicant described electrical commodity groups and their intended function in the following

sections of the LRA:

* 2.5.2.1 electrical penetrations

* 2.5.2.2 fuse holders

" 2.5.2.3 non-EQ cables and connections

* 2.5.2.4 off site power/SBO recovery path

Sections 2.5.2.1-2.5.2.4 present the staff's review findings regarding LRA

Sections 2.5.2.1-2.5.2.4, respectively.

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2.5.2.1 Electrical Penetrations

2.5.2.1.1 Summary of Technical Information in the Application

In LRA Section 2.5.2.1, the applicant described the electrical penetrations. The electrical

penetrations assemblies consist of one or more electrical conductors and materials, which

provide a pressure boundary between the inboard and outboard sides of the penetration. The

penetration must be capable of maintaining the license renewal intended function of "electrical

continuity" through the boundary. The cable and material associated with maintaining the

license renewal intended function is the focus of this review. Section 2.4.13 of the LRA contains

portions and materials of the penetration assembly associated with the license renewal

intended function "pressure boundary" (or essentially leaktight containment barrier). For an

electrical penetration to be within the scope of license renewal, it must support an intended

function of one of the systems or components identified as within the scope of license renewal.

MNGP uses penetrations manufactured by GE and D.G. O'Brien. There are 24 electrical

penetrations at MNGP. Nineteen of these are in use and five are spares. There are six

penetrations designated as requiring EQ and are addressed in SER Section 4.7. Of the

remaining 13 penetrations, only 4 are within the scope of license renewal. The other nine

penetrations do not contain cables which provide a license, renewal SR intended function or are

credited for any of the regulated events.

The intended function of electrical penetrations is to provide electrical connections to specified

sections of an electrical circuit

In LRA Table 2.5.2-1, the applicant identified the following commodity groups that are within the

scope of license renewal and subject to an AMR:

* non-EQ insulated cables and connections

* non-EQ electrical and I&C penetration assemblies except cable and connections

(electrical components only-potting compound, vapor barrier, and support)

non-EQ electrical cables used in instrumentation circuits not subject to 10 CFR 50.49

EQ requirements that are sensitive to reduction in conductor insulation resistance

2.5.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5.2.1 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

2.5.2.1.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the

electrical penetrations components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the commodity groups for electrical penetrations components that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.5.2.2 Fuse Holders

2.5.2.2.1 Summary of Technical Information in the Application

In LRA Section 2.5.2.2, the applicant described the fuse holders. For a fuse holder (block, clips,

and connection points) to be within scope, it must support an intended function of one of the

systems or components identified as within the scope of license renewal. In addition, the review

of fuse holders applies only to those that are not part of a larger assembly, but support SR and

NSR functions in which the failure of a fuse precludes a safety function from being

accomplished. Fuse holders inside an enclosure of an active component, such as the

switchgear, load center, MCC, distribution panel, power supply, power inverter, charger,

converter, inverter, or circuit board, are parts of the larger assembly. Since the applicant

regularly inspects and maintains piece parts and subcomponents in such an enclosure as part

of the plant's normal maintenance and surveillance activities, they are not subject to an AMR.

Since there is no all-inclusive fuse database at MNGP, the applicant used various databases,

analysis/calculations, and plant walkdowns to identify those fuse holders meeting the above

criteria. Based on the above reviews of databases, analysis/calculations, and in-plant

walkdowns, the applicant determined that the majority of the fuse holders at MNGP are located

inside an active device enclosure. For those fuse holders not located inside an active device

enclosure, the applicant performed further evaluation to determine whether the fuse holder

supported an intended function of systems or components identified as within the scope of

license renewal. Those fuse holders not supporting an intended function were scoped out and

no further evaluations were performed. Those fuse holders that do support an intended function

were scoped in and are subject to AMR.

The intended function of fuse holders is to provide electrical connections to specified sections

of an electrical circuit.

In LRA Table 2.5.2-2, the applicant identified the fuse holders as a commodity group that is'

within the scope of license renewal and subject'to an AMR.

2.5.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.5.2.2 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

2.5.2.2.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the fuse

holders that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the

fuse holders as a commodity group that is subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.5.2.3 Non-EQ Cables and Connections

2.5.2.3.1 Summary of Technical Information in the Application

In LRA Section 2.5.2.3, the applicant described the non-EQ cables and connections. The

components evaluated are non-EQ power, I&C insulated cables and connections (connections

include connectors, splices, and terminal blocks), and uninsulated (bare) ground conductors.

SER Section 4.7 evaluates components that are part of the Environmental Qualification

Program. In accordance with the Department of Energy's cable aging management guideline

presented in SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power

Plants-Electrical Cable and Terminations," issued September 1996, an insulated cable is an

assembly of a single electrical conductor (wire) with an insulation covering or a combination of

conductors insulated from one another with overall coverings. Connections (or terminations) are

used to connect the cable conductors to other cables or electrical devices. The applicant

evaluated several types of connections. Plug-in connectors are one or more electrical contacts

that plug or screw into a mating receptacle. Splice insulation systems (heat shrink and tape) are

insulation material generally applied over compression (i.e., bolted) or fusion connections and

are used to seal and insulate cable or splice terminations or junctions from the surrounding

environment. Terminal blocks are an insulating base with fixed points for landing of wiring or

connection of terminal (ring) lugs. Terminal blocks are installed in enclosures such as control

boards, MCCs, motors, terminal boxes, or power panel boards for protection from both physical

and environmental damage. Uninsulated ground conductors are electrical conductors (e.g.,

bare copper cable, bare copper bar) that are used to make electrical equipment ground

connections.

Uninsulated ground cables are neither classified as SR nor relied upon for SR equipment to

perform their intended function, as identified in 10 CFR 54.4(a); therefore, the applicant has

determined that uninsulated ground cables are outside the scope of license renewal.

The intended function of non-EQ cable and connections is to provide electrical connections to

specified sections of an electrical circuit.

In LRA Table 2.5.2-3, the applicant identified the non-EQ cables and connections as commodity

groups that are within the scope of license renewal and subject to an AMR as follows:

" electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

" electrical cables used in instrumentation circuits not subject to 10 CFR 50.49 EQ

requirements that are sensitive to reduction in conductor insulation resistance

* inaccessible medium voltage (2 kV to 34.5 kV) cable and connections (e.g., installed in

conduit or direct buried) not subject to 10 CFR 50.49 EQ requirements

2.5.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.5.2.3 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

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2.5.2.3.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the

non-EQ cables and connections that are within the scope of license renewal, as required by

10 CFR 54.4(a), and the non-EQ cables and connections as commodity groups that are

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.5.2.4 Offsite PowerISBO Recovery Path

2.5.2.4.1 Summary of Technical Information in the Application

In LRA Section 2.5.2.4, the applicant described the offsite power/SBO recovery path. The

passive, long-lived, in-scope components comprising the offsite power/SBO recovery path

subject to an AMR include phase bus, switchyard bus, high-voltage insulators, transmission

conductors, non-EQ cables and connections, and non-EQ buried cable. The hardware used to

secure or attach switchyard bus and transmission conductors to high-voltage insulators is also

included. Phase bus is a bus that is enclosed (either within its own enclosure or inside a vault)

and is not part of an active component, such as switchgear, load center, or MCC. There are

four types of phase bus-isolated-phase bus, 'nonsegregated phase bus, phase bus enclosed

in a vault, and segregated phase bus. MNGP has two of the types of phase buses mentioned

above. A switchyard bus is an uninsulated, unenclosed, rigid electrical conductor used in

switchyards to connect two or more elements of an electrical power circuit, such as active

disconnect (gang) switches and passive transmission conductors. Included with the switchyard

bus is the hardware used to secure the bus to a high-voltage insulator or transmission

conductor. Switchyard bus connections to an active component (e.g., disconnect (gang) switch,

transformer) are inspected and maintained along with the active components (e.g., disconnect

(gang) switch, transformer) and are not included here. In accordance with the Institute of

Electrical and Electronics Engineers, an insulator is an insulating material in a form designed to

support a conductor physically and separate the conductor electrically from another conductor

or object. Transmission conductors are uninsulated, stranded electrical cables used to

electrically connect two or more elements of an electrical power circuit. The offsite power

system/recovery path boundary includes the 345-kV, 11 5-kV, and 1 3.8-kV system components

from the plant 4.16-kV buses out to the first switchyard breaker, which disconnects the plant

from the 345-kV or 115-kV ring bus or the 13.8-kV system fed from the No. 10 transformer.

In LRA Table 2.5.2-4, the applicant identified the following commodity groups for offsite

power/SBO recovery path that are within the scope of license renewal and subject to an AMR:

* nonsegregated phase bus

* high-voltage insulators

a high-voltage switchyard bus

* high-voltage transmission conductors

" electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

* inaccessible medium voltage (2 kV to 34.5 kV) cable (e.g., installed in conduit or direct

buried) not subject to 10 CFR 50.49 EQ requirements

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The intended functions of the above commodity groups include the following:

" insulate and support'an electrical conductor

• provide electrical connections to specified sections of an electrical circuit

2.5.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.5.2.4 and the USAR using the evaluation methodology

described in SER Section 2.5. The staff conducted its review in accordance with the guidance

described in SRP-LR Section 2.5.

The staff's review of LRA Section 2.5.2.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In RAI 2.5.2-1, dated August 18, 2005, the staff noted that LRA Section 2.5.2.4, under the

description of Offsite Power/SBO Recovery Path, states that the path boundary includes the

345-kV, 11 5-kV, and 13.8-kV system components from the plant 4.16-kV buses out to the first

switchyard breaker, which disconnects the plant from the 345-kV or 11 5-kV ring bus or the

13.8-kV system fed from the No. 10 transformer in the switchyard. The staff requested that the

applicant confirm that the path boundary also includes the associated control circuits subject to

an AMR.

In its response, by letter dated September 16, 2005, the applicant confirmed that the control

circuits for the offsite power/SBO recovery path components within the scope of license renewal

are included within the AMR scope.

Based on its review, the staff found the applicant's response to RAI 2.5.2-1 acceptable because

the applicant verified that the associated control circuits are subject to an AMR. Therefore, the

staff's concern described in RAI 2.5.2-1 is resolved.

2.5.2.4.3 Conclusion

On the basis of its review, the staff concluded that the applicant adequately identified the offsite

power/SBO recovery path components that are within the scope of license renewal, as required

by 10 CFR 54.4(a), and adequately identified the commodity group for the offsite power/SBO

recovery path components that are subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.6 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for

Identifying Structures and Components Subject to Aging Management Review, and

Implementation Results." The staff determined that the applicant's scoping and screening

methodology was consistent with the requirements of 10 CFR 54.21 (a)(1) and the SRP-LR on

the treatment of SR and NSR SSCs within the scope of license renewal and that the SCs

identified as requiring an AMR are consistent with the requirements of 10 CFR 54.4 and

10 CFR 54.21 (a)(1).

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On the basis of its review, the staff concluded that the applicant adequately identified those

systems and components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those systems and components that are subject to an AMR, as required

by 10 CFR 54.21 (a)(1).

2-169

SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) contains the staff's evaluation of the

applicant's aging management programs (AMPs) and aging management reviews (AMRs). In

Appendix B to its license renewal application (LRA), the applicant described the 35 AMPs that it

relies on to manage or monitor the aging of long-lived, passive structures and components

(SCs).

In LRA Section 3, the applicant provided the results of the AMRs for those SCs that it identified

in LRA Section 2 as being within the scope of license renewal and subject to an AMR.

3.0 Applicant's Use of the Generic Aging Lessons Learned Report

In preparing its LRA, Nuclear Management Company, LLC (NMC or the applicant), credited

NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report," issued July 2001. The GALL

Report contains the staff's generic evaluation of the existing plant programs, and it documents

the technical basis for determining when existing programs are adequate without modification,

and when existing programs should be augmented for the extended period of operation. The

evaluation results documented in the GALL Report indicate that many of the existing programs

are adequate to manage the aging effects for particular SCs for license renewal without

change. The GALL Report also contains recommendations on specific areas for which existing

programs should be augmented for license renewal. An applicant may reference the GALL

Report in its LRA to demonstrate that the programs at its facility correspond to those reviewed

and approved in the report.

The GALL Report provides a summary of staff-approved AMPs to manage or monitor the aging

of SCs that are subject to an AMR. If an applicant commits to implementing these

staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA will

likely be reduced, thereby improving the efficiency and effectiveness of the license renewal

review process. The GALL Report also serves as a reference for applicants and staff reviewers

to quickly identify those AMPs and activities that the staff has determined will adequately

manage or monitor aging during the period of extended operation.

The GALL Report identifies (1) systems, structures, and components (SSCs), (2) SC materials,

(3) the environments to which the SCs are exposed, (4) the aging effects associated with the

given materials and environments, (5) the AMPs that are credited with managing or monitoring

the aging effects, and (6) recommendations for further applicant evaluations of aging

management for certain component types.

The staff performed its review in accordance with the requirements of Title 10, Part 54,

"Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code of

Federal Regulations (10 CFR Part 54), the guidance provided in NUREG-1 800, "Standard

Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

issued July 2001, and the guidance provided in the GALL Report.

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In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and

associated AMPs, as described in the "Audit and Review Plan for Plant Aging Management

Reviews and Programs for Monticello Nuclear Generating Plant," dated June 2, 2005. The staff

designed its onsite audits and reviews to maximize the efficiency of its review of the LRA. This

helps reduce the need for formal correspondence between the staff and the applicant, thereby

improving the review's efficiency. In addition, the applicant could respond to questions.and the

staff could readily evaluate the applicant's responses.

3.0.1 Format of the License Renewal Application

The applicant submitted an application that followed the standard LRA format, which was

agreed to by the U.S. Nuclear Regulatory Commission (NRC) staff and the Nuclear Energy

Institute (NEI) (see letter dated April 7, 2003, ADAMS Accession No. ML030990052). This

revised LRA format incorporates lessons learned from the staff's reviews of the previous five

LRAs. These previous applications used a format developed from information gained during an

NRC staff and NEI demonstration project that was conducted to evaluate the use of the GALL

Report in the staff's review process.

The organization of LRA Section 3 parallels Chapter 3 of the SRP-LR. Two types of tables

present the AMR results information in LRA Section 3:

(1) Table 1-Table 3.x.1, where "3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, and "1" indicates that this is the first table

type in LRA Section 3.

(2) Table 2-Table 3.x.2-y, where "3" indicates the LRA section number, "x" indicates the

subsection number from the GALL Report, "2" indicates that this is the second table type

in LRA Section 3, and "y" indicates the system table number.

The content of previous applications for other plants' renewals and the Monticello Nuclear

Generating Plant (MNGP) application is essentially the same. The revised format used for the

MNGP application was intended to modify the tables in Section 3 to provide additional

information that will assist the staff in its review. In Table 1, the applicant summarized the

portions of the application that it considered to be consistent with the GALL Report. In Table 2,

the applicant identified the linkage between the scoping and screening results in Section 2 of

the LRA and the AMRs in Section 3.

3. 0. 1.1 Overview of Table 1

Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the

corresponding tables in the GALL Report, Volume 1. The table is essentially the same as

Tables 1 through 6 provided in the GALL Report, Volume 1, except that the 'Type" column has

been replaced by an "Item Number" column and the "Item Number in GALL" column has been

replaced by a "Discussion" column. The "Item Number" column provides the reviewer with a

means to cross-reference from Table 2 to Table 1. The applicant used the "Discussion" column

to provide clarifying and amplifying information. This column might contain the following types

of information:

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" further evaluation recommended (information or reference to the location of that

information)

" the name of a plant-specific program being used

* exceptions to the GALL Report assumptions

• a discussion of how the line is consistent with the corresponding line item in the GALL

Report when this may not be intuitively obvious

" a discussion of how the item is different from the corresponding line item in the GALL

Report (e.g., when an exception is taken to an AMP that is listed in the GALL Report)

The format of Table .1 allows the staff to align a specific Table 1 row with the corresponding

GALL Report, Volume 1, table row so that the consistency can be easily verified.

3.0.1.2 Overview of Table 2

Table 3.x.2-y (Table 2) provides the detailed results of the AMRs for those components

identified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the

systems or components within a system grouping (e.g., reactor coolant system (RCS),

engineered safety features (ESFs), and auxiliary systems). For example, the ESF group

contains tables specific to the core spray (CSP) system, high-pressure coolant injection (HPC)

system, and residual heat removal (RHR) system,. Table 2 consists of the following nine

columns:

(1) Component Type-The first column identifies the component types from LRA Section 2

that are subject to an AMR. The table lists the component types in alphabetical order.

(2) Intended Function-The second column contains the license renewal intended functions

for the listed component types. LRA Table 2.1-1 contains definitions of intended

functions.

(3) Material-The third column lists the particular materials of construction for the

component type.

(4) Environment-The fourth column lists the environment to which the component types

are exposed. The column indicates the internal and external service environments; LRA

Table 3.0-1 lists these environments.

(5) Aging Effect Requiring Management (AERM)-The fifth column lists aging effects

requiring management. As part of the AMR process, the applicant determined any

AERMs for each combination of material and environment.

(6) AMPs-The sixth column lists the AMPs that the applicant used to manage the identified

aging effects.

(7) NUREG-1 801 Volume 2 Line Item-The seventh column lists the GALL Report item(s)

that the applicant identified as being similar to the AMR results in the LRA. The

applicant compared each combination of component type, material, environment,

AERM, and AMP in LRA Table 2 to the items in the GALL Report. If the GALL Report

contained no corresponding items, the applicant left the column blank. In this way, the

applicant identified the AMR results in the LRA tables that correspond to the items in the

GALL Report tables.

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(8) Table 1 Item-The eighth column lists the corresponding summary item number from

Table 1. If the applicant identified AMR results in Table 2 that are consistent with the

GALL Report, then Table 2 should list the associated Table 3.x.1 line summary item

number. If the GALL Report contains no corresponding item, then the applicant left the

eighth column blank. In this way, the information from the two tables can be correlated.

(9) Notes-The ninth column lists the corresponding notes that the applicant used to

identify how the information in Table 2 aligns with that in the GALL Report. An NEI

working group developed the notes identified by letters, which will be used in future

LRAs. Any plant-specific notes are identified by a number and provide additional

information concerning the consistency of the line item with the GALL Report.

3.0.2 Staff's Review Process

The staff conducted the following three types of evaluations of the AMRs and associated AMPs:

(1) For items that the applicant stated were consistent with the GALL Report, the staff

conducted either an audit or a technical review to determine consistency with the GALL

Report.

(2) For items that the applicant stated were consistent with the GALL Report with

exceptions and/or enhancements, the staff conducted either an audit or a technical

review of the item to determine consistency with the GALL Report. In addition, the staff

conducted either an audit or a technical review of the applicant's technical justification

for the exceptions and the adequacy of the enhancements.

(3) For other items, the staff conducted a technical review per 10 CFR 54.21 (a)(3).

The staff performed audits and technical reviews of the applicant's AMPs and AMRs. These

audits and technical reviews determine whether the effects of aging on SCs can be adequately

managed so that their intended functions can be maintained consistent with the plant's current

licensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.

3.0.2. 1 Review of AMPs

For those AMPs for which the applicant claimed consistency with the GALL Report AMPs, the

staff conducted either an audit or a technical review to verify that the applicant's AMPs were

consistent with the AMPs in the GALL Report. For each AMP that had one or more deviations,

the staff evaluated each deviation to determine (1) whether the deviation is acceptable and (2)

whether the AMP, as modified, will adequately manage the aging effect(s) for which it is

credited. For AMPs that the GALL Report, the staff performed a full review to determine the

adequacy of the AMPs. The staff evaluated the AMPs against the following 10 program

elements defined in SRP-LR Appendix A:

(1) Scope of the Program-Scope of the program should include the specific SCs subject to

an AMR for license renewal.

(2) Preventive Actions-Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected-Parameters monitored or inspected should be

linked to the degradation of the particular SC intended function(s).

3-4
(4) Detection of Aging Effects-Detection of aging effects should occur before there is a

loss of SC intended function(s). This element includes aspects such as method or

technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data

collection, and timing of new/one-time inspections to ensure the timely detection of

aging effects.

(5) Monitoring and Trending-Monitoring and trending should provide predictability of the

extent of degradation, as well as timely corrective or mitigative actions.

(6) Acceptance Criteria-Acceptance criteria, against which the need for corrective action

will be evaluated, should ensure that the SC intended function(s) are maintained under

all CLB design conditions during the period of extended operation.

(7) Corrective Actions-Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process-The confirmation process should ensure that preventive actions

are adequate and that appropriate corrective actions have been completed and are

effective.

(9) Administrative Controls-Administrative controls should provide a formal review and

approval process.

(10) Operating Experience-Operating experience of the AMP, including past corrective

actions resulting in program enhancements or additional programs, should provide

objective evidence to support the conclusion that the effects of aging will be managed

adequately so that the SC intended function(s) will be maintained during the period of

extended operation.

The "Audit and Review Report for Plant Aging Management Reviews and Programs Monticello

Nuclear Generating Plant," dated October 12, 2005 (hereafter referred to as the MNGP audit

and review report), details the staff's audit evaluation of program elements (1) through (6), as

summarized in SER Section 3.0.3.

The staff reviewed the applicant's Corrective Action Program (CAP) and documented its

evaluations in SER Section 3.0.4. The staff's evaluation of the CAP included assessment of the

Corrective Actions, Confirmation Process, and Administrative Controls program elements.

The staff reviewed the information concerning the Operating Experience program element and

documented its evaluation in the MNGP audit and review report. The staff also included a

summary of the program in SER Section 3.0.3.

The staff reviewed the Updated .Safety Analysis Report (USAR) supplement for each AMP to

determine if it adequately describes the program or activity, as required by 10 CFR 54.21 (d).

3.0.2.2 Review of AMR Results

LRA Table 2 contains information concerning whether the applicant's AMRs align with the

AMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the

intended function, material, environment, AERM, and AMP combination for a particular

component type within a system. The applicant identified the AMRs that correlate between a

combination in Table 2 and a combination in the GALL Report using a referenced item number

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in the seventh column, "NUREG-1 801 Volume 2 Line Item." The staff also conducted onsite

audits to verify the correlation. A blank seventh column indicates that the applicant could not

locate an appropriate corresponding combination in the GALL Report. The staff conducted a

technical review of these combinations that were not consistent with the GALL Report. The next

column, 'Table 1 Item," provides a reference number that indicates the corresponding row in

Table 1.

3.0.2.3 USAR Supplement

Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff also

reviewed the USAR supplement that summarizes the applicant's programs and activities for

managing the effects of aging for the period of extended operation, as required by

10 CFR 54.21(d).

3.0.2.4 Documentation and Documents Reviewed

In performing its review, the staff relied heavily on the LRA, the LRA supplements, the SRP-LR,

and the GALL Report.

In addition, during the onsite audit, the staff examined the applicant's justification, as

documented in the staff's MNGP audit and review report, to verify that the applicant's activities

and programs will adequately manage the effects of aging on SCs. The staff also conducted •

detailed discussions and interviews with the applicant's license renewal project personnel and

others with technical expertise relevant to aging management.

3.0.3 Aging Management Programs

Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B.

The table also indicates the GALL Report program that the applicant claimed its AMP was

consistent with (if applicable) and the SSCs for managing or monitoring aging. Finally, the table

provides the section of the SER that documents the staff's evaluation of the program.

Table 3.0.3-1 MNGP's Aging Management Programs

SMNG GALL GLL LRASystems or Structures Staffs

Existing AMPs

10 CFR 50, Appendix J Consistent with XI.S4 containments, structures, 3.0.3.2.1

Program exceptions and component supports

(B2.1.1)

ASME Section XI Consistent with XI.M1 reactor coolant system, 3.0.3.2.2

In-Service Inspection, exception engineered safety features

Subsections IWB,

IWC, and IWD

Program

(B2.1.2)

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MNGP AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s)- 'That Credit the AMP SER Section

ASME Section Xl, Consistent with XI.S3 containments, structures, 3.0.3.2.3

Subsection IWF enhancement and component supports

Program

(B2.1 .3)

Bolting Integrity Consistent with XI.M18 reactor coolant system, 3.0.3.2.4

Program enhancements engineered safety features,

(B2.1.4) auxiliary systems, steam and

power conversion system,

containment, structures, and

component supports

Buried Piping & Tanks Consistent with XI.M34 engineered safety features; 3.0.3.2.5

Inspection Program enhancements auxiliary systems;

(B2.1.5) containments, structures,

and component supports

BWR Control Rod Consistent with XI.M6 reactor coolant system 3.0.3.2.6

Drive Return Line exceptions

Nozzle Program

(B2.1.7)

BWR Feedwater Consistent with XI.M5 reactor coolant system 3.0.3.2.7

Nozzle Program enhancements

(B2.1.8)

BWR Penetrations Consistent with XI.M8 reactor coolant system 3.0.3.2.8

Program exceptions

(B2.1.9)

BWR Stress Corrosion Consistent with XI.M7 reactor coolant system, 3.0.3.2.9

Cracking Program exception engineered safety features,

(B2.1.10) auxiliary systems

BWR Vessel ID Consistent with XI.M4 reactor coolant system 3.0.3.2.10

Attachment Welds exception

Program

(B2.1.1 f)

BWR Vessel Internals Consistent with XI.M9 reactor coolant system 3.0.3.2.11

Program exception and

(B2.1.12) enhancement

Closed-Cycle Cooling Consistent with XI.M21 reactor coolant system, 3.0.3.2.12

Water System Program exceptions and engineered safety features,

(B2.1.13) enhancement auxiliary systems

Compressed Air Consistent with XI.M24 auxiliary systems 3.0.3.2.13

Monitoring Program exceptions and

(B2.1.14) enhancements

Fire Protection Consistent with XI.M26 auxiliary systems; 3.0.3.2.15

Program exception and containments, structures,

(B2.1.17) enhancement and component supports

Fire Water System Consistent with XI.M27 auxiliary systems 3.0.3.2.16

Program enhancement

(B2.1.18) 1

3-7
MNGP AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison' AMP(s) That Credit thie AMP SER Section

Flow-Accelerated Consistent XI.M17 reactor coolant system, 3.0.3.1.2

Corrosion Program engineered safety features,

(82.1.19) auxiliary systems, steam and

power conversion system

Fuel Oil Chemistry Consistent with XI.M30 auxiliary systems 3.0.3.2.17

Program exceptions and

(B2.1.20) enhancements

Inspection of Overhead Consistent with XI.M23 containments, structures, 3.0.3.2.18

Heavy Load and Light exception and and component supports

Load (Related to enhancements

Refueling) Handling

Systems Program

(82.1.22)

Open-Cycle Cooling Consistent XI.M20 engineered safety features, 3.0.3.1.5

Water System Program auxiliary systems, steam and

(82.1.24) power conversion system

Plant Chemistry Consistent with XI.M2 reactor coolant system, 3.0.3.2.19

Program exceptions engineered safety features,

(82.1.25) auxiliary systems, steam and

power conversion system

Primary Containment Consistent XI.S1 containments, structures, 3.0.3.1.6

In-Service Inspection and component supports

Program

(82.1.26)

Protective Coating Consistent with XI.S8 containments, structures, 3.0.3.2.20

Monitoring & enhancement and component supports

Maintenance Program

(82.1.27)

Reactor Head Closure Consistent with XI.M3 reactor coolant system 3.0.3.1.7

Studs Program exceptions

(82.1.28)

Reactor Vessel Consistent with XI.M31 reactor coolant system 3.0.3.2.21

Surveillance Program enhancement

(B2.1.29)

Structures Monitoring Consistent with XI.S6 containments, structures, 3.0.3.2.23

Program enhancements and component supports

(82.1.31)

System Condition Plant-specific NA reactor coolant system; 3.0.3.3.2

Monitoring Program engineered safety features;

(B2.1.32) auxiliary systems; steam and

power conversion system;

containments, structures,

and component supports

3-8
MNGP AMP GALL GALL LRA Systems or Structures Staff's

(LRA Section) Comparison AMP(s) That Credit the AMP SER Section

Thermal Aging & Consistent XI.M1 3 reactor coolant system 3.0.3.1.8

Neutron Irradiation

Embrittlement of Cast

Austenitic Stainless

Steel (CASS) Program

(B2.1.33)

Electrical Equipment Consistent X.E1 electrical and instrumentation 3.0.3.1.9

Subject to and controls

10 CFR 50.49

Environmental

Qualification (EQ)

Requirements Program

(B3.1)

Metal Fatigue of the Consistent with X.M1 reactor coolant system, 3.0.3.2.24

Reactor Coolant enhancement engineered safety features

Pressure Boundary

Program

(B3.2) I I I

New AMPs

Bus Duct Inspection Plant specific NA electrical and instrumentation 3.0.3.3.1

Program and controls

(B2.1.6)

Electrical Cables & Consistent XI.E1 electrical and instrumentation 3.0.3.1.1

Connections Not and controls

Subject to

10 CFR 50.49

Environmental

Qualification

Requirements Program

(B2.1.15)

Electrical Cables Not Consistent with XI.E2 electrical and instrumentation 3.0.3.2.14

Subject to exceptions and controls

10 CFR 50.49

Environmental

Qualification

Requirements Used in

Instrumentation

Circuits Program

(B2.1.16)

Inaccessible Medium Consistent XI.E3 electrical and instrumentation 3.0.3.1.3

Voltage (2kV to and controls

34.5kV) Cables Not

Subject to

10 CFR 50.49 EQ

Requirements Program

(B2.1.21)

One-Time Inspection Consistent XI.M32 reactor coolant system, 3.0.3.1.4

Program engineered safety features,

(B2.1.23) auxiliary systems, steam and

power conversion system

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MNGP AMP GALL GALL LRA.Systems or Structures Staffs

(LRA Section) Comparison.. AMP(s) ihat Credit the AMP SER Section

Selective Leaching of Consistent with XI.M33 engineered safety features, 3.0.3.2.22

Materials Program exception auxiliary systems, steam and

(B2.1.30) power conversion system

3.0.3. 1 AMPs That Are Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL

Report:

" Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental

Qualification (EQ) Requirements Program (B2.1.15)

" Flow-Accelerated Corrosion (FAC) Program (82.1.19)

" Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

Requirements Program (B2.1.21)

" One-Time Inspection Program (B2.1.23)

* Open-Cycle Cooling Water (OCCW) System Program (B2.1.24)

" Primary Containment In-Service Inspection Program (82.1.26)

* Reactor Head Closure Studs Program (B2.1.28)

* Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS) Program (82.1.33)

" Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program (83.1)

3.0.3.1.1 Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Program

Summary of Technical Information in the Application. In LRA Section B2.1.15, the applicant

described the Electrical Cables & Connections* Not Subject to 10 CFR 50.49 EQ Requirements

Program, stating that-this new program is consistent with GALL AMP XI.E1, "Electrical Cables

and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." An

adverse localized environment is a condition in a limited plant area that is significantly more

severe than the specified service environment for the component. An adverse variation in

environment is significant if it could appreciably increase the rate of aging of a component or

have an immediate adverse effect on operability. In most areas of the plant, the actual ambient

environments (e.g., temperature, radiation, or moisture) are less severe than the plant design

environment. However, in a limited number of localized areas, the actual environments may be

more severe than the plant design environment for those areas. Cable and connection

insulation materials may degrade more rapidly than expected in these adverse localized

environments. Since they are not subject to the EQ requirements of 10 CFR 50.49,

"Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power

Plants," the electrical cables and connections covered by this AMP are either not exposed to

harsh accident conditions or not required to remain functional during or following an accident to

which they are exposed. The scope of this program includes accessible non-EQ electrical

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cables and connections, including control and instrumentation circuits, within the scope of

license renewal.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report documents the details of

the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the

AMP described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.E1.

The staff reviewed those portions of AMP B2.1.15, "Electrical Cables & Connections Not

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program," which the

applicant claims are consistent with GALL AMP XI.E1, "Electrical Cables & Connections Not

Subject to 10 CFR 50.49 Environmental Qualification Requirements Program," and found them

consistent with the GALL Report AMP. Because it is consistent with the GALL Report, the AMP

ensures that the effects of aging will be adequately managed. The staff found the applicant's

LRA AMP acceptable because it conforms to the recommended GALL Report AMP.

Ooerating Experience. In LRA Section B2.1.15, the applicant explained tlhat the Electrical

Cables & Connections Not*Subject to 10 CFR 50.49 EQ Requirements Program is a new

site-specific program and therefore does not have any operating experience. However, as

noted in the GALL Report, industry operating experience shows that adverse local

environments caused by heat or radiation for electrical cables and connections have been

shown to exist and produce degradation of insulating material degradation that can be detected

visually.

During the audit and review, the staff asked the applicant how it captures operating experience.

The applicant stated that the site's CAP identifies, tracks, and trends site operating experience

related to all site components. It documents any site component identified as degraded, failed,

or potentially unable to fulfill its intended functions in the site CAP database. The plant

engineering staff then evaluates these.components for the extent of the condition and takes

appropriate followup actions. The plant engineering staff also trends related CAPs to identify

generic issues and addresses trended site issues in program health reports presented to site

management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21,

"Contents of Application-Technical Information," and external operating events reported by the

NRC, Institute of Nuclear Power Operations (INPO), Licensing Information Service (LIS), and

NMC Fleet. The staff reviewed the applicant's response and found it acceptable.

The staff recognized that the CAP, which captures internal and external operating experience

issues, will ensure that the licensee reviews and incorporates operating experience in the

future.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Program will adequately manage the aging effects identified in the LRA for which

this AMP is credited.

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USAR Supplement. In LRA Section A2.1.15, the applicant provided the USAR supplement for

the Electrical Cables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.

Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement to

include the following commitment, documented as commitment 26 in Table A.5:

Prior to the period of extended operation, the MNGP Electrical Cables &

Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Program will be implemented as a new program consistent with

the recommendations of NUREG-1801 Chapter Xl Program XI.E1. The program

will manage the aging of conductor insulation material on cables, connectors,

and other electrical insulation materials that are installed in an adverse localized

environment caused by heat, radiation, or moisture.

The staff reviewed this section and determined that the information in the USAR supplement as

augmented by the commitment adequately describes the program as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Electrical Cables &

Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that

those program elements for which the applicant claimed consistency with the GALL Report are

consistent with the GALL Report. The staff concluded that the applicant demonstrated that the

effects of aging will be adequately managed so that intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.1.2 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. In LRA Section B2.1.1%9 the applicant

described the Flow-Accelerated Corrosion (FAC) Program, stating that this existing program is

consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion." The program implements the

Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R2, "Recommendations for

an Effective Flow-Accelerated Corrosion Program." This program also requires the use of

CHECWORKS as a predictive tool. The program includes (1) an analysis to determine locations

susceptible to flow-accelerated corrosion (FAC), (2) performance of limited baseline

inspections, (3) followup inspections to confirm the predictions, and (4) repairing or replacing

components, as necessary. The MNGP FAC Program includes the response made to Generic

Letter (GL) 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning, dated May 2, 1989."

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent-with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M17.

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During the audit and review, the staff asked the applicant to clarify the minimum allowable wall

thickness defined in the MNGP FAC program. The applicant stated that if degradation is

detected such that the measured wall thickness is less than 87.5 percent of nominal wall

thickness for safety-related (SR) piping or 60 percent of nominal wall thickness for

nonsafety-related (NSR) piping, it will perform an engineering evaluation to determine whether

the degraded component is acceptable for continued use. If the component requires repair or

replacement during the inspection outage, the applicant will initiate a condition

report (CR)/action request (AR) in accordance with the site-specific CAP. If a replacement is

planned for the next refueling outage, the applicant will initiate a work request in accordance

with the site-specific process for work requests/work orders (WOs). In addition to the

engineering evaluation, the applicant will examine adjacent areas to bound the thinning and

assure that the actual minimum wall thickness is measured.

The applicant further evaluated the adequacy of using 60 percent of pipe nominal wall thickness

as a trigger point for an engineering evaluation of NSR piping. The applicant determined that

the 60-percent criterion has technical merit in statistical analysis, but lacks rigorous justification

because the applicant has not performed any plant-specific analysis to ensure its validity for all

cases at MNGP. By letter dated August 11, 2005, the applicant provided responses to

questions raised during the AMP and AMR audits. In this letter, the applicant committed to

revise its FAC Inspection Program to use the industry-accepted 87.5 percent of nominal pipe

wall thickness for NSR piping as a trigger point for an engineering evaluation. The applicant

identified this as commitment 53 in Table A.5 of the USAR supplement provided in its letter

dated March 15, 2006. On the basis of its review, the staff found the applicant's response

acceptable because it adequately addressed the minimum wall thickness evaluation.

The staff reviewed those portions of the MNGP AMP B2.1.19, "Flow-Accelerated Corrosion

Program," that the applicant claimed are consistent with GALL AMP XI.M17, "Flow-Accelerated

Corrosion," and found them consistent with the GALL Report AMP. Because it is consistent with

the GALL Report, the AMP ensures that the effects of aging will be adequately managed. The

staff found the applicant's AMP acceptable because it conforms to the recommended GALL

Report AMP.

Operatinq Experience. In LRA Section B2.1.19, the applicant explained that the FAC wall

thinning problems in single-phase systems have occurred throughout the industry in

feedwater (FW) and condensate systems, and in two-phase piping in extraction steamlines and

moisture separator reheater and FW heater drains. Application of the program at MNGP has

resulted in the identification and replacement of susceptible piping sections with materials more

resistant to FAC (e.g., extraction steam system piping and piping downstream of the moisture

separators). The NRC originally outlined the FAC program in NUREG-1 344,

"Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants," issued 1989,

and implemented it through GL 89-08. The MNGP program has evolved through industry

experience and is now implemented using the guidelines of NSAC-202L-R2 and CHECWORKS

as a predictive tool. Monitoring locations and inspection methods have improved over time

based on industry and plant experience and through the development of new techniques.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's FAC Program will

adequately manage the aging effects at the applicant's plant.

3-13
USAR Supplement. In LRA Section A2.1.19, the applicant provided the"USAR supplement for

the FAC Program. The staff reviewed this section and determined that the information in the

USAR supplement provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's FAC Program, the staff

determined that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. The staff concluded that the applicant

demonstrated that the effects of aging will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.1.3 Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49

EQ Requirements Program

Summary of Technical Information in the Application. In LRA Section B2.1.21, the applicant

described the Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to

10 CFR 50.49 EQ Requirements Program, stating that this new program is consistent with

GALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements." The intended function of insulated cables and

connections is to provide electrical connections to specified sections of an electrical circuit to

deliver voltage, current, or signals. Most electrical cables at MNGP are located in dry

environments. However, some cables may be exposed to condensation and wetting in

inaccessible locations, such as conduits, cable trenches, cable troughs, duct banks,

underground vaults, or direct buried installations. When an energized medium-voltage cable is

exposed to wet conditions for which it was not designed, water treeing or a decrease in the

dielectric strength of the conductor insulation can occur. This can potentially lead to electrical

failure. In this AMP, the applicant takes periodic actions to prevent the exposure of cables to

significant moisture, such as inspecting for water collection in cable manholes and conduit, and

draining water, as needed. In-scope, medium-voltage cables exposed to significant moisture

and significant voltage are tested to provide an indication of the condition of the conductor

insulation. The specific type of test performed will be determined before the initial test, and it will

be a proven test for detecting deterioration of the insulation system as a result of wetting, such

as power factor, partial discharge, polarization index, or other testing that is state-of-the-art at

the time the test is performed.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.E3.

During the audit and review, the staff asked that the applicant explain the process for assuring

that cables in conduit are not subject to significant moisture and, thus, are not subject to

3-14
testing. The applicant indicated that it is impossible to assure that cables in underground

conduit are not exposed to significant moisture. The applicant further noted that the majority of

its underground cables are buried without the use of conduit and are thus subject to significant

moisture and required to be tested. Cables located in underground conduit are also subject to

significant moisture from condensation and required to be tested. In addition, under the

Parameters Monitored or Inspected program element, included as part of MNGP AMP B2.1.21,

"Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

Requirements," the MNGP program will test medium-voltage cables (2 kilovolt (kV) to 34.5 kV)

within the scope of license renewal exposed to moisture (direct buried or in underground

conduit) and energized more than 25 percent of the time. The staff reviewed this response and

found it acceptable.

In the course of its review, the staff noted the applicant's statement that, in the Preventive

Actions program element, it takes periodic actions, like inspecting for water collection in cable

manholes and conduit and draining water as needed, to prevent prolonged exposure of

medium-voltage cables to significant moisture. In the LRA, the applicant stated the following:

Medium voltage cables, for which such actions are taken, are not required to be

tested since operating experience indicates that prolonged exposure to

significant moisture and being energized for significant periods of time are

required to induce this aging effect.

In Request for Additional Information (RAI) B2.1.21-1, dated November 7, 2005, thestaff noted

its position that inaccessible medium-voltage cables be tested and inspected. Therefore, the

staff requested that the applicant remove the line from the LRA indicating that medium-voltage

cables are not required to be tested. In addition, the staff requested that the applicant state the

inspection frequency and its basis.

In its response, by letter dated December 7, 2005, the applicant stated that it will revise the

Preventive Action program element in LRA Section B2.1.21 to delete the following text:

Medium-voltage cables, for which such actions are taken, are not required to be

tested since operating experience indicates that prolonged exposure to

significant moisture and being energized for significant periods of time are

required to induce this effect.

In its letter dated March 15, 2006, the applicant amended the Detection of Aging Effects

program element by adding the following statement:

In addition, the underground electrical vaults (manholes, handholes, etc)

containing cable at MNGP are designed and installed without a concrete bottom.

The electrical vaults are set on natural soil which is porous river sand.

Historically, water accumulation in electrical vaults has not been an issue due to

the natural draining of the porous soil. The inspection frequency for water

collection will be based on actual plant experience. For those electrical vaults

within the scope of license renewal, the initial inspection frequency for water

accumulation will be at least once every two years. The first inspection for

license renewal is to be completed before the period of extended operation.

3-15
Based on its review, the staff found the applicant's response to RAI B2.1.21-1 acceptable. The

staff found that the applicant's response addresses the staff's concern regarding testing and

inspection of water in manholes for inaccessible medium-voltage cables. Therefore, the staff's

concern described in RAI B2.1.21-1 is resolved.

The staff reviewed those portions of MNGP AMP B2.1.21 that the applicant claimed are

consistent with GALL AMP XI.E3 and found them consistent with the GALL Report AMP.

Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be

adequately managed. The staff found the applicant's LRA AMP acceptable because it conforms

to the recommended GALL Report AMP.

Operating Experience. In LRA Section B2.1.21, the applicant explained that the Inaccessible

Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements

Program is a new program with no operating experience. However, as noted in the GALL

Report, industry operating experience shows that cross-linked polyethylene or high-molecular

weight polyethylene insulation materials are most susceptible to water tree formation. The

formation and growth of water trees vary directly with operating voltage. Treeing is much less

prevalent in 4-kV cables than those operated at 13-kV or 33-kV. Minimizing exposure to

moisture also lessens the potential for the development of water treeing.

During the audit and review, the staff asked the applicant how it captures operating experience.

The applicant indicated that the site's CAP identifies, tracks, and trends site operating

experience related to all site components. The applicant documents any site component

identified as degraded, failed, or potentially unable to fulfill its intended functions in the site CAP

database. The plant engineering staff then evaluates these components for the extent of the

condition and takes appropriate followup actions. The plant engineering staff also trends related

CAPs to identify generic issues and addresses trended site issues in program health reports

presented to site management on a scheduled basis. The CAP also addresses issues related to

10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMC Fleet. The

staff reviewed the applicant's response and found it acceptable.

The staff recognized that the CAP, which captures internal and external operating experience

issues, will ensure that operating experience is reviewed and incorporated in the future.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

Requirements Program will adequately manage the aging effects identified in the LRA for which

this AMP is credited.

USAR Supplement. In LRA Section A2.1.21, the applicant provided the USAR supplement for

the Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

Requirements Program.

Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement to

include the following commitment, documented as commitment 36 in Table A.5:

Prior to the period of extended operation, the MNGP Inaccessible

Medium-Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

3-16
Requirements Program will be implemented as a new program consistent with

the recommendations of NUREG-1 801 Chapter XI, Program XI.E3.

The staff reviewed this section and determined that the information in the USAR supplement as

augmented by the commitment adequately describes the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Inaccessible Medium Voltage

(2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff

determined that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. The staff concluded that the applicant

demonstrated that the effects of aging will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.1.4 One-Time Inspection Program

Summary of Technical Information in the Application. In LRA Section B2.1.23, the applicant

described the One-Time Inspection Program, stating that this new program is consistent with

GALL AMP XI.M32, "One-Time Inspection." The MNGP One-Time Inspection Program

addresses concerns with and confirmation for the potential long incubation period for certain

aging effects on SCs. In some cases, (1) an aging effect is not expected to occur but data are

not sufficient to completely rule it out, or (2) an aging effect is expected to progress very slowly.

The activities of the One-Time Inspection Program include (1) determination of the sample size

based on an assessment of materials of fabrication, environment, plausible aging effects, and

operating experience, (2) identification of the inspection locations in the system or component

based on the aging effect, (3) determination of the examination technique, including acceptance

criteria that will be effective in managing the aging effect for which the component is examined,

and (4) evaluation of the need for followup examinations to monitor the progression of any

identified aging degradation. The program will manage the aging effects caused by corrosion,

cracking, erosion, fouling, fretting, or thermal exposure. The program will also verify the

absence of reduction of neutron absorption capacity of boral in the spent fuel pool.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M32.

The staff reviewed those portions of the MNGP AMP B2.1.23, "One-Time Inspection Program,"

that the applicant claimed are consistent with GALL AMP XI.M32 and found them consistent

with the GALL Report AMP. Because it is consistent with the GALL Report, the AMP ensures

that the effects of aging will be adequately managed. The staff found the applicant's AMP

acceptable because it conforms to the recoinmended GALL Report AMP.

3-17
Operating Experience. In LRA Section B2.1.23, the applicant explained that the One-Time

Inspection Program is a new program with no operating experience.

During the audit and review, the staff asked the applicant how it captures operating experience.

The applicant indicated that the MNGP CAP identifies, tracks, and trends site operating

experience related to all site components. The applicant documents any site component

identified as degraded, as failed, or as potentially unable to fulfill its intended functions in the

site CAP database. The plant engineering staff then evaluates these components for the extent

of the condition and takes appropriate followup actions. The plant engineering staff also trends

related CAPs to identify generic issues and addresses trended site issues in program health

reports presented to site management on a scheduled basis. The CAP also addresses issues

related to 10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMC

Fleet. The staff reviewed the applicant's response and found it acceptable.

The staff recognized that the CAP, which captures the internal and external operating

experience issues, will ensure evaluation and incorporation of operating experience for

objective evidence of the adequate management of aging effects.

USAR Supplement. In LRA Section A2.1.23, the applicant provided the USAR supplement for

the One-Time Inspection Program.

Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement to

include the following commitment, documented as commitment 38 in Table A.5:

Prior to the period of extended operation, the MNGP One-Time Inspection

Program will be implemented as a new program consistent with the

recommendations of NUREG-1 801 Chapter XI Program XI.M32, "One-Time

Inspection." This program will include measures to verify the effectiveness of the

following aging management programs: Plant Chemistry Program and Fuel Oil

Chemistry Program. This program will also confirm the absence of age related

degradation in selected components (e.g., flow restrictors, venturis) within

License Renewal scope.

The staff reviewed this section and determined that the information in the USAR supplement as

augmented by the commitment adequately describes the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's One-Time Inspection

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. The staff concluded

that the applicant demonstrated that the effects of aging will be adequately managed so that

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21(d).

3-18
3.0.3.1.5 Open-Cycle Cooling Water System Program

Summary of Technical Information in the Application. In LRA Section B2.1.24, the applicant

described the Open-Cycle Cooling Water (OCCW) System Program, stating that this existing

program is consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System." The

MNGP OCCW System Program relies on the implementation of the recommendations of NRC

GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," dated July

18, 1989, to ensure that the effects of aging on the raw water service water systems will be

managed for the period of extended operation. This program manages the aging effects of

metallic components in water systems (e.g., piping and heat exchangers) exposed to raw,

untreated (e.g., service) water. Corrosion, erosion, and biofouling in SSCs serviced by the

OCCW system cause these aging effects. The program includes (1) surveillance and control of

biofouling, (2) tests to verify heat transfer, and (3) routine inspection and maintenance. The

MNGP OCCW System Program complies with the MNGP response to NRC GL 89-13. The

applicant has incorporated the commitments it made to comply with GL 89-13 into plant

procedures and programs.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M20.

The staff reviewed those portions of the MNGP AMP B2.1.24, "Open-Cycle Cooling Water

System Program," that theapplicant claimed are consistent with GALL AMP XI.M20, "OpenCycle Cooling Water System," and found them consistent with the GALL Report AMP. Because

it is consistent with the GALL Report, the AMP ensures that the effects of aging will be

adequately managed. The staff found the applicant's AMP acceptable because it conforms to

the recommended GALL Report AMP.

Operating Experience. In LRA Section B2.1.24, the applicant explained that the OCCW System

Program has been effective in managing loss of material and heat transfer degradation aging

effects for systems within the scope of the program. Various self-assessments and Nuclear

Oversight Department reviews have demonstrated program effectiveness and have shown that

MNGP has implemented the requirements of GL 89-13. The applicant has documented and

evaluated corrosion and material condition issues in the site CAP.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that the plant-specific operating experience revealed

no degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience, the

staff concluded that applicant's OCCW System Program will adequately manage the aging

effects identified in the LRA for which this AMP is credited.

3-19
USAR Supplement. In LRA Section A2.1.24, the applicant provided the USAR supplement for

the OCCW System Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's OCCW System Program, the

staff determined that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. The staff concluded that the applicant

demonstrated that the effects of aging will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.1.6 Primary Containment In-Service Inspection Program

Summary of Technical Information in the Application. In LRA Section B2.1.26, .he applicant

described the Primary Containment In-Service Inspection Program, stating that this existing

program is consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE." The MNGP

Primary Containment In-Service Inspection Program requires visual examinations of the

accessible surfaces (base metal and welds) of the drywell, torus, vent lines, internal vent

system, penetration assemblies, and associated integral attachments. The program also

requires examination of pressure-retaining bolting and the drywell interior slab moisture barrier.

The program conforms to the applicable requirements of 10 CFR 50.55a, "Codes and

Standards," and the 1992 Edition with 1992 Addenda of the American Society of Mechanical

Engineers (ASME) Boiler and Pressure Vessel Code (ASME Code), Subsection IWE. The

applicant performs a detailed visual examination (VT)-3 and VT-1 examination once during

each 10-year inservice inspection (ISI) interval. This examination occurs either at the end of the

interval or is spread across the three periods that comprise the interval. The applicant performs

general visual examinations that assess the overall structural condition once during each

period. Surface and/or volumetric examination augments visual examination as required to

define the extent of observed conditiOns or to identify deterioration at inaccessible locations.

Limited scope examinations are performed as required to evaluate disassembled bolting and

the condition of the normally submerged torus surface when the suppression pool is drained.

The applicant periodically updates the program as required by 10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.S1.

The applicant stated in MNGP AMP B2.1.26, "Primary Containment In-Service Inspection

Program," that exceptions to ASME Code requirements granted by approved code cases or

relief requests are not considered exceptions to the GALL Report criteria. In addition, the

discussions of some program elements cite a number of relief requests. In all cases, the

applicant reiterated that these are not considered exceptions since the NRC reviewed the

3-20
MNGP IWE program and the program is in accordance with 10 CFR 50.55a with

NRC-approved relief requests.

The staff noted that 10 CFR 54.21 requires the LRA to contain information for each SC within

the scope of license renewal demonstrating that the applicant will adequately manage aging

effects so that intended functions will be maintained consistent with the CLB for the period of

extended operation. The staff questioned the applicant's position that exceptions to ASME

Code requirements granted by code cases or relief requests are not considered exceptions to

the GALL Report.

In its letter dated August 31, 2005, the applicant stated the following:

The statement under the 'NUREG-1 801 Consistency' regarding 'Exceptions to

ASME Code requirements that have been granted by approved Code Cases or

relief requests are not considered to be exceptions to NUREG-1 801 criteria'

should be removed. The statement is not required. ASME Section Xl,

Subsection IWE alternatives expire prior to the period of extended operation.

The statement under the 'Scope of Program' regarding 'These are not

considered exceptions since the MNGP program has been reviewed by the NRC

and is in accordance with 10 CFR 50.55a with NRC approved relief requests'

should be removed. The statement is not required. ASME Section XI,

Subsection IWE alternatives expire prior to the period of extended operation.

The statement under the 'Parameters Monitored or Inspected' regarding 'These

are not considered exceptions since the MNGP program has been reviewed by

the NRC and is in accordance with 10 CFR 50.55a with NRC approved relief

requests' should be removed. The statement is not required. ASME Section Xl,

Subsection IWE alternatives expire prior to the period of extended operation.

The statement under the 'Detection of Aging Effects' regarding 'This is not

considered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved relief

requests' should be removed. The statement is not required. ASME Section XI,

Subsection IWE alternatives expire prior to the period of extended operation.

The statement under the 'Monitor and Trending' regarding 'This is not

considered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved relief

requests' should be removed. The statement is not required. ASME Section Xl,

Subsection IWE alternatives expire prior to the period of extended operation.

The statement under the 'Corrective Actions' regarding 'This is not considered

an exception since the MNGP program has been reviewed by the NRC and is in

accordance with 10 CFR 50.55a with NRC approved relief requests' should be

removed. The statement is not required. ASME Section Xl, Subsection IWE

alternatives expire prior to the period of extended operation.

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The statement under the 'Confirmation Process' regarding 'This is not

considered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved relief

requests' should be removed. The statement is not required. ASME Section Xl,

Subsection IWE alternatives expire prior to the period of extended operation.

The staff found the applicant's position acceptable, because the applicant removed references

stating that relief requests were not considered exceptions to the GALL Report and the relief

requests will not be credited for aging management.

The staff reviewed those portions of the MNGP AMP B2.1.26 that the applicant claimed are

consistent with GALL AMP XI.S1 and found them consistent with the GALL Report AMP.

Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be

adequately managed. The staff found the applicant's AMP acceptable because it conforms to

the recommended GALL Report AMP.

Operating Experience. In LRA Section B2.1.26, the applicant explained that the Primary

Containment In-Service Inspection Program, when implemented in conjunction with the

10 CFR 50, Appendix J Program and special examinations conducted to address specific

industry issues, has demonstrated that aging of the primary containment, the internal vent

system, and steel components within the torus is managed in an effective manner. Special

examinations have verified the absence of significant corrosion in the drywell sand pocket

region and on the normally submerged surfaces of the torus. The applicant also stated that

leakage testing has been effective in early detection of passive isolation barrier deterioration

(active barriers are outside the scope of the AMP). Examinations under the ISI program have

shown that there is no significant corrosion on, or other deterioration of, accessible containment

shell, vent system, and penetration assembly surfaces.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the Primary Containment In-Service

Inspection Program will adequately manage the aging effects identified in the LRA for which the

AMP is credited.

USAR Supplement. In LRA Section A2.1.26, the applicant provided the USAR supplement for

the Primary Containment In-Service Inspection Program. The staff reviewed this section and

determined that the information in the USAR supplement adequately describes the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Primary Containment

In-Service Inspection Program, the staff determined that those program elements for which the

applicant claimed consistency with the GALL Report are consistent with the GALL Report. The

staff concluded that the applicant demonstrated that the effects of aging will be adequately

managed so that intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR

supplement for this AMP and concluded that it adequately describes the program, as required

by 10 CFR 54.21(d).

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3.0.3.1.7 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. In LRA Section B2.1.28, the applicant

described the Reactor Head Closure Studs Program, stating that this existing program is

consistent with GALL AMP XI.M3, "Reactor Head Closure Studs." The MNGP Reactor Head

Closure Studs Program is part of the MNGP ASME Section XI In-Service Inspection Program.

The Reactor Head Closure Studs Program is in accordance with the ASME Code, Section XI,

1995 Edition through the 1996 Addenda, and provides for condition monitoring of the reactor

head closure stud bolting. Replacement reactor head studs available for use at MNGP include

preventive measures described in Regulatory Guide (RG) 1.65, "Material and Inspection for

Reactor Vessel Closure Studs," issued October 1973. The applicant updates the program

periodically as required by 10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and, review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M3.

During the audit and review, the staff noted that the applicant stated the following in LRA

Section B2.1.28:

Exceptions to ASME requirements that have been granted by approved Code

Cases or relief requests are not considered to be exceptions to NUREG-1 801

criteria.

The staff asked that the applicant clarify this statement. The applicant responded that it used

Code Case N-307-2, "Revised Ultrasonic Examination Volume for Class 1 Bolting,

Table IWB-2500-1, Examination Category B-G-1, When the Examinations Are Conducted From

the End of the Bolt or Stud or From the Center-Drilled Hole," dated September 24, 1999, that

applied to the reactor head closure studs. The applicant also used the ASME Code, Section XI,

2001 edition, in lieu of the 1995 edition with addenda through 1996, for repair and replacement

activities; the staff discusses this second exception below. Code users employ code cases

when they cannot or do not want to perform a particular code requirement. This is an allowed

exception to the application of the code by the user and thus is an exception to GALL Report

recommendations. The staff determined that the code case used affected the GALL Report

recommendation and that its use constituted an exception. In its letter dated August 11, 2005,

supplemented by its letter dated August 31, 2005, the applicant stated that it will change its

application to identify the use of the code case as an exception to this AMP. The following

provides the staff evaluation of these exceptions.

Exception 1.: The GALL Report identifies the following recommendation for the Parameters

Monitored or Inspected program element associated with the exception:

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The ASME Section Xl ISI program detects and sizes cracks, detects loss of

material, and detects coolant leakage by following the examination and

inspection requirements specified in Table IWB-2500-1.

In its letter dated August 11, 2005, the applicant stated that when conducting ultrasonic testing

(UT) examinations from the end of the stud to satisfy ASME Code, Section XI, examination

requirements, the examination volume may be limited to a cylinder of 1/4-inch thickness

measured from the minor diameter and the length of the threaded portion of the stud.

The staff confirmed that Table 1 of RG 1.147, Revision 13, "In-Service Inspection Code Case

Acceptability, ASME Section Xl, Division 1," issued January 2004, lists Code Case N-307-2.

Based on this listing, the NRC staff has reviewed this code case and accepted it for general

industry use.

The staff then reviewed both the applicable ASME Code, Section Xl ISI requirements for the

reactor head closure studs and the alternative requirements of Code Case N-307-2. ASME

Code, Section Xl, requires a visual examination of the surfaces of the reactor head closure

nuts, washers, and bushings; a volumetric examination of the vessel flange threads and reactor

head closure stud when examined in place; and a surface and volumetric examination of the

reactor head closure stud when removed. In lieu of the volumetric examination required by

ASME Code, Section Xl, of essentially the entire volume of the reactor head closure stud, Code

Case N-307-2 allows examination of a cylindrical region of 1/4-inch thickness measured from

the minor diameter of the reactor head closure stud and the length of the threaded portion of

the stud. The staff noted that the use of this code case reduces the required examination

volume to the higher stress area of the bolting. The roots of the threads are stress risers and,

hence, likely sites for crack initiation. Cracks at the roots of threads will be perpendicular to

straight beam UT examination from the end of the stud and will create a corner trap for angle

beam UT examination from the center hole. The staff reviewed the difference between the two

requirements and noted that the use of the code case alters the portion of the stud examined

but continues to identify relevant aging effects(i.e., cracking and general corrosion) as the

high-stress portion of the stud continues to be examined. Thus, the staff determined that the

applicant's use of the code case has no impact on the aging effect being managed.

On the basis of a review of the above exception and of operating experience for AMP B2.1.28,

"Reactor Head Closure Studs Program," the staff found this exception acceptable.

Exception 2: The GALL Report identified the following recommendation for the Corrective

Actions program element associated with the exception:

Repair and replacement are in conformance with the requirements of IWB-4000

and IWB-7000, respectively, and the material and inspection guidance of RG

1.65.

In its letter dated August 11, 2005, the applicant stated that the staff has already generically

reviewed and approved the use of the ASME Code, Section XI, 2001 edition, as an alternative

to the 1995 edition with 1996 addenda, for repair and replacement for aging management of

systems and components within the scope of license renewal. Therefore, this alternative will not

affect the aging management of components crediting ISI performed in accordance with ASME

Code, Section Xl. The applicant provided the following justification, published in Volume 69 of

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the Federal Register, pages 58804 and 58816 on October 1, 2004, accompanying the NRC's

amendments to its regulations that incorporated, by reference, certain updated editions and

addenda of the ASME Code for use by NRC licensees:

Accordingly, an applicant may use Subsections IWB, IWC, IWD, IWE, IWF, and

IWL of Section Xl of the ASME BPV Code (2001 Edition and the 2002 and 2003

Addenda) as acceptable alternatives to the requirements of the 1995 Edition up

to and including the 1996 Addenda of the ASME Code, Section XI referenced in

the GALL AMPs without the need to submit these alternatives for NRC review in

its plant-specific license renewal application.

Because the NRC staff has already reviewed and approved this alternative, related to repair

and replacement, generically for aging management of systems and components within the

scope of license renewal, the staff concluded that it does not need to be classified as an

exception and that the affected program element is consistent with the GALL Report.

Exception 3: The GALL Report identified the following recommendations for the Scope of

Program element associated with the exception:

The program includes preventive measures of NRC Regulatory Guide 1.65 to

mitigate cracking. The program is applicable to closure studs and nuts

constructed from materials with a maximum tensile strength limited to less than

1172 MPa (170 ksi) (Nuclear Regulatory Commission [NRC] Regulatory Guide

[RG] 1.65).

The inspectors noted that RG 1.65 recommends that reactor head closure stud material

measured ultimate tensile strength not exceed 170 kilo-pounds per square inch (ksi) to

minimize the likelihood of stress-corrosion cracking (SCC). Hardness tests conducted on the

installed reactor head studs showed that most studs have greater than 170 ksi tensile stress.

The applicant committed to document this exception to NUREG-1801 in the LRA. In its letter

dated March 15, 2006, the applicant stated the following:

The Reactor Head Closure Studs Program does not incorporate the ultimate

tensile strength requirement of NRC Regulatory Guide 1.65 for the existing

reactor head closure studs. NMC considers this an acceptable exception to

NUREG-1801, since these studs are considered susceptible to cracking at

MNGP and NMC continues to manage them through the preventative measures

recommended by Regulatory Guide 1.65 regardless of the tensile strength.

The inspectors found this exception to the GALL Report acceptable because the applicant

considers these studs to be susceptible to cracking, continues to manage the studs using the

other preventive measures of RG 1.65, continues to conduct UT and surface examinations on a

10- year interval, and, to date, has identified no apparent discontinuities.

The staff reviewed those portions of AMP B2.1.28 that the applicant claimed are consistent with

GALL AMP XI.M3 and found them consistent. The staff found the applicant's AMP acceptable

because it conforms to the recommended GALL Report AMP with the exceptions described.

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Operating Experience. In LRA Section B2.1.28, the applicant explained that the Reactor Head

Closure Studs Program has been effective in managing the aging effects of reactor pressure

vessel (RPV) closure studs. The applicant has considered plant operating experience in the

evaluation of stud performance. The MNGP inspection and testing methodologies have

detected no cracking, nondestructive examination (NDE) indications, or aging effects for the

RPV studs. Intergranular SCC (IGSCC) was seen in two RPV head studs at another plant. In

response to this incident, MNGP performed field hardness testing and UT examination of the

reactor head studs removed from the reactor cavity during the 1991 outage, evaluated the test

results, and evaluated the original certified material test reports. It found no evidence of RPV

head stud cracking.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

Reactor Head Closure Stud Program will adequately manage the aging effects identified in the

LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.28, the applicant provided the USAR supplement for

the Reactor Head Closure Studs Program. The staff reviewed this section and determined that

the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's Reactor Head Closure Studs

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. The staff concluded

that the applicant demonstrated that the effects of aging will be adequately managed so that

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21 (d).

3.0.3.1.8 Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS) Program

Summary of Technical Information in the Application. In LRA Section B2.1.33, the applicant

described the Thermal Aging & Neutron -Irradiation Embrittlement of CASS Program, stating

that this existing program is consistent with GALL AMP XI.M13, "Thermal Aging and Neutron

Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)." The MNGP Thermal Aging

and Neutron Irradiation Embrittlement of CASS Program monitors the aging effects of loss of

fracture toughness on the intended function of the component by performing examinations on

CASS reactor vessel internal components as part of the MNGP ASME Section Xl In-Service

Inspection Program. The Thermal Aging and Neutron Irradiation Embrittlement of CASS

Program is in accordance with ASME Code, Section Xl, Subsection IWB, Category B-i1 and

B-2 requirements, and provides for condition monitoring 6f the CASS components. The

applicant performs additional enhanced visual inspections that incorporate the requirements of

the Boiling Water Reactor Vessel and Internals Project (BWRVIP) to detect the effects of loss

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of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS

reactor vessel internals. The applicant updates the program periodically as required by

10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M13.

During the audit and review, the staff questioned the applicant regarding the screening criteria

for determining the susceptibility of CASS components to thermal aging. The applicant stated

that it does not address this screening process; instead, the program includes all CASS reactor

vessel internal components. These components consist of jet pump assembly castings, the

orifice fuel support casting, and the guide tube base casting. The staff found this approach

conservative and therefore acceptable.

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP program elements. In its letter dated August 31,

2005, the applicant identified the following exception to the GALL Report program element.

Exception: The GALL Report identifies the following recommendations for the Corrective

Actions program element associated with the exception taken:

Repair is in conformance with IWA-4000 and IWB-4000, and replacement is in

accordance with IWA-7000 and IWB-7000.

In its letter dated August 11, 2005, the applicant stated that an approved alternative allows the

use of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996

addenda for repair/replacement activities. Section 3.0.3.1.7 of the SER provides the staff's

evaluation of this exception.

Because the NRC has already reviewed and approved this alternative, relating to repair and

replacement, generically for aging management of systems and components within the scope

of license renewal, the staff concluded that it does not need to be classified as an exception

and that, with regard to this item, the affected program element is consistent with the GALL

Report.

The staff reviewed those portions of AMP B2.1.33, "Thermal Aging & Neutron Irradiation

Embrittlement of Cast Austenitic Stainless Steel (CASS) Program," that the applicant claimed

are consistent with GALL AMP XI.M13 and found them consistent. The staff found the

applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with

the exception described.

Operating Experience. In LRA Section B2.1.33, the applicant explained that the Thermal Aging

& Neutron Irradiation Embrittlement of CASS Program has been effective in managing aging

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effects due to thermal aging and neutron irradiation embrittlement. The applicant periodically

examines materials within the scope of the program and evaluates them for corrective action as

needed. In addition to ASME inspection requirements, the applicant follows vendor guidance

(e.g., BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals

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

Evaluation Guidelines").

In addition, the staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's Thermal Aging &

Neutron Irradiation Embrittlement of CASS Program will adequately manage the aging effects

identified in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.33, the applicant provided the USAR supplement for

the Thermal Aging & Neutron Irradiation Embrittlement of CASS Program. The staff reviewed

this section and determined that the information in the USAR supplement adequately describes

the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Thermal Aging & Neutron

Irradiation Embrittlement of CASS Program, the staff determined that those program elements

for which the applicant claimed consistency with the GALL Report are consistent with the GALL

Report. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21 (d).

3.0.3.1.9 Electrical Equipment Subject to 10 CFR 5 0.49 EQ Requirements Program

Summary of Technical Information in the Application. In LRA Section B3.1, the applicant

describedthe Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program,

stating that this existing program that is consistent with GALL AMP X.E1, "Environmental

Qualification (EQ) of Electric Components." The purpose of the MNGP EQ program is to ensure

that SR electrical equipment is capable of performing its function in a harsh environment

(effects of a loss-of-coolant accident (LOCA), high-energy line break (HELB), or post-LOCA

radiation) and is qualified in accordance with the Equipment Qualification Final Rule,

10 CFR 50.49, dated February 22, 1983. This program describes EQ program attributes, and

how those attributes ensure that the EQ program remains effective throughout the license

renewal period (60 years).

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's

evaluation of this AMP. The staff determined that this AMP is consistent with the AMP

described in the GALL Report, including the associated operating experience attribute.

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The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's MNGP audit and review report, which assesses the consistency

of the AMP elements with GALL AMP X.EI.

The staff reviewed those portions of AMP B3.1, "Electrical Equipment Subject to 10 CFR 50.49

EQ Requirements Program," that the applicant claimed are consistent with GALL AMP X.E1

and found them consistent. Because it is consistent with the GALL Report, the AMP ensures

that the effects of aging will be adequately managed. The staff found the applicant's AMP

acceptable because it conforms to the recommended GALL Report AMP.

Operatina Experience. In LRA Section B3.1, the applicant explained that the MNGP EQ

program includes monitoring and assessment of industry information in order to assess its

impact on EQ components at MNGP. The EQ Coordinator is responsible for reviewing the

disposition of such information, as well as subsequent assignment of actions to be taken, and

confirming that completion of the actions has satisfactorily addressed potential MNGP EQ aging

issues. The following examples provide objective evidence that the MNGP EQ program is

responsive to externally identified operating experience items as well as proactive in

self-identification activities:

" An NRC safety system design inspection, conducted in March 2003, resulted in two

green findings and four corrective actions.

" A nuclear oversight quality assurance (QA) assessment in June 2003 resulted in no

findings.

" The 2001 internal self-assessment resulted in a determination of effective

implementation, but noted specific areas needing improvement and additional

recommendations for continued improvement.

* The applicant periodically performs program health reviews to measure the acceptability

of the program and identify improvements as applicable in accordance with MNGP and

NMC Fleet procedures.

* The applicant conducts operating experience reviews of EQ issues identified at other

sites and processes these items through the CAP.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the Electrical Equipment Subject to

10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects observed

at the applicant's plant.

USAR Supplement. In LRA Section A4.1, the applicant provided the USAR supplement for the

Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed

this section and determined that the information in the USAR supplement adequately describes

the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Electrical Equipment Subject

to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements

for which the applicant claimed consistency with the GALL Report are consistent with the GALL

Report. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

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the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21(d).

3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions or Enhancements

In LRA Appendix B, the applicant identified the following AMPs that are, or will be, consistent

with the GALL Report, with exceptions or enhancements:

* 10 CFR 50, Appendix J Program (B2.1.1)

* ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD

Program (B2.1.2)

0 ASME Section Xl, Subsection IWF Program (82.1.3)

0 Bolting Integrity Program (B2.1.4)

• Buried Piping & Tanks Inspection Program (B2.1.5)

a BWR Control Rod Drive (CRD) Return Line Nozzle Program (B2.11.7)

a BWR FW Nozzle Program (B2.1.8)

* BWR Penetrations Program (B2.1.9)

* BWR Stress Corrosion Cracking (SCC) Program (12.1.10)

* BWR Vessel Inside Diameter (ID) Attachment Welds Program (B2.1.11)

* BWR Vessel Internals Program (82.1.12)

• Closed-Cycle Cooling Water (CCCW) System Program (B2.1.13)

* Compressed Air Monitoring Program (82.1.14)

* Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in

Instrumentation Circuits Program (B2.1.16)

* Fire Protection Program (B2.1.17)

* Fire Water System Program (B2.1.18)

* Fuel Oil Chemistry Program (82.1.20)

* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program (82.1.22)

* Plant Chemistry Program (82.1.25)

• Protective Coating Monitoring & Maintenance Program (82.1.27)

" Reactor Vessel Surveillance Program (B2.1.29)

" Selective Leaching of Materials Program (82.1.30)

• Structures Monitoring Program (82.1.31)

" Metal Fatigue of the Reactor Coolant Pressure Boundary Program (83.2)

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For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions or

enhancements, the staff performed an audit to confirm that those attributes or features-of the

program for which the applicant claimed consistency with the GALL Report are indeed

consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to

determine whether they are acceptable and adequate. The following sections document the

results of the staff's audit and reviews.

3.0.3.2.1 10 CFR 50, Appendix J Program

Summary of Technical Information in the Application. In LRA Section B2.1.1, the applicant

described the 10 CFR 50, Appendix J Program, stating that this existing program is consistent,

with exceptions, with GALL AMP XI.S4, "10 CFR Part 50, Appendix J." The MNGP 10 CFR 50,

Appendix J Program specifies pneumatic pressure tests and visual examinations to verify the

structural and leak-tight integrity of the primary containment. An overall (Type A) pressure test

assesses the capacity of the containment to retain design-basis accident (DBA) pressure. This

test also measures total leakage through the containment pressure-retaining boundary. Local

(Type B & C) tests measure leakage through individual penetration isolation barriers. These

barriers are maintained as required to keep overall and local leakage under technical

specification (TS) and plant administrative limits. The applicant performs tests at intervals

determined by the risk and performance factors applicable to each tested item in accordance

with governing regulations and standards. Visual examinations are performed before each Type

A test. The applicant also performs these examinations at least once during each containment

ISI period in which no Type A test is conducted. The examinations are performed to detect

corrosion and other types of deterioration on the accessible surfaces of the containment.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.S4.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.S4 in the GALL Report.

Exception 1.: The GALL Report identifies the following recommendation for the Scope of

Program element associated with the exception taken:

The scope of the containment LRT program includes all pressure-retaining

components. Two types of tests are implemented. Type A tests are performed to

measure the overall primary containment integrated leakage rate which is

obtained by summing leakage through all potential leakage paths including

containment welds, valves, fittings, and components that penetrate containment.

Type B tests are performed to measure local leakage rates across each

pressure-containing or leakage-limiting boundary for containment penetrations.

Type A and B tests described in 10 CFR Part 50, Appendix J, are acceptable

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methods for performing these LRTs. Leakage testing for containment isolation

valves (normally performed under Type C tests), if not included under this

program, is included under LRT programs for systems containing the isolation

valves.

In the LRA, the applicant stated that main steam isolation valves (MSIVs) are tested at

25 pounds per square inch gauge (psig) instead of at an accident pressure of 42 psig. The

applicant indicated that Section II1.C.2 of Appendix J, "Primary Reactor Containment Leakage

Testing for Water-Cooled Power Reactors," to 10 CFR Part 50, "Domestic Licensing of

Production and Utilization Facilities," requires, in part, that Type C testing be performed at the

peak calculated accident pressure, which for MNGP is 42 psig. The outboard MSIVs are tested

by pressurizing the volume between the inboard and outboard valves. The inboard MSIVs at

MNGP are angled (Y-pattern globe) in the main steamlines for better closure characteristics. A

test pressure at the peak calculated accident pressure (42 psig) acting under the inboard valve

disc could lift the disc off its seat and cause excessive leakage into the vessel. The NRC has

approved Type C testing of these valves at a reduced pressure of 25 psig as part of a request

for relief (letter from Darrell G. Eisenhut, NRC, to D.M. Musolf, NMC, dated June 3, 1984). The

staff determined that the inboard valves are the same design as the valves evaluated by the

NRC and that a test pressure alternative in the leakage test will have no impact on aging

management. Therefore, the staff concluded that this exception is acceptable.

Exception 2: The GALL Report identifies the following recommendation for the Monitoring and

Trending program element associated with the exception taken:

Because the LRT program is repeated throughout the operating license period,

the entire pressure boundary is monitored over time. The frequency of these

tests depends on which option (A or B) is selected. With Option A, testing is

performed on a regular fixed time interval as defined in 10 CFR Part 50,

Appendix J. In the case of Option B, the interval for testing may be increased on

the basis of acceptable performance in meeting leakage limits in prior tests.

Additional details for implementing Option B are provided in NRC Regulatory

Guide 1.163 and NEI 94-01, Rev. 0.

In the LRA, the applicant stated that the Type A test interval is extended, on a one-time basis,

to 15 years, exceeding the 10-year interval limit in NEI 94-01, "Industry Guideline for

Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," issued March 1996.

The applicant stated that MNGP is currently under Option B, "Performance-Based

Requirement," of Appendix J to perform the Type A containment integrated leakage rate test. In

accordance with Option B provisions and acceptable Type A test performance history, the Type

A testing will occur at a frequency of 10 years. The most recent Type A test was in March 1993;

thus, the applicant will have to perform the subsequent test no later than March 2003. Following

general industry practice, the applicant submitted a request for a one-time test interval

extension to 15 years based on a plant-specific, risk-based evaluation. The staff approved this

request in a letter from L.M. Padovan, NRC, to D.L. Wilson, NMC, dated March 31, 2003;

therefore, MNGP will have to perform one Type A test no later than March 2008, before the

period of extended operation. The frequency of future Type A tests will be determined on the

basis of the next Type A test results and the limit set forth in Appendix J, Option B.

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The staff found that, in addition to the integrated leakage test, Type A test requirements include

visual examination of the containment exterior and interior to detect conditions that might

adversely affect structural integrity or leak tightness. The applicant performs an examination

before each Type A test and between tests at nominal intervals of 40 months. Because MNGP

followed its CLB in having a Type A test interval extended once to 15 years ending before the

period of extended operation and the additional visual examination requirements are in place,

the staff found this exception acceptable.

The staff reviewed those portions of the AMP B2.1.1, "10 CFR 50, Appendix J Program," that

the applicant claimed are consistent with GALL AMP XI.S4 and found them consistent. The

staff found the applicant's AMP acceptable because it conforms to the recommended GALL

Report AMP with the exceptions as described above.

Operating Experience. In LRA Section B2.1.1, the applicant explained that the 10 CFR 50,

Appendix J Program tests conducted under the program have been effective principally in

detecting developing leakage through containment isolation valves, which, as active

components, are outside the scope of the AMP. Testing has also detected developing leakage

in both an electrical penetration conductor seal and a hot piping penetration expansion bellows.

The applicant corrected both of these conditions while the leakage was still small. MNGP is

committed to the risk- and performance-based program defined by Option B of Appendix J".

This approach uses plant- and industrywide operating experience as the bases for defining the

performance and risk factors, which, in turn, are used to determine testing intervals. Using this

approach enhances the effectiveness of the program as an aging management tool by

concentrating testing and maintenance resources on components that have higher risk and/or a

history of high leakage.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's 10 CFR 50, Appendix J

Program will adequately manage the aging effects identified in the LRA for which this AMP is

credited.

USAR Supplement. In LRA Section A2.1.1, the applicant provided the USAR supplement for

the 10 CFR 50, Appendix J Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's 10 CFR 50, Appendix J

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the exceptions and the associated justifications and determined that the AMP, with the

exceptions, is adequate to manage the aging effects for which it is credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

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10 CFR 54.21 (d).

3.0.3.2.2 ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program

Summary of Technical Information in the Application. In LRA Section B2.1.2, the applicant

described the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD

Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M1,

"ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The MNGP ASME

Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD Program is part of the

MNGP ASME Section XI In-Service Inspection Program. This program is in accordance with the

ASME Code, Section Xl, 1995 edition through the 1996 addenda and is subject to the

limitations and modifications of 10 CFR 50.55a. The program provides for condition monitoring

of Class 1, 2, and 3 pressure-retaining components and their integral attachments. The

applicant inspects Class 1 and 2 piping in accordance with the risk informed ISI (RI-ISI)

program as described in the EPRI Topical Report (TR)-1 12657, Revision B-A, "Revised Risk

Informed In-Service Inspection Evaluation Procedure." The NRC has approved the use of RI-ISI

in a safety evaluation (SE) documented in an NRC letter dated July 24, 2002, "Monticello

Nuclear Generating Plant-Risk Informed In-Service Inspection Program (TAC No. MB3819)."

The applicant updates the program periodically as required by 10 CFR 50.55a. The Plant

Chemistry Program augments this program where applicable.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M1.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M1 in the GALL Report.

Exceptions 1 and 2: The GALL Report recommends the following for the Scope of Program

element associated with the exception taken:

The ASME Section XI program provides the requirements for ISI, repair, and

replacement. The components within the scope of the program are specified in

Subsections IWB-1 100, IWC-1 100, and IWD-1 100 for Class 1, 2, and 3

components, respectively, and include all pressure-retaining components and

their integral attachments in light-water cooled power plants. The components

described in Subsection IWB-1 220, IWC-1 220 and IWD-1 220 are exempt from

the examination requirements of Subsections IWB-2500, IWC-2500, and

IWD-2500.

In the LRA, the applicant stated that, pursuant to 10 CFR 50.55a(b)(2)(xi), it uses the

requirements of IWB-1220 in the 1989 edition of the ASME Code, Section Xl, for Class 1 piping

instead of the 1995 edition of the ASME Code, Section XI, with the 1996 addenda and that,

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pursuant to 10 CFR 50.55a(b)(2)(xxi)(B), reused CRD bolting must meet examination

requirements for Table IWB-2500-1, Category B-G-2, Item B7.80, of the 1995 edition of the

ASME Code, Section XI.

The staff determined that both of the items that the applicant identified as exceptions are, in

fact, requirements codified in 10 CFR 50.55a and that the Scope of Program program element

in the GALL Report mentions no specific ASME Code, Section XI, edition or addenda. The staff

asked the applicant why it considered these items exceptions to the GALL Report. The

applicant stated that it "conservatively" identified these items as exceptions solely because they

are requirements not contained in the ASME Code, Section XI, 1995 edition through 1996

addenda identified in the GALL Report program description for this AMP. The applicant stated

that these codified requirements result in inspections that otherwise will not be required by the

1995 edition through 1996 addenda of the ASME Code, Section Xl. Because the items

identified by the applicant are requirements codified in 10 CFR 50.55a and necessitate more

stringent examinations than the ASME Code, Section Xl, 1995 edition~through 1996 addenda

would otherwise call for, the staff found these exceptions acceptable.

During the audit and review, the staff asked the applicant whether its approved ISI relief

requests or code cases affect any of the AMP elements. The applicant stated that code cases

and relief requests for the MNGP ASME Section XI In-Service Inspection, Subsections IWB,

IWC, IWD, and IWF Program are valid for approximately 21 months into the period of extended

operation and that the current inspection interval ends on May 31, 2012. In addition, the

applicant provided results of its reevaluation of code cases and relief requests as documented

in its letter dated August 31, 2005. That reevaluation identified six additional exceptions

(Exceptions 3 through 8) to the GALL Report program elements. The following paragraphs

describe and evaluate these additional exceptions to the GALL Report.

Exception 3: The GALL Report identifies the following recommendation for the Detection of

Aging Effects program element associated with the exception taken:

Category B-G-1 specifies volumetric examination of studs in place, from the top of the

nut to the bottom of the flange hole; surface and volumetric examination of studs when

removed; volumetric examination of flange threads; and visual VT-1 examination of the

surfaces of nuts, washers, and bushings.

In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-Service

Inspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case

N-307-2, which revises the UT examination volume for Class 1 bolting.

Table 1 of RG 1.147 lists Code Case N-307-2. The applicant categorized implementation of

this code case as an exception to the GALL Report because the description of the Detection of

Aging Effects program element in GALL Report AMP XI.M1 references ASME Code,

Section XI, Table IWB-2500-1, Examination Category B-G-1. The applicant stated that the only

Class 1 bolts at MNGP with center holes are the reactor head closure studs and the reactor

recirculation (REC) pump bolts. The applicant also stated that provisions of this code case were

added to Table IWB-2500-1, Figure IWB-2500-12, and Appendix VIII, Supplement 8, 1.1(c), to

the 2000 addenda of the ASME Code, Section Xl. The applicant stated that this code case

changes the portion of the bolt evaluated but will still detect the presence of the relevant aging

effect. Because this code case only changes the portion of the component examined and

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continues to examine all applicable components in a way that will detect relevant aging effects,

the staff concluded that this exception to the GALL Report is acceptable.

Exception 4: The GALL Report identifies the following recommendation for the Monitoring and

Trending program element associated with the exception taken:

For Class 1, 2, or 3 components, the inspection schedule of IWB-2400,

IWC-2400, or IWD-2400, respectively, and the extent and frequency of

IWB-2500-1, IWC-2500-1, or IWD-2500-1, respectively, provides for timely

detection of degradation.

In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-Service

Inspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case

N-526, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section Xl,

Division 1," issued January.2004, which provides alternative requirements for successive

inspections mandated by IWB-2420 and IWC-2420 when areas of the vessel are found, by

volumetric examinations, to contain subsurface flaws.

Table 1 of RG 1.147 lists Code Case N-526. The applicant categorized implementation of this

code case as an exception to the GALL Report because the successive inspections required by

IWB-2420 and IWC-2420 may be waived when a flaw is found acceptable for continued service

in accordance with IWB-3600. In its letter dated August 11, 2005, the applicant stated that

vessel aging effects are still managed and that any flaws for which successive inspections are

waived are required to be acceptable for continued service in accordance with IWB-3600. The

applicant also stated that the ASME Code, Section Xl, requires that the sequence of

component examinations established during the first inspection interval be repeated during

each successive inspection interval to the extent practical. Because any flaws are determined to

be acceptable in accordance with IWB-3600 and component examinations are required to be

repeated during successive inspection intervals (so that any flaw area will be reexamined at

least once in each inspection interval), the staff concluded that this exception to the GALL

Report is acceptable.

Exception 5: The GALL Report identifies the following recommendation for the Detection of

Aging Effects program element associated with the exception taken:

Class 1 Components, Table IWB-2500-1

Examination Category B-D, for full penetration welds of nozzles in reactor

vessels, pressurizers, steam generators (primary side), and heat exchangers

(primary side): This category specifies volumetric examination of all

nozzle-to-vessel welds and the nozzle inside radius.

In its letter dated August 11, 2005, the applicant stated that its ASME Section Xl In-Service

Inspection, Subsections IWB, IWC, and IWD Program will deviate from the requirements of

ASME Code, Section XI, Table IWB-2500-1 and Figure IWB-2500-7(b) with regard to the

examination volume for Category B-D components (full penetration welded nozzles in vessels).

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The applicant identified that, based on its implementation of ASME Code, Section Xl, Code

Case N-613-1, "Ultrasonic Examination of Penetration Nozzles in Vessels, Examination

Category B-D, Item Nos. B3.10 and B3.90, Reactor Nozzle to Vessel Welds, Figs. IWB-2500-

7(a), (b), and (c), Section XI, Division 1,," issued June 2001, examination of Category B-D

components will deviate from the requirements of the 1995 edition through 1996 addenda of

ASME Code, Section XI, Table IWB-2500-1, Item No B3.90 and from the requirements of

ASME Code, Section XI, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires

that a minimum volume of material equal to a distance of one-half the reactor vessel shell

thickness (i.e., a distance of approximately 2-1/2 inches for MNGP) be included in the

examination volume on each side of the weld; however, the applicant's ASME Section XI

In-Service Inspection, Subsections IWB, IWC, and IWD Program at MNGP, instead, includes a

reduced examination volume of one-half inch of base metal on each side of the widest portion

of.the weld. The applicant provided the following technical justification for the reduction in

examination volume:

The required examination volume for the reactor vessel pressure retaining

nozzle-to-vessel welds extends far beyond the weld into the base metal, and is

unnecessarily large. The proposed alternative re-defined the examination volume

boundary to 1⁄2 inch of base metal on each side of the widest portion of the weld,

removing from examination the base metal that was extensively examined during

prior inspections, and that is not in the high residual stress region associated

with the weld.

The creation of flaws during plant service in the volume excluded from the

proposed reduced examination is unlikely because of the low stress in the base

metal away from the weld. The stresses caused by welding are concentrated at

or near the weld. Cracks, should they initiate, occur in the high-stressed areas of

the weld. These high-stress areas are contained in the volume that is defined by

Code Case N-613-1 and are thus subject to examination. During previous

examinations, no indications exceeding the allowable limits of the preservice or

Inservice criteria were found in the reactor vessel nozzle to shell examination

volumes including the base metal areas proposed for exclusion from examination

in this request.

The staff reviewed the applicant's description and technical justification for this exception

summarized in the preceding paragraph. The staff also reviewed the applicant's request for

relief, "Request for Authorization to Utilize Code Case N-613-1 ," dated February 27, 2004,

which provides a similar technical justification and includes tables of previous examination

results. Because the examination volume will still include the heat-affected regions of base

metal around the welds where new cracks are most likely to occur and previous examinations of

the base metal beyond the heat-affected regions have detected no unacceptable conditions, the

staff concluded that this exception is acceptable.

Exception 6: The GALL Report identifies the following recommendation for the Corrective

Actions program element associated with the exception taken:

For Class 1, 2, and 3, respectively, repair is in conformance with IWB-4000,

IWC-4000, and IWD-4000, and replacement according to IWB-7000, IWC-7000,

and IWD-7000. Approved BWRVIP-44 and BWRVIP-45 documents,

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respectively, provide guidelines for weld repair of nickel alloys and for weldability

of irradiated structural components.

In its letter dated August 11, 2005, the applicant stated that an approved alternative allows the

use of the 2001 edition of the ASME Code, Section XI, in lieu of the 1995 edition with the 1996

addenda for repair/replacement activities. Section 3.0.3.1.7 of this SER provides the-staff's

evaluation of this exception.

On the basis that the NRC staff has already reviewed and approved this alternative related to

repair and replacement generically for aging management of systems and components within

the scope of license renewal, the staff concluded that it is not an exception and that the affected

program element is consistent with the GALL Report.

Exception .7: The GALL Report identifies the following recommendation for the Detection of

Aging Effects program element associated with the exception taken:

• Components are examined and tested as specified in Tables IWB-2500-1,

IWC-2500-1, and IWD-2500-1, respectively, for Class 1, 2, and 3 components.

The tables specify the extent and schedule of the inspection and examination

methods for the components of the pressure-retaining boundaries. Alternative

approved methods that meet the requirements of IWA-2240 are also specified in

these tables.

In its letter dated August 11, 2005, the applicant stated that its ASME Section Xl In-Service

Inspection, Subsections IWB, IWC, and IWD Program includes an RI-ISI methodology that

provides an alternative to the ASME Code, Section Xl, ISI requirements as to (1) the number of

locations inspected, (2) the locations inspected, and (3) the method of inspection. This

alternative applies to welds in ASME Code, Section XI, Categories B-F (Class 1 pressure

retaining dissimilar metal welds in vessel nozzles), B-J (Class 1 pressure retaining welds in

piping), C-F-1 (Class 2 pressure retaining welds in austenitic stainless steel or high-alloy

piping), and C-F-2 (Class 2 pressure retaining welds in carbon or low-alloy steel piping).

The applicant submitted a description of its RI-ISI program in its letter dated December 18,

2001, "Alternative to the ASME Boiler and Pressure Vessel Code Section Xl Requirements for

Class 1 and 2 Piping Welds-Risk Informed In-Service Inspection Program.". In a letter,

"Monticello Nuclear Generating Plant-Risk-Informed In-Service Inspection Program (TAC No.

MB3818)," dated July 24, 2002, the NRC documents authorization for the applicant's Ri-ISI

program during the current (fourth) 10-year ISI interval.

In its letter dated August 11, 2005, supplemented by its August 31, 2005, letter, the applicant

justified continuation of its RI-ISI program into the period of extended operation:

...The RI-ISI program maintains the fundamental requirements of ASME

Section XI, such as the examination technique, examination frequency, and

acceptance criteria. Although the RI-ISI program reduces the number of required

examination locations, it maintains an acceptable level of quality and safety

pursuant to 10 CFR 50.55a(a)3, by focusing inspections on the most safety

significant welds with nondestructive examination techniques that are more

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focused towards finding the type of expected degradation as well as the types of

flaws and degradation found during traditional inspections.

A systematic approach was used to identify component susceptibility to common

degradation mechanisms and to categorize these degradation mechanisms into

the appropriate degradation categories with respect to their potential to result in

a postulated leak or rupture in the pressure boundary. An evaluation to

determine the susceptibility of components to a particular degradation

mechanism that may be a precursor to a leak or rupture in the pressure

boundary, and an independent assessment of the consequences of a failure at

that location were performed. Industry and plant-specific piping operating

experience was used to identify piping degradation mechanisms and failure

modes, and consequence evaluations performed used probabilistic risk

assessment to establish safety ranking of piping segments for selecting new

inspection locations. The degradation mechanisms identified in the RI-ISI

Program include thermal fatigue including thermal stratification, cycling, and

striping (TASCS) and thermal transients (TT); intergranular stress corrosion

cracking (IGSCC); and flow-accelerated corrosion (FAC). The consequences of

pressure boundary failures were evaluated and ranked on their impact on core

damage and early release. Therefore, redistributing the welds to be inspected

with consideration of the safety significance of the segments provides assurance

that segments whose failure have a significant impact on plant risk receive an

acceptable and improved level of inspection.

The RI-ISI examinations result in improved detection of service-related

degradations over those currently required by ASME Section XI. Therefore, the

aging effect of cracking continues to be adequately managed for the piping

welds.

The staff reviewed the applicant's technical justification for this exception. In addition, the staff

reviewed the applicant's detailed RI-ISI program description in its letter requesting relief, dated

December 18, 2001, and NRC authorization to implement the RI-ISI program in a letter dated

July 24, 2002. Based on its review of these documents, the staff determined the following:

* The letter from MNGP dated December 18, 2001, lists 15 systems that its RI-ISI

program encompasses.

" For 10 of the 15 systems that the RI-ISI methodology characterizes in the high- or

medium-risk regions, the MNGP RI-ISI program will change the location and category

and, typically, will reduce the number of inspected welds from the ASME Code,

Section Xl, numbers, locations, and categories. However, the applicant will continue to

inspect a representative number of welds in each of these systems per ASME Code,

Section XI, requirements.

a For 5 of the 15 systems (component cooling water, control rod drive (CRD) hydraulic,

fuel pool emergency cooling, primary containment and atmospheric control, and torus

hard vent systems) where the RI-ISI methodology characterizes all pipe welds in the

low-risk region, the MNGP RI-ISI program will eliminate inspection of welds previously

inspected in accordance with ASME Code, Section Xl, requirements.

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The NRC staff review of the applicant's RI-ISI program, documented in a letter dated

July 24, 2002, concluded that the MNGP RI-ISI program will provide an acceptable level

of quality and safety pursuant to 10 CFR 50.55a with regard to the number of

inspections, locations of inspections, and methods of inspections.

Supported by its previous approval of the applicant's RI-ISI program, the staff concluded that

the ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD Program, as

modified by the RI-ISI program approved by the NRC in a letter dated July 24, 2002, is

acceptable for managing applicable component aging effects through the end of the applicant's

current ISI inspection interval on May 31, 2012, approximately 21 months into the extended

operating period. The staff based this conclusion on the fact that (1) the Class 1 and 2 welds

affected by implementation of RI-ISI representative welds most susceptible to various

age-related degradation mechanisms are still examined to ASME Code, Section Xl,

requirements, (2) any continuation of the RI-ISI program into the period of extended operation

beyond May 31, 2012, will require review and authorization pursuant to 10 CFR 50.55a, and (3)

any subsequent authorization to continue the RI-ISI program into the next ISI inspection interval

will include consideration of any adverse industry or plant-specific operating experience that

might preclude the use or require modification of the RI-ISI program for affected component

aging management through the period of extended operation. On the basis of these

considerations, the staff concluded that the applicant's implementation of RI-ISI is an

acceptable exception to the Detection of Aging Effects program element as described in the

GALL Report for AMP XI.M1.

Exception 8: The GALL Report recommends the following for the Detection of Aging Effects

element associated with the exception taken:

Examination category B-H for integral attachments for vessels: This category

specifies volumetric or surface examination of essentially 100% of the length of

the attachment weld at each attachment subject to examination.

In its letter dated August 11, 2005, the applicant stated that based on a relief request approved

pursuant to 10 CFR 50.55a, its ASME Section Xl In-Service Inspection, Subsections IWB, IWC,

and IWD Program excludes volumetric or surface examination of the reactor vessel stabilizer

bracket welds to the exterior of the RPV. The 1995 edition of the ASME Code, Section Xl,

classifies the reactor vessel stabilizer bracket welds as Category B-H components (integral

attachments for vessels) in the IWB-2500 examination category tabulation and, based on a

change in ASME Code, Section XI, category nomenclature, the 1995 addenda classify them as

Category B-K components (welded attachments for vessels, piping, pumps, and valves) in the

IWB-2500 examination category tabulation.

In its letter dated August 11, 2005, the applicant justified not performing a volumetric or surface

examination of the reactor vessel stabilizer bracket welds as specified by ASME Code,

Section XI, and described in the GALL Report:

Four RPV (reactor pressure vessel) stabilizer brackets are attached to the Class

1 RPV with full penetration fillet welds at 00, 900, 1800, and 2700 RPV azimuth at

an elevation of 994'-2". The RPV stabilizers are connected with flexible couplings

to the brackets on the RPV and also to the biological shield wall. The RPV

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stabilizers, brackets, and their attachment welds are designed to withstand and

resist local loads (jet reaction forces) and seismic loads while allowing axial and

radial movement due to normal thermal growth. The RPV stabilizer brackets do

not provide structural support during normal operation. The MNGP RPV has

never experienced jet reaction forces or seismic events, therefore the stabilizers,

brackets, and attachment welds have not experienced the loads for which they

are designed.

The area abround the stabilizers is extremely congested. The vessel stabilizer

brackets are surrounded by mirror insulation that is secured by cable hangers

and buckles, ventilation ductwork with support bracing, and electrical installations

such as thermocouples. All of this equipment must be relocated and restored to

provide access to the stabilizers for examination of the welds. Additionally, due

to the location of the stabilizer brackets and the lack of a working platform at the

stabilizer location, a complex scaffold installation is required to provide access to

the examination location.

As an alternative to the requirements of Table IWB-2500-1, Category B-K, Item B10.10, in

Section Xl of the ASME Code, the applicant proposed a surface examination on the stabilizer

brackets if local (jet reaction forces) or seismic design loads are experienced. In addition, the

applicant stated that a one-time VT-3 inspection of the accessible areas of all four welded..

attachments during the 2005 refueling outage noted no reportable conditions.

The applicant also stated that relief from this inspection will have no effect on aging

management of the components within the scope of license renewal crediting these programs.

The welds are part of the external surface of the reactor vessel. LRA Table 3.1.2-2 discusses

aging management for the vessel external surface. The staff reviewed the applicant's

justification for this exception. In addition, the staff reviewed the NRC's letter, "Monticello

Nuclear Generating Plant-Fourth 10-Year In-Service Inspection Interval Request for Relief No.

4 (TAC No. MC2222)," dated January 6, 2005, in which the staff approved the applicant's

request for relief from the requirements of the ASME Code, Section Xl, with regard to the

requirements of Table IWB-2500-1, Category B-K, Item B10.10 for inspection of the reactor

vessel stabilizer bracket welds.

On the basis of the information reviewed and additional discussions with the applicant, the NRC

issued RAI B2.1.2-1 on August 18, 2005, to obtain an additional technical basis for this

exception. The staff asked the applicant to describe details of the weld used for the stabilizer

bracket attachment, describe applicable examination requirements and any available results

from the time of vessel manufacture, describe inspections since initial startup of the plant,

identify and describe stressors that the welds experience during normal operation, state

whether the welds have experienced any stressors different from the normal operating

stressors, and summarize any related industry experience with similar welds known to the

applicant.

In its response, dated September 16, 2005, the applicant provided additional information on

weld type and examinations. The four 3-1/2-inch-thick stabilizer brackets are welded to the

outside of the RPV with a double-bevel groove weld (3/16-inch root opening, 1/8-inch root face,

and 30' groove angle) and a concave reinforcing fillet: At the time of vessel manufacture, a UT

examination was conducted of the vessel shell surface before the stabilizer brackets were

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welded at the weld location to a depth at least equal to the thickness of the bracket and over

the entire area of the subsequent connection, plus a band all around this area half as wide as

the thickness of the bracket. After the stabilizer brackets were welded to the vessel, a magnetic

particle examination was conducted of the welds. The only examination of the stabilizer bracket

welds since manufacture occurred in March 2005 and consisted of a VT-3 examination of the

stabilizer brackets using a flashlight and mirror looking for cracks or linear indications, wear,

corrosion, and contaminants. This examination did not identify any reportable indications on any

of the four stabilizer brackets.

The applicant's response also provided the following bases to conclude that degradation of the

stabilizer bracket welds is unlikely:

Degradation of the stabilizer bracket welds is unlikely because the cumulative fatigue

usage factor for the stabilizer brackets is extremely low, so cracking due to fatigue is not

expected to occur.

* The brackets and welds are made of carbon steel, and SCC is not applicable for this

material; furthermore, during reactor operation, the drywell is maintained in an inert

atmosphere with the RPV at high temperatures, so loss of material due to general

corrosion is not expected to occur.

MNGP does not use boric acid or a borated solution as a moderator in the reactor

coolant system. Therefore, loss of material due to boric acid corrosion of external

surfaces does not occur.

Flexible couplings connect the RPV stabilizers to the brackets on the RPV and to the

biological shield wall. The RPV stabilizers, brackets, and their attachment welds are

designed towithstand and resist local loads (jet reactor forces) and seismic loads while

allowing axial and radial movement due to normal thermal growth. During normal

operation, there is no loading on the stabilizer brackets; the stabilizers, brackets, and

attachment welds have never experienced the loads for which they were designed.

Because of design differences, the Duane Arnold plant was able to conduct surface

examinations on portions of its stabilizer bracket attachment welds in April 2005 and

found no reportable indications. In addition, the MNGP staff does not know of any

failures or defects of these or similar welds at any other boiling-water reactors (BWRs).

Based on the applicant's additional information that an appropriate original inspection of the

stabilizer brackets and welds was performed, that there are no stressors to cause degradation

of the brackets or welds during normal operation, that no operational events have subjected the

brackets or welds to abnormal stressors, that a recent VT-3 examination of the brackets found

no indications of weld or bracket degradation, and that industry operating experience does not

suggest occurrence of any age-related degradation of the stabilizer brackets or welds, the staff

concluded that this exception to the Detection of Aging Effects program element is acceptable.

The staff reviewed those portions of AMP B2.1.1, "ASME Section XI In-Service Inspection,

Subsections IWB, IWC, and IWD Program," that the applicant claimed are consistent with

GALL AMP XI.M1 and found them consistent. The staff found the applicant's AMP acceptable

because it conforms to the recommended GALL Report AMP with the exceptions as described

above.

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Operating Experience. In LRA Section B2.1.2, the applicant stated that a review of operating

experience for the ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD

Program identified no adverse trends or issues with program performance. The program

identified and corrected problems before they caused any significant impact to safe operation or

loss of intended functions. The applicant took corrective actions to prevent recurrence. The

MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program

monitors the condition of the pressure-retaining components within the license renewal

boundary. MNGP procedures contain guidance for indications of degradation requiring

evaluation, repair, or replacement. The applicant performs periodic self-assessments and

reviews of industry and plant experience to identify any areas needing improvement. Some

examples include the following:

The applicant modified its ASME Section XI In-Service Inspection, Subsections IWB,

IWC, and IWD Program at the end of the third interval to incorporate an improved

strategy for NDE as described in EPRI TR-1 12657 and in compliance with the

requirements of RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk

Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing

Basis," issued November 2002, and RG 1.178, Revision 1, "An Approach for

Plant-Specific Risk-Informed Decision-Making for In-Service Inspection of Piping,"

issued September 2003.

* Inspections in 1998 and 2001 of steam dryer jacking screws revealed a crack-like

indication in the screw tack weld at 325 degrees. Following the inspection in 1998, an

evaluation indicated that the crack was acceptable. Reinspections of the jacking screws

in 2001 showed no crack growth in the 325 degree screw and no indications of cracking

.in the other screws.

" The applicant detected cracking in 34 tack welds on jet pump beam adjusting screws in

1994 during the in-vessel visual inspection at the end of cycle 16. Cracking was

ascribed to high cycle fatigue. Applicant staff restored tack welds so that each adjusting

screw had a minimum of one uncracked tack weld. Tack welds are and will continue to

be visually inspected.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the applicant's program against the program elements

described in the GALL Report AMP, its review of the above industry and plant-specific operating

experience, and its discussions with the applicant's technical personnel, the staff concluded that

the applicant's ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD

Program will adequately manage the aging effects identified in the LRA for which this AMP is

credited.

USAR Supplement. In LRA Section A2.1.2, the applicant provided the USAR supplement for

the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program. The

staff reviewed this section and determined that the information in the USAR supplement

adequately describes the program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its review and audit of the applicant's ASME Section Xl In-Service

Inspection, Subsections IWB, IWC, and IWD Program, the staff determined that those program

elements for which the applicant claimed consistency with the GALL Report are consistent with

the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications

and determined that the AMP, with the exceptions, is adequate to manage the aging effects for

which it is credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21(d).

3.0.3.2.3 ASME Section XI, Subsection IWF Program

Summary of Technical Information in the Application. In LRA Section B2.1.3, the applicant

described the ASME Section XI, Subsection IWF Program, stating that this existing program is

consistent, with enhancement, with GALL AMP XI.S3, "ASME Section Xl, Subsection IWF." The

MNGP ASME Section XI, Subsection IWF Program is part of the MNGP ASME Section XI

In-Service Inspection Program. The applicant performs the ASME Section XI, Subsection IWF

Program in accordance with the ASME Code, Section Xl, 1995 edition through the 1996

addenda and 10 CFR 50.55a. The program provides for condition monitoring of Class 1, 2, 3,

and MC component supports. The applicant selects component supports for inspection in

accordance with the ASME Code classification and increases the quantity of component

supports selected for examination as a result of discovered support deficiencies. Visual

inspection is the primary method for identifying deficiencies. The applicant periodically updates

the program as required by 10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancement and the associated justifications to

determine whether the AMP, with the enhancement, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.S3.

In the LRA, the applicant stated that, after enhancement of its current program, it will contain no

exceptions to program elements of GALL AMP XI.S3; however, during the audit and review, the

staff asked the applicant whether its approved ISI relief requests or code cases affect any of its

AMP elements. In its letter dated August 11, 2005, supplemented by its letter dated August 31,

2005, the applicant identified for Code Case N-491-2, "Rules for Examination of Class 1, 2, 3,

and MC Component Supports of Light-Water Cooled Power Plants, Section XI, Division 1,"

issued March 2000, the following exception to the GALL Report program element.

Exception: The GALL Report recommends the following for the Corrective Actions program

element associated with the exception taken:

In accordance with IWF-3122, supports containing unacceptable conditions are

evaluated or tested, or corrected before returning to service. Corrective actions

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are delineated in IWF-3122.2. IWF-3122.3 provides an alternative for evaluation

or testing to substantiate structural integrity and/or functionality.

In its letter dated August 11, 2005, the applicant stated that it may perform corrective measures

on a component support to return it to design condition after acceptance by evaluation or test

without requiring additional examinations.

The applicant explained that most of the provisions of the original code case were added to the

1990 addenda to the ASME Code, Section Xl, but that Code Case N-491-2 provisions were

added to IWF-3112.3 and IWF-3122.3 in the 1997 addenda. Because some of the provisions

were added by ASME Code, Section Xl, addenda later than what the GALL Report references,

the applicant has identified these provisions as an exception to the GALL Report description of

the ASME Section Xl, Subsection IWF Program.

The applicant stated in its letter dated August 11, 2005, that this exception to the Corrective

Action Program element of GALL Report AMP XI.S3 will have no impact on aging management

for the component supports. The staff reviewed the applicant's description of this exception

together with requirements specified in the ASME Code, Section Xl, 1995 Edition through 1996

Addenda. Because the applicant's AMP provides inspections required by ASME Code,

Section Xl, Subsection IWF (involving requirements for Class 1, 2, 3, and MC component

supports of light-water-cooled power plants) and requires reasonable and appropriate corrective

actions before a defective component returns to service, the staff agreed that this exception will

have no detrimental impact on the adequacy of affected component aging management. For

this reason, together with review of the ASME Section XI, Subsection IWF Program operating

experience, the staff found this exception acceptable.

In the LRA, the applicant stated that it will implement the following enhancement to make this

AMP consistent with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for the Scope of Program program

element associated with the enhancement made:

Starting with the 1990 Addenda to the 1989 Edition, the scope of Subsection

IWF was revised. The required percentages of each type of nonexempt support

subject to examination were incorporated into Table IWF-2500-1. The revised

percentages are 25% of Class 1 nonexempt piping supports, 15% of Class 2

nonexempt piping supports, 10% of Class 3 nonexempt piping supports, and

100% of supports other than piping supports (Class 1, 2, 3, and MC). For pipe

supports, the total sample consists of supports from each system (such as main

steam, feedwater, residual heat removal), where the individual sample sizes are

proportional to the total number of nonexempt supports of each type and function

within each system. For multiple components other than piping within a system

of similar design, function, and service, the supports of only one of the multiple

components are required to be examined. To the extent practical, the same

supports selected for examination during the first inspection interval are

examined during each successive inspection interval.

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In the LRA, the applicant stated that it will enhance its ASME Section Xl, Subsection IWF

Program to inspect Class MC components supports consistent with the GALL Report,

Chapter III, Section B1.3, "Supports for ASME Class MC Components."

During the audit and review, the staff asked the applicant for more details about its current IWF

program and to identify the inspections that the enhancement will add. In response, the

applicant provided the following information:

* The current MNGP IWF program does not include VT-3 examination of MC supports.

" The current MNGP IWE program includes general visual examinations of MC

components and their supports in accordance with ASME Code, Section Xl, Table

IWE-2500-1.

The applicant stated that examinations conducted under the current IWE program include the

following MC supports:

* torus/ring header seismic restraints

* drywell male and female stabilizers

* shield stabilizers

* torus columns

* torus saddles

* vent system supports

* downcomer bracing

The applicant further stated that for the period of extended operation, the ASME Section Xl,

Subsection IWF Program will perform VT-3 examinations of the MC supports listed above in

accordance with ASME Code, Section Xl, Table IWF-2500-1 in compliance with the ASME

Code, Section Xl, 1995 edition and 1996 addenda ISI requirements. In addition, for the period

of extended operation, the ASME Section Xl, Subsection IWE Program will continue the

general visual examination of the MC components and their supports listed above in

accordance with ASME Code, Section Xl, Table IWE-2500-1.

The staff reviewed the applicant's response together with the applicant's program-basis

document (PBD) for the IWF program. The staff concluded that by adding a requirement for

VT-3 inspection of MC component supports, the applicant's current program will be consistent

with GALL AMP XI.S3. On this basis, the staff found the applicant's response acceptable.

The staff asked whether the applicant's program, when enhanced as described in the LRA, will

provide for inspection of all Class MC supports rolled up into applicable line items of the GALL

Report, Chapter II, Section B1 .3, which specifies ASME Code, Section Xl, Subsection IWF as

the AMP. In response, the applicant stated the following:

When the ASME Section XI, Subsection IWF Program is enhanced, all MNGP

MC supports will be rolled up into the applicable NUREG-1 801 line items to the

extent required by ASME Section Xl, Table IWF-2500-1.

The staff reviewed the applicant's response together with the applicant's proposed program

enhancement as described in the LRA and evaluated in the applicant's PBDs. Based on this

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review, the staff concluded that the applicant's program includes appropriate components as

required by ASME Code, Section XI, Table IWF-2500-1. On this basis, the staff found the

applicant's response acceptable.

Based on the applicant's responses to the staff's questions and review of associated

documents provided by the applicant, the staff concluded that the existing program, enhanced

as described in the LRA, will be fully consistent with the AMP elements described in GALL

AMP XI.S3.

The applicant stated, in the LRA, that the enhancement is required to satisfy the GALL Report

AMP recommendations and is scheduled for implementation before the period of extended

operation. On the basis of its evaluations of the applicant's program against the program

elements described in the GALL Report AMP, together with its review of AMP B2.1.3, "ASME

Section Xl, Subsection IWF," program operating experience, the staff found this enhancement

acceptable, as such changes to the applicant's program provide assurance that the program

will adequately manage the effects of aging.

The staff reviewed those portions of AMP B2.1.3 that the applicant claimed are consistent with

GALL AMP XI.S3 and found them consistent. The staff found the applicant's AMP acceptable

because it conforms to the recommended GALL Report AMP with the exception and

enhancement as described above.

Operating Experience. In LRA Section B2.1.3, the applicant stated that the MNGP ASME

Section Xl, Subsection IWF Program addresses industry operating experience and prescribes

the need for additional augmented requirements for Class 1, 2, 3, and MC component supports

as applicable. In addition, MNGP has been performing a general visual examination on

accessible Class MC component supports in accordance with the ASME Section Xl, Subsection

IWE Program and has not identified any aging effects of concern.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the applicant's program against the program elements

described in the GALL Report AMP, its review of the above industry and plant-specific operating

experience, and discussions with the applicant's technical personnel, the staff concluded that

the applicant's ASME Section Xl, Subsection IWF program will adequately manage the aging

effects identified in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.3, the applicant provided the USAR supplement for

the ASME Section Xl, Subsection IWF Program.

Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement to

include the following commitment, documented as commitment 9 in Table A.5:

Prior to the period of extended operation, the MNGP ASME Section XI,

Subsection IWF Program will be enhanced to provide inspections of Class MC

components supports consistent with NUREG-1 801, Chapter III Section B1.3.

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The staff reviewed this section and determined that the information in the USAR supplement as

augmented by the commitment adequately describes the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's ASME Section Xl, Subsection

IWF Program, the staff determined that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the

staff reviewed the enhancement and confirmed that its implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21(d).

3.0.3.2.4 Bolting Integrity Program

Summary of Technical Information in the Application. In LRA Section B2.1.4, the applicant

described its Bolting Integrity Program, stating that this existing AMP is consistent, with

enhancements, with GALL AMP XI.M18, "Bolting Integrity."

The applicant stated that the Bolting Integrity Program manages the aging affects associated

with bolting within the scope of license renewal through periodic inspection, material selection,

thread lubricant control, assembly and torque requirements, and repair and replacement

requirements. These activities are based on the applicable requirements of the ASME Code,

Section XI, and plant operating experience and include consideration of the guidance contained

in NUREG-1339, 'Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in

Nuclear Power Plants," EPRI'NP-5769, "Degradation and Failure of Bolting in Nuclear Power

Plants," EPRI TR-1 04213, "Bolted Joint Maintenance & Application Guide," and EPRI NP-5067,

Volumes 1 and 2, "Good Bolting Practices."

The Bolting Integrity Program credits 11 AMPs for the inspection of installed bolts, namely

(1) 10 CFR 50, Appendix J, (2) ASME Section Xl In-Service Inspection, Subsections IWB, IWC

and IWD, (3) Primary Containment In-Service Inspection, (4) Inspection of Overhead Heavy

Load and Light Load (Related to Refueling) Handling Systems, (5) ASME Section XI,

Subsection IWF, (6) Buried Piping and Tanks Inspection, (7) Bus Duct Inspection, (8) BWR

Vessel Internals, (9) Reactor Head Closure Studs Monitoring, (10) System Condition

Monitoring, and (11) Structures Monitoring Programs.

The applicant stated that enhancements are required to satisfy the GALL Report AMP

recommendations. It will add the enhancements to the Parameters Monitored or Inspected and

Acceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load

(Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System

Condition Monitoring Program. These enhancements will add guidance for visual bolting

inspections found in EPRI TR-1 04213 and EPRI NP- 5067, Volumes 1 and 2.

The LRA also states that inspection of bolting for ASME Code, Section XI, Class 1, 2, 3, and

MC components is in accordance with the ASME Code, Section Xl requirements. Because the

scope of license renewal includes components besides those related to ASME Code,

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Section Xl, the applicant relies upon other programs for additional inspections that include

checking the material condition of bolting for signs of corrosion, wear, and other problems, and

associated pressure-retaining joints for signs of leakage. Upon detection of degraded

conditions, the applicant performs followup inspections, repairs, replacements, or application of

additional testing methods as required by the site CAP and applicable ASME Code, Section XI

acceptance criteria.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancements and the associated justifications

to determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited.

The staff reviewed the Bolting Integrity Program against the AMP elements in the GALL Report,

SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on the program's management

of aging effects through the incorporation of the 10 program elements. The applicant indicated

that the site-controlled Quality Assurance Program includes the Corrective Actions,

Confirmation Process, and Administrative Controls elements. SER Section 3.0.4 discusses the

staff's evaluation of the Quality Assurance Program.

LRA Section B2.1.4 states that the Bolting Integrity Program is consistent with GALL

AMP XI.M18 with enhancements added to the Parameters Monitored or Inspected and

Acceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load

(Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System

Condition Monitoring Program. These enhancements will add guidance for visual bolting

inspections found in EPRI TR-104213, and EPRI NP-5067, Volumes 1 and 2. The staff

reviewed the Parameters Monitored or Inspected and Acceptance Criteria elements and

concluded that the applicant has acceptable criteria for visual bolting inspections and

acceptance criteria for the Inspection of Overhead Heavy Load and Light Load (Related to

Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition

Monitoring Program. The staff has reviewed and approved similar enhancements to bolting

programs based on EPRI NP-5067 and EPRI-TR-104213, as documented in NUREG-1743,

"Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 1,"

issued April 2001. For these reasons, the staff found that the guidelines for enhancements to

the Bolting Integrity Program reflect industry practice and meet the recommendations of GALL

AMP XI.M18.

The staff's review of LRA Section B2.1.4 identified an area for which it needed additional

information to complete its evaluation of the applicant's program elements. The applicant

responded to the staff's RAI as discussed below.

In RAI B2.1.4-1, dated July 20, 2005, the staff noted that Table Items 3.3.1-18, 3.3.1-24, and

3.4.1-08 in the LRA provide a general discussion of the Bolting Integrity Program as applied to

the ESF, auxiliary, and steam and power conversion (SPC) systems. Therefore, the staff

requested that the applicant state whether the Bolting Integrity Program manages all closure

bolting in the ESF, auxiliary, and SPC systems for loss of preload, even though the AMR tables

contain no specific line items for this aging effect.

In its response, by letter dated August 16, 2005, the applicant stated the following:

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As discussed in Section B2.1.4 of the License Renewal Application, the Bolting

Integrity Program manages aging effects for bolting within the scope of license

renewal. This includes closure bolting that is required to support a pressure

boundary intended function for components of the systems listed in Section

B2.1.4, Scope of Program. Detection of aging effects includes visual inspection

of pressure retaining joints for signs of leakage, which may be the result of loss

of preload. With the exception of the Emergency Filtration (EFT) System, this

includes all closure bolting of the Engineered Safety Features (ESF), Auxiliary,

and Steam and Power Conversion (SPC) systems in the LRA. As noted in LRA

Table 3.3.2-7, bolting of the EFT System is not susceptible to aging effects due

to is location in a controlled environment and is, therefore, not included in the

.Bolting Integrity Program.

In a telephone conversation on November 4, 2005, the staff requested that the applicant explain

why closure bolting of the EFT system is not susceptible to aging effects and not included in the

Bolting Integrity Program.

In its response, by letter dated November 17, 2005, the applicant stated that bolting in the EFT

system is not susceptible to aging effects (i.e., corrosion) because of its location in a controlled

air environment; however, the Bolting Integrity Program is credited with managing the loss of

preload aging effect for the EFT system. The applicant supplemented its response to

RAI B2.1.4-1 as follows:

Closure bolting of the EFT system is managed by the Bolting Integrity Program

for loss of preload. Section B.2.1.4, Scope of Program, of the LRA for the Bolting

Integrity Program is revised to include the EFT system.

Based on its review, the staff found the applicant's response to RAI B2.1.4-1 acceptable. The

applicant stated that the Bolting Integrity Program manages all closure bolting in the ESF,

auxiliary, and SPC systems for loss of preload; therefore, the staff's concern described in RAI

B2.1.4-1 is resolved.

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP program elements. In its letter dated August 31,

2005, the applicant identified the following exception to the GALL Report for the Bolting Integrity

Program:

Element: 7: Corrective Actions

Exception: An approved alternative allows the use of the 2001 Edition of ASME

Section XI in lieu of the 1995 Edition with the 1996 Addenda for

repair/replacement activities.

SER Section 3.0.3.1.7 documents the staff's evaluation of this exception.

Because the NRC has already reviewed and approved this alternative, as it relates to repair and

replacement, generically for aging management of systems and components within the scope

of license renewal, the staff concluded that the applicant need not classify it as an exception

and that, with regard to this item, the affected program element is consistent with the GALL

Report.

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Operating Experience. The applicant stated that both the industry and the NRC have revealed a

number of instances of bolting concerns, from material control and certification to bolting

practices, use of lubrication, and the impact of aging mechanisms. The MNGP Bolting Integrity

Program incorporates both plant and industry experience on bolting issues. For example,

MNGP previously evaluated and addressed NRC information notices (INs), bulletins, circulars,

and GLs listed in Section 3 of NUREG-1 339. Some of these resulted in confirmatory analyses

or inspections and others in modifications or the addition of special items to consider in the

procurement and design processes. MNGP replaced all reactor vessel shroud head bolts with a

new vendor recommended design, for example, when it identified cracking issues with the prior

design.

A review of plant operating experience identified issues with missing or loose bolts, inadequate

thread engagement, and improper bolt applications. In all cases, MNGP corrected the identified

concern; no significant safety event resulted; and the applicant implemented additional actions,

such as procedural enhancements, as needed to minimize the potential for recurrence.

In RAI B2.1.4-2, dated July 20, 2005, the staff noted that, after the applicant had submitted the

LRA, failed bolts on tee-quencher supports were found at the Hatch Nuclear Plant Unit 2

(Hatch 2). Subsequent analysis revealed that high-strength bolts are susceptible to

hydrogen-induced cracking and may fail after 20 to 25 years of service. Therefore, the staff

requested that the applicant explain why the tee-quencher bolts at MNGP will not fail as a result

of hydrogen-induced cracking.

In its response, by letter dated August 16, 2005, the applicant stated that the tee-quencher

support design at MNGP differs from the design at Hatch 2. In addition, all bolts are 1-inchdiameter, 3.75-inch-long hex bolts procured to the requirements of American Society for

Testing Materials (ASTM) A-325 Type 1 or A-1 93 Grade B7 material specification. These are

not high-strength bolts, having ultimate strength of approximately 125 ksi or less, and are well

below the ultimate strength of SA540 Grade B21 Class 1 bolts at Hatch 2. Further, analysis of

the Hatch 2 event determined that the most likely cause of SCC of the high-strength bolts was

the significant contribution of hydrogen embrittlement. One possible source of the hydrogen

embrittlement was the use of a zinc primer inside the torus. MNGP does not use a zinc primer;

instead, it uses a modified phenolic-based primer in the torus. Finally, MNGP performs

underwater inspections of these bolts periodically, and the May 1993 inspection identified no

problems or loose connections.

Based on its review, the staff found the applicant's response to RAI B2.1.4-2 acceptable. The

staff concurred with the applicant's conclusions that the Hatch 2 event does not apply to MNGP

because the tee-quencher design differs from the design at Hatch 2. The bolts at MNGP are

lower strength bolts not susceptible to SCC, and the application of phenolic-based instead of

zinc-based primer inside the torus has minimized any source of hydrogen. In addition, the

applicant performs periodic inspection of tee-quencher bolts in accordance with the

requirements of its Primary Containment In-Service Inspection Program, providing added

assurance that bolting materials inside the torus will be adequately managed during the period

of extended operation. Therefore, the staff's concern described in RAI B2.1.4-2 is resolved.

On the basis of its review of the above industry and plant-specific operating experience, the

staff concluded that the Bolting Integrity Program will adequately manage the aging effects

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identified in the LRA for which this AMP is credited. The staff concluded that this program

attribute is acceptable.

USAR Supplement. In LRA Section A2.1.4, the applicant provided the USAR supplement for

the Bolting Integrity Program.

Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement to

include the following commitment, documented as commitmr ent 10 in Table A.5:

Prior to the period of extended operation, the guidance for performing visual

bolting inspections contained in EPRI TR-1 04213, Bolted Joint Maintenance &

Application Guide, and the Good Bolting Practices Handbook (EPRI NP-5067

Volumes 1 and 2) will be included in the Bus Duct Inspection Program,

Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program, Structures Monitoring Program and the System

Condition Monitoring Program.

The staff reviewed this section and determined that the information in the USAR supplement as

augmented by the commitment adequately describes the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Bolting Integrity Program, the

staff determined that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

enhancements and confirmed that their implementation before the period of extended operation

will result in the existing AMP being consistent with the GALL Report AMP to which it was

credited. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21(d).

3.0.3.2.5 Buried Piping & Tanks Inspection Program

Summary of Technical Information in the Application. In LRA Section B2.1.5, the applicant

described the Buried Piping & Tanks Inspection Program, stating that this existing program is

consistent, with enhancements, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."

The Buried Piping & Tanks Inspection Program consists of preventive and condition monitoring

measures to manage the aging effects for buried piping, conduit, and tanks within the scope of

license renewal. Buried components within the scope of license renewal include carbon steel

piping, bolting, conduit, and tanks (loss of material due to general', crevice, galvanic, pitting, and

microbiologically influenced corrosion (MIC)) and cast iron piping (loss of material due to

general, crevice, galvanic,, and pitting corrosion, MIC, and selective leaching). Preventive

measures consist of protective coatings and/or wraps on buried components. Condition

monitoring consists of periodic inspections of buried components. In addition, buried

components are not routinely uncovered during maintenance activities. Therefore, other system

monitoring and functional testing activities are relied upon to provide effective degradation

aging management of buried piping and tanks. Some of these activities are neither preventive

nor mitigative in nature, but they do provide indication of a leak. However, the potential problem

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(i.e., small leak) is detected at an early stage, such that repairs can be made before the loss of

component intended function.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancements and the associated justifications

to determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses consistency of the AMP

elements with GALL AMP XI.M34.

In the LRA, the applicant stated that the following enhancements will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement 1: The GALL Report recommends the following for the Scope of Program

program element associated with the enhancement made:

The program relies on preventive measures such as coating and wrapping and

periodic inspection for loss of material caused by corrosion of the external

surface of buried carbon steel piping and tanks. Loss of material in these

components, which may be exposed to aggressive soil environment, is caused

by general, pitting, and crevice corrosion, and microbiologically influenced

corrosion (MIC). Periodic inspections are performed when the components are

excavated for maintenance or for any other reason.

The applicant stated in the LRA that it will update the scope of the Buried Piping & Tanks

Inspection Program to implement procedures to include inspections of buried components when

uncovered. In interviews with the applicant's technical personnel about the enhanc6d program,

the applicant stated that the enhanced program will take inspection opportunities when buried

components are uncovered at times other than scheduled buried piping inspections. In addition,

it will update the excavating procedure to perform inspection(s), when buried components are

Uncovered. The staff reviewed the applicant's response and plant procedures and found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

During the aging management inspection, the inspectors noted that, although the PBDs

indicate that the Buried Piping & Tanks Inspection Program would manage buried conduit, the

existing inspections and related procedures were limited to buried piping and the diesel fuel oil

storage tank. Since buried conduit is galvanized and not wrapped or coated, aging of conduit

could be different from that of underground piping and tanks. In its letter dated March 15, 2006,

the applicant amended the scope of the program to include conduit. The staff found this

acceptable because it ensures that potential aging effects of buried conduit are managed.

Enhancement 2: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the enhancement made:

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The program monitors parameters such as coating and wrapping integrity that

are directly related to corrosion damage of the external surface of buried carbon

steel piping and tanks. Coatings and wrappings are inspected by visual

techniques. Any evidence of damaged wrapping or coating defects, such as

coating perforation, holidays, or other damage, is an indicator of possible

corrosion damage to the external surface of piping and tanks.

In the LRA, the applicant stated that it will add the Diesel Fuel Oil Storage Tank T-44 internal

inspections to the list of scheduled inspections in the Buried Piping & Tanks Inspection

Program.

The staff noted that the applicant's buried diesel fuel oil storage tank inspection is an internal

inspection. In RAI B2.1.5-1, dated October 31, 2005, the staff requested that the applicant

clarify whether the diesel fuel oil storage tank internal inspection is in addition to or in lieu of the

external inspection recommended in the GALL Report.

In its response, by letter dated November 22, 2005, the applicant stated that the Buried Piping

& Tanks Inspection Program and the 10-year diesel fuel oil storage tank internal inspection will

supplement the external inspection as recommended in the*GALL Report and will include both

visual and UT inspections. External inspections of the diesel fuel oil storage tank will take place

as opportunities arise. Should the applicant excavate the tank during maintenance activities, it

will perform an external inspection consistent with the GALL Report for inspecting the external

surfaces of buried piping and tanks.

In the Detection of Aging Effects program element, the applicant stated, "An enhancement to

the underground piping inspections is to include a provision that if evaluations of pipe wall

thickness show a susceptibility to corrosion, further evaluation as to the extent of susceptibility

will be performed." The applicant restated in its RAI response that inspections of the external

surfaces of other buried carbon steel components will also indicate the external surface

condition of the diesel fuel oil storage tank.

The applicant stated that the diesel fuel oil storage tank internal inspection supplements the

external inspections recommended in the GALL Report and, therefore, is an acceptable AMP

for the detection of aging effects consistent with the GALL Report. The staff reviewed the

applicant's response and found this enhancement acceptable as it provides assurance that the

effects of aging will be adequately managed.

Enhancement 3: The GALL Report recommends the following for the Detection of Aging

Effects program element associated with the enhancement made:

Periodic inspection of susceptible locations to confirm that coating and wrapping

are intact is an effective method to ensure that corrosion of external surfaces

has not occurred and the intended function is maintained. The inspections are

performed in areas with the highest likelihood of corrosion problems, and in

areas with a history of corrosion problems. Because the inspection frequency is

plant-specific and also depends on the plant operating experience, the

applicant's proposed inspection frequency is to be further evaluated for the

extended period of operation.

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In the LRA, the applicant stated that it will revise the Buried Piping & Tanks Inspection Program

to include a provision that if evaluations of pipe wall thickness show susceptibility to corrosion,

further evaluation as to the extent of susceptibility will be performed. It will revise the Buried

Piping & Tanks Inspection Program to specify a 10-year buried pipe inspection frequency and a

10-year Diesel Fuel Oil Storage Tank T-44 internal inspection frequency.

During the audit and review, the staff asked the applicant about the types of inspections it will

perform for this program before the period of extended operation. In response, the applicant

stated that a visual and UT inspection of the buried Diesel Fuel Oil Storage Tank T-44 was

performed in 2003 and showed no significant loss of material due to corrosion on the tank

interior. Additionally, the applicant stated that a visual and UT inspection of the buried pipe near

the offgas stack was performed in 1999 and no degradation due to aging effects was detected.

The applicant also stated that it regularly inspects the underground piping for the offgas system

going to the plant stack. The Offsite Safety Review Committee established this requirement to

preclude leakage of offgas from the underground piping for any reason, including aging effects.

The staff reviewed the applicant's response and plant procedures and found the enhancement

acceptable by providing assurance that AMP B2.1.5, "Buried Piping & Tanks Inspection

Program," is consistent with the AMP elements described in GALL AMP XI.M34.

Enhancement 4: The GALL Report recommends the following for the Monitoring and Trending

program element associated with the enhancement made:

Results of previous inspections are used to identify susceptible locations.

In the LRA, the applicant stated that the underground piping inspections will include review of

previous buried piping issues to determine possibly susceptible locations.

During the audit and. review, the applicant provided technical information regarding the

statement that MNGP has mild soil conditions. In response to the staff's questions, the

applicant provided technical data for pH, chloride, and sulfate concentrations, which verified this

conclusion. The enhancement of the Monitoring and Trending program element will include a

review of previous buried piping issues to determine possibly susceptible locations. The staff

reviewed the applicant's response and found AMP B2.1.5 consistent with the AMP elements

described in GALL AMP XI.M34.

The staff reviewed those portions of AMP B2.1.5 that the applicant claimed are consistent with

GALL AMP XI.M34 and found them consistent. The staff found the applicant's AMP acceptable

because it conforms to the recommended GALL Report AMP with the enhancements as

described above.

Operating Experience. In LRA Section B2.1.5, the applicant stated that the Buried Piping &

Tanks Inspection Program relies on preventive measures, periodic inspections, and functional

testing to manage the aging effects of buried components. MNGP operating experience has

shown no buried component failures for systems within the scope of license renewal

(emergency service water (ESW), diesel generator, hangars and supports, secondary

containment system, fire system (FIR)). The only failures of buried components were on the

well water piping system and the instrument air system to the cooling towers. These are not SR

systems and they are outside the scope of license renewal. The failures are not located near

3-55
any buried components within the scope of license renewal. The well water piping failure was

postulated to be caused by MIC and not a failure of the protective coating. The cause of the

failure of the instrument air line is yet to be determined. Periodic visual and UT inspections of

buried pipe have shown no significant loss of material due to pipe corrosion. Periodic UT

inspections of the diesel fuel oil storage tank interior have also shown no significant loss of

material due to corrosion. Periodic functional testing of the ESW and fire header systems has

shown no functional failures. Periodic vapor point monitoring and ground water monitoring near

the diesel fuel oil storage tank have shown no functional failures of the storage tank or the

diesel fuel oil lines.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant',stechnical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review, operating experience documentation, and discussions with-the

applicant's technical personnel, the staff concluded that the applicant's Buried Piping & Tanks

Inspection Program will adequately manage the aging effects identified in the LRA for which

this AMP is credited.

USAR Supplement. In LRA Section A2.1.5, the applicant provided the USAR supplement for

the Buried Piping & Tanks Inspection Program. The staff reviewed this section and determined

that the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter dated June 10, 2005, the applicant supplemented LRA Section A2.1.5 by listing ,the

following commitments, documented as commitments 11-16 in Table A.5,. to be performed

before the period of extended operation:

(1) The Buried Piping and Tanks Inspection Program will update the

implementing procedures to include inspections of buried components

when they are uncovered.

(2) The Diesel Fuel Oil Storage Tank, T-44, internal inspection will be added

to the list of scheduled inspections in the Buried Piping and Tanks

Inspection Program.

(3) The Buried Piping and Tanks Inspection Program will be revised to

include a provision that if evaluations of pipe wall thickness show a

susceptibility to corrosion, further evaluation as to the extent of

susceptibility will be performed.

(4) The Buried Piping and Tanks Inspection Program will be revised to

specify a 10-year buried pipe inspection frequency.

(5) The Buried Piping and Tanks Inspection Program will be revised to

specify a 10-year inspection frequency for Diesel Fuel Oil Storage Tank

T-44.

(6) The Buried Piping and Tanks Inspection Program will be revised to

include a review of previous buried piping issues to determine possible

susceptible locations.

3-56
Conclusion. On the basis of its review and audit of the applicant's Buried Piping & Tanks

Inspection Program, the staff determined that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the

staff reviewed the enhancements and confirmed that their implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21(d).

3.0.3.2.6 BWR Control Rod Drive Return Line Nozzle Program

Summary of Technical Information in the Application. In LRA Section B2.1 .7, the applicant

described the BWR CRD Return Line Nozzle Program, stating that this existing program is

consistent, with exceptions, with GALL AMP XI.M6, "BWR Control Rod Drive Return Line

Nozzle." The MNGP BWR CRD Return Line Nozzle Program is part of the MNGP ASME

Section XI In-Service Inspection Program. The BWR CRD Return Line Nozzle Program is in

accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda, and

provides for condition monitoring of the BWR CRD return line (CRDRL) nozzle. In 1977, the

CRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986, the

CRDRL nozzle was modified again by removing the portion of the existing weld butter layer

susceptible to IGSCC, by re-cladding the weld prep area with corrosion-resistant cladding, and

by installing a new nozzle cap of non-IGSCC susceptible stainless steel. As a result of capping

the CRDRL nozzle, the NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return

Line Nozzle Cracking: Resolution of Generic Technical Activity A-10," issued November 1980,

augmented examinations are no longer required. Not performing the NUREG-0619 augmented

examinations is considered an exception to GALL Report AMP XI.M6. The applicant updates

the program periodically as required by 10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M6.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M6 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Parameters Monitored or

Inspected, Detection of Aging Effects, and Monitoring and Trending program elements

associated with the exception taken:

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The aging management program (AMP) monitors the effects of cracking on the

intended function of the component by detecting and sizing cracks by ISI in

accordance with Table IWB 2500-1 and NUREG-0619.

The extent and schedule of inspection, as delineated in NUREG 0619, assures

detection of cracks before the loss of intended function of the component.

Inspection recommendations include liquid penetrant testing (PT) of the CRDRL

nozzle blend radius and bore regions and the reactor vessel wall area beneath

the nozzle, return-flow-capacity demonstration, CRD-system-performance testing

and ultrasonic inspection of welded connections in the rerouted line. The

inspection is to include base metal to a distance of one-pipe-wall thickness or 0.5

in., whichever is greater, on both sides of the weld.

The inspection schedule of NUREG-0619 provides timely detection of cracks.

In the LRA, the applicant stated that it does not perform the NUREG-0619 augmented

inspections; it removed the CRDRL nozzle safe end and capped the nozzle in 1977. The

applicant also stated that it modified the nozzle again in 1986 to remove that portion of the

existing weld butter layer susceptible to IGSCC by re-cladding the weld prep area with

corrosion-resistant cladding and by installing a new nozzle cap of 316 L nuclear-grade stainless

steel. Because of these modifications, the applicant stated in its LRA that the required

augmented inspections on the CRDRL nozzle specified in NUREG-0619 through NRC GL

80-95, "Generic Activity A-10," dated November 13, 1980, are no longer necessary. Although

the applicant did not perform those augmented inspections specified in NUREG-0619, it did

follow the guidance in NUREG-0619, Section 8.2, for other inspections and maintenance

activities related to the CRD system. The following summarizes the activities related to

NUREG-0619, Section 8.2:

Section 8.2(3)-The final PT inspection of the CRDRL nozzle showed no indications. A

system flow and performance test had satisfactory results.

* Section 8.2(3a)-The welded connection joining the rerouted CRDRL to the reactor

water cleanup (RWCU) system is inspected every refueling outage with UT and includes

base metal to a distance of one pipe-wall thickness or 0.5 inches, whichever is greater,

on both sides of the weld.

* Section 8.2(3b)-The remainder of the CRDRL does not meet the definition of Class 1,

2, or 3 pipe and, therefore, NUREG-0313, Revision 2, ',Technical Report on Material

Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping,"

issued January 1988, does not require augmented inspections.

" Section 8.2(3c)-Since carbon steel piping was retained in the exhaust header,

procedures were developed for (1) periodically performing a random sampling of

hydraulic accumulator unit filters to determine if cleaning and flushing is required, and

(2) periodically performing a flush of the CRD exhaust header.

The applicant further stated that its commitment in response to GL 80-95 to implement the

requirements for the CRDRL nozzle specified in NUREG-0619, Section 8, has been completed.

The activities described above relating to NUREG-0619, Sections 8.2(3a) and 8.2(3c), are

existing NRC commitments and will continue through the period of extended operation.

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On the basis of its review of the completion of CRDRL nozzle-related modifications, the

completion of commitments in response to GL 80-95, and operating experience for AMP

B2.1.7, the staff found this exception acceptable.

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP program elements. In its letter dated August 31,

2005, the applicant identified the following additional exception to the GALL Report program

element:

Exception 2: The GALL Report recommends the following for the Corrective Actions program

element associated with the exception taken:

Repair is in conformance with IWB-4000 and replacement in accordance with

IWB-7000.

In its letter dated August 11, 2005, the applicant stated that an approved alternative allows the

use of the ASME Code, Section Xl, 2001 edition in lieu of the 1995 edition with the 1996

addenda for repair/replacement activities.

The staff concluded that this item is not an exception and that with regard to this item, the

affected program element is consistent with the GALL Report. SER Section 3.0.3.1.7

documents the staff's evaluation.

The staff reviewed those portions of AMP B2.1.7, "BWR Control Rod Drive Return Line Nozzle

Program," that the applicant claimed are consistent with GALL AMP XI.M6 and found them

consistent. The staff found the applicant's LRA AMP acceptable because it conforms to the

recommended GALL Report AMP with the exceptions as described above.

Operating Experience. In LRA Section B2.1.7, the applicant stated that it implements the BWR

Control Rod Drive Return Line Nozzle Program inspections through the Inservice Inspection

Program, which incorporates applicable requirements of the ASME Code. The inspection and

testing methodologies have been effective in detecting aging effects due to cracking.

Engineering evaluations were performed based on plant and industry experience and

component and programmatic corrective actions implemented as required. For example, in

1977 the CRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986,

the CRDRL nozzle was modified again by removing the portion of the existing weld butter layer

susceptible to IGSCC by re-cladding the weld prep area with corrosion-resistant cladding, and

by installing a new nozzle cap. As a result of capping the CRDRL nozzle as discussed above,

the NUREG-0619 augmented examinations are no longer required.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's BWR CRDRL Nozzle

Program will adequately manage the aging effects identified in the LRA for which this AMP is

credited.

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USAR Supplement. In LRA Section A2.1.7, the applicant provided the USAR supplement for

the BWR CRDRL Nozzle Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's BWR CRDRL Nozzle

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the exceptions and the associated justifications and determined that the AMP, with the

exceptions, is adequate to manage the aging effects for which it is credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21 (d).

3.0.3.2.7 BWR Feedwater Nozzle Program

Summary of Technical Information in the Application. In LRA Section B2.1.8, the applicant

described the BWR Feedwater Nozzle Program, stating that this existing program is consistent,

with enhancements, with GALL AMP XI.M5, "BWR Feedwater Nozzle." The MNGP BWR

Feedwater Nozzle Program is part of the MNGP ASME Section Xl In-Service Inspection

Program. The BWR Feedwater Nozzle Program is in accordance with the ASME Code,

Section XI, 1995 edition through the 1996 addenda, with Appendix VIII. The program provides

for condition monitoring of the BWR FW nozzles. The BWR FW nozzles were all repaired in

1977 and the safe ends were all replaced in 1981 with a tuning fork design with a welded-in

thermal sleeve. The BWR Feedwater Nozzle Program is not currently augmented by the

recommendations of General Electric (GE) Topical Report NE-523-A71-0594, Revision 1,

"Alternate BWR Feedwater Nozzle Inspection Requirement." The applicant will enhance the

program by including the recommendations of GE-NE-523-A71-0594-A, Revision 1. The

applicant updates the program periodically as required by 10 CFR 50.55a.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the. GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancements and the associated justifications

to determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses consistency of the AMP

elements with GALL AMP XI.M5.

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP program elements.

In its letter dated August 31, 2005, the applicant identified the following additional exception to

the GALL Report program element.

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Exception: The GALL Report recommends for the Corrective Actions program element

associated with the exception taken:

Repair is in conformance with IWB-4000 and replacement in accordance with

IWB-7000.

In its letter dated August 111,.2005, the applicant stated that an approved alternative allows the

use of the ASME Code, Section Xl, 2001 edition in lieu of the 1995 edition with the 1996

addenda for repair/replacement activities.

The staff concluded that this item is not an exception and that with regard to this item, the

affected program element is consistent with the GALL Report. SER Section 3.0.3.1.7

documents the staff's evaluation.

In the LRA, the applicant described the following enhancement in meeting the GALL Report

elements.

Enhancement: The GALL Report recommends the following for the Parameters Monitored or

Inspected, Detection of Aging Effects, and Monitoring and Trending program elements

associated with the enhancement made:

The aging management program (AMP) monitors the effects of cracking on the

intended function of the component by detection and sizing of cracks by ISI in

accordance with ASME Section Xl, Subsection IWB and the recommendation of

GE NE-523-A71-0594, as described below.

The extent and schedule of the inspection prescribed by the program are

designed to ensure that aging effects will be discovered and repaired before the

loss of intended function of the component. Inspection can reveal crack initiation

and growth. GE NE-523-A71-0594 specifies ultrasonic testing (UT) of specific

regions of the blend radius and bore. The UT examination techniques and

personnel qualifications are in accordance with the guidelines of GE

NE-523-A71-0594. Based on the inspection method and techniques and

plant-specific fracture mechanics assessments, the inspection schedule is in

accordance with Table 6-1 of GE NE-523-A71-0594. Leakage monitoring may be

used to modify the inspection interval.

Inspections scheduled in accordance with GE NE-523-A71-0594 provide timely.

detection of cracks.

In the LRA, the applicant stated that it will enhance the BWR Feedwater Nozzle Program by

including the recommendations of GE-NE-523-A71-0594-A, Revision 1.

By letter dated September 24, 1999, the BWR Owners Group (BWROG) submitted for staff

review Topical Report GE-NE-523-A71-0594-A, Revision 1. This report proposed an alternative

to the recommendations of NUREG-0619. The topical report proposed to (1) accept the UT as

the basis to eliminate supplemental liquid PT of inside radii of the RPV nozzles, (2) lengthen the

time interval between routine UT of inside radii of the RPV nozzles, and (3) reduce the

inspection area of inside radii of the RPV nozzles. In its review of the topical report, the staff

3-61
focused on the quality and reliability of the UT examinations. In its letter to BWROG, dated

March 10, 2000, the staff approved the proposed inspection program and schedule as

described in the BWROG topical report; therefore, GE-NE-523-A71-0594-A, Revision 1, is an

acceptable alternative to the NUREG-0619 inspection guidelines.

The applicant stated that it had made four long-term inspection commitments based on

NUREG-0619 in 1989, as follows:

(1) Review online FW nozzle thermal sleeve leak detection system data monthly.

(2) Perform external UT examinations on two of the four FW nozzles each refueling outage.

(3). Perform visual inspections of the spargers and the nozzle blend radius areas of all four

FW nozzles each refueling outage.

(4) Perform PT examinations of nozzles at the next appropriate opportunity in the event that

(a) UT examinations indicate a flaw or (b) online leakage monitoring systems identify

excessive leakage (greater than 0.3 gallons per minute).

In the corresponding SER, the staff stated that MNGP will continue inspections for "9 inspection

interval-refueling cycles or 135 startup/shutdown cycles" as stated in NUREG-0619. The

inspection interval began with the installation of welded thermal sleeves during the 1981

refueling outage. With the completion of inspections during the 1998 refueling outage, the

applicant had completed the required nine inspection interval-refueling cycles with no observed

degradation of the FW nozzles. The most recent FW nozzle inspections during the third 10-year

ASME Section Xl In-Service Inspection Program (ending on May 1, 2003) also revealed no

cracking on these nozzles.

During the audit and review, the staff asked the applicant to clarify plans to update its current

BWR Feedwater Nozzle Program to meet the recommendations in GE-NE-523-A71-0594,

Revision 1. The applicant stated that (1) the requirement specified in ASME Code, Section Xl,

Table IWB-2500-1, Examination Category B-D, for full-penetration welded nozzles has been

incorporated into the BWR Feedwater Nozzle Program, (2) the region inspected, examination

techniques, and personnel qualifications will be consistent with the recommendations of GENE-523-A71-0594, Revision 1, Section 4.0, and (3) the requirement of Appendix VIII to ASME

Code, Section XI, including IWB-2400 schedule requirements has been incorporated into the

BWR Feedwater Nozzle Program, which will be enhanced for consistency with the

recommendations of GE-NE-523-A71-0594, Revision 1, Sections 6.2 and 6.3. If defects are

detected, the applicant will expand the scope of examinations pursuant to the requirements of

IWB-2430. The staff found this enhancement acceptable because the associated

recommendations are based on (1) the availability of the proven improved UT techniques, (2)

meeting the inspection commitments made in 1989, (3) acceptable performance history of the

FW nozzles with the new thermal sleeves, and (4) the staff's approval of use of GENE-523-A71-0594, Revision 1.

On the basis of its review of the above enhancement and discussions with the applicant's

technical personnel, the staff found this enhancement acceptable as such changes to the

applicant's program provide assurance that the effects of aging will be adequately managed.

3-62-
The staff reviewed those portions of AMP B2.1.8, "BWR Feedwater Nozzle Program," that the

applicant claimed are consistent with GALL AMP XI.M5 and found them consistent. The staff

found the applicant's AMP acceptable because it conforms to the recommended GALL Report

AMP with the exception and enhancement as described above.

Operating Experience. In LRA Section B2.1.8, the applicant explained that it performed

engineering evaluations based on plant and industry experience and component and

programmatic corrective actions implemented as required:

" Repairs were made to the FW nozzles and safe ends in 1977 to minimize damage to the

FW nozzles due to thermal cycling. Cladding was removed from the nozzle blend radius

and bore, and an FW sparger interference fit thermal sleeve with a piston ring seal was

installed.

* New FW nozzle safe ends were installed in 1981. These safe ends have a tuning fork

design with a welded-in thermal sleeve and provide a significant reduction in thermal

cycling.

" The applicant incorporated considerations from NUREG-0619, along with NRC GL

81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking

(NUREG-0619)," dated February 29, 1981, into the BWR Feedwater Nozzle Program

during the third 10-year inspection interval ending on May 1, 2003. No cracking was

identified as a result of these inspections.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's BWR Feedwater Nozzle

Program will adequately manage the aging effects identified in the LRA for which this AMP is

credited.

USAR Supplement. In LRA Section A2.1.8, the applicant provided the USAR supplement for

the BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

In its letter dated June 10, 2005, the applicant added the following three commitments to USAR

Section A2.1.8, documented as commitments 18-20 in Table A.5, that it will complete before

the period of extended operation:

(1) The parameters monitored and inspected are consistent with the recommendations of

GE-NE-523-A71-0594-A, Revision 1.

(2) The regions being inspected, examination techniques, personnel qualifications, and

inspection schedule are consistent with the recommendations of GENE-523-A71-0594-A, Revision 1.

(3) The applicant will schedule inspections per recommendations of GENE-523-A71-0594-A, Revision 1.

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The BWR Feedwater Nozzle Program is not currently augmented by the recommendations of

GE-NE-523-A71-0594. The applicant will enhance the program by including the

recommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant updates this program

periodically as required by 10 CFR 50.55a.

Conclusion. On the basis of its review and audit of the applicant's BWR Feedwater Nozzle

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the enhancements and confirmed that their implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21(d).

3.0.3.2.8 BWR Penetrations Program .:'

Summary of Technical Information in the Application. In LRA Section B2.1.9, the applicant

described the BWR Penetrations Program, stating that this existing program is consistent, with

exceptions, with GALL AMP XI.M8, "BWR Penetrations." The MNGP BWR Penetrations

Program is part of the MNGP ASME Section Xl In-Service Inspection Program. The BWR

Penetrations Program is in accordance with the ASME Code, Section XI, 1995 edition through

the 1996 addenda (with approved ISI relief requests) and provides for condition monitoring of

the BWR penetrations. The BWR water chemistry is controlled in accordance with the EPRI

guidelines of BWRVIP-130 (TR-1 008192), "BWR Water Chemistry Guideli.nes-2004 Revision."

This document supersedes previous revisions of the guidelines, including BWRVIP-29

(TR-103515),"BWR Water Chemistry Guidelines-i1993 Revision." Program activities at

MNGP incorporate the inspection and evaluation guidelines of BWRVIP-49, "BWR Vessel and

Internals Project, Instrument Penetration Inspection and Flaw Evaluation Guidelines," for

instrument penetrations and BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby

Liquid Control System/Core Plate DP Inspection and Flaw Evaluation Guidelines," for the

standby liquid control (SLC) system. The applicant updates the program periodically as required

by 10 CFR 50.55a and the BWRVIP.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses consistency of the AMP

elements with GALL AMP XI.M8.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M8 in the GALL Report.

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Exception 1: The GALL Report recommends the following for the program description

associated with of the exception taken:

The program includes monitoring and control of reactor coolant water chemistry

in accordance with the guidelines of BWRVIP-29 (Electric Power Research

[EPRI] TR-1 03515) to ensure the long-term integrity and safe operation of boiling

water reactor (BWR) vessel internal components.

The GALL Report recommends the following for the Preventive Actions program element

associated with the exception taken:

Maintaining high water purity reduces susceptibility to SCC or IGSCC, and

reactor coolant water chemistry is monitored and maintained in accordance with

the guidelines in BWRVIP-29 (EPRI TR-1 03515).

In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-130

instead of the guidelines in BWRVIP-29 recommended by the GALL Report.

The staff evaluated this exception as part of the Plant Chemistry Program. SER Section

3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basis

for monitoring reactor water chemistry.

The applicant stated, in the LRA, that its BWR Penetrations Program is "in accordance with

ASME Section Xl, 1995 Edition through 1996 Addenda (with approved ISI relief requests)."

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP elements. In its response, by letter dated August

31, 2005, the applicant identified the following additional exception to the GALL Report program

elements.

Exception 2: The GALL Report recommends the following for the Detection of Aging Effects

program element associated with the identified exception:

Instrument penetrations and SLC system nozzles or housings are inspected in

accordance with the requirements of ASME Section XI, Subsection IWB.

Components are examined and tested as specified in Table IWB-2500-1,

examination categories B-E for pressure-retaining partial penetration welds in

vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for

pressure-retaining-dissimilar metal nozzle-to-safe-end welds, or B-J for similar

metal nozzle-to-safe end welds. In addition, these components are part of

examination category B-P for pressure-retaining boundary.

In its letter dated August 11, 2005, the applicant stated that its BWR Penetrations Program will

deviate from ASME Code, Section Xl, Table IWB-2500-1 and Figure IWB-2500-7(b)

requirements in terms of the examination volume for Category B-D components.

In its evaluation of the effects of current approved ISI relief requests and code cases, the

applicant stated that during the current ISI inspection interval, which will extend approximately

21 months into the period of extended operation, examination of Category B-D components

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(Full Penetration Welded Nozzles in Vessels) will deviate from the requirements of ASME

Code, Section Xl, Table IWB-2500-1, Item No. B3.90, and from the requirements of ASME

Code, Section Xl, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires that a

minimum volume of material equal to a distance of one-half the reactor vessel shell thickness

(i.e., a distance of approximately 2-1/2 inches) be included in the examination on each side of

the weld; however, the BWR Penetrations Program instead will examine a reduced volume of

one-half inch of base metal on each side of the widest portion of the weld. The applicant

identified this reduction in weld examination volume as an exception to the recommendations of

GALL AMP XI.M8. The applicant technically justified the reduction in examination volume as

follows:

The required examination volume for the reactor vessel pressure retaining

nozzle-to-vessel welds extends far beyond the weld into the base metal, and is

unnecessarily large. The proposed alternative re-defined the examination volume

boundary to 1⁄22 inch of base metal on each side of the widest portion of the weld,

removing from examination the base metal that was extensively examined during

prior inspections, and that is not in the high residual stress region associated

with the weld.

The creation of flaws during plant service in the volume excluded from the

proposed reduced examination is unlikely because of the low stress in the base

metal away from the weld. The stresses caused by welding are concentrated at

or near the weld. Cracks, should they initiate, occur in the high-stressed areas of

the weld. These high-stress areas are contained in the volume that is defined by

Code Case N-613-1 and are thus subject to examination. During previous

examinations, no indications exceeding the allowable limits of the preservice or

inservice criteria were found in the reactor vessel nozzle to shell examination

volumes including the base metal areas proposed for exclusion from examination

in this request.

In its letter dated August 31, 2005, the applicant stated that it considers the alternative

examination of Category B-D welds based on Code Case N-613-1 an exception to the

Detection of Aging Effects program element as described in GALL AMP XI.M8. The staff

reviewed the applicant's description and technical justification for this exception as summarized

in the preceding paragraph. The staff also reviewed the applicant's letter dated February 27,

2004, which provides a similar technical justification and includes tables of previous

examination results. Because the examination volume includes the heat-affected regions of

base metal around the welds where new cracks are most likely to occur and previous

examinations of the base metal beyond the heat-affected regions have not detected any

unacceptable indications, the staff concluded that this exception is acceptable.

During the audit and review, the staff noted that in the Detection of Aging Effects program

element the applicant referred parenthetically to "risk-informed ISI." Specifically, the first

sentence of the Detection of Aging Effects program element reads as follows:

The detection of aging effects is prescribed by the MNGP BWR Penetrations

Program in accordance with the requirements of ASME Section Xl,

Table IWB-2500-1 for Examination Categories B-D, B-0 and B-W and NRC

approved alternatives for Categories B-F and B-J (risk-informed ISI (RI-ISI)).

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The staff asked the applicant to address the effects of its RI-ISI associated with the Detection of

Aging Effects program element.

In its response, by letter dated August 31, 2005, the applicant stated that its implementation of

RI-ISI affects the Detection of Aging Effects program element of its BWR Penetrations Program

and is an exception to GALL AMP XI.M8.

Exception 3: The GALL Report recommends the following for the Detection of Aging Effects

program element associated with the exception:

Instrument penetrations and SLC system nozzles or housings are inspected in

accordance with the requirements of ASME Section Xl, Subsection IWB.

Components are examined and tested as specified in Table IWB-2500-1,

examination categories B-E for pressure-retaining partial penetration welds in

vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for

pressure-retaining dissimilar metal nozzle-to-safe end welds, or B-J for similar

metal nozzle-to-safe-end welds. In addition, these components are part of

examination category B-P for pressure-retaining boundary. Further details for

examination are described in Chapter XI.M1, "ASME Section XI, In-Service

Inspection, Subsection IWB, IWC, and IWD," of this report.

In the LRA, the applicant stated that its ASME Section Xl In-Service Inspection,

Subsections IWB, IWC, and IWD Program will include an RI-ISI methodology as an alternative

to the ASME Code, Section XI ISI requirements in terms of (1) the number of locations

inspected, (2) the locations inspected, and (3) the method of inspection. This alternative applies

to welds in ASME Code, Section Xl Categories B-F (Class 1 pressure-retaining dissimilar metal

welds in vessel nozzles), B-J (Class 1 pressure-retaining welds in piping), C-F-1 (Class 2

pressure-retaining welds in austenitic stainless steel or high-alloy piping), and C-F-2 (Class 2

pressure-retaining welds in carbon or low-alloy steel piping).

In its letter dated August 31, 2005, the applicant stated that its implementation of RI-ISI during

the current inspection interval affects both GALL AMP XI.M1 and GALL AMP XI.M8. The staff's

evaluation documented in SER Section 3.0.3.2.2, exception 7, applies to this exception, so the

staff concluded that the applicant's implementation of RI-ISI is an acceptable exception for

managing applicable component aging effects through the end of the applicant's current ISI

inspection interval on May 31, 2012, approximately 21 months into the extended operating

period.

On the basis of the review of the above exceptions and of operating experience for the BWR

Penetrations Program, the staff found these exceptions acceptable.

The staff reviewed those portions of AMP B2.1.9, "BWR Penetrations Program," that the

applicant claimed are consistent with GALL AMP XI.M8 and found them consistent. The staff

found the applicant's LRA AMP acceptable because it conforms to the recommended GALL

Report AMP with the exceptions as described above.

Operating Experience. In LRA Section B2.1.9, the applicant explained that it periodically

examines materials within the scope of the BWR Penetrations Program and evaluates them for

corrective action as needed. The program incorporates vendor guidance (e.g., BWRVIP-49 and

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-27). The applicant has implemented corrective actions to replace materials susceptible to

cracking. For example, (1) the SLC nozzle safe end was replaced in 1984 using different

materials to resist IGSCC, (2) in 1984 the jet pump instrumentation safe end and penetration

seal were replaced with a jet pump instrumentation nozzle penetration seal using 316L stainless

steel materials to resist IGSCC, and (3) a corrosion-resistant clad overlay was applied to the

inside diameter (ID) of the reactor vessel head vent nozzle (N7) and the reactor vessel head

cooling spray nozzles N6A & B (penetrations). The corrosion-resistant clad overlay isolated the

IGSCC susceptible weld butter from the reactor coolant.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the applicant's program against the program elements

described in the GALL Report AMP, the above industry and plant-specific operating experience,

and its discussions with the applicant's technical personnel, the staff concluded that the

applicant's BWR Penetrations Program will adequately manage the aging effects identified in

the LRA for which this AMP is credited.

USAR Sumplement. In LRA Section A2.1.9, the applicant provided the USAR supplement for

the BWR Penetrations Program. The staff noted that this USAR supplement includes

parenthetic mention of "approved ISI relief requests." In its letter dated August 31, 2005, the

applicant stated that it will delete the reference to ISI relief requests from the USAR supplement

description of the BWR Penetrations Program. The staff reviewed this section and determined

that the information in the USAR supplement after deletion of the reference to ISI relief

requests adequately describes the program as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's BWR Penetrations Program,

the staff determined that those program elements for which the applicant claimed consistency

with the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff concluded that the

applicant demonstrated that the effects of aging will be adequately managed so that intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concluded that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.2.9 BWR Stress Corrosion Cracking Program

Summary of Technical Information in the Application. In LRA Section B2.1.10, the applicant

described the BWR Stress Corrosion Cracking Program, stating that this existing program is

consistent, with exception, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking." The

applicant is implementing ASME Code, Section XI, with UT volumetric, surface, and visual

inspections and the RI-ISI program. The MNGP BWR Stress Corrosion Cracking Program

incorporates NUREG-0313 and NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic

Stainless Steel Piping," dated January 25, 1988, and its Supplement 1. The applicant has

replaced all IGSCC susceptible materials or protected them with a cladding of resistant weld

material. Therefore, all piping welds are now classified as IGSCC Category A in accordance

with NUREG-0313 and GL 88-01. As part of the MNGP recirculation piping replacement effort,

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the applicant replaced austenitic stainless steel portions of piping systems 4 inches in nominal

diameter or larger operating at temperatures above 200 OF of the reactor coolant pressure

boundary in accordance with the requirements of NUREG-0313. In addition, a hydrogen water

chemistry system now operates, which reduces the oxidizing environment by introducing excess

hydrogen to the RCS that combines with the free oxygen produced by radiolysis.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and the associated justifications to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M7.

The applicant stated that the LRA mentioned relief requests, including RHISI, as parts of the

current ASME Code, Section Xl programs credited with managing aging effects. The applicant

further stated that it did not consider relief requests as exceptions to GALL Report because

they are temporary and many will expire before the period of extended operation. The applicant

stated that code cases and relief requests related to its ASME Section XI In-Service Inspection,

Subsections IWB, IWC, IWD, and IWF Program are valid for approximately 21 months into the

period of extended operation and that the current inspection interval ends on May 31, 2012. In

addition, the applicant stated that except for one difference related to the Corrective Actions

program element, its implementation of RI-ISI and currently approved relief requests affect

none of its BWR Stress Corrosion Cracking Program elements. Consequently, as documented

in its letter dated August 31, 2005, the applicant stated that it will revise the LRA to delete all

references to the RI-ISI program in the BWR Stress Corrosion Cracking Program description.

The staff reviewed the applicant's BWR Stress Corrosion Cracking Program and additional

descriptions of its RI-ISI program in the applicant's letter dated December 18, 2001. On the

basis of its review, the staff concluded that the RI-ISI program and approved ISI relief requests

affect'no BWR Stress Corrosion Cracking Program elements. The staff also found that the

applicant's change to delete all references to the RI-ISI program in the description of its BWR

Stress Corrosion Cracking Program is acceptable.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M7 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Preventive Actions program

element associated with the exception taken:

The program delineated in NUREG-0313 and NRC GL 88-01 does not provide

specific guidelines for controlling reactor water chemistry to mitigate IGSCC;

however, maintaining high water purity reduces susceptibility to SCC or IGSCC,

and reactor coolant water chemistry is monitored and maintained in accordance

with the guidelines in BWRVIP-29 (Electric Power Research Institute (EPRI)

TR-103515).

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In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-1 30. This

document supersedes previous revisions of the BWR water chemistry guidelines, including

BWRVIP-29 referenced in the GALL Report.

The staff evaluated this exception as part of the Plant Chemistry Program. SER Section

3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basis

for monitoring reactor water chemistry.

During the audit and review, the staff asked the applicant whether its current approved ISI relief

requests or code cases affect any of its AMP elements. In its letter dated August 31, 2005, the

applicant identified the following additional exception to the GALL Report program elements.

Exception 2: The GALL Report recommends the following for the Corrective Actions program

element associated with the exception taken:

The guidance for weld overlay repair and stress improvement or replacement is

provided in NRC GL 88-01; ASME Section XI, Subsections IWB-4000 and

IWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively,

for Class 1, 2, or 3 components; and ASME Code Case 504-1.

In its letter dated August 11, 2005, the applicant stated that an approved alternative allows the

use of the ASME Code, Section Xl, 2001 edition in lieu of the 1995 edition with 1996 addenda

for repair/replacement activities.

The staff concluded that this alternative is not an exception and that with regard to this item, the

affected program element is consistent with the GALL Report. SER Section 3.0.3.1.7

documents the staff's evaluation.

The staff reviewed those portions of AMP B2.1 .10, "BWR Stress Corrosion Cracking Program,"

that the applicant claimed are consistent with GALL AMP XI.M7 and found them consistent. The

staff found the applicant's AMP acceptable because it conforms to the recommended GALL

Report AMP with the exceptions as described above.

Operating Experience. In LRA Section B2.1.10, the applicant explained that a review of plant

operating experience for the BWR Stress Corrosion Cracking Program identified no adverse

trends or issues with program performance. The applicant identified problems and corrected

them before they caused any significant impact to safe operation, and it took adequate

corrective actions to prevent recurrence. The BWR Stress Corrosion Cracking Program

effectively detects flaw indications in susceptible components and contains appropriate

guidance for evaluation or repair of flaws. As needed, plant staff can adjust the inspection plan

based on results to enhance program effectiveness. The applicant performs periodic

self-assessments of the program and reviews of industry and plant experience to identify any

needed improvements. Examples of corrective actions implemented as a result of program

activities include the following:

In 1984, a corrosion-resistant cladding overlay was applied to the ID of the head vent

nozzle and head cooling spray and instrumentation nozzles. The weld overlay of 308L

isolated the IGSCC susceptible existing weld butter located in the weld residual stress

area from the reactor coolant.

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" In 1984, the recirculation inlet safe ends and thermal sleeve assembly and the

recirculation outlet safe ends were replaced using nuclear-grade stainless steel

materials to resist IGSCC.

* In 1986, new CSP nozzle safe ends featuring a tuning fork design with a thermal'sleeve

were installed. The applicant performed this modification to minimize IGSCC in the CSP

system.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the applicant's program against the program elements

described in the GALL Report AMP, the above industry and plant-specific operating experience,

and discussions with the applicant's technical personnel, the staff concluded that the applicant's

BWR Stress Corrosion Cracking Program will adequately manage the aging effects identified in

the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2. 1.10, the applicant provided the USAR supplement for

the BWR Stress Corrosion Cracking Program. The staff reviewed this section and determined

that the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d). The staff noted that this USAR supplement describes "the risk-informed ISI

program" in the same way as in the applicant's statement on consistency with the GALL Report.

In its August 31, 2005, letter the applicant stated that it will delete the reference to the RI-ISI

program from the USAR supplement description of the BWR Stress Corrosion Cracking

Program.

Conclusion. On the basis of its review and audit of the applicant's BWR Stress Corrosion

Cracking Program, the staff determined that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the

staff reviewed the exception and the associated justifications and determined that the AMP,

with the exception, is adequate to manage'the aging effects for which it is credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21(d).

3.0.3.2.10 BWR Vessel ID Attachment Welds Program

Summary of Technical Information in the Application. In LRA Section B2.1.11, the applicant

described the BWR Vessel ID Attachment Welds Program, stating that this existing program is

consistent, with exception, with GALL AMP XI.M4, "BWR Vessel ID Attachment Welds." The

MNGP BWR Vessel ID Attachment Welds Program is part of the MNGP ASME Section XI

In-Service Inspection AMP. The BWR Vessel ID Attachment Weld Program is in accordance

with the ASME Code, Section XA, 1995 edition through the 1996 addenda and approved ISI

relief requests. The program provides for condition monitoring of the BWR vessel ID

attachment welds. It includes inspection and flaw evaluation in accordance with BWRVIP-48

(EPRI TR-108724), "Vessel ID Attachment Weld and Inspection and Flaw Guidelines.". The

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BWR water chemistry is controlled in accordance with the EPRI guidelines of BWRVIP-130".

The applicant updates the program periodically as required by 10 CFR 50.55a, and

supplements it by implementing the guidelines of the BWRVIP documents.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and the assbciated justifications to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M4.

In the LRA, the applicant stated the following exception to the program elements listed for AMP

XI.M4 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Preventive Actions program

element associated with the exception taken:

The BWRVIP-48 provides guidance on detection, but does not provide guidance

on methods to mitigate cracking. Maintaining high water purity reduces

susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored

and maintained in accordance with the guidelines in BWRVIP-29 (EPRI

TR-103515). The program description and evaluation and technical basis of

monitoring and maintaining reactor water chemistry are presented in

Section XI.M2, "Water Chemistry."

In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-1 30

instead of the guidelines in BWRVIP-29 recommended by the GALL Report.

The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents the

staff's evaluation.

During the audit and review, the staff asked the applicant to address whether its current

approved ISI relief requests or code cases affect any of its AMP program elements. In its letter

dated August 31, 2005, the applicant identified the following additional exception to the GALL

Report program elements.

Exception 2: The GALL Report recommends the following for the Corrective Actions program

element associated with the exception taken:

Repair and replacement procedures are equivalent to those requirements in the

ASME Section XI. Repair is in conformance with IWB-4000 and replacement

occurs according to IWB-7000. As discussed in the appendix to this report, the

staff found that licensee implementation of the guidelines in BWRVIP-48, as

modified, will provide an acceptable level of quality for inspection and flaw

evaluation of the safety-related components addressed in accordance with

10 CFR Part 50, Appendix B, corrective actions.

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In its letter dated August 11, 2005, the applicant stated that an approved alternative allows the

use of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996

addenda for repair/replacement activities.

The staff concluded that this alternative is not an exception and that with regard to this item, the

affected program element is consistent with the GALL Report. SER Section 3.0.3.1.7

documents the staff's evaluation.

The staff reviewed those portions of AMP B2.1.11, "BWR Vessel ID Attachment Welds

Program," that the applicant claimed are consistent with GALL AMP XI.M4 and found them

consistent. The staff found the applicant's AMP acceptable because it conforms to the

recommended GALL Report AMP with the exceptions as described above. I

Operatina Experience. In LRA Section B2.1.11, the applicant explained that it performed the

engineering evaluations based on plant and industry experience and implemented component

and programmatic corrective actions as required. For example, a vendor notification discussed

the susceptibility of Alloy 182 welds to IGSCC/interdendritic SCC in shroud support structures

such as those used in the MNGP vessel and shroud. BWRVIP-38, "BWR Shroud Support

Inspection and Flaw Evaluation Guidelines," provides guidance on the inspection of the shroud

support structure. The 2000 outage included inspection of the recommended 10-percent

portions of the H8 and H9 welds using enhanced visual examination (EVT)-I techniques around

the access holes at the 0 and 180 degree locations. No indications were found. In addition, the

applicant inspected 14 shroud support legs using a VT-3 technique because of flaw indications

found on the initially examined support leg. The applicant continues to inspect the H8 and H9

welds in accordance with BWRVIP-38 but has found no operability impacts.

The staff reviewed the applicant's operating experience evaluation for the BWR Vessel ID

Attachment Welds Program and interviewed the applicant's program manager for this program

to confirm that plant-specific operating experience revealed no degradation not identified by

industry experience.

On the basis its evaluation of the applicant's program against the program elements described

in the GALL Report AMP, review of the above industry and plant-specific operating experience,

and discussions with the applicant's technical personnel, the staff concluded that the applicant's

BWR Vessel ID Attachment Welds Program will adequately manage the aging effects identified

in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.11, the applicant provided the USAR supplement for

the BWR Vessel ID Attachment Welds Program. The staff reviewed this section and

determined that the information in the USAR supplement adequately describes the program, as

required by 10 CFR 54.21 (d). The staff noted that this USAR supplement mentions "approved

ISI relief requests." In its August 31, 2005, letter the applicant stated that it will delete the

reference to ISI relief requests from the USAR supplement description of the BWR Vessel ID

Attachment Welds Program.

Conclusion. On the basis of its review and audit of the applicant's BWR Vessel ID Attachment

Welds Program, the staff determined that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the

staff reviewed the exception and the associated justifications and determined that the AMP,

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with the exception, is adequate to manage the aging effects for which it is credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3), The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21(d).

3.0.3.2.11 BWR Vessel Internals Program

Summary of Technical Information in the Application. In LRA Section B2.1.12, the applicant

described the BWR Vessel Internals Program, stating that this existing program is consistent,

with exception and enhancement, with GALL AMP XI.M9, "BWR Vessel Internals." The BWR

Vessel Internals Program is part of the ASME Section XI In-Service Inspection Program. The

BWR Vessel Internals Program is in accordance with the ASME Code, Section Xl, 1995 edition

through the 1996 addenda and approved ISI relief requests. The program provides for condition

monitoring of the BWR vessel internals for crack initiation and growth. MNGP activities include

in-vessel examination procedures and plant water chemistry procedures. The in-vessel

examination procedures implement the recommendations of the BWRVIP guidelines, as well as

the requirements of the ASME Code, Section XI. This program relies on monitoring and control

of water chemistry to keep peak levels of various contaminants below system-specific limits

based on the EPRI guidelines in BWRVIP-130." This document supersedes previous revisions

of the BWR water chemistry guidelines, including BWRVIP-29. The applicant updates this

program periodically as required by 10 CFR 50.55a and the BWRVIP program.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and enhancement and the associated

justifications to determine whether the AMP, with the exception and enhancement, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M9.

During the audit and review, the staff noted that, in the LRA, the applicant's program description

stated that the BWR Vessel Internals Program is "in accordance with ASME Section XI 1995

Edition through 1996 Addenda and approved ISI relief requests." The staff asked that the

applicant clarify the phrase "and approved ISI relief requests." In its letter dated August 11,

2005, the applicant stated that the LRA mentions relief requests because they are parts of the

current ASME Code, Section XI programs credited with managing aging effects. The applicant

further stated that it did not consider relief requests as exceptions to the GALL Report because

they are temporary and many expire before the period of extended operation. The applicant

stated that code cases and relief requests of its ASME Section XI In-Service Inspection,

Subsections IWB, IWC, IWD and IWF Program are valid for approximately 21 months into the

period of extended operation and that the current inspection interval ends on May 31, 2012.

The applicant stated that none of its approved ISI relief requests affect any of the program

elements of the BWR Vessel Internals Program. Subsequently, as documented in its letter

dated August 31, 2005, the applicant revised the LRA to delete all references to ISI relief

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requests in the description of the BWR Vessel Internals Program. Upon review of the

applicant's evaluation of program elements against the approved relief requests, the staff found

that no approved ISI relief requests affect any BWR Vessel Internals Program element. On this

basis, the staff also found the applicant's revision to delete all references to ISI relief requests

in the description of its BWR Vessel Internals Program acceptable.

In the LRA, the applicant stated the following exception to the program elements listed for AMP

XI.M9 in the GALL Report.

Exception: The GALL Report recommends the following for the Preventive Actions program

element associated with the exception taken:

Maintaining high water purity reduces susceptibility to cracking due to SSC or

IGSCC. Reactor coolant water chemistry is monitored and maintained in

accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program

description and evaluation, and technical basis of monitoring and maintaining

reactor water chemistry are presented in Chapter XI.M2, 'Water Chemistry."

In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-130

instead of the guidelines in BWRVIP-29 recommended by the GALL Report.

The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents the

staff's evaluation.

In the LRA, the applicant stated that the following enhancement will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for the Scope of Program. program

element associated with the enhancement made:

The BWRVIP documents provide generic guidelines intended to present the

applicable inspection recommendations to assure safety function integrity of the

subject safety-related reactor pressure vessel internal components...

The various applicable BWRVIP guidelines are as follows:

Core shroud: BWRVIPs -07,-63, and -76; and BWRVIP-02,

Rev. 2.

Core plate: BWRVIP-25; BWRVIP-50.

Shroud support: BWRVIP-38; BWRVIP-52.

Low-pressure coolant injection (LPCI) coupling: BWRVIP-42;

BWRVIP-56.

Top guide: BWRVIP-26; BWRVIP-50.

Core spray: BWRVIP-18; BWRVIP-16 and BWRVIP-19.

Jet pump assembly: BWRVIP-41; BWRVIP-51..

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Control rod drive (CRD) housing: BWRVIP-47; BWRVIP-58.

Lower plenum: BWRVIP-47; BWRVIP-57.

Steam Dryer: BWRVIP-139

For each component or assembly, the first listed BWRVIP document provides guidelines for

inspection and evaluation and the second, or last, listed provides guidelines for repair design

criteria.

In addition, BWRVIP-44 provides guidelines for weld repair of nickel alloys, and BWRVIP-45

provides guidelines for weldability of irradiated structural components.

In the LRA, the applicant stated that it will add the repair/replacement guidelines in

BWRVIP-16, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to its BWR Vessel

Internals Program.

The applicant stated in the LRA that the enhancement is required to satisfy the GALL Report

AMP recommendations and that the enhancement is scheduled for completion before the

period of extended operation. The staff found that the addition of the listed BWRVIP documents

is an appropriate enhancement to the applicant's current program that will make the applicant's

BWR Vessel Internals Program consistent with the recommendations of the GALL Report

during the period of extended operation.

The staff asked the applicant to verify that it will implement the applicable BWRVIP guidelines

during the period of extended operation. In response, the applicant provided the following

description of its conformance with industry commitments for implementation of the BWRVIP

guidelines:

In a letter dated May 30,1997, from Carl Terry (Niagara Mohawk Power

Company, Chairman of BWR Vessel and Internals Project) to Brian Sheron

(NRC), the BWRVIP member utilities commitments were expressed. The letter

stated, 'We will implement the BWRVIP products at each of our plants as

appropriate considering individual plant schedules, configurations and needs.'

One such document is BWRVIP-94, Program Implementation Guide.

BWRVIP-94 states that each member utility, of which Monticello/NMC is, will

implement the BWRVIP guidelines tothe fullest extent possible.

Because the applicant's implementation documents indicate a very high degree of conformance

to BWRVIP guidelines, the staff considered this response acceptable. Additionally, in its letter,

dated March 15, 2006, the applicant submitted commitment 57, which states that NMC is an

active member of the BWRVIP and will continue to follow applicable inspection guidelines and

recommendations that the executive committee of the BWRVIP has reviewed and approved

throughout the period of extended operation.

SER Section 4.8 discusses the'staff's review of the impact of the time-limited aging analysis

(TLAA) of the reactor internals core plate holddown bolts. During review of the issues, the staff

requested that the applicant identify the results from the baseline inspections recommended for

the core plate holddown bolts in BWRVIP-25 (TR-1 07284), "BWR Core Plate Inspection and

Flaw Evaluation Guidelines," issued December 1996. The applicant stated that it had not yet

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completed the recommended inspections because tooling had not been developed to perform

the inspections. Therefore, the staff requested that the applicant complete this action before

entering the period of extended operation. If tooling is not available, the applicant could use

wedges that provide lateral restraint for the core plate, or propose alternative inspection

methods that the staff will review and approve. In its letter dated March 31, 2006, the applicant

provided commitment 60 in Appendix A, stating that before the period of extended operation, it

would either inspect the core plate holddown bolts in accordance with the BWRVIP inspection

guidelines, install the core plate wedges, or develop an alternative to the inspections identified

in BWRVIP-25 and submit it to the staff for review and approval. The staff found this response

acceptable because it is consistent with the inspection guidelines described in BWRVIP-25.

The staff reviewed those portions of the AMP B2.1.12, "BWR Vessel Internals Program," that

the applicant claimed are consistent with GALL AMP XI.M9 and found them consistent. The

staff found the applicant's AMP acceptable because it conforms to the recommended GALL

Report AMP with the exception and enhancement described above.

During the aging management inspection, the inspectors identified that additional changes were

necessary to ensure that the applicant adequately managed plant aging effects relating to

reactor vessel internals in accordance with the AMP.

The inspectors noted that incore monitoring instrument dry tubes are within the scope of the

AMP. However, these tubes are not subject to periodic inspections under the applicant's AMP

that credits the BWRVIP-130 BWR water chemistry guidelines and the ASME Code, Section X1

inspection programs. Because these tubes are subject to radiation-induced damage above the

threshold for irradiation-assisted SCC (IASCC), they could crack and cause pressure boundary

leakage. Operating experience for GALL AMP XI.M9 identified that cracking has been observed

at other BWRs. Furthermore, GE Service Information Letter (SIL)-409, "Incore Dry Tube

Cracks," recommended periodic (every other outage) visual examinations focused on the upper

2 feet of the tube to detect cracking. The applicant voluntarily implemented these examinations

for the current license; however, the applicant had not committed to continue with these

examinations during the period of extended operation. The applicant stated that the next annual

LRA revision will incorporate into its AMP the examinations of incore monitoring instrument dry

tubes recommended in GE SIL-409. In its letter, dated March 15, 2006, the applicant provided

commitment 56 in Table A.5, which states that NMC has inspected the incore monitoring dry

tubes at every other refueling outage and will continue to perform this inspection during the

period of extended operation, in accordance with the guidance provided in GE SIL-409. The

staff found the applicant's response acceptable because it ensures that aging effects for the dry

tubes will be adequately managed during the period of extended operation.

The inspectors determined that the steam dryer was within the scope of license renewal for its

structural function, and the applicant conducted periodic inspection of steam dryer welds

potentially subject to cracking. The applicant submitted the LRA before the issuance of the

BWRVIP inspection program guidance defined in BWRVIP-139, "Steam Dryer Inspection and

Flaw Evaluation Guidelines." The applicant stated that the next annual LRA revision would

incorporate the BWRVIP-139 steam dryer weld examinations into the AMP. In its letter, dated

March 15, 2006, the applicant provided commitment 58 in Table A.5, which states that NMC will

follow the guidance provided in BWRVIP-139 for the MNGP steam dryer inspections. The staff

found the applicant's response acceptable because BWRVIP-1 39 provides specific guidelines

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to ensure that cracking of the steam dryer will be adequately managed during the period of

extended operation.

In CAP 014359 (CR 20000209), the applicant documented that during the 2000 refueling

outage, areas of the steam dryer in close proximity to the main steam (MST) nozzles appeared

polished and that this wear could be caused by steam impingement. The applicant also

documented in AR 000032 that Vermont Yankee, with an identical steam dryer design, had

observed evidence of steam erosion at the underside of the steam dryer. To evaluate if steam

erosion was occurring, a degradation mechanism not identified for the steam dryer in GALL

AMP XI.M9, the applicant stated that it will reinspect the affected areas of the MNGP steam

dryer during the next refueling outage. The evaluation of the areas will determine if erosion is

an aging mechanism that needs to be managed.

The inspectors also identified that in LRA Table B1.6-1 1, the applicant stated that the internal

CSP piping welds P1, P2, and P3 were not inspected in accordance with BWRVIP-18, "Core

Spray Internals Inspection and Flaw Evaluation Guidelines," because mechanical clamps were

installed to ensure the structural integrity of the sparger T-box welds, and that a visual

inspection was conducted each outage to confirm that T-box integrity was maintained.

Specifically, the applicant performed a general visual examination (VT-3) of the mechanical

clamp repair hardware installed around the welds, instead of an enhanced visual examination

(EVT-1) of the welds.

BWRVIP-1 8 does not require examination of repaired CSP pipe welds unless the integrity of

the repair depends upon these welds. The inspectors noted that if cracks develop in the

noninspected CSP piping welds P1, P2, and P3, a cooling water flow diversion path would exist

outside the core shroud that could adversely affect the applicant's peak fuel clad temperature

analysis. Because the applicant's primary clad temperature analysis relied, to some extent, on

the leakage integrity for these repaired welds, the inspectors determined that these welds

should be inspected using EVT-1. methods to meet BWRVIP-18 requirements. Therefore, the

inspectors concluded that the applicant had deviated from the BWRVIP-1 8 guidance and that

this deviation should be identified as an exception to the GALL Report. The applicant stated

that it will change the LRA to remove statements about not inspecting these welds during the

next annual LRA revision, and that it will also change the applicable inspection procedures to

implement enhanced visual examinations of these welds. In its letter, dated March 15, 2006, the

applicant provided commitment 59 in Table A.5, which states that NMC will add inspection

requirements for the P1, P2, and P3 CSP piping welds in accordance with guidance provided in

BWRVIP-1 8, or subsequent revisions. The staff found the applicant's response acceptable

because it will ensure that aging effects that might impact the welds will be adequately

managed in accordance with the guidance in BWRVIP-18.

Operating Experience. In LRA Section B2.1.12, the applicant explained that the BWR Vessel

Internals Program is based on inspection requirements contained in plant procedures, which

incorporate the requirements of the ASME Code. Further, the ASME Code inspections are

enhanced with inspections requirements consistent with the BWRVIP. The inspection and

testing methodologies have been effective in detecting aging effects due to crack initiation and

growth. As shown in the following examples, the applicant performed engineering evaluations

based on plant and industry experience and implemented component and programmatic

corrective actions as required:

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* In 2003, UT inspection of the CSP line found cracking in the CSP piping slip joint welds.

The previous evaluation was determined to bound the current flaw size, and no further

action was necessary.

* In 1994, mechanical clamps were installed on both of the in-vessel tee box assemblies

for the CSP sparger loops A and B. This modification provided a permanent fix that

mitigates the crack in the CSP in-vessel lateral header and ensures the CSP system's

safety function.

0 In 1994, visual inspection of the jet pumps during the refueling outage revealed cracking

of tack welds on the jet pump restrainer bracket adjusting screws. The cracking was

attributed to high cycle fatigue from jet pump vibration. The applicant added new tack

welds to the jet pumps restrainer bracket adjusting screws.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

BWR Vessel Internals Program will adequately manage the aging effects identified in the LRA

for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.12, the applicant provided the USAR supplement for

the BWR Vessel Internals Program. The staff reviewed this section and determined that the

information in the USAR supplement: adequately describes the program, as required by

10 CFR 54.21 (d).

The staff noted that this USAR supplement also mentions "approved ISI relief requests." In its

letter, dated August 31, 2005, theapplicant stated that it will delete the reference to ISI relief

requests from the USAR supplement description of the BWR Vessel Internals Program.

In its letter, dated June 10, 2005, the applicant committed to add the repair/replacement

guidelines in BWRVIP-1 6, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to the BWR

Vessel Internals Program before the period of extended operation. In addition, during the period

of extended operation, the applicant committed to add top guide grid inspections using the

EVT-1 method of examination for the high fluence locations (grid beam and beam-to-beam

crevice slot locations with fluence exceeding 5.0x1020 neutrons per square centimeter (n/cm2)).

The applicant will inspect 10 percent of the total population within 12 years, with a minimum of

5 percent inspected within the first 6 years.

Conclusion. On the basis of its review and audit of the applicant's BWR Vessel Internals

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the exception and the associated justifications and determined that the AMP, with the

exception, is adequate to manage the aging effects for which it is credited. The staff also

reviewed the enhancement and confirmed that their implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

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the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21 (d).

3.0.3.2.12 Closed-Cycle Cooling Water System Program

Summary of Technical Information in the Application. In LRA Section B2.1.13, the applicant

described the Closed-Cycle Cooling Water (CCCW) System Program, stating that this existing

program is consistent, with exceptions and enhancement, with GALL AMP XI.M21,

"Closed-Cycle Cooling Water System." The MNGP CCCW System Program includes (1)

preventive measures to minimize corrosion and (2) periodic system and component

performance testing and inspection to monitor the effects of corrosion and confirm that intended

functions are met. Preventive measures include the monitoring and control of corrosion

inhibitors and other chemical parameters, such as pH, in accordance with the guidelines of

EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline," vendor recommendations,

and plant operating experience. EPRI TR-1007820 is the current revision (Revision 1) of

EPRI-1 07396, "Closed Cooling Water Chemistry Guidelines." As the applicant made only minor

changes to the MNGP CCCW System Program to implement EPRI TR-1007820, the program

is also still in accordance with the EPRI Revision 0 guidelines identified in GALL AMP XI.M21

(i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to confirm

function anrd monitor corrosion, in accordance with EPRI TR-1007820, vendor

recommendations, and industry and plant operating experience. A review of plant operating

experience demonstrates these measures ensure CCCW systems are performing their

intended functions.

The applicant has four systems within the scope of license renewal meeting the definition for

consideration as CCCW systems and portions of three additional systems (heat exchangers or

coolers) serviced directly by these cooling water systems. These systems and portions of

systems are not subject to significant sources of contamination, in which water chemistry is

controlled and heat is not rejected directly to a heat sink. The adequacy of chemistry control is

confirmed by routine sampling and monitoring for established limits and by equipment

performance monitoring to identify aging effects. Corrosion inhibitor concentrations are

maintained within limits based on a combination of EPRI TR-1 007820 guidelines, vendor

recommendations, and plant experience. System and component performance test results are

evaluated in accordance with EPRI TR-1 007820 guidelines and used as a basis for evaluating

the effectiveness of actions to mitigate cracking, corrosion, and heat exchanger fouling.

Acceptance criteria and tolerances are also based on system design parameters and functions.

Many chemical parameters monitored are based on ranges identical to or more restrictive than

those noted in both EPRI TR-1 007820 and EPRI TR-1 07396. Others are based on vendor

recommendations and plant experience. The frequency of performance and functional tests is

consistent with EPRI TR-1 007820 and based on plant operating experience, trends, and

equipment performance. System and component operability tests are typically more frequent

than once per cycle, whereas more intrusive inspections (e.g., disassembly, eddy current

testing) are performed less frequently.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and enhancement and the associated

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justifications to determine whether the AMP, with the exceptions and enhancement, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M21.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M21 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Scope of Program program

element associated with the exception taken:

A CCCW system is defined as part of the service water system that is not

subject to significant sources of contamination, in which water chemistry is

controlled and in which heat is not directly rejected to a heat sink. The program

described in this section applies only to such a system. If one or more of these

conditions are not satisfied, the system is to be considered an open-cycle cooling

water system. The staff notes that if the adequacy of cooling water chemistry

control can not be confirmed, the system is treated as an open-cycle system as

indicated in Action III of Generic Letter (GL) 89-13.

In the LRA, the applicant stated that its CCCW System Program uses EPRI TR-1 007820, not

EPRI TR-1 07396, as recommended by the GALL Report. EPRI TR-1 007820 is the current

revision (Revision 1) of EPRI TR-107396.

The GALL Report recommends using EPRI TR-1 07396 to monitor for corrosion effects. The

applicant uses EPRI TR-1007820, the revision of the same EPRI technical report. The staff

reviewed the EPRI TR-107396 standards, compared them to EPRI TR-1007820, and noted that

these EPRI reports contain both control and diagnostic parameters. EPRI defines control

parameters (e.g., pH, conductivity, or corrosion inhibitor concentration) as those that have an

immediate effect on corrosion and strict adherence to them is expected. EPRI defines

diagnostic parameters as those that provide baseline information on system conditions or that

assist in problem troubleshooting and adherence to them is suggested. EPRI based the

changes made to TR'-1007820 on industry experience updated since the original EPRI technical

report. The staff noted that the control parameters of the newer EPRI TR-1007820 are either

the same as or more conservative than those in the older EPRI TR-1 07396. On the basis of this

comparison, the staff determined that no technical concerns are associated with the use of

EPRI TR-1007820 and found the exception acceptable.

Exception 2: The GALL Report recommends the following for the Preventive Actions program

element associated with the exception taken:

The program relies on the use of appropriate materials, lining, or coating to

protect the underlying metal surfaces and maintenance of system corrosion

inhibitor concentrations within specified limits of EPRI TR-1 07396 to minimize

corrosion. The program includes monitoring and control of cooling water

chemistry to minimize exposure to aggressive environments and application of

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corrosion inhibitor in the CCCW system to mitigate general, crevice, and pitting

corrosion.

In the LRA, the applicant stated that the Closed-Cycle Cooling Water System Program does not

include some of the chemical parameters recommended for routine monitoring by EPRI

TR-1 007820 and EPRI TR-1 07396. Chosen parameters are deemed adequate.based on a

combination of system design features (which preclude the need for monitoring some

chemicals), makeup water source requirements, EPRI TR-1007820 guidelines, vendor

recommendations, and plant operating experience.

The applicant stated in the LRA that it monitors most of the chemical parameters recommended

by the GALL heport and EPRI TR-1 007820 in the closed-cycle cooling systems. The applicant

also stated that system design precludes any need to monitor several of these parameters, and

operating and inspection activities preclude the need to monitor others. The staff noted that the

LRA indicates the specific parameters monitored or excluded for the inhibitor type of each

CCCW system, and the PBD itemizes them on a parameter basis.

The staff concluded that the parameters that the applicant monitored in its CCCW systems

accomplished the same goal as did those recommended by the GALL Report. The only

parameters recommended for monitoring by EPRI that the applicant did not monitor are those

not used or applicable at MNGP.

On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,

the staff found this exception acceptable.

Exception 3: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the exception taken:

The aging management program (AMP) monitors the effects of corrosion by

surveillance testing and inspection in accordance with standards in EPRI

TR-107396 to evaluate system and component performance. For pumps, the

parameters monitored include flow and discharge and suction pressures. For

heat exchangers, the parameters monitored include flow, inlet and outlet

temperatures, and differential pressure.

In the LRA, the applicant stated that some of the heat exchanger and pump performance

parameters recommended by the GALL Report are not monitored for specific pumps or smaller

coolers serviced by the closed-cooling water systems. Some of these components are within

the scope of license renewal only for pressure boundary considerations. Chemical control and

established performance monitoring techniques based on plant experience have been

adequate to detect changes in system performance due to cracking or corrosion.

The staff reviewed selected inspection and monitoring procedures, then compared the required

heat exchanger and pump performance parameters against those recommended by the GALL

Report. The staff noted the following exceptions to the GALL Report recommendations and the

applicant's actions in lieu of those recommendations.

The applicant stated that, as an exception to the GALL Report, inlet reactor building closed

cooling water (RBC) heat exchanger temperature is not monitored; however, in addition to the

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recommendations of the GALL Report, the outlet RBC temperature and both inlet and outlet

raw water side temperatures are measured. After an evaluation, the staff found that the

additional information that the applicant had gathered is an adequate substitute for the

information recommended by the GALL Report, because it verifies that no aging effects reduce

heat transfer. The staff reviewed the applicant's additional information and found it acceptable.

The applicant stated that, as an exception to the GALL Report, the RHR and REC pump seal

coolers pressure is not monitored; however, flow through these pump seal coolers is monitored,

as are RBC surge tank level, various temperatures and flows, and radionuclide levels, all of

which alarm when values go out of range. These parameters indicate pressure integrity failures

within this closed loop system. Reduced heat transfer performance from temperature

monitoring results also can indicate internal corrosion. Additionally, the staff noted that the

applicant performed UT measurements of pipe wall thickness to determine the extent of

corrosion on select portions of RBC system piping, including piping connected to the REC

system pump seal coolers inside the drywell, which confirmed the effectiveness of water

chemistry. However, the staff found no direct inspection confirming chemistry effectiveness in

mitigating corrosion effects on the RBC system portion connected to the RHR system pump

seal coolers or CRD system pump coolers. The staff observed that as an enhancement, a

one-time inspection will monitor the effects of corrosion of the RHR system and CRD system

pump coolers and nearby connected piping. The staff found that the additional information that

the applicant had gathered adequately substituted for information recommended by the GALL

Report, because the parameters monitored will ensure that the pressure boundary intended

function will continue through the period of extended operation. The staff reviewed the

applicant's additional information and found it acceptable.

The applicant stated that, as an exception to the GALL Report, the emergency diesel

generator (EDG) jacket water pump suction and discharge pressures and flow are not

measured; however, water temperature, closed coolant level, lube oil pressure, and lube oil

temperature are monitored quarterly as part of EDG operability tests. As part of the 12-year

preventive maintenance (PM) requirements for the EDGs, the jacket water pumps are replaced,

the jacket water header of the lube oil cooler is visually inspected, and the jacket water system

is inspected for any evidence of leakage from piping or joints (a leak detector dye is used in the

coolant). The staff found that the additional information the applicant had gathered adequately

substituted for information recommended by the GALL Report, because the parameters

monitored will identify aging effects that may impact the intended function of the EDG. The staff

reviewed the applicant's additional information and found it acceptable.

The applicant stated that, as an exception to the GALL Report, differential pressure across the

EDG coolant heat exchangers is not monitored; however, heat exchanger performance is

tested periodically by gathering temperature and flow results. Eddy current testing of the heat

exchanger tubes is also periodic. The staff found that the additional information that the

applicant had gathered adequately substituted for information recommended by the GALL

Report, because it identifies aging effects reducing heat transfer. The staff reviewed the

applicant's additional information and found it acceptable.

The applicant stated that, as an exception to the GALL Report, it does not perform heating and

ventilation (HTV) system and component performance monitoring. The system contains no heat

exchangers, but does contain a number of heating coils for heating to various plant locations.

The scope of license renewal includes the piping system and heater coils for pressure integrity

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only. Some of the heating coils are visually inspected annually for leaks. After an evaluation, the

staff found that the additional information that the applicant had gathered adequately

substituted for information recommended by the GALL Report, because it will verify that the

pressure integrity intended function will continue through the period of extended operation. The

staff reviewed the applicant's additional information and found it acceptable.

On the basis of the above review and of a review of operating experience for AMP B2.1.13, the

staff found this exception acceptable.

Exception 4: The GALL Report recommends the following for the Acceptance Criteria program

element associated with the exception taken:

Corrosion inhibitor concentrations are maintained within the limits specified in the

EPRI water chemistry guidelines for CCCW. System and component

performance test results are evaluated in accordance with the guidelines of EPRI

TR-1 07396. Acceptance criteria and tolerances are also based on system design

parameters and functions.

In the LRA, the applicant stated that some of the acceptance criteria (ranges) for monitored

chemistry parameters based on vendor recommendations and plant operating experience are

not identical to the typical ranges specified by EPRI TR-1007820 or EPRI TR-107396. The

ranges based on plant operating experience have been sufficient to manage aging effects.

The staff observed that both EPRI TR-1 07396 and EPRI TR-1 007820 specify normal operating

ranges for chemical control parameters. They also specify diagnostic parameters, but do not

include action levels and ranges, as these parameters are used for trending. Specifically, with

regard to the four CCCW systems, the chemical control parameter ranges recommended by

EPRI, and hence by the GALL Report, and the corresponding ranges used at MNGP are as

follows:

(1) The following applies to the chromate-based RBC system, which also serves the RHR,

REC, and CRD coolers:

a. Chromate-Chromate is monitored to a range of 500 to 1800 parts per million

(ppm), not 150 to 300 ppm as recommended by the GALL Report and EPRI. As

noted in EPRI TR-1 07396 and EPRI TR-1 007820, this may have a detrimental

impact on pump seal integrity. The RBC pump seals are consumables. The

applicant installed a new design seal replaced on a 2-year frequency and has

monitored for but not detected any impact to system pressure boundary integrity.

b. pH-pH is monitored to a more restrictive range of 9.0 to 9.7 versus the EPRI

TR-1 07396 range of 8.5 to 10.5 and the EPRI TR-1 007820 range of 8.0 to 11.0.

c. Chloride-Chloride is not monitored in the RBC system. Chloride is monitored in

the makeup demineralized water source, which provides makeup to the RBC

system. Chloride limits for demineralized water have a limit of 10 parts per billion

(ppb), which is substantially lower than the limit of 10 ppm established by both

EPRI reports.

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(2) The following applies to the cooling loops of the EDG system (DGN):

a. Nitrite-The chemical range for nitrite is identical to that in EPRI TR-1 07396 (500

to 1000 ppm) and more restrictive than that in EPRI TR-1 007820 (50 to 1500

ppm).

b. pH--The range for pH is 9.0 to 10.7, which is more restrictive than the 8.5 to

11.0 range in EPRI TR-1 007820 and close to the 8.5 to 10.5 range specified in

EPRI TR-107396.

c. Tolytriazole-The specified range for tolytriazole is 10 to 40 ppm, as opposed to

the 5 to 30 ppm range recommended in EPRI TR-1 07396, and more restrictive

than the 5 to 100 ppm range recommended in EPRI TR-1 007820. EPRI TR107396 identified no adverse impacts for slightly higher tolytriazole ranges.

d. Chloride-Chloride is not monitored in the cooling loops of the DGN. Chloride is

monitored in the makeup demineralized water source, which provides makeup to

the cooling loops. Chloride limits for demineralized water have a limit of 10 ppb,

which is substantially lower than the limit of 10 ppm established by the EPRI

reports.

(3) The following applies to the piping and heating coils of the HTV system:

a. EPRI TR-107396 and EPRI TR-1 007820 do not specify chemical ranges for the

piping and heating coils of the HTV system, so they are monitored in accordance

with vendor recommendations and plant experience. These include conductivity,

pH, phosphate, sulfites, and total gamma activity and are specified by plant

procedure.

(4) The following applies to the closed cooling loop used on the #14 air compressor of the

instrument and service air (AIR) system:

a. Glycol percent volume-Both EPRI TR-1 07396 and EPRI TR-1007820

recommend that glycol percent volume remain above 30 percent to avoid

becoming a nutrient for microbiological growth. Further, EPRI TR-1 007820

recommends that the level remain below 60 percent. The applicant maintains a

concentration of about 50 percent, which is within the range specified by the

EPRI reports.

b. pH-MNGP procedures do not provide a specific range for pH; however,

procedures require routine sampling and measurement of pH, and pH is

maintained within the range specified by EPRI TR-1 007820 of 7.5 to 11.0.

The staff reviewed the operating ranges of each of the above 10 chemical control parameters

and noted that eight were either equivalent to or more conservative than the range

recommended by the EPRI technical reports. One, the chromate, had a higher range, but the

applicant took effective action to mitigate the effects of that higher range. The last was in

accordance with vendor recommendations and plant operating experience, as the GALL Report

provides no recommendation.

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On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,

the staff found this exception acceptable.

In the LRA, the applicant stated that the following enhancement will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the enhancement made:

The aging management program (AMP) monitors the effects of corrosion by

surveillance testing and inspection in accordance with standards in EPRI

TR-107396 to evaluate system and component performance. For pumps, the

parameters monitored include flow and discharge and suction pressures. For

heat exchangers, the parameters monitored include flow, inlet and outlet

temperatures, and differential pressure.

In the LRA, the applicant stated that a one-time inspection will monitor the effects of corrosion

on select portions of CCCW systems that perform a pressure-integrity intended function.

The staff reviewed the applicant's proposed enhancement and determined that augmenting the

CCCW systems with a one-time inspection to monitor the effects of corrosion on select portions

of CCCW systems that perform a pressure-integrity intended function will provide additional

assurance that aging effects are identified before component failures, consistent with GALL

AMP XI.M21. On the basis of its review, the staff found this enhancement acceptable, as such

changes to the applicant's program provide assurance that the effects of aging will be

adequately managed.

The staff reviewed those portions of AMP B2.1.13, "Closed-Cycle Cooling. Water System

Program," that the applicant claimed are consistent with GALL AMP XI.M21 and found them

consistent. The staff found the applicant's AMP acceptable because it conforms to the

recommended GALL Report AMP with the exceptions and enhancement as described above.

Operating Experience. In LRA Section B2.1.13, the applicant stated that, for the Closed-Cycle

Cooling Water System Program, it initiates CRs/ARs when it finds that water chemistry is out of

specification or equipment performance does not meet standards. The time duration of these

conditions is typically short and no evidence of detrimental equipment impacts was found. The

applicant did not identify any examples of CCCW system functional failures due to corrosion,

SCC, or heat transfer degradation due to fouling resulting from inadequate chemistry control.

Steam leaks have occurred in various portions of the piping and heating coils of the HTV

system (steam traps, temperature control valve packing/gaskets, heating coils, and fittings).

These leaks have been isolated and corrected, were typically minor in nature, did not impact

the operation of nearby safety equipment, and were not linked to inadequate chemistry or

corrosion as the cause of the leak. Procedural requirements for chemistry limits are established

based on EPRI and industry standards and routinely monitored. The applicant entered a CR

into the site CAP because a liquid penetrant examination showed a pin-hole leak on the top

side of a sampling line at the tubing end of a tubing-to-insert fillet weld (sampling line connected

on top of an RBC heat exchanger). Inadequate original welding of the connection was

determined to be the cause of the leak. Adjacent and external surfaces did not show pitting or

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other signs of distress, suggesting this was a localized effect. The applicant removed and

replaced the affected section of stainless steel tubing.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

CCCW System program will adequately manage the aging effects identified in the LRA for

which this AMP is credited.

USAR Supplement. In LRA Section A2.1.13, the applicant provided the USAR supplement for

the CCCW System Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.13,

documented as commitment 23 in Table A.5, that before the period of extended operation, it will

conduct a one-time inspection to monitor the effects of corrosion on select portions of CCCW

systems performing a pressure-integrity intended function.

Conclusion. On the basis of its review and audit of the applicant's CCCW System Program, the

staff determined that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff also reviewed the

enhancement and confirmed that their implementation before the period of extended operation

will result in the existing AMP being consistent with the GALL Report AMP to which it was

credited. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will 'be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.13 Compressed Air Monitoring Program

Summary of Technical Information in the Application. In LRA Section B2.1.14, the applicant

described the Compressed Air Monitoring Program, stating that this existing program is

consistent, with exceptions and enhancements, with GALL AMP XI.M24, "Compressed Air

Monitoring." The MNGP Compressed Air Monitoring Program consists of inspection, monitoring,

and testing of the AIR system to provide reasonable assurance that they will perform their

intended function for the duration of extended operation.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and enhancements and the

associated justifications to determine whether the AMP, with the exceptions and enhancements,

remains adequate to manage the aging effects for which it is credited.

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The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M24.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XLM24 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the exception taken:

In-service inspection (ISI) and testing is performed to verify proper air quality and

confirm that maintenance practices, emergency procedures, and training are

adequate to ensure that the intended function of the air system is maintained.

In the LRA, the applicant stated that it does not perform ISI and inservice testing to verify

proper air quality or confirm that maintenance practices, emergency procedures, and training

are adequate to ensure that the air system intended function is maintained. This is not an ISI or

inservice testing function or activity. Staff engineering personnel verify air quality through

semiannual testing in accordance with procedures based on GL 88-14, "Instrument Air Supply

System Problems Affecting Safety Equipment," dated August 8, 1988; American National

Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3, "Quality Standard for

Instrument Air;" ANSI Z86.1-1973, "Commodity Specification for Air and Drager Operating

Instruction;" and EPRI TR-1 03595, "Report of Instrument Air Working Group." Station

administrative and training procedures control maintenance practices, emergency procedures,

and training.

On the basis of its review of NRC, EPRI, and other industry guidelines and standards, the staff

determined that the applicant's inspection and testing verify proper air quality and confirm that

maintenance practices, emergency procedures, and training are adequate to ensure that the

intended function of the compressed air monitoring systems is maintained. Procedures and

programs at MNGP implement Compressed Air Monitoring Program activities recommended by

the GALL Report. The MNGP audit and review report details the staff's review. On the basis of

a review of the above exception and of operating experience for the Compressed Air Monitoring

Program, the staff found this exception acceptable.

Exception 2: The GALL Report recommends the following for the Detection of Aging Effects

program element associated with the exception taken:

Guidelines in EPRI NP-7079, EPRI TR-1 08147, and ASME OM-S/G-1 998, Part

17, ensure timely detection of degradation of.the compressed air system

function. Degradation of the piping and any equipment would become evident by

observation of excessive corrosion, by the discovery of unacceptable leakage

rates, and by failure of the system or any item of equipment to meet specified

performance limits.

In the LRA, the applicant stated that its program is based on the guidance provided in

ANSI/ISA-S7.3-1975, ANSI/ISA-Z86.1-1973, EPRI TR-103595, and GL 88-14 augmented by

previous NRC IN 81-38, "Potentially Significant Equipment Failures Resulting for Contamination

of Air-Operated Systems," dated December 17, 1981; IN 87-28, "Air System Problems at U.S.

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Light-Water Reactors," dated June 22, 1987; IN 87-28 Supplement 1, and by the INPO

Significant Operating Event Report (INPO SOER) 88-01. The applicant takes exception to

ANSI/ISA-S7.0.01-1996 because it uses ANSI/ISA-S7.3-1975 instead. The applicant takes

exception to ASME OM-S/G-1 998 Part 17 as specified in GALL AMP XI.M24.

The staff observed that, in lieu of the EPRI NP-7079 guidelines recommended by the GALL

Report to detect degradation of compressed air system function, the applicant developed

procedures and instructions based on GL 88-14, ANSI/ISA S7.3-1975, ANSI/ISA Z86.1-1973,

EPRI TR-103595, INPO SOER 88-01 augmented by IN 81-38, and IN 87-28 with Supplement

1. The staff reviewed and compared ANSI/ISA-S7.3-1975 with ANSI/ISAS7.0.01-1996 and

found ANSI/ISA-S7.3-1975 acceptable for use as its criteria are more conservative than

recommended by ANSI/ISA-S7.0.01-1996.

During the audit, the staff asked that the applicant clarify its reason for taking exception to

ASME OM-S/G-1 998, Part 17, which provides guidance for performance testing of instrument

air systems in light-water reactor power plants. The applicant responded that the scope of

components included in the compressed air monitoring activities includes distribution piping,

valves, accumulators for air-operated SR valves, and the containment isolation valves of the

instrument air system. The applicant stated that the instrument air system compressors,

receivers, filters, and dryers are not within the scope of license renewal. The applicant also

stated that its Compressed Air Monitoring Program will adequately manage aging for those

instrument air system components within the scope of license renewal. The staff reviewed

several procedures and instructions to determine their adequacy and completeness, their

frequencies, and their results, including a sampling from the applicant's CAP, and concluded

that the applicant is able to ensure timely detection of degradation of the compressed air

system function, as shown by its ability to detect corrosion or high leak rates or the failure of

any component to meet its performance limits. The staff found the applicant's response

acceptable.

On the basis of a review of the above exception and of a review of operating experience for the

Compressed Air Monitoring Program, the staff found this exception acceptable.

In the LRA, the applicant stated that the following enhancements will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement 1: The GALL Report recommends the following for the Scope of Program

program element associated with the enhancement made:

The program manages the effects of corrosion and the presence of

unacceptable levels of contaminants on the intended function of the compressed

air system. The AMP includes frequent leak testing of valves, piping, and other

system components, especially those made of carbon steel, and a preventive

maintenance program to check air quality at several locations in the system.

In the LRA, the applicant stated that it will revise the Compressed Air Monitoring Program

procedures to include corrective action requirements if water vapor, oil content, or particulate

acceptance limits are not met. In addition, it will clarify the acceptance criteria for oil content

testing and provide the acceptance limit bases for water vapor, oil content, and particulate tests.

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During the audit, the staff asked that the applicant clarify the above enhancement. The

applicant responded that, although it regarded the guidance identified in Exception 2 as

conservative compared to the guidance recommended by the GALL Report, it wanted to apply

further conservatism in the event that acceptance criteria were not met in any area. The

acceptance criteria of the compressed air monitoring systems procedures are evaluated under

the CAP. The staff reviewed the enhancement and found this potential augmentation of the

acceptance criteria of the compressed air monitoring systems procedures consistent with the

recommendations of the GALL Report as it provides additional assurance that aging effects are

identified before compressed air monitoring system component failure. Therefore, the staff

found this enhancement acceptable.

On the basis of a review of the above enhancement and a review of operating experience for

the Compressed Air Monitoring Program, the staff found the enhancement acceptable as such

changes to the applicant's program provide assurance that the effects of aging will be

adequately managed.

Enhancement 2: The GALL Report recommends the following for the Detection of Aging

Effects program element associated with the enhancement made:

Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part

17, ensure timely detection of degradation of the compressed air system

function. Degradation of the piping and any equipment would become evident by

observation of excessive corrosion, by the discovery of unacceptable leakage

rates, and by failure of the system or any item of equipment to meet specified

performance limits.

In the LRA, the applicant stated that it will revise its Compressed Air Monitoring Program to

include inspection of air distribution piping based on recommendations of EPRI TR-1 08147,

"Compressor and Instrument Air System Maintenance Guide," issued March 1998.

During the audit, the staff asked that the applicant clarify the above enhancement. The

applicant responded that EPRI TR-1 08147 addressed the subject piping with updated

recommendations. The staff reviewed the enhancement and determined that expanding the

detection of aging effects by including air distribution piping is consistent with the

recommendations of the GALL Report and will provide additional assurance that aging effects

are identified before compressed air monitoring component failure.

On the basis of a review of the above enhancement and a review of the operating experience

for the Compressed Air Monitoring Program, the staff found this enhancement acceptable as

such changes to the applicant's program provide assurance that the effects of aging will be

adequately managed.

The staff reviewed those portions of AMP B2.1.14 "Compressed Air Monitoring Program," that

the applicant claimed are consistent with GALL AMP XI.M24 and found them consistent. The

staff found the applicant's AMP acceptable because it conforms to the recommended GALL

Report AMP with the exceptions and enhancements as described above.

Operating Experience. In LRA Section B2.1.14, the applicant explained that it based the

Compressed Air Monitoring Program on appropriate NRC requirements and industry guidance,

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including the MNGP response to NRC GL 88-14. It perfo'rms established PM tasks and other

inspections on a routine basis. For example, it performed and completed a major PM task in

June 2003. Plant staff identified a number of system leaks, notified the system engineer, and

initiated and completed repair WOs to fix the leaks. Such PM activities and inspections, system

repairs, ongoing monitoring, and review of plant and industry operating experience have been

effective in maintaining air system performance. Unavailability targets for this system are well

within established goals.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

.discussions with the applicant's technical personnel, the staff concluded that the Compressed

Air Monitoring Program will adequately manage the aging effects identified in the LRA for which

this AMP is credited.

USAR Supplement. In LRA Section A2.1.14, the applicant provided the USAR supplement for

the Compressed Air Monitoring Program. The staff reviewed this section and determined that

the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

In its letter, dated June 10, 2005, the applicant added commitments to USAR Section A2.1.14,

documented as commitments 24 and 25 in Table A.5, that before the period of extended

operation, it will (1) revise Compressed Air Monitoring Program procedures to include corrective

action requirements if the acceptance limits for water vapor, oil content, or particulate are not

met, clarify acceptance criteria for oil content testing, and provide the basis for the acceptance

limits for the water vapor, oil content, and particulate tests and (2) revise the Compressed Air

Monitoring Program to include inspection of air distribution piping based on the

recommendations of EPRI TR-1 08147.

Conclusion. On the basis of its review and audit of the applicant's Compressed Air Monitoring

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the exceptions and the associated justifications and determined that the AMP, with the

exceptions, is adequate to manage the aging effects for which it is credited. The staff also

reviewed the enhancements and confirmed that their implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21 (d).

3.0,3.2.14 Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program

Summary of Technical Information in the Application. In LRA Section B2.1.16, the applicant

described the Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

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Requirements Used in Instrumentation Circuits Program, stating that this new program is

consistent, with exceptions, with GALL AMP XI.E2, "Electrical Cables and Connections Not

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation

Circuits." This program applies to non-EQ electrical cables used in radiation monitoring and

nuclear instrumentation circuits with sensitive, low-level signals that are within scope of license

renewal and are installed in adverse localized environments caused by heat, radiation, and

moisture in the presence of oxygen. Exposure of electrical cables to adverse localized

environments caused by heat or radiation can result in reduced insulation resistance (IR).

Reduced IR causes an increase in leakage currents between conductors and from individual

conductors to ground. A reduction in IR is a concern for circuits with sensitive, low-level signals

such as radiation monitoring and nuclear instrumentation since it may contribute to inaccuracies

in the instrument loop.

This AMP uses routine calibration tests performed as part of the plant surveillance test program

to identify the potential existence of aging degradation. When an instrumentation loop is found

to be out of calibration during routine surveillance testing, troubleshooting is performed on the

loop, including the instrumentation cable. In cases in which a calibration or surveillance program

does not include the cabling system in the testing circuit, or as an alternative to the review of

calibration results described above, the applicant will perform cable system testing. Plant staff

will perform a proven cable system test for detecting deterioration of the insulation system

(such as IR tests, time domain reflectometry test, or other testing judged to be effective in

determining cable insulation condition).

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.E2.

In the LRA, the applicant stated the following exception to the program elements listed for AMP

XI.E2 in the GALL Report.

Exception: The GALL Report identifies the following criteria for the Parameters Monitored or

Inspected, Detection of Aging Effects, and Acceptance Criteria program elements associated

with the exception taken:

Parameters Monitored/Inspected:

The parameters monitored are determined from the plant technical

specifications and are specific to the instrumentation loop being

calibrated, as documented in the surveillance testing procedure.

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Detection of Aging Effects:

Calibration provides sufficient indication of the need for corrective

actions by monitoring key parameters and providing trending data

based on acceptance criteria related to instrumentation loop

performance. The normal calibration frequency specified in the plant

technical specifications provides reasonable assurance that severe

aging degradation will be detected prior to loss of the cable intended

function. The first tests for license renewal are to be completed before

the period of extended operation.

Acceptance Criteria:

Calibration readings are to be within the loop-specific acceptance

criteria, as set out in the plant technical specifications surveillance test

procedures.

In the LRA, the applicant stated that the surveillance tests required by its TS either do not

include all cables within the scope of license renewal or do not include the cable as part of the

calibration procedure. The program will periodically test the cable insulation condition for those

cables not already tested by TS requirements.

The applicant further stated that for those cables not tested as part of TS surveillance

procedures, the program will periodically test the cable insulation. The staff reviewed the

applicant's exception and found it acceptable because Interim Staff Guidance (ISG)-1 5 states

that either (.1) calibration results or findings of surveillance testing or (2) direct testing of cable

systems can be used to detect aging degradation of electrical cables not subject to

10 CFR 50.49 EQ requirements used in instrumentation circuits.

On the basis of its review of the Electrical Cables Not Subject to 10 CFR 50.49 EQ

Requirements Used in Instrumentation Circuits Program and in conjunction with the operating

experience, the staff found this exception acceptable.

The staff reviewed those portions of the AMP B2.1.16, "Electrical Cables Not Subject to

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits

Program," that the applicant claimed are consistent with GALL AMP XI.E2 and found them

consistent. The staff found the applicant's AMP acceptable because it conforms to the

recommended GALL Report AMP with the exception as described above.

Operating Experience. In LRA Section B2.1.16, the applicant stated that the Electrical Cables

Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program is a

new program and as such has no plant-specific operating experience; however, as noted in the

GALL Report, industry operating experience shows that exposure of electrical cables to adverse

local environments caused by heat or radiation result in reduced IR. Reduced IR causes an

increase in leakage currents between conductors and from individual conductors to ground. A

reduction in IR is a concern for circuits with sensitive, low-level signals like radiation monitoring

and nuclear instrumentation circuits as it may contribute to signal inaccuracies.

3-93
During the audit and review, the staff asked the applicant how it captures operating experience.

The applicant stated that its CAP identifies, tracks, and trends site operating experience with all

site components. The applicant documents any site component identified as degraded, failed,

or potentially unable to fulfill intended functions in the site CAP database. Plant engineering

staff then evaluate these CAPs for the extent of the condition and take appropriate followup

actions. Plant engineering staff also trend related CAPs to identify generic issues. They

address trended site issues in program health reports and present them to site management on

a scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating

events from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant's

response and found it acceptable.

The staff recognizes that the CAP, which captures internal and external plant operating

experience issues, ensures review and incorporation of operating experience as objective

evidence to support the conclusion that aging effects are adequately managed.

USAR Supplement. In LRA Section A2.1.16, the applicant provided the USAR supplement for

the Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation

Circuits Program. The staff reviewed this section and determined that the information in the

USAR supplement adequately describes the program, as required by 10 CFR 54.21 (d).

In its letter, dated June 10, 2005, the applicant included a commitment to USAR

Section A2.1.16, documented as commitment 27 in Table A.5, which states the following:

Prior to the period of extended operation, the Electrical Cables Not Subject to

10 CFR 50.49 Environmental Qualification Requirements Used in

Instrumentation Circuits Program will be implemented as a new program. With

exceptions, it will be consistent with the recommendations of NUREG-1 801

Chapter Xl Program XI.E2.

Conclusion. On the basis of its review and audit of the applicant's Electrical Cables Not Subject

to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program, the staff

determined that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff concluded that the

applicant demonstrated that the effects of aging will be adequately managed so that intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concluded that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.2.15 Fire Protection Program

Summary of Technical Information in the Application. In LRA Section B2.1.17, the applicant

described the Fire Protection Program, stating that this existing program is consistent, with

exception and enhancement, with GALL AMP XI.M26, "Fire Protection." For license renewal

purposes, the MNGP Fire Protection Program includes a fire barrier inspection program, a

diesel-driven fire pump inspection program, and a halon fire suppression system inspection.

The fire barrier inspection program requires periodic visual inspection of fire barrier penetration

seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests

3-94
of associated fire rated doors to ensure that their operability is maintained. The diesel-driven

fire pump inspection program requires that the pump be periodically tested and the diesel

engine inspected to ensure that the fuel supply line can perform the intended function. The

halon fire suppression system inspection included periodic inspection and testing of the cable

spreading room halon fire suppression system.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and enhancement and the associated

justifications to determine whether the AMP, with the exception and enhancement, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M26.

In the LRA, the applicant stated the following exception to the program elements listed for AMP

XI.M26 in the GALL Report.

Exception: The GALL Report recommends the following for the Parameters Monitored and

Inspected program element associated with the exception taken:

Periodic visual inspection and function test at least once every six months

examines the signs of degradation of the halon/carbon dioxide fire suppression

system. The suppression agent charge pressure is monitored in the test.

Material conditions that may affect the performance of the system, such as

corrosion, mechanical damage, or damage to dampers, are observed during

these tests. Inspections performed at least once every month to verify that the

extinguishing agent supply valves are open and the system is in automatic

mode.

In the LRA, the applicant stated that it conducts periodic visual inspections and function tests of

halon systems at least once every 6 months. The cable spreading room halon system is

functionally tested and visually inspected every 18 months instead of every 6 months as

recommended in GALL AMP XI.M26.

In LRA Section B2.1.17 and the associated basis document, the applicant provided its

justification conducting these activities every 18 months instead of every 6. According to the

applicant, the surveillance interval specified in the Operations Manual is part of the

NRC-approved Fire Protection Program, and thus forms an element of the plant's CLB. In

response to the staff interviews, the applicant's personnel provided further information,

including the System Health Report-Fire Protection.

The applicant's technical personnel stated that they reviewed industry operating experience, the

previous cable spreading room halon system surveillance test results, and plant-specific

operating experience for this subsystem. This review of operating experience revealed no

age-related degradation, and thus the applicant stated that the 18-month frequency is

acceptable.

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The staff interviewed the applicant about parameters monitored or inspected as part of fire

protection (FP) relative to the guidelines for the frequency of inspections. The applicant stated

that the program has specific guidelines for the frequency of inspections requiring, for example,

visual inspections of penetration seal fire area boundaries protecting safe-shutdown equipment

every 18 months or following repair or maintenance of such penetrations. These inspections

cover 10 percent of each type of seal, consistent with GALL Report recommendations. The staff

also reviewed other inspection criteria for fire doors, the diesel driven fire pump, and the

halon/carbon dioxide systems. Based on the staff's review of industry and plant-specific

operating experience, performance of surveillance tests, and the FP system health reports, the

exception of the inspection frequency of 18 months instead of 6 months is acceptable, because

the incubation period for the effect is long, and the different inspection frequencies did not

result in any differences in finding aging effects.

In the LRA, the applicant stated that the following enhancement will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement: The 'GALL Report recommends the following for the Detection of Aging Effects

program element associated with the enhancement made:

...If any sign of degradation is detected within that 10 percent, the scope of the

inspection and frequency is expanded to ensure timely detection of increased

hardness and shrinkage of the penetration seal before the loss of the component

intended function. Visual inspection (VT-1 or equivalent) of the fire barrier walls,

ceilings, and floors performed in walkdown at least once every refueling outage

ensures timely detection for concrete cracking, spalling, and loss of material.

Visual inspection (VT-3 or equivalent) detects any sign of degradation of the fire

door such as wear and missing parts...

In the LRA, the applicant stated that it will revise its existing Fire Protection Program cable

spreading room halon visual inspection procedure to include inspection for any signs of

degradation such as corrosion and mechanical damage. This visual inspection will manage

aging for external surfaces of the cable spreading room halon fire suppression system. The

applicant will revise the Fire Protection Program plan document to include qualification criteria

for individuals visually inspecting penetration seals, fire barriers, and fire doors. The

qualification criteria will be in accordance with VT-1 or equivalent and VT-3 or equivalent, as

applicable.

The staff's evaluation and review of plant-specific operating experience found the enhancement

to the Fire Protection Program to detect signs of aging by including qualification criteria for

inspection personnel and VT-1 and VT-3 inspections of the penetration seals, fire barriers, and

fire doors to be acceptable and consistent with the GALL Report for this AMP, which will

manage aging during the period of extended operation.

On the basis of the staff evaluation of the above enhancement and review of the operating

experience for the Fire Protection Program, the staff found this enhancement acceptable as

such changes to the applicant's program provide assurance that the effects of aging will be

adequately managed.

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The staff reviewed those portions of AMP B2.1.17, "Fire Protection Program," that the applicant

claimed are consistent with GALL AMP XI.M26 and found them consistent. The staff found the

applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with

the exception and enhancement as described above.

Operatinq Experience. In LRA Section B2.1.17, the applicant explained that, through the use of

established plant surveillance and procedures, its staff inspects barriers and other features on a

periodic basis. Recent assessments have noted that the overall material condition is good. For

example, the December 2000 self-assessment using industry guidance (NEI Self- Assessment

Guide 99-05) concluded that the observed seals and fireproofing appeared to be in good

condition. The applicant documents and resolves problems through the site CAP. It entered

prior issues with program performance noted during the NRC 2002 inspection into the site CAP

database for assessment and resolution. MNGP implemented a number of extensive corrective

actions to improve program performance, including improved identification and resolution of

deficiencies. It performed an extensive self-assessment in March 2004 to evaluate progress

and program compliance. Though some areas of vulnerability were noted for correction and

continued focus, a number of program strengths were identified and the assessment concluded

that the MNGP program is consistent with corporate directive requirements and had made

significant progress in addressing the findings from the 2002 inspection.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's Fire Protection Program

will adequately manage the aging effects identified in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.17, the applicant provided the USAR supplement for

the Fire Protection Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter, dated June 10, 2005, the applicant included the following two commitments to

Section A2.1.17, documented as commitments 28 and 29 in Table A.5, that it will implement

before the period of extended operation:

(1) The applicant will revise the Fire Protection Program to include a visual inspection of the

halon fire suppression system to detect any signs of degradation, such as corrosion, or

mechanical damage. This visual inspection will manage aging for external surfaces of

the halon fire suppression system.

(2) The applicant will'revise the Fire Protection Program to include qualification criteria for

individuals visually inspecting penetration seals, fire barriers, and fire doors. The

qualification criteria will be in accordance with VT-1, VT-3, or equivalent as applicable.

Conclusion. On the basis of its review and audit of the applicant's Fire Protection Program, the

staff determined that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

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exception and the associated justifications and determined that the AMP, with the exception, is

adequate to manage the aging effects for which it is credited. The staff also reviewed the

enhancement and confirmed that its implementation before the period of extended operation

will result in the existing AMP being consistent with the GALL Report AMP to which it was

credited. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.16 Fire Water System Program

Summary of Technical Information in the Application. In LRA Section B2.1.18, the applicant

described the Fire Water System Program, stating that this existing program is consistent, with

enhancement, with GALL AMP XI.M27, "Fire Water System." The Fire Water System Program

relies on testing of water-based FP system piping and components in accordance with

applicable National Fire Protection Association (NFPA) recommendations. In addition, the

applicant will modify this program to include (1) portions of the FP sprinkler system that are

subjected to full flow tests before the period of extended operation and (2) portions of the FP

system exposed to water that are internally visually inspected. To ensure that the aging

mechanisms of corrosion and biofouling/fouling are properly being managed in the fire water

system, the applicant conducts periodic full flow flush tests and system performance tests. The

system is also normally maintained at required operating pressure and is monitored such that

loss of system pressure is immediately detected and corrective actions initiated.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancement and the associated justifications to

determine whether the AMP, with the enhancement, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M27.

In the LRA, the applicant stated that the following enhancement will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for the Program Description

program element associated with the enhancement made:

...In addition, a sample of sprinkler heads is to be inspected by using the

guidance of NFPA 25, Section 2.3.3.1. This NFPA section 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...

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In the LRA, the applicant stated it will enhance the Fire Water System Program by

implementing procedures that will be revised to include the extrapolation of inspection results to

below-grade fire water piping with conditions similar to those within the above-grade fire water

piping. It will inspect and test the Fire Water System Program sprinkler heads or replace them

before the end of the 50-year sprinkler head service life and at 1 0-year intervals thereafter

during the extended period of operation to ensure that signs of degradation, such as corrosion,.

are detected promptly. Enhancements are scheduled for completion before the period of

extended operation.

The staff found in its evaluation and review of plant-specific operating experience that the

enhancement to the Fire Water System Program to detect signs of aging by wall thickness

evaluations on above-grade piping, inspections before the period of extended operation, and

extrapolations of above-ground conditions to below-ground piping for further inspections is

acceptable and consistent with GALL Report recommendations relying on NFPA codes and

with GALL AMP XI.M27.

On the basis of its review of the above enhancement and review of operating experience for the

MNGP Fire Water System Program, the staff found this enhancement acceptable as such

changes to the applicant's program provides assurance that the effects of aging will be

adequately managed.

The staff reviewed those portions of AMP B2.1.18, "Fire Water System Program," that the

applicant claimed are consistent with GALL AMP XI.M27 and found them consistent. The staff

found the applicant's AMP acceptable because it conforms to the recommended GALL Report

AMP with the enhancement as described above.

OperatingExperience. In LRA Section B2.1.18, the applicant explained that through the use of

established plant surveillances and procedures, the fire water system is periodically inspected,

tested, flushed, and maintained. It evaluates industry and plant experience for system

performance impacts. The applicant documents performance issues and evaluates them

through the site CAP. System availability has been good; only six cases of system impairment

for more than 48 hours, in order to perform required maintenance, have occurred since October

1996. System unavailability is within Maintenance Rule program goals. The applicant also

provided an example of program activities. It conducted a FP system walkdown that reported

that the system was in good condition but identified two areas of concern. First, the FP system

engineer trended greater than minimal packing leakage on the screenwash/fire pump. The

applicant will perform repacking when necessary to resolve this issue. The second concern was

with a seal leak on the FP jockey pump. Plant staff replaced the mechanical seal under the

work control process.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience-and discussions with the

applicant's technical personnel, the staff concluded that the applicant's Fire Water System

Program will adequately manage the aging effects identified in LRA for which this AMP is

credited.

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USAR Supplement. In LRA Section A2.1.18, the applicant provided the USAR supplement for

the Fire Water System Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter dated June 10, 2005, the applicant added the following three commitments to LRA

Section A2.1.18, documented as commitments 30, 31, and 32 in Table A.5, which the applicant

will perform before the period of extended operation:

(1) The applicant will revise the implementing procedures for the Fire Water System

Program to include extrapolation of inspection results to below-grade fire water piping

with conditions similar to those within above-grade fire water piping.

(2) Sprinkler heads will be inspected and tested in accordance with NFPA requirements or

replaced before the end of their 50-year service life and at 10-year intervals thereafter

during the extended period of operation to ensure that degradation, such as corrosion, is

detected promptly. Procedures to be used for aging management activities (AMAs) of

the Fire Water System Program will be verified and testing will be performed in

accordance with applicable NFPA codes and standards. The applicant will revise

relevant procedures as appropriate.

(3) The applicant will verify that the procedures to be used for AMAs of the fire water

system apply testing in accordance with the applicable NFPA codes and standards. It

will revise the relevant procedures as appropriate.

Conclusion. On the basis of its review and audit of the applicant's Fire Water System Program,

the staff determined that those program elements for which the applicant claimed consistency

with the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

enhancement and confirmed that its implementation before the period of extended operation

will result in the existing AMP being consistent with the GALL Report AMP to which it was

credited. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21(d).

3.0.3.2.17 Fuel Oil Chemistry Program

Summary of Technical Information in the Application. In LRA Section B2.1.20, the applicant

described the Fuel Oil Chemistry Program, stating that this existing program is consistent, with

exceptions and enhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry." The Fuel Oil

Chemistry Program mitigates and manages aging effects on the internal surfaces of diesel fuel

oil storage tanks and associated components in systems that contain diesel fuel oil. The

program includes (1) surveillance and monitoring procedures for maintaining diesel fuel oil

quality by controlling contaminants in accordance with applicable ASTM standards, (2) periodic

draining of water from diesel fuel oil tanks, if water is present, (3) periodic or conditional visual

inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external

surfaces of diesel fuel oil tanks, and (4) one-time inspections of a representative sample of

components in systems. that contain diesel fuel oil.

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Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and enhancements and the

associated justifications to determine whether the AMP, with the exceptions and enhancements,

remains adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M30.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M30 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Preventive Actions program

element associated with the exception taken:

The quality of fuel oil is maintained by additions of biocides to minimize biological

activity, stabilizers to prevent biological breakdown of the diesel fuel, and

corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows

removal of sediments, and periodic draining of water collected at the bottom of a

tank minimizes the amount of water and the length of contact time. Accordingly,

these measures are effective in mitigating corrosion inside diesel fuel oil tanks.

Coatings, if used, prevent or mitigate corrosion by protecting the internal

surfaces of the tank from contact with water and microbiological organisms.

In the LRA, the applicant stated that its Fuel Oil Chemistry Program does not currently use

biocides, stabilizers, and corrosion inhibitors.

The staff found this exception acceptable based on its review of various documents on site,

including a comparison of ASTM standards with those recommended in the GALL Report,

historical oil analyses, the PBD, and discussions with plant personnel. The review of the

historical oil analyses and discussions with plant personnel showed that there had been no

biological breakdown of fuel oil and that the oil purchased to ASTM D 975 requirements has

remained stable and free of corrosion during storage and use. On the basis of the above review

and review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff

found this exception acceptable.

Exception 2: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the exception taken:

The AMP monitors fuel.oil quality and the levels of water and microbiological

organisms in the fuel oil, which cause the loss of material of the tank internal

surfaces. The ASTM Standard D 4057 is used for guidance on oil sampling. The

ASTM Standards D 1796 and D 2709 are used for determination of water and

sediment contamination in diesel fuel. For determination of particulates, modified

ASTM D 2276, Method A, is used. The modification consists of using a filter with

a pore size of 3.0 pm, instead of 0.8 pm. These are the principal parameters

relevant to tank structural integrity.

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In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but ASTM

D 6217, "Test Method for Particulate Contamination in Middle Distillate Fuels by Laboratory

Filtration," as a laboratory test to sample diesel fuel oil for suspended particulates. This

standard applies to the grade of diesel fuel oil and also uses the more conservative

0.8 micrometer (pm) filter pore size instead of the recommended 3.0 pm.

The staff found this exception acceptable based on its review of various documents on site, including a comparison of ASTM standards with those recommended in the GALL Report.

Review of ASTM D 6217 showed that this laboratory analysis of the fuel oil specifically applies

to the grade of oil used, and the applicant uses a more conservative filter pore size than that

recommended by the GALL Report. On the basis of the above review and its review of

plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this

exception acceptable.

Exception 3: The GALL Report recommends the following for the Acceptance Criteria program

element associated with the exception taken:

The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTM

Standards D 1796 and D 2709 are used for guidance on the determination of

water and sediment contamination in diesel fuel. Modified ASTM D 2276,

Method A is used for determination of particulates. The modification consists of

using a filter with a pore size of 3.0 pm, instead of 0.8 pm.

In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but uses

ASTM D 6217 as a laboratory test to sample diesel fuel oil for suspended particulates. This

standard applies to the grade of diesel fuel oil used at MNGP and uses the more conservative

0.8 pm filter pore size instead of the recommended 3.0 pm.

The staff found this exception acceptable based on its review of various documents on site,

including a comparison of ASTM standards with those recommended in the GALL Report.

Review of ASTM D 1796 showed that it specifically applies to the type of diesel fuel used and

contains the necessary and sufficient requirements for sampling for sediment and water.

Additionally, a review of ASTM D 6217 showed that it contains test parameters, performed by

an offsite laboratory, equivalent to ASTM D 2276 recommended in the GALL Report. On the

basis of the above review and its review of plant-specific operating experience for the Fuel Oil

Chemistry Program, the staff found this exception acceptable.

In the LRA, the applicant stated that the following enhancements will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement 1: The GALL Report recommends the following for the Scope of Program

program element associated with the enhancement made:

The program is focused on managing the conditions that cause general, pitting,

and microbiologically influenced corrosion (MIC) of the diesel fuel tank internal

surfaces. The program serves to reduce the potential of exposure of the tank

internal surface to fuel oil contaminated with water and microbiological

organisms.

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In the LRA, the applicant stated that it will revise the procedures for the diesel fuel oil system to

include requirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and

cracking.

The staff review of various documents on site, including a comparison of ASTM standards with

those recommended in the GALL Report, the PBD, and discussions with plant personnel

determined that the requirements to check for general, pitting, crevice, and galvanic corrosion,

MIC, and cracking will continually verify the effectiveness of the program. On the basis of the

above review and its review of plant-specific operating experience for the Fuel Oil Chemistry

Program, the staff found this enhancement acceptable as such changes to the applicant's

program provide assurance that the effects of aging will be adequately managed.

Enhancement 2: The GALL Report recommends the following for the Preventive Actions

program element associated with the enhancement made:

The quality of fuel oil is maintained by additions of biocides to minimize biological

activity, stabilizers to prevent biological breakdown of the diesel fuel, and

corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows

removal of sediments, and periodic draining of water collected at the bottom of a

tank minimizes the amount of water and the length of contact time. Accordingly,

these measures are effective in mitigating corrosion inside diesel fuel oil tanks.

Coatings, if used, prevent or mitigate corrosion by protecting the internal

surfaces of the tank from contact with water and microbiological organisms.

In the LRA, the applicant stated that it will revise its Fuel Oil Chemistry Program to require tank

draining, cleaning, and inspection if deemed necessary based on trends indicated by results of

the diesel fuel oil analysis, or if recommended by the system engineer based on equipment

operating experience.

The staff review of various documents on site, including a comparison of ASTM standards with

those recommended in the GALL Report, the PBD, and discussions with plant personnel

determined that these requirements (i.e., to provide tank draining, cleaning, and inspection if

deemed necessary based on the trends indicated by the results of the diesel fuel oil analysis or

as recommended by the system engineer based on equipment operating experience) will

provide a continuing check on the effectiveness of the program. On the basis of the above

review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program,

the staff found this enhancement acceptable as such changes to the applicant's program

provide assurance that the effects of aging will be adequately managed.

Enhancement 3: The GALL Report recommends the following for the Detection of Aging

Effects program element associated with the enhancement made:

Degradation of the diesel fuel oil tank cannot occur without exposure of the tank

internal surfaces to contaminants in the fuel oil, such as water and

microbiological organisms. Compliance with diesel fuel oil standards in item 3,

above, and periodic multilevel sampling provide assurance that fuel oil

contaminants are below acceptable levels. Internal surfaces of tanks that are

drained for cleaning are visually inspected to detect potential degradation.

However, corrosion may occur at locations in which contaminants may

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accumulate, such as a tank bottom, and an ultrasonic thickness measurement of

the tank bottom surface ensures that significant degradation is not occurring.

In the LRA, the applicant stated it will write a procedure or revise existing procedures in the

MNGP Fuel Oil Chemistry Program to require periodic inspections of the diesel fuel oil tanks.

The staff review of various documents on site, including a comparison of ASTM standards with

those described in the GALL Report, the PBD, and discussions with plant personnel,

determined that the requirement to write or revise the Fuel Oil Chemistry Program procedures

to require periodic inspections of the diesel fuel oil tanks will be a continuing check on the

effectiveness of the program. The addition of periodic tank inspections will make the program

consistent with the recommendations of the GALL Report. On the basis of the above review

and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the

staff found this enhancement acceptable as such changes to the applicant's program provide

assurance that the effects of aging will be adequately managed.

The staff reviewed those portions of the AMP B2.1.20, "Fuel Oil Chemistry Program," that the

applicant claimed are consistent with GALL AMP XI.M30 and found them consistent. The staff

found the applicant's AMP acceptable because it conforms to the recommended GALL Report

AMP with the exceptions and enhancements as described above.

Operatina Experience. In LRA Section B2.1.20, the applicant explained that monthly and

quarterly diesel fuel oil sampling and trending activities have confirmed the adequacy of the

diesel fuel oil supply. Past tank cleanings and inspections have shown that the condition of the

tanks has not degraded.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the Fuel Oil

Chemistry Program will adequately manage the aging effects identified in the LRA for which this

AMP is credited.

USAR Supplement. In LRA Section A2.1.20, the applicant provided the USAR supplement for

the Fuel Oil Chemistry Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

In its letter dated June 10, 2005, the applicant included commitments to LRA Section A2.1.20,

documented as commitments 33, 34, and 35 in Table A.5, to perform the following before the

period of extended operation:

(1) The applicant will revise its procedures related to the diesel fuel oil system to include

requirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and

cracking.

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(2) The applicant will revise its Fuel Oil Chemistry Program procedures to require tank

draining, cleaning, and inspection if deemed necessary based on the trends indicated by

the results of the diesel fuel oil analysis, or as recommended by the system engineer

based on equipment operating experience.

(3) The applicant will develop or revise procedures for the MNGP Fuel Oil Chemistry

Program to require periodic inspections of the diesel fuel oil tanks.

Conclusion. On the basis of its review and audit of the applicant's Fuel Oil Chemistry Program,

the staff determined that those program elements for which the applicant claimed consistency

with the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff also reviewed the

enhancements and confirmed that their implementation before the period of extended operation

will result in the existing AMP being consistent with the GALL Report AMP to which it was

credited. The staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.18 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program

Summary of Technical Information in the Application. In LRA Section B2.1.22, the applicant

described the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program, stating that this existing program is consistent, with exception and

enhancement, with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load

(Related to Refueling) Handling Systems." The Inspection of Overhead Heavy Load & Light

Load (Related to Refueling) Handling Systems Program, which the applicant implements

through plant procedures and PM, manages loss of material of structural components for heavy

load and fuel handling components within the scope of license renewal. The Inspection of

Overhead Heavy Load & Light Load (Related to Refueling) Handling Systems Program provides

for visual and NDE inspections of load-handling components within the scope of license

renewal. The applicant also performs functional tests to assure their integrity. The cranes also

comply with the Maintenance Rule requirements provided in 10 CFR 50.65, "Requirements for

Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and enhancement and the associated

justifications to determine whether the AMP, with the exception and enhancement, remains

adequate to manage the aging effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M23.

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In the LRA, the applicant stated the following exception to the program elements listed for AMP

XI.M23 in the GALL Report.

Exception: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the exception taken:

The program evaluates the effectiveness of the maintenance monitoring

program and the effects of past and future usage on the structural reliability of

cranes. The number and magnitude of lifts made by the crane are also reviewed.

In the LRA, the applicant stated, except for special lifts made by the turbine building crane, its

program does not track the number and size of lifts because administrative controls ensure that

only allowable loads are handled, and fatigue failure of structural elements is not expected with

the limited number of lifts.

The staff reviewed information on the reactor building crane that notes that it has the design

capacity for many more lifts at a higher rated tonnage than are expected to take place over its

60-year life. Additionally, the applicant informed the staff that it also performs inspections and

functional checks on the other cranes periodically and before use. The applicant also provided

operating experience showing no degradation caused by aging since plant startup. The staff

found this exception acceptable based on its review of information that demonstrates the design

capabilities of the reactor building crane and the required inspections before the operation of

other cranes, and review of operating experience.

In the LRA, the applicant stated that the following enhancement will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for Detection of Aging Effects

program element associated with the enhancement made:

Crane rails and structural components are visually inspected on a routine basis

for degradation. Functional tests are also performed to assure their integrity.

The applicant will enhance the program to specify a 5-year inspection frequency for the fuel

preparation machines.

The staff review of various documents on site, including a comparison of the GALL Report

recommendations with the proposed enhancements, the PBD, and discussions with plant

personnel, determined that this requirement, a 5-year inspection frequency for the fuel

preparation machines, continually verifies the effectiveness of the program. The 5-year

frequency is acceptable as operating experience shows no degradation caused by aging since

installation; therefore, any aging mechanisms appear to act slowly. The addition of a specified

period for fuel preparation machine inspection ensures that each component is visually

inspected routinely for degradation and conforms with the recommendation in the GALL Report.

On the basis of the above review and a review of operating experience for the AMP, the staff

found this enhancement acceptable as such changes to the applicant's program provide

assurance that the effects of aging will be adequately managed.

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The staff reviewed those portions of AMP B2.1.22, "Inspection of Overhead Heavy Load and

Light Load (Related to Refueling) Handling Systems Program," that the applicant claimed are

consistent with GALL AMP XI.M23 and found them consistent. The staff found the applicant's

AMP acceptable because it conforms to the recommended GALL Report AMP with the

exception and enhancement as described above.

Operatinq Experience. In LRA Section B2.1.22, the applicant explained that no incidents of

failure of passive components for cranes and special lifting devices because of aging have

occurred at MNGP. The inspection activities have detected and managed aging effects in crane

and special lifting device components. A magnetic particle inspection of the dryer and steam

separator sling found a linear indication, which was repaired before to use. An inspection of the

reactor vessel head lifting device noted some minor degradation, which, in accordance with

procedure, was repaired and painted.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the Inspection of

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will

adequately manage the aging effects identified in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.22, the applicant provided the USAR supplement for

the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program. The staff reviewed this section and determined that the information in the

USAR supplement adequately describes the program, as required by 10 CFR 54.21 (d).

In its letter dated June 10, 2005, the applicant included a commitment to LRA Section A2.1.22,

documented as commitment 37 in Table A.5, that before the period of extended operation, the

applicant will enhance the Inspection of Overhead Heavy Load & Light Load (Related to

Refueling) Handling Systems Program to specify a 5-year inspection frequency for the fuel

preparation machines.

Conclusion. On the basis of its review and audit of the applicant's Inspection of Overhead

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff

determined that those program elements for which the applicant claimed consistency with the

GALL Report are consistent with the GALL Report. In addition, the staff reviewed the exception

and the associated justifications and determined that the AMP, with the exception, is adequate

to manage the aging effects for which it is credited. The staff also reviewed the enhancement

and confirmed that its implementation before the period of extended operation will result in the

existing AMP being consistent with the GALL Report AMP to which it was credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21 (d).

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3.0.3.2.19 Plant Chemistry Program

Summary of Technical Information in the Application. In LRA Section B2.1.25, the applicant

described the Plant Chemistry Program, stating that this existing program is consistent, with

exceptions, with GALL AMP XI.M2, 'Water Chemistry." The MNGP Plant Chemistry Program

mitigates the aging effects on component surfaces that are exposed to water as the process

fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and

sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer

degradation due to fouling in select heat exchangers. This program relies on monitoring and

control of water chemistry to keep peak levels of various contaminants below system-specific

limits based on BWRVIP-1 30". This document supersedes previous revisions of the BWR water

chemistry guidelines, including BWRVIP-29. For low-flow or stagnant portions of a system, a

one-time inspection of selected components at susceptible locations provides verification of the

effectiveness of the Plant Chemistry Program.

.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exceptions and the associated justifications to

determine whether the AMP, with the exceptions, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M2.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M2 in the GALL Report.

Exception 1: The GALL Report recommends the following for the Scope of Program element

associated with the exception taken:

The program includes periodic monitoring and control of known detrimental

contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and

sulfate concentrations below the levels known to result in loss of material or

crack initiation and growth. Water chemistry control is in accordance with the

guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI

TR-105714, Rev. 3, for primary water chemistry in PWRs; EPRI TR102134,

Rev. 3, for secondary water chemistry in PWRs; or later revisions or updates of

these reports as approved by the staff.

In the LRA, the applicant stated that the Plant Chemistry Program uses BWRVIP-130, which

supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29.

Based on technical analysis, the staff found the provisions of Revision 2 of BWRVIP-29, issued

in 2000, acceptable based on updated industry experience. BWRVIP-130 is the current update

of the BWR water chemistry guidelines and supersedes BWRVIP-29, Revision 2. BWRVIP-1 30

is based on updated industry experience with increased emphasis on fuel performance

concerns, while retaining the chemistry parameters, action levels, and associated measurement

frequencies essentially unchanged.

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LRA Section B2.1.25 states that this program has one exception in that the Plant Chemistry

Program uses the 2004 -revision, not the 1993, 1996, or 2000 revisions, of the EPRI BWR water

chemistry guidelines. BWRVIP-130 replaced BWRVIP-29, Revision 2. The applicant stated that

the new program incorporates updated industry experience with increased focus on fuel

performance, while retaining the chemistry parameters, action levels, and associated

measurement frequencies essentially unchanged. The staff interviewed the applicant regarding

the relationship of the existing Plant Chemistry Program and the elements of BWRVIP-1 30 to

the 2000 revision of the BWR water chemistry guidelines. The applicant stated that the Plant

Chemistry Program has the elements of BWRVIP-29 and incorporates updated guidelines

based on industry experience. The staff comparison of the EPRI 2000 revision of the guidelines

against the EPRI 2004 revision used by the applicant also shows that the guideline was

updated to show industry experience.

The staff determined from the documentation of these chemistry revisions that the adoption of

the 2004 revision (BWRVIP-1 30) resulted in no significant changes to critical program

elements, and that the revision includes updates to the technical basis and guidance to reflect

additional industry experience with increased focus on fuel performance, while retaining the

same chemistry parameters, action levels, and associated measurement frequencies.

Therefore, the staff found the exception acceptable.

Exception 2: The GALL Report recommends the following for the Parameters Monitored or

Inspected program elements associated with the exception taken:

BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-103515) for

BWR reactor water recommend that the concentration of chlorides, sulfates, and

dissolved oxygen are monitored and kept below the recommended levels to,

mitigate corrosion. The two impurities, chlorides and sulfates, determine the

coolant conductivity; dissolved oxygen, hydrogen peroxide, and hydrogen

determine electrochemical potential (ECP). The EPRI guidelines recommend

that the coolant conductivity and ECP are also monitored and kept below the

recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI

guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and

control rod drive water recommends that conductivity, dissolved oxygen level,

and concentrations of iron and copper (feedwater only) are monitored and kept

below the recommended levels to mitigate SCC. The EPRI guidelines in

BWRVIP-29 (TR-103515) also include recommendations for controlling water

chemistry in auxiliary systems: torus/pressure suppression chamber, condensate

storage tank, and spent fuel pool.

In the LRA, the applicant stated the Plant Chemistry Program does not measure hydrogen

peroxide. Instead, plant staff perform site-specific radiolysis modeling. As noted in

BWRVIP-1 30, reliable measurements of hydrogen peroxide are exceptionally difficult to obtain,

and concentration can be estimated from radiolysis models.

The staff interviewed the applicant for technical justification for its initial use of reactor vendor

models as the basis for hydrogen water chemistry. Since then, EPRI had developed a software

program, known as the BWR Vessel and Internals Application, as part of the BWRVIP now

used for radiolysis and ECP monitoring for specific regions inside the reactor vessel. Results

from this model have been compared to prior reactor vendor models to confirm appropriate

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application of the software modeling applications. The applicant runs the model at least twice

during each operating cycle to account for changes in reactor flux and core flow on model

results.

The staff found in its evaluation and review of plant-specific operating experience that the

exception to the Plant Chemistry Program to use site-specific radiolysis modeling instead of

measuring hydrogen peroxide is acceptable and consistent with the GALL Report because

radiolysis models are acceptable for establishing hydrogen injection rates (to reduce oxidants in

the RCS, and thus SCC) as established by EPRI guidelines for BWR vessel internals.

On the basis of its review of the above exception and of operating experience for the Plant

Chemistry Program, the staff found this exception acceptable.

The staff reviewed those portions of AMP B2.1.25, "Plant Chemistry Program," that the

applicant claimed are consistent with GALL AMP XI.M2 and found them consistent. The staff

found the applicant's AMP acceptable because it conforms to the recommended GALL Report

AMP with the exceptions as described above.

Operating Experience. In LRA Section B2.1.25, the applicant explained that CRs/ARs are

initiated when water chemistry is found to be out of specification. Many of these conditions

result from equipment or plant transient conditions (e.g., plant startup) that are resolved once

the transient condition subsides. The time duration of these conditions is typically short and no

evidence of detrimental equipment impacts could be found. Further, no examples of component

functional failures due to corrosion, cracking, or heat transfer degradation resulting from

inadequate chemistry control were identified. The applicant addressed industry experience

related to IGSCC issues by replacing components with less susceptible materials,

implementation of hydrogen water chemistry, and improvements in water chemistry standards.

It replaced the entire recirculation system piping, a number of safe ends connected to the

reactor vessel, the jet pump holddown beam assemblies, and the shroud head bolts with

materials less susceptible to IGSCC. No adverse trends in water chemistry control were

identified based on a review of various chemistry performance indicators. Established

procedural requirements for chemistry limits are based on EPRI and industry standards and

routinely monitored by the site. Recent external and internal assessments have identified

chemistry trending as a strength and personnel knowledge as good. These conclusions are

based on a review of CAP issues on chemistry (and out of specification chemistry limits) from

January 1, 1996, through May 1, 2004, recent external and internal Chemistry Department

assessment results, system health reports, and chemistry performance indicators and trends.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above operating experience and discussions with the

applicant's technical personnel, the staff concluded that the applicant's Plant Chemistry

Program will adequately manage the aging effects identified in the LRA for which this AMP is

credited.

USAR Supplement. In LRA Section A2.1.25, the applicant provided the USAR supplement for

the Plant Chemistry Program. The staff reviewed this section and determined that the

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information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its review and audit of the applicant's Plant Chemistry Program, the

staff determined that those program elements for which the applicant claimed consistency with

the GALL Report are consistent with the GALL Report. In addition, the staff reviewed the

exceptions and the associated justifications and determined that the AMP, with the exceptions,

is adequate to manage the aging effects for which it is credited. The staff concluded that the

applicant demonstrated that the effects of aging will be adequately managed so that intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concluded that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.2.20 Protective Coating Monitoring & Maintenance Program

Summary of Technical Information in the ADplication. In LRA Section B2.1.27, the applicant

described the Protective Coating Monitoring & Maintenance Program, stating that this existing

program is consistent, with enhancements, with GALL AMP XJ.S8, "Protective Coating

Monitoring and Maintenance Program." The Protective Coating Monitoring and Maintenance

Program applies to Service Level 1 protective coatings inside containment to address the

concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System

and the Containment Spray System after a Loss-of-Cooling Accident because of Construction

and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14, 1998.

The Protective Coating Monitoring & Maintenance Program prevents the degradation of

coatings that could lead to the clogging of Emergency Core Cooling System (ECCS)

suppression pool suction strainers. MNGP does not credit the Protective Coating Monitoring

and Maintenance Program for the prevention of corrosion of carbon steel components. As

outlined in the MNGP response to GL 98-04, the Protective Coating Monitoring and

Maintenance Program is a comparable program for monitoring and maintaining protective coatings inside the primary containment and subject to the requirements of ANSI N101.4-1972,

to the extent specified in ANSI N1 8.7-1976 and as modified by RG 1.54, "Service Level I, II, and

III Protective Coatings Applied to Nuclear Power Plants," issued June 1973.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancements and the associated justifications

to determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.S8.

In the LRA, the applicant stated that the following enhancements will make this AMP consistent

with the recommendation in the GALL Report.

Enhancement 1: The GALL Report recommends the following for the Scope of Program

program element associated with the enhancement made:

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The minimum scope of the program is Service Level 1 coatings, defined in

RG 1.54, Rev 1, as follows: "Service Level 1 coatings are used in areas inside

the reactor containment where the coating failure could adversely affect the

operation of post-accident fluid systems and thereby impair safe shutdown."

In the LRA, the applicant stated that it will update the MNGP Protective Coating Monitoring &

Maintenance Program to include inspection of all accessible painted surfaces inside

containments.

The staff noted that the GALL Report states that a comparable program for monitoring and

maintaining protective coatings inside containments, developed in accordance with RG 1.54,

Revision 0, or the ANSI standards (since withdrawn) referenced in RG 1.54, Revision 0, and

coatings maintenance programs described in licensee responses to GL 98-04,- is also

acceptable as an AMP for license renewal. The applicant's program is a "comparable program,"

as defined above. The staff determined that this enhancement (i.e., requiring an inspection of

all accessible painted surfaces inside containment) makes the program consistent with the

GALL Report recommendation of Service Level 1 coatings as defined in RG 1.54, Revision 1.

On the basis of the above review and its review of operating experience for the Protective

Coating Monitoring & Maintenance Program, the staff found the enhancement acceptable as

such changes to the applicant's program provide assurance that the effects of aging will be

adequately managed.

Enhancement 2: The GALL Report recommends the following for the Detection of Aging

Effects program element associated with the enhancement made:

ASTM D 5163-96, paragraph 5, defines the inspection frequency to be each

refueling outage or during other major maintenance outages as needed.

ASTM D 5163-96, paragraph 8, discusses the qualifications for inspection

personnel, the inspection coordinator, and the inspection results evaluator.

ASTM D 5163-96, subparagraph 9.1, discusses development of the inspection

plan and the inspection methods to be used. It states, "A general visual

inspection shall be conducted on all readily accessible coated surfaces during a

walk-through. After a walk-through, thorough visual inspections shall be carried

out on previously designated areas and on areas noted as deficient during the

walk-through. A thorough visual inspection shall also be carried out on all

coatings near sumps-or screens associated with the Emergency Core Cooling

System (ECCS)." This subparagraph also addresses field documentation of

inspection results. ASTM D 5163-96, subparagraph 9.5, identifies instruments

and equipment needed for inspection.

In the LRA, the applicant stated that before the period of extended operation, all coating

inspectors will meet the requirements of ANSI N45.2.6, "Qualification of Inspection,

Examination, and Testing Personnel for the Construction Phase of Nuclear Power Plants."

The staff review noted that the relevant ASTM standard requires that coating inspectors be

qualified in accordance with ANSI N45.2.6 or the ASTM requirements. The staff queried the

applicant about the qualification requirement for inspectors. The applicant agreed to add this

enhancement. By letter dated August 11, 2005, the applicant stated that before the period of

extended operation all coating inspectors will meet ANSI N45.2.6 requirements. The staff

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determined that this enhancement (i.e., requiring all coating inspectors to be qualified in

accordance with ANSI N45.2.6) makes this program consistent with the GALL Report

recommendation of qualification under the requirements in paragraph 8 of ASTM D 5163-96,

"Standard Guide for Establishing Procedures To Monitor the Performance of Safety Related

Coatings in an Operating Nuclear Power Plant," for inspection personnel, inspection

coordinators, and inspection results evaluators. On the basis of the above review and its review

of operating experience for the Protective Coating Monitoring & Maintenance Program, the staff

found this enhancement acceptable as such changes to the applicant's program provide

assurance that the effects of aging will be adequately managed.

Enhancement 3: The GALL Report recommends the following for the Monitoring and Trending

program element associated with the enhancement made:

ASTM D 5163-96 identifies monitoring and trending activities in

subparagraph 6.2, which specifies a pre-inspection review of the previous two

monitoring reports, and in subparagraph 10.1.2, which specifies that the

inspection report should prioritize repair areas as either needing repair during the

same outage or postponed to future outages, but under surveillance in the

interim period.

In the LRA, the applicant stated it will include a preinspection review of the previous two

inspection reports to identify trends.

The staff review has determined that this enhancement (i.e., a preinspection review of the

previous two inspection reports to identify trends) makes this program consistent with the GALL

Report recommendation above. On the basis of the above review and its review of operating

experience for the Protective Coating Monitoring & Maintenance Program, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

Enhancement 4: The GALL Report recommends the following for the Acceptance Criteria

program element associated with the enhancement made:

ASTM D 5163-96, subparagraphs 9.2.1 through 9.2.6, 9.3, and 9.4, contain

guidance for characterization, documentation, and testing of defective or

deficient coating surfaces. Additional*ASTM and other recognized test methods

are identified for use in characterizing the severity of observed defects and

deficiencies. The evaluation covers blistering, cracking, flaking, peeling,

delamination, and rusting. ASTM D 5163-96, paragraph 11, addresses

evaluation. It specifies that the inspection report is to be evaluated by the

responsible evaluation personnel, who prepare a summary of findings and

recommendations for future surveillance or repair, including an analysis of

reasons or suspected reasons for failure. Repair work is prioritized as major or

minor defective areas. A recommended corrective action plan is required for

major defective areas so that these areas can be repaired during the same

outage, if appropriate.

In the LRA, the applicant stated that it will revise the AMP implementation procedures to include

analysis of suspected reasons for coating failure.

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The staff review determined that this enhancement (i.e., revising implementation procedures to

include analysis of suspected reasons for coating failure) makes this program consistent with

the GALL Report recommendation. On the basis of the above review and its review of operating

experience for the Protective Coating Monitoring & Maintenance Program, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

The staff reviewed those portions of AMP B2.1.27, "Protective Coating Monitoring and

Maintenance Program," that the applicant claimed are consistent with GALL AMP XI.S8 and

found them consistent. The staff found the applicant's AMP acceptable because it conforms to

the recommended GALL Report AMP with the enhancements as described above.

Operatina Experience. In LRA Section B2.1.27, the applicant explained that it does not rely

upon the Protective Coating Monitoring & Maintenance Program to manage the loss of material

due to corrosion of carbon steel structural elements. Therefore, only the operating experience

concerned with degradation of coatings and their consequential clogging of the ECCS strainers

is of importance. Since there currently are no coating inspection requirements for all

components inside containment, the only inspection experience to date is from those

inspections of the drywell and torus shells. Inspections of the drywell and torus shell have

identified the following signs of paint degradation-chipping, rusting, peeling, blistering,

cracking, and other signs of degradation. All unacceptable coating degradation has been

repaired or in the case of the torus is scheduled for repair during the next torus draining. These

inspections have detected and evaluated aging effects before the loss of intended function of

the ECCS suction strainers. Where applicable, the applicant made repairs to minimize further

degradation of the coatings, which may lead to clogging of the ECCS suction strainers.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the Protective

Coating Monitoring & Maintenance Program will adequately manage the aging effects identified

in the LRA for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.27, the applicant provided the USAR supplement for

the Protective Coating Monitoring & Maintenance Program. The staff reviewed this section and

determined that the information in the USAR supplement adequately describes the program, as

required by 10 CFR 54.21 (d).

In its letter dated June 10,2005, the applicant included the commitments to USAR

Section A2.1.27, documented as commitments 39, 40, and 41 in Table A.5, which the applicant

will complete before the period of extended operation:

(1) The applicant will update procedures to include inspection of all accessible painted

surfaces inside containment.

(2) The applicant will revise the program to include a preinspection review of the previous

two inspection reports so that trends can be identified.

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(3) The applicant will revise implementation procedures to include provisions for analysis of

suspected reasons for coating failure.

In a letter dated August 11, 2005, the applicant provided a new commitment, stating that before

the period of extended operation, coating inspectors will meet ANSI N45.2.6 requirements.

Conclusion. On the basis of its review and audit of the applicant's Protective Coating Monitoring

& Maintenance Program, the staff determined that those program elements for which the

applicant claimed consistency with the GALL Report are consistent with the GALL Report. In

addition, the staff reviewed the enhancements and confirmed that their implementation before

the period of extended operation will result in the existing AMP being consistent with the GALL

Report AMP to which it was credited. The staff concluded that the applicant demonstrated that

the effects of aging will be adequately managed so that intended functions will be maintained

consistent with the, CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.2.21 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. In LRA Section B2.1.29, the applicant

described the Reactor Vessel Surveillance Program, stating that this existing program is

consistent, with enhancement, with GALL AMP XI.M31, "Reactor Vessel Surveillance."

The applicant stated that the Reactor Vessel Surveillance Program is part of the BWRVIP

Integrated Surveillance Program (ISP) that uses data from BWR member surveillance

programs to select the "best" representative material for monitoring radiation embrittlement for

a particular plant. The BWRVIP ISP monitors capsule test results from various member plants.

The program was implemented to comply with Appendix H, "Reactor Vessel Material

Surveillance Program Requirements," to 10 CFR Part 50. The BWRVIP ISP guidance describes

the scope of the Reactor Vessel Surveillance Program. BWRVIP-86-A, "BWR Vessel and

Internals Project: BWR Integrated Surveillance Program (ISP) Implementation," includes the

ISP capsule removal schedule, and BWRVIP-78, "BWR Vessel and Internals Project: BWR

Integrated Surveillance Program (ISP) Plan," describes its technical basis.

The applicant stated in the Detection of Aging Effects program element of the Reactor Vessel

Surveillance Program that the ISP performs Charpy V-notch testing on specimens to measure

the applicable aging effect, loss of fracture toughness. The applicant further stated that the

Reactor Vessel Surveillance Project uses the BWRVIP ISP to monitor the effect of irradiation

on the vessel.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in

LRA Section B2.1.29 about the applicant's demonstration of the Reactor Vessel Surveillance

Program to ensure that the effects of aging will be adequately managed so that intended

functions will be maintained consistent with the CLB throughout the period of extended

operation.

Appendix H to 10 CFR Part 50 provides the NRC's requirements for implementing surveillance

programs required for a plant's reactor vessel beltline materials. The programs are used to

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monitor for any changes in fracture toughness properties of a plant's reactor vessel beltline

base metal and weld materials from neutron irradiation during the plant's service lifetime.

Section III.C of Appendix H to 10 CFR Part 50 provides the specific requirements for

implementation of an ISP.

The BWRVIP has developed an ISP for the reactor vessel base metal and weld materials in all

operating BWRs. The BWRVIP ISP is in proprietary topical reports BWRVIP-78, "BWR

Integrated Surveillance Program (ISP) Plan," and BWRVIP-86, "BWR Vessel and Internals

Project: BWR Integrated Surveillance Program (ISP) Implementation." The NRC approved

these proprietary reports applying the design and implementation of the ISP by BWRs during

their first 40-year operating period in its February 1, 2002, final safety evaluation report to the

BWRVIP.

The BWRVIP issued proprietary topical report BWRVIP-1 16, "BWR Vessel and Internals

Project Integrated Surveillance Program (ISP) Implementation for License Renewal," to address

ISP changes necessary for LRAs for operating BWRs. This report was approved by the NRC in

a letter dated March 1, 2006, from M.A. Mitchell (NRC) to B. Eaton (BWRVIP).

The applicant identified the Reactor Vessel Surveillance Program as an existing ISP designed

to comply with the requirements for ISPs in Appendix H to 10 CFR Part 50 and to conform with

recommended guidelines in GALL AMP XI.M31. The applicant stated that USAR supplement

Section A2.1.29 describes the Reactor Vessel Surveillance Program.

The applicant stated that it based the Reactor Vessel Surveillance Program on the BWRVIP

ISP as described and discussed in BWRVIP-78 and BWRVIP-86. The ISP provides for a

number of surveillance capsules to be removed from specified BWRs and to be available for

testing during the license renewal period for the BWR fleet. The ISP establishes acceptable

technical criteria for capsule withdrawal and testing.

The staff approved the application of the BWRVIP ISP to the applicant's reactor vessel in the

April 22, 2003, SE, in which the staff concurred that the BWRVIP ISP, as approved in

BWRVIP-78 and BWRVIP-86-A (the staff-approved version of BWRVIP-86), met requirements

in Appendix H to 10 CFR Part 50 for the RPV.

Proprietary topical reports BWRVIP-78 and BWRVIP-86-A, the staff's February 1, 2002,

generic final safety evaluation report, and the staff's April 22, 2003, SE provide an acceptable

basis for approving the Reactor Vessel Surveillance Program for the current operating period.

To address the impacts of license renewal on the program, the applicant will enhance the AMP

through the period of extended operation.

The applicant stated that the BWRVIP ISP has been enhanced to address the impact of license

extension on the ISP for BWR facilities and that proprietary topical report BWRVIP-1 16

discusses the enhanced program.

The BWRVIP submitted BWRVIP-1 16 to the staff in 2003 to address the impacts of license

extension on the proposed surveillance capsule withdrawal schedule and to determine whether

additional ISP capsules will need to be designated for the proposed surveillance capsule

withdrawal schedule.

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The staff's review of LRA Section B2.1.29 identified an area for which it needed additional

information to complete its evaluation of the applicant's program. The applicant responded to

the staff's RAI as discussed below.

In RAI B2.1.29-1, dated September 28, 2005, the staff requested that the applicant commit to

enhancing the Reactor Vessel Surveillance Program to ensure that any additional requirements

that result from the staff review of BWRVIP-1 16 will be addressed before the period of

extended operation.

In its response, by letter dated October 28, 2005, the applicant stated that it will enhance the

Reactor Vessel Surveillance Program to address additional requirements from the staff review

before the period of extended operation.

In its letter dated March 15, 2006, the applicant provided commitment 42 in Table A.5, which

will ensure that it will incorporate into the Reactor Vessel Surveillance Program any changes to

the withdrawal schedule requirements for the ISP, as approved in the staff's acceptance of

BWRVIP-1 16 and found applicable to the reactor vessel, will be incorporated into its RVSP.

With this RVSP enhancement included as a commitment for the LRA, the staff found the

applicant's response acceptable.

Operating Experience. In the Operating Experience program attribute for the Reactor Vessel

Surveillance Program, the applicant stated that it participates in the BWRVIP ISP to ensure the

program meets accepted industry practices. The staff has accepted the ISP methodology for

monitoring radiation embrittlement at BWRVIP plants as reasonable assurance that the2

applicant will continue to evaluate aging effects of reactor vessel material loss of fracture

toughness by sampling, analysis, and testing. The staff has confirmed that these topical reports

and NRC evaluations apply to the staff's approval of the Reactor Vessel Surveillance Program

for the applicant's CLB. The staff therefore concluded that the applicant's Operating Experience

attribute for the Reactor Vessel Surveillance Program. is acceptable.

USAR Supplement. In LRA Section A2.1.29, the applicant provided the USAR supplement for

the Reactor Vessel Surveillance Program. The staff reviewed this section and determined that

the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter dated June 10, 2005, the applicant included the following commitments to USAR

Section A2.1.29, documented as commitments 42 and 43 in Table A.5:

(1) NMC intends to use the ISP for MNGP during the period of extended operation by

implementing the requirements of BWRVIP-1 16, which the NRC is currently reviewing.

(2) NMC will retain the capsules removed from the MNGP reactor vessel as part of the

Reactor Vessel Surveillance Program.

Conclusion. On the basis of its review and audit of the applicant's Reactor Vessel Surveillance

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the enhancement and confirmed that its implementation before the period of extended

operation will result in the existing AMP being consistent with the GALL Report AMP to which it

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was credited. The staff concluded that the applicant demonstrated that the effects of aging will

be adequately managed so that intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21(d).

3.0.3.2.22 Selective Leaching of Materials Program

Summary of Technical Information in the Application. In LRA Section B2.1.30, the applicant

described the Selective Leaching of Materials Program, stating that this new program is

consistent, with exception, with GALL AMP XI.M33, "Selective Leaching of Materials." The

program includes a one-time visual inspection and hardness measurement of selected

components that are susceptible to selective leaching. In situations where hardness testing is

not practical, the applicant will use a qualitative method by other NDE or metallurgical methods

to determine the presence and extent of selective leaching. The program will determine if

selective leaching is occurring for selected components. The applicant will write any required

instructions or procedures during development of the program, and may use existing MNGP

procedures or work instructions.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the exception and the associated justifications to

determine whether the AMP, with the exception, remains adequate to manage the aging effects

for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.M33.

In the LRA, the applicant stated the following exceptions to the program elements listed for

AMP XI.M33 in the GALL Report.

Exceptions 1 and 2: The GALL Report recommends the following for the Detection of Aging

Effects program element associated with the exceptions taken:

The one-time visual inspection and hardness measurement includes close

examination of a select set of components to determine whether selective

leaching has occurred and whether the resulting loss of strength and/or material

will affect the intended functions of these components during the period of

extended operation. Selective leaching generally does not cause changes in

dimensions and is difficult to detect. However, in certain brasses it causes

plug-type dezincification, which can be detected by visual inspection. One

acceptable procedure is to visually inspect the susceptible components closely

and conduct Brinell Hardness testing on the inside surfaces of the selected set of

components to determine if selective leaching has occurred. If it is occurring, an

engineering evaluation is initiated to determine acceptability of the affected

components for further service.

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In the LRA, the applicant stated that the first exception is that the program may use hardness

testing, other than Brinell hardness testing, to detect selective leaching of material. In the

second exception, the applicant stated that it will use qualitative methods in lieu of hardness

testing to detect selective leaching where hardness testing is not practical.

The staff discussed these exceptions with the applicant's technical personnel. With regard to

Exception 1, the staff concurred that Brinell hardness testing is one of several methodologies

that are currently being used and is only a GALL Report recommendation. The staff found the

applicant's position acceptable. With regard to Exception 2, the staff asked that the applicant

clarify the use of qualitative methods versus hardness testing.

In its letter dated August 11, 2005, the applicant stated that the methods used to detect

selective leaching include visual inspection in conjunction with mechanistic techniques like

scratch testing, hardness testing, or NDEs. The staff found the applicant's position acceptable

because the applicant is using qualitative mechanistic techniques in addition to visual

inspection, as recommended by the GALL Report.

The staff reviewed those portions of AMP B2.1.30, "Selective Leaching of Materials Program,"

that the applicant claimed are consistent with GALL AMP XI.M33 and found them consistent.

The staff found the applicant's AMP acceptable because it conforms to the recommended

GALL Report AMP with the exceptions as described above.

Operatinq Experience. In LRA Section B2.1.30, that applicant stated that the Selective

Leaching of Materials Program is a new program with no operating experience.

During the audit and review, the staff asked the applicant how it captures operating experience.

The applicant indicated that the CAP identifies, tracks, and trends site operating experience

related to all site components. The site CAP database documents any site components

identified as degraded, as failed, or as potentially unable to fulfill intended functions. Plant

engineering staff then evaluate these CAPs for the extent of the condition and take appropriate

followup actions. Plant engineering staff also trend related CAP data to identify generic issues.

They address trended site issues in program health reports presented to site management on a

scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating events

from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant's response

and found it acceptable.

A review of CRs for leaching identified a possible selective leaching issue, a higher than normal

lead content in the number 12 EDG lube oil. A document review indicated that INPO

SOER 80-04 recommends that if lead soldered joint coolers are installed, there should be

inspections for exfoliation-type solder corrosion. A work history review determined that the

number 11 EDG lube oil cooler had been replaced with the rolled tube design in 1991, but that

the number 12 EDG lube oil cooler still had its original cooler. The applicant replaced the

number 12 EDG lube oil cooler during the 2003 refueling outage with a rolled tube design.

The staff recognized that the CAP captures, evaluates, and incorporates internal and external

plant operating experience for objective evidence of adequate management of aging effects.

USAR Supplement. In LRA Section A2.1.30, the applicant provided the USAR supplement for

the Selective Leaching of Materials Program. The staff reviewed this section and determined

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that the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

In its letter dated June 10, 2005, the applicant included the commitment to USAR

Section A2.1.30, documented as commitment 44 in Table A.5, that before the period of

extended operation, it will implement the Selective Leaching of Materials Program as a new

program consistent, with exceptions, to the recommendations of GALL AMP XI.M33.

Conclusion. On the basis of its review and audit of the applicant's Selective Leaching of

Materials Program, the staff determined that those program elements for which the applicant

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the

staff reviewed the exception and the associated justifications and determined that the AMP,

with the exception, is adequate to manage the aging effects for which it is credited. The staff

concluded that the applicant demonstrated that the effects of aging will be adequately managed

so that intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concluded that it adequately describes the program, as required by

10 CFR 54.21(d).

3.0.3.2.23 Structures Monitoring Program

Summary of Technical Information in the ADplication. In LRA Section B2.1.31, the applicant

described the Structures *Monitoring Program, stating that this existing program is consistent,

with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." The Structures

Monitoring Program is based on the guidance provided in RG 1.160, Revision 2, "Monitoring the

Effectiveness of Maintenance at Nuclear Power Plants," issued March 1997, and

NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness of

Maintenance at Nuclear Power Plants," issued April 1996. The applicant implements the

Structures Monitoring Program as part of the structures monitoring done under the MNGP

Maintenance Rule program and with additional inspections of the intake structure and diesel

fuel oil transfer house. The Structures Monitoring Program also implements GALL AMP XI.S5,

"Masonry Wall Program." Masonry block wall inspections are performed as part of the

Maintenance Rule inspections and are based on Inspection and Enforcement Bulletin 80-11

with administrative controls in accordance with IN 87-67, "Lessons Learned from Regional

Inspections of Licensee Actions in Response to IE Bulletin 80-11," dated December 21, 1987.

As permitted by GALL AMP XI.S7, "RG 1,127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants," the Structures Monitoring Program includes the

inspection of water control structures. The only water control structure in scope for license

renewal is the intake structure. Maintenance Rule inspections are performed on the portions of

the intake structure above the water line. The Structures Monitoring Program includes separate

inspections of the underwater portions of the intake structure. In addition, special settlement

checks of the diesel fuel oil transfer house are performed outside the Maintenance Rule

inspections. The Structures Monitoring Program does not rely upon protective coatings to

manage the effects of aging.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancements and the associated justifications

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to determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP XI.S6.

In the LRA, the applicant stated that it will implement the following enhancements to make this

AMP consistent with the recommendations in the GALL Report.

Enhancement 1: The GALL Report recommends the following for the Scope of Program

program element for GALL AMPs XI.S5 and XI.S7 associated with the enhancement made:

The scope includes all masonry walls identified as performing functions in

accordance with 10 CFR 54.4.

RG 1.127 applies to water-control structures associated with emergency cooling

water systems or flood protection of nuclear power plants.

The applicant indicated that it is not committed to RG 1.127, Revision 1, "Inspection of WaterControl Structures Associated with Nuclear Power Plants," March 1978. The Structures

Monitoring Program includes inspections of water control structures as recommended by the

GALL Report.

In the LRA, the applicant stated that it will expand the Structures Monitoring Program, as

necessary, to include inspections of structures and structural elements within the scope of

license renewal not inspected as part of another AMP.

According to AMP B2.1.31, "Structures Monitoring Program," the program includes masonry

block walls and water control structures within the scope of license renewal. The Scope of

Program program element lists water control structures, which include the access tunnel and

diesel fire pump house.

On the basis of its review of Structures Monitoring Program operating experience and based on

satisfying the GALL Report recommendations as discussed above, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

Enhancement 2: The GALL Report recommends the following for the Scope of Program

program element for GALL AMP XI.S7 associated with the enhancement made:

The water-control structures included in the RG 1.127 program are concrete

structures; embankment structures; spillway structures and outlet works;

reservoirs; cooling water channels and canals, and intake and discharge

structures; and safety and performance instrumentation.

In the LRA, the applicant stated that it will enhance implementing procedures for the Structures

Monitoring Program to ensure that structural inspections are performed on submerged portions

of the intake structure from the service water bays to the wing walls.

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The applicant stated, in the LRA, that the Structures Monitoring Program includes separate

inspections of the underwater portions of the intake structure and that under the Scope of

Program element, the program also provides inspection requirements to manage aging effects

described in the Parameters Monitored or Inspected element. As documented in the audit and

review report, the applicant's structural inspections of the service water bays will include more

detailed inspection criteria. In addition, the frequency of the applicant's structural inspections of

the submerged portions of the intake structure will meet or exceed that required by American

Concrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety Related Concrete

Structures."

On the basis of its review of Structures Management Program operating experience and based

on satisfying the GALL Report recommendations as discussed above, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

Enhancement 3: The GALL Report recommends the following for the Parameters Monitored or

Inspected program element associated with the enhancement made:

...ACI 349.3R-96 and ANSI/ASCE 11-90 provide an acceptable basis for

selection of parameters to be monitored or inspected for concrete or steel

structural elements...

In the LRA, the applicant stated that it will enhance existing implementing procedures for the

Structures Monitoring Program to include monitoring/inspection parameters for structural

components within the scope of license renewal.

The staff reviewed the Structures Monitoring Program PBD, which incorporates intake

structures and masonry walls, and found it to be in general agreement with the above

recommendations.

On the basis of its review of Structures Management Program operating experience and based

on satisfying the GALL Report recommendations as discussed above, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

Enhancements 4 and 5: The GALL Report recommends the following for the Parameters

Monitored or Inspected program element associated with the enhancement made:

Parameters monitored or inspected are to be commensurate with industry codes,

standards and guidelines, and are to also consider industry and plant-specific

operating experience.

In the LRA, the applicant stated that it will enhance the Structures Monitoring Program to

sample ground water for pH, chloride concentration, and sulfate concentration.

The applicant stated, in the LRA, that to ensure that the soil environment remains

nonaggressive, it will enhance the Structures Monitoring Program to include periodic

ground-water sampling for pH, chloride concentration, and sulfate concentration. The PBD

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reiterates this statement, providing the limiting values of pH greater than 5.5, chlorides less

than 500 ppm, and sulfates less than 1500 ppm for a nonaggressive environment.

On the basis of its review of Structures Management Program operating experience and based

on satisfying the GALL Report recommendations as discussed above, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

In the LRA, the applicant stated that it will enhance the Structures Monitoring Program to

include concrete evaluations of inaccessible areas if degradation of accessible areas is

detected to ensure the soundness of the buried concrete. The PBD reiterates this statement.

On the basis of its review of the Structures Management Program operating experience and

based on satisfying the GALL Report recommendations as discussed above, the staff found

this enhancement acceptable as such changes to the applicant's program provide assurance

that the effects of aging will be adequately managed.

Enhancement 6: The GALL Report recommends the following for the Acceptance Criteria

program element of GALL AMP XI.S7 associated with the enhancement made:

"Evaluation Criteria" provided in Chapter 5 of ACI 349.3R-96 provides

acceptance criteria (including quantitative criteria) for determining the adequacy

of observed aging effects and specifies criteria for further evaluation. Although

not required, plant-specific acceptance criteria based on Chapter 5 of ACI

349.3R-96 are acceptable.

In the LRA, the applicant stated that it will enhance the implementing procedures for the

Structures Monitoring Program to include acceptance criteria for structural inspections of

submerged portions of the intake structure.

The applicant's technical personnel stated that for structural components of the intake structure

in a raw water/river water environment, acceptance criteria will be based on relevant industry

codes and standards. ACI 349.3R-96 will guide evaluation of concrete degradation.

On the basis of its review of Structures Monitoring Program operating experience and based on

satisfying the GALL Report recommendations as discussed above, the staff found this

enhancement acceptable as such changes to the applicant's program provide assurance that

the effects of aging will be adequately managed.

The staff reviewed those portions of AMP B2.1.31, "Structures Monitoring Program," that the

applicant claimed are consistent with GALL AMP XI.S6 and found them consistent. The staff

found the applicant's AMP acceptable because it conforms to the recommended GALL Report

AMP with the enhancements as described above.

Operatincq Experience. In LRA Section B2.1.31, the applicant stated that the Structures

Monitoring Program, including the Masonry Block Wall Program and RG 1.127 and

implemented through the Maintenance Rule and other procedures, has detected aging effects

of structural components and has ensured that repairs were made in a timely manner before

the loss of intended function. The program also evaluates external operating experience for

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impact on structures and structural inspections through administrative procedures and the

corrective action process.

The two most recent inspections, performed in 1998 and 2001/2002, noted several deficiencies.

The 1998 inspection noted 21 deficiencies and the 2001/2002 inspection noted 30 deficiencies.

.However, not all of these deficiencies were directly attributed to an aging effect. The aging

effects detected during the structural inspections were concrete spalling, cracking, surface

deterioration and flaking, grout deterioration, corroded rebar or other steel components, and

cracked welds. Applicant personnel created WOs and/or corrective actions to repair the

deficiencies. Several deficiencies were evaluated and determined to be acceptable as-is and

subjected to further inspections.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its review of the above industry and plant-specific operating experience and

discussions with the applicant's technical personnel, the staff concluded that the applicant's

Structures Monitoring Program will adequately manage the aging effects identified in the LRA

for which this AMP is credited.

USAR Supplement. In LRA Section A2.1.31, the applicant provided the USAR supplement for

the Structures Monitoring Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

By letter dated June 10, 2005, the applicant included the following commitments to USAR

Section A2.1.31 that it will perform before the period of extended operation:

(1) The program will be expanded, as necessary, to include inspections of

structures and structural elements in scope for License Renewal that are

not inspected as part of another aging management program.

(2) Implementing procedures will be enhanced to ensure that structural

inspections are performed on submerged portions of the Intake Structure

from the service water bays to the wing walls.

(3) Implementing procedures will be revised to include the

monitoring/inspection parameters for structural components within the

scope of License Renewal.

(4) The program will be enhanced to include a requirement to sample ground

water for pH, chloride concentration and sulfate concentration.

(5) The program will be enhanced to include concrete evaluations of

inaccessible areas if degradation of accessible areas is detected.

(6) Implementing procedures will be enhanced to include acceptance criteria

for structural inspections of submerged portions of the Intake Structure.

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Conclusion. On the basis of its review and audit of the applicant's Structures Monitoring

Program, the staff determined that those program elements for which the applicant claimed

consistency with the GALL Report are consistent with the GALL Report. In addition, the staff

reviewed the enhancements and confirmed that their implementation before the period of

extended operation will result in the existing AMP being consistent with the GALL Report AMP

to which it was credited. The staff concluded that the applicant demonstrated that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the USAR supplement for this AMP and concluded that it adequately describes the

program, as required by 10 CFR 54.21 (d).

3.0.3.2.24 Metal Fatigue of the Reactor Coolant Pressure Boundary Program

Summary of Technical Information in the Application. In LRA Section B3.2, the applicant

described the Metal Fatigue of the Reactor Coolant Pressure Boundary Program, stating that

this existing program is consistent, with enhancement, with GALL AMP X.M1, "Metal Fatigue of

Reactor Coolant Pressure Boundary." The Metal Fatigue of the Reactor Coolant Pressure

Boundary Program is part of the Thermal Fatigue Monitoring Program (FMP). The MNGP

Thermal FMP provides for the periodic review of plant transients for impact on selected

components. In addition, environmental effects have been evaluated in accordance with

NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for Selected

Nuclear Power Plant Components." Selected components were evaluated using material

specific guidance presented in NUREG/CR-6583, "Effects of LWR Coolant Environments on

Fatigue Design Curves ofCarbon and Low-Alloy Steels," issued February 1998, for carbon and

low alloy steels and in NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue

Design Curves of Austenitic Stainless Steels," issued April 1999. The MNGP program ensures

that limiting components remain within the acceptance criteria for cumulative fatigue usage

throughout the licensed term and, if trends indicate otherwise, appropriate corrective action can

be implemented.

Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim of

consistency with the GALL Report. The MNGP audit and review report details the staff's audit

evaluation of this AMP. The staff reviewed the enhancement and the associated justifications to

determine whether the AMP, with the enhancement, remains adequate to manage the'aging

effects for which it is credited.

The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, the

documents cited in the staff's audit and review report, which assesses the consistency of the

AMP elements with GALL AMP X.M1.

In the LRA, the applicant stated that it will implement the following enhancement to make this

AMP consistent with the recommendation in the GALL Report.

Enhancement: The GALL Report recommends the following for the Scope of Program program

element associated with the enhancement made:

The program includes preventive measures to mitigate fatigue cracking of metal

components of the reactor coolant pressure boundary caused by anticipated

cyclic strains in the material.

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In the LRA, the applicant stated that it will incorporate requirements for inclusion of

NUREG/CR-6260 locations in implementing procedures for the Thermal FMP.

During the audit and review, the staff noted that this enhancement also affects the Monitoring

and Trending program element as described in GALL AMP X.M1.

The GALL Report recommends the following for the Monitoring and Trending program element:

The program monitors a sample of high fatigue usage locations. As a minimum,

this sample is to include the locations identified in NUREG/CR-6260.

The staff found the applicant's enhancement to the Metal Fatigue of the Reactor Coolant

Pressure Boundary Program (to include all NUREG/CR-6260 locations in implementing

procedures for the Thermal FMP necessary for consistency with the GALL Report AMP

description and acceptable.

During the audit and review, the staff asked whether the applicant has plant-specific locations

where fatigue cumulative usage factors (CUFs) are projected to be higher than the values

projected for NUREG/CR-6260 locations. In response, the applicant stated that the LRA

identified other areas as acceptable in accordance with 10 CFR 54.21 (c)(1)(iii) projected to

have cumulative fatigue usage values higher than those for NUREG/CR-6260 locations. The

applicant stated that it will revise its FMP to include these locations as well as the

NUREG/CR-6260 locations. The applicant stated that it updates fatigue evaluations conducted

in accordance with this program once per cycle and projects them to a 60-year end of life (EOL)

and that it will take appropriate corrective actions for any locations projected to exceed the code

acceptance criteria for fatigue before its occurrence.

The staff reviewed the applicant's response together with the pertinent section of the LRA.

Because the applicant's Thermal Fatigue Management Program includes most limiting locations

and all of the applicable NUREG/CR-6260 locations, the staff found the applicant's response

acceptable.

For the "Acceptance Criteria" program element, the applicant indicated that an alternative

approach will be taken if the fatigue usage limit for the monitored components can not be

demonstrated to remain less than 1.0. In accordance with GALL program X.M1; acceptable

corrective actions include a more rigorous analysis of the component to demonstrate that the

design code limit will not be exceeded, repair, or replacement of the component. The applicant

indicated that an alternative approach would be to show that potential cracking is maintained

below the criteria of ASME Section XI, Appendix L, or an approved NRC limit. The staff has not

endorsed an alternative approach which relies on inspection in lieu of meeting the ASME Code

fatigue limit of 1.0. The staff notes that, if this alternative option is selected, the inspection

details, including scope, qualification, method, and frequency must be provided to the NRC for

review and approval prior to the period of extended operation. An aging management program

under this option would be a departure from the design basis CUF evaluation, described in the

USAR supplement, and therefore, would require a license amendment pursuant to 10 CFR

50.59.

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The staff reviewed those portions of AMP B3.2, "Metal Fatigue of the Reactor Coolant Pressure

Boundary Program," that the applicant claimed are consistent with GALL AMP X.M1 and found

them consistent. The staff found the applicant's AMP acceptable because it conforms to the

recommended GALL Report AMP with the enhancement as described above.

ODeratina Experience. In LRA Section B3.2, the applicant explained that the MNGP technical

staff monitors industry operating experience through peer groups, industry information (e.g.,

INs, licensee event reports, SILs), and by communications with other plant's subject matter

experts. The staff evaluates information from these sources for impact on the Metal Fatigue of

the Reactor Coolant Pressure Boundary Program. In addition, the MNGP technical staff

updates internal operating experience to account for operating cycles and their effect on fatigue

of limiting components on a frequency of at least once per refueling cycle. This ensures the

adequacy of the program in terms of providing a periodic means of evaluating fatigue margins

and establishing corrective action plans as necessary. For example, in May 1999, MNGP

experienced several transients as indicated by FW and RWCU flow data. Subsequent review

concluded that these transients could have an impact on FW nozzle fatigue usage and that they

did not conform to the transient descriptions that will normally be considered in the Thermal

FMP. An evaluation of these transients found that the effect on fatigue was not significant

(0.003 addition). However, the applicant incorporated the results into the Thermal FMP which is

updated at least once every refueling cycle. The MNGP CAP database documents this

operating experience.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that plant-specific operating experience revealed no

degradation not bounded by industry experience.

On the basis of its evaluation of the applicant's program against the .program elements

described in the GALL Report AMP, its review of the above industry and plant-specific operating

experience, and its discussions with the applicant's technical personnel, the staff concluded that

the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary Program will

adequately manage the aging effects identified in LRA for which this AMP is credited.

USAR SuDplement. In LRA Section A4.2, the applicant provided the USAR supplement for the

Metal Fatigue of the Reactor Coolant Pressure Boundary Program. The staff reviewed this

section and determined that the information in the USAR supplement adequately describes the

program, as required by 10 CFR 54.21 (d).

By letter dated June 10, 2005, the applicant included commitment 52, that before the period of

extended operation, it will incorporate requirements for inclusion of NUREG/CR-6260 locations

in implementing procedures for the Thermal Fatigue Monitoring Program; however, USAR

supplement Section A4.2 did not capture this commitment. The applicant stated that it will

update the USAR supplement to. include the commitment in the annual LRA update letter. In its

letter dated February 28, 2005, the applicant provided a revision to USAR supplement Section

A4.2, which included the commitment.

Conclusion. On the basis of its review and audit of the applicant's Metal Fatigue of the Reactor

Coolant Pressure Boundary Program, the staff determined that those program elements for

which the applicant claimed consistency with the GALL Report are consistent with the GALL

Report. In addition, the staff reviewed the enhancement and confirmed that its implementation

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before the period of extended operation will result in the existing AMP being consistent with the

GALL Report AMP to which it was credited. The staff concluded that the applicant

demonstrated that the effects of aging will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concluded

that it adequately describes the program, as required by 10 CFR 54.21 (d).

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, the applicant identified the following plant-specific AMPs:

" Bus Duct Inspection Program (B2.1.6)

" System Condition Monitoring Program (B2.1.32)

For AMPs that are not consistent with or not addressed by the GALL Report, the staff

performed a complete review of the AMPs to determine if they are adequate to manage aging.

The following sections of this SER document the staff's review of these plant-specific AMPs.

3.0.3.3.1 Bus Duct Inspection Program

Summary of Technical Information in the Application. In LRA Section B2.1 .6, the applicant

described the Bus Duct Inspection Program, stating that this new program will be consistent

with the applicable 10 elements described in SRP-LR Appendix A. In the LRA, the applicant

stated that the primary purpose of this new, plant-specific program is to demonstrate that aging

effects will be adequately managed so that nonsegregated bus ducts within the scope of

license renewal will perform their intended function in accordance with the CLB during the

period of extended operation. The intended function of nonsegregated bus ducts is to provide

electrical connections to specified sections of an electrical circuit to deliver voltage, current, or

signals.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.6 regarding the applicant's demonstration of the Bus Duct

Inspection Program to ensure that the effects of aging, as discussed above, will be adequately

managed so that intended functions will be maintained consistent with. the CLB for the period of

extended operation.

The applicant credited the Bus Duct Inspection Program with aging management of the

nonsegregated phase bus. The applicant stated that the Bus Duct Inspection Program is a new

plant-specific program. Its purpose is to demonstrate that the aging effects caused by ingress

of moisture or contaminants (dust and debris), insulation degradation from heat or radiation in

the presence of oxygen, and bolt relaxation from thermal cycling will be adequately managed so

that the nonsegregated bus ducts subject to an AMR will perform their intended function in

accordance with the CLB during the period of extended operation.

To determine whether the applicant's AMP is adequate to manage the effects of aging so that

intended functions will be maintained consistent with the CLB for the period of extended

operation, the staff evaluated the (1) scope of program, (2) preventive actions, (3) parameters

monitored or inspected, (4) detection of aging effects, (5) monitoring and trending,

(6) acceptance criteria, and (7) operating experience. SER Section 3.0.4 provides the staff's

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evaluation of the applicant's corrective actions, confirmation process, and administrative

controls.

(1) Scope of Program-This program applies to all bus ducts within the scope of license

renewal. The program manages the aging effects for components in the offsite power/station

blackout (SBO) recovery path commodity group. The staff reviewed the specific components

that the program identified.

The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criterion.

The program includes all bus ducts within the scope of license renewal. On this basis, the staff

found the applicant's program scope acceptable.

(2) Preventive Actions-The Bus Duct Inspection Program monitors conditions. The program

does not include any actions to prevent or mitigate aging degradation, and the staff identified no

need for such actions.

The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criterion.

The staff identified no need for preventive actions for this AMP as a condition monitoring

program. On this basis, the staff found the applicant's Preventive Actions program element

acceptable.

(3) Parameters Monitored or Inspected-The applicant stated that this program will check a

sample of accessible bolted connections (bus joints and ending devices) for proper torque, or

the resistance of bolted joints for resistance with a micro-ohmmeter of sufficient current

capacity for checking bus bar connections. This program will also inspect internal portions of

accessible bus ducts for cracks, corrosion, foreign debris, dust buildup, and moisture intrusion.

The applicant will inspect the bus insulating system for signs of embrittlement, cracking,

melting, swelling, or discoloration that may indicate overheating or aging degradation. It will

inspect the bus supports for structural integrity and cracking.

The staff confirmed that the.Parameters Monitored or Inspected element satisfies the

SRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.

On this basis, the staff found the applicant's Parameters Monitored or Inspected program

element acceptable.

(4) Detection of Aging Effects-The applicant stated that this program visually inspects internal

portions of bus ducts, the bus insulating system, and the bus supports. In addition, a torque test

or resistance test of a sample of accessible bolted connections will be performed. The applicant

will complete the program before the end of the initial 40-year license term and every 10 years

thereafter, a period adequate for preventing failures of the bus ducts as experience shows that

aging degradation is a slow process. A 10-year inspection frequency provides two data points

during a 20-year period to characterize the degradation rate.

In RAI B2.1.6-1, dated November 7, 2005, the staff noted that vendors do not recommend the

re-torque of bolted connections unless the joint requires service or the bolted connections are

clearly loose. The torque required to turn the fastener in the tightening direction (restart torque)

is not a good indication of the preload after the fastener is in service. Because of relaxation of

parts of the joint, the final loads are likely to be lower than the installed loads; therefore, the

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staff requested that the applicant justify that re-torquing of bolted connections is a good

indicator of the preload after the fastener is in service.

In its response dated December 7, 2005, the applicant stated that it will follow the guidance of

EPRI TR-104213, Section 8.2, "Inspection of Electrical Bolted Joints," which does not

recommend re-torquing of bolted connections. It will check a sample of accessible bolted

connections loose connections by thermography or by connection resistance measurement with

a low-range ohmmeter. Metal enclosed bus (MEB) internal surfaces will be visually inspected

for aging degradation of insulating material, foreign debris and excessive dust buildup, and

evidence of moisture intrusion. Bus insulation will be visually inspected for signs of

embrittlement, cracking, melting, swelling, or discoloration that may indicate overheating or

aging degradation. Internal bus supports will be visually inspected for structural integrity and

cracks. The applicant will complete this program before the period of extended operation and

every 10 years thereafter if visual inspection is not used to check bolted connections. A 10-year

inspection interval will provide two data points during a 20-year period to characterize the

degradation rate. This inspection frequency is adequate to prevent failures of the MEBs, as

experience shows that aging degradation is a slow process.

The applicant will use visual inspection as an alternative to thermography or connection

resistance measurement for accessible bolted connections covered with heat-shrink tape,

sleeving, insulating boots, and other materials. Visual inspection of the insulation material will

detect surface anomalies, such as discoloration, cracking, chipping, or surface contamination.

When this alternative visual inspection is used to check bolted connections, the first inspection

will be completed before the period of extended operation and every 5 years thereafter.

Based on its review, the staff found that the visual inspection of bus ducts and internal bus

supports will indicate aging effects and that thermography or resistance checks of a sample of

bolted jbints will ensure that bolted connections do not loosen from ohmic heating. The staff

also found-that the 10-year inspection frequency is adequate to prevent failures of bus ducts as

industry experience shows that the aging degradation is a slow process. Therefore, the staff's

concern described in RAI B2.1.6-1 is resolved.

The staff confirmed that the Detection of Aging Effects element satisfies SRP-LR

Section A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects. On

this basis, the staff found the applicant's proposed Detection of Aging Effects program element

acceptable.

(5) Monitoring and Trending-The applicant stated that this program does not include trending

actions because the ability to trend inspection results is limited. The staff found this acceptable

because trending will be performed under a controlled administrative process.

The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3

criteria, as it takes into consideration plant-specific and industry operating experience. On this

basis, the staff found the applicant's proposed Monitoring and Trending program element

acceptable.

(6) Acceptance Criteria-The applicant stated that in this program, bolted connections must

meet the manufacturer's minimum torque specifications or the resistance of bolted joints must

meet required specifications. Bus ducts must be free from any surface anomalies that suggest

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conductor insulation degradation exists. An additional acceptance criterion requires no

indication of unacceptable corrosion, cracking, foreign debris, dust buildup, or moisture

intrusion. Any condition or situation that, if not corrected, could lead to a loss of intended

function is considered unacceptable.

As discussed above, the staff expressed concern about re-torquing of the bolted connections.

The applicant stated that it will revise its acceptance criteria to remove reference to checking

the torque of bolted connections, and to use thermography or resistance checks of a sample of

bolted joints for reasonable assurance that bolted connections do not loosen from ohmic

heating. In its letter dated February 28, 2006, the applicant revised the acceptance criteria to

remove reference to checking bolt torque, which resolved the staffs concern.

The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1.2.3 criteria. The

Acceptance Criteria element provides a basis for evaluation of the need for corrective actions to

ensure that the bus duct intended function will be maintained during the period of extended

operation. On this basis, the staff found the applicant's Acceptance Criteria program element

acceptable.

After reviewing the Corrective Actions program element, the staff identified an area for which it

needed additional information to complete its evaluation of the applicant's Bus Duct Inspection

Program. In RAI B2.1.6-2, dated November 7, 2005, the staff noted that, with regard to this

element, the applicant had stated that requirements of AppendixB, "Quality Assurance Criteria

for Nuclear Power Plants and Fuel Processing Plants," to 10 CFR Part 50 apply; however, it is

the staff's position that the Corrective Actions element should provide for further investigation

and evaluation when acceptance criteria are not met. Corrective actions may include but are not

limited to cleaning, drying, increased inspection frequency, repair, or replacement of the

affected metal enclosed bus components. If an unacceptable condition or situation is identified,

a determination is made as to whether the same condition or situation applies to other

accessible or inaccessible metal enclosed bus. Therefore, the staff requested that the applicant

revise the corrective actions in LRA Section B2.1.6 to add specific requirements or justify why

corrective actions are not necessary.

In its response, by letter dated December 7, 2005, the applicant stated that it will add the

following statement to the Corrective Actions element:

Further investigation and evaluation are performed when the acceptance criteria

are not met. Corrective actions may include, but are not limited to, cleaning,

drying, increased inspection frequency, replacement, or repair of the affected

metal enclosed bus components. If an unacceptable condition or situation is

identified, a determination is made as to whether the same condition or situation

is applicable to other accessible or inaccessible metal enclosed bus.

Based on its review, the staff found the applicant's response to RAI B2.1.6-2 acceptable;

therefore, the staff's concern described in RAI B2.1.6-2 is resolved.

The staff confirmed that the Corrective Actions element satisfies the SRP-LR A.1.2.3 criteria.

The Corrective Actions element describes actions to be taken when the acceptance criteria are

not met to ensure that the bus duct intended function will be maintained during the period of

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extended operation: On this basis, the staff found the applicant's Corrective Actions program

element acceptable.

Operatinq Experience. In LRA Section B2.1.6, the applicant explained that the Bus Duct

Inspection Program is a new program and no site operating experience exists. Industry

operating experience has demonstrated that the failures of bus ducts are caused by cracked

insulation of the bus combined with moisture or debris buildup internal to the bus ducts. It has

also been shown that bus duct internals exposed to appreciable ohmic heating during operation

may experience loosening of bolted connections related to repeated cycling of connected loads.

The staff found that the proposed program will ensure that bus ducts are not exposed to

excessive ohmic or ambient heating.

USAR Supplement. In LRA Section A2.1.6, the applicant provided the USAR supplement for

the Bus Duct Inspection Program. The staff reviewed this section and determined that the

information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21 (d).

In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.6,

documented as commitment 17 in Table A.5, which states that before the period of extended

operation, the applicant will implement the Bus Duct Inspection Program consistent with the

appropriate 10 elements described in Appendix A to the SRP-LR.

Conclusion. On the basis of its review and audit of the applicant's Bus Duct Inspection

Program, the staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21(d).

3.0.3.3.2 System Condition Monitoring Program

Summary of Technical Information in the Application. In LRA Section B.2.1.32, the applicant

described its System Condition Monitoring Program". The applicant stated that this existing

plant-specific MNGP program with enhancements, will be consistent with the applicable 10

elements described in SRP-LR Appendix A.

The applicant stated that the System Condition Monitoring Program is an existing plant-specific

program that is based on system engineer monitoring. Although MNGP performs many

monitoring activities, this AMP brings aging management into the scope of the monitoring

activities. Other groups augment this program by identifying and reporting adverse material

conditions via the corrective action process or work control process. This monitoring consists of

system-level performance monitoring, inspections and walkdowns, health and status reporting,

and PM.

The applicant will enhance this program to include specific activities and criteria for managing

age-related degradation for SSCs within the scope of license renewal. This program manages

aging effects for normally accessible external surfaces of piping, tanks, hangers and supports,

racks, panels, and other components and equipment within the scope of license renewal. These

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aging effects are managed through visual inspection and monitoring of external surfaces for

leakage and evidence of material degradation.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information

included in LRA Section B2.1.32 to demonstrate that the System Condition Monitoring Program

will ensure that the effects of aging will be adequately managed so that the intended function

will be maintained consistent with the CLB throughout the period of extended operation.

The staff reviewed the System Condition Monitoring Program against the AMP elements found

in the GALL Report, SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1, and focused on the

program's management of aging effects through the effectiv.e incorporation of the 10 program

elements. The applicant indicated that the site-controlled Quality Assurance Program includes

the corrective actions, confirmation process, and administrative controls. SER Section 3.0.4

discusses the staff's evaluation of the Quality Assurance Program.

(1) Scope of Program-The applicant stated that the System Condition Monitoring Program

visually inspects and monitors the accessible external surfaces of systems and components

within the scope of license renewal for signs of excessive and/or abnormal aging effects and

material degradation. The System Condition Monitoring Program consists of activities that

manage the aging effects for components of various mechanical and civil/structure systems,

including alternate nitrogen supply, automatic pressure relief, chemistry sampling, circulating

water (CWT), combustible gas control (CGC), condensate and FW, condensate storage, CRD,

CSP, demineralized water, EDGs, emergency filtration train, ESW, FIR, fuel pool cooling and

cleanup (FPC), hangers and supports, HTV, HPCI, AIR, main condenser (MC), MST, primary

containment mechanical, radwaste solid and liquid, reactor building, RBC, reactor core isolation

cooling (RCIC), reactor head vent, REC, reactor vessel instrumentation, RWCU, RHR,

secondary containment, service and seal water, SLC, turbine generator, and wells and

domestic water.

The staff's review of LRA Section B2.1.32 identified areas for which it needed additional

information to complete its evaluation of the applicant's program elements. The applicant

responded to the staff's RAIs as discussed below.

In RAI B2.1.32-1, dated July 20, 2005, the staff requested that the applicant list any

inaccessible surfaces of components (including lagged/insulated piping <212 OF) to be

managed by this program and discuss the bases for determining that the inaccessible surfaces

will be adequately managed.

In its response, by letter dated August 16, 2005, the applicant stated the following:

The System Condition Monitoring Program manages aging effects through visual

inspection and monitoring of SSCs that are accessible during normal operation,

during refueling outages, or as part of planned maintenance.

Accessible areas are those areas that are available for inspection and monitoring

during routine operations or that become accessible for inspection and

monitoring during refueling or maintenance activities. Insulated piping can be

made accessible, as needed, for inspection and monitoring for the presence of

age related degradation of SSCs within the scope of license renewal. For

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example, insulated piping at operating temperatures >212 degrees F can

normally be evaluated for aging effects based on the inspection of uninsulated

piping of the same materials in the same environment. Because of this

temperature, a wetted environment is not expected. For insulated piping

operating <212 degrees F (e.g., HVAC cooling loops), inspections will include

removal of insulation where it is determined that inspections of uninsulated

portions cannot be extrapolated for managing relevant aging effects.

Visual inspections will be performed of observable indicators that detect

age-related degradation. Examples of observable indicators are crack-like

indications, corrosion, erosion, leakage, presence of moisture (condensation), or

physical displacement. I

Inaccessible areas are those areas that have no access due to facility

construction (i.e., require a plant modification to access) or that present a

significant health, safety, and/or radiological hazard. SSCs that require aging

management that are inaccessible will be evaluated for the impact of aging

based on comparable accessible locations. This evaluation will be performed on

accessible SSCs on the basis of same material(s) and the same or more severe

environment(s) as those portions that are considered inaccessible.

If an unacceptable condition or situation is identified in an accessible portion of a

system, an extent of condition evaluation will be performed to determine whether

the same condition or situation is applicable to other accessible or inaccessible

portions of the system. Appropriate follow-up inspection and corrective actions

will be implemented as needed.

Based on its review, the staff found the applicant's response to RAI B2.1.32-1 acceptable. The

applicant stated that it will evaluate inaccessible surfaces for the impact of aging based on

comparable accessible locations. For insulated piping, inspections will include removal of

insulation where inspections of uninsulated portions cannot be extrapolated. This will allow for

managing relevant aging effects consistent with the staff's position for management of

inaccessible surfaces for the External Surfaces Monitoring Program in Revision 1 of the GALL

Report. Therefore, the staff's concern described in RAI B2.1.32-1 is resolved.

The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criteria.

The scope of the program identifies mechanical, civil, and structural components from various

systems included in the program. On this basis, the staff found the applicant's program scope

acceptable.

(2) Preventive Actions-The applicant stated that no preventive actions are associated with this

AMP, the objective of which is to identify and manage aging effects of concern before the loss

of intended function (i.e., condition monitoring).

The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criteria.

The staff identified no need for preventive actions for this AMP as a condition monitoring

program. On this basis, the staff found the applicant's Preventive Actions program element

acceptable.

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(3) Parameters Monitored or Inspected-The applicant stated that the System Condition

Monitoring Program uses periodic plant system inspections and walkdowns to monitor for

material degradation of mechanical systems/components and civil structures. It will also inspect

hanger and support, rack, panel, and anchorage material condition for excessive and/or

abnormal material degradation conditions such as cracking, paint deterioration (an indicator of

possible underlying degradation), loose, worn or missing parts/components, fluid leaks, bolting

or fastener degradation, evidence of corrosion, sealant deterioration, and other problems. It will

revise implementing instructions and procedures to include specific parameters to be monitored

and inspected. These parameters will be generated based on industry practices from INPO,

EPRI, and other organizations.

The staff confirmed that the Parameters Monitored or Inspected element satisfies the

SRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.

On this basis, the staff found the applicant's Parameters Monitored or Inspected program

element acceptable.

(4) Detection of Aging Effects-The applicant stated that the readily accessible external

surfaces of various components (e.g., pump casings, valve bodies, piping, expansion joints) are

visually inspected for leakage and evidence of excessive and abnormal material degradation.

The minimum walkdown frequency is once per year for systems and components accessible

during normal operation. The inspection frequency may be increased according to the safety

significance, production significance, and/or operating experience of each system. The

applicant inspects systems and components accessible only during plant outages at least once

per refueling interval.

In RAI B2.1.32-2, dated July 20, 2005, the staff requested that the applicant discuss the

inspection methods and acceptance criteria for the aging effects listed below:

a) change in material properties and cracking for neoprene ventilation seals in

ESF systems,

b) SCC for stainless steel piping and fittings in auxiliary systems,

c) crevice corrosion for steel and copper alloy components in the auxiliary

systems,

d) crevice corrosion for copper alloy components in the steam and power

conversion systems,

e) SCC and crevice corrosion for stainless steel spent fuel pool liner.

In its response, by letter dated August 16, 2005, the applicant stated the following:

The methods and techniques for the detection of the above aging effects will be

accomplished in accordance with the recommendations of industry guidelines.

Direct visual inspection may be augmented by the use of tools such as mirrors,

binoculars, and flashlights. EPRI documents will be the general source for

guidance on aging detection techniques. These guidance documents include

field guides and aging identification and assessment checklists. These

documents provide descriptions of observable indicators relative to specific aging

degradation.

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Examples of EPRI guidance documents are:

" EPRI TR-107668, "Guidelines for System Monitoring by System Engineers"

" EPRI TR-104514, "How to Conduct Material Condition Inspections"

* EPRI 1007933, "Aging Assessment Field Guide."

EPRI 1007933 is a field guide for assessing aging degradation. This field guide

provides a description of the aging degradation and photographic images of the

actual degradation. This field guide has specific indicators to identify aging

degradation. For example, the polymers (including neoprene) section lists

indicators for chemical, thermal, radiation, ultraviolet, etc. induced degradation.

Crevice corrosion is also included under the topic of metal degradation.

Instruction to understand age-related degradation of plant SSCs and to identify

the leading indicators of various degradation mechanisms and effects will be

provided. EPRI guidance, supplemented by other related materials, will be used

to establish this instruction. Examples of training topics are:

* .Fundamentals

• Metals Aging Degradation

• Concrete Aging Degradation

* Polymers Aging Degradation

* Protective Coatings and Linings Aging Degradation

* Electrical Components Aging Degradation

Should there be indication of an unacceptable degradation, the visual inspection

will be supplemented with other examine techniques or analytical evaluation as

needed. For example, visual observation of crack-like-indications identified

during monitoring will be reported via the corrective action process. As part of

the corrective action process, further evaluation will be performed using

applicable techniques such as non-destructive examination methods (e.g., dye

penetrant testing), to determine the extent of degradation and needed corrective

actions. This process would be used to confirm the presence of stress corrosion

cracking.

In response to the specific items in this question, the following information is

provided:

Item a

Regarding changes in material condition or cracking in

elastomers, including neoprene, visual inspection will detect

degradation indicators such as discoloration, surface films,

wrinkling, distortion, and crack-like indications. The presence of

any of these indicators will trigger an evaluation to determine the

extent of degradation.

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Item b

Visual inspection will identify crack-like indications that will require

further evaluation via the corrective action process. Further

evaluation, via NDE methods, will identify the specific type of

cracking, such as stress corrosion cracking. See response to

RAI 3.3.2.3-1.

Items c and d

Visual inspection will identify loss of material due to corrosion as

evidenced by the presence of localized corrosion products, such

as scale and metal oxides. The majority of the remaining exposed

base metal will appear unaffected. Identification of the corrosion

as crevice corrosion is based on locations and materials that

would be susceptible to this type of corrosion because of crevice

geometry (e.g., presence of crevices or crevice forming materials,

bolted versus welded connections) and stagnant liquid

environment. Additional guidance (from industry sources such as

NACE International) will be used to identify crevice corrosion as

well as other types of corrosion as appropriate. Significant surface

degradation will be evaluated via the corrective action process.

Item e

Cracking due to stress corrosion cracking and loss of material due

to crevice corrosion for the stainless steel spent fuel pool liner in a

treated water environment is managed by the Plant Chemistry

Program as stated in LRA Table 3.5.2-15 (Page 3-748). This is

consistent with GALL line item IIl.A5.2-b...

...Additionally, Note 539 states, "The System Condition Monitoring

Program is credited for monitoring the spent fuel pool water level

and spent fuel pool leakage". This note was specifically added to

define the consistency with GALL and to differentiate between the

two AMPs with regard to what aging effect/mechanism was

managed by each.

Based on its review, the staff found the applicant's response to RAI B2.1.32-2 acceptable. The

applicant addressed inspection methods and acceptance criteria for various aging effects,

including change in material properties for elastomers, SCC, pitting, and crevice corrosion. The

methods described by the applicant are acceptable detection techniques for the aging effects

addressed; therefore, the staff's concern described in RAI B2.1.32-2 is resolved.

The staff confirmed that the Detection of Aging Effects element satisfies SRP-LR

Section A.1.2.3 criteria. The Detection of Aging Effects element links the Parameters Monitored

or Inspected element to the aging effects managed, the System Condition Monitoring Program

adequately describes data collection, and examination methods and frequency are adequately

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linked to plant-specific and industry operating experience. On this basis, the staff found the

applicant's proposed Detection of Aging Effects program element acceptable.

(5) Monitoring and Trending-The applicant stated that the System Condition Monitoring

Program is capable of detecting the effects of aging before a structure's (hangers and

supports) or component's loss of function can occur. Visual inspections performed at least once

per year for systems and components accessible during normal plant operation may increase in

frequency based on the safety significance, production significance, or operating experience of

each system. The applicant inspects systems and components accessible only during plant

outages at least once per refueling interval. These inspections and walkdowns provide timely

detection of aging effects (i.e., before the loss of intended function). It documents inspection

and walkdown results for condition trending information.

The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3

criteria. The System Condition Monitoring Program monitors and trends certain attributes like

leakage and addresses the predictability of the extent of degradation and, thus, timely

corrective action. On this basis, the staff found the applicant's proposed Monitoring and

Trending program element acceptable.

(6) Acceptance Criteria-The applicant stated that it will use normal design standards,

procedural requirements, CLB information, and industry codes or standards (e.g., EPRI, INPO)

to determine acceptance criteria. Implementing instructions and procedures will include

acceptance criteria for age-related degradation such as corrosion, leakage, deformation,

cracking, and other adverse conditions that negatively impact performance of a license renewal

intended function. The applicant will use references such as EPRI field guides for acceptance

criteria guidance. It will enter excessive or abnormal conditions not meeting acceptance criteria

into the corrective action process based on evaluation results.

The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1 .2.3 criteria. The

Acceptance Criteria element provides a basis for evaluation of the need for corrective actions to

ensure that the SC intended function will be maintained during the period of extended

operation. On this basis, the staff found the applicant's Acceptance Criteria program element

acceptable.

Operating Experience. The applicant stated that the System Condition Monitoring Program has

been effective in monitoring system performance and, as enhanced, provides reasonable

assurance of effective management of aging effects from external visible aging mechanisms.

The System Condition Monitoring Program is based on routine walkdowns by qualified system

engineers. The Engineering Department monitors walkdown progress monthly as a

performance indicator, with a goal of 90 percent completed as scheduled. Since data gathering

began in May 2003, the applicant completed 100 percent of the monthly walkdowns through

August 2004 as scheduled. Numerous examples were noted where system engineers

documented needed corrective actions through minor maintenance tasks, WOs, or AR (entered

into the site CAP). System engineers maintain system health reports as one way to track the

progress of system performance, outstanding work, and the results of their operating

experience reviews. Of the 82 systems tracked by system health reports, all but three met or

exceeded performance expectations as of September 2004.

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The staff confirmed that the Operating Experience element satisfies SRP-LR A.1.2.3 criteria.

Operating experience with the existing program shows that the System Condition Monitoring

Program detects system degradation in a timely manner. On this basis, the staff found the

applicant's Operating Experience program element acceptable.

The applicant credited the System Condition Monitoring Program with managing aging effects

for structural components like concrete anchors and elastomers. The GALL Report

recommends the Structures Monitoring Program for management of these types of

components. As documented in the audit and review report, the staff asked the applicant to

discuss how the System Condition Monitoring Program addresses the GALL Report

recommendations for the Structures Monitoring Program for managing aging effects of these

components. The applicant stated that it reassigned a number of components to be managed

by the Structures Monitoring Program as recommended by the GALL Report to the System

Condition Monitoring Program. For these components, the 10 attributes of both AMPs are

compatible in that they address similar scope, preventive actions, parameters monitored or

inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

actions, confirmation process, and administrative controls elements. On the basis of its review

and the information provided by the applicant, the staff found that the System Condition

Monitoring Program provides acceptable aging management for these structural components.

USAR Supplement. In LRA Section A2.1.32, the applicant provided the USAR supplement for

the System Condition Monitoring Program. The staff reviewed this section and determined that

the information in the USAR supplement adequately describes the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its review and audit of the applicant's System Condition Monitoring

Program, the staff concluded that the applicant demonstrated that the effects of aging will be

adequately managed so that intended functions will be maintained consistent with the CLB for

the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed

the USAR supplement for this AMP and concluded that it adequately describes the program, as

required by 10 CFR 54.21 (d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), a license renewal applicant must demonstrate that the effects

of aging on SCs subject to an AMR will be adequately managed so that their intended functions

will be maintained consistent with the CLB for the period of extended operation.

Branch Technical Position IQMB-1, "Quality Assurance For Aging Management Programs,"

(SRP-LR Section A.2) provides the following guidance with regard to the QA attributes of

AMPs:

* SR SCs are subject to the requirements of Appendix B to 10 CFR Part 50, which are

adequate to address all quality-related aspects of an AMP consistent with the CLB of

the facility for the period of extended operation.

* For NSR SCs that are subject to an AMR, an applicant has an option to expand the

scope of its program for Appendix B to 10 CFR Part 50 to include these SCs to address

corrective actions, the confirmation process, and administrative controls for aging

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management during the period of extended operation. In this case, the applicant should

document such a commitment in the USAR supplement in accordance with

10 CFR 54.21(d).

3.0.4.1 Summary of Technical Information in the Application

LRA Section A2, "Programs That Manage the Effects of Aging," states that the elements of

Corrective Actions, Confirmation Process, and Administrative Controls in the Quality Assurance

Program apply to both SR and NSR SSCs subject to an AMR. In LRA Section B1.3, "Quality

Assurance Program and Administrative Controls," the applicant described the quality attributes

of the plant-specific AMPs and summarized them as follows:

A single corrective actions process is applied regardless of the safety classification of

the SC. Corrective actions are implemented through the initiation of an AR in

accordance with plant procedures established in response to Appendix B to

10 CFR Part 50.

The programs correct equipment deficiencies through the initiation of a WO in

accordance with plant procedures. Although a WO may initially document equipment

deficiencies, the corrective action process specifies that an AR also be initiated for

actual or potential problems, including failures, malfunctions, discrepancies, deviations,

defective material and equipment, nonconformances, and administrative control

discrepancies. Site-specific administrative work instructions will apply to both SR and

NSR SCs that are subject to an AMR consistent with the CLB during the period of

extended operation.

The confirmation process is part of the CAP. The confirmation process focuses on the

followup actions that must be taken to verify effective implementation of corrective

actions. Effectiveness is measured in terms of correcting the adverse condition and

precluding repetition of significant conditions adverse to quality. Plant procedures

include provisions for timely evaluation of adverse conditions and implementation of any

corrective actions required, including root cause determinations and prevention of

recurrence where appropriate (e.g., significant conditions adverse to quality). These

procedures provide for tracking, coordinating, monitoring, reviewing, verifying,

validating, and approving corrective actions to ensure that effective corrective actions

are taken. The AR process is also monitored for potentially adverse trends. The

existence of an adverse trend because of recurring or repetitive adverse conditions will

result in the initiation of an AR. The AMAs required for license renewal will also uncover

any unsatisfactory condition resulting from ineffective corrective action. The applicant

will enhance site documents that implement AMAs for license renewal to ensure that an

AR is prepared in accordance with plant procedures whenever nonconforming

conditions are found (i.e., the acceptance criteria are not met).

The document control process applies to all MNGP documents, procedures, and

instructions regardless of safety classification of the associated SC. The applicant

implements the document control processes in accordance with the requirements of

Appendix B to 10 CFR Part 50. The document control requirements will apply to AMPs.

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In its letter dated June 10, 2005, the applicant revised Appendix A to its LRA to add

Section A.5, which contains a commitment list related to license renewal aging management

that will be added to the USAR following receipt of the extended license.

3.0.4.2 Staff Evaluation

The staff reviewed portions of the applicant's AMPs described in LRA Sections A2, A5, and

B1.3 to ensure that the AMAs are consistent with the staff's guidance in Branch Technical

Position IQMB-1 regarding AMP QA attributes. The staff confirmed that the descriptions,

commitments, and applicability of the plant-specific AMPs and their associated quality attributes

provided in LRA.Sections A2, A5, and B1.3 are consistent with the staff position in Branch

Technical Position IQMB-1 regarding aging management QA.

3.0.4.3 Conclusion

The applicant described the quality attributes of the programs and activities for managing the

effects of aging for both SR and NSR SSCs within the scope of license renewal. The staff found

that the QA attributes of the applicant's AMPs as described in LRA Sections A2, A5, and B1.3

are consistent with the staff position in Branch Technical Position IOMB-1. Therefore, the QA

attributes of the applicant's AMPs appropriately ensure adequate management of aging effects

to maintain intended functions consistent with the CLB in accordance with 10 CFR 54.21 (a)(3).

The staff also found the commitment in the applicant's letter dated June 10, 2005, to revise the

USAR to specify commitments related to license renewal aging management consistent with

Branch Technical Position IQMB-1. Therefore, it meets the requirement in 10 CFR 54.21 (d).

3.1 Aging Management of Reactor Coolant System

This section of the SER documents the staff's review of the applicant's AMR results for the

RCS components and component groups associated with the following systems:

* reactor head vent system

0 reactor pressure vessel

0 reactor pressure vessel internals

0 reactor recirculation system

- reactor vessel instrumentation

3.1.1 Summary of Technical Information in the Application

In LRA Section 3.1, the applicant provided AMR results for the RCS components and

component groups. In LRA Table 3.1.1, the applicant provided a summary comparison of its

AMRs with the AMRs evaluated in the GALL Report for the reactor vessel, internals, and RCS

components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

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review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the FICS components that are within the scope of

license renewal and subject to an AMR will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA is applicable and that the applicant had identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, which is summarized in SER

Section 3.1.2.1.

The staff also performed an onsite audit of those selected AMRs that are consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations are-consistent with the acceptance criteria in Section 3.1.2.2 of

the SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which

are summarized in SER Section 3.1.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified all plausible aging effects and

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The MNGP audit and review report documents the staff's audit

evaluations. SER Section 3.1.2.3 documents the staff's audit evaluations and technical review.

Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensure

that theyadequately describe the programs credited with managing or monitoring aging for the

RCS components.

Table 3.1-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.1, that are addressed in the GALL Report.

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Table 3.1-1 Staff Evaluation for Reactor Coolant System Components in the GALL

Report

Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism Report _________________

Reactor coolant Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

pressure boundary damage accordance with evaluated in

components 10 CFR 54.21 (c) Section 4.3, Metal

(Item Number Fatigue of the RPV

3.1.1-01) and Internals, and.

Reactor Coolant

Pressure Boundary

Piping and

Components

Steam generator Loss of material Inservice Not applicable,

shell assembly due to pitting and inspection; water PWR only

(Item Number crevice corrosion chemistry

3.1.1-02)

Isolation condenser Loss of material Inservice Not applicable (see

(Item Number due to general, inspection; water Section 3.1.2.2.2)

3.1.1-03) pitting, and crevice chemistry

corrosion

Pressure vessel Loss of fracture TLAA, evaluated in TLAA This TLAA is

ferritic materials toughness due to accordance with evaluated in

that have a neutron neutron irradiation Appendix G to Section 4.2,

fluence greater than embrittlement 10 CFR 50 and Neutron

1017 n/cm 2 RG 1.99 Embrittlement of the

(E > 1 MeV) Reactor Pressure

(Item Number Vessel and

3.1.1-04) Internals

Reactor vessel Loss of fracture Reactor vessel Reactor Vessel Consistent with

beltline shell and toughness due to surveillance Surveillance GALL, which

welds neutron irradiation Program (B2.1.29) recommends further

(Item Number embrittlement evaluation (see

3.1.1-05) Section 3.1.2.2.3)

Westinghouse and Loss of fracture Plant specific Not applicable,

B&W baffle/former toughness due to PWR only

bolts neutron irradiation

(Item Number embrittlement and

3.1.1-06) void swelling

Small-bore reactor Crack initiation and Inservice ASME Section XI Consistent with

coolant system and growth due to SCC, inspection; water In-Service GALL, which

connected systems intergranular SCC, chemistry, one-time Inspection, recommends further

piping and thermal and inspection Subsections IWB, evaluation (see

(Item Number mechanical loading IWC, and IWD Section 3.1.2.2.4)

3.1.1-07) Program (B2.1.2);

One-Time

Inspection Program

(B2.1.23); Plant

Chemistry Program

(B2.1.25)

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Component Group Aging Effect/ AMP in GALL AMP In LRA Staff Evaluation

Mechanism Report ________

Jet pump sensing Crack initiation and Plant specific ASME Section XI The jet pump

line, and reactor growth due to SCC, In-Service sensing lines

Vessel flange leak intergranular stress Inspection, internal to the

detection line corrosion cracking Subsections IWB, reactor vessel are

(Item Number (IGSCC), or cyclic IWC, and IWD outside the scope of

3.1.1-08) loading Program (B2.1.2); license renewal.

One-Time The vessel flange

Inspection Program leak detection line

(B2.1.23); Plant is covered by Item

Chemistry Program Number 3.1.1-07.

(82.1.25) Further evaluation

in Section 3.1.2.2.4

Isolation condenser Crack initiation and Inservice Not applicable (see

(Item Number growth due to stress inspection; water Section 3.1.2.2.4)

3.1.1-09) corrosion cracking chemistry

(SCC) or cyclic

loading

Vessel shell Crack growth due to TLAA Not applicable,

(Item Number cyclic loading PWR only

3.1.1-10)

Reactor internals Changes in Plant specific Not applicable,

(Item Number dimension due to PWR only

3.1.1-11) void swelling

PWR core support Crack initiation and Plant specific Not applicable,

pads, instrument growth due to SCC PWR only

tubes (bottom head and/or primary

penetrations), water stress

pressurizer spray corrosion cracking

heads, and nozzles (PWSCC)

for the steam

generator

instruments and

drains

(Item Number 3.1 .1-1 2)__ _ _ _ _ _ _ __ _ _ _ _ _ ___ _ _ _ _ _ _

Cast austenitic Crack initiation and Plant specific Not applicable,

stainless steel growth due to SCC PWR only

(CASS) reactor

coolant system

piping

(Item Number

3.1.1-13)

Pressurizer Crack initiation and Inservice Not applicable,

instrumentation growth due to inspection; water PWR only

penetrations and PWSCC chemistry

heater sheaths and

sleeves made of

Ni-alloys

(Item Number

3.1.1-14) II__ _ _ I

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Component Group Aging Effe•t/. AMP in GALL' - AMP in LRA '!Staff Evaluation'

-Mephanism 'Reporqq ,- ________

Westinghouse and Crack initiation and Plant specific Not applicable,

B&W baffle former growth due to SCC PWR only

bolts and IASCC

(Item Number

3.1.1-15)

Westinghouse and Loss of preload due Plant specific Not applicable,

B&W baffle former to stress relaxation PWR only

bolts

(Item Number

3.1.1-16)

Steam generator Loss of section Plant specific Not applicable,

feedwater thickness due to PWR only

impingement plate erosion

and support

(Item Number

3.1.1-17)

(Alloy 600) steam Crack initiation and Steam generator Not applicable,

generator tubes, growth due to tubing integrity; PWR only

repair sleeves, and PWSCC, outside water chemistry

plugs diameter stress

(Item Number corrosion cracking

3.1.1-18) (ODSCC), and/or

intergranular attack

(IGA) or loss of

material due to

wastage and pitting

corrosion, and

fretting and wear; or

deformation due to

corrosion at tube

support plate

intersections

Tube support lattice Loss of section Plant specific Not applicable,

bars made of thickness due to PWR only

carbon steel FAC

(Item Number

3.1.1-19)

Carbon steel tube Ligament cracking Plant specific Not applicable,

support plate due to corrosion PWR only

(Item Number

3.1.1-20)

Steam generator Loss of material Combustion Not applicable,

feedwater inlet ring due to engineering (CE) PWR only

and supports flow-corrosion steam generator

(Item Number feedwater ring

3.1.1-21) inspection

Reactor vessel Crack initiation and Reactor head Reactor Head Consistent with

closure studs and growth due to SCC closure studs Closure Studs GALL Report, which

stud assembly and/or IGSCC Program (B2.1.28) recommends no

(Item Number further evaluation

3.1.1-22)

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Corn onent-Group 'Aging Eff•cVtl - AMP in GALL .AMP ••- In LRA Staff swalutlon

Mechanism Repor,

CASS pump casing Loss of fracture Inservice inspection ASME Section XI Consistent with

and valve body toughness due to In-Service GALL Report (see

(Item Number thermal aging Inspection, Section 3.1.2.1.1)

3.1.1-23) embrittlement Subsections IWB,

IWC, and IWD

Program (B2.1.2)

CASS piping Loss of fracture Thermal aging Not applicable,

(Item Number toughness due to embrittlement of MNGP does not

3.1.1-24) thermal aging CASS have CASS piping

embrittlement

BWR piping and Wall thinning due to Flow-accelerated Flow-Accelerated Consistent with

fittings; steam flow-accelerated corrosion Corrosion Program GALL Report for

generator corrosion (B2.1.19) BWR piping and

components fittings in the RCS.

(Item Number

3.1.1-25) MNGP is a BWR

and does not have

a steam generator

Reactor coolant Loss of material Bolting integrity Bolting Integrity Consistent with

pressure boundary due to wear, loss of Program (B2.1.4) GALL Report, which

(RCPB) valve preload due to recommends no

closure bolting, stress relaxation, further evaluation

manway and crack initiation and

holding bolting, and growth due to cyclic

closure bolting in loading and/or SCC

high pressure and

high-temperature

systems

(Item Number

3.1.1-26)

Feedwater and Crack initiation and Feedwater nozzle, BWR Control Rod Consistent with

control rod drive growth due to cyclic CRD retum line Drive Retum Line GALL Report, which

(CRD) return line loading nozzle Nozzle Program recommends no

nozzles (B2.1.7), BWR further evaluation

(Item Number Feedwater Nozzle

3.1.1-27) Program (B2.1.8)

Vessel shell Crack initiation and BWR vessel ID BWR Vessel ID Consistent with

attachment welds growth due to SCC, attachment welds, Attachment Welds GALL Report, which

(Item Number IGSCC water chemistry Program (B2.1.11), recommends no

3.1.1-28) Plant Chemistry further evaluation

Program (B2.1.25)

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Component Group'. Aging Effect] AMP in GALL' .,:AMP In LRA Staff Evaluation

-Mechanism .-Report0

Nozzle safe ends, Crack initiation and BW R stress ASME Section Xl Consistent with

recirculation pump growth due to SCC, corrosion cracking; In-Service GALL Report, which

casing, connected IGSCC water chemistry Inspection, recommends no

systems piping and Subsections IWB, further evaluation

fittings, body and IWC, and IWD

bonnet of valves Program (B2.1.2);

(Item Number BWR Stress

3.1.1-29) Corrosion Cracking

Program (B2.1.10);

One-Time

Inspection Program

(B2.1.23); Plant

Chemistry Program

(B2.11.25)

Penetrations Crack initiation and BWR penetrations, BWR Penetrations Consistent with

(Item Number growth due to SCC, water chemistry Program (82.1.9), GALL Report, which

3.1.1-30) IGSCC, cyclic Plant Chemistry recommends no

loading Program (B2.1.25) further evaluation

Core shroud and Crack initiation and BWR vessel BWR Vessel Consistent with

core plate, support growth due to SCC, intemals, water Internals Program GALL Report, which

structure, top guide, IGSCC, IASCC chemistry (B2.1.12), Plant recommends no

core spray lines and Chemistry Program further evaluation

spargers, jet pump (12.1.25)

assemblies, control

rod drive housing,

nuclear

instrumentation

guide tubes

(Item Number

3.1.1-31)

Core shroud and Crack initiation and ASME Section XI ASME Section XI Consistent with

core plate access growth due to SCC, inservice In-Service GALL Report, which

hole cover (welded IGSCC, IASCC inspection; water Inspection, recommends no

and mechanical chemistry Subsections IWB, further evaluation

covers) IWC, and IWD

(Item Number Program (82.1.2);

3.1.1-32) Plant Chemistry

Program (B2.1.25)

Jet pump assembly Loss of fracture Thermal aging and Thermal Aging & Consistent with

castings, orificed toughness due to neutron irradiation Neutron Irradiation GALL Report, which

fuel support thermal aging and embrittlement Embrittlement of recommends no

(Item Number neutron Cast Austenitic further evaluation

3.1.1-33) embrittlement Stainless Steel

(CASS) Program

(82.1.33)

Unclad top head Loss of material Inservice Not applicable. The

and nozzles due to general, inspection; water top head enclosure

(Item Number pitting, and crevice chemistry is clad at MNGP

3.1.1-34) corrosion

CRD nozzle Crack initiation and Ni-alloy nozzles and Not applicable,

(Item Number growth due to penetrations, water PWR only

3.1.1-35) PWSCC chemistry

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Component Group Aging Effect/ AMP in GALL- AMP in LRA: Staff EvaluationMechOanism'- Report,- 7_ _ _ _ _

Reactor vessel Crack initiation and Inservice Not applicable,

nozzles safe ends growth due to cyclic inspection; water PWR only

and CRD housing, loading, and/or SCC chemistry

reactor coolant and PWSCC

system components

(except CASS and

bolting)

(Item Number

3.1.1-36)

Reactor vessel Loss of fracture Thermal aging and Not applicable,

internals CASS toughness due to neutron irradiation PWR only

components thermal aging, embrittlement

(Item Number neutron irradiation

3.1.1-37) embrittlement, and

void swelling

External surfaces of Loss of material Boric acid corrosion Not applicable,

carbon steel due to boric acid PWR only

components in corrosion

reactor coolant

system pressure

boundary

(Item Number

3.1.1-38)

Steam generator Loss of material Inservice inspection Not applicable,

secondary due to erosion PWR only

manways and

handholds (CS)

(Item Number

3.1.1-39)

Reactor intemals, Loss of material Inservice inspection Not applicable,

reactor vessel due to wear PWR only

closure studs, and

core support pads

(Item Number

3.1.1-40)

Pressurizer integral Crack initiation and Inservice inspection Not applicable,

support growth due to cyclic PWR only

(Item Number loading

3.1.1-41)

Upper and lower Loss of preload due. Inservice Not applicable,

intemals assembly to stress relaxation inspection; loose PWR only

(Westinghouse) part and/or neutron

(Item Number noise monitoring

3.1.1-42)

Reactor vessel Loss of fracture PWR vessel Not applicable,

internals in fuel toughness due to internals, water PWR only

zone region (except neutron irradiation chemistry

Westinghouse and embrittlement, and

B&W baffle bolts) void swelling

(Item Number

3.1.1-43) __

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Component Group Aging Effect/ AMP in GALL AMP In LRA Stiff E valuatldnf _____________ Medchrnilsm Report ________

Steam generator Crack initiation and Inservice Not applicable,

upper and lower growth due to SCC, inspection; water PWR only

heads, tubesheets, PWSCC, IASCC chemistry

primary nozzles and

safe ends

(Item Number

3.1.1-44)

Vessel internals Crack initiation and PWR vessel Not applicable,

(except growth due to SCC intemals, water PWR only Westinghouse and and IASCC chemistry

B&W baffle former

bolts)

(Item Number

3.1.1-45)

Reactor internals Loss of preload due Inservice Not applicable, (B&W screws and to stress relaxation inspection; loose PWR only

bolts) part monitoring (Item Number

3.1.1-46)

Reactor vessel Loss of material Reactor head Not applicable, closure studs and due to wear closure studs PWR only

stud assembly

(Item Number

3.1.1-47)

Reactor internals Loss of preload due Inservice Not applicable,

(Westinghouse to stress relaxation inspection; loose PWR only

upper and lower part monitoring internal assemblies;

CE bolts and tie

rods)

(Item Number

3.1.1-48) A

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in SER Section 3.1.2.1, involves the staff's review of the AMR results

for components in the RCS that the applicant indicated are consistent with the GALL Report

and do not require further evaluation. Another approach, documented in SER Section 3.1.2.2,

involves the staff's review of the AMR results for components in the RCS that the applicant

indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.1.2.3, involves the staff's

review of the AMR results for components in the RCS that the applicant indicated are not

consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff's

review of AMPs that are credited to manage or monitor aging effects of the RCS components.

3.1.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicant

identified the materials, environments' and AERMs. The applicant identified the following

programs that manage the aging effects related to the RCS components:

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" ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD

Program (B2.1.2)

" Bolting Integrity Program (B2.1.4)

* BWR Control Rod Drive Return Line Nozzle Program (B2.1.7)

* BWR Feedwater Nozzle Program (B2.1.8)

* BWR Penetrations Program (B2.1.9)

* BWR Stress Corrosion Cracking Program (82.11.10)

* BWR Vessel ID Attachment Welds Program (B2.1.11)

" BWR Vessel Internals Program (B2.1.12)

* Closed-Cycle Cooling Water System Program (B2.1.13)

* Flow-Accelerated Corrosion Program (B2.1 .19)

" One-Time Inspection Program (B2.1.23)

* Plant Chemistry Program (B2.1.25)

" Reactor Head Closure Studs Program (B2.1.28)

* Reactor Vessel Surveillance Program (B2.1.29)

" System Condition Monitoring Program (B2.1.32)

* Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic Stainless

Steel (CASS) Program (B2.1.33)

Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant provided a summary of

AMRs for the RCS components, and identified which AMRs it considered to be consistent with

the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

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the GALL Reliort. The staff verified that it had reviewed and accepted the identified exceptions

to the GALL Report AMPs. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant was unable

to find a listing of some system components in the GALL Report. However, the applicant

identified a different component in the GALL Report that has the same material, environment,

aging effect, and AMP as the component under review. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the AMR line item

of the different component is applicable to the component under review and whether the AMR is

valid for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component is applicable to the component under review. The staff verified that it had reviewed

and accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

these line items to verify consistency with the GALL Report. The staff also determined whether

the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The

following sections discuss the staff's evaluation.

3.1.2.1.1 Loss of Fracture Toughness Due to Thermal Aging Embrittlement

NRC Audit Item 3.1-18

In the discussion section of LRA Table 3.1.1, Item Number 3.1.1-23, the applicant stated the

following:

This line item is not used at MNGP. The reactor coolant systems components of

CASS material are portions of the Jet Pump, Fuel Support, and CRD

assemblies. See items 3.1.1-31 and 3.1.1-33 for these components. In addition,

CASS valve bodies in the ESF system are discussed in item 3.2.1-11 of

Table 3.2.1.

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During the audit and review, the staff noted that the LRA states that, 'This line iterh is not used

at MNGP." Based on the LRA discussion in Table 3.1.1, Item 3.1.1-23, the staff reviewed ESF

Item Number 3.2.1-11 in LRA Table 3.2.1 for CASS piping and fittings in the ECCS. The staff

confirmed that the LRA includes AMR results for CASS valve bodies in the CSP system (LRA

Table 3.2.2-3) and in the RHR system (LRA Table 3.2.2-7), which the applicant had referenced

appropriately to GALL Report line IV.C1.3-b. The staff also confirmed that the material,

environment, aging effect, and AMP combination specified in the LRA for these valves is

consistent with GALL Report line IV.C1.3-b, which applies to CASS valves in a reactor coolant

water environment with an aging effect of loss of fracture toughness due to thermal aging

embrittlement and which specifies the ASME Section XI In-Service Inspection,

Subsections IWB, IWC, and IWD Program as the AMP for Class 1 components. However, the

staff noted that the applicant had linked these AMR results with Item 3.1.1-23 in LRA

Table 3.1.1, where the discussion states that, 'This line item is not used at MNGP."

Therefore, the staff asked that the applicant resolve the LRA discrepancy linking AMR results

for components in one table with an item number in another table, while stating that MNGP

does not use the item number. In its response, dated August 11, 2005, the applicant stated the

following:

LRA Table 3.1.1, Item Number 3.1.1-23, should be revised to read, 'CASS

components in the ESF systems subject to an environment that supports loss of

fracture toughness due to thermal aging embrittlement were assigned to the

ASME Section XI In-Service Inspection, Subsections IWB, IWC and IWD

Program. Those CASS components that are subject to this aging effect!

mechanism are valves.'

Based on its review, the staff found the applicant's response to NRC Audit Item 3.1-18

acceptable because the components, material, aging effect, and AMP identified in the LRA are

consistent with the GALL Report. The staff found that the applicant had appropriately

addressed the aging management for these components. SER Section 3.0.3.2.2 documents the

staff's evaluation of the applicant's ASME Section XI In-Service Inspection, Subsections IWB,

IWC, and IWD Program.

On the basis of its review, the staff found that the applicant addressed the aging effects and

mechanisms as identified in the GALL Report.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. On the basis of its review, the

staff concluded that the AMR results, which the applicant claimed to be consistent with the

GALL Report, are consistent with the AMRs in the GALL Report; therefore, the staff concluded

that the applicant has demonstrated that the effects of aging for these components will be

adequately managed so that their intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

RCS components. The applicant provided information concerning how it will manage the

following aging effects:

• cumulative fatigue damage

" loss of material due to pitting and crevice corrosion

* loss of fracture toughness due to neutron irradiation embrittlement

* crack initiation and growth due to thermal and mechanical loading or stress corrosion

cracking

" crack growth due to cyclic loading

* changes in dimension due to void swelling

* crack initiation and growth due to stress corrosion cracking or primary water stress

corrosion cracking

" crack initiation and growth due to stress corrosion cracking or irradiation-assisted stress

corrosion cracking

* loss of preload due to stress relaxation

* loss of section thickness due to erosion

* crack initiation and growth due to PWSCC, ODSCC, or intergranular attack or loss of

material due to wastage and pitting corrosion or loss of section thickness due to fretting

and wear or denting due to corrosion of carbon steel tube support plate

• loss of section thickness due to flow-accelerated corrosion

* ligament cracking due to corrosion

" loss of material due to flow-accelerated corrosion

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addressed the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in Section 3.1.2.2 of

the SRP-LR. The staff's audit and review report details the staff's audit. The following sections

discuss the staff's evaluation of the aging effects.

3.1.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3, "Definitions." Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's review of the applicant's evaluation

of this TLAA.

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3.1 .2.2.2 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Sections 3.1.2.2.2.1 and 3.1.2.2.2.2 against SRP-LR Section 3.1.2.2.2

criteria.

In LRA Section 3.1.2.2.2.1, the applicant addressed loss of material due to pitting and crevice

corrosion in the steel pressurized-water reactor (PWR) steam generator shell assembly.

Loss of material for a steam generator shell assembly applies to PWRs only. The staff found

this aging effect not applicable.

In LRA Section 3.1.2.2.2.2, the applicant addressed loss of material due to pitting and crevice

corrosion in BWR isolation condenser components.

MNGP has no isolation condenser. The staff found this aging effect not applicable.

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Sections 3.1.2.2.3.1 through 3.1.2.2.3.3 against SRP-LR

Section 3.1.2.2.3 criteria.

In LRA Section 3.1.2.2.3.1, the applicant addressed loss of fracture toughness due to neutron

irradiation embrittlement for pressure vessel ferritic materials with a neutron fluence greater

than 1017 n/cm2. The applicant stated that neutron irradiation embrittlement is a TLAA as

defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). LRA Section 4.2 describes the applicant's evaluation of this TLAA.

In LRA Section 3.1.2.2.3.2, the applicant addressed loss of fracture toughness due to neutron

irradiation embrittlement for the reactor vessel, stating that the Reactor Vessel Surveillance

Program, described in LRA Section B2.1.29, manages loss of fracture toughness due to

neutron irradiation embrittlement for the reactor vessel. SER Section 3.0.3.2.21 documents the

staff's review of the Reactor Vessel Surveillance Program.

SRP-LR Section 3.1.2.2.3 states that certain aspects of neutron irradiation embrittlement are

TLAAs as defined in 10 CFR 54.3 and that TLAAs must be evaluated in accordance with

10 CFR 54.21 (c)(1). SER Section 4.2 documents the staff's review of the applicant's evaluation

of this.TLAA. SRP-LR Section 3.1.2.2.3 also states that for loss of fracture toughness due to

neutron embrittlement of the reactor vessel beltline shell, nozzle, and welds exposed to reactor

coolant and neutron flux, a reactor vessel materials surveillance program monitors neutron

irradiation embrittlement of the reactor vessel.

Appendix H to 10 CFR Part 50 requires the applicant's Reactor Vessel Surveillance Program.

BWRVIP ISP guidance describes the scope of the Reactor Vessel Surveillance Program.

BWRVIP-86-A includes the ISP capsule removal schedule, and BWRVIP-78 describes its

technical basis. The NRC approved the ISP in an SE to the BWRVIP, dated February 1, 2002,

concluding that, if implemented in accordance with the conditions in the SE, the ISP is an

acceptable alternative to all existing BWR plant-specific RPV surveillance programs for

maintaining compliance with the requirements of Appendix H to 10 CFR Part 50 through the

end of the current facility 40-year operating license period.

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BWRVIP-1 16 incorporates the technical criteria specified in BWRVIP-78 and BWRVIP-86 and

extends the ISP to cover the BWR fleet through an extended period of operation. The applicant

committed to implement the requirements of BWRVIP-1 16, when approved.

In LRA Section 3.1.2.2.3.3, the applicant addressed loss of fracture toughness due to neutron

irradiation embrittlement in Westinghouse and Babcock and Wilcox (B&W) baffle/former bolts.

This section applies to PWRs only. The staff found this aging effect not applicable.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.1.2.2.3. For those line items that apply to LRA Sections 3.1.2.2.3.1 through

3.1.2.2.3.3, the staff determined that the applicant's AMRs are consistent with the GALL Report

and the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.2.4 Crack Initiation and Growth Due to Thermal and Mechanical Loading or StressCorrosion Cracking

The staff reviewed LRA Sections 3.1.2.2.4.1 through 3.1.2.2.4.3 against SRP-LR

Section 3.1.2.2.4 criteria.

In LRA Section 3.1.2.2.4.1, the applicant addressed crack initiation and growth due to thermal

and mechanical loading or SCC in small-bore RCS and connected system piping less than 4-

inch nominal pipe size (NPS). The applicant stated that the ASME Section XI In-Service

Inspection, Subsections IWB, IWC, and IWD Program, together with the Plant Chemistry

Program and One-Time Inspection Program manage the aging effect. The applicant further

stated that the ASME Code, Section XI, does not require volumetric examination of pipes less

than 4-inch NPS and that the scope of the One-Time Inspection Program validates AMP

effectiveness by verifying unacceptable degradation. The applicant stated that the aging effects

monitored/inspected by its One-Time Inspection Program include crack initiation and growth

and that this program includes one-time inspections to monitor a component's degradation

using a variety of NDE methods.

SRP-LR Section 3.1.2.2.4, item 1, states the following:

Crack initiation and growth due to thermal and mechanical loading or SCC

(including intergranular stress corrosion cracking [IGSCC]) could occur in

small-bore reactor coolant system and connected system piping less than NPS

4. The existing program relies on ASME Section XI ISI and on control of water

chemistry to mitigate SCC. The GALL report recommends that a plant-specific

destructive examination or a nondestructive examination (NDE) that permits

inspection of the inside surfaces of the piping be conducted to ensure that

cracking has not occurred and the component intended function will be

maintained during the extended period. The AMPs should be augmented by

verifying that service-induced weld cracking is not occurring in the small-bore

piping less than NPS 4, including pipe, fittings, and branch connections. A

one-time inspection of a sample of locations is an acceptable method to ensure

that the aging effect is not occurring and the component's intended function will

be maintained during the period of extended operation.

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The staff reviewed LRA Section 3.1.2.2.4.1, Tables 3.1.2-1 through 3.1.2-5, and LRA

Appendix B2..1.23, and confirmed that the applicant's One-Time Inspection Program

appropriately includes the small bore, Class 1 piping in the head vent system and the reactor

vessel instrumentation system.

The staff also reviewed the applicant's drawings of the RCS and connected systems and

identified a number of small-bore, Class 1 pipe segments. The staff asked the applicant

whether the One-Time Inspection Program includes each of the segments. In its response, by

letter dated August 11, 2005, the applicant provided additional information including references

to LRA table entries. The staff reviewed the applicant's response and concluded that the

applicant's One-Time Inspection Program appropriately includes all Class 1 small-bore pipe

segments.

As part of its response, the applicant stated that in Class 1, small-bore stainless steel piping,

the aging effect managed by the Plant Chemistry and One-Time Inspection Programs is

cracking due to SCC; however, in Class 1, small-bore carbon steel piping, the aging effect

managed by the Plant Chemistry and One-Time Inspection Programs is loss of material due to

corrosion. Because different examination techniques are typically required to detect the aging

effect of cracking versus that of loss of material, the staff asked the applicant to justify why it

does not manage the Class 1, small-bore carbon steel piping for an aging effect of crack

initiation and growth due to thermal and mechanical loading.

In its response dated August 11, 2005, the applicant stated that it had performed an analytical

evaluation to classify all Class 1 and 2 piping welds by failure potential based on methodology

in EPRI TR-1 12657, Revision B-A. Based on this evaluation, the applicant determined that it

has no Class 1, small-bore carbon steel piping in an environment where cracking due to

mechanical or thermal loading will occur. Consequently, one-time inspection of Class 1,

small-bore carbon steel piping will focus on the loss of material, but not on the crack initiation

and growth aging effect.

The staff reviewed the applicant's response together with the applicant's calculation providing

the analytical basis for excluding cracking as an aging effect in Class 1, small-bore carbon steel

piping. The staff noted that SRP-LR Section 3.1.2.2.4 makes no distinction between stainless

steel and carbon steel piping, and that the purpose of the one-time inspection is to validate the

absence of cracks that the ASME Code, Section XI, examinations required for small-bore piping

might not detect. Because the applicant used an appropriate methodology to exclude the aging

effect of cracking in carbon steel small-bore piping and will perform a one-time inspection for

cracking in stainless steel small-bore piping, the staff found the applicant's programs for

managing aging effects in Class 1, small-bore piping acceptable. SER Sections 3.0.3.2.2,

3.0.3.2.19, and 3.0.3.1.4 document the staff's evaluations of the applicant's ASME Section XI,

In-Service Inspection, Subsections IWB, IWC, and IWD Program, Plant Chemistry Program,

and One-Time Inspection Program, respectively.

On the basis of its review, the staff concluded that the applicant has met the SRP-LR

Section 3.1.2.2.4.1 criteria for further evaluation. For those line items that apply to LRA

Section 3.1.2.2.4.1, the staff found that the applicant's AMRs are consistent with the GALL

Report and the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained during the period of extended

operation as required by 10 CFR 54.21 (a)(3).

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In LRA Section 3.1.2.2.4.2, the applicant addressed crack initiation and growth due to thermal

and mechanical loading or SCC in reactor vessel flange leak detection lines and jet pump

sensing lines.

SRP-LR Section 3.1.2.2.4, item 2, states the following:

Crack initiation and growth due to thermal and mechanical loading or SCC

(including IGSCC) could occur in BWR reactor vessel flange leak detection line

and BWR jet pump sensing line. The GALL report recommends that a plant

specific aging management program be evaluated to mitigate or detect crack

initiation and growth due to SCC of vessel flange leak detection line.

In LRA Section 3.1.2.2.4.2, the applicant stated that the jet pump sensing lines internal to the

reactor vessel are not within the scope of license renewal, referring to the LRA's "Further

Evaluation" description of crack initiation and growth due to thermal and mechanical loading or

SCC regarding management of the reactor vessel flange leak detection line and other

small-bore RCS and connected system piping.

The staff noted that the jet pump sensing lines external to the vessel are small-bore piping and

included in LRA Table 3.1.2-5 as piping and fittings made of stainless steel in a treated water

environment with an aging effect of cracking due to SCC/IGA. For this component, material,

environment, and aging effect, the LRA stated that the applicable AMPs are the ASME Section

XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, the One-Time Inspection

Program, and the Plant Chemistry Program. This is consistent with the GALL Report

recommendation for small-bore, stainless steel pipe in a reactor coolant water environment.

Based on consistency with the GALL Report recommendations, the staff found the applicant's

AMPs for these components acceptable as consistent with the GALL Report recommendations.

For aging management of the reactor vessel flange leak detection line, the applicant, in LRA

Section 3.1.2.2.4.2, stated that the aging effects/mechanisms for this component are the same

as for other small-bore RCS and connected system piping. For these components, the

applicable AMPs are the ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and

IWD Program together with the Plant Chemistry Program and the One-Time Inspection

Program. As the reactor vessel flange leak detection line has the same material and

environment and, consequently, the same aging effects as Class 1 small-bore piping, the staff

concluded that the AMPs that the applicant identified for this component are acceptable. SER

Sections 3.0.3.2.2, 3.0.3.2.19, and 3.0.3.1.4 document the staff reviews and evaluations of the

applicant's ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD Program,

Plant Chemistry Program, and One-Time Inspection Program, respectively.

On the basis of its review, the staff concluded that the applicant has met SRP-LR

Section 3.1.2.2.4.2 criteria for further evaluation. For those line items that apply to LRA

Section 3.1.2.2.4.2, the staff found that the applicant's AMRs are consistent with the GALL

Report and the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended functions will be maintained during the period of extended

operation as required by 10 CFR 54.21 (a)(3).

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In LRA Section 3.1.2.2.4.3, the applicant addressed crack initiation and growth due to thermal

and mechanical loading or SCC in the BWR isolation condenser. Because there is no isolation

condenser, the staff found this aging effect not applicable.

3.1.2.2.5 Crack Growth Due to Cyclic Loading

The staff reviewed LRA Section 3.1.2.2.5 against SRP-LR Section 3.1.2.2.5 criteria.

In LRA Section 3.1.2.2.5, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in the

reactor vessel shell and the RCS piping and fittings. SRP-LR Table 3.1-1 states that further

evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.6 Changes in Dimension Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.6 against SRP-LR Section 3.1.2.2.6 criteria.

In LRA Section 3.1.2.2.6, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.6 states that changes in dimension due to void swelling could occur in

reactor internal components. SRP-LR Table 3.1-1 states that further evaluation for this aging

effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.7 Crack Initiation and Growth Due to Stress-Corrosion Cracking or Primary Water

Stress-Corrosion Cracking

The staff reviewed LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3 against SRP-LR

Section 3.1.2.2.7 criteria.

In LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3, the applicant stated that this aging effect

applies to PWRs only.

SRP-LR Section 3.1.2.2.7 states that crack initiation and growth due to SCC and PWSCC could

occur (1) in PWR core support pads (or core guide lugs), instrument tubes (bottom head

penetrations), pressurizer spray heads, and nozzles for the steam generator instruments and

drains, (2) in PWR CASS RCS piping and fittings and pressurizer surge line nozzles, and (3) in

PWR pressurizer instrumentation penetrations and heater sheaths and sleeves made of nickel

alloys. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants

only.

The staff found this aging effect not applicable.

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3.1.2.2.8 Crack Initiation and Growth Due to Stress-Corrosion Cracking or Irradiation-Assisted

Stress-Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.8 against SRP-LR Section 3.1.2.2.8 criteria.

In LRA Section 3.1.2.2.8, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.8 states that crack initiation and growth due to SCC or IASCC could

occur in baffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states

that further evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 against SRP-LR Section 3.1.2.2.9 criteria.

In LRA Section 3.1.2.2.9, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation could occur in

baffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states that further

evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.10 Loss of Section Thickness Due to Erosion

The staff reviewed LRA Section 3.1.2.2.10 against SRP-LR Section 3.1.2.2.10 criteria.

In LRA Section 3.1.2.2.10, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.10 states that loss of section thickness due to erosion could occur in

steam generator FW impingement plates and supports. SRP-LR Table 3.1-1 states that further

evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.11 Crack Initiation and Growth Due to Primary Water Stress-Corrosion Cracking,

Outside-Diameter Stress-Corrosion Cracking, or Intergranular Attack or Loss of

Material Due to Wastage and Pitting Corrosion or Loss of Section Thickness Due to

Fretting and Wear or Denting Due to Corrosion of Carbon Steel Tube Support Plate

The staff reviewed LRA Section 3.1.2.2.11 against SRP-LR Section 3.1.2.2.11 criteria.

In LRA Section 3.1.2.2.11, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.11 states that crack initiation and growth due to PWSCC, ODSCC, or

IGA or loss of material due to wastage and pitting corrosion or deformation due to corrosion

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could occur in Alloy 600 components of the steam generator tubes, repair sleeves, and plugs.

SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.12 Loss of Section Thickness Due to Flow-Accelerated Corrosion

The staff reviewed LRA Section 3.1.2.2.12 against SRP-LR Section 3.1.2.2.12 criteria.

In LRA Section 3.1.2.2.12, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.12 states that loss of section thickness due to FAC could occur in tube

support lattice bars made of carbon steel. SRP-LR Table 3.1-1 states that further evaluation for

this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.13 Ligament Cracking Due to Corrosion

The staff reviewed LRA Section 3.1.2.2.13 against SRP-LR Section 3.1.2.2.13 criteria.

In LRA Section 3.1.2.2.13, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.13 states that ligament cracking due to corrosion could occur in carbon

steel components in the steam generator tube support plate. SRP-LR Table 3.1-1 states that

further evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.1.2.2.14 Loss of Material Due to Flow-Accelerated Corrosion

The staff reviewed LRA Section 3.1.2.2.14 against SRP-LR Section 3.1.2.2.14 criteria.

In LRA Section 3.1.2.2.14, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.1.2.2.14 states that loss of material due to FAC could occur in FW inlet ring

and supports. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR

plants only.

The staff found this aging effect not applicable.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the applicable issues that were further evaluated. The staff found that the effects of

aging will be adequately managed so that intended functions will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-5,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning the management of the

aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material

for the AMR line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination does not apply. Note J

indicates that the GALL Report does not evaluate either the component or the material and

environment combination for the line item.

Staff Evaluation. For component type, material, and environment combinations that the GALL

Report does not evaluate, the staff reviewed the applicant's evaluation to determine whether

the applicant had demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation. The following sections discuss line items that are not consistent with the GALL

Report or not addressed in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant identified AMR line items for which it had

not identified any aging effects as a result of the aging review process. Specifically, the

applicant stated that no aging effects occurred when components fabricated from stainless

steel material were exposed to a primary containment air or plant indoor air environment, or

when components fabricated from stainless steel or carbon steel were exposed to a lubricating

oil internal environment. The applicant stated that a material science evaluation for these

materials in these environments discovered no aging effects.

Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence of

corrosive species, as stated in the Metals Handbook, Ninth Edition, American Society for Metals

International, the staff accepted the position that stainless steel in an indoor, uncontrolled air

environment (e.g., plant indoor air) or in a gas environment (e.g., primary containment air

inerted with nitrogen) exhibits no aging effect and that the SC will therefore remain capable of

performing intended functions consistent with the CLB for the period of extended operation.

Because both oxygen and moisture must be present to corrode steel, also stated in the Metals

Handbook, Ninth Edition, the staff likewise accepted the position that steel (carbon or stainless)

in a lubricating oil internal environment with no water pooling exhibits no aging effect and that

the SC will therefore remain capable of performing intended functions consistent with the CLB

for the period of extended operation.

On the basis of its review of current industry research and operating experience, the staff found

that plant indoor air or primary containment air on stainless steel, or lubricating oil on stainless

steel or carbon steel, will not cause aging of concern during the period of extended operation;

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therefore, the staff concluded that no AERMs apply to the component, material, and

environment described in the preceding discussion.

3.1.2.3.1 Reactor Coolant System - Reactor Head Vent System - Summary of Aging

Management Evaluation - Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the

reactor head vent system component groups.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the applicant had demonstrated that

the effects of aging will be adequately managed so intended functions will be maintained

consistent with the CLB during the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.1.2.3.2 Reactor Coolant System-Reactor Pressure Vessel-Summary of Aging

Management Evaluation-Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the

RPV component groups.

In LRA Table 3.1.2-2, the applicant stated that the aging effect of cumulative fatigue damage of

Type 316NG stainless steel materials for the component type of nozzle safe end/CRDRL cap

exposed to a reactor coolant water environment does not apply and no AMP is specified. The

LRA assigns Note I to this item, indicating that the aging effect in the GALL Report for this

component, material, and environment combination does not apply. An additional note in the

LRA states that the CRD hydraulic return nozzle was capped with a 4-inch diameter pipe cap in

1977, that the CRD return nozzle weld butter was removed and the weld preparation reclad with

chromium carbide to improve resistance to IGSCC, and that a new nozzle cap was installed in

1986. LRA Table 3.1.2-2 also states that the aging effect of crack initiation and growth due to

SCC or IGSCC also applies to this component, and that the BWR SCC Program (AMP B2.1.10)

and the Plant Chemistry Program (AMP B2.1.25) manage the aging effect.

The staff noted that the applicant's evaluation of this component refers to GALL Report,

Volume 2, Item IV.A1.4-b, which is the CRDRL nozzle safe end. The GALL Report line item is

based on an inservice CRDRL safe end that will routinely experience cyclic flow, not one

effectively out of service by removal of the previously attached pipe and installation of a cap on

the safe end. Capping the CRDRL safe end eliminated the cyclic flow environment to which the

safe end had been exposed and thereby eliminated the potential for the aging effect of

cumulative fatigue damage. In addition, review of operating experience since the CRDRL

nozzle cap replacement in 1986 indicates that no new cracking has occurred at this location.

Because there is no potential for cumulative fatigue damage from flow cycling at the capped

CRDRL safe end and no new cracking has been detected at this location since the nozzle was

capped, the staff found the applicant's statement that cumulative fatigue damage does not

apply to the CRDRL safe end cap in the RPV acceptable.

The applicant proposed to manage crack initiation and growth/SCC for the top head torus,

flange, and dollar plate using the ASME Section Xl In-Service Inspection, Subsections IWB,

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IWC, and IWD Program and Plant Chemistry Program. The material is identified as alloy steel

(A533 Grade B Class and A508 Class 2) and clad (308/309).

The staff's review of LRA Section 3.1.2 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the.

staff's RAI as discussed below.

In RAI 3.1.2-1, dated September 28, 2005, the staff requested that the applicant identify which

materials provide the pressure boundary function and provide the basis, including any operating

experience, for concluding that these materials are susceptible to crack initiation and growth

due to SCC.

In its response, by letter dated October 28, 2005, the applicant responded that the base

material provided the pressure boundary function and that operating experience identified in

BWRVIP-74-A, -BWR Reactor Pressure Vessel inspection and Flaw Evaluation Guidelines for

License Renewal," indicates that the base material was susceptible to SCC. The staff reviewed

this BWRVIP report and could find no operating experience indicating that the alloy steel base

material will be susceptible to SCC. In its letter dated December 16, 2005, the applicant agreed

with the staff that this aging mechanism does not affect the low-alloy base material and stated

that it will revise the LRA accordingly as part of the annual update. By letter dated March 15,

2006, the applicant removed crack initiation and growth due to SCC as an AERM from the top

head enclosure components in LRA Table 3.1.2-2. The staff agreed that crack initiation and

growth is not an AERM for the alloy steel base material in a steam environment; therefore, the

staff's concerns described in RAI 3.1.2-1 are resolved.

The applicant identified no aging effect for the external surface of the reactor vessel exposed to

primary containment air. The staff agreed with this conclusion because the primary containment

air has not caused degradation of the reactor vessel.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the applicant had demonstrated that

the effects of aging will be adequately managed so that the intended functions will be

maintained during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.3 Reactor Coolant System-Reactor Pressure Vessel Internals-Summary of Aging

Management Evaluation-Table 3.1.2-3

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the

RPV internals component groups.

In LRA Table 3.1.2-3, the applicant proposed to manage crack initiation and growth due to

cyclic loading of stainless steel materials for the steam dryer exposed to reactor coolant water

or steam environment using AMP B2.1.12.

SER Section 3.0.3.2.11 documents the staff's evaluation of the BWR Vessel Internals Program.

The applicant's BWR Vessel Internals Program monitors the condition of the BWR vessel

internals for crack initiation and growth. The program includes in-vessel examination and plant

water chemistry procedures. The in-vessel examination procedures implement the

recommendations of the BWRVIP guidelines as well as the requirements of the ASME Code,

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Section Xl. As a result of steam dryer failure at Quad Cities following an extended power

uprate, steam dryers have been within the scope of license renewal pursuant to

10 CFR 54.4(a)(2), because it was shown that failure of the NSR component could prevent

satisfactory accomplishment of intended functions of SR components. They may exhibit

cracking due to flow-induced vibration or cyclic loading and therefore require an AMP.

LRA Table 3.1.2-3 identifies AMP B2.1.12 as the applicable program to manage the aging

effect/mechanism of crack initiation and growth due to cyclic loading. The applicant, in note 136

of the LRA, stated that it will inspect the steam dryer using the guidelines in the approved

BWRVIP topical report for steam dryer inspection and will reevaluate the inspection

requirements if it installs a new steam dryer. Because the applicant's steam dryer inspections

will be consistent with approved, industry-consensus inspection guidelines, the staff found that

the applicant's proposed AMP is acceptable to manage the aging effect of crack initiation and

growth due to cyclic loading of stainless steel material in the steam dryer exposed to a reactor

coolant water or steam environment.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the applicant has demonstrated that the

effects of aging will be adequately managed so that intended functions will be maintained

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.4 Reactor Coolant System-Reactor Recirculation System--Summary of Aging

Management Evaluation-Table 3.1.2-4

The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for the

REC system component groups.

In LRA Table 3.1.2-4, the applicant identified no aging effect for stainless steel fasteners, heat

exchangers, manifolds, piping and fittings, pump casings, thermowells, and valve bodies

exposed to a primary containment air environment.

In addition, it identified no aging effects for carbon steel and stainless steel components

exposed to a lubricating oil environment. SER Section 3.1.2.3 documents the staff's evaluation.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the applicant has demonstrated that the

effects of aging will be adequately managed so that intended functions will be maintained

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.5 Reactor Coolant System-Reactor Vessel Instrumentation-Summary of Aging

Management Evaluation-Table 3.1.2-5

The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMR evaluations for the

reactor vessel instrumentation component groups.

In LRA Table 3.1.2-5, the applicant identified no aging effect for stainless steel fasteners,

manifolds, piping and fittings, restricting orifices, thermowells, and valve bodies exposed to a

primary containment air environment. SER Section 3.1.2.3 documents the staff's evaluation.

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On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the applicant has demonstrated that the

effects of aging will be adequately managed so that intended functions will be maintained

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERM, and AMP combinations that the GALL

Report does not evaluate. The staff found that the applicant has demonstrated that the effects

of aging will be adequately managed so that intended functions will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the RCS components that are within the scope of license renewal and

subject to an AMR will be adequately managed so that intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the RCS, as required

by 10 CFR 54.21 (d).

3.2 Aging Management of Engineered Safety Features

This section of the SER documents the staff's review of the applicant's AMR results for the ESF

components and component groups associated with the following systems:

" automatic pressure relief system

" combustible gas control system * core spray system

* high pressure coolant injection system

" primary containment mechanical system

* reactor core isolation cooling system

* residual heat removal system

• secondary containment system

3.2.1 Summary of Technical Information in the Application

In LRA Section 3.2, the applicant provided AMR results for the ESF components and

component groups. In LRA Table 3.2.1, the applicant provided a summary comparison of its

AMRs with the AMRs evaluated in the GALL Report for the ESF components and component

groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews involved evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

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review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the ESF components that are within the scope of

license renewal and subject to an AMR will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA is applicable and that the applicant had identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, as summarized in SER

Section 3.2.2.1.

The staff also performed an onsite audit of those selected AMRs that are' consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations were consistent with the acceptance criteria in Section 3.2.2.2 of

the SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which

are summarized in SER Section 3.2.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified and evaluated all plausible aging

effects and evaluating whether the aging effects listed are appropriate for the combination of

materials and environments specified. The MNGP audit and review report documents the staff's

audit evaluations. SER Section 3.2.2.3 documents these audit evaluations as well as the staff's

evaluation of its technical review.

Finally, thestaff reviewed the AMP summary descriptions in the USAR supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

ESF components.

Table 3.2-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.2, that are addressed in the GALL Report.

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Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the GALL

Report

Compo nent Group Agin g ýEff~ct/ Y Amp InGALAPi R Staff Evaluation

Piping, fittings, and Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

valves in damage accordance with evaluated in Section

emergency core 10 CFR 54.21 (c) 4.3, Metal Fatigue cooling system of the RPV and

(Item Number Intemals, and

3.2.1-01) Reactor Coolant

Pressure Boundary

Piping and

Components

Piping, fittings, Loss of material Water chemistry, One-Time Consistent with

pumps, and valves due to general one-time inspection Inspection Program GALL, which

in emergency core corrosion (B2.1.23), Plant recommends further

cooling system Chemistry Program evaluation (see

(Item Number (B2.1.25) Section 3.2.2.2.2)

3.2.1-02)

Components in Loss of material Plant specific One-Time Consistent with

containment spray due to general Inspection Program GALL, which

(PWR only), corrosion (B2.1.23), System recommends further

standby gas Condition evaluation (see

treatment (BWR Monitoring Program Section 3.2.2.2.2)

only), and (B2.1.32)

containment

isolation, and

emergency core

cooling systems (Item Number

3.2.1-03)

Piping, fittings, Loss of material Water chemistry, One-Time Consistent with

pumps, and valves due to pitting and one-time inspection Inspection Program GALL, which

in emergency core crevice corrosion (B2.1.23), Plant recommends further

cooling system Chemistry Program evaluation (see

(Item Number (B2.1.25) Section 3.2.2.2.3)

3.2.1-04)

Components in Loss of material Plant specific One-Time Consistent with

containment spray due to pitting and Inspection Program GALL, which

(PWR only), crevice corrosion (B2.1.23), Plant recommends further

standby gas Chemistry Program evaluation (see

treatment (BWR (B2.1.25) Section 3.2.2.2.3)

only), containment

isolation, and

emergency core

cooling systems

(Item Number

3.2.1-05)

Containment Loss of material Plant specific One-Time Consistent with

isolation valves and due to Inspection Program GALL, which

associated piping microbiologically (B2.1.23), Plant recommends further

(Item Number influenced corrosion Chemistry Program evaluation (see

3.2.1-06) 1 1 (B2.1.25) Section 3.2.2.2.4)

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Component Group Aging Effect/ AMP In GALL AMP nI LRA Staff Evaluation>

___________ Mechanism Report ________ _______

Seals in standby Changes in Plant specific One-Time Consistent with

gas treatment properties due to Inspection Program GALL, which

system elastomer (B2.1.23), System recommends further

(Item Number degradation Condition evaluation (see

3.2.1-07) Monitoring Program Section 3.2.2.2.5)

(B2.1.32)

High-pressure Loss of material Plant specific Not applicable,

safety injection due to erosion PWR only (see

(charging) pump Section 3.2.2.2.6)

miniflow orifice

(Item Number

3.2.1-08)

Drywell and Plugging of nozzles Plant specific Not applicable (see

suppression and flow orifices Section 3.2.2.2.7)

chamber spray due to general

system nozzles and corrosion

flow orifices

(Item Number

3.2.1-09)

External surface of Loss of material Plant specific One-Time Consistent with

carbon steel due to general Inspection Program GALL, which

components (Item corrosion (B2.1.23), System recommends further

Number 3.2.1-10) Condition evaluation (see

Monitoring Program Section 3.2.2.2.2)

(82.1.32)

Piping and fittings Loss of fracture Thermal aging Not applicable.

of CASS in toughness due to embrittlement of No CASS

emergency core thermal aging CASS components

cooling system embrittlement susceptible to

(Item Number thermal aging

3.2.1-11) embrittlement in

engineered safety

features

Components Local loss of Open-cycle cooling One-Time Consistent with

serviced by material due to water system Inspection Program GALL Report, which

open-cycle cooling corrosion and/or (82.1.23), recommends no.

system buildup of deposit Open-Cycle Cooling further evaluation

(Item Number due to biofouling Water System

3.2.1-12) Program (B2.1.24),

Plant Chemistry

Program (B2.1.25)

Components Loss of material Closed-cycle Closed-Cycle Consistent with

serviced by due to general, cooling water Cooling Water GALL Report, which

closed-cycle cooling pitting, and crevice system System Program recommends no

system corrosion (82.1.13) further evaluation

(Item Number

3.2.1-13) 1

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Component Group Aging Effect/ AMP in GALL: AMP In LRA -Staff Evaluation

Mechanism Repf- 9 --

Emergency core Wall thinning due to Flow-accelerated This line item is not

cooling system flow-accelerated corrosion used at MNGP (see

valves and lines to corrosion Section 3.2.2.1.1)

and from HPCI and

RCIC pump

turbines

(Item Number

3.2.1-14)

Pumps, valves, Crack initiation and Water chemistry Not applicable,

piping, and fittings growth due to SCC PWR only

in containment

spray and

emergency core

cooling systems

(Item Number

3.2.1-15)

Pumps, valves, Crack initiation and Water chemistry, BWR Stress Consistent with

piping, and fittings growth due to SCC BWR stress Corrosion Cracking GALL Report, which

in emergency core and IGSCC corrosion cracking Program (B2.1.10), recommends no

cooling systems One-Time further evaluation

(item Number Inspection Program

3.2.1-16) (B2.1.23), Plant

Chemistry Program (B2.1.25)

Carbon steel Loss of material Boric acid corrosion Not applicable,

components due to boric acid PWR only

(Item Number corrosion

3.2.1-17)

Closure bolting in Loss of material Bolting integrity Bolting Integrity Consistent with

high-pressure or due to general Program (B2.1.4) GALL Report, which

high-temperature corrosion, loss of recommends no

systems preload due to further evaluation

(Item Number stress relaxation,

3.2.1-18) and crack initiation

and growth due to

cyclic loading or

SCC

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in Section 3.2.2.1, involves the staff's review of the AMR results for

components in the ESF systems that the applicant indicated are consistent with the GALL

Report and do not require further evaluation. Another approach, documented in Section 3.2.2.2,

involves the staff's review of the AMR results for components in the ESF systems that the

applicant indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in Section 3.2.2.3, involves the staff's review of

the AMR results for components in the ESF systems that the applicant indicated are not

consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff's

review of AMPs that are credited to manage or monitor aging effects of the ESF systems

components.

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3.2.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the ESF components:

ASME Section Xl In-Service Inspection, Subsections IWB, IWC, and IWD

Program (B2.1.2)

* Bolting Integrity Program (B2.1.4)

* Buried Piping & Tanks Inspection Program (B2.1.5)

* BWR Stress Corrosion Cracking Program (B2.1.10)

* Closed-Cycle Cooling Water System Program (B2.1.13)

* Flow-Accelerated Corrosion Program (B2.1.19)

* One-Time Inspection Program (B2.1.23)

" Open-Cycle Cooling Water System Program (B2.1.24)

* Plant Chemistry Program (B2.1.25)

* Selective Leaching of Materials Program (B2.1.30)

* System Condition Monitoring Program (B2.1.32)

Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant summarized the AMRs

for the ESF components and identified which AMRs it considered to be consistent with the

GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe the relationship of

the information in the tables to the information in the GALL Report. The staff audited those

AMRs with Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that the staff had reviewed and accepted the identified

exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by

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the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is

valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant could not find

a listing of some system components in the GALL Report. However, the applicant identified a

different component in the GALL Report that has the same material, environment, aging effect,

and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component is applicable to the component under review and whether the AMR is valid

for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component applies to the component under review. The staff verified whether it had reviewed

and accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

.these line items to verify consistency with the GALL Report. The staff also determined whether

the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The

following sections discuss the staff's evaluation.

3.2.2.1.1 Wall Thinning Due to Flow-Accelerated Corrosion

In the discussion section of LRA Table 3.2.1, Item Number 3.2.1-14, the applicant stated the

following:

Aging effect is managed by the Flow-Accelerated Corrosion program.

Consistent with NUREG-1 801, some sections of the High Pressure Coolant

Injection (HPC) and Reactor Core Isolation Cooling (RCI) systems are

susceptible to flow-accelerated corrosion (FAC) and the Flow-Accelerated

Corrosion Program is credited to manage the aging effect. The predominate

sections of the HPC and RCI systems were evaluated as not susceptible to FAC

based on material type or the components have no flow or operate less than 2%

of the plant operating time. The components that fall in the latter category do not

require aging management for FAC in accordance with EPRI, NSAC-202L, R2

3-171
and NUREG-1 557, 'Summary of Technical Information and Agreements from the

Nuclear Regulatory Management and Resources Council Industry Reports

Addressing License Renewal.'

During the audit and review, the staff noted that the applicant did not use Table 3.2.1, Item

3.2.1-14, for Table 2 data. The staff reviewed the GALL Report (Sections V.D2.1-f, V.D2.3-a),

which contains no line item covering ECCS piping in treated water susceptible to FAC. The

applicant did not use Table 3.2.1, Item 3.2.1-14; instead, the applicant included ECCS piping

and fittings exposed to treated water and susceptible to FAC in LRA Table 3.1.1, Item 3.1.1-25.

This line item was a better match for the GALL Report (Section IV.C1.1-c) for materials,

environment, aging effects, and components. The staff asked the applicant the reason for

crediting another line item for this aging effect. The applicant responded that the GALL Report,

Chapter V, contains no line item for ECCS piping in treated water susceptible to FAC; for this

reason, the applicant did not use this line item. Instead the applicant used Table 1 Item 3.1.1-25

as a better match with the GALL Report (Section IV.C.1.1 -c). By its letter dated August 11,

2005, the applicant revised the LRA Table 1, Item 3.2.1-14, from "Aging effect is managed by

the FAC Program," to, "This line item is not used at MNG P."

On this basis, the staff found this program acceptable for managing aging of wall thinning due

to FAC for some sections of the HPC and RCI systems. SER Section 3.0.3.1.2 documents the

staff evaluation of the FAC Program.

On the basis of its review, the staff found that the applicant addressed the aging

effect/mechanism as identified in the GALL Report.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals fo& managing associated aging effects. The staff's review concluded

that the AMR results, which the applicant claimed to be consistent with the GALL Report, are

consistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

ESF components. The applicant provided information concerning its management of the

following aging effects:

* cumulative fatigue damage

* loss of material due to general corrosion

* local loss of material due to pitting and crevice corrosion

" local loss of material due to microbiologically influenced corrosion

" changes in properties due to elastomer degradation

" local loss of material due to erosion

* buildup of deposits due to corrosion

3-172
Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addressed the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in Section 3.2.2.2 of

the SRP-LR. The staff's audit and review report details the staff's audit. The following sections

discuss the staff's evaluation of the aging effects.

3.2.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.2.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

3.2.2.2.2 Loss of Material Due to General Corrosion

The staff reviewed LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2 against the criteria in SRP-LR

Section 3.2.2.2.2.

In LRA Section 3.2.2.2.2.1, the applicant addressed the loss of material due to general

corrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the

One-Time Inspection Program or a combination of the One-Time Inspection Program and Plant

Chemistry Program manages the aging effect.

SRP-LR Section 3.2.2.2.2 states the following:

The management of loss of material due to general corrosion of pumps, valves,

piping, and fittings associated with some of the BWR emergency core cooling

systems (high-pressure coolant injection, reactor core isolation cooling,

high-pressure core spray, low-pressure core spray, low-pressure coolant

injection (residual heat removal)) and with lines to the suppression chamber and

to the drywell and suppression chamber spray system should be further

evaluated. The existing aging management program relies on monitoring and

control of primary water chemistry based on BWRVIP 29 (EPRI TR-103515) for

BWRs to mitigate degradation. However, control of primary water chemistry does

not preclude loss of material due to general corrosion at locations of stagnant

flow conditions. Therefore, verification of the effectiveness of the chemistry

control program should be performed to ensure that corrosion is not occurring.

The GALL Report recommends further evaluation of programs to manage loss of

material due to general corrosion to verify the effectiveness of the chemistry

control program. A one-time inspection of select components at susceptible

locations is an acceptable method to determine whether an aging effect is not

occurring or an aging effect is progressing very slowly such that the component's

intended function will be maintained during the period of extended operation.

In LRA Section 3.2.2.2.2.1, the applicant stated that loss of material due to general corrosion of

piping, fittings, pumps, and valves could occur in the ECCS and will be managed by the

One-Time Inspection Program, or a combination of the One-Time Inspection Program and the

Plant Chemistry Program. The applicant stated that, when applied in combination with the Plant

3-173
Chemistry Program, the scope of the One-Time Inspection Program incorporates activities to

verify the effectiveness of the Plant Chemistry Program, including a sample of components

where the flow of water is low or stagnant conditions exist.

SER Sections 3.0.3.1.4 and 3.0.3.2.19 document the staff's evaluations of the One-Time

Inspection Program and the Plant Chemistry Program, respectively.

The applicant, in the LRA, included some component types subject to general corrosion

(fans/blower housings and turbines) not consistent with the GALL Report; however, the

materials, environments, and aging effects are similar. The staff found that these items will be

properly managed during the period of extended operation. In addition, there are some aging

mechanisms, galvanic corrosion and MIC, covered in LRA Section 3.2.2.2.2, managed by the

One-Time Inspection Program and Plant Chemistry Program not consistent with the GALL

Report. The staff requested that the applicant explain why it added these aging mechanisms.

The applicant responded that these mechanisms could cause the aging effect, loss of material,

and that this approach was conservative. The staff concluded that the applicant had taken a

conservative approach to aging management and was consistent with the GALL Report.

Based on the technical information provided in LRA Section 3.2 and review of the One-Time

Inspection and Plant Chemistry Programs, the staff found that the applicant appropriately

addressed the aging effect/mechanism of loss of material due to general corrosion of pumps,

valves, piping, and fittings associated with some of the ECCSs (HPC, RCI, low-pressure CSP,

LPCI (RHR)) and lines to the suppression chamber and to the drywell and suppression

chamber spray system for components in the ESF systems.

In LRA Section 3.2.2.2.2.2, the applicant addressed the loss of material due to general

corrosion of components in the standby gas treatment and containment isolation systems, and

ECCS. The applicant stated that the One-Time Inspection Program or the System Condition

Monitoring Program manages the aging effect.

SRP-LR Section 3.2.2.2.2.2 states the following:

Loss of material due to general corrosion could occur in the drywell and

suppression chamber spray (BWR) systems header and spray nozzle

components, standby gas treatment system components (BWR), containment

isolation valves and associated piping, the automatic depressurization system

piping and fittings (BWR), emergency core cooling system header piping and

fittings and spray nozzles (BWR), and the external surfaces of BWR carbon steel

components. The GALL Report recommends further evaluation on a

plant-specific basis to ensure that the aging effect is adequately managed.

The applicant stated in LRA Section 3.2.2.2.2.2, that the One-Time Inspection Program and/or

the System Condition Monitoring Program manages the aging effect for an air/gas environment.

The LRA describes the One-Time Inspection Program as a new AMP. The scope of this new

AMP includes activities to verify potential long incubation periods for certain aging effects on

SCs. The environments applicable to this item are characteristic of long incubation periods

(air/gas environments with the potential for moisture). The staff evaluated the One-Time

Inspection Program and found it acceptable for managing the aging effects of loss of material

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due to general corrosion. SER Section 3.0.3.1.4 documents the evaluation of the One-Time

Inspection Program.

The LRA describes the System Condition Monitoring Program as an existing plant-specific

program that manages aging effects for normally accessible, external surfaces of piping, tanks,.

and other components and equipment within the scope of license renewal. The applicant

manages these aging effects through visual inspection and monitoring of external surfaces for

leakage and evidence of material degradation.

The staff considers visual inspection an examination technique capable of detecting loss of

material due to various aging mechanisms (e.g., general or galvanic corrosion) on the exterior

surface of components, and the staff considers an examination frequency of once per year or

per refueling outage adequate for the detection of this effect before the loss of component

function occurs. The staff's review found the System Condition Monitoring Program acceptable

for managing aging of general corrosion during the period of extended operation. SER Section

3.0.3.3.2 documents the evaluation of the System Conditioning Monitoring Program.

The System Conditioning Monitoring Program and One-Time Inspection Program cover aging

management in the drywell and suppression chamber spray, systems header and spray nozzle

components, standby gas treatment system (SGTS) components, containment isolation valves

and associated piping, the automatic depressurization system piping and fittings, ECCS header

piping and fittings and spray nozzles, and the external surfaces of carbon steel components.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.2. For those line items that apply to LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2,

the staff determined that the applicant's AMRs are consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Sections 3.2.2.2.3.1 and 3.2.2.2.3.2 against the criteria in SRP-LR

Section 3.2.2.2.3.

In LRA Section 3.2.2.2.3.1, the applicant addressed the loss of material due to pitting and

crevice corrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that

the One-Time Inspection Program, or the combination of the One-Time Inspection Program and

Plant Chemistry Program, manages the aging effect.

SRP-LR Section 3.2.2.2.3 states the following:

The management of local loss of material due to pitting and crevice corrosion of

pumps, valves, piping, and fittings associated with some of the BWR emergency

core cooling system piping and fittings (high-pressure coolant injection, reactor

core isolation cooling, high-pressure core spray, low-pressure core spray,

low-pressure coolant injection (residual heat removal)) and with lines to the

suppression chamber and to the drywell and suppression chamber spray system

should be evaluated further. The existing aging management program relies on

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monitoring and control of primary water chemistry based on EPRI guidelines of

TR-105714 for PWRs and BWRVIP 29 (EPRI TR-1 03515) for BWRs to mitigate

degradation. However, control of coolant water chemistry does not preclude loss

of material due to crevice and pitting corrosion at locations of stagnant flow

conditions. Therefore, verification of the effectiveness of the chemistry control

program should be performed to ensure that corrosion is not occurring. The

GALL Report recommends further evaluation of programs to manage the loss of

material due to pitting and crevice corrosion to verify the effectiveness of the

chemistry control program. A one-time inspection of select components at

susceptible locations is an acceptable method to determine whether an aging

effect is not occurring or an aging effect is progressing very slowly so that the

component's intended function will be maintained during the period of extended

operation.

In LRA Section 3.2.2.2.3.1, the applicant addressed loss of material due to pitting and crevice

corrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the

One-Time Inspection Program, or the combination of the One-Time Inspection Program and

Plant Chemistry Program, manages the aging effect. When applied in combination with the

Plant Chemistry Program, the scope of the One-Time Inspection Program incorporates

activities to verify the effectiveness of the Plant Chemistry Program, including a sample of

components where the flow of water is low or stagnant conditions exist. Implementation of the

One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect

provides added assurance that the aging effect is not occurring or that the aging effect is

progressing very slowly, such that the component's intended function will be maintained during

the period of extended operation.

As documented in the audit and review report, the applicant stated that in some instances, the

component within the scope of license renewal has an environment that does not lend itself to

benefits from the Plant Chemistry Program (low-flow stagnant conditions, or an air/gas

environment). The staff determined that the use of the One-Time Inspection Program alone in

certain cases, such as no-flow conditions, in which the use of the Plant Chemistry Program is

not a viable option, is acceptable. The staff concluded, based on MNGP technical procedures,

that this is an appropriate aging management method based on the details of the program's

sampling locations, frequencies, and corrective actions.

The applicant uses the One-Time Inspection Program, or the combination of the One-Time

Inspection Program and the Plant Chemistry Program, to manage the aging effect/mechanism

of loss of material due to pitting and crevice corrosion for areas of stagnant flow. The staff

evaluated the One-Time Inspection Program and Plant Chemistry Program, as documented in

SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively.

The staff reviewed the applicant's programs credited for aging management for the materials,

environment, and aging effects/mechanisms. The pumps, valves, piping, and fittings associated

with some of the BWR ECCS piping and fittings (HPC, RCl, low-pressure CSP, LPCI (RHR))

and with lines to the suppression chamber and to the drywell and suppression chamber spray

system are subject to local loss of material due to pitting and crevice corrosion. The One-Time

Inspection Program or the combination of the Plant Chemistry Program and the One-Time

Inspection Program manages the aging effects.

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In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material due to pitting and crevice

corrosion of components in the standby gas treatment and containment isolation systems, and

ECCS. The applicant stated that the One-Time Inspection Program, or the combination of the

One-Time Inspection Program and Plant Chemistry Program, manages the aging effect.

SRP-LR Section 3.2.2.2.3.2 states the following:

Local loss of material from pitting and crevice corrosion could occur in the

containment isolation valves and associated piping, and automatic

depressurization system piping and fittings (BWR). The GALL Report

recommends further evaluation to ensure that the aging effect is adequately

managed.

In LRA Section 3.2.2.2.3.2, the applicant stated that the One-Time Inspection Program is a new

AMP. The scope of this new AMP will include activities to verify potential long incubation

periods for certain aging effects on SCs. The environments applicable to this item are

characteristic of long incubation periods (air/gas environments with the potential for moisture).

This program is sometimes used by itself in locations where the Plant Chemistry Program will

not be effective (such as air/gas or low-flow/stagnant environments). The staff determined that

the use of the One-Time Inspection Program alone in certain cases, such as no-flow conditions,

in which the use of the Plant Chemistry Program is not a viable option, is acceptable.

The staff evaluated the Plant Chemistry and One-Time Inspection Programs and found them

acceptable for managing the aging effect of local loss of material from pitting and crevice

corrosion that could 'occur in the containment isolation valves and associated piping, and ADS

piping and fittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluation of the

Plant Chemistry Program and One-Time Inspection Program, respectively.

The staff evaluated both of these AMPs with respect to applications to the materials,

environment, and aging effects. The applicant included an additional aging mechanism

(galvanic corrosion) not consistent with the GALL Report (Sections V.C.1-a/b, V.D2.1-e). The

staff determined that the applicant used a conservative approach for aging management by

including this additional aging mechanism, and that this is consistent with the GALL Report for

the aging effect.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.3. For those line items that apply to LRA Sections 3.2.2.2.3.1 and 3.2.2.2.3.2,

the staff determined that the applicant's AMRs are consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced Corrosion

The staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4.

In LRA Section 3.2.2.2.4, the applicant addressed loss of material due to MIC of valves and

associated piping in containment isolation.

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SRP-LR Section 3.2.2.2.4 states the following:

Local loss of material due to microbiologically influenced corrosion (MIC) could

occur in BWR and PWR containment isolation valves and associated piping in

systems that are not addressed in other chapters of the GALL Report. The GALL

Report recommends further evaluation to ensure that the aging effect is

adequately managed.

Although the applicant does not use this line item at MNGP, the loss of material due to MIC is

predicted for ESF system valve bodies and associated piping. The applicant credited a

combination of the Plant Chemistry Program and the One-Time Inspection Program for the

aging effect. The staff evaluated the Plant Chemistry Program and One-Time Inspection

Program and found them acceptable for managing aging of local loss of material from MIC that

could occur in the containment isolation valves and associated piping, and ADS piping and

fittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the evaluation of the Plant Chemistry

Program and One-Time Inspection Program, respectively.

The applicant's LRA is consistent with the GALL Report (Section V.C. 1 -a/b) for components,

materials, environment, and programs for managing aging for the containment isolation valves.

Based on the information provided by the applicant, as noted in the LRA, the staff's review and

audit found that the applicant's AMPs are acceptable for management of loss of material due to

MIC for the containment isolation valves and associated piping.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.4. For those line items that apply to LRA Section 3.2.2.2.4, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.5 Changes in Properties Due to Elastomer Degradation

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.

In LRA Section 3.2.2.2.5, the applicant addressed the change in material properties of seals in

the SGTS. The applicant stated that the One-Time Inspection Program manages the aging

effect for the internal environment and the System Condition Monitoring Program manages it for

the external environment. The System Condition Monitoring Program is an existing

plant-specific program.

SRP-LR Section 3.2.2.2.5 states the following:

Changes in properties due to elastomer degradation could occur in seals

associated with the standby gas treatment system ductwork and filters. The

GALL Report recommends further evaluation to ensure that the aging effect is

adequately managed.

The One-Time Inspection Program is a new AMP, the scope of which includes activities to

verify potential long incubation periods for certain aging effects on SCs. The environments

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applicable to this item are characteristic of long incubation periods (high-temperature air or

ozone). The staff evaluated the One-Time Inspection Program and found it acceptable and

consistent with the GALL Report for managing this aging effect. SER Section 3.0.3.1.4

documents the evaluation of the One-Time Inspection Program.

The System Condition Monitoring Program is an existing plant-specific program that is based

on system engineer monitoring, and it is used to manage the aging effect/mechanisms on

system components in the ESF, including elastomer degradation of seals in the SGTS ductwork

and filters. The staff reviewed the System Condition Monitoring Program and found it

acceptable and consistent with the GALL Report for managing this aging effect/mechanism.

SER Section 3.0.3.3.2 documents the evaluation of the System Condition Monitoring Program.

The staff reviewed the applicant's use of the One-time Inspection Program and System

Condition Monitoring Program (which is periodic) and determined that it is acceptable and

consistent with the GALL Report (Sections V.B.1-b, V.B.2-b) as the programs will verify the

condition of the elastomer seals and provide reasonable assurance that hardening and cracking

do not occur. The staff found that the materials, environment, aging effects, and the aging

programs are consistent with the GALL Report. The applicant manages these aging effects

through visual inspection of internal surfaces and monitoring of external surfaces for leakage

and evidence of material degradation.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.5. For those line items that apply to LRA Section 3.2.2.2.5, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.6 Local Loss of Material Due to Erosion

The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.

In LRA Section 3.2.2.2.6, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.2.2.2.6 states that local loss of material due to erosion could occur in the

high-pressure safety injection pump miniflow orifice. SRP-LR Table 3.2-1 states that further

evaluation for this aging effect is for PWR plants only.

The staff found this aging effect not applicable.

3.2.2.2.7 Buildup of Deposits Due to Corrosion

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

In LRA Section 3.2.2.2.7, the applicant addressed plugging of nozzles and flow orifices in the

drywell and suppression chamber spray system due to general corrosion. The drywell and

suppression chamber spray system nozzles are fabricated from copper alloy materials, which

are not susceptible to loss of material (plugging of nozzles and flow orifices) due to general

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corrosion; therefore, no aging management is required. The associated GALL Report line item

(Section V.D2.5-b) does not evaluate copper alloy material.

SRP-LR Section 3.2.2.2.7 states the following:

The plugging of components due to general corrosion could occur in the spray

nozzles and flow orifices of the drywell and suppression chamber spray system.

This aging mechanism and effect will apply since the spray nozzles and flow

orifices are occasionally wetted, even though the majority of the time this system

is on standby. The wetting and drying of these components can aid in the

acceleration of this particular corrosion. The GALL Report recommends further

evaluation to ensure that the aging effect is adequately managed.

The staff reviewed the GALL Report (Section V.D2.5-b), which addresses only carbon steel in

an air environment for drywell suppression chamber spray systems. The materials at MNGP are

made of copper in an air/potential water environment, which the GALL Report does not

address. After reviewing documentation from the GALL Report for aging effects, materials, and

environments, the staff concurred that these nozzles are not subject to aging effects in the

environments listed according to material science evaluations (as noted below) and, therefore,

are not susceptible to corrosion product buildup that could cause plugging.

As shown in the Metals Handbook, Ninth Edition, Volume 13, "Corrosion," comprehensive tests

over a 20-year period under the supervision of ASTM confirmed the suitability of copper alloys

for atmospheric exposure. Additionally, the gaseous internal environments to which

components within the scope of license renewal may be subject include air, nitrogen, carbon

dioxide, freon, and halon. Industry experience suggests that copper piping exposed to an

internal gaseous operating condition will be resistant to any age-related degradation; therefore,

the SC will remain capable of performing intended functions consistent with the CLB for the

period of extended operation.

On the basis of its review of current industry research and operating experience, the staff found

that effects of the listed environments on the listed materials will not cause aging of concern

during the period of extended operation; therefore, the staff concluded that there are no

applicable AERMs for the component material and environment described in the preceding

discussion.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.2.2.2.7. For those line items that apply to LRA Section 3.2.2.2.7, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the issues that were further evaluated. The staff found that the applicant has

demonstrated that the effects of aging will be adequately managed so that intended functions

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will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-8,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report, and provided information concerning the management of the

aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material

for the AMR line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination is not applicable. Note J

indicates that the GALL Report evaluates neither the component nor the material and

environment combination for the line item.

Staff Evaluation. For component type, material, and environment combinations that the GALL

Report does not evaluate, the staff reviewed the applicant's evaluation to determine whether the

applicant had demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation. The following sections discuss the staff's evaluation.

In LRA Tables 3.2.2-1 through 3.2.2-8, the staff identified AMR line items for which the

applicant stated that there were no aging effects as a result of the AMR process. In most

instances, the applicant identified materials that have no aging effects in the environments they

are exposed to during plant operations. The applicant stated that no aging effects occur for

ESF system components fabricated from the following materials:

* copper

* carbon steel

" nickel alloy

* stainless steel

* CASS

* insulation

These materials are exposed to the following environments:

* plant indoor air (external/internal)

* primary containment air (external/internal)

* air/gas (internal)

* gas-instrument air (internal)

* gas-nitrogen (internal)

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* lubricating oil (external/internal)

" outdoor air protected

The applicant stated that components fabricated from these materials in these environments

have no aging effects based on material science evaluations of these materials exposed to

atmospheric conditions. Specifically, the applicant stated that no aging effects occur when

components fabricated from stainless steel material are exposed to a primary containment air,

plant indoor air (and outdoor air protected), lubricating oil, or gas (instrument air) environment,

or when components fabricated from copper alloys are exposed to a primary containment air,

plant indoor air, lubricating oil, or gas (instrument air) environment. The applicant also stated

that no aging effects occur in components fabricated from carbon steel in a gas (nitrogen or

instrument air) or lubricating oil environment. In addition, the applicant stated that no aging

effects occur in components fabricated from CASS or nickel alloys in a primary containment air

or plant indoor air environment. The applicant stated that a material science evaluation for

these materials in these environments found no aging effects.

The GALL Report states that steel, copper, nickel alloy, and stainless steel in an environment of plant indoor air (external), gas, and lubricating oil are not subject to any aging mechanisms.

The staff reviewed this technical information against LRA Tables 3.2.2-1 through 3.2.2-8 and

concluded that the applicant's analysis of the material and environment combinations will allow

components within the scope of license renewal fabricated from these materials in these

environments to perform their intended functions through the period of extended operation. This

conclusion is based on industry and plant operating experience of these components in these

environments.

As cited in Metals Handbook, Ninth Edition, Volume 13, stainless steels are highly resistant to

corrosion in dry atmospheres in the absence of corrosive species; therefore, stainless steel in

an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment (e.g.,

primary containment air inerted with nitrogen) exhibits no aging effect, and such an SC will

remain capable of performing intended functions consistent with the CLB for the period of

extended operation. Because both oxygen and moisture must be present to corrode steel, as

cited in Metals Handbook, Ninth Edition, steel (carbon or stainless) and copper alloys in a

lubricating oil internal environment with no water pooling exhibit no aging effect, and such an

SC will therefore remain capable of performing intended functions consistent with the CLB for

the period of extended operation. Because components fabricated from CASS, copper, and

nickel alloys are highly resistant to corrosion in dry atmospheres in the absence of corrosive

species, as cited in the Metals Handbook, Ninth Edition, the staff accepted the position that

CASS, copper, and nickel alloys in an indoor (primary containment), uncontrolled air

environment (e.g., plant indoor air), or gas environment (e.g., plant instrument air) exhibit no

aging effect, and such SCs will therefore remain capable of performing intended functions

consistent with the CLB for the period of extended operation.

LRA Tables 3.2.2.4 and 3.2.2.7 list insulation for piping and heat exchangers in the HPC and

RHR systems exposed to plant indoor air. LRA Section 3.2.1 states that the GALL Report does

not show this material for this component as subject to aging management.

The staff reviewed technical information based on industry experience and concluded that the

applicant's analysis of the material and environment is acceptable, and insulation exposed to

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plant indoor air will remain capable of performing its intended function during the period of

extended operation.

The staff reviewed the materials and environments for this section and compared this

information with the technical references noted above. Except for carbon steel in outdoor air,

the ESF components fabricated from carbon steel, nickel alloy, stainless steel, CASS, and

insulation subject to plant indoor air (external/internal), primary containment air

(external/internal), air/gas (internal), gas (instrument air/nitrogen), lubricating oil

(external/internal), or outdoor air are not subject to aging effects/mechanisms.

On the basis of its review of current industry research and operating experience, the staff found

that the listed materials in the listed environments will not experience aging effects of concern

during the period of extended operation; therefore, the staff concluded that there are no

applicable AERMs for the component material and environment described in the preceding

discussion.

3.2.2.3.1 Engineered Safety Features-Automatic Pressure Relief System-Summary of

Aging Management Evaluation-Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the

automatic pressure relief system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.2.2.3 above.

3.2.2.3.2 Engineered Safety Features-Combustible Gas Control System-Summary of Aging

Management Evaluation-Table 3.2.2-2

In its letter dated March 15, 2006, the applicant stated that it deactivated the CGC system by

cuffing and capping process lines connecting to interfacing systems during the 2005 refueling

outage because of NRC approval of License Amendment 138, which eliminated the

requirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen

monitoring. Therefore, the system has been removed from the scope of license renewal.

3.2.2.3.3 Engineered Safety Features-Core Spray System-Summary of Aging Management

Evaluation-Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the

CSP system component groups.

In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to crevice

corrosion, MIC, and pitting corrosion of copper alloys for ESF heat exchangers exposed to a

raw water environment using the Open-Cycle Cooling Water Program.

The OCCW System Program relies on the implementation of the recommendations of GL 89-13

to ensure that the effects of aging on the raw water service water systems will be managed for

the period of extended operation. This program manages the aging effects of metallic

components in water systems (e.g., piping and heat exchangers) exposed to raw, untreated

(e.g., service) water. The staff reviewed the OCCW System Program and found it to be

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acceptable and consistent with the GALL Report. SER Section 3.0.3.1.5 documents the

evaluation of the OCCW System Program. The staff determined that this AMP is adequate for

managing this material, environment, and aging effect.

In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to selective

leaching of copper alloys for ESF heat exchangers in a raw water environment using the

Selective Leaching of Materials Program.

The staff reviewed the applicant's Selective Leaching of Materials Program, and SER

Section 3.0.3.2.22 documents its evaluation. This new program includes a one-time visual

inspection and hardness measurement of certain components susceptible to selective leaching.

The program will determine if selective leaching occurs for certain components. The staff

determined that this AMP is adequate for managing this material, environment, and aging

effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the aging effect of loss of material due

to crevice corrosion, MIC, and pitting corrosion and loss of material due to selective leaching of

copper alloys for ESF heat exchangers exposed to raw water environment in LRA Table 3.2.2-3

are effectively managed using the OCCW System Program and the Selective Leaching of

Materials Program, respectively.

3.2.2.3.4 Engineered Safety Features-High-Pressure Coolant Injection System-Summary

of Aging Management Evaluation-Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the

HPC system component groups.

In LRA Table 3.2.2-4, the applicant proposed to manage heat transfer degradation and fouling

of heat exchangers fabricated from copper alloy in lubricating oil (external)/treated water

(internal) environments with the One-Time Inspection Program, and in steam (external)/treated

water (internal) environments using the Plant Chemistry Program combined with the One-Time

Inspection Program. The applicant also proposed to manage the loss of material due to crevice

corrosion and pitting corrosion of heat exchangers fabricated from copper alloy in steam

(external)/treated water (internal) environments, and MIC in a treated water (internal)

environment using the Plant Chemistry Program, combined with the One-Time Inspection

Program.

The staff reviewed the applicant's Plant Chemistry Program and the One-Time Inspection

Program, and SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document its evaluation of

each. The Plant Chemistry Program mitigates the aging effects on component surfaces

exposed to water as the process fluid; chemistry programs are used to control water chemistry

for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth

or that cause heat transfer degradation due to fouling in select heat exchangers. This program

relies on monitoring and control of water chemistry to keep peak levels of various contaminants

below system-specific limits. The new One-Time Inspection Program is consistent with the

recommendations of GALL AMP XI.M32. This program will include measures to verify the

effectiveness of the Plant Chemistry Program. This program will also confirm the absence of

age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping)

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within the scope of license renewal. The One-Time Inspection Program addresses concerns

and provides confirmation for the potential long incubation period for certain aging effects on

SCs. If system contaminants are maintained within the limits specified by the Plant Chemistry

Program, the corrosion exhibited by the copper alloy in a closed system is adequately

managed. The applicant has chosen a different combination of AMPs to manage the AERM.

The staff found this combination adequate and acceptable for managing this material,

environment, and aging effect, because contaminants are maintained within limits to inhibit

corrosion of the copper alloy.

The staff's review of LRA Section 3.2 identified areas for which it needed additional information

to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs

as discussed below.

In RAI 3.2-1, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant stated

that it would manage heat transfer degradation due to fouling of heat exchangers fabricated

from copper alloy in a lubricating oil environment using the One Time Inspection Program. On

the basis of the staff's review of the information provided in the LRA, it was not clear what

preventive measures the applicant was taking to ensure that the lubricating oil remains free of

contaminants that might degrade the tubing.. Therefore, the staff requested that the applicant

provide the following:

a) Specific material composition of the copper alloys.

b) A description of the oil analysis program and/or other methods to ensure that

the lubricating oil remains free of contaminants which might degrade the

tubing.

c) PM procedures to ensure that heat transfer degradation does not reach

unacceptable levels.

In its response, by letter dated August 16, 2005, the applicant stated the following:

a) The High Pressure Coolant Injection System (HPC) lubricating oil

cooler (E-206) is an American Standard (Whitlock) cooler of carbon steel

construction with 5/8" O.D. Admiralty tubes in accordance with the vendor's

technical manual. Admiralty brass is composed of 71Cu-28Zn-1Sn.

b) Lube oil samples from the HPC lube oil cooler are obtained every six months

in accordance with MNGP site procedures, and the sample results are

evaluated and trended. These parameters include iron, copper, etc. for

indications of wear, dielectric, viscosity, etc. for chemical analysis and water,

silicon, etc. for indication of contamination. Sampling is performed lAW

EPRI 1007459 (November 2002) for the HPC lube oil cooler. Electric Power

Research Institute (EPRI) Report 1007459 recommends that 'oil moisture

content be verified on a monthly basis and that acidity, viscosity, and particle

count be verified each quarter until a data trending program can justify

extending the inspection frequency.' This frequency, based upon data

trending results, was extended to a six-month frequency. Any indication of an

anomalous condition or adverse trend will result in an investigation under the

site corrective action program. All results have been acceptable to date to

3-185
ensure that the lubricating oil remains free of contaminants that could

potentially degrade the heat exchanger (cooler) tubes, with the last sample

taken and evaluated in March 2005.

c) Preventive maintenance procedures are in effect to both clean and inspect

the HPC lube oil cooler and perform eddy current testing every three cycles.

Eddy current testing was last performed in January 2000 on the originally

installed cooler. All tubes were inspected. No tubes required plugging and no

unacceptable defects were detected.

Based on its review, the staff found the applicant's response to RAI 3.2-1 acceptable because

the lube oil coolers are monitored and tested in accordance with industry standards and NRC

guidelines. In addition, the applicant's operational experience supports the adequacy of its

maintenance practices; therefore, the staff's concern described in RAI 3.2-1 is resolved.

In RAI 3.2-2, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant stated

that it will manage heat transfer degradation due to fouling of the copper alloy heat exchanger

tubes in a steam environment with the Plant Chemistry and One-Time Inspection Programs.

The applicant further stated that the GALL Report does not evaluate either the components or

the material and environment combination; therefore, the staff requested that the applicant

verify that the steam in the heat exchangers identified above originated from treated water. In

addition, the staff requested the applicant to justify not considering erosion and FAC as aging

mechanisms for this material and environment combination.

In its response, by letter dated August 16, 2005, the applicant stated the following:

Per LRA 2.3.2.4, High Pressure Coolant Injection (HPC) System, 'The HPC

turbine is driven with steam from the RPV. Two sources of water are available for

the HPC System. Normally, water is supplied to the suction of the HPC pump

from the two condensate storage tanks (CST). When the level in either CST falls

to the predetermined setpoint, the pump suction is automatically transferred to

the suppression pool.' The HPC heat exchanger in question is the HPC Gland

Seal Condenser, E-204, which condenses the gland seal steam from the HPC

turbine by using cooling water from the discharge of the HPC pump. Therefore,

the steam in this heat exchanger is produced by the treated water in the RPV.

EPRI NSAC 202L, R2, 'Recommendations for an Effective Flow-Accelerated

Corrosion (FAC) Program,' page 4-3, allows an exclusion from FAC for systems

which operate less than 2% of the time, which would be applicable to this HPC

condenser. In addition, this component is not subject to high velocity, constricted

flow, or fluid direction changes. Therefore, in accordance with EPRI 1003056,

'Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,'

Revision 3, loss of material due to erosion or FAC are not potential aging

mechanisms.

Based on its review, the staff found the applicant's response to RAI 3.2-2 acceptable because

the applicant provided satisfactory explanations of the purity of the steam environment and the

absence of erosion and FAC as aging mechanisms for the heat exchanger in question;

therefore, the staff's concern described in RAI 3.2-2 is resolved.

3-186
In LRA Table 3.2.2-4, the applicant proposed to manage the loss of material due to selective

leaching of heat exchangers fabricated from copper alloy in a steam (external)/treated water

(internal) environment with the Selective Leaching of Materials Program.

The staff reviewed the applicant's Selective Leaching of Materials Program, and SER

Section 3.0.3.2.22 documents its evaluation. This new program includes a one-time visual

inspection and hardness measurement of selected components susceptible to selective

leaching. The program will determine if selective leaching occurs for selected components. The

staff found this program adequate for managing this material, environment, and aging effect.

3.2.2.3.5 Engineered Safety Features-Primary Containment Mechanical System-Summary

of Aging Management Evaluation-Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the

primary containment mechanical system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.2.2.3 above.

3.2.2.3.6 Engineered Safety Features-Reactor Core Isolation Cooling System-Summary of

Aging Management Evaluation-Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the

RCI system component groups.

In LRA Table 3.2.2-6, the applicant proposed to manage heat transfer degradation and fouling

of heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with

the One-Time Inspection Program, and in a treated water (internal) environment with the Plant

Chemistry Program, combined with the One-Time Inspection Program. The applicant also

proposed to manage the loss of material due to crevice corrosion, pitting corrosion, and MIC of

heat exchangers fabricated from copper alloy in a treated water (internal) environment with the

Plant Chemistry Program, combined with the One-Time Inspection Program.

The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-Time

Inspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.

The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to

water as the process fluid; chemistry programs are used to control water chemistry for

impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth or

that cause heat transfer degradation due to fouling in select heat exchangers. This program

relies on monitoring and control of water chemistry to keep peak levels of various contaminants

below system-specific limits. The new One-Time Inspection Program is consistent with the

recommendations of GALL AMP XI.M32. This program will include measures to verify the

effectiveness of the Plant Chemistry Program. This program will also confirm the absence of

age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping)

within scope of license renewal. The One-Time Inspection Program addresses concerns and

provides confirmation for the potential long incubation period for certain aging effects on SCs. If

system contaminants are maintained within the limits specified by the Plant Chemistry Program,

the corrosion exhibited by the copper alloy in a closed system is adequately managed. The

applicant has chosen a different combination of AMPs to manage the AERM. The staff found

3-187
this combination adequate and acceptable for managing this material, environment, and. aging

effect, because contaminants are maintained within limits to inhibit corrosion of the copper

alloy.

The response to RAI 3.2-1, discussed in SER Section 3.2.2.3.4, is generally applicable to the

copper alloy components of the heat exchangers in the RCI system.

The staff found the applicant's response reasonable and acceptable because the lube oil

coolers are monitored and tested in accordance with industry standards and NRC guidelines. In

addition, the applicant's operational experience supports the adequacy of its maintenance

practices.

In LRA Table 3.2.2-6, the applicant proposed to manage the loss of material due to selective

leaching of heat exchangers fabricated from copper alloy in a treated water (internal)

environment using the Selective Leaching of Materials Program.

The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, as

documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection

and hardness measurement of certain components susceptible to selective leaching. The

program will determine if selective leaching occurs for certain components. The staff found this

program adequate and acceptable for managing this material, environment, and aging effect.

3.2.2.3.7 Engineered Safety Features-Residual Heat Removal System-Summary of Aging

Management Evaluation-Table 3.2.2-7

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the

RHR system component groups.

In LRA Table 3.2.2-7, the applicant proposed to manage heat transfer degradation and fouling

of heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with

the One-Time Inspection Program, and in a raw water (internal) environment using the

Open-Cycle Cooling Water System Program. The applicant also proposed to manage the loss

of material due to crevice corrosion, MIC, and pitting corrosion of heat exchangers fabricated

from copper alloy in a raw water (internal) environment using the Open-Cycle Cooling Water

System Program.

The staff reviewed and evaluated the applicant's One-Time Inspection Program, as

documented in SER Section 3.0.3.1.4. The new One-Time Inspection Program, consistent with

the recommendations of GALL AMP XI.M32, will confirm the absence of age degradation in

selected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of

license renewal. The One-Time Inspection Program addresses-concerns and provides

confirmation for the potential long incubation period for certain aging effects on SCs.

The OCCW System Program relies on the implementation of the recommendations of GL 89-13

to ensure that the effects of aging on the raw water service water systems will be managed for

the period of extended operation. This program manages the aging effects of metallic

components in water systems (e.g., piping and heat exchangers) exposed to raw, untreated

(e.g., service) water. The staff reviewed the OCCW System Program and found it acceptable

and consistent with the GALL Report. SER Section 3.0.3.1.5 documents the evaluation of the

3-188
OCCW System Program. The staff has found this AMP adequate and acceptable for managing

this material, environment, and aging effect.

In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to MIC,

crevice corrosion, and pitting corrosion of RHR nozzles fabricated from copper alloy in a treated.

water (internal) environment with the Plant Chemistry Program, combined with the One-Time

Inspection Program.

The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-Time

Inspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.

The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to

water as the process fluid; chemistry programs are used to control water chemistry for

impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth, or

that cause heat transfer degradation due to fouling in select heat exchangers. This program

relies on monitoring and control of water chemistry to keep peak levels of various contaminants

below system-specific limits.

The new One-Time Inspection Program, consistent with the recommendations of GALL AMP

XI.M32, will include measures to verify the effectiveness of the Plant Chemistry Program and

will also confirm the absence of age degradation in selected components (e.g., flow restrictors,

venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection

Program addresses concerns and provides confirmation for the potential long incubation period

for certain aging effects on SCs. If system contaminants are maintained within the limits

specified by the Plant Chemistry Program, the corrosion exhibited by the copper alloy in a

closed system is adequately managed. The applicant has chosen a different combination of

AMPs to manage the AERM. The staff found this combination adequate and acceptable for

managing this material, environment, and aging effect, because contaminants are maintained

within limits to inhibit corrosion of the copper alloy.

In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to selective

leaching of heat exchangers fabricated from copper alloy in a raw water (internal) environment,

and RHR nozzles fabricated from copper alloy in a treated water (internal) environment with the

Selective Leaching of Materials Program.

The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, as

documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection

and hardness measurement of certain components susceptible to selective leaching. Because

the program will determine if selective leaching occurs for certain components, the staff found

this AMP adequate and acceptable for managing this material, environment, and aging effect.

In LRA Table 3.2.2-7, the applicant contends that no aging effects are associated with thermal

insulation installed on heat exchangers and exposed to an indoor plant air environment. The

staff concurred with the applicant's assessment and found the applicant's routine maintenance

practices adequate to maintain the thermal insulation of the RHR heat exchangers effectively.

3-189
3.2.2.3.8 Engineered Safety Features-Secondary Containment System-Summary of Aging

Management Evaluation-Table 3.2.2-8

The staff reviewed LRA Table 3.2.2-8, which summarizes the results of AMR evaluations for the

secondary containment system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.2.2.3 above.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERMs, and AMP combinations that are not

evaluated in the GALL Report. The staff found that the applicant has demonstrated that the

effects of aging will be adequately managed so that intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.2.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the ESF components that are within the scope of license renewal and

subject to an AMR will be adequately managed so. that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the ESF, as required by

10 CFR 54.21 (d).

3.3 Aaing Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups associated with the following systems:

" alternate nitrogen system

* chemistry sampling system

* circulating water system

* control rod drive system * demineralized water system

* emergency diesel generators system

" emergency filtration train system

* emergency service water system

" fire system

* fuel pool cooling and cleanup system

* heating and ventilation system

* instrument and service air system

* radwaste solid and liquid system

* reactor building closed cooling water system

* .reactor water cleanup system

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* service and seal water system

* standby liquid control system

* wells and domestic water system

3.3.1 Summary of Technical Information in the Application

In LRA Section 3.3, the applicant provided AMR results for the auxiliary systems components

and component groups. In LRA Table 3.3.1 ,the applicant provided a summary comparison of its

AMRs with the AMRs evaluated in the GALL Report for the auxiliary systems components and

component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the auxiliary systems components that are within the

scope of license renewal and subject to an AMR will be adequately managed so that intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA is applicable and that the applicant identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, which is summarized in SER

Section 3.3.2.1.

The staff also performed an onsite audit of those selected AMRs that were consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations were consistent with the acceptance criteria in Section 3.3.2.2 of

the SRP-LR. The staff's audit evaluations are documented in the MNGP audit and review report

and are summarized in SER Section 3.3.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified all plausible aging effects and

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The MNGP audit and review report documents the staff's audit

evaluations. SER Section 3.3.2.3 summarizes the staff's audit evaluations and documents its

technical review.

3-191
Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

auxiliary systems components.

Table 3.3-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.3 that are addressed in the GALL Report.

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report

Components in

spent fuel pool

cooling and cleanup

(Item Number

3.3.1-01)

Loss of material

due to general, pitting, and crevice

corrosion

One-Time

Inspection Program

(B2.1.23), Plant

Chemistry Program

(B2.1.25)

Consistent with

GALL, which

recommends further

evaluation (see

Section 3.3.2.2.1)

Linings in spent fuel Hardening, cracking Plant specific Not applicable (see

pool cooling and and loss of strength Section 3.3.2.2.2)

cleanup system, due to elastomer

seals and collars in degradation; loss of

ventilation systems material due to

(Item Number wear

3.3.1-02)

Components in load Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

handling, chemical damage accordance with evaluated in Section

and volume control 10 CFR 54.21 (c) 4.3, Metal Fatigue

system (PWR), and of the RPV and

reactor water Intemals, and

cleanup and Reactor Coolant

shutdown cooling Pressure Boundary

systems (older Piping and

BWR) Components and

(Item Number Section 4.9,

3.3.1-03) Reactor Building

Crane Load Cycles

Heat exchangers in Crack initiation and Plant specific Not applicable (see

reactor water growth due to SCC Section 3.3.2.2.4)

cleanup system or cracking

(BWR); high

pressure pumps in

chemical and

volume control

system (PWR)

(Item Number

3.3.1-04)

3-192
Component Group~ Aging Effect/ AMP IdGALL 'AM In LRA Staff Evaluation - Mechanism' Reot'~_______

Components in Loss of material Plant specific Fire Protection Consistent with

ventilation systems, due to general, Program (B2.1.17), GALL, which

diesel fuel oil pitting, and crevice Fire Water System recommends further

system, and corrosion, and MIC Program (B2.1.18), evaluation (see

emergency diesel One-Time Section 3.3.2.2.5)

generator systems; Inspection Program

external surfaces of (B2.1.23), System

carbon steel Condition Monitoring

components Program (B2.1.32)

(Item Number

3.3.1-05)

Components in Loss of material One-time Not applicable (see

reactor coolant due to galvanic, inspection Section 3.3.2.2.6)

pump oil collect general, pitting, and

system of fire crevice corrosion

protection

(Item Number

3.3.1-06)

Diesel fuel oil tanks Loss of material Fuel oil chemistry, Fuel Oil Chemistry Consistent with

in diesel fuel oil due to general, one-time inspection Program (B2.1.20), GALL, which

system and pitting, and crevice One-Time recommends further

emergency diesel corrosion, MIC, and Inspection Program evaluation (see

generator system biofouling (B2.1.23) Section 3.3.2.2.7)

(Item Number

3.3.1-07)

Piping, pump Loss of material Water chemistry, Compressed Air Consistent with

casing, and valve due to pitting and one-time inspection Monitoring Program GALL, which

body and bonnets in crevice corrosion (B2.1.14), One-Time recommends further

shutdown cooling Inspection Program evaluation (see

system (older BW R) (82.1.23), Plant Section 3.3.2.2.1)

(Item Number Chemistry Program

3.3.1-08) (B2.1.25)1_

Heat exchangers in Crack initiation and Water-chemistry Not applicable,

chemical and growth due to SCC and a plant-specific PWR only

volume control and cyclic loading verification program

system

(Item Number

3.3.1-09)

Neutron-absorbing Reduction of Plant specific One-Time Consistent with

sheets in spent fuel neutron-absorbing Inspection Program GALL, which

storage racks capacity and loss of (B2.1.23), Plant recommends further

(Item Number material due to Chemistry Program evaluation (see

3.3.1-10) general corrosion (B2.1.25) Section 3.3.2.2.10)

(boral, boron steel)

New fuel rack Loss of material Structures None Not applicable

assembly due to general, monitoring

(Item Number pitting, and crevice

3.3.1-11) corrosion

3-193
Component Gr'ouq u AgingEffect/ 'AMP In GA4 .LL AMP In LRA Staff Evaluation-

.2 . Mechan ism Re6port ______________ ____________

Neutron-absorbing Reduction of Boraflex monitoring Not applicable;

sheets in spent fuel neutron-absorbing Boraflex is not used

storage racks capacity due to at MNGP

(Item Number Boraflex

3.3.1-12) degradation

Spent fuel storage Crack initiation and Water chemistry Plant Chemistry Consistent with

racks and valves in growth due to stress Program (B2.1.25) GALL Report, which

spent fuel pool corrosion cracking recommends no

cooling and cleanup further evaluation

(Item Number

3.3.1-13)

Closure bolting and Loss of material Boric acid corrosion Not applicable.

external surfaces of due to boric acid Loss of material

carbon steel and corrosion due to boric acid

low-alloy steel corrosion is not

components applicable since

(Item Number MNGP is a BWR3.3.1-14) type facility that

does not use boric

acid

Components in or Loss of material Closed-cycle Closed-Cycle Consistent with

serviced by due to general, cooling water Cooling Water GALL Report, which

closed-cycle cooling pitting, and crevice system System Program recommends no

water system corrosion, and MIC (B2.1.13), One-Time further evaluation

(Item Number Inspection Program

3.3.1-15) (B2.1.23)

Cranes including Loss of material Overhead heavy Inspection of Consistent with

bridge and trolleys due to general load and light load Overhead Heavy GALL Report, which

and rail system in corrosion and wear handling systems Load and Light Load recommends no

load handling (Related to further evaluation

system Refueling) Handling

(Item Number Systems Program

3.3.1-16) (B2.1.22)

Components in or Loss of material Open-cycle cooling One-Time Consistent with

serviced by due to general, water system Inspection Program GALL Report, which

open-cycle cooling pitting, crevice, and (B2.1.23), recommends no

water systems galvanic corrosion, Open-Cycle Cooling further evaluation

(Item Number MIC, and biofouling; Water System

3.3.1-17) buildup of deposit Program (B2.1.24)

due to biofouling

Buried piping and Loss of material Buried piping and Bolting Integrity Consistent with

fittings due to general, tanks surveillance Program (B2.1.4), GALL Report, which

(Item Number pitting, and crevice Buried Piping & recommends no

3.3.1-18) corrosion, and MIC or Tanks Inspection further evaluation

Program (B2.1.5)

Buried piping and

tanks inspection

3-194
C6miponent Group; Aging Effect -AMP I GALL AMP I n LRA7 StaffEvaluation

______________ Mechianism ~ 'Re'pot4-

Components in Loss of material Compressed air Compressed Air Consistent with

compressed air due to general and monitoring Monitoring Program GALL Report, which

system pitting corrosion (12.1.14) recommends no

(Item Number further evaluation

3.3.1-19)

Components (doors Loss of material Fire protection Fire Protection Consistent with

and barrier due to wear; Program (12.1.17) GALL Report, which

penetration seals) hardening and recommends no

and concrete shrinkage due to further evaluation

.structures in fire weathering

protection

(Item Number

3.3.1-20)

Components in Loss of material Fire water system Fire Protection Consistent with

water-based fire due to general, Program (B2.1.17), GALL Report (see

protection pitting, crevice, and Fire Water System Section 3.3.2.1.1)

(Item Number galvanic corrosion, Program (B2.1.18)

3.3.1-21) MIC, and biofouling

Components in Loss of material Fire protection, fuel Fire Protection This line item was

diesel fire system due to galvanic, oil chemistry Program (B2.1.17), not used at MNGP.

(Item Number general, pitting, and Fuel Oil Chemistry The Fire Protection

3.3.1-22) crevice corrosion Program (B2.1.20), Program is applied

One-Time to those

Inspection Program components in the

(12.1.23) fire system

associated with the

diesel fire pump, with the exception

of the diesel engine

fuel oil supply.

Components in the

diesel engine fuel

oil supply are

included in the

emergency diesel

generators system,

and the aging effect

is managed by the

Fuel Oil Chemistry

and One-Time

Inspection

Programs

Tanks in diesel fuel Loss of material Aboveground Not applicable.

oil system due to general, carbon steel tanks MNGP does not

(item Number pitting, and crevice have any above

3.3.1-23) corrosion ground carbon steel

tanks exposed to

outdoor ambient

conditions within the

scope of license

renewal

3-195
- - - - - - - -~ -- ~ -I- -~ - I -

Clormponent Group -Aging Effect/ 'AMP In GALL4

Repqrt

AMP In LRA

I q 9

Closure bolting

(Item Number

3.3.1-24)

Loss of material

due to general

corrosion, crack

initiation and growth

due to cyclic

loading and SCC

Bolting integrity Bolting Integrity

Program (B2.1.4)

Consistent with

GALL Report, which

recommends no

further evaluation

Components in Crack initiation and Water chemistry Not applicable. At

contact with sodium growth due to SCC MNGP, the

pentaborate components

solution in standby exposed to sodium

liquid control pentaborate

system (BWR) solution are in an

(Item Number environment such

3.3.1-25) that the

components are not

susceptible to SCC

Components in Crack initiation and Reactor water One-Time Consistent with

reactor water growth due to SCC cleanup system Inspection Program GALL Report, which

cleanup system and IGSCC inspection (B2.1.23), Plant recommends no

(Item Number Chemistry Program further evaluation

3.3.1-26) (B2.1.25)

Components in Crack initiation and BWR stress BWR Stress Consistent with

shutdown cooling growth due to SCC corrosion cracking Corrosion Cracking GALL Report, which

system (older BWR) and water Program (B2.1.10), recommends no

(Item Number chemistry Closed-Cycle further evaluation

3.3.1-27) Cooling Water

System Program

(B2.1.13), One-Time

Inspection Program

(B2.1.23), Plant

Chemistry Program

(B2.1.25)

Components in Loss of material Closed-cycle Not applicable

shutdown cooling due to pitting and cooling water

system (older BWR) crevice corrosion, system

(Item Number and MIC

3.3.1-28)

Components Loss of material Selective leaching Selective Leaching Consistent with

(aluminum bronze, due to selective of materials of Materials GALL Report, which

brass, cast iron, leaching Program (B2.1.30) recommends no

cast steel) in further evaluation

open-cycle and

closed-cycle cooling

water systems, and

ultimate heat sink

(Item Number

3.3.1-29)

3-196
Comnponent Group Aging Effect/ -AMP in GALL AMP In.LRA ýStaff-Evaluation

'IV11Mechanism - Report..~

Fire barriers, walls, Concrete cracking Fire protection, Fire Protection Consistent with

ceilings, and floors and spalling due to structures Program (B2.1.17), GALL Report, which

in fire protection freeze-thaw, monitoring Structures recommends no

(Item Number aggressive Monitoring Program further evaluation

3.3.1-30) chemical attack, (B2.1.31)

and reaction with

aggregates; loss of

material due to

corrosion of

embedded steel

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in SER Section 3.3.2.1, involves the staff's review of the AMR results

for components in the auxiliary systems that the applicant indicated are consistent with the

GALL Report and do not require further evaluation. Another approach, documented in SER

Section 3.3.2.2, involves the staff's review of the AMR results for components in the auxiliary systems that the applicant indicated are consistent with the GALL Report and for which further

evaluation is recommended. A third approach, documented in SER Section 3.3.2.3, involves the

staff's review of the AMR results for components in the auxiliary systems that the applicant

indicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3

documents the staff's review of AMPs that are credited to manage or monitor aging effects of

the auxiliary systems components.

3.3.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the auxiliary systems components:

* Bolting Integrity Program (B2.1.4)

* Buried Piping & Tanks Inspection Program (B2.1.5)

BWR Stress Corrosion Cracking Program (82.1.10)

* Closed-Cycle Cooling Water System Program (82.1.13)

* Compressed Air Monitoring Program (B2.1.14)

* Fire Protection Program (B2.1.17)

* Fire Water System Program (82.1.18)

* Flow-Accelerated Corrosion Program (82.1.19)

* Fuel Oil Chemistry Program (82.1.20)

* One-Time Inspection Program (B2.1.23)

• Open-Cycle Cooling Water System Program (82.1.24)

* Plant Chemistry Program (B2.1.25)

* Selective Leaching of Materials Program (82.1.30)

* System Condition Monitoring Program (82.1.32)

Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant summarized the AMRs

for the auxiliary systems components and identified which AMRs it considered to be consistent

with the GALL Report.

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For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it had reviewed and accepted the identified exceptions

to the GALL Report AMPs. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant could not find

a listing of some system components in the GALL Report; however, the applicant identified a

different component in the GALL Report that has the same material, environment, aging effect,

and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component is applicable to the component under review and whether the AMR is valid

for the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component applies to the component under review. The staff verified whether it had reviewed

and accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

these line items to verify consistency with the GALL Report. The staff also determined whether

the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

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The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The

following sections discuss the staff's evaluation.

3.3.2.1.1 Loss of Material for Components in Water-Based Fire Protection

In the discussion section of LRA Table 3.3.1, Item 3.3.1-21, the applicant stated the following:

Loss of material due to general, pitting, crevice, galvanic corrosion, and MIC as

well as heat transfer degradation due to fouling for components in the fire

system are managed by the Fire Protection and Fire Water System Programs.

The Fire Water System Program is applied for the majority of the components in

the fire system. The Fire Protection Program is applied to those components in

the fire system associated with the diesel fire pump with the exception of the

diesel fire pump diesel engine fuel oil supply. In addition, the Fire Protection

Program is applied to non-water-based fire protection subsystems such as

Halon. Exceptions apply to NUREG-1 801 recommendations for Fire Protection

Program implementation. Implementation of the Fire Water System and Fire

Protection Programs to manage the aging effect provides added assurance that

the aging effect is not occurring; or that the aging effect is progressing very

slowly such that the component's intended function will be maintained during the

period of extended operation.

In RAI 3.3.2.1.9-3, the staff noted that in LRA Table 3.3.2-9 for FIR, the applicant credited the

Fire Protection Program with managing loss of material due to general, pitting, crevice, and

galvanic corrosion, and MIC for copper alloy, and loss of material due to general and galvanic

corrosion for gray cast iron material in a raw water environment, referring to GALL Report item

VII.G6-b, which evaluates filter, fire hydrant, mulsifier, pump casing, sprinkler, strainer, and

valve bodies from various materials including cast iron, bronze, and copper. The GALL Report

also recommends the Fire Water System Program for managing this aging effect. The applicant

referenced Note E, which indicates that a different AMP, Fire Protection Program, is used. As

stated above, the applicant, in Table 3.3-1, Item 3.3.1-21, indicated that it applies the Fire

Protection Program to nonwater-based fire protection systems. This indication conflicts with the

Table 3.3.2-9 line items. Furthermore, the LRA does not identify in the program description how

the Fire Protection Program will manage this aging effect in water-based systems.

Therefore, the staff requested that the applicant clarify how the Fire Protection Program will

manage loss of material due to general, pitting, crevice, and galvanic corrosion in water-based

FP systems.

In its response, dated November 22, 2005, the applicant stated the following:

Although the LRA does not expressly identify how the Fire Protection Program

will manage loss of material in water-based subsystems (i.e., diesel fire pump) in

the Program Description of Appendix B, this is specifically addressed in the Fire

Protection AMP Program Basis Document (PBD). Under the heading

'Diesel-Driven Fire Pump,' the PBD states that the water initiated aging effects

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will be managed by the Fire Water System AMP. Therefore, the Fire Protection

Program invokes the Fire Water System Program to manage loss of material

due to crevice, galvanic, general and pitting corrosion in the water-based

subsystem for the diesel fire pump. This is confirmed in the Fire Water System

PBD.

As a result, the Fire Protection AMP will adequately manage the effect of loss of

material due to crevice, galvanic, general and pitting corrosion for these

components in the Fire System by invoking the Fire Water System AMP for the

water initiated aging effects related to the diesel fire pump water-based

subsystem.

The applicant's response also stated, "Although the Fire Water System AMP is credited in the

license renewal database for managing the aging effect of loss of material for copper alloy

filters and strainers in a raw water environment, it was inadvertently omitted from LRA

Table 3.3.2-9. The Fire Water System AMP is credited for managing these components in the

water-based portion of the Fire System."

The applicant agreed to revise the Fire Protection Program in the LRA to specifically address

how it intends to credit the Fire Water System Program with managing loss of material in

water-based subsystems. The applicant will also provide revised AMR line items to correct the

inadvertent omission of the Fire Water System Program for managing the aging effect of loss of

material for copper alloy filters and strainers in a raw water environment.

In its letter dated February 28, 2006, the applicant provided an update to LRA Table 3.3.2-9,

adding the Fire Water System Program to the Fire Protection Program for managing the aging

effect of loss of material for copper alloy filters and strainers in a raw water environment. In

addition, the applicant amended the program description of the Fire Protection Program to

invoke the Fire Water System Program for water-initiated aging effects related to the diesel fire

pump water-based subsystem. Because the Fire Protection Program credits the Fire Water

System Program for managing the aging effects of loss of material in water-based subsystems,

the staff found the applicant's response acceptable. Therefore, the staff's concern described in

RAI 3.3.2.1.9-3 is resolved.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. The staff's review concluded

that the AMR results, which the applicant claimed to be consistent with the GALL Report, are

consistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

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auxiliary systems components. The applicant provided information concerning how it will

manage the following aging effects:

* loss of material due to general, pitting, and crevice corrosion

* hardening and cracking or loss of strength due to elastomer degradation or loss of

material due to wear

* cumulative fatigue damage

" crack initiation and growth due to cracking or stress corrosion cracking

* loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion

* loss of material due to general, galvanic, pitting, and crevice corrosion

• loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion and biofouling

* crack initiation and growth due to stress corrosion cracking and cyclic loading

• reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addressed the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in Section 3.3.2.2 of

the SRP-LR. The staff's audit and review report details the staff's audit. The following sections

discuss the staff's evaluation of the aging effects.

3.3.2.2.1 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2 against the criteria in SRP-LR

Section 3.3.2.2.1.

In LRA Section 3.3.2.2.1.1, the applicant addressed loss of material due to general, pitting, and

crevice corrosion of heat exchanger components in the auxiliary systems.

SRP-LR Section 3.3.2.2.1.1 states the following:

Loss of material due to general, pitting, and crevice corrosion could occur in the

channel head and access cover, tubes, and tubesheets of the heat exchanger in

the spent fuel pool cooling and cleanup (system). The Water Chemistry program

relies on monitoring and control of reactor water chemistry based on EPRI

guidelines of BWRVIP-29 (TR-1 03515) for water chemistry in BWRs to manage

the effects of loss of material from general, pitting or crevice corrosion. However,

high concentrations of impurities at crevices and locations of stagnant flow

conditions could cause general, pitting, or crevice corrosion. Therefore,

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verification of the effectiveness of the chemistry control program should be

performed to ensure that corrosion is not occurring. The GALL Report

recommends further evaluation of programs to manage loss of material from

general, pitting, and crevice corrosion to verify the effectiveness of the Water

Chemistry program. A one-time inspection of select components at susceptible

locations is an acceptable method to ensure that corrosion is not occurring and

that the component's intended function will be maintained during the period of

extended operation.

In LRA Section 3.3.2.2.1.1, the applicant stated that the One-Time Inspection Program is

applied in combination with the Plant Chemistry Program. The scope of this new AMP includes

activities to verify the effectiveness of the Plant Chemistry Program, including a sample of

components where the flow of water is low, or stagnant conditions exist. Implementation of the

One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect

adds assurance that the aging effect does not occur or progresses very slowly, such that the

component's intended function will be maintained during the period of extended operation. The

applicant stated that in some cases in which the Plant Chemistry Program is not a viable option

and aging effects/mechanisms are not expected to be significant, the One-Time Inspection

Program alone is credited with managing aging effects.

The staff's review determined that the applicant's Plant Chemistry Program exceptions are

nontechnical; the program is based on a more recent EPRI document for BWR water chemistry

instead of the EPRI document recommended in the GALL Report, BWRVIP-29. The staff

determined that the use of a more recent issue of the BWRVIP chemistry program document is

acceptable. The staff determined that the use of the One-Time Inspection Program alone is

acceptable in certain cases, such as no-flow conditions, in which the Plant Chemistry Program

is not a viable option. These AMPs are appropriate for the aging effects/mechanisms identified

and assure effective management through the period of extended operation. The staff reviewed

the Plant Chemistry Program and the One-Time Inspection Program and found them

acceptable for managing aging degradation. SER Sections 3.0.3.2.19 and 3.0.3.1.4,

respectively, document the evaluations.

In LRA Section 3.3.2.2.1.2, the applicant addressed loss of material due to pitting and crevice

corrosion of components in the auxiliary systems.

SRP-LR Section 3.3.2.2.1.2 states the following:

Loss of material due to pitting and crevice corrosion could occur in the piping,

filter housing, valve bodies, and shell and nozzles of the ion exchanger in the

spent fuel pool cooling and cleanup system. The Water Chemistry program relies

on monitoring and control of reactor water chemistry based on EPRI guidelines

of BWRVIP-29 (TR-103515) for water chemistry in BWRs to manage the effects

of loss of material from pitting or crevice corrosion. However, high concentrations

of impurities at crevices and locations of stagnant flow conditions could cause

pitting or crevice corrosion. Therefore, verification of the effectiveness of the

chemistry control program should be performed to ensure that corrosion is not

occurring. The GALL Report recommends further evaluation of programs to

manage loss of material from pitting and crevice corrosion to verify the

effectiveness of the Water Chemistry program. A one-time inspection of select

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components at susceptible locations is an acceptable method to ensure that

corrosion is not occurring and that the component's intended function will be

maintained during the period of extended operation.

In LRA Section 3.3.2.2.1.2, the applicant stated that the One-Time Inspection Program, the

combination of the One-Time Inspection Program and the Plant Chemistry Program, or the

Compressed Air Monitoring Program manages the loss of material due to pitting and crevice

corrosion of these components. The scope of the One-Time Inspection Program incorporates

activities to verify the effectiveness of the Plant Chemistry Program, including a sample of

components where the water flow is low or stagnant conditions exist. Implementation of the

One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect

adds assurance that the aging effect does not occur or progresses very slowly such that the

component's intended function will be maintained during the period of extended operation. In

some cases in which the Plant Chemistry Program is not a viable option and aging

effects/mechanisms are not expected to be significant, the One-Time Inspection Program alone

is credited with managing aging effects. The Compressed Air Monitoring Program is used to

manage loss of material of stainless steel valve bodies of the AIR system in an air/gas

environment (the applicant conservatively treats components with a "wet air/gas" environment in

the same manner as treated water). The scope of the Compressed Air Monitoring Program

includes procedurally required testing for water vapor, oil content, and particulate to ensure that

instrument air quality does not have unacceptable levels of contaminants. In addition, external

visual inspections of the AIR systems check once per cycle for corrosion and system pressure

boundary degradation.

The staff's review determined that the applicant's Plant Chemistry Program exceptions are

nontechnical and that the program is based on a more recent EPRI document for BWR water

chemistry instead of the EPRI document recommended by the GALL Report, BWRVIP-29. The

staff determined that the use of the One-Time Inspection Program- alone is acceptable in

certain cases, such as no flow conditions, in which the use of the Plant Chemistry Program is

not a viable option. The Compressed Air Monitoring Program includes procedurally required

testing for water vapor, oil content, and particulate to ensure that instrument air quality does not

have unacceptable levels of contaminants. In addition, external visual inspections of the AIR

systems check once per cycle for corrosion and system pressure boundary degradation.

Engineering personnel must conduct a system walkdown and look for vibrating piping, leaks, or

other indications of pending failures. These AMPs are appropriate for the aging

effects/mechanisms identified and assure effective management through the period of

extended operation. The staff reviewed the Plant Chemistry Program, the One-Time Inspection

Program, and the Compressed Air Monitoring Program and found them acceptable for

managing aging degradation. SER Sections 3.0.3.2.19, 3.0.3.1.4, and 3.0.3.2.13, respectively,

document the evaluations.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.1. For those line items that apply to LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2,

the staff determined that the applicant's AMRs are consistent with the GALL Report and the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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3.3.2.2.2 Hardening and Cracking or Loss of Strength Due to Elastomer Degradation or Loss

of Material Due to Wear

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.

In LRA Section 3.3.2.2.2, the applicant addressed hardening and cracking or loss of strength

due to elastomer degradation or loss of material due to wear in the auxiliary systems.

SRP-LR Section 3.3.2.2.2 states the following:

Hardening and cracking due to elastomer degradation could occur in elastomer

linings of the filter, valve, and ion exchangers in spent fuel pool cooling and

cleanup systems (BWR and PWR). Hardening and loss of strength due to

elastomer degradation could occur in the collars and seals of the duct and in the

elastomer seals of the filters in the control room area, auxiliary and radwaste

area, and primary containment heating ventilation systems and in the collars and

seals of the duct in the diesel generator building ventilation system. Loss of

material due to wear could occur in the collars and seals of the duct in the

ventilation systems. The GALL report recommends further evaluation to ensure

that these aging effects are adequately managed.

In LRA Section 3.3.2.2.2, the applicant stated that elastomer (e.g., neoprene, rubber)

components are indoors and not subject to ultraviolet (UV) radiation, ozone, or significant

radiation exposure. In addition, they are not subject to temperatures where change in material

properties or cracking could occur. Therefore, the applicant claims that aging management is

not required.

The applicant provided a detailed discussion of the technical basis for determining that aging

management is not required in response to RAI 3.2.2.3-3, dated August 16, 2005. SER Section

3.3.2.3 documents the discussion and the staff's evaluation.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.2. For those line items that apply to LRA Section 3.3.2.2.2, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.3 Cumulative Fatigue Damage

In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER

Sections 4.3 and 4.9 document the staff's review of the applicant's evaluation of this TLAA for

mechanical auxiliary systems and the reactor building crane, respectively.

3.3.2.2.4 Crack Initiation and Growth Due to Cracking or Stress-Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.4 against the criteria in SRP-LR Section 3.3.2.2.4.

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In LRA Section 3.3.2.2.4, the applicant addressed cracking for heat exchangers in the RWCU

system.

SRP-LR Section 3.3.2.2.4 states the following:

Crack initiation and growth due to SCC could occur in the regenerative and

non-regenerative heat exchanger components in the reactor water cleanup

system of BWR plants. The GALL Report recommends further evaluation to

ensure that these aging effects are managed adequately.

In LRA Section 3.3.2.2.4, the applicant stated that cracking due to SCC does not apply to its

RWCU system heat exchangers. Industry operating experience shows that for carbon steel

RWCU system heat exchanger components within the scope of license renewal in a treated

water environment, crack initiation and growth does not occur and no aging management is

required.

The staff's review determined that the applicant's assessment that SCC does not apply to the

carbon steel shell is acceptable; therefore, the staff concluded that the applicant's further

evaluation is acceptable because SRP-LR Section 3.3.2.2.4 does not apply.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.4. For those line items that apply to LRA Section 3.3.2.2.4, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

3.3.2.2.5 Loss of Material Due to General, Microbiologically Influenced, Pitting, and Crevice

Corrosion

The staff reviewed LRA Section 3.3.2.2.5 against the criteria in SRP-LR Section 3.3.2.2.5.

In LRA Section 3.3.2.2.5, the applicant addressed loss of material due to general, pitting, and

crevice corrosion and MIC of mechanical components in the auxiliary systems.

SRP-LR Section 3.3.2.2.5 states the following:

Loss of material due to general, microbiologically influenced, pitting, and crevice

corrosion could occur in the piping and filter housing and supports in the control

room area, the auxiliary and radwaste area,.the primary containment heating and

ventilation systems, in the piping of the diesel generator building ventilation

system, in the above ground piping, and fittings, valves, and pumps in the diesel

fuel oil system and in the diesel engine starting air, combustion air intake, and

combustion air exhaust subsystems in the EDG system. Loss of material due to

general, pitting, crevice and microbiologically influenced corrosion could occur in

the duct fittings, access doors, and closure bolts, equipment frames and housing

of the duct, due to pitting and crevice corrosion could occur in the

heating/cooling coils of the air handler heating/cooling, and due to general

corrosion could occur on the external surfaces of all carbon steel structures and

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components, including bolting exposed to operating temperatures less than

212 'F in the ventilation systems. The GALL Report recommends further

evaluation to ensure that these aging effects are adequately managed.

In LRA Section 3.3.2.2.5, the applicant stated that loss of material due to corrosion of

mechanical components could occur on surfaces exposed to air/gas under a range of

atmospheric conditions. For the internal surfaces of mechanical components in the EDGs,

emergency filtration train, and HTV systems, the One-Time Inspection Program is credited with

managing the aging effect. For the external surfaces of mechanical components in all auxiliary

systems, the applicant credits the Fire Water System Program, Fire Protection Program,

System Condition Monitoring Program, and/or One-Time Inspection Program with managing the

aging effect.

The staff's review determined that the applicant's Fire Water System Program and the Fire

Protection Program together manage aging effects in the water-based FP system piping and

components in accordance with applicable NFPA recommendations and aging effects for

components in the FIR, including components for the diesel fire pump. The staff also reviewed

the System Condition Monitoring Program and determined that this existing plant-specific AMP

manages aging effects for normally accessible external surfaces of piping, tanks, and other

components and equipment within the scope of license renewal. The applicant manages these

aging effects through visual inspection and monitoring of external surfaces for leakage and

evidence of material degradation. The staff's review also determined that the One-Time

Inspection Program includes a sample of components in which flow is low or stagnant

conditions exist. Implementation of the One-Time Inspection Program adds assurance that the

aging effect does not occur or progresses very slowly, such that the component's intended

function will be maintained during the period of extended operation. The staff reviewed the

applicant's Fire Water System Program, the Fire Protection Program, the One-Time Inspection

Program, and the System Condition Monitoring Program and found them. acceptable for

managing aging degradation. SER Sections 3.0.3.2.16, 3.0.3.2.15, 3.0.3.1.4, and 3.0.3.3.2,

respectively, document the evaluations. These AMPs are appropriate for the aging

effects/mechanisms identified and assure effective management of aging effects through the

period of extended operation.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.5. For those line items that apply to LRA Section 3.3.2.2.5, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.6 Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.

In LRA Section 3.2.2.2.6, the applicant addressed loss of material due to general, galvanic,

pitting, and crevice corrosion for components in the reactor coolant pump (RCP) oil collection

system for FP.

SRP-LR Section 3.2.2.2.6 states the following:

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Loss of material due to general, galvanic, pitting, and crevice corrosion could

occur in tanks, piping, valve bodies, and tubing in the reactor coolant pump oil

collection system in fire protection. The Fire Protection program relies on a

combination of visual and volumetric examinations in accordance with the

guidelines of 10 CFR Part 50 Appendix R and Branch Technical Position 9.5-1 to

manage loss of material from corrosion. However, corrosion may occur at

locations where water from wash downs may accumulate. Therefore, verification

of the effectiveness of the program should be performed to ensure that corrosion

is not occurring. The GALL Report recommends further evaluation of programs

to manage loss of material due to general, galvanic, pitting, and crevice

corrosion to verify the effectiveness of the program. A one-time inspection of the

bottom half of the interior surface of the tank of the reactor coolant pump oil

collection system is an acceptable method to ensure that corrosion is not

occurring and that the component's intended function will be maintained during

the period of extended operation.

In LRASection 3.3.2.2.6, the applicant stated that MNGP is not designed with an RCP

(recirculation pump) oil collection system because these pumps are within the primary

containment, which is inerted with nitrogen during normal operation.

On the basis of its review, the staff determined that the applicant has no components covered

by SRP-LR Section 3.3.2.2.6. The staff found this aging effect not applicable.

3.3.2.2.7 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion and Biofouling

The staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7.

In LRA Section 3.3.2.2.7, the applicant addressed loss of material due to general, pitting, and

crevice corrosion, MIC, and biofouling for components in the EDGs.

SRP-LR Section 3.3.2.2.7 states the following:

Loss of material due to general, pitting, and crevice corrosion, MIC, and

biofouling could occur on the internal surface of tanks in the diesel fuel oil

system and due to general, pitting, and crevice corrosion and MIC in the tanks of

the diesel fuel oil system in the EDG system. The existing AMP relies on the fuel

oil chemistry program for monitoring and control of fuel oil contamination in

accordance with the guidelines of ASTM Standards D4057, D1 796, D2709 and

D2276 to manage loss of material due to corrosion or biofouling. Corrosion or

biofouling may occur at locations where contaminants accumulate. Verification of

the effectiveness of the chemistry control program should be performed to

ensure that corrosion is not occurring. The GALL Report recommends further

evaluation of programs to manage corrosion/biofouling to verify the effectiveness

of the program. A one-time inspection of selected components at susceptible

locations is an acceptable method to ensure that corrosion is not occurring and

that the component's intended function will be maintained during the period of

extended operation.

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In LRA Section 3.3.2.2.7, the applicant stated that its Fuel Oil Chemistry Program manages

loss of material for all components wetted by fuel oil. The One-Time Inspection Program

confirms the effectiveness of the Fuel Oil Chemistry Program. The Fuel Oil Chemistry Program

uses existing diesel oil system procedures that encompass the GALL Report program

requirements. The Fuel Oil Chemistry Program mitigates and manages aging effects on the

surfaces wetted by fuel oil in fuel oil storage tanks and associated components, including the

tank and other components supplying fuel to the diesel fire pump. The program includes (1).

surveillance and monitoring procedures for maintaining fuel oil quality by controlling

contaminants in accordance with applicable ASTM standards, (2) periodic draining of water

from fuel oil tanks, (3) periodic or conditional visual inspection of internal surfaces or wall

thickness measurements (e.g., by UT) from external surfaces of fuel oil tanks, and (4) one-time

inspections of a representative sample of components in systems that contain fuel oil. The

One-Time Inspection Program includes (1) determination of sample size based on an

assessment of materials of fabrication, environment, plausible aging effects, and operating

experience, (2) identification of the inspection locations in the system or component based on

the aging effect, (3) determination of the examination technique, including acceptance criteria

that will be effective in managing the aging effect for which the component is examined; and (4)

evaluation of the need for followup examinations to monitor the progression of any aging

degradation.

The staff reviewed the applicant's Fuel Oil Chemistry Program and the One-Time Inspection

Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.17

and 3.0.3.1.4, respectively, document the evaluation.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.7. For those line items that apply to LRA Section 3.3.2.2.7, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.8 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff's evaluation of the applicant's Quality Assurance Program.

3.3.2.2.9 Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9.

In LRA Section 3.3.2.2.9, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.3.2.2.9 states that crack initiation and growth due to SCC and cyclic loading

could occur in the channel head and access cover, tubesheet, tubes, shell and access cover,

and closure bolting of the regenerative heat exchanger and in the channel head and access

cover, tubesheet, and tubes of the letdown heat exchanger in the chemical and volume control

system (CVCS). SRP-LR Table 3.3-1 states that further evaluation for this aging effect is for

PWR plants only.

The staff found this aging effect not applicable.

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3.3.2.2.10 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

The staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.10.

In LRA Section 3.3.2.2.10, the applicant addressed reduction of neutron-absorbing capacity and

loss of material due to general corrosion for boral.

SRP-LR Section 3.3.2.2.10 states the following:

Reduction of neutron-absorbing capacity and loss of material due to general

corrosion could occur in the neutron-absorbing sheets of the spent fuel storage

rack in the spent fuel storage. The GALL Report recommends further evaluation

to ensure that these aging effects are adequately managed.

In LRA Section 3.3.2.2.10, the applicant stated that the Plant Chemistry Program manages the

aging effects of loss of material and reduction of neutron-absorbing capacity of boral in a

treated water environment due to crevice, galvanic, and pitting corrosion and MIC and the aging

effect of cracking due to SCC by ensuring that corrosive ion concentrations do not exceed

acceptable limits and by limiting the amount of impurities in the water. General corrosion does

not apply as boral/aluminum develops a strongly bonded oxide film with excellent corrosion

resistance. The One-Time Inspection Program will verify the effectiveness of the Plant

Chemistry Program by confirming the absence of aging effects on boral coupon samples stored

in the spent fuel pool. Aging effects that could affect rack integrity or neutron absorption

characteristics are not expected because none have been observed during coupon sample

evaluations conducted over the past 20 years. By letter dated November 17, 2005, the applicant

stated that it will visually examine the unclad boral coupon sample before the period of

extended operation. The applicant will remove thecoupon from the spent fuel pool for a brief

period of time, visually examine it, and then immediately return it to the spent fuel pool.

The staff's review determined that the Plant Chemistry Program, supplemented by the OneTime Inspection Program, will manage reduction of neutron-absorbing capacity and loss of

material due to general corrosion. The one-time inspection of boral coupon test specimens will

confirm that no significant aging degradation will occur and that the neutron-absorbing

capability of the boral has not been reduced.

These AMPs are appropriate for the aging effects/mechanisms identified and assure effective

management through the period of extended operation. The staff reviewed the Plant Chemistry

Program and the One-Time Inspection Program and found them acceptable for managing

aging degradation. SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document the

evaluations.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.3.2.2.10. For those line items that apply to LRA Section 3.3.2.2.10, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

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3.3.2.2.11 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

In LRA Section 3.3.2.2.11, the applicant addressed loss of material due to general, pitting, and

crevice corrosion and MIC of underground (buried) piping and fittings in the DGN, FIR, and

ESW systems.

SRP-LR Section 3.3.2.2.11 states the following:

Loss of material due to general, pitting, and crevice corrosion and MIC could

occur in the underground piping and fittings in the open-cycle cooling water

system (SW system) and in the diesel fuel oil system. The buried piping and

tanks inspection program relies on industry practice, frequency of pipe

excavation, and operating experience to manage the effects of loss of material

from general, pitting, and crevice corrosion and MIC. The effectiveness of the

buried piping and tanks inspection program should be verified to evaluate an

applicant's inspection frequency and operating experience with buried

components, ensuring that loss of material is not occurring.

In LRA Section 3.3.2.2.11, the applicant stated that the Buried Piping & Tanks Inspection

Program manages the loss of material due to general, pitting, and crevice corrosion, MIC,

galvanic corrosion, and selective leaching for buried valve bodies, piping, and fittings. The

Bolting Integrity Program manages loss of material due to general, pitting, and crevice

corrosion, MIC, and galvanic corrosion for buried fasteners. The Buried Piping & Tanks

Inspection Program consists of preventive and condition monitoring measures to manage the

aging effect. Preventive measures consist of protective coatings and/or wraps on buried

components. Condition monitoring consists of periodic inspections of buried components. The

applicant's operating experience shows no buried pipe/tank failures for components within the

scope of license renewal. The Bolting Integrity Program consists of guidelines on materials

selection, strength and hardness properties, installation procedures, lubricants and sealants,

corrosion considerations in the selection and installation of pressure-retaining bolting for

nuclear applications, and inspection techniques.

The staff's review determined that the Buried Piping & Tanks Inspection Program provides

adequate management of aging effects for buried pipes, components, and tanks during the

period of extended operation. The Bolting Integrity Program references and invokes the

provisions of the Buried Piping & Tanks Inspection Program to implement inspection of these

components. The staff reviewed the Buried Piping & Tanks Inspection Program and the Bolting

Integrity Program and found them acceptable for managing aging degradation. SER

Sections 3.0.3.2.5 and 3.0.3.2.4, respectively, document the evaluations.

On the basis of its review, the staff concluded that the applicant has met SRP-LR

Section 3.3.2.2.11 criteria. For those line items that apply to LRA Section 3.3.2.2.11, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

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Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the issues that werefurther evaluated. The staff found that the applicant has

demonstrated that the effects of aging will be adequately managed so that intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-18,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report and provided information concerning the management of the aging

effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the

AMR line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination does not apply. Note J

indicates that the GALL Report evaluates neither the component nor the material and

environment combination for the line item.

Staff Evaluation. For-component type, material, and environment combinations that the GALL

Report does not evaluate, the staff reviewed the applicant's evaluation to determine whether

the applicant had demonstrated that the effects of aging will be adequately managed so that

intended functions will be maintained consistent with the CLB during the period of extended

operation. This section addresses the AMR results for which LRA Tables 3.3.2-1 through

3.3.2-18 do not identify any aging effects. Each table discussion separately addresses other

line items not consistent with or not addressed in the GALL Report. The following sections

discuss the staff's evaluation.

The staff's review of LRA Tables 3.3.2-1 through 3.3.2-18 identified areas for which it needed

additional information to complete its evaluation of the applicant's results. The applicant

responded to the staff's general RAIs as discussed below.

In RAI 3.3.2.3-2, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-8

identify heat transfer degradation due to fouling as an AERM for copper heat exchangers (heat

transfer and pressure boundary functions) in a lubricating oil environment. The applicant

credited the One-Time Inspection Program with managing this aging effect. The One-Time

Inspection Program verifies the effectiveness of an AMP and confirms the absence of an aging

effect. For fouling of heat exchangers in a lubricating oil environment, mitigation of the aging

effect depends on a lubricating oil monitoring program to maintain the integrity of the oil;

therefore, the staff requested that the applicant identify an AMP to mitigate the effects of fouling

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in the heat exchangers during the period of extended operation and verify the effectiveness of

that program with a one-time inspection.

In its response, by letter dated August 16, 2005, the applicant stated the following:

Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-8,

Emergency Service Water System (ESW) identify copper alloy heat exchanger

tubes for both the EDG lube oil coolers and RHR Service Water (RSW) pump

motor thrust bearing oil coolers, with lubricating oil as an external environment

for these Auxiliary Systems.

The NMC position concerning the potential aging effect of heat transfer

degradation due to fouling in a lubricating oil environment is that degradation

effects are insignificant for lubricating oil systems if the oil remains free of water

and other contaminants. Under these conditions, lubricating oil systems and

associated components have few, if any, significant aging effects. The purity of

the EDG and ESW lubricating oil systems is maintained and chemically analyzed

periodically. For equipment not normally in operation during power operation

such as the EDG lube oil coolers and the RSW motor thrust bearing oil coolers,

periodic testing of the equipment, in conjunction with oil sampling, is performed

to detect any contaminants or water in the oil.

Lubricating oil is usually non-corrosive and flow rates for lube oil systems are.

typically low. Strict controls for the quality and purity of the lubricating oil

procured and scheduled sampling techniques and parameters monitored are

requirements of the MNGP lubricating oil sampling procedures. Very little

corrosion occurs in lubricating oil systems due to low oxygen content, the fact

that lubricating oils are not good electrolytes and purification systems are

generally installed and/or corrosion inhibitors added to maintain the lubricating oil

free of corrosion products.

Lube oil samples for the EDG lube oil coolers are obtained quarterly and

samples for the RSW pump motor thrust bearing oil coolers are obtained

annually in accordance with MNGP site procedures. The sample results are

evaluated and trended for these components. Any indication of an anomalous

condition or adverse trend will result in an investigation under the site corrective

action program. All sample results have been acceptable to date to ensure that

the lubricating oil remains free of moisture and contaminants that could

potentially degrade the heat exchanger tubes, with the last samples taken and

evaluated for both the EDG and ESW systems in 2005. Although MNGP

operating experience did result in the replacement of the EDG lube oil coolers

due to the lead solder joints and resultant exfoliation corrosion, this was a design

issue and not age-related (Institute of Nuclear Power Operations SOER 80-04).

Based on the above procurement and sampling requirements to maintain the

integrity of the lubricating oil and MNGP plant-specific operating experience that

confirms the absence of this aging effect, MNGP conservatively credits the

One-Time Inspection Program to verify the absence of the aging effect of heat

transfer degradation due to fouling for these components in the EDG and ESW

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Systems. The MNGP One-Time Inspection Program will use the Corrective

Action Program to evaluate indications or relevant conditions of degradation. The

need to increase the number of selected components for inspection will also be

evaluated when indications or relevant conditions of degradation or unacceptable

conditions are found.

Based on its review, the staff found the applicant's response to RAI 3.3.2.3-2 acceptable,

because the applicant satisfactorily identified procurement and sampling requirements to

maintain the integrity of the lubricating oil and use of the One-Time Inspection Program to verify

the absence of the aging effect of heat transfer degradation due to fouling in the DGN and

ESW system heat exchangers; therefore, the staff's concern described in RAI 3.3.2.3-2 is

resolved.

In RAI 3.3.2.3-3, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3 and 3.3.2-16

identify no aging effects for rubber expansion joints in a raw water environment; therefore, the

staff requested that the applicant identify an AMP to manage hardening and loss of strength for

rubber expansion joints in a raw water environment.

In its response, by letter dated August 16, 2005, the applicant stated the following:

Several EPRI Technical Reports and Industry handbooks were reviewed for

aging of elastomers. A summary of the review is provided below.

EPRI Report 1008035, 'Expansion Joint Maintenance Guide', Revision 1, May

2003, Table 5-4, rates elastomers against oxidation, tensile strength, and

radiation. Elastomers, such as neoprene, natural rubber, Chlorobutyl, Buna-N,

viton, and EPDM, are rated as good or better in the categories of oxidation,

tensile strength, and radiation.

EPRI Report NP-6608, 'Shelf Life of Elastomeric Components,' May 1994,

Appendix A, provides curves that describe the change in physical properties for

different elastomers as they undergo natural aging. The figures demonstrate that

there is very little change in the hardness and tensile strength of elastomers over

a 33 year period.

EPRI Report NP-6408, 'Guidelines for Establishing, Maintaining, and Extending

the Shelf Life Capability of Limited Life Items (NCIG-1 3)', May 1992,

section 4.3.2, states that test results demonstrated Viton and Neoprene as

having excellent weather resistance and are therefore UV resistant.

Section 4.4.2 states that these elastomers are also highly resistant to ozone.

The Parker O-Ring Handbook, Page 2-24, in a discussion about aging of rubber

seals states, 'It is environment and not age that is significant to seal life, both in

storage and actual service.' The following is a discussion of the role of

environment on the aging of elastomers.

EPRI 1003056, November 2001, 'Non-Class 1 Mechanical Implementation

Guideline and Mechanical Tools, Revision 3, states 'For a complete discussion of

the aging effects of typical elastomers used in nuclear plants, the applicant is

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referred to EPRI TR-1 14881, 'Aging Effects for Structures and Structural

Components (Structural Tools)'. EPRI TR-1 14881 has been superceded by

EPRI 1002950, 'Aging Effects for Structures and Structural Components

(Structural Tools), Revision 1', May 2003. This report discusses the three

stressors: (1) Ultraviolet, (2) Thermal, and (3) Radiation listed below.

(1) Ultraviolet: The Structural Tools state 'Rubber is decomposed by

exposure to ultraviolet radiation. Ultraviolet radiation sources at nuclear

plants include solar radiation and ultraviolet or fluorescent lamps. The

deterioration of rubber is greatly accelerated in the presence of oxygen.

Cracking and checking (splitting), which may occur when rubber is

exposed to air and sunlight, are due mainly to reaction with ozone.' None

of the elastomers in the scope of license renewal at MNGP are exposed

to solar radiation. EPRI Report NP-6408, Section 4.3.2, states that UV on

elastomers caused by artificial light is of little concern since the amount of

UV is very small. For conservatism, MNGP took the position that any

elastomers in close proximity to fluorescent lamps would be managed for

aging, however none were found. Therefore, given the absence of solar

radiation and the negligible effects from artificial light, these elastomers

are not susceptible to hardening and loss of strength, which could be

caused by the ultraviolet radiation exposure.

(2) Thermal: The Structural Tools state, 'In general, if the ambient

temperature is less than about 95 °F, then thermal aging may be

considered not significant for the period of extended operation'. Since

these elastomers are not exposed to temperatures >95 degrees F, they

are therefore not susceptible to hardening and loss of strength caused by

thermal exposure.

(3) Radiation: The Structural Tools state, 'Material property changes and

cracking owing to radiation is an applicable aging effect for rubber,

neoprene, and silicone elastomers in environments where the radiation

exceeds the limits defined above.' The limit listed for rubber is 107 Rads,

Butyl Rubber 106 Rads, and Neoprene 106 Rads. Since these elastomers

are not exposed to this degree of ionizing radiation exposure, which is

orders of magnitude above that corresponding to 60 years of normal

plant operation, they are therefore not susceptible to hardening and loss

of strength caused by radiation.

EPRI 1002950, 'Structural Tools,' reviewed industry failure data and NRC

generic communications to determine if there was any additional aging effects

that should be considered for elastomers. The review did not uncover any new

aging effects.

EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003, pages

60 through 65, lists degradation mechanisms brought on by the stressors:

Thermal, Radiation, and Ultraviolet. Since these elastomers are not exposed to

ultraviolet, radiation, or temperatures >95°F, they are therefore not susceptible to

hardening and loss of strength and therefore no aging management is required.

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Consistent with the above discussion, Monticello only included elastomers in an

aging management program that are subject to elevated temperature, ultraviolet,

or ionizing radiation. Elastomers are included in the One-Time Inspection

Program to confirm that unacceptable degradation has not occurred such that

they will perform their intended function during the period of extended operation.

If inspections of these more severe applications identify unacceptable

degradation, the inspection scope would be expanded as required by the

One-Time Inspection Program. The expanded scope would include less

environmentally severe applications and could eventually include the elastomers

that were excluded from aging management as described above. Therefore,

elastomers not explicitly identified as requiring aging management, based on

industry experience and technical research, are subject to the One-Time

Inspection Program requirements concerning scope expansion and could be

inspected if needed based on the examination results of more severe

applications.

By letter, dated November 17, 2005, the applicant described the following additional aging

management for elastomers in an air environment exposed to ozone:

After further evaluation of this issue, NMC has taken the conservative approach

of managing change in material properties due to ozone for elastomers in an air

environment, specifically for natural rubber. This is a result of the fact that

neither representative ozone concentrations nor technically substantiated

thresholds could be adequately or consistently determined, even though

plant-specific operating experience has indicated that there has been no change

in material properties due to ozone for these elastomer components. Further

evaluation also revealed the inability to confirm that none of these components

are fabricated from natural rubber.

As a result, elastomers in an external air environment in the following LRA tables

will utilize the System Condition Monitoring Program to manage the potential

aging effect of change in material properties due to ozone which shall be

assigned to these components.

* Table 3.3.2-3 expansion joints in the Circulating Water System

* Table 3.3.2-5 piping and fittings in the Demineralized Water System

* Table 3.3.2-6 piping and fittings in the Emergency Diesel Generators

System

* Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System

* Table 3.3.2-16 expansion joints in the Service and Seal Water System

* Table 3.4.2-2 expansion joints in the Condensate and Feedwater System

(those which were not previously managed externally)

Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary Containment

System) are presently being managed utilizing the One-Time Inspection

Program for the internal surfaces and the System Condition Monitoring Program

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for the external surfaces. These Aging Management Programs (AMPs) were

initially credited to manage change in material properties and cracking due to

thermal exposure, since a temperature threshold of greater than 95 'F was

assigned to these components. Consequently, these same AMPs will also

manage change in material properties due to ozone which shall be assigned to

these components.

Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do not

require aging management since these components do not serve a pressure

boundary intended function but provide for plate-out and holdup of radioactive

material during design basis events. Condenser integrity is continuously

demonstrated during normal plant operation thus validating that this intended

function is maintained as stated in the plant-specific notes for these components

in Section 3.4 of the LRA.

Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings in

the Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation seals

in the Emergency Filtration Train System) will utilize the One-Time Inspection

Program to manage the potential aging effect of change in material properties

due to ozone which shall be assigned to these components.

Elastomers in both an internal and external air environment in Table 3.3.2-11

(ventilation seals in the Heating and Ventilation System) were inadvertently

omitted from this table. These components shall be managed for the potential

aging effect of change in material properties due to ozone utilizing the One-Time

Inspection Program for the internal surfaces and the System Condition

Monitoring Program for the external surfaces which shall be assigned to these

components.

All the elastomers addressed are long-lived components. Any component that is

not long-lived and replaced at specified intervals is eliminated from AMR

consideration during the screening process. Although the expansion joints are

presently under review for replacement on a fixed periodicity, this change has

not been effected and they remain as and have been analyzed as long-lived

components.

Any degradation of elastomer components in an air environment resulting from

change in material properties due to ozone for the external surfaces of these

components shall be evaluated as discussed in the response to RAI B2.1.32-2

which addresses the System Condition Monitoring AMP.

This response also applies to the previous RAI responses concerning elastomers

including RAI 3.3.2.3-3, RAI 3.3.2.3-4, RAI 3.3.2.3-5, RAI 3.3.2.3-6, and

RAI 3.4-01.

Based on its review, the staff found the applicant's response to RAI 3.3.2.3-3 acceptable,

because it satisfactorily identified stressors and thresholds for which hardening and loss of

strength are aging effects for elastomer components and applied aging management for these

cases. Where the stressors and thresholds for which hardening and loss of strength are not

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exceeded, aging management is not required. Therefore; the staff's concern described in

RAI 3.3.2.3-3 is resolved.

In RAI 3.3.2.3-4, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3, 3.3.2-5, 3.3.2-6,

3.3.2-7, and 3.3.2-16 identify no aging effects for rubber expansion joints, piping and fittings,

and elastomer ventilation seals in a plant indoor air environment; therefore, the staff requested

that the applicant identify an AMP to manage hardening and loss of strength for these rubber

and elastomer components in a plant indoor air environment.

In its response, by letter dated August 16, 2005, the applicant stated that its response to

RAI 3.3.2.3-3 applies to this RAI as well.

The staff found the applicant's response acceptable. Therefore, the staff's concern described in

RAI 3.3.2.3-4 is resolved.

In RAI 3.3.2.3-5, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-5 and 3.3.2-17

identify no aging effects for rubber accumulators, piping, and fittings in a treated water

environment. Previously, the staff had identified hardening and loss of strength as aging effects

for rubber and elastomer components in this environment and recommended a plant-specific

program to manage these aging effects by periodic inspections of the components; therefore,

the staff requested that the applicant identify an AMP to manage hardening and loss of strength

for these rubber components in a treated water environment.

In its response, by letter dated August 16, 2005, the applicant referred to its response to

RAI 3.3.2.3-3.

The staff found the applicant's response acceptable; therefore, the staff's concern described in

RAI 3.3.2.3-5 is resolved.

In RAI 3.3.2.3-6, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-7

identify no aging effects for rubber ventilation seals, piping, and fittings in a gas and air internal

environment; therefore, the staff requested thatthe applicant identify an AMP to manage

hardening and loss of strength for these rubber components in a gas and air internal

environment where the internal temperature exceeds 95 OF.

In its response, by letter dated August 16, 2005, the applicant referred to its response to

RAI 3.3.2.3-3.

The staff found the applicant's response acceptable; therefore, the staff's concern described in

RAI 3.3.2.3-6 is resolved.

In RAI 3.3.2.3-7, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-9

identify no aging effects for stainless steel fasteners/bolting and copper alloy flame arresters in

an environment exposed to weather; therefore, the staff requested that the applicant identify an

AMP to manage loss of material due to pitting and crevice corrosion for these stainless steel

and copper alloy components exposed to weather.

In its response, by letter dated August 16, 2005, the applicant stated the following:

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Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-9,

Fire System (FIR) identify stainless steel fasteners/bolting (EDG and FIR),

copper alloy flame arrestors (EDG and FIR) and hose house supply valves (FIR)

exposed to weather for these Auxiliary Systems. The NMC materials science

position, which is in accordance with EPRI 1003056 (Non-Class I Mechanical

Implementation Guideline and Mechanical Tools, Revision 3), is that these

components do not have a surface exposed to an aggressive chemical species,

do not have the potential for concentrating contaminants and are not subject to

wetting other than their normal environment. Therefore, loss of material due to

crevice or pitting corrosion is not a potential aging mechanism.

Crevice corrosion is a potential aging mechanism for wetted stainless steel and

high zinc copper alloys under certain conditions. Crevice corrosion is strongly

dependent on the presence of dissolved oxygen. Although oxygen depletion in

crevices may occur as a result of the corrosion process, oxygen is still required

for the onset of corrosion, and a bulk fluid oxygen content or the presence of

contaminants such as chlorides is necessary for the continued dissolution of

material in the crevice. For systems with extremely low oxygen content (<0.1

ppm), crevice corrosion is considered insignificant. This form of corrosion

requires a crevice where contaminants and corrosion products can concentrate.

In addition to oxygen, moisture is required for the mechanism to operate.

Alternate wetting and drying is particularly harmful as this leads to a

concentration of atmospheric pollutants and contaminants if they are present.

These conditions do not exist at the MNGP.

Pitting corrosion is a potential aging mechanism for wetted stainless steel and

high zinc copper alloys under certain conditions. Unless cupric, ferric or mercuric

halides are present in the environment, oxygen is required for pitting initiation.

Areas where aggressive species can concentrate are particularly susceptible to

pitting. Most pitting is the result of halide contamination, with chlorides, bromides,

and hypochlorites being prevalent. Pitting is a significant aging effect for

stainless steels and high zinc copper alloys when exposed to a corrosive

environment. Any continuously wetted or alternately wetted and dried surfaces

tend to concentrate aggressive species if they are present and are prone to

pitting corrosion. These conditions also do not exist at the MNGP.

For conservatism, the stainless steel fastener/bolting component was added as a

'global' asset to assure no components, materials or environments were

inadvertently omitted during the AMR process. Recent walk downs of both the

EDG and FIR Systems revealed there were no stainless steel fasteners/bolting

exposed to weather in either of these systems. Additionally, the FIR hose house

supply valves reside within the individual hose house metal enclosures. Although

these copper alloy valves are subjected to an 'Outside Air Protected from

Weather' environment, they were conservatively assigned to the 'Exposed to

Weather' environment. Sheltered environments tend to preclude the presence of

sufficient moisture to promote significant corrosion. Lastly, the copper alloy flame

arrestors, though painted (no credit is taken for coatings at MNGP with respect

to the mechanical systems), were confirmed to be aluminum during these walk

downs. Since aluminum and copper alloys are analyzed essentially in the same

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manner for loss of material due to crevice and pitting corrosion in an 'exposed to

weather' external environment, the difference in actual material is considered

inconsequential. However, both the EDG and FIR Systems' stainless steel

fasteners/bolting exposed to weather asset shall be removed from Table 3.3.2-6

and Table 3.3.2-9 and the material for the flame arrestors shall be changed from

copper alloy to aluminum in Table 3.3.2-6.

Since none of these components have a surface exposed to an aggressive

chemical species (sulfur dioxide, chlorine gases, sulfur gases, ozone, etc.), do

not have the potential for concentrating contaminants and are not subject to

wetting other than their normal environment, loss of material due to crevice or

pitting corrosion is not a potential aging mechanism. This has been confirmed by

system walk downs and substantiated by plant-specific operating experience.

Based on its review, the staff found the applicant's response to RAI 3.3.2.3-7 acceptable

because (1) no stainless steel fasteners/bolting in the DGN and FIR system are exposed to

weather and (2) the aluminum flame arrestors in Table 3.3.2-6 and the copper alloy hose house

supply valves in Table 3.3.2-9 are not subject to environments that promote pitting and crevice

corrosion. Therefore, aging management is not required for these components and the staff's

concern described in RAI 3.3.2.3-7 is resolved.

In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant identified line items for which it did not

identify any aging effects as a result of the aging review process.

Specifically, the applicant stated that no aging effects occur when components fabricated from

bronze, CASS, copper alloy, and stainless steel materials are exposed to air/gas (internal and

external), concrete (external), dry air (internal), gas-halon (internal), gas-instrument air

(internal), gas-nitrogen (internal), gas-refrigerant (internal), lubricating oil (internal and external),

plant indoor air (internal and external), and primary containment air (external) environments. In

addition, components fabricated from carbon steel, galvanized steel, and cast iron exposed to

these same environments, with the exception of indoor air and primary containment air

environments, have no aging effects. The applicant stated that materials science evaluation of

these materials in such environments found no aging effects for the components and materials.

No aging effects are considered applicable to components fabricated from the above list of

materials exposed to the given environments.

As shown in the Metals Handbook, Ninth Edition, Volume 13, comprehensive tests over a

20-year period under ASTM supervision confirmed the suitability of copper alloys for

atmospheric exposure. Additionally, because the gaseous internal environments to which

components within the scope of license renewal may-be subject include air, nitrogen, carbon

dioxide, freon, and halon, industry experience shows that copper piping exposed to an internal

gaseous environment will be resistant to any age-related degradation; therefore, the SC will

remain capable of performing intended functions consistent with the CLB for the period of

extended operation.

As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisture

must be present to corrode steel. Experience has shown that general corrosion of steel

(including carbon steel, alloy steel, gray cast iron, and galvanized steel) will apply only if it were

exposed to outdoor or indoor environments that promote condensation of water on the external

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surfaces of components; therefore, the SC will remain capable of performing intended functions

consistent with the CLB for the period of extended operation.

As shown in Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highly

resistant to corrosion in dry atmospheres in the absence of corrosive species (which will be

reflective of indoor uncontrolled air or primary containment air inerted with nitrogen); therefore,

the SC will remain capable of performing intended functions consistent with the CLB for the

period of extended operation.

As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisture

must be present to corrode steel. Components are not subject to wetting if their surfaces

remain oil-coated; therefore, steel (carbon or stainless) in a lubricating oil environment with no

water pooling exhibits no aging effect, and the SC will remain capable of performing intended

functions consistent with the CLB for the period of extended operation.

For carbon steel embedded in concrete, loss of material due to general corrosion could occur in

an aggressive environment. An aggressive environment has pH less than 5.5, chlorides greater

than 500 ppm, or sulfates greater than 1500 ppm. Plant documents confirm that the

below-grade environment is not aggressive. The applicant's data indicate that the

pH exceeds 7, chlorides are less than 100 ppm, and sulfates are less than 100 ppm. To ensure

that the below-grade environment remains nonaggressive, the Structures Monitoring Program

includes periodic monitoring of ground water chemistry for the above parameters; therefore, the

SC will remain capable of performing intended functions consistent with the CLB for the period

of extended operation.

The staff's review of current industry research and operating experience found that effects of

the listed environments on the given materials will not result in aging effects of concern during

the period of extended operation; therefore, the staff concluded that no AERMs apply for the

component, material, and environment combinations described in the preceding discussion.

3.3.2.3.1 Auxiliary Systems-Alternate Nitrogen System-Summary of Aging Management

Evaluation-Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the

alternate nitrogen system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.3.2.3 above.

3.3.2.3.2 Auxiliary Systems-Chemistry Sampling System-Summary of Aging Management

Evaluation-Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the

chemistry sampling system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.3.2.3 above.

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3.3.2.3.3 Auxiliary Systems-Circulating Water System-Summary of Aging Management

Evaluation-Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the

CWT system component groups.

The applicant stated that it expects no aging effects for stainless steel and polyvinyl chloride

(PVC) filters/housings exposed to a plant indoor air environment. The staff's review of

plant-specific and industry operating experience found no aging effects expected for stainless

steel and PVC filters/housings exposed to a plant indoor air environment in the CWT system.

Likewise, the applicant stated that it expects no aging effects for rubber expansion joints

exposed to plant indoor air and treated water environments. RAIs 3.3.2.3-3 and 3.3.2.3-4 in

SER Section 3.3.2.3 discuss the staff's evaluation.

Based on the above evaluations, the staff found that the applicant has identified the appropriate

AMP for the materials and environment associated with the above components in the CWT

system.

3.3.2.3.4 Auxiliary Systems-Control Rod Drive System-Summary of Aging Management

Evaluation-Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the

CRD system component groups.

The applicant proposed to manage the CRD system aging effects with the System Condition

Monitoring Program. SER Section 3.0.3.3.2 documents the staff's review of the applicant's

System Condition Monitoring Program.

The staff's review of LRA Table 3.3.2-4 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In RAI 3.3.2.3-1, dated July 20, 2005, the staff noted that LRA Table 3.3.2-4 identifies SCC as

an AERM for stainless steel piping and fittings in a primary containment air environment. To

manage this aging effect, the applicant credited the System Conditioning Monitoring Program,

which uses visual inspections of component external surfaces for detection of aging effects;

therefore, the staff requested that the applicant provide operating experience or other bases for

determining that SCC is an aging effect in this environment. In addition, since methods like

VT-1, liquid penetrant, or volumetric inspections are used to detect SCC, the staff asked the

applicant to identify the methods and acceptance criteria of the System Conditioning Monitoring

Program to detect SCC for these components.

In its response, by letter dated August 16, 2005, the applicant stated the following:

Data suggests that temperature is an important factor in stress corrosion

cracking (SCC) and that SCC is seldom found at temperatures below

140 degrees F. However, a review of plant operating experience revealed two

locations where cracking was observed on the exterior of the Control Rod Drive

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System (CRD) withdrawal lines, prompting NMC to manage cracking on the

exterior of the stainless steel CRD lines located inside containment.

In 1998, during performance of the visual walkdown portion of the reactor

coolant pressure boundary leakage test, a crack was identified on a CRD

withdrawal line within the drywell. The specific CRD is CRD 34-27. Failure

analysis performed by a metallurgical laboratory revealed the cause to be

transgranular stress corrosion cracking (TGSCC) due to chloride attack of the

external surface. This evaluation showed the cracking to originate from the

outside diameter inwards. Also, the metallurgical laboratory found chloride in the

through wall flaw. The source of the chloride contamination was not positively

identified. The leaking pipe was in an area located directly under catwalks.

These open areas are more vulnerable to contamination due to personnel traffic

and potential for spills.

As a result of the leak, the following inspections were made during the 1998

refueling outage:

* All lines were VT-2 inspected during the ASME Code, Section Xl, reactor

coolant pressure boundary leakage test. No leaks were found after the

cracked piping was replaced.

* All elbows (where the vertical run turns horizontal for penetration of the

biological shield) were visually inspected. There were no indications.

* Dye penetrant testing on the elbows of 14 withdraw lines in the same

bundle as CRD 34-27 (outside of the biological shield, with the exception

of an elbow on CRD 38-27 which was inside the biological shield.) was

conducted. No indications were found.

During the 2000 outage, the accessible CRD piping had been wiped down and

foreign material, including tape, was removed. After the piping was cleaned, an

inspection of 504 one-foot long sections of all accessible CRD insert and

withdrawal lines from the hydraulic accumulator units (HCUs) to the reactor

pedestal was implemented. A crack indication was found on CRD withdrawal

line 14-27 inside the drywell. The drywell pipe section contained a defect greater

than 10% through wall. The apparent cause of the indication appears to have

been chloride induced SCC. The indication was identified as being under a piece

of tape on a vertical section of the withdraw line. The laborer removing the tape

from the area with the relevant indication noted that that particular piece of tape

was different from the others removed in that it was both discolored and difficult

to remove. It is possible, although unlikely, that the chlorides necessary for

TGSCC leached from this tape. However, a more plausible explanation is that

chloride contaminated water from another source dripped down the pipe and the

tape acted as a crevice, providing a spot for the aqueous chlorides to begin their

attack. A source of aqueous chlorides leaking from above would be consistent

with the relevant conditions found during the 1998 refueling outage.

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In view of this plant specific operating experience, NMC conservatively assumed

cracking on the external surface of the CRD pipes inside the drywell despite the

extensive testing already conducted. The cracking will be managed using the

System Condition Monitoring Program. The System Condition Monitoring

Program is an existing plant-specific program. This program manages aging

effects for normally accessible, external surfaces of piping, tanks, and other

components and equipment within the scope of license renewal. The aging

effects are to be managed through visual inspection to look for degradation

conditions such as crack-like indications and corrosion. Crack-like indications will

be entered into the corrective action process for evaluation. The evaluation will

include appropriate acceptance criteria based on applicable code specifications

and industry practices such as EPRI. The evaluation will consider the need for

further surface examinations such as liquid penetrant or volumetric inspection to

determine the extent of condition.

The staff reviewed the applicant's response and found it acceptable. The applicant satisfactorily

explained its management of SCC as an aging effect in this environment and identified the

methods and acceptance criteria used by System Conditioning Monitoring Program to detect

SCC for these components. The staff's concern described in RAI 3.3.2.3-1 is resolved.

The staff's review of plant-specific and industry operating experience found that the System

Condition Monitoring Program effectively manages cracking due to SCC of stainless steel

material for component types in the CRD system; therefore, the staff found that the applicant

has identified the appropriate AMP for the materials and environment associated with the above

CRD system components.

3.3.2.3.5 Auxiliary Systems-Demineralized Water System-Summary of Aging Management

Evaluation-Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the

DWS component groups.

The applicant stated that it expects no aging effects for PVC and fiberglass piping, fittings,

pump casings, tanks, thermowells, and valve bodies exposed to plant indoor air and treated

water environments in the DWS. On the basis of its review of plant-specific and industry

operating experience, the staff agreed with this statement.

RAIs 3.3.2.3-4 and 3.3.2.3-5 in SER Section 3.3.2.3 discusses the staff's evaluation with

respect to the lack of aging effects for rubber piping and fittings exposed to a plant indoor air

and treated water environments.

Based on the above evaluations, the staff found that the applicant has identified the appropriate

AMP for the materials and environment associated with the above components in the DWS.

In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to pitting and

crevice corrosion and MIC of copper alloy materials for the component types of flow elements,

piping and fittings, and valve bodies exposed to a treated water environment with the Plant

Chemistry Program combined with the One-Time Inspection Program.

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The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-Time

Inspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.

The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to

water as the process fluid; chemistry programs control water chemistry for impurities (e.g.,

chloride and sulfate) that accelerate corrosion or crack initiation and growth, or that cause heat

transfer degradation due to fouling in select heat exchangers. This program relies on monitoring

and control of water chemistry to keep peak levels of various contaminants below

system-specific limits. The new One-Time Inspection Program is consistent with the

recommendations of GALL AMP XI.M32, and includes measures to verify the effectiveness of

the Plant Chemistry Program. The One-Time Inspection Program addresses concerns and

provides confirmation of the potential long incubation period for certain aging effects on SCs. If

system contaminants are maintained within the limits specified by the Plant Chemistry Program,

the corrosion exhibited by the copper alloy in a closed system is adequately managed. The

applicant has chosen a different combination of AMPs to manage the AERM. The staff found

this combination adequate and acceptable for managing this material, environment, and aging

effect because contaminants are maintained within limits to inhibit corrosion of the copper alloy.

In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of flow elements, piping and fittings,

and valve bodies exposed to a treated water (internal) environment with the Selective Leaching

of Materials Program.

The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, as

documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection

and hardness measurement of certain susceptible components to determine if selective

leaching occurs. The staff determined that this AMP is adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Plant Chemistry Program,

combined with the One-Time Inspection and theSelective Leaching OF materials Programs,

effectively manages the aging effect of loss of material due to MIC and selective leaching of

copper alloy material exposed internally to treated water environment given in LRA

Table 3.3.2-5.

3.3.2.3.6 Auxiliary Systems-Emergency Diesel Generators System-Summary of Aging

Management Evaluation-Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the

DGN component groups.

The staff reviewed AMR line items for the DGN, which experiences cracking due to SCC of

copper alloy, carbon steel, and cast iron; fouling of copper alloy; and loss of material for copper

alloy for the following component types:

* piping and fittings

" fasteners and bolting

* flame arrestors

* gauges (flow, sight and level)

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• heat exchangers

* pump casings

" tanks

" valve bodies

* heaters/coolers

For those components requiring staff review, the following environments apply:

* exposed to weather (external)

* treated water (internal)

* lubricating oil (external)

* fuel oil (internal)

• treated water (external)

RAI 3.3.2.3-7 in SER Section 3.3.2.3 discusses the staff's evaluation with respect to aging

effects for stainless steel fasteners and bblting exposed to weather environment as well as for

copper alloy flame arrestors exposed to weather environment is discussed in RAI 3.3.2.3-7 in

SER Section 3.3.2.3. RAIs 3.3.2.3-4 and 3.3.2.3-6 in SER Section 3.3.2.3 discuss the staff's

evaluation with respect to aging effects for rubber piping and fittings exposed to a plant indoor

air and gas instrument air environments. RAI 3.3.2.3-2 in SER Section 3.3.2.3 discusses the

staff's review of the management of fouling of heat exchangers in a lubricating oil environments

using the One-Time Inspection Program.

The applicant proposed to manage DGN aging effects with the CCCW System Program,

One-Time Inspection Program, and Fuel Oil Chemistry Program. SER Sections 3.0.3.2.12,

3.0.3.1.4, and 3.0.3.2.17, respectively, document the, staff's evaluation of these programs.

The staff's review of plant-specific and industry operating experience found that the ClosedCycle Cooling Water System Program, One-Time Inspection Program, Fuel Oil Chemistry

Program effectively manage cracking due to SCC of copper alloy, carbon steel, and cast iron,

fouling of copper alloy, and loss of material for copper alloy for DGN component types.

Based on the above evaluations, the staff found that applicant has identified the appropriate

AMPs for the materials and environment associated with the above components of the DGN

components.

In LRA Table 3.3.2-6, the applicant proposed to manage heat transfer degradation due to

fouling of copper alloy materials for component types of heat exchangers exposed to a treated

water environment with the Closed-Cycle Cooling Water System Program.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting and

crevice corrosion, and MIC of copper alloy materials for component types including gauges

(flow, level, and sight), heat exchangers, and valve bodies exposed to a treated water

environment with the Closed-Cycle Cooling Water System Program.

SER Section 3.0.3.2.12 documents the staff's review and evaluation of the applicant's CCCW

Program. The CCCW Program includes (1) preventive measures to minimize corrosion and (2)

periodic system and component performance testing and inspection to monitor the effects of

corrosion and confirm performance of intended functions. Preventive measures include the

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monitoring and control of corrosion inhibitors and other chemical parameters like pH, in

accordance with the guidelines of EPRI TR-1 007820, vendor recommendations, and plant

operating experience.

As the applicant made only minor changes to its CCCW System Program to implement EPRI

TR-1007820, the program is also still in accordance with the guidelines identified in GALL AMP

XI.M21 (i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to

confirm function and monitor corrosion in accordance with EPRI TR-1 007820, vendor

recommendations, and industry and plant operating experience. If system corrosion inhibitor

concentrations are maintained within the limits specified by the Plant Chemistry Program,

corrosion of the copper alloy in a closed system is adequately managed. The staff found this

AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of gauges (flow, level, and sight),

heat exchangers, and valve bodies exposed to treated water environment with -the Selective

Leaching of Materials Program.

The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, as

documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection

and hardness measurement of certain components susceptible to selective leaching. The

program will determine if selective leaching occurs for certain components. The staff found this

AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting and

crevice corrosion and MIC of copper alloy materials for the component types of valve bodies

exposed to a fuel oil environment with the Fuel Oil Chemistry Program, combined with the

One-Time Inspection Program.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting and

crevice corrosion and MIC of stainless steel materials for component types of manifolds, piping

and fittings, and valve bodies exposed to a fuel oil environment with the Fuel Oil Chemistry

Program, combined with the One-Time Inspection Program.

The staff reviewed and evaluated the applicant's Fuel Oil Chemistry Program, as documented

in Section 3.0.3.2.17, and the One-Time Inspection Program, as documented in SER

Section 3.0.3.1.4. The Fuel Oil Chemistry Program is an existing program using existing diesel

fuel oil system procedures that. encompass the GALL Report program recommendations in

mitigating and managing aging effects on the internal surfaces of diesel fuel oil storage tanks

and associated components in systems that contain diesel fuel oil. The program includes (1)

surveillance and monitoring procedures for maintaining diesel fuel oil quality by controlling

contaminants in accordance with applicable ASTM standards, (2) periodic draining of water, if

present, from diesel fuel oil tanks, (3) periodic or conditional visual inspection of internal

surfaces or wall thickness measurements (e.g., by UT) from external surfaces of diesel fuel oil

tanks, and (4) one-time inspections of a representative sample of components in systems that

contain diesel fuel oil.

The applicant's new One-Time Inspection Program is consistent with the recommendations of

GALL AMP XI.M32. This program will include measures to verify the effectiveness of the Plant

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Chemistry Program and the Fuel Oil Chemistry Program and also confirm the absence of age

degradation in selected components (e.g., flow restrictors, venturis, and small bore piping)

within the scope of license renewal. The One-Time Inspection Program addresses concerns

and provides confirmation of the potential long incubation period for certain aging effects on

SCs. The staff review found the Fuel Oil Chemistry Program supplemented by the One-Time

Inspection Program adequate for managing these material, environment, and aging effects

combinations.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Closed-Cycle Cooling Water

System Program, Selective Leaching of Materials Program, or Fuel Oil Chemistry Program

combined with the One-Time Inspection Program effectively manage the aging effects of heat

transfer degradation due to fouling, loss of material due to pitting and crevice corrosion, and

MIC, and loss of material due to selective leaching of copper alloy or stainless steel materials

exposed to a treated water (internal or external) or fuel oil environments in LRA Table 3.3.2-6.

3.3.2.3.7 Auxiliary Systems-Emergency Filtration Train System-Summary of Aging

Management Evaluation-Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the

emergency filtration train system component groups.

RAIs 3.3.2.3-4 and 3.3.2.3-6 discuss the staff evaluation with respect to aging effects for

elastomer ventilation seals exposed to air, gas, and plant indoor air environments.

Based on the above evaluation, the staff found that the applicant has identified the appropriate

AMPs for the materials and environments associated with the above components in the

emergency filtration train system.

In LRA Table 3.3.2-7, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of chillers exposed to a wet air/gas

(external) environment with the Selective Leaching of Materials Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement of certain components susceptible to selective leaching to determine if

selective leaching occurs.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Selective Leaching of Materials

Program effectively manages the aging effect of loss of material due to selective leaching of

copper alloy material exposed externally to a wet air/gas environment. On this basis, the staff

found the applicant's program to manage loss of material due to selective leaching in LRA

Table 3.3.2-7 acceptable.

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3.3.2.3.8 Auxiliary Systems-Emergency Service Water System-Summary of Aging

Management Evaluation-Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the

ESW system component groups.

The staff reviewed AMR line items for the ESW system. This system experiences fouling of the

copper alloy component of heat exchangers.

For those components requiring staff review, the lubricating oil (external) environment applies.

The applicant proposed to manage the ESW system aging effects with the One-Time

Inspection Program. SER Section 3.0.3.1.4 documents the staff's evaluation of this program.

RAI 3.3.2.3-2 discusses the staff evaluation with respect to managing fouling of heat

exchangers in a lubricating oil environment using the One-Time Inspection Program.

The staff's review of the plant-specific and industry operating experience found that the OneTime Inspection Program effectively manages fouling of copper alloy components in the ESW

system.

Based on the above evaluation, the staff found that the applicant has identified the appropriate

AMP for the material and environment associated with the above components in the ESW

system.

3.3.2.3.9 Auxiliary Systems-Fire System-Summary of Aging Management

Evaluation-Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the

FIR component groups.

In LRA Section 3.3.2.1.9 and Table 3.3.2-9, the applicant identified the materials, environments,

and AERMs. The materials identified include bronze, carbon steel, cast iron, copper alloy,

ductile iron, galvanized steel, gray cast iron, and stainless steel.

The applicant identified the inside, outside, and buried environments to which these materials

could be exposed as air and gas (wetted, ambient and dry), atmosphere/weather, halon, raw

water, and treated water. The applicant identified loss of material (from corrosion or leaching)

and heat transfer degradation due to fouling as the aging effects associated with the FIR.

The applicant proposed to manage the FIR aging effects with the Bolting Integrity Program,

Buried Piping & Tanks Inspection Program, Fire Protection Program, Fire Water System

Program, and System Condition Monitoring Program. SER Sections 3.0.3.2.4, 3.0.3.2.5,

3.0.3.2.15, 3.0.3.2.16, and 3.0.3.3.2, respectively, document the staff's.evaluations of these

programs.

The staff reviewed LRA Section 3.3.2.1.9 and LRA Table 3.3.2-9 to determine whether the

applicant demonstrated that it will adequately manage the aging effects for the FIR during the

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period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff conducted its

review, described below, in accordance with SRP-LR Section 3.3 and the GALL Report.

The staff's review of LRA Table 3.3.2-9 identified areas for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAIs as discussed below.

In RAI 3.3.2.1.9-1, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 refers to

Notes J and 319, which describe the AMRs for copper alloy in heat exchangers; therefore, the

staff requested that the applicant justify the conclusion in Note 319 that "the AMP referenced is

appropriate for the aging effects/mechanisms identified and provides assurance that the aging

effects/mechanisms are effectively managed through the period of extended operation."

In its response, by letter dated September 16, 2005, the applicant stated that the Fire Water

System Program manages aging of water-based FIR piping and components in accordance

with applicable NFPA recommendations. The FP AMP manages aging of fire barriers, the

diesel-driven fire pump, and the halon fire suppression system consistent with the GALL

Report, since GALL AMP XI.M26 states for FP that, "For operating plants, the fire protection

AMP includes a fire barrier inspection program and a diesel-driven fire pump inspection

program." As a result, both the Fire Water System and Fire Protection Programs are credited

for line items such as filter/strainers, manifolds, pump casings, and valve bodies because these

line items apply to both the diesel-driven fire pump (Fire Protection Program) as well as the

remainder of the water-based components (Fire Water System Program). In this specific case,

the Fire Protection Program, not the Fire Water System Program, manages the copper alloy

heat exchanger (radiator) for the diesel-driven fire pump addressed in the Fire Protection

Program. Consequently, Note J, which states, "Neither the component nor the material and

environment combination is evaluated in NUREG-1801 ," applies to this line item because the

GALL Report, Section VII.G, addresses the diesel-driven fire pump copper heat exchanger in

neither a treated water nor raw water environment. Additionally, Note 319, which states the

following, further defines this issue:

NUREG-1 801, Volume 2, Chapter VII (Auxiliary Systems), Section G.6 (Fire

Protection) does not address this environment for the mechanical portion of the

Fire Protection AMP (XI.M26). The AMP referenced is appropriate for the aging

effects/mechanisms identified and provides assurance that the aging

effects/mechanisms are effectively managed through the period of extended

operation to further define this issue.

Consequently, the Fire Protection Program, as defined in LRA Section B2.1.17, is appropriate

to manage the aging effects of heat transfer degradation and loss of material for the copper

alloy diesel-driven fire pump heat exchanger addressed in LRA Table 3.3.2-9 and assures

effective management of the aging effects/mechanisms through the period of extended

operation.

Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-1 acceptable

because it adequately explains that the GALL Report does not evaluate the copper alloy

diesel-driven fire pump heat exchanger, in both treated water and raw water environments. The

applicant stated that the Fire Protection Program manages the aging effects of heat transfer

degradation and loss of material for the copper alloy diesel-driven fire pump heat exchanger.

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The staff reviewed the applicant's Fire Protection Program and found acceptable the

management of heat transfer degradation due to fouling and loss of material due to general,

galvanic, crevice, and pitting corrosion and MIC, as given in LRA Table 3.3.2-9; therefore, the.

staff's concern described in RAI 3.3.2.1.9-1 is resolved.

In RAI 3.3.2.1.9-2, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 shows no

AMP for stainless steel fasteners/bolting; therefore, the staff requested that the applicant

explain why these fasteners/bolting do not require an AMP as recommended by GALL AMP

XI.M18.

In its response, by letter dated September 16, 2005, the applicant stated that Table 3.3.2-9

identifies stainless steel fasteners/bolting in exposed to weather and plant indoor air external

environments. The applicant's materials science position, which is consistent with

EPRI 1003056, is that these components have no surface exposed to an aggressive chemical

species, have no potential for concentrating contaminants, and are not subject to wetting other

than their normal environment; therefore, loss of material is not a potential aging effect as

identified by LRA Note 327. Additionally, the FIR has no bolts with a specified minimum yield

strength >150 ksi.

Crevice corrosion is a potential aging mechanism for wetted stainless steel under certain

conditions. Crevice corrosion depends strongly on the presence of dissolved oxygen. Although

oxygen depletion in crevices may occur as a result of corrosion, oxygen is still required for the

onset of corrosion and bulk fluid oxygen content or the presence of contaminants like chlorides

is necessary for the continued dissolution of material in the crevice. In systems with extremely

low oxygen content (< 0.1 ppm), crevice corrosion is considered insignificant. This form of

corrosion requires a crevice where contaminants and corrosion products can concentrate. In

addition to oxygen, moisture is required for the mechanism to operate. Alternate wetting and

drying is particularly harmful as this leads to a concentration of atmospheric pollutants and

contaminants, if present. These conditions do not exist for stainless steel fasteners/bolting at

MNGP.

Pitting corrosion is a potential aging mechanism for wetted stainless steel under certain

conditions. Unless cupric, ferric, or mercuric halides are present in the environment, oxygen is

required for pitting initiation. Areas where aggressive species can concentrate are particularly

susceptible to pitting. Most pitting is the result of halide contamination with prevalent chlorides,

bromides, and hypochlorites. Pitting is a significant aging effect for stainless steels when

exposed to a corrosive environment. Any continuously wetted or alternately wetted and dried

surfaces tend to concentrate any aggressive species, if they are present, and are prone to

pitting corrosion. These conditions also do not exist for stainless steel fasteners/bolting at

MNGP.

For conservatism during the integrated plant assessment process, both the exposed to weather

and plant indoor air environments include the stainless steel fastener/bolting component to

ensure that the evaluations have not inadvertently omitted any components, materials, or

environments from the evaluations; however, recent walkdowns of the FIR revealed no

stainless steel fasteners/bolting exposed to weather.

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Consequently, the applicant will remove the FIR stainless steel fasteners/bolting exposed to

weather asset from LRA Table 3.3.2-9. Stainless steel fasteners/bolting in a plant indoor air

environment have no aging effects for the same reasons as stated above.

Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-2 acceptable,

because the applicant stated that stainless steel fasteners/bolting in the FIR have no potential

for concentrating contaminants and are not subject to wetting other than their normal

environment. The applicant also stated that recent walkdowns of the FIR revealed no stainless

steel fasteners/bolting exposed to weather, so it will remove this asset from LRA Table 3.3.2-9;

therefore, the staff's concern described in RAI 3.3.2.1.9-2 is resolved.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the aging effects from exposure of the

fire water system components to the environments described in LRA Table 3.3.2.6 are

consistent with the GALL Report and with industry experience for these material-environment

combinations; therefore, the staff found that the applicant identified the applicable aging effects

and associated AMPs and that they are appropriate for the combination of materials and

environments listed.

In LRA Table 3.3.2-9, the applicant proposed to manage heat transfer degradation due to

fouling, loss of material due to crevice and pitting corrosion, MIC, and loss of material due to

selective leaching of copper alloy materials for the component types of heat exchangers

exposed to a raw water environment with the Fire Protection Program.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to crevice and

pitting corrosion, MIC, and loss of material due to selective leaching of copper alloy materials

for the component types of heat exchangers exposed to a glycol corrosion-inhibited treated

water (external) environment with the Fire Protection Program.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to general,

galvanic, crevice, and pitting corrosion, MIC, and loss of material due to selective leaching of

gray cast iron materials for the component types of heat exchangers exposed to a glycol

corrosion-inhibited treated water (internal) environment with the Fire Protection Program.

The staff reviewed and evaluated the Fire Protection Program, as documented in SER

Section 3.0.3.2.15. The Fire Protection Program includes a fire barrier inspection program, a

diesel-driven fire pump inspection program, and a halon fire suppression system inspection.

The program requires periodic visual inspection of fire barriers, seals, walls, ceilings, floors, and

associated fire-rated doors. The diesel-driven fire pump inspection program periodically tests

the pump and inspects the diesel engine to ensure that the fuel supply line can perform the

intended function. The halon fire-suppression system inspection includes periodic inspection

and testing of the cable spreading room halon fire-suppression system. The applicant will

enhance the existing Fire Protection Program under the Parameters Monitored or Inspected

element to be consistent, with certain exceptions, with GALL AMP XI.M26, as modified by

ISG-04. The exception to the GALL Report concerns the periodic visual inspection and function

test of halon systems at least once every 6 months. The applicant functionally tests and visually

inspects the cable spreading room halon system every 18 months instead of every 6 months as

recommended in the GALL Report. The staff found this exception acceptable, as documented

in SER Section 3.0.3.2.15.

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With respect to copper alloy in raw water, the staff has accepted that these AERMs exist in

other systems, such as CWT and diesel generator support systems. The fire water and FP

systems also have instances of copper alloy in raw water. The applicant credits the Fire

Protection Program with managing loss of material due to crevice and pitting corrosion, MIC,

and selective leaching. The staff review found this AMP adequate for managing this material,

environment, and aging effect. With respect to copper alloy in glycol corrosion-inhibited treated

water (external), the staff has accepted that these AERMs exist in other systems, such as the

CWT and diesel generator support systems. With respect to gray cast iron in glycol

corrosion-inhibited treated water (external), the applicant credited the Fire Protection Program

with managing loss of material due to general, galvanic, crevice, and pitting corrosion, MIC, and

selective leaching. The staff's review found this AMP adequate for managing the AERMs of

heat transfer degradation due to fouling, loss of material due to crevice and pitting corrosion,

and MIC for the materials identified.

In RAI 3.3.2.2.5-1, dated October 31, 2005, the staff requested that the applicant demonstrate

how the Fire Water System and the Fire Protection Programs will manage loss of material due

to selective leaching for these materials.

In its response, dated November 22, 2005, the applicant stated that it inadvertently omitted the

FIR from the applicable systems table in LRA Section B2.1.30 (under "Scope of Program") for

the Selective Leaching of Materials Program. The applicant agreed to revise LRA Section

B2.1.30 to include the FIR within the scope of the program. In its letter dated February 28,

.2006, the applicant revised LRA Section B2.1.30 to include the FIR within the scope of the

program.

Additionally, in its response, the applicant stated that under "Scope of Program," the Fire

Protection, Fire Water System, and Buried Piping & Tanks Programs credit the Selective

Leaching of Materials Program for managing loss of material due to selective leaching. The

applicant inadvertently omitted such credits not specifically stated from these program

descriptions in the LRA for the respective AMPs.

It was not clear to the staff how the applicant intended to credit the Selective Leaching of

Material Program, as the Parameters Monitored or Inspected element and the Detection of

Aging Effects element for the AMPs do not specify, any components that could have an aging

effect of loss of material due to selective leaching. The applicant agreed to revise these AMPs

to describe how they will credit the Selective Leaching of Materials Program. In its letter, dated

February 28, 2006, the applicant revised the Scope of Program element for the Fire Protection,

Fire Water System, and Buried Piping & Tanks Programs to include loss of material due to

selective leaching by crediting the Selective Leaching of Materials Program.

The staff found this response acceptable; therefore, the staff's concern described in

RAI 3.3.2.2.5-1 is resolved.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to galvanic and

general corrosion of carbon steel materials for the component types of valve bodies exposed to

air/gas (internal) environment with the Fire Water System Program.

The staff reviewed and evaluated the Fire Water System Program, as documented in SER

Section 3.0.3.2.16. The Fire Water System Program relies on testing of water-based FP system

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piping and components in accordance with applicable NFPA recommendations. In addition, the

applicant will modify this program to include (1) portions of the FP sprinkler system subject to

full-flow tests before the period of extended operation and (2) portions of the FP system

exposed to water that are visually inspected internally. Periodic full-flow flush tests and system

performance tests ensure that the aging mechanisms of corrosion and biofouling/fouling are

properly managed in the fire water system. With respect to carbon steel in an air/gas (internal)

environment, the applicant has chosen, for conservatism, to manage the AERM as though the

environment were water. The staff review found this AMP adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects and plant-specific and

industry operating experience, the staff determined that the Fire Protection and Fire Water

System Programs effectively manage the aging effect of heat transfer degradation due to

fouling, loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, and

loss of material due to selective leaching of copper alloy, gray cast iron, and carbon steel

materials exposed to raw water, glycol corrosion-inhibited treated water (internal and external),

and air/gas (internal) environments. On this basis, the staff found acceptable the management

of heat transfer degradation due to fouling, loss of material due to general, galvanic, crevice,

and pitting corrosion and MIC, and loss of material due to selective leaching in LRA

Table 3.3.2-9.

3.3.2.3.10 Auxiliary Systems-Fuel Pool Cooling and Cleanup-Summary of Aging

Management Evaluation-Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for

the FPC component groups.

In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to crevice and

pitting corrosion and MIC of copper alloy materials for the component types of piping and

fittings, and valve bodies exposed internally to a treated water environment with the Plant

Chemistry Program combined with the One-Time Inspection Program.

The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-Time

Inspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.

The Plant Chemistry Program mitigates the aging effects on component surfaces that are

exposed to water as the process fluid; chemistry programs are used to control water chemistry

for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth

and that cause heat transfer degradation due to fouling in select heat exchangers. This

program relies on monitoring and control of water chemistry to keep peak levels of various

contaminants below system-specific limits. The new One-Time Inspection Program is consistent

with the recommendations of GALL AMP XI.M32 and will verify the effectiveness of the Plant

Chemistry Program. The One-Time Inspection Program addresses concerns and provides

confirmation for the potential long incubation period for certain aging effects on SCs. The staff

review determined that the Plant Chemistry Program supplemented by the One-Time Inspection

Program is adequate for managing this material, environment, and aging effect combination.

In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of piping and fittings, and valve

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bodies exposed internally to a treated water environment with the Selective Leaching of

Materials Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement to determine if selective leaching occurs for certain susceptible

components. The staff's program review found management of loss of material due to selective

leaching in LRA Table 3.3.2-7 acceptable.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Plant Chemistry Program combined

with the One-Time Inspection Program, and the Selective Leaching of Materials Program,

effectively manage the aging effects of loss of material due to crevice and pitting corrosion,

MIC, and selective leaching of copper alloy material exposed to a treated water (internal)

environment. On this basis, the staff found management of loss of material due to crevice and

pitting corrosion, MIC, and selective leaching, as given in LRA Table 3.3.2-10, acceptable.

3.3.2.3.11 Auxiliary Systems-Heating and Ventilation-Summary of Aging Management

Evaluation-Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for

the HTV component groups.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting and

crevice corrosion of copper alloy materials for the component types of heaters/coolers, heating,

ventilation, and air conditioning (HVAC) units, piping and fittings, and valve bodies exposed to a

treated water or steam environment with the Closed-Cycle Cooling Water System Program.

The staff reviewed and evaluated the CCCW System Program, as documented in SER

Section 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimize

corrosion and (2) periodic system and component performance testing and inspection to

monitor the effects of corrosion and confirm performance of intended functions. Preventive

measures monitor and control corrosion inhibitors and other chemical parameters like pH, in

accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant

operating experience: As only minor changes were made to the CCCW System Program to

implement EPRI TR-1 007820, the program is also still consistent with the guidelines identified

in GALL AMP XI.M21 (i.e., EPRI TR-1 07396). Periodic inspection and testing to confirm

function and monitor corrosion are also performed in accordance with EPRI TR-1007820,

vendor recommendations, and industry and plant-operating experience. The staff's review

found this AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting and

crevice corrosion and MIC of copper alloy materials for the component types of gauges (flow,

level, and sight), chillers, piping and fittings, and valve bodies exposed to a treated water

environment with the One-Time Inspection Program.

The staff reviewed and evaluated the One-Time Inspection Program, as documented in SER

Section 3.0.3.1.4. The new One-Time Inspection Program is consistent with the

recommendations of GALL AMP XI.M32 and verifies the effectiveness of the Plant Chemistry

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Program and the Fuel Oil Chemistry Program. This program will also confirm the absence of

age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping)

within the scope of license renewal. The One-Time Inspection Program addresses concerns

and provides confirmation for the potential long incubation period for certain aging effects on

SCs. The applicant noted in the LRA that in some cases in which aging effects/mechanisms are

not expected to be significant, the one-time inspection alone is credited with managing them.

The staff's review determined that the use of the One-Time Inspection Program alone is

acceptable in certain cases, such as no-flow conditions, where the CCCW System Program is

not a viable option. The staff's review determined that this AMP is appropriate for the aging

effects/mechanisms identified and assures effective management of them through the period of

extended operation.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of chillers, gauges (flow, level, and

sight), heaters/coolers, HVAC units, piping and fittings, and valve bodies exposed to treated

water, treated water or steam (internal), and wet air/gas (external) environments with the

Selective Leaching of Materials Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement to determine if selective leaching occurs for certain susceptible

components. The staff's review found this AMP adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Closed-Cycle Cooling Water

System Program, One-Time Inspection Program, and Selective Leaching of Materials Program

effectively manage the aging effect of loss of material due to pitting and crevice corrosion, MIC,

and selective leaching of copper alloy material exposed to treated water (internal), treated water

or steam (internal), and wet air/gas (external) environments. On this basis, the staff found that

management of loss of material due to pitting and crevice corrosion, MIC, and selective

leaching in LRA Table 3.3.2-11 is acceptable.

3.3.2.3.12 Auxiliary Systems-Instrument and Service Air System-Summary of Aging

Management Evaluation-Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for

the AIR system component groups.

In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to crevice and

pitting corrosion and MIC of copper alloy materials for the component types of gauges (flow,

level, and sight) and valve bodies exposed to a treated water environment with the CCCW

System Program.

The staff reviewed and evaluated the CCCW System Program, as documented in SER

Section 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimize

corrosion and (2) periodic system and component performance testing and inspection to

monitor the effects of corrosion and confirm performance of intended functions. Preventive

measures monitor and control corrosion inhibitors and other chemical parameters like pH in

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accordance with the guidelines of EPRI TR-1 007820, vendor recommendations, and plant

operating experience. As only minor changes were made to the CCCW System Program to

implement EPRI TR-1007820, the program is also still consistent with the guidelines identified

in GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm

function and monitor corrosion are also performed in accordance with EPRI TR-1 007820,

vendor recommendations, and industry and plant operating experience. The staff's review

found this AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to crevice and

pitting corrosion and MIC of copper alloy materials for the component types of valve bodies

exposed to a gas-compressed air environment with the Compressed Air Monitoring Program.

The staff reviewed and evaluated the Compressed Air Monitoring Program, as documented in

SER Section 3.0.3.2.13. The Compressed Air Monitoring Program consists of inspection,

monitoring, and testing of the AIR system for reasonable assurance that the components will

perform their intended functions for the period of extended operation. With respect to copper

alloy in a gas-compressed air environment, MNGP has chosen, for conservatism, to manage

the AERM as though it were an environment with condensation. The staff's review found this

AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of gauges (flow, level, and sight)

and valve bodies exposed to treated water and gas-compressed air environments with the

Selective Leaching of Materials Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement to determine if selective leaching occurs for certain susceptible

components. The staff's review found this AMP adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Closed-Cycle Cooling Water

System Program, Compressed Air Monitoring Program, and Selective Leaching of Materials

Program effectively manage the aging effect of loss of material due to crevice and pitting

corrosion, MIC, and selective leaching of copper alloy material exposed to treated water

(internal) and gas-compressed air (internal) environments. On this basis, the staff found

management of loss of material due to crevice and pitting corrosion, MIC, and selective

leaching in LRA Table 3.3.2-12 acceptable.

3.3.2.3.13 Auxiliary Systems-Radwaste Solid and Liquid System-Summary of Aging

Management Evaluation-Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for

the radwaste solid and liquid system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.3.2.3 above.

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3.3.2.3.14 Auxiliary Systems-Reactor Building Closed Cooling Water System-Summary of

Aging Management Evaluation-Table 3.3.2-14

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for

the RBC system component groups.

In LRA Table 3.3.2-14, the applicant proposed to manage loss of material due to crevice and

pitting corrosion and MIC of copper alloy materials for component types of piping and fittings

and valve bodies exposed to a treated water environment with the CCCW System Program.

The staff reviewed and evaluated the CCCW System Program, as documented in SER

Section 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimize

corrosion and (2) periodic system and component performance testing and inspection to

monitor the effects of corrosion and confirm performance of intended functions. Preventive

measures monitor and control corrosion inhibitors and other chemical parameters like pH, in

.accordance with the guidelines of EPRI TR-1 007820, vendor recommendations, and plant

operating experience. As only minor changes were made to the CCCW System Program to

implement EPRI TR-1 007820, the program is also -still consistent with the guidelines identified

in GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm

function and monitor corrosion are also performed in accordance with EPRI TR-1 007820,

vendor recommendations, and industry and plant operating experience. The staff's review

found this AMP adequate for managing this material, environment, and aging effect.

In LRA Table 3.3.2-14, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of piping and fittings and valve

bodies exposed to a treated water environment with the Selective Leaching of Materials

Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement to determine if selective leaching occurs for certain susceptible

components. The staff's review found this AMP adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Closed-Cycle Cooling Water

System Program and Selective Leaching of Materials Program effectively manage the aging

effect of loss of material due to crevice and pitting corrosion, MIC, and selective leaching of

copper alloy material exposed to a treated water (internal) environment. On this basis, the staff

found that management of loss of material due to crevice and pitting corrosion, MIC, and

selective leaching, as given in LRA Table 3.3.2-14, is acceptable.

3.3.2.3.15 Auxiliary Systems-Reactor Water Cleanup System-Summary of Aging

Management Evaluation-Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for

the RWCU system component groups.

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All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.3.2.3 above.

3.3.2.3.16 Auxiliary Systems-Service and Seal Water System-Summary of Aging

Management Evaluation-Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for

the service and seal water system component groups.

RAIs 3.3.2.3-3 and 3.3.2.3-4 discuss the staff evaluation with respect to aging effects for rubber

expansion joints exposed to plant indoor air and raw water environments in the service and seal

water system.

Based on the RAI evaluations, the staff found that the applicant has identified the appropriate

AMP for the materials and environments associated with the above components in the service

and seal water system. All other line items in this table are consistent with the GALL Report or

are included in the discussion in Section 3.3.2.3 above.

3.3.2.3.17 Auxiliary Systems-Standby Liquid Control System-Summary of Aging

Management Evaluation-Table 3.3.2-17

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for

the SLC system component groups.

RAI 3.3.2.3-5 discusses the staff evaluation with respect to aging effects for rubber

accumulators exposed to nitrogen gas and plant indoor air environments in the SLC system.

Based on the evaluation of the response to the above RAI, the staff found that applicant has

identified the appropriate AMP for the materials and environments associated with the above

components in the SLC system. All other line items in this table are consistent with the GALL

Report or are included in the discussion in Section 3.3.2.3 above.

3.3.2.3.18 Auxiliary Systems-Wells and Domestic Water System-Summary of Aging

Management Evaluation-Table 3.3.2-18

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for

the wells and domestic water system component groups.

In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevice and

pitting corrosion, MIC, and erosion of copper alloy materials for the component types of piping

and fittings and valve bodies exposed to a raw water environment with the One-Time Inspection

Program.

The staff reviewed and evaluated the One-Time Inspection Program, as documented in SER

Section 3.0.3.1.4. The new One-Time Inspection Program is consistent with the

recommendations of GALL AMP XI.M32 and will confirm the absence of age degradation in

selected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of

license renewal. The One-Time Inspection Program addresses concerns and provides

confirmation for the potential long incubation period for certain aging effects on SCs. The

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applicant has noted in the LRA that in some cases in which aging effects/mechanisms are not

expected to be significant, the One-Time Inspection Program alone is credited with managing

aging effects. The staff determined that the use of the One-Time Inspection Program alone is

acceptable where the use of the Plant Chemistry Program is not a viable option. This AMP is

appropriate for the aging effects/mechanisms identified and assures effective management of

them through the period of extended operation.

In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevice

corrosion, pitting corrosion, and MIC of Hastelloy (C-276) material for the component types of

piping and fittings exposed to a raw water environment using the One-Time Inspection

Program. In addition, the applicant stated that Hastelloy (C-276) in a concrete or plant indoor air

environment has no AERM and therefore requires no AMP.

The staff determined that Hastelloy (C-276) is a highly corrosion-resistant material, and

degradation is not expected in typical domestic water applications. Hastelloy (C-276) piping and

fitting material exposed to concrete or an air environment in the absence of moisture with

contaminants has no aging effects and requires no aging management. Similarly, degradation

of Hastelloy (C-267) in a raw water internal environment is not expected. It is conservative to

assume loss of material due to crevice and pitting corrosion and MIC in this environment with

the potential for unknown contaminants. The staff's review found the One-Time Inspection

Program adequate to manage the aging effects of this corrosion-resistant material in this

environment to confirm that degradation is not occurring.

In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to selective

leaching of copper alloy materials for the component types of piping and fittings and valve

bodies exposed to a raw water environment with the Selective Leaching of Materials Program.

The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented

in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and

hardness measurement to determine if selective leaching occurs for certain susceptible

components. The staff's review found this AMP adequate for managing this material,

environment, and aging effect.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the One-Time Inspection Program and

Selective Leaching of Materials Program effectively manage the aging effect of loss of material

due to crevice and pitting corrosion, MIC, erosion, and selective leaching of copper alloy

material exposed to a raw water (internal) environment. On this basis, the staff found

management of loss of material due to crevice and pitting corrosion, MIC, erosion, and selective

leaching, as given in LRA Table 3.3.2-18, acceptable.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERM, and AMP combinations that are not

evaluated in the GALL Report. The staff found that the applicant has demonstrated that the

aging effects will be adequately managed so that intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.3.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

aging effects for the auxiliary systems components that are within the scope of license renewal

and subject to an AMR will be adequately managed so that intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited with managing aging of the auxiliary systems,

as required by 10 CFR 54.21 (d).

3.4 Aging Management of Steam and Power Conversion System

This section of the SER documents the staff's review of the applicant's AMR results for the SPC

system components and component groups associated with the following systems:

" condensate storage system

* condensate and feedwater system

" main condenser system

" main steam system

" turbine generator system

3.4.1 Summary of Technical Information in the Application

In LRA Section 3.4, the applicant provided AMR results for the SPC system components and

component groups. In LRA Table 3.4.1, the applicant provided a summary comparison of its

AMRs with the AMRs evaluated in the GALL Report for the SPC system components and

component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the SPC system components that are within the

scope of license renewal and subject to an AMR will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

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presented in the LRA is applicable and that the applicant identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, which are summarized in SER

Section 3.4.2.1.

The staff also performed an onsite audit of those selected AMRs that are consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations are consistent with the acceptance criteria in SRP-LR

Section 3.4.2.2. The MNGP audit and review report documents the staff's audit evaluations,

which are summarized in SER Section 3.4.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified all plausible aging effects and

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The MNGP audit and review report documents the staff's audit

evaluations. SER Section 3.4.2.3 summarizes these audit evaluations and documents the

staff's evaluation of its technical review.

Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

SPC system components.

Table 3.4-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.4 that are addressed in the GALL Report.

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System

the GALL Report

Components in

Com onent Group Agi:ng Effect/ AMP in GALL AM : 1 P in. LA: Staff Evaluation

Mechanism Report ________ _______

Piping and fittings in Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

main feedwater line, damage accordance with evaluated in Section

steamline and AFW 10 CFR 54.21(c) 4.3, Metal Fatigue

piping (PWR only) of the RPV and

(Item Number Internals, and

3.4.1-01) Reactor Coolant

Pressure Boundary

Piping and

Components (see

Section 3.4.2.2.1)

Piping and fittings, Loss of material Water chemistry, One-Time Consistent with

valve bodies and due to general one-time inspection Inspection Program GALL Report, which

bonnets, pump (carbon steel only), (B2.1.23), Plant recommends further

casings, tanks, pitting, and crevice Chemistry Program evaluation (see

tubes, tubesheets, corrosion (82.1.25) Section 3.4.2.2.2)

channel head and

shell (except main

steam system)

(Item Number

3.4.1-02)

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Component Group Aging Effect/ AMPlin GALL AMP In LRA Staff Evaluation

Mechanism Report

Auxiliary feedwater Loss of material Plant specific Not applicable,

(AFW) piping due to general, PWR only (see

(Item Number pitting, and crevice Section 3.4.2.2.3)

3.4.1-03) corrosion, MIC, and

biofouling

Oil coolers in AFW Loss of material Plant specific Not applicable,

system (lubricating due to general PWR only (see

oil side possibly (carbon steel only), Section 3.4.2.2.3)

contaminated with pitting, and crevice

water) corrosion and MIC

(Item Number

3.4.1-04)

External surface of Loss of material Plant specific System Condition Consistent with

carbon steel due to general Monitoring Program GALL Report, which

components corrosion (82.1.32) recommends further

(Item Number evaluation (see

3.4.1-05) Section 3.4.2.2.4)

Carbon steel piping Wall thinning due to Flow-accelerated Flow-Accelerated Consistent with

and valve bodies flow-accelerated corrosion Corrosion Program GALL Report, which

(Item Number corrosion (B2.1.19) recommends no

3.4.1-06) further evaluation

Carbon steel piping Loss of material Water chemistry Plant Chemistry This line item was

and valve bodies in due to pitting and Program (B2.1.25), not used at MNGP.

main steam system crevice corrosion One-Time See Item Number

(Item Number Inspection (B2.1.23) 3.4.1-02

3.4.1-07)

Closure bolting in Loss of material Bolting integrity Bolting Integrity Consistent with

high-pressure or due to general Program (82.1.4) GALL Report, which

high-temperature corrosion; crack recommends no

systems initiation and growth further evaluation

(Item Number due to cyclic

3.4.1-08) loading and/or SCC

Heat exchangers Loss of material Open-cycle cooling Not applicable (see

and due to general ,water system Section 3.4.2.1.1)

coolers/condensers (carbon steel only),

serviced by pitting, and crevice

open-cycle cooling corrosion, MIC, and

water biofouling; buildup

(Item Number of deposit due to

3.4.1-09) biofouling

Heat exchangers Loss of material Closed-cycle Not applicable.

and due to general cooling water No heat exchangers

coolers/condensers (carbon steel only), system serviced by

serviced by pitting, and crevice closed-cycle cooling

closed-cycle cooling corrosion water

water

(Item Number

3.4.1-10) 1

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism Report _ _ _ ,

External surface of Loss of material Above ground Not applicable.

aboveground due to general carbon steel tanks MNGP condensate

condensate storage (carbon steel only), storage tanks are

tank pitting, and crevice not within the scope

(Item Number corrosion of license renewal

3.4.1-11)

External surface of Loss of material Buried piping and Buried Piping & Emergency diesel

buried condensate due to general, tanks surveillance Tanks Inspection generators system

storage tank and pitting, and crevice Program (B2.1.5) oil storage tank

AFW piping corrosion and MIC or external surface is

(Item Number managed by the

3.4.1-12) Buried piping and Buried Piping &

tanks inspection Tanks Inspection

Program

External surface of Loss of material Boric acid corrosion Not applicable,

carbon steel due to boric acid PWR only

components corrosion

(Item Number

3.4.1-13)

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in SER Section 3.4.2.1, involves the staff's review of the AMR results

for components in the SPC system that the applicant indicated are consistent with the GALL

Report and do not require further evaluation. Another approach, documented in SER

Section 3.4.2.2, involves the staff's review of the AMR results for components in the SPC

system that the applicant indicated are consistent with the GALL Report and for which further

evaluation is recommended. A third approach, documented in SER Section 3.4.2.3, involves the

staff's review of the AMR results for components in the SPC system that the applicant indicated

are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents

the staff's review of AMPs that are credited to manage or monitor aging effects of the SPC

system components.

3.4.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the SPC system components:

• Bolting Integrity Program (B2.1.4)

• Flow-Accelerated Corrosion Program (B2.1.19)

* One-Time Inspection Program (B2.1.23)

* Open-Cycle Cooling Water System Program (B2.1.24)

* Plant Chemistry Program (B2.1.25)

* Selective Leaching of Materials Program (B2.1.30)

* System Condition Monitoring Program (B2.1.32)

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Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant summarized the AMRs

for the SPC system components, and identified which AMRs it considered to be consistent with

the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes described how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it had reviewed and accepted the identified exceptions

to the GALL Report AMPs. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant could not find

a listing of some system components in the GALL Report. However, the applicant identified a

different component in the GALL Report that has the same material, environment, aging effect,

and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component applies to the component under review and whether the AMR is valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component applies to the component under review. The staff verified that it had reviewed and

accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

these line items to verify consistency with the GALL Report. The staff also determined whether

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the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report. The staff did not repeat its review of the matters

described in the GALL Report; however the staff did verify that the material presented in the

LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The

following sections discuss the staff's evaluation.

3.4.2.1.1 Loss of Material Due to General, Pitting, and Crevice Corrosion, MIC, and

Biofouling; Buildup of Deposit Due to Biofouling

In LRA Table 3.4.1, Item 3.4.1-09, the applicant addressed the loss of material due to general,

pitting, and crevice corrosion, MIC, and biofouling, and buildup of deposit due to biofouling for

heat exchangers and coolers/condensers serviced by OCCW. The applicant stated that Item

3.4.1-09 does not apply. The applicant stated that the management of aging effects of certain

components of the CDR with the intended function of plateout and holdup of radioactive

material is not applicable because the CDR structural integrity is demonstrated continuously

during normal plant operation.

During the audit and review, the staff noted that in LRA Table 3.4.2-3 the applicant presented

its AMR results for the CDR system. In the table, the applicant claimed consistency with the

GALL Report for aging management of the internal and external surfaces of the carbon steel

condenser shell. The table cited generic Note E (i.e., the component, material, and environment

are consistent with the GALL Report recommendation but the applicant applied a different

AMP). However, the applicant claimed that an AMP is not required and referenced

plant-specific Note 410. The staff questioned the applicant's use of Note E for these AMR

entries as no AMP is credited.

In response, the applicant stated that the structural integrity of the CDR required to perform its

post-accident intended function is demonstrated continuously during normal plant operation;

therefore, no traditional AMP is required. The post-accident intended function of the CDR is to

provide a holdup volume and plateout surface for MSIV leakage. This intended function does

not require the CDRs to be leak tight because the post-accident conditions in the CDRs are

essentially atmospheric and there will be no challenge to their pressure boundary integrity.

Normal plant operation assures adequate CDR pressure boundary integrity and the

post-accident intended function to provide pressure boundary and holdup volume and plateout

surface.

The staff noted that SRP-LRSection A. 1.2.3.4 states that a program based solely on detecting SC failures is not considered an effective AMP. The staff then reviewed the applicant's

justification and asked it to clarify why it had described no AMP for these components.

The applicant stated that radioactive iodine is assumed to plate out on the interior surfaces of

the CDR for both loss of coolant and control rod drop accidents. Aging management is not

required for the CDR components that have only a plateout and holdup of radioactive material

intended function. For these components, the aging effects do not require aging management

as the condenser surface condition does not affect the deposition of iodine in the CDR. To

maintain the intended function, the CDR and the components which make up the CDR complex

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simply have to remain intact. Condenser structural integrity is demonstrated continuously during

normal operation when the condenser is required to maintain vacuum. When the condenser is

required to perform its intended function following a DBA, the MSIVs will be closed and

condenser vacuum will be lost. The condenser will not be required to perform a pressure

boundary function because essentially atmospheric conditions will exist inside the condenser.

Since normal performance considerations, such as fouling and in-leakage (e.g., CWT or air

leaks), place greater requirements on condenser operation than the post-accident plateout,

then, as long as the condenser is intact and operational, the post-accident plateout and holdup

of radioactive material will be maintained and no aging management is required.

Additionally, as documented in its August 31, 2005, letter, the applicant revised plant-specific

Note 410 to clarify the discussion of the intended function of the CDR:

No traditional aging management of the main condenser for plateout and holdup

is required. The main condenser is required to perform a post-accident intended

function of plateout and holdup. This post-accident intended function does not

require the main condenser to be leak tight and post-accident conditions in the

main condenser would be essentially atmospheric. During normal plant

operation, the main condenser continuously verifies its structural integrity by

maintaining condenser vacuum that is constantly monitored and provides

assurance that it will perform its post-accident intended function of iodine

plateout and holdup.

The staff's review of the applicant's response found that the CDR need not be leak-tight, as

post-accident conditions in the CDR are essentially atmospheric. During normal plant

operations, the applicant continuously monitors condenser vacuum to verify the integrity of the

CDR. Degradation of its integrity to a loss of vacuum will require placement of the plant in a

mode that will obviate the post-accident intended function; therefore, acceptable performance

during normal plant operation is adequate assurance that the CDR can perform the holdup and

plateout post-accident function.

On this basis, the staff found that the applicant appropriately addressed the aging effect and

mechanism as identified in the GALL Report.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. The staff's review concluded

that the AMR results, which the applicant claimed to be consistent with the GALL Report, are

consistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicant

has demonstrated that the aging effects for these components will be adequately managed so

that their intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section-3.4.2.2 the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

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SPC system components. The applicant provided information concerning how it will manage the

following aging effects:

" cumulative fatigue damage

* loss of material due to general, pitting, and crevice corrosion

" loss of material due to general, pitting, and crevice corrosion, microbiologically

influenced corrosion, and biofouling

" general corrosion

* loss of material due to general, pitting, crevice, and microbiologically influenced

corrosion

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addressed the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in SRP-LR

Section 3.4.2.2. The staff's audit and review report details the staff's audit. The following

sections discuss the staff's evaluation of the aging effects.

3.4.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2.

In LRA Section 3.4.2.2.2 the applicant addressed loss of material due to general, pitting, and

crevice corrosion of carbon steel and cast iron piping and fittings, valve bodies and bonnets,

pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells

except for MST system components in the SPC system. This section also addresses loss of

material due to pitting and crevice corrosion of stainless steel components in the SPC system.

SRP-LR Section 3.4.2.2.2 states the following:

The management of loss of material due to general, pitting, and crevice

corrosion should be evaluated further for carbon steel piping and fittings, valve

bodies and bonnets, pump casings, pump suction and discharge lines, tanks,

tubesheets, channel heads, and shells except for main steam system

components and for loss of material due to pitting and crevice corrosion for

stainless steel tanks and heat exchanger/cooler tubes. The water chemistry

program relies on monitoring and control of water chemistry based on the

guidelines in BWRVIP-29 (EPRI guideline TR-1 03515) for water chemistry to

manage the effects of loss of material due to general, pitting, or crevice

corrosion. However, corrosion may occur at locations of stagnant flow conditions.

Therefore, the effectiveness of the chemistry control program should be verified

to ensure that corrosion is not occurring. The GALL Report recommends further

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evaluation of programs to manage loss of material due to general, pitting, and

crevice corrosion to verify the effectiveness of the water chemistry program. A

one-time inspection of select components and susceptible locations is an

acceptable method to ensure that corrosion is not occurring and that the

component's intended function will be maintained during the period of extended

operation.

In LRA Section 3.4.2.2.2, the applicant stated that the One-Time Inspection Program and Plant

Chemistry Program manage the aging effect. Exceptions apply to GALL Report

recommendations for the Plant Chemistry Program implementation (refer to LRA

Section B2.1.25). The One-Time Inspection Program is a new AMP. The scope of this new

AMP will incorporate activities to verify the effectiveness of the Plant Chemistry Program,

including a sample of components where the flow of water is low or stagnant conditions exist

(refer to LRA Section B2.1.23). Implementation of the One-Time Inspection Program, in

conjunction with the Plant Chemistry Program, to manage the aging effect provides added

assurance that the aging effect is not occurring at locations of stagnant or low flow; or that the

aging effect is progressing very slowly such that the component's intended function will be

maintained during the period of extended operation.

The applicant stated in the LRA that the Plant Chemistry Program manages the loss of material

for carbon and stainless steel components in SPC systems, and that a one-time inspection of

selected components and susceptible locations will verify the efficacy of that program. SER

Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluations of the Plant Chemistry

Program and One-Time Inspection Program, respectively.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.4.2.2.2. For those line items that apply to LRA Section 3.4.2.2.2, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion, and Biofouling

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.

In LRA Section 3.4.2.2.3, the applicant stated that this aging effect applies to PWRs only.

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and biofouling could occur in carbon steel piping and fittings for untreated water

from the backup water supply in the PWR auxiliary FW (AFW) system. SRP-LR Table 3.3-1

states that further evaluation for this aging effect is for PWR plants only.

The staff found that this aging effect is not applicable at MNGP.

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3.4.2.2.4 General Corrosion

The staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4.

In LRA Section 3.4.2.2.4 the applicant addressed loss of material due to general corrosion on

the external surfaces of carbon steel and cast iron components of the SPC system in air/gas

environments.

SRP-LR Section 3.4.2.2.4 states the following:

Loss of material due to general corrosion could occur on the external surfaces of

all carbon steel structures and components, including closure bolting, exposed to

operating temperature less that 212 OF. The GALL Report recommends further

evaluation to ensure that this aging effect is adequately managed.

In LRA Section 3.4.2.2.4, the applicant stated that the System Condition Monitoring Program

manages the loss of material for carbon steel and cast iron components in SPC systems. The

System Condition Monitoring Program manages the aging effect on the external surfaces of

carbon steel and cast iron components in air/gas environments. Management of the aging

effect associated with certain components of the CDR with the plateout and holdup of

radioactive material intended function is not applicable, as the CDR structural integrity is

demonstrated continuously during normal plant operation. As documented in its August 31,

2005, letter, the applicant stated that it will revise the LRA to eliminate reference to the pressure

boundary function of the CDRs as this function is inappropriate for these components. The

System Condition Monitoring Program is an existing plant-specific program that manages aging

effects for normally accessible external surfaces of piping, tanks, and other components and

equipment within the scope of license renewal through visual inspection and monitoring of

external surfaces for leakage and evidence of material degradation. Implementation of the

System Condition Monitoring Program to manage corrosion adds assurance that corrosion

does not occur and that the aging effect progresses so slowly that the component's intended

function will be maintained during the period of extended operation. SER Section 3.0.3.3.2

documents the staff's review of the applicant's System Condition Monitoring Program.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.4.2.2.4. For those line items that apply to LRA Section 3.4.2.2.4, the staff determined

that the applicant's AMRs are consistent with the GALL Report and the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

The staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR Section 3.4.2.2.5.

The applicant stated in LRA Section 3.4.2.2.5.2 that MNGP CSTs are not SR and therefore not

within the scope of licensing renewal. The applicant also stated in LRA Section 3.4.2.2.5.2 that

MNGP has no underground CSTs.

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Because the applicant has no components from this group, the staff concurred with the

applicant's determination that this aging effect is not applicable.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the issues that were further evaluated. The staff found that the applicant has

demonstrated that the aging effects will be adequately managed so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.4.2-1 through 3.4.2-5,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report and provided information concerning how it will manage the aging

effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the

AMR'line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination is not applicable. Note J

indicates that the GALL Report does not evaluate either the component or the material and

environment combination for the line item.

Staff Evaluation. For component type, material, and environment combinations that the GALL

Report does not evaluate, the staff reviewed the applicant's evaluation to determine whether the

applicant demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB during the period of extended

operation. This section addresses AMR results for which LRA Tables 3.4.2-1 through 3.4.2-5

identified no aging effects. The discussion on each table addresses the other line items that are

not consistent with the GALL Report or not addressed in the GALL Report. The following

sections discuss the staff's evaluation.

In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant identified AMR line items for which the

aging review process identified no aging effects. Specifically, the applicant identified no aging

effects for components fabricated from stainless steel and rubber materials that are exposed to

a primary containment air, plant indoor air, instrument air, or gas environment or for

components fabricated from carbon steel or stainless steel that are exposed to a lubricating oil

environment. The applicant stated that a materials science evaluation for these materials in

these environments discovered no aging effects.

Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence of

corrosive species, as cited in the Metals Handbook, Ninth Edition, the staff agreed that stainless

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steel in an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment

(e.g., primary containment air inerted with nitrogen) exhibits no aging effect and that the SC will,

therefore, remain capable of performing its intended functions consistent with the CLB for the

period of extended operation. In addition, because both oxygen and moisture must be present

to corrode steel, as cited in the Metals Handbook, the staff agreed that carbon steel or stainless

steel in a lubricating oil internal environment with no water pooling exhibits no aging effect and

that the SC will, therefore, remain capable of performing its intended functions consistent with

the CLB for the period of extended operation.

As listed in the GALL Report, rubber that is not in an environment of elevated temperature (i.e.,

above 95 OF (35 °C)) with additional factors such as exposure to ozone, oxidation, and radiation

will remain capable of performing intended functions consistent with the CLB for the period of

extended operation. Because specific ozone concentrations could not be determined, by letter

dated November 17, 2005, the applicant stated that it will manage change in material properties

due to ozone for elastomers in an external air environment using the System Condition

Monitoring Program. SER Section 3.4.2.3.3 documents the staff's evaluation.

The staff's review of current industry research and operating experience found that plant indoor

air, primary containment air, instrument air on stainless steel, or lubricating oil on stainless steel

or carbon steel will not result in aging of concern during the period of extended operation;

therefore, the staff concluded that the component, material, and environment combinations

described in the preceding discussion have no applicable AERMs.

The staff's review of current industry research and operating experience found that-the

applicant demonstrated that no aging effects are predicted for the material and environmental

combinations reported and that the SPC system components fabricated from these materials in

the environments listed above will maintain their intended functions consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.1 Steam and Power Conversion System-Condensate Storage System-Summary of

Aging Management Evaluation-Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the

condensate storage system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.4.2.3 above.

3.4.2.3.2 Steam and Power Conversion System-Condensate and Feedwater

System-Summary of Aging Management Evaluation-Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the

condensate and FW system component groups.

In LRA Table 3.4.2-2, the applicant proposed to manage cracking and change in material

properties due to thermal exposure of rubber materials for the component types of expansion

joints exposed to a treated water (internal) environment using the One-Time Inspection

Program. I

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SER Section 3.0.3.1.4 documents the staff's review of the One-Time Inspection Program. The

One-Time Inspection Program is a new program consistent with the recommendations of GALL

AMP XI.M32". This program will include measures to verify the effectiveness of the Plant

Chemistry Program and the Fuel Oil Chemistry Program and also will confirm the absence of

age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping)

within scope of license renewal. The One-Time Inspection Program, addresses concerns and

provides confirmation for the potential long incubation period for certain aging effects on SCs.

The applicant has noted in the LRA that in some cases in which aging effects/mechanisms are

not expected to be significant, the One-Time Inspection Program alone is credited with

managing aging effects. The staff's review determined that the use of the One-Time Inspection

Program alone is acceptable in certain cases in which the use of the Plant Chemistry Program

is not a viable option. This AMP is appropriate for the aging effects/mechanisms identified and

assures effective management of the aging effects through the period of extended operation. I

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the One-Time Inspection Program effectively

manages the aging effects of cracking and change in material properties due to thermal

exposure of rubber material exposed to a treated water (internal) environment. On this basis,

the staff found that management of cracking due to thermal exposure, as given in LRA

Table 3.4.2-2, is acceptable.

3.4.2.3.3 Steam and Power Conversion System-Main Condenser System-Summary of

Aging Management Evaluation-Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the

CDR system component groups.

In Table 3.4.2-2, the applicant identified no AERMs for rubber expansion joints intended to

maintain the pressure boundary function in a plant indoor air environment. The applicant stated

that the GALL Report does not evaluate either the components or the material and environment

combination. The applicant further stated that these elastomer components (e.g., neoprene,

rubber) are indoors and not subject to UV rays or ozone, nor are they in locations subject to

radiation exposure or to temperatures at which changes in material properties or cracking could

occur (>95 OF); therefore, the applicant contended that no aging management is required. In

industry experience, however, elastomeric expansion joints degrade due to oxidation in

environments that are not necessarily harsh, as discussed in EPRI Report 1008035 and EPRI

Report 1007933.

The staff's review of LRA Section 3.4 identified areas for which it needed additional information

to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs

as discussed below.

In RAI 3.4-1, dated July 20, 2005, the staff requested that the applicant discuss its inspection

procedures for the rubber expansion joints related to preventive maintenance, for both external

and internal surfaces of the elastomer.

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In its response, by letter dated August 16, 2005, the applicant stated the following:

EPRI Report 1008035, 'Expansion Joint Maintenance Guide,' Revision 1,

May 2003, Table 5-4, rates elastomers against oxidation, tensile strength, and

radiation. Elastomers, such as Neoprene, Natural Rubber, Chlorobutyl, Buna-N,

Viton, and EPDM, are rated as good or better in the categories of oxidation,

tensile strength, and radiation.

EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003,

pages 60 through 65, lists oxidation as a degradation mechanism brought on by

the stressors: Thermal, Radiation, and Ultraviolet. As stated in the first

paragraph of the question, these elastomers are not exposed to these stressors.

Since these elastomers are not exposed to ultraviolet, radiation, or temperatures

>95 degrees F, they are therefore not susceptible to oxidation and no aging

management is required.

In addition, the applicant referred to a related response to RAI 3.3.2.3-3, which addresses the

oxidation effects and degradation of elastomers due to thermal, irradiation, and UV exposure.

The staff also noted that the applicant's response to RAI 3.3.2.3-4, dated August 16, 2005, had

not addressed degradation of rubber by oxidation resulting from exposure to ozone in air. The

staff asked the applicant to provide the specific designation of the types of elastomers installed

at the plant and the data related to exposure to ozone in air for each type, if available. In

addition, the staff asked the applicant to explain its method for evaluating degradation caused

by oxidation from exposure to ozone.

The staff was concerned that some of the elastomers in question may not be long-lived

components designed for 60 years. The applicant's response had not clearly stated that these

components are not long-lived and are replaced at specified intervals. The staff asked the

applicant to confirm this and provide supporting data.

In its response, by letter dated November 17, 2005, the applicant stated the following:

After further evaluation of this issue, NMC has taken the conservative approach

of managing change in material properties due to ozone for elastomers in an air

environment, specifically for natural rubber. This is a result of the fact that

neither representative ozone concentrations nor technically substantiated

thresholds could be adequately or consistently determined, even though plant

specific operating experience has indicated that there has been no change in

material properties due to ozone for these elastomer components. Further

evaluation also revealed the inability to confirm that none of these components

are fabricated from natural rubber.

As a result, elastomers in an external air environment in the following LRA tables

will utilize the System Condition Monitoring Program to manage the potential

aging effect of changes in material properties due to ozone which shall be

assigned to these components.

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* Table 3.3.2-3 expansion joints in the Circulating Water System

* Table 3.3.2-5 piping and fittings in the Demineralized Water System

* Table 3.3.2-6 piping and fittings in the Emergency Diesel Generators

System

" Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System

" Table 3.3.2-16 expansion joints in the Service and Seal Water System

" Table 3.4.2-2 expansion joints in the Condensate and Feedwater System

(those which were not previously managed externally)

Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary Containment

System) are presently being managed utilizing the One-Time Inspection

Program for the internal surfaces and the System Condition Monitoring Program

for the external surfaces. These Aging Management Programs (AMPs) were

initially credited to manage change in material properties and cracking due to

thermal exposure, since a temperature threshold of greater than 95 OF was

assigned to these components. Consequently, these same AMPs will also

manage change in material properties due to ozone which shall be assigned to

these components.

Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do not

require aging management since these components do not serve a pressure

boundary intended function but provide for plate-out and holdup of radioactive

material during design basis events. Condenser integrity is continuously

demonstrated during normal plant operation thus validating that this intended

function is maintained as stated in the plant-specific notes for these components

in Section 3.4 of the LRA.

Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings in

the Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation seals

in the Emergency Filtration Train System) will utilize the One-Time Inspection

Program to manage the potential aging effect of change in material properties

due to ozone which shall be assigned to these components.

Elastomers in both an internal and external air environment in Table 3.3.2-11

(ventilation seals in the Heating and Ventilation System) were inadvertently

omitted from this table. These components shall be managed for the potential

aging effect of change in material properties due to ozone utilizing the One-Time

Inspection Program for the internal surfaces and the System Condition

Monitoring Program for the external surfaces which shall be assigned to these

components.

All the elastomers addressed are long-lived components. Any component that is

not long-lived and replaced at specified intervals is eliminated from AMR

consideration during the screening process. Although the expansion joints are

presently under review for replacement on a fixed periodicity, this change has

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not been effected and they remain as and have been analyzed as long-lived

components.

Any degradation of elastomer components in an air environment resulting from

change in material properties due to ozone for the external surfaces of these

components shall be evaluated as discussed in the response to RAI B2.1.32-02

which addresses the System Condition Monitoring AMP.

The staff's review found the applicant's response acceptable, because the applicant added the

System Condition Monitoring and One-Time Inspection Programs for the management of aging

effects in elastomers. The applicant also satisfactorily addressed the staff's concern related to

long-lived components. SER Sections 3.0.3.3.2 and 3.0.3.1.4 document the staff reviews of the

System Condition Monitoring and One-Time Inspection Programs, respectively; therefore, the

staff's concern described in RAI 3.3.2.3-4 is resolved.

In RAI 3.4-2, dated July 20, 2005, the staff noted that in LRA Table 3.4.2-3 the applicant

identified the aging effects of changes in material properties and cracking due to irradiation and

thermal exposure for rubber expansion joints in an internal steam environment. The intended

function of the expansion joints is to maintain holdup of radioactive material. The applicant

stated that the GALL Report does not evaluate either the components or the material and

environment combination. The applicant further stated that the aging effect/mechanism is

applicable but requires no management as the intended function for this component is

post-accident iodine plateout and holdup. According to the applicant, CDR structural integrity is

continuously demonstrated during normal plant operation, thus maintaining the intended

function; however, the staff position is that this component type (rubber expansion joint) is

within the scope of license renewal and its aging effects should be managed. The staff

requested that the applicant provide the appropriate AMP to manage the aging effects of

changes in material properties and cracking due-to irradiation and thermal expansion of the

rubber expansion joints in a steam environment.

In its response, by letter dated August 16, 2005, the applicant further demonstrated that the

post-accident plateout and holdup of radioactive material intended function will be maintained

and no aging management is required. The applicant stated the following:

For both a Loss of Coolant Accident (LOCA) and a Control Rod Drop

Accident (CRDA), radioactive iodine is assumed to be held up and plate-out on

the interior surfaces of the main condenser. 'Plate-out and holdup of radioactive

material' is the only intended function assigned to the main condenser expansion

joints.

Aging management is not required for the main condenser components that

have only a plate-out and holdup of radioactive material intended function. For

these components, the aging effects do not require aging management because

the deposition of iodine in the main condenser is unaffected by the condenser

surface condition. To maintain the intended function, the main condenser and

the components, which make up the main condenser complex, simply have to

remain intact.

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Condenser structural integrity is continuously demonstrated during normal

operation when the condenser is required to maintain vacuum. Following a

design basis accident, when the condenser is required to perform its intended

function, the main steam isolation valves will be closed and vacuum will be lost.

The condenser will not be required to perform a pressure boundary function

because atmospheric conditions will exist inside the condenser.

Since normal performance considerations such as fouling and in-leakage (e.g.,

circulating water or air leaks) place greater requirements on condenser operation

than the post-accident plate-out, then as long as the condenser is intact and

operational, the post-accident plate-out and holdup of radioactive material

intended function will be maintained and no aging management is required.

The staff's review found the applicant's response to RAI 3.4-2 acceptable because the

condenser is likely to remain operational following a DBA as well as during normal operation,

and no aging management is required; therefore, the staff's concern described in RAI 3.4-2 is

resolved.

3.4.2.3.4 Steam and Power Conversion System-Main Steam System-Summary of Aging

Management Evaluation-Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the

MST system component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.4.2.3 above.

3.4.2.3.5 Steam and Power Conversion System-Turbine Generator System-Summary of

Aging Management Evaluation-Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the

turbine generator system component groups.

In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to selective

leaching of cast iron materials for the component types of steam traps exposed to a treated

water or steam (internal) environment, or for copper alloy component types of heat exchangers

exposed to a wet air or gas environment, or for component types of piping and fittings exposed

to a raw water environment, using the Selective Leaching of Materials Program.

SER Section 3.0.3.2.22 documents the staff's review and evaluation of the applicant's Selective

Leaching of Materials Program. The Selective Leaching of Materials Program includes a

one-time visual inspection and hardness measurement of certain components susceptible to

selective leaching. In situations in which hardness testing is not practical, the applicant will use

a qualitative approach by other NDE or metallurgical methods to determine the presence and

extent of selective leaching. The program will determine if selective leaching occurs for certain

components and ensure the integrity of components made of gray cast iron, bronze, brass, and

other alloys exposed to a raw water, treated water, or ground-water environment that may

cause selective leaching of one of the metal components. The staff's review found this AMP

adequate for managing this material, environment, and aging effect combination.

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In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to MIC, pitting,

and crevice corrosion of copper alloy materials for the component types of gauges, piping and

fittings, and valve bodies exposed to a treated water (internal) environment using the One-Time

Inspection Program and the Plant Chemistry Program.

SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's reviews of the applicant's Plant

Chemistry Program and the One-Time Inspection Program, respectively. The Plant Chemistry

Program mitigates the aging effects on component surfaces that are exposed to water as the

process fluid; chemistry programs are used to control water chemistry for impurities (e.g.,

chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat

transfer degradation due to fouling in select heat exchangers. This program relies on monitoring

and control of water chemistry to keep peak levels of various contaminants below

system-specific limits. The One-Time Inspection Program is a new program consistent with the

recommendations of GALL AMP XI.M32 and verifies the effectiveness of the Plant Chemistry

Program. The One-Time Inspection Program addresses concerns and provides confirmation for

the potential long incubation period for certain aging effects on SCs. The staff review

determined that the Plant Chemistry Program supplemented by the One-Time Inspection

Program is adequate for managing these combinations of material, environment, and aging

effects.

In LRA Table 3.4.2-5, the applicant proposed to manage loss of material due to MIC, pitting,

and crevice corrosion of copper alloy materials for the component types of heat exchangers

exposed to a wet air or gas (external) environment using the System Condition Monitoring

Program.

SER Section 3.0.3.3.2 documents the staff's review and evaluation of the applicant's System

Condition Monitoring Program.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the Plant Chemistry Program, OneTime Inspection Program, and System Condition Monitoring Program effectively manage the

aging effect of loss of material due to MIC, pitting, and crevice corrosion of copper alloy

material exposed to wet air or gas, or treated water environment. The Selective Leaching of

Materials Program effectively manages the loss of material due to selective leaching of cast

iron material exposed to treated water environment, and copper alloy exposed to wet air or gas

and raw water environments. The staff found that the applicant's program to manage loss of

material due to MIC, pitting, crevice corrosion, and selective leaching, as given in LRA

Table 3.4.2-5, is acceptable.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERMs, and AMP combinations that the GALL

Report does not evaluate. The staff found that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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3.4.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the SPC system components that are within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended functions will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the SPC system, as

required by 10 CFR 54.21(d).

3.5 Aqinq Manaaement of Containments, Structures, and Component Supports

This section of the SER documents the staff's review of the applicant's AMR results for the

containments, structures, and component supports components and component groups

associated with the following systems:

* cranes, heavy loads, rigging

" diesel fuel oil transfer house

* emergency diesel generator building

* emergency filtration train building

" fire protection barriers commodity group

* hangers and supports commodity group

* HPCI building

* intake structure

* miscellaneous SBO yard structures

* off gas stack

• offgas storage and compressor building

• plant control and cable spreading structure

• primary containment

* radioactive waste building

* reactor building

• structures affecting safety

• turbine building

* underground duct bank

3.5.1 Summary of Technical Information in the Application

In LRA Section 3.5, the applicant provided AMR results for the containments, structures, and

component supports components and component groups. In LRA Table 3.5.1, the applicant

provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for

the containments, structures, and component supports components and component groups.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

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review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient information

to demonstrate that the aging effects for the containments, structures, and component supports

system components that are within the scope of license renewal and subject to an AMR will be

adequately managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA is applicable and that the applicant had identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, as summarized in SER

Section 3.5.2.1.

The staff also performed an onsite audit of those selected AMRs that are consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations are consistent with the acceptance criteria in SRP-LR

Section 3.5.2.2. The MNGP audit and review report documents the staff's audit evaluations,

which and are summarized in SER Section 3.5.2.2..

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified all plausible aging effects and

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The MNGP audit and review report documents the staff's audit

evaluations. SER Section 3.5.2.3 summarizes these audit evaluations and documents the

staff's technical review.

Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensure

that they adequately describe the programs credited with .managing or monitoring aging for the

containments, structures, and component supports system components.

Table 3.5-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.5 that are addressed in the GALL Report.

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Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports in

the GALL Report

Component Group Aging Effect/] AMP in GALL AMP in LRA I Staff Evaluation,

Mechanism Report ____. __-__ ... ..... ...

Common Components of All Types of PWR and BWR Containment

Penetration Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

.sleeves, penetration damage (CLB accordance with evaluated in Section

bellows, and fatigue analysis 10 CFR 54.21 (c) 4.3, Metal Fatigue

dissimilar metal exists) of the RPV and

welds Internals, and

(Item Number Reactor Coolant

3.5.1-01) Pressure Boundary

Piping and

Components and

Section 4.6, Fatigue

Analysis of the

Primary

Containment,

Attached Piping,

and Components

Penetration Cracking due to Containment ISI, 10 CFR 50, Consistent with

sleeves, bellows, cyclic loading, or containment leak- Appendix J GALL Report, which

and dissimilar metal crack initiation and rate test Program (B2.1.1), recommends further

welds growth due to SCC Primary evaluation (see

(Item Number Containment Section 3.5.2.2.1)

3.5.1-02) In-Service

Inspection Program

(B2.1.26)

Penetration Loss of material Containment ISI, 10 CFR 50, Consistent with

sleeves, penetration due to corrosion containment leak- Appendix J GALL Report, which

bellows, and rate test Program (B2.1.1), recommends no

dissimilar metal Primary further evaluation

welds Containment

(Item Number In-Service

3.5.1-03) Inspection Program

(B2.1.26)

Personnel airlock Loss of material Containment ISI, 10 CFR 50, Consistent with

and equipment due to corrosion containment leak- Appendix J GALL Report, which

hatch rate test Program (82.1.1), recommends no

(Item Number Primary further evaluation

3.5.1-04) Containment

In-Service

Inspection Program

(82.1.26)

Personnel airlock Loss of leak Containment leak- 10 CFR 50, Consistent with

and equipment tightness in closed rate test, plant Appendix J GALL Report, which

hatch position due to Technical Program (B2.1.1) recommends no

(Item Number mechanical wear of Specifications further evaluation

3.5.1-05) locks, hinges, and

closure mechanism

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism :'Report .. .. _ __ " '_ _•

Seals, gaskets, and Loss of sealant and Containment ISI, 10 CFR 50, Consistent with

moisture barriers leakage through containment leak- Appendix J GALL Report, which

(Item Number containment due to rate test' Program (B2.1.1), recommends no

3.5.1-06) deterioration of joint Primary further evaluation

seals, gaskets, and Containment

moisture barriers In-Service

Inspection Program

(B2.1.26)

PWR Concrete (Reinforced and Prestressed) and Steel Containment

BWR Concrete (Mark II and Il) and Steel (Mark I, II, and Ill) Containment

Concrete elements Aging of accessible Containment ISI Not applicable to

-foundation, walls, and inaccessible MNGP Mark I

dome concrete areas due containment

(Item Number to leaching of

3.5.1-07) calcium hydroxide,

aggressive

chemical attack,

and corrosion of

embedded steel

Concrete elements Cracks, distortion, Structures Not applicable to

-foundation and increases in Monitoring MNGP Mark I

(Item Number component stress containment

3.5.1-08) level due to

settlement

Concrete elements Reduction in Structures Not applicable to

-foundation foundation strength Monitoring MNGP Mark I

(Item Number due to erosion of containment

3.5.1-09) porous concrete

subfoundation

Concrete elements Reduction of Plant specific Not applicable to

-foundation, dome, strength and MNGP Mark I

and wall modulus due to containment

(Item Number elevated

3.5.1-10) temperature

Prestressed Loss of prestress TLAA, evaluated in Not applicable to

containment due to relaxation, accordance with MNGP Mark I

-tendons and shrinkage, creep, 10 CFR 54.21 (c) containment

anchorage and elevated

components temperature

(Item Number

3.5.1-11)

Steel elements Loss of material Containment ISI, 10 CFR 50, Consistent with

-liner plate, due to corrosion in containment leak- Appendix J GALL Report, which

containment shell accessible and rate test Program (82.1.1), recommends further

(Item Number inaccessible areas Primary evaluation

3.5.1-12) Containment (see

In-Service Section 3.5.2.2.1)

Inspection Program

(B2.1.26)

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Component Group- Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism Report _-_ _ _ _ _ _ _

Steel elements Cumulative fatigue TLAA, evaluated in TLAA This TLAA is

-vent header, damage (CLB accordance with evaluated in Section

drywell head, torus, fatigue analysis 10 CFR 54.21(c) 4.3, Metal Fatigue

downcomers, pool exists) of the RPV and

shell Internals, and

(Item Number Reactor Coolant

3.5.1-13) Pressure Boundary

Piping and

Components and

Section 4.6,

Fatigue Analysis of

the Primary

Containment,

Attached Piping,

and Components

Steel elements- Loss of material Protective coating 10 CFR 50, Consistent with

protected by coating due to corrosion in monitoring and Appendix J GALL Report.

(Item Number accessible areas maintenance Program (B2.1.1), Protective Coating

3.5.1-14) only Primary Monitoring &

Containment Maintenance

In-Service Program is not

Inspection Program relied upon for

(12.1.26), managing loss of

Protective Coating material due to

Monitoring & corrosion, but is

Maintenance credited for

Program (B2.1.27) preventing

degradation of

coatings that could

lead to clogging of

ECCS suppression

pool suction

strainers

Prestressed Loss of material Containment ISI Not applicable to

containment- due to. corrosion of MNGP Mark I

tendons and prestressing containment. There

anchorage tendons and are no prestressed

components anchorage containment

(Item Number components tendons and

3.5.1-15) anchorage

components

Concrete elements Scaling, cracking, Containment ISI Not applicable to

-foundation, dome, and spalling due to MNGP Mark I

and wall freeze-thaw; containment

(Item Number expansion and

3.5.1-16) cracking due to

reaction with

aggregate

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism Report ____ ...... __

Steel elements Cracking due to Containment ISl, 10 CFR 50, Consistent with

-vent line bellows, cyclic loads or crack containment leak- Appendix J GALL Report, which

vent headers, initiation and growth rate test Program (82.1.1), recommends further

downcomers due to SCC Primary evaluation (see

(Item Number Containment Section 3.5.2.2.1)

3.5.1-17) In-Service

Inspection Program

(B2.1.26)

Steel elements- Crack initiation and Containment ISI, Not applicable to

suppression growth due to SCC containment leak- MNGP Mark I

chamber liner rate test containment

(Item Number

3.5.1-18)

Steel elements Fretting and lockup Containment ISI Not applicable to

-drywell head and due to wear MNGP.

downcomer pipes Components not

(Item Number subject to relative

3.5.1-19) motion

Class I Structures

All groups except All types of aging Structures Structures Consistent with

Group 6 effects Monitoring Monitoring Program GALL Report, which

-accessible (B2.1.31) recommends further

interior/exterior evaluation

concrete and steel (see

components Section 3.5.2.2.2)

(Item Number

3.5.1-20)

Groups 1-3, 5, 7-9 Aging of Plant specific None Consistent with

-inaccessible inaccessible GALL Report, which

concrete concrete areas due MNGP meets the recommends further

components, such to aggressive criteria specified in evaluation (see

as exterior walls chemical attack, the GALL Report Section 3.5.2.2.2)

below grade and and corrosion of

foundation embedded steel

(Item Number

3.5.1-21)

Group 6-all All types of aging Inspection of Structures Consistent with

accessible/ effects, including water-control Monitoring Program GALL Report, with

inaccessible loss of material due structures or (B2.1.31) enhancements in

concrete, steel, and to abrasion, FERC/U.S. Army the Structures

earthen cavitation, and Corp of Engineers Monitoring Program

components corrosion dam inspection and to include

(Item Number maintenance RG 1.127,

3.5.1-22) Inspection of WaterControl Structures

Associated with

Nuclear Power

Plants.

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

"Mechanism.. • Report .... _________, __ - _

Group 5-4liners Crack initiation and Water chemistry Plant Chemistry Consistent with

(Item Number growth from SCC and monitoring of Program (B2.1.25), GALL Report, which

3.5.1-23) and loss of material spent fuel pool Primary recommends no

due to crevice water level Containment further evaluation

corrosion In-Service

Inspection Program

(B2.1.26), and

System Condition

Monitoring Program

(B2.1.32)

Groups 1 -3, 5, 6- Cracking due to Masonry wall Fire Protection Consistent with

all masonry block restraint, shrinkage, Program (B2.1.17), GALL Report, with

walls creep, and Structures enhancements in

(Item Number aggressive Monitoring Program the Structures

3.5.1-24) environment (B2.1.31) Monitoring Program

to include masonry

walls

Groups 1-3, 5, 7-9 Cracks, distortion, Structures Structures Consistent with

-foundation and increases in monitoring Monitoring Program GALL Report

(Item Number component stress (B2.1.31) only for (see

3.5.1-25) level due to the fuel oil transfer Section 3.5.2.2.1)

settlement house

Groups 1-3, 5-9- Reduction in Structures None Consistent with

foundation foundation strength monitoring GALL Report

(Item Number due to erosion of MNGP meets the (see

3.5.1-26) porous concrete criteria specified in Section 3.5.2.2.1)

subfoundation the GALL Report

Groups 1-5-- Reduction of Plant specific None Consistent with

concrete strength and GALL Report, which

(Item Number modulus due to Concrete recommends further

3.5.1-27) elevated temperatures do not evaluation

temperature exceed GALL (see

Report Section 3.5.2.2.1)

recommended limits

Groups 7, 8-liners Crack initiation and Plant specific Not applicable.

(Item Number growth due to SCC; MNGP has no

3.5.1-28) loss of material due Group 7 (concrete

to crevice corrosion tanks) or Group 8

(steel tanks) with

liners

Component Supports

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Component Group Aging Effect/ AMP in GALL AMP in LRA Staff Evaluation

Mechanism Report

All groups-support Aging of component Structures Buried Piping & Consistent with

members-anchor supports Monitoring Tanks Inspection GALL Report, which

bolts, concrete Program (B2.1.5), recommends further

surrounding anchor Primary evaluation

bolts, welds, grout Containment (see

pad, bolted In-Service Section 3.5.2.2.3)

connections, etc. Inspection Program

(Item Number (B2.1.26),

3.5.1-29) Structures

Monitoring Program

(B2.1.31), System

Condition

Monitoring Program

(82.1.32)

Groups B1.1, B1.2, Cumulative fatigue TLAA, evaluated in This TLAA is

and B1.3-support damage (CLB accordance with evaluated in Section

members-anchor fatigue analysis 10 CFR 54.21(c) 4.3, Metal Fatigue

bolts, welds exists) of the RPV and

(Item Number Internals, and

3.5.1-30) Reactor Coolant

Pressure Boundary Piping and

Components

All groups-support Loss of material Boric acid corrosion Not applicable,

members-anchor due to boric acid PWR only

bolts, welds corrosion

(Item Number

3.5.1-31)

Groups B1.1, B1.2, Loss of material ISI ASME Section XI, Consistent with

and 81.3-support due to Subsection IWF GALL Report, which

members-anchor environmental Program (B2.1.3) recommends no

bolts, welds, spring corrosion; loss of further evaluation

hangers, guides, mechanical function

stops, and vibration due to corrosion,

isolators distortion, dirt,

(Item Number overload, etc.

3.5.1-32)

Group B1.1-high- Crack initiation and Bolting integrity Not applicable to

strength low-alloy growth due to SCC MNGP. There are

bolts no high-strength

(Item Number low-alloy bolts in

3.5.1-33) use at MNGP for

structural

applications

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in SER Section 3.5.2.1, involves the staff's review of the AMR results

for components in the containments, structures, and component supports that the applicant

indicated are consistent with the GALL Report and do not require further evaluation. Another

approach, documented in SER Section 3.5.2.2, involves the staff's review of the AMR results

for components in the containments, structures, and component supports that the applicant

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indicated are consistent with the GALL Report and for which further evaluation is

recommended. A third approach, documented in SER Section 3.5.2.3, involves the staff's

review of the AMR results for components in the containments, structures, and component

supports that the applicant indicated are not consistent with, or not addressed in, the GALL

Report. Section 3.0.3 documents the staff's review of AMPs that are credited to manage or

monitor aging effects of the containments, structures, and component supports components.

3.5.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the containments, structures, and

component supports system components:

* 10 CFR 50, Appendix J Program (B2.1.1)

0 ASME Section XI, Subsection IWF Program (B2.1.3)

a Buried Piping & Tanks Inspection Program (B2.1.5)

0 Fire Protection Program (B2.1.17)

* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program (B2.1.22)

* One-Time Inspection Program (B2.1.23)

• . Plant Chemistry Program (B2.1.25)

* Primary Containment In-Service Inspection Program (B2.1.26)

* Protective Coating Monitoring & Maintenance Program (B2.1.27)

* Structures Monitoring Program (B2.1 .31)

* System Condition Monitoring Program (B2.1.32)

Staff Evaluation. In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant summarized the AMRs

for the containments, structures, and component supports components and identified which

AMRs it considered to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

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identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it had reviewed and accepted the identified exceptions

to the GALL Report AMPs. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant could not find

a listing of some system components in the GALL Report; however, the applicant identified a

different component in the GALL Report that has the same material, environment, aging effect,

and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component applies to the component under review and whether the AMR is valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component applies to the component under review. The staff verified that it had reviewed and

accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

these line items to verify consistency with the GALL Report. The staff also determined whether

the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The

following sections discuss the staff's evaluation.

3.5.2.1.1 Loss of Material Due to Corrosion in Accessible Areas

In reviewing entries in LRA Table 3.5.2-13 for carbon steel and low-alloy steel in treated water

and air/gas environments, the staff identified some discrepancies in notes for AMR line items

that reference GALL Report line item ll.B.1.1.1-a. The discrepancies resulted because the

applicant credited different AMPs from those recommended by the GALL Report and used

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exceptions where none existed. The staff asked the applicant to resolve these discrepancies. In

its response, by letter dated August 11, 2005, the applicant stated the following:

LRA line ll.B.1.1.1-a for the component structural steel in a treated water

environment for the AMP Primary Containment Inservice Inspection program, the

note should have been 'C' and not 'D.'

LRA line ll.B.1.1.1-a for the component structural steel in a treated water

environment for the AMP Plant Chemistry program, the note should have been

'E' and not 'D.'

LRA line ll.B.1.1.1-a for the component support members, welds, bolted

connections, torus internal catwalk support columns in a treated water

environment for the AMP Primary Containment Inservice Inspection program, the

note should have been 'C' and not 'D.'

LRA line ll.B.1.1.1-a for the component support members, welds, bolted

connections, torus internal catwalk support columns in a treated water

environment for the AMP Plant Chemistry Program, the note should have been

'E' and not 'D.'

LRA line ll.B.1.1.1-a for the component structural steel inside torus, torus internal

catwalk in an air/gas environment, for the AMP Primary Containment Inservice

Inspection Program, the note should have been 'C' and not 'D.'

Because the components, material, and AMP identified in the LRA are consistent with the GALL

Report, the staff concluded that the applicant appropriately addressed aging management for

the above components.

The staff's review found that the applicant appropriately addressed the aging

effects/mechanisms, as recommended by the GALL Report.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. The staff's review concluded

that the AMR results, which the applicant claimed to be consistent with the GALL Report, are

consistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicant

has demonstrated that the aging effects for these components will be adequately managed so

that their intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

containments, structures, and component supports components. The applicant provided

information concerning how it will manage the following aging effects for PWR and BWR

containments:

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* aging of inaccessible concrete areas

* cracking, distortion, and increase in component stress level due to settlement; reduction

of foundation strength due to erosion of porous concrete subfoundations, if not covered

by the Structures Monitoring Program

* reduction of strength and modulus of concrete structures due to elevated temperature

" loss of material due to corrosion in inaccessible areas of steel containment shell or liner

plate

* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

* cumulative fatigue damage

• cracking due to cyclic loading and SCC

The applicant also provided information on its management of the following aging effects for

Class 1 structures:

" aging of structures not covered by the Structures Monitoring Program

* aging management of inaccessible areas

Finally, the applicant provided information on its management of aging effects for component

supports:

* aging of supports not covered by the Structures Monitoring Program

* cumulative fatigue damage due to cyclic loading

Staff Evaluation. For component groups evaluated in'the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addresses the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in SRP-LR

Section 3.5.2.2. The staff's audit and review report details the staff's audit. The following

sections discuss the staff's evaluation of the aging effects.

3.5.2.2.1 PWR and BWR Containments

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1,

which addresses several areas discussed below.

A-qing of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against the

criteria in SRP-LR Section 3.5.2.2.1.1.

In LRA Section 3.5.2.2.1.1, the applicant addressed aging of inaccessible concrete areas.

SRP-LR Section 3.5.2.2.1.1 states the following:

Cracking, spalling, and increases in porosity and permeability due to leaching of

calcium hydroxide and aggressive chemical attack; and cracking, spalling, loss

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of bond, and loss of material due to corrosion of embedded steel could occur in

inaccessible areas of PWR concrete and steel containments; BWR Mark II

concrete containments; and Mark III concrete and steel containments. The GALL

Report recommends further evaluation of plant-specific programs to manage the

aging effects for inaccessible areas if specific criteria defined in the GALL Report

cannot be satisfied.

In LRA Section 3.5:2.2.1.1, the applicant stated that these aging effects/mechanisms do not

apply to the MNGP containment because it is a BWR Mark I design, which does not include

concrete as part of the containment structure. The staff found that these aging

effects/mechanisms do not apply for the MNGP containment.

Cracking, Distortion, and Increase in Component Stress Level Due to Settlement: Reduction of

Foundation Strength Due to Erosion of Porous Concrete Subfoundations. If Not Covered by the

Structures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria

in SRP-LR Section 3.5.2.2.1.2.

In LRA Section 3.5.2.2.1.2, the applicant addressed cracking, distortion, and increase in

component stress level due to settlement as well as reduction of foundation strength due to

erosion of porous concrete subfoundations.

SRP-LR Section 3.5.2.2.1.2 states the following:

Cracking, distortion, and increase in component stress level due to settlement

could occur in PWR concrete and steel containments and BWR Mark II concrete

containments and Mark III concrete and steel containments. Also, reduction of

foundation strength due to erosion of porous concrete subfoundations could

occur in all types of PWR and BWR containments. Some plants may rely on a

de-watering system to lower the site ground-water level. If the plant's CLB credits

a de-watering system, the GALL Report recommends verification of the

continued functionality of the de-watering system during the period of extended

operation. The GALL Report recommends no further evaluation if this activity is

included in the scope of the applicant's structures monitoring program.

In LRA Section 3.5.2.2.1.2, the applicant addressed aging effects due to settlement, specifically

whether it needs to manage the aging effects/mechanisms based on a plant-specific review of

the conditional requirements outlined in the GALL Report.

This subsection mainly concerns PWR and BWR Mark II and III concrete containments;

however, the settlement criteria presented apply to all concrete foundations. The plant initial

licensing basis did not include a program to monitor settlement. With the exception of the diesel

fuel oil transfer house, no significant settlement has been observed on any major structure, and

de-watering systems are not used. These circumstances satisfy the GALL Report

recommendations on concrete settlement and, therefore, with the exception of the diesel fuel oil

transfer house, cracks, distortion, and increase in component stress levels due to settlement

require no aging management.

The diesel fuel oil transfer house is a moderate-weight structure exerting a mean bearing

pressure of about 1100 pounds per square foot (lb/ft2) on the underlying foundation material.

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The foundation material of compacted granular backfill underlain by stiff clay lenses and

sandstone bedrock should not be susceptible to settlement under the load imposed. However,

the diesel fuel oil transfer house has undergone significant differential settlement. According to

plant records and settlement data, the diesel fuel oil transfer house settled rapidly following

construction, which the applicant stated probably resulted from washout after a rainstorm and

was long ago effectively complete. Data recorded annually since 1992 show no significant

continued settlement of the structure.

The Structures Monitoring Program manages the aging effects for the diesel fuel oil transfer

house. As part of the Structures Monitoring Program, the applicant performs an annual

inspection of the diesel fuel oil transfer house for settlement to manage the aging effects of

cracks, distortion, and increase in component stress level due to settlement. The inspection

adds assurance that the aging effects do not occur or progress so slowly that the component's

intended function will be maintained during the period of extended operation.

SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.

The staff found this program acceptable for managing the aging effects of cracks, distortion,

and increase in component stress level due to settlement as it inspects for settlement.

The applicant also addressed the aging effects of all types of PWR and BWR containments due

to erosion of porous concrete subfoundations, specifically whether it needs to manage the

aging effects/mechanisms based on a plant-specific review of the conditional requirements

outlined in the GALL Report. The applicant's response to erosion of cement from porous

concrete subfoundations, as described in IN 97-11, "Cement Erosion from Containment

Subfoundations at Nuclear Power Plants," dated March 21, 1997, and IN 98-26, "Settlement

Monitoring and Inspection of Plant Structures Affected by Degradation of Porous Concrete

Subfoundations," dated July 24,1998, concluded that foundation materials contain no porous

layers. The concrete base or lean concrete fill material beneath major building foundations

contains no high-alumina cement. The applicant does not rely on a de-watering system to lower

site ground water.

The applicant concluded that the GALL Report recommendations are satisfied for porous

concrete subfoundations and therefore the aging effects due to erosion of porous concrete

subfoundations necessitate no aging management.

The staff found the applicant's further evaluation of both settlement and erosion of porous

concrete subfoundations acceptable because (1) the applicant monitors the effects of

differential settlement of the diesel fuel oil transfer house during inspections under the

Structures Monitoring Program, (2) the applicant has no porous concrete subfoundations, and

(3) the applicant does not employ a de-watering system.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.1.2. For those line items that apply to LRA Section 3.5.2.2.1.2, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

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Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. The

staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.

In LRA Section 3.5.2.2.1.3, the applicant addressed reduction of strength and modulus of

concrete structures due to elevated temperature.

SRP-LR Section 3.5.2.2.1.3 states the following:

Reduction of strength and modulus of elasticity due to elevated temperatures

could occur in PWR concrete and steel containments and BWR Mark II concrete

containments and Mark III concrete and steel containments. The GALL Report

recommends further evaluation if any portion of the concrete containment

components exceeds specified temperature limits (i.e., general area temperature

66°C [150'F] and local area temperature 930C [200 OF]).

The applicant stated that this aging effect mainly concerns PWR and BWR Mark II and III

concrete containments; however, the temperature criteria presented in this section apply to all

concrete. Plant documents confirm that concrete elements are not subject to elevated

temperatures in excess of 150 OF generally and 200 OF locally. Plant areas that bound hightemperature considerations are the drywell general area and biological shield wall piping

penetration local area, which experience temperatures of 135 OF and 179 OF, respectively.

The staff's review determined that the applicant has evaluated the temperatures of hot piping

penetrations considering the presence of insulation, which is credited with maintaining the

penetration temperatures below the local limits of 200 OF. Insulation is included within the scope

of license renewal and is subject to an AMR.

The staff found the applicant's AMRs consistent with the GALL Report in demonstrating that the

temperatures do not exceed the temperatures recommended in the GALL Report for which

evaluation is required.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.1.3. For those line items that apply to LRA Section 3.5.2.2.1.3, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner

Plate. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR

Section 3.5.2.2.1.4.

In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to corrosion for the

drywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).

SRP-LR Section 3.5.2.2.1.4 states the following:

Loss of material due to corrosion could occur in inaccessible areas of the steel

containment shell or the steel liner plate for all types of PWR and BWR

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containments. The GALL Report recommends further evaluation of plant-specific

programs to manage this aging effect for inaccessible areas if specific criteria

defined in the GALL Report cannot be satisfied.

In LRA Section 3.5.2.2.1.4, the applicant stated that MNGP satisfies the requirements specified

in the GALL Report for concrete quality, inspections, and housekeeping; therefore, a

plant-specific AMP for loss of material due to corrosion of steel elements in inaccessible areas

is not required.

The applicant also stated that the Protective Coating Monitoring & Maintenance Program is not

credited with managing loss of material due to corrosion but with preventing degradation of

coatings that could lead to clogging of ECCS suppression pool suction strainers.

Implementation of this program to manage the aging effect adds assurance that the aging

effect does not occur or progresses so slowly that the component's intended function will be

maintained during the period of extended operation.

The staff reviewed LRA Section 3.5.2.2.1.4 and determined that the applicant satisfied the

specific criteria defined in the GALL Report for preventing loss of material due to corrosion for

the drywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).

The staff's review of applicant documents specifying that (1) plant concrete meets ACI 318 or

349 criteria, (2) the Structures Monitoring Program inspects the concrete around the inside of

the drywell adjacent to the moisture barrier, (3) the scope of the Primary Containment

In-Service Inspection Program includes the moisture barrier, and (4) borated water leaks do not

apply for BWR plants. Therefore, the staff determined that further evaluation is not necessary.

The staff found that the applicant is consistent with the GALL Report, and a plant-specific AMP

for loss of material is not required. SER Section 3.5.2.3.6 documents further discussion of the

staff's review of loss of material due to corrosion for the drywell shell in inaccessible areas.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.1.4. For those line items that apply to LRA Section 3.5.2.2.1.4, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. The staff

reviewed LRA Section 3.5.2.2.1.5 against the criteria in SRP-LR Section 3.5.2.2.1.5.

In LRA Section 3.5.2.2.1.5, the applicant addressed loss of prestress due to relaxation,

shrinkage, creep, and elevated temperature.

SRP-LR Section 3.5.2.2.1.5 states the following:

Loss of prestress forces due to relaxation, shrinkage, creep, and elevated

temperature for PWR prestressed concrete containments and BWR Mark II

prestressed concrete containments is a TLAA as defined in 10 CFR 54.3. TLAAs

are required to be evaluated in accordance with 10 CFR 54.21 (c).

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In LRA Section 3.5.2.2.1.5, the applicant stated that this aging effect applies to Mark II BWR

containments only.

Because MNGP is not a PWR and has no BWR Mark II containment, the staff found this aging

effect not applicable:

Cumulative Fatigue Damage. In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue is a

TLAA as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). SER Sections 4.3 and 4.6 document the staff's review of the applicant's

evaluation of this TLAA.

Cracking Due to Cyclic Loading and SCC. The staff reviewed LRA Section 3.5.2.2.1.7 against

the criteria in SRP-LR Section 3.5.2.2.1.7.

In LRA Section 3.5.2.2.1.7, the applicant addressed cracking due to cyclic loading and SCC.

SRP-LR Section 3.5.2.2.1.7 states the following:

Cracking of containment penetrations (including penetration sleeves, penetration

bellows, and dissimilar metal welds) due to cyclic loading or SCC could occur in

all types of PWR and BWR containments. Cracking could also occur in vent line

bellows, vent headers, and downcomers due to SCC for BWR containments. A

visual VT-3 examination would not detect such cracks. The GALL Report

recommends further evaluation of the inspection methods implemented to detect

these aging effects.

In LRA Section 3.5.2.2.1.7, the applicant listed components associated with primary

containment that require aging management for cracking due to cyclic loading because their

original design bases did not include CLB fatigue analyses. Specifically, components requiring

aging management for cracking due to cyclic loading include drywell penetrations, drywell

penetration sleeves, and associated dissimilar metal welds. These components are designed to

stress levels without requiring fatigue analyses and thus fine cracks are unlikely to occur;

therefore, existing requirements for leak-rate testing pursuant to the 10 CFR 50, Appendix J

Program and surface inspections pursuant to the Primary Containment In-Service Inspection

Program are adequate to detect cracking due to cyclic loading.

The applicant also listed components associated with primary containment that require aging

management for crack initiation and growth due to SCC, specifically the stainless steel vent line

bellows and drywell penetration bellows. The GALL Report states that weld Examination

Categories E-B (pressure retaining welds, VT-1 examination method) and E-F (dissimilar

pressure retaining welds, surface examination method) for vent line and other penetration

bellows assemblies are warranted for the extended period of operations.

The applicant stated that its operating history on bellows replacements is limited to bellows

X-1 6B. Leakage was identified during local leak-rate testing and not from cracks observed

during a visual examination. The leakage was identified at the outer-most bellows from a small

failure underneath the outer-most collar of the expansion joint. The applicant did not identify any

cracks in the weld metal. Industry operating history has identified cracks of the bellows but none

in the weld metal. Welds for bellows assemblies are in a sheltered, noncorrosive environment.

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Additionally, bellows assemblies are located outside primary containment in an air/gas

environment with temperatures not expected to exceed threshold limits for SCC. Because of the

nonaggressive environmental exposures and plant-specific and industry operating histories, the

applicant stated that weld examinations using optional Examination Categories E-B and E-F are

not warranted. The applicant stated that existing requirements for visual examinations, in

accordance with ASME Code, Section XI (Subsection IWE), Examination Category E-A, and

Appendix J leak-rate testing, Examination Category E-P, should be sufficient to detect cracking

of the bellows assemblies.

The applicant concluded that implementation of these programs to manage aging effects adds

assurance that the aging effects do not occur or progress so slowly that the component's

intended function will be maintained during the period of extended operation.

SER Sections 3.0.3.1.6 and 3.0.3.2.1 document the staff's reviews of the applicant's Primary

Containment In-Service Inspection Program and the 10 CFR 50, Appendix J Program,

respectively. The NRC staff found these programs acceptable for managing cracking due to

cyclic loading and SCC in accessible areas.

The staff reviewed industry operating experience on cracking of containment penetrations

(including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclic

loading and SCC and found it to be similar to the applicant's operating experience. The staff

concluded that the applicant appropriately addressed further evaluation of this aging effect.

On the basis of its review, the staff concluded that, based on the programs identified above, the

applicant has met the criteria of SRP-LR Section 3.5.2.2.1.7. For those line items that apply to

LRA Section 3.5.2.2.1.7, the staff determined that the applicant's AMRs are consistent with the

GALL Report and the applicant has demonstrated that the'eff ects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.2.2 Class 1 Structures

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,

which addresses several areas discussed below.

Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.

In LRA Section 3.5.2.2.2.1, the applicant addressed various aging effects for concrete and

carbon steel components. The applicant specifically addressed whether it needs to manage the

aging effects/mechanisms based on plant-specific review of the conditional requirements

outlined in the GALL Report.

SRP-LR Section 3.5.2.2.2.1 states the following:

The GALL Report recommends further evaluation of certain structure/aging

effect combinations if they are not covered by the Structures Monitoring

Program. This includes (1) scaling, cracking, and spalling due to repeated

freeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spalling and

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increase in porosity and permeability due to leaching of calcium hydroxide and

aggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion and

cracking due to reaction with aggregates for Groups 1-5, 7-9 structures; (4)

cracking, spalling, loss of bond, and loss of material due to corrosion of

embedded steel for Groups 1-5, 7-9 structures; (5) cracks, distortion, and

increase in component stress level due to settlement for Groups 1-3," 5, 7-9

structures; (6) reduction of foundation strength due to erosion of porous concrete

subfoundation for Groups 1-3, 5-9 structures; (7) loss of material due to

corrosion of structural steel components for Groups 1-5, 7-8 structures; (8) loss

of strength and modulus of concrete structures due to elevated temperatures for

Groups 1-5; and (9) crack initiation and growth due to SCC and loss of material

due to crevice corrosion of stainless steel liner for Groups 7 and 8 structures.

Further evaluation is necessary only for structure/aging effect combinations not

covered by the structures monitoring program. Technical details of the aging

management issue are presented in SRP-LR Subsection 3.5.2.2.1.2 for items (5)

and (6) and Subsection 3.5.2.2.1.3 for item (8).

The applicant stated that, in accordance with the GALL Report for carbon steel in accessible

areas, loss of material due to corrosion requires aging management. It performs aging

management of carbon steel in accessible areas within the Structures Monitoring Program

through general visual inspections. Protective coatings, including galvanization, are not relied

:upon to manage the aging effects.

The applicant also stated that the underground duct bank and intake structures include

'below-grade steel components. As the below-grade sides of the carbon steel components are

not-accessible, the condition of the accessible sides of the carbon steel components located in

an atmosphere/weather, air/gas, or raw water environment, will be used to evaluate the

condition of the inaccessible sides of the carbon steel components.

The applicant stated that, in accordance with the GALL Report and ISG-03, concrete in

accessible areas requires aging management for the aging mechanisms of freeze-thaw,

leaching of calcium hydroxide, reaction with aggregates, corrosion of embedded steel, and

aggressive chemical attack. The applicant performs aging management of concrete in

accessible areas through general visual inspections within the Structures Monitoring Program.

The applicant stated that concrete in inaccessible areas requires no aging management and

provided justification in the following paragraphs from LRA Section 3.5.2.2.2.1:

MNGP is located in a severe weathering region according to Figure 1 of ASTM

C33-90, and therefore a freeze-thaw evaluation is required. Plant documents

confirm that the concrete has an air content between 3 and 6%, and subsequent

inspections performed on concrete in accessible areas did not exhibit

degradation related to freeze-thaw. This evaluation satisfies GALL Report and

ISG-03 condition requirements for concrete in inaccessible areas, and therefore

loss of material and cracking due to freeze-thaw do not require aging

management.

Plant documents confirm that the concrete was constructed in accordance with

the recommendations in ACI 201.2R-77 for durability. Additionally, there is no

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flowing water acting on any below-grade concrete basemat or concrete wall.

Building foundations may or may not fall below the ground-water table. For those

below the ground-water table, evaluation shows that ground-water flow velocity is

well below the threshold at which any significant erosion or leaching of calcium

hydroxide is possible. This evaluation satisfies the GALL Report and ISG-03

condition requirements for concrete in inaccessible areas, and therefore increase

in porosity and permeability and loss of strength due to leaching of calcium

hydroxide do not require aging management.

Tests and petrographic examinations performed according to ASTM C289-64

and ASTM C295 verified that aggregates used are not reactive. This satisfies the

GALL Report and ISG-03 condition requirements for concrete in inaccessible

areas, and therefore expansion and cracking due to reaction with aggregates do

not require aging management.

The GALL Report and ISG-03's description of an aggressive environment is pH

< 5.5, chlorides >500 ppm, or sulfates > 1500 ppm. Plant documents confirm

that the below-grade environment is not aggressive (MNGP data indicates that

the pH is > 7.0, the chlorides are < 100 ppm and the sulfates are < 100 ppm).

The Structures Monitoring Program includes examinations of below-grade

concrete when excavated for any reason. To ensure the below-grade

environment remains non-aggressive, ground-water chemistry is monitored

periodically for the above parameters as part of the Structures Monitoring.

Program. This satisfies the GALL Report and ISG-03 condition requirements for

concrete in inaccessible areas, and therefore cracking, loss of bond, and loss of

material due to corrosion of embedded steel do not require aging management.

Based on the above rationale, increase in porosity and permeability, cracking,

and loss of material due to aggressive chemical attack do not require aging

management.

Finally, the applicant stated in LRA Section 3.5.2.2.2.1 that implementation of the Structures

Monitoring Program to manage aging effects/mechanisms adds assurance that the aging

effects do not occur or progress so slowly that the component's intended function will be

maintained during the period of extended operation.

SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.

The staff reviewed component/aging effect combinations and the need to manage the aging

effects/mechanisms based on plant-specific review of the conditional requirements outlined in

the GALL Report and determined that the applicant appropriately addressed these conditions.

The staff's review of the applicant's evaluations found them acceptable.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.2.1. For those line items that apply to LRA Section 3.5.2.2.2.1, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21(a)(3).

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Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 against

the criteria in SRP-LR Section 3.5.2.2.2.2.

In LRA Section 3.5.2.2.2.2, the applicant addressed aging management of inaccessible areas

for Class 1 structures.

SRP-LR Section 3.5.2.2.2.2 states the following:

.Cracking, spalling, and increases in porosity and permeability due to aggressive

chemical attack, and cracking, spalling, loss of bond, and loss of material due to

corrosion of embedded steel could occur in below-grade inaccessible concrete

areas. The GALL Report recommends further evaluation to manage these aging

effects in inaccessible areas of Groups 1-3, 5, 7-9 structures, if specific criteria

defined in the GALL Report cannot be satisfied.

In LRA Section 3.5.2.2.2.2 the applicant stated that it has no Group 7.or 8 structures; therefore,

discussion of the aging effects for these structures is not required. For other structures, the

applicant concluded that concrete in inaccessible aireas requires no aging management for

corrosion of embedded steel and aggressive chemical attack and provided justification in LRA

Section 3.5.2.2.2.1.

The staff reviewed LRA Section 3.5.2.2.2.1 and found the specific criteria defined in the GALL

Report satisfied; therefore, further evaluation is not necessary.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.2.2. For those line items that apply to LRA Section 3.5.2.2.2.2, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.5.2.2.3 Component Supports

The staff reviewed LRA Section 3.5.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.3,

which addresses several areas discussed below.

Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRA

Section 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1.

In LRA Section 3.5.2.2.3.1, the applicant discussed aging of component supports, specifically

whether it needs to manage the aging effects/mechanisms based on a plant-specific review of

the conditional requirements outlined in the GALL Report.

SRP-LR Section 3.5.2.2.3.1 states the following:

The GALL Report recommends further evaluation of certain component

support/aging effect combinations if they are not covered by the Structures

Monitoring Program. This includes (1) reduction in concrete anchor capacity due

to degradation of the surrounding concrete, for Groups B1-B5 supports; (2) loss

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of material due to environmental corrosion, for Groups B2-B5 supports; and (3)

reduction/loss of isolation function due to degradation of vibration isolation

elements, for Group B4 supports. Further evaluation is necessary only for

structure/aging effect combinations not covered by the Structures Monitoring

Program.

The applicant stated that component supports include structural elements connected to the

building or its structures and extending to a system or system component for support or

restraint. Component supports include support members, anchor bolts, welds, bolted

connections, grout pads, and building concrete at locations of expansion and at grouted

anchors. This boundary definition includes any vibration isolation elements. Spray or drip

shields for equipment are included with component supports. In addition, electrical and

instrumentation racks, electrical panels, cabinets and enclosures, lighting fixtures, tube track,

conduit, and cable trays provide support and, thus, are included with component supports.

Miscellaneous steel structures such as platforms, stairs, whip restraints, and masonry wall

supports are parts of the structures in which they are located.

The applicant stated in the LRA that the AERM for carbon steel components is loss of material.

In accordance with EPRI 1002950 guidelines, only general corrosion is an aging mechanism

applicable to loss of material for carbon steel in air/gas or atmosphere/weather environments.

The EPRI guidelines also indicate that general, crevice, and pitting corrosion and MIC are aging

mechanisms applicable to loss of material for carbon steel in treated water and below-grade

environments. Therefore, as the applicant stated in the LRA, management of this aging effect is

required:

The aging effect requiring management for reinforced concrete and grout

components is reduction in concrete anchor capacity due to local concrete

degradation. The only mechanism applicable to this aging effect is

.service-induced cracking or other concrete aging mechanism. Operating

experience has shown that service-induced cracking can occur in concrete and

grouted foundations. Concrete expansion bolts (anchors) can lose anchor

capacity due to concrete or grout degradation. Therefore, management of this

aging effect is required.

The aging effect requiring management for elastomers (rubber, neoprene,

silicone, etc.) is reduction or loss of isolation function. The aging mechanisms

applicable to this aging effect are radiation hardening, temperature, humidity,

and sustained vibratory loading. Operating experience has also shown that

elastomer materials can degrade over time. Therefore, management of this

aging effect is required.

Concerning AMPs used in addressing aging management, the applicant stated the following in

the LRA:

The System Condition Monitoring Program is used to identify and correct aging

concerns for component supports in an air/gas or atmosphere/weather

environment. Through general visual inspections, the System Condition

Monitoring Program identifies and evaluates general corrosion of carbon steel

components, service-induced cracking of grout and concrete local to support

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anchorage as well as degradation due to radiation hardening, temperature,

humidity, and sustained vibratory loading of vibration isolation elements.

The Structures Monitoring Program is used to identify and correct aging

concerns with miscellaneous steel components in an air/gas environment.

Through general visual inspections, the Structures Monitoring Program identifies

and evaluates general corrosion of carbon steel components as well as

service-induced cracking and degradation of grout and concrete local to the

anchorage.

The Buried Piping & Tanks Inspection Program is used to identify loss of

material for carbon steel conduit and the Diesel Fuel Oil Storage Tank flood

tie-downs in a below-grade environment through internal inspections of buried

tanks, system functional testing, and periodic inspections of buried pipe. A

condition assessment evaluation is made of the buried conduit and the Diesel

Fuel Oil Storage Tank flood tie-downs such that repairs can be made, if

necessary, prior to loss of intended function.

Access to the components inside the torus is limited. Since the Primary

Containment In-Service Inspection Program inspects components inside the

torus when available, it is relied upon to manage the aging effects of the.

miscellaneous steel components, support members, welds, and bolted

connections located inside the torus. Through general visual inspections, the

Primary Containment In-Service Inspection Program identifies and evaluates

general (environmental), crevice, galvanic, MIC, and pitting corrosion of carbon

steel components in treated water and general corrosion in air/gas.

Finally, the applicant stated that implementation of these programs to manage aging

effects/mechanisms provides added assurance that the aging effects do not occur or progress

so slowly that the component's intended function will be maintained during the period of

extended operation.

The staff reviewed component support/aging effect combinations not addressed by the

Structures Monitoring Program and determined that other AMPs address them. The staff

concluded that the applicant used the appropriate AMPs.

SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.

SER Section 3.0.3.3.2 documents the staff's evaluation of the System Condition Monitoring

Program. SER Section 3.0.3.2.5 documents the staff's evaluation of the Buried Piping & Tanks

Inspection Program. Finally, SER Section 3.0.3.1.6 documents the staff's evaluation of the

Primary Containment In-Service Inspection Program.

On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LR

Section 3.5.2.2.3.1. For those line items that apply to LRA Section 3.5.2.2.3.1, the staff

determined that the applicant's AMRs are consistent with the GALL Report and the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB during the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

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Cumulative Fatigue Damage Due to Cyclic Loading. Cumulative fatigue is a TLAA, as defined in

10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). SER

Section 4.3 documents the evaluation of this TLAA.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the issues that were further evaluated. The staff found that the applicant has

demonstrated that the aging effects will be adequately managed so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-18,

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report and provided information concerning how it will manage the aging

effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the

AMR line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination is not applicable. Note J

indicates that the GALL Report does not evaluate either the component or the material and

environment combination for the line item.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant .demonstrated that the aging effects will be adequately managed so that

intended functions will be maintained consistent with the CLB during the period of extended

operation. The following sections discuss the staff's evaluation.

In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant identified AMR result line items for which

the aging review process identified no aging effects. The applicant stated that it identified no

aging effects for components fabricated from the materials and exposed to the environments

described below.

No aging effects were considered applicable to components fabricated from stainless steel

material exposed to air/gas environments. On the basis of the staff's review of current industry

research and operating experience, stainless steel in dry air or gas (such as nitrogen, carbon

dioxide, freon, and halon) exhibits no aging effect and the SC will therefore remain capable of

performing its intended functions consistent with the CLB for the period of extended operation.

Based on the Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highly

resistant to corrosion in dry atmospheres in the absence of corrosive species, as will be the

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case for the gases referenced; therefore, the staff found that stainless steel in an air/gas

environment will not result in aging that will be of concern during the period of extended

operation. The staff concluded that no AERMs apply for stainless steel components exposed to

air or gas environments.

In RAI 3.5.2-1, dated September 28, 2005, the staff noted that the applicant listed below-grade

concrete (foundation, walls) as requiring no AMP in Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6,

3.5.2-7, 3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicant

stated that an AMP is not required to manage aging because, as described in Note 501, plant

documents confirm that the concrete had an air content between 3 and 6 percent and

inspections performed on concrete in accessible areas did not exhibit degradation related to

freeze-thaw. The staff noted that the GALL Report recommends that concrete have a

water-to-cement ratio of 0.35:0.45 to ensure no aging degradation related to freeze-thaw;

therefore, the staff requested that the applicant verify the water-to-cement ratio or provide an

appropriate AMP if the ratio does not meet the GALL Report recommendation. The staff raised

the same question for below-grade concrete (foundations, walls, lean concrete) listed in

Table 3.5.2-8.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Note: This response applies to Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,

3.5.2-8, 3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16,

3.5.2-17 and 3.5.2-18 but is not applicable to Table 3,5.2-13 (i.e. not applicable

since there is no below grade concrete inside drywell).

The criteria used to evaluate concrete located below grade were consistent with

NRC Staff final position issued for Interim Staff Guidance (ISG)-03 (see LRA

Section 2.1.4.3). ISG-03 provided the following criteria for the aging effects loss

of material (spalling, scaling) and cracking due to freeze-thaw for concrete in

inaccessible areas (i.e. exterior locations below grade and foundations).

'Inaccessible Areas:

Evaluation is needed for plants that are located in moderate to severe

weathering conditions (weathering index>1 00 day-inch/yr) (NUREG-1 557).

Documented evidence to confirm that the in-place concrete had the air

content between 3 percent to 6 percent and the subsequent inspections

performed did not exhibit degradations related to freeze-thaw should be

considered a part of the evaluation.'

LRA Note 501 and Table 1, item 3.5.1-20, and further evaluation for 3.5.2.2.2.1

included the following statement.

'MNGP is located in a severe weathering region according to Figure 1 of

ASTM C33-90, and therefore freeze-thaw evaluation is required. Plant

documents confirm that the concrete had an air content between 3 percent

and 6 percent, and subsequent inspections performed on concrete in

accessible areas did not exhibit degradation related to freeze-thaw. This

evaluation satisfies NUREG-1 801 and ISG-03 condition requirements for

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concrete in inaccessible areas, and therefore loss of material and cracking

due to freeze-thaw do not require aging management.'

All criteria of ISG-03 have been satisfied including an aging effect evaluation due

to severe weather location, documentation confirming that the concrete had an

air content between 3 percent and 6 percent, and plant inspection findings that

did not exhibit degradation related to freeze-thaw.

Additionally, ISG-03 was one of five ISG guidance documents issued for

implementation by the NRC prior to the LRA submittal. Under this guidance, the

Staff removed the water-to-cement ratio and replaced it with the statement, 'subsequent inspections performed did not exhibit degradations related to

freeze-thaw'. This substitution is consistent with ACl 318, Durability

.Requirements that state, 'Since it is difficult to accurately determine the

water-cementitious materials ratio of concrete during production, the f'c specified

should be reasonably consistent with the water-cementitious materials ratio

required for durability. Selection of an f'c that is consistent with the

water-cementitious ratio selected for durability will help ensure that the required

water-cementitious materials ratio is actually obtained in the field.' ACl 318 also

states that the quality and production of concrete must be considered. At MNGP,

all in place concrete met or exceeded the design required strength (f'c).

Concrete inspections continue to show no evidence of degradation due to

freeze-thaw. Plant concrete design specifications (Specification for Purchase of

Off-Site Concrete for the MNGP, Specification for Forming, Placing, Finishing

and Curing of Concrete, and Specification for Materials Testing Services, etc.)

include requirements that satisfy ACI 318 standards for materials, durability,

concrete quality, mixing, and placing. Plant documents confirm that the concrete

was constructed in accordance with the recommendations in ACI 201.2R for

durability and therefore able to resist freeze-thaw and other age related

degradation. Materials used in the concrete mix design conformed to ASTM

specifications (C-94, C-1 50, etc.) that ensured consistent, proportional,

non-porous concrete of quality materials. Aggregates conformed to the

requirements of ASTM C-33 and were accepted based on ASTM C-295

(petrographic) C-289 (reactivity) and other tests. Mixing and delivering of

concrete was in accordance with ACI standards for hot and cold weather

conditions (ACI 305, ACl 306) and appropriate air entrainment, adequate curing,

and special attention to construction practices were maintained with reference to

ASTM C-260, C-494 and C-618. Utilizing industry construction standards

ensured good workmanship and quality control practices (i.e., the requirements

of ACI 304, 308, 309, ASTM C-94, etc.).

Compliance with the above industry code requirements and guidelines ensures

that freeze-thaw is not significant as proven by the absence of freeze-thaw

degradation.

The staff's review found the applicant's response to RAI 3.5.2-1 acceptable. The staff found

that the applicant provided sufficient information to conclude that its below-grade concrete will

not require an AMP for loss of material due to the freeze-thaw aging mechanism; therefore, the

staff's concern described in RAI 3.5.2-1 is resolved.

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In RAI 3.5.2-2, dated September 28, 2005, the staff noted that the applicant listed below-grade

concrete (foundation, walls) as requiring no AMP in Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,

3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicant stated that

no AMP is required to manage aging because, as described in Note 506, (1) the plant initial

licensing basis did not include a program to monitor settlement, (2) no significant settlement

has been observed, and (3) de-watering systems are not used. The applicant's statement is

inconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the

requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific

program for inaccessible areas." Therefore, the staff requested that the applicant provide an

appropriate AMP for this component group and below-grade concrete (foundation, walls, lean

concrete) listed in Table 3.5.2-8.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Note: This response applies to Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7, 3.5.2-8,

3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16, 3.5.2-17 and

3.5.2-18 but is not applicable to Table 3.5.2-13 (i.e. not applicable since there is

no below grade concrete inside drywell).

ISG-03 did not include an evaluation for the aging effects cracks, distortion, and

increase in component stress level due to settlement and therefore

NUREG-1 801 (2001) was used to evaluate the plant specific applicability of this

aging effect. Settlement is a condition that directly affects the concrete

foundation components (see NUREG-1,557 page B-154 and Electric Power

Research Institute (EPRI) 103842 page 4-88), and thus applicable to

inaccessible concrete. NUREG-1 801 (2001) states that,

'The initial Licensing Basis for some plants included a program to monitor

settlement. If no settlement was evident during the first decade or so, the

NRC may have given the licensee approval to discontinue the program.

However, if a de-watering system is relied upon for control of settlement,

then the licensee is to ensure proper functioning of the de-watering system

through the period of extended operation.'

LRA Note 506, Table 3.5.1 item number 3.5.1-25, and further evaluation

3.5.2.2.1.2 included the following statement.

'The plant initial Licensing Basis did not include a program to monitor

settlement. No significant settlement has been observed on any major

structure and de-watering systems are not used. This satisfies NUREG-1801

condition requirements on concrete settlement, and therefore cracks,

distortion, and increase in component stress levels due to settlement do not

require aging management.'

The NUREG-1801 criteria used to evaluate concrete for settlement consists of

an initial Licensing Basis program to monitoring settlement, evident of settlement

during the first decade, and a de-watering system relied upon for settlement

control. All are not applicable to the MNGP. The initial licensing basis did not

include a settlement monitoring program, no significant settlement has ever been

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observed on any major structure, and de-watering systems were not used (see

discussion on the Diesel Fuel Oil Transfer House that follows).

Additionally, the MNGP USAR, Section 12.2.1.11 includes a discussion on

foundation design and construction. The USAR provides conclusions on

foundation designs based on soil bearing values. Major building structures were

constructed on bedrock, compacted granular fill, or stiff clay. No unusual or

unforeseen foundation construction problems were encountered. A survey

traverse of points on the buildings was established to monitor foundation

settlement. This survey determined that settlement was uniform and within the

predicted values. The reactor building, the turbine building and other structures

are supported on mat foundations. The stack and control and cable spreading

building are also on mat foundations, and the emergency diesel generator

building is constructed on a continuous footing foundation. The emergency

filtration train building rests on a combination of mat and caisson foundations.

The MNGP review is consistent with NUREG-1 801 condition requirements for

settlement, similar to the review performed in the Dresden and Quad Cities

Safety Evaluation Report (SER), NUREG-1796. NUREG-1796 stated that, 'no

aging management is required' and the Staff responded with, 'The Staff finds the

applicant's explanation to be acceptable because there has been no requirement

to monitor settlement as part of the licensing basis for all four units, and there

are no de-watering systems in place.'

Although not managed for cracks, distortion, and increase in component stress

level due to settlement (except for the Diesel Fuel Oil Transfer House, see

below), all accessible concrete is managed for aging effects including cracks,

loss of material, etc. Additionally, whenever an inaccessible area is excavated,

exposed or modified, an inspection is performed.

As stated above, settlement has not been observed at any major structures. The

Diesel Fuel Oil Transfer House, a small structure north of the Emergency Diesel

Generator Building has experienced settlement. The structure is rectangular with

external dimensions of 11'-6" (N-S) x 14' (E-W) x 13'-6" high. Walls are

1'-6" thick. It is a moderate weight structure exerting a mean bearing pressure of

about 1,100 lb. / ft.2 on the underlying foundation material. The foundation

material is compacted granular backfill underlain by stiff clay lenses and

sandstone bedrock, and should not be susceptible to settlement under the load

imposed. However the Diesel Fuel Oil Transfer House has undergone significant

differential settlement. Based on plant records and settlement data, settlement of

the Diesel Fuel Oil Transfer House occurred rather rapidly following construction

and was probably due to washout after a rainstorm and was long ago effectively

complete. Settlement data recorded annually since 1992 continues to show no

significant settlement of the structure. A Nonconformance Report root cause

analysis concluded there was insufficient foundation support to prevent settling.

Measurements taken in 1976, 1979 and 1991 show settlement has continued

over the years since construction but at an extremely low rate. Surveys

determined that the entire building has settled about 34" to 1" on the east side

and about 5 1/•" to 5 1/2" on the west side. No evidence of cracks or distortion has

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been observed by the Structures Monitoring Program inspections performed in

1996 and 2002. The Diesel Fuel Oil Transfer House is monitored for the aging

effects of cracks, distortion, and increase in component stress level due to

settlement now on an annual basis as part of the Structures Monitoring Program

and will be managed throughout the period of extended operation.

In conclusion, cracks, distortion, and increase in component stress level due to

settlement is not an applicable aging mechanism for any in scope structure with

the exception of the Diese[iFuel Oil Transfer House which is managed for aging

effects due to settlement.

The staff's review found the applicant's response to RAI 3.5.2-2 acceptable. The applicant

provided sufficient information to justify that, except for the diesel fuel oil transfer house, which

is managed for aging effects due to settlement, other building structures need no management

for aging effects due to settlement. The staff found the applicant's statement reasonable and

acceptable regarding its management of all accessible concrete for aging effects, including

cracks and loss of material, and its inspection of inaccessible areas whenever they are

excavated, exposed, or modified; therefore, the staff's concern described in RAI 3.5.2-2 is

resolved.

The staff's audit and review of the applicant's program found that the applicant demonstrated

that the aging effects will be adequately managed so that the intended functions will be

maintained during the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.5.2.3.1 Structures and Component Supports-Cranes, Heavy Loads, Rigging-Summary of

Aging Management Evaluation-Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the

cranes, heavy loads, and rigging component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.2 Structures and Component Supports-Diesel Fuel Oil Transfer House-Summary of

Aging Management Evaluation-Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the

diesel fuel oil transfer house component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.3 Structures and Component Supports-Emergency Diesel Generator

Building-Summary of Aging Management Evaluation-Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the

EDG building component groups.

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All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.4 Structures and Component Supports-Emergency Filtration Train

Building-Summary of Aging Management Evaluation-Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the

emergency filtration train building component groups..

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.5 Structures and Component Supports-Fire Protection Barrier-Summary of Aging

Management Evaluation-Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the

FP barrier commodity groups.

The staff also reviewed LRA Section 3.5.2.1.5, which identified the materials, environments,

AERMs, and AMPs for the FP barrier commodity group. The staff conducted its review,

described below, in accordance with SRP-LR Section 3.5 and the GALL Report.

The staff's review of LRA Table 3.5.2-5 identified areas for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAIs as discussed below.

In RAI 3.5.2.1.5-1, dated August 18, 2005, the staff noted that LRA Table 3.5.2-5 refers'to the

Fire Protection Program as the AMP to manage loss of material for carbon steel in air/gas.

Therefore, the staff requested that the applicant justify this conclusion.

In its response, by letter dated September 16, 2005, the applicant stated that LRA Table 3.5.2-5

refers to the Fire Protection Program as the AMP for carbon steel with a fire barrier intended

function in an air/gas environment. The scope of the program described in Fire Protection

Program PBD/AMP-013, Table 7.1, includes fire barriers with specific reference to carbon steel

with an aging effect of loss of material in a plant indoor air environment (i.e., air/gas

environment). This description is consistent with LRA Table 3.5.2-5.

The staff's review found the applicant's response to RAI 3.5.2.1.5-1 acceptable because the

scope of the Fire Protection Program includes fire barriers with specific reference to carbon

steel with an aging effect of loss of material in a plant indoor air environment, as described in

Fire Protection Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire

Protection Program, including Table 7.1 of PBD/AMP-013, found that it provides reasonable

assurance that carbon steel components in an air/gas environment in the FP system will be

managed for aging effects during the period of extended operation. Therefore, the staff's

concern described in RAI 3.5.2.1.5-1 is resolved.

In RAI 3.5.2.1.5-2, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-5, 3.5.2-15,

and 3.5.2-17 refer to the Fire Protection Program as the AMP for fibrous fire wraps (thermal

insulating wool/fiber), cementitious fireproofing (thermal insulating mastic), and rigid board

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(thermal insulating board).in air/gas; therefore, the staff requested that the applicant justify this

conclusion.

In its response, by letter dated September 16, 2005, the applicant stated that LRA

Tables 3.5.2-5, 3.5.2-15, and 3.5.2-17 refer to the Fire Protection Program as the AMP for

managing aging effects for fibrous fire wraps, cementitious fireproofing, and rigid board with a

fire barrier intended function in an air/gas environment. The scope of the Fire Protection

Program, as described in Fire Protection Program PBD/AMP-013, Table 7.1, includes fire

barriers with specific reference to fibrous fire wraps, cementitious fireproofing, and rigid board

with the aging effects of cracking, delamination, and loss of material in an air/gas environment.

This description is consistent with LRA Tables 3.5.2-5, 3.5.2-15, and 3.5.2-17.

The staff's review found the applicant's response to RAI 3.5.2.1.5-2 acceptable because the

scope of the Fire Protection Program includes fire barriers with specific reference to fibrous fire

wraps, cementitious fireproofing, and rigid board with the aging effects of cracking,

delamination, and loss of material in an air/gas environment, as described in Fire Protection

Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire Protection

Program, including PBD/AMP-013, Table 7.1, found that it provides reasonable assurance that

fibrous fire wraps, cementitious fireproofing, and rigid board in an air/gas environment in the FP

system will be managed for aging effects during the period of extended operation. Therefore,

the staff's concern described in RAI 3.5.2.1.5-2 is resolved.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant adequately identified applicable

aging effects and the AMPs credited with managing them for the fire barrier commodity group

not addressed by the GALL Report. The staff found the applicant's AMR results for the fire

barrier commodity group acceptable.

3.5.2.3.6 Structures and Component Supports-Hangers and Supports-Summary of Aging

Management Evaluation-Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the

hangers and supports commodity groups.

The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion of

stainless steel materials for supports for ASME Code Class MC components (i.e., vent header

column support pins exposed to treated water environment) using the ASME Section Xl,

Subsection IWF Program.

SER Section 3.0.3.2.3 documents the staff's review of the ASME Section XI, Subsection IWF

Program. The ASME Section Xl, Subsection IWF Program is part of the ASME Section Xl

In-Service Inspection Program. It provides for condition monitoring of Class 1, 2, 3, and MC

component supports. The applicant will enhance it to inspect Class MC component supports

consistent with the GALL Report, Chapter III, Section B13.3. The parameters monitored or

inspected are loss of material and loss of mechanical function. The NDE technique used is the

VT-3 method to detect unacceptable conditions such as loss of material and loss of mechanical

function.

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In RAI 3.5.2-3, dated September 28, 2005, the staff noted that the Table 3.5.2-6 lists belowgrade concrete (diesel fuel oil storage tank deadmen) as requiring no AMP. The applicant

stated that no AMP is required to manage aging because, as described in Note 552,

"NUREG-1 801 lists inside or outside containment as the environment. Consider that this

environment includes atmosphere/weather and below grade." The applicant's statement is

inconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the

requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific

program for inaccessible areas." Therefore, the staff requested that the applicant provide an

appropriate AMP for this component group.

In its response, by letter dated October 28, 2005, the applicant stated the following:

The buried Diesel Fuel Oil Storage Tank is anchored to a concrete foundation.

To account for this condition, NUREG-1801 line item IIl.B4.3-a, 'building

concrete at locations of expansion and grouted anchors' was used. Although

probably not the best usage of line IIl.B4.3-a, it was chosen to address this

unique condition. Note 552 was provided to clarify the different environment used

than that specified in NUREG-1 801 (i.e., below grade rather than the

NUREG-1801 environment, inside or outside containment). The LRA AMP also

differed from that specified in NUREG-1 801. Generic Note 'T was used to

describe these differences since it was considered the 'best' note available to

describe this unique condition. The aging effect, 'reduction in concrete anchor

capacity due to local degradation' for the inaccessible location was evaluated by

considering all possible concrete degradation mechanisms including

freeze-thaw (Ill.A3.1 -a), leaching of calcium hydroxide (Ill.A3.1 -b), reaction with

aggregate (Ill.A3.1 -c), corrosion of embedded steel (I11.A3.1 -e), aggressive

chemical attack (II.A3.1-g), settlement (llI.A3.1-h), and erosion of porous

concrete sub-foundations (llI.A3.1-h). The evaluation concluded that these

mechanisms did not require aging management (see page 3-686 of the LRA).

Service induced cracking was also not applicable since vibration/movement of

the tank is not expected and the fact that the tank is surrounded by soil/fill

material. Therefore reduction in concrete anchor capacity due to local

degradation was determined insignificant and aging management not required.

The staff's review found the applicant's response to RAI 3.5.2-3 acceptable. The applicant's

response stated that it had evaluated all the possible aging mechanisms/effects and concluded

that they did not require an AMP. The staff found the applicant's conclusion reasonable and

acceptable; therefore, the staff's concern described in RAI 3.5.2-3 is resolved.

In RAI 3.5.2-7, dated September 28, 2005, the staff noted that Table 3.5.2-6 identifies two line

items related to carbon steel and low-alloy steel embedded in concrete as not requiring aging

management. Note 549 states, "Requirements specified in NUREG-1 801 for concrete quality,

inspections, and housekeeping are satisfied for steel elements in inaccessible areas." Based on

the industry-wide experience related to corrosion of the drywell shell in the sand pocket region,

the staff requested that the applicant provide information regarding its inspections and

housekeeping related to carbon steel and low-alloy steel embedded in concrete and explain

why these activities should not be a part of an existing AMP. The embedded items are included

in an existing program to look for evidence of environment change (e.g., sand drains not

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working properly) in accessible areas that will indicate potential degradation in inaccessible

areas.

The same question applied to carbon steel and low-alloy steel embedded in concrete listed in

Table 3.5.2-13.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Components in Table 3.5.2-6 refer to the embedded anchorage of the drywell

support skirt, the embedded components of the female stabilizers, and

embedded conduit. The evaluation of the embedded portions of the drywell shell

and drywell support skirt is provided in Table 3.5.2-13.

The applicant deliberated how these components meet the following four recommendations in

GALL Report line item lI.B13.1.1.-a:

(1). Concrete meeting the requirements of ACI 318 or 349 and the guidance

of ACl 201.2R was used for the containment concrete in contact with the

embedded containment shell or liner.

(2) The concrete is monitored to ensure that it is free of penetrating cracks

that provide a path for water seepage to the surface of the containment

shell or liner.

(3) The moisture barrier, at the junction where the shell or liner becomes

embedded, is subject to aging management activities in accordance with

IWE requirements.

(4) Borated water spills and water ponding on the containment concrete floor

are not common and when detected are cleaned up in a timely manner.

The applicant provided the following plant-specific evaluation:

(1) Concrete meeting the following requirements was used for the

containment concrete in contact with the embedded containment shell

and skirt. The MNGP concrete design specifications for Purchase of

Off-Site Concrete for the MNGP, Specification for Forming, Placing,

Finishing and Curing of Concrete, Specification for Materials Testing

Services and others specifications include requirements that satisfy

ACl 318 standards for materials, durability, concrete quality, mixing and

placing. Plant documents confirm that the concrete was constructed in

accordance with the recommendations in ACI 201.2R for durability and

therefore able to resist weathering action, chemical attack, abrasion,

leaching of calcium hydroxide, corrosion of reinforcement, and chemical

reactions of aggregates. Materials used in the concrete mix design

conformed to ASTM specifications (C-94, C-150, etc.) that ensure

consistent, proportional, non-porous concrete of quality materials.

Aggregates conformed to the requirements of ASTM C-33 and were

accepted based on ASTM C-295 (petrographic) C-289 (reactivity) and

other tests. Mixing and delivering of concrete was in accordance with ACI

standards for hot and cold weather conditions (ACI 305, ACI 306) and

appropriate air entrainment, adequate curing, and special attention to

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construction practices were maintained (ASTM C-260, C-494 and C-618).

MNGP construction specifications ensure good workmanship and quality

control practices (ACI 304, 308, 309, ASTM C-94, etc.).

(2) For accessible concrete inside drywell, the Structures Monitoring

Program inspects for cracking adjacent to the moisture barrier, at the

concrete floor, and RPV Pedestal. Inspections ensure that the concrete is

free of penetrating cracks that provide a path for water seepage to the

containment shell. The bioshield wall is completely encased in steel and

therefore inaccessible for inspection.

AMPs will be used to manage the drywell to reactor building refueling seal

bellows assembly located between the drywell outer shell and the reactor

building concrete (See Table 3.5.2-15). By managing this assembly for aging

degradation and water leakage (during refueling activities), any water seepage

past the assembly to the drywell shell, sand pocket, embedded shell, and

embedded skirt will be prevented, or detected and corrected. Therefore, loss of

material due to corrosion for these components will beinsignificant. Aging

managed for the drywell to reactor building refueling seal bellows assembly will

be provided by the Primary Containment In-Service Inspection Program and

the Structures Monitoring Program. These Programs ensure that degradation

of the assembly or any water leakage past the assembly will be detected and

corrected before loss of intended function. These programs ensure that,

- the drywell air gap drain outlets and sand pocket drain outlets are not

obstructed prior to refueling - the drain lines that are incorporated into the refueling bellows assembly

are monitored for leaks - the drywell air gap drain outlets and drywell sand pocket drain outlets

are inspected for signs of leakage during refueling, and - aging effects including loss of material are detected.

The Plant Chemistry Program is also used to manage the assembly by

ensuring that the water chemistry remains within design parameters.

MNGP operating history showed no evidence of refueling seal leakage, no

water observed in air gap during construction, and no water used to extinguish

a fire in the air gap or for any other reason. Plant engineering and maintenance

personnel confirmed the absence of leakage at the drywell air gap drains, and

the sand pocket drains. Plant specific operating history has proven that

inspection and monitoring activities adequately manage aging effects to ensure

no loss of intended function.

The applicant further asserted that the Primary Containment In-Service Inspection Program

manages aging effects associated with the moisture barrier and that borated water inside the

drywell is not a concern for BWR plants. With these assertions, the applicant pointed out that

loss of material due to corrosion is not significant.

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The staff evaluated the information provided above, and the information provided to the NRC's

aging management inspection team on the status of the drywell shell, and made the following

findings:

* The operating history confirmed that there is no indication of water in the air gap

between the shell and the shield concrete.

* The UT measurements taken, in mid-1 986 and at the end of 1987, indicate that the

metal thickness in the sand pocket region varies from 1.065 inches to 1.13 inches, and

the design thickness in this area of the drywell shell is 1.0 inch.

* In response to NRC GL 87-05, "Request for Additional Information Assessment of

Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells,"

the applicant made sure that the three drain paths (i.e., the drain that would prevent

potential leakages from refueling seal areas, the drains at the sand pocket areas above

the sealed sand pocket area, and the drains at the bottom of .the sand pocket area) are

clear of any obstruction. The applicant has been monitoring these drains and plans to

continue the practice during the period of extended operation.

* The entire refueling seal area is within the scope of license renewal.

* During the 1987 visual examination, some surface corrosion was noted where the

concrete floor meets the inside surface of the drywell shell. This was attributed to the

joint sealant used during initial construction. The sealant was removed and replaced

with nonshrink grout and a new type of sealant that would prevent corrosion. The

applicant will periodically examine this area as required by Subsection IWE of Section Xl

of the ASME Code.

Based on the above findings, the staff concluded that MNGP will adequately manage the

inaccessible areas of the drywell shell during the period of extended operation, and the concern

expressed in RAI 3.5.2-7 is resolved.

In RAI 3.5.2-8, dated September 28, 2005, the staff noted that recent experience with torus

cracking at Fitzpatrick indicates HPC discharge configuration in the torus as a cause of

cracking; therefore, the staff requested that the applicant describe its HPC configuration that

could affect torus integrity during the period of extended operation.

In its response, by letter dated October 28, 2005, the applicant stated the following:

The HPCI turbine exhaust discharge pipe configuration at MNGP is significantly

different than that at Fitzpatrick.

- The HPCI turbine exhaust at Fitzpatrick is located near the torus ring

girder (end bay) while the MNGP HPCI turbine exhaust is located

approximately mid-bay between torus ring girders

The Fitzpatrick HPCI exhaust pipe incorporates a 90 degree elbow, is

relatively short with no holes, and discharges vertically in the vicinity of

the torus ring girder and stiffener plates that are part of the torus external

column support system. The Fitzpatrick torus crack was observed

adjacent to these stiffener plates. The MNGP exhaust pipe is

considerably longer with a submerged sparger that consist of a pipe,

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capped at one end, with a large number of holes in the lower portion

which increases the area available for steam condensation compared to

a straight pipe discharge. The MNGP pipe is not a vertical run, but

instead, incorporates a 60 degree elbow.

Based on the above comparison, the HPCI Turbine Exhaust configuration and

location at MNGP is unlike that at Fitzpatrick. The MNGP pipe configuration and

location are believed to be less susceptible to cracking and therefore less likely

to affect torus integrity during the period of extended operation.

The staff's review found the applicant's response to RAI 3.5.2-8 acceptable. Based on the

review of the root cause analysis of the through-wall crack at Fitzpatrick, the configuration of

HPC steam discharge (using spargers), and the location of HPC exhaust pipe, the staff found

the applicant's torus is not prone to such cracking. Therefore, the staff's concern described in

RAI 3.5.2-8 is resolved.

In RAI 3.5.2-9, dated September 28, 2005, the staff noted that three line items in Table 3.5.2-6

indicate that lubrite plates have been used at several locations in hangers and supports. The

staff's position is that an inspection of the accessible portion of the lubrite bearing is needed to

ensure proper functioning during postulated environmental conditions; therefore, the staff

requested that the applicant incorporate an examination of the accessible portion of the lubrite

bearings in an appropriate AMP.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Industry guidance provided in EPRI-1 002950, Aging Effects for Structures and

Structural Components, Revision 1 dated August 2003 for lubrite or similar

material states that, 'An extensive search of industry operating experience did

not identify any instances of lubrite plate degradation or failure to perform its

intended function.' Additionally EPRI states that, 'Lubrite material resists

deformation, has a low coefficient of friction, resists softening at elevated

temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion,

withstands high intensities of radiation, and will not score or mar. Lubrite

products are solid, permanent, completely self lubricating, and require no

maintenance for the design life of the product. The lubrite lubricants used in

nuclear applications are designed specifically for the environments to which they

are exposed.'

Review of the MNGP pipe support and MC component support drawings where

Lubrite or similar material was used reveals that the sliding surfaces are

sandwiched between plates, and therefore, inaccessible for inspection. Plant

specific operating experience found no evidence of age-related degradation for

Lubrite or similar material during support overhaul activities, and no pipe or pipe

support failures attributed to the inability of sliding surface material to function as

designed.,

However, the applicant stated that aging effects for lubrite or similar materials are not

significant, and although no aging management is required, the ASME Section Xl, Subsection

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IWF Program inspects the supports in LRA Table 3.5.2-6 incorporating the use of lubrite or

similar materials.

The staff's review found the applicant's response to RAI 3.5.2-9 acceptable. The staff

recognized the operating experience with the use of lubrite bearings and found the applicant's

approach to inspect them under its ASME Section Xl, Subsection IWF program acceptable.

Therefore, the staff's concern described in RAI 3.5.2-9 is resolved.

On the basis of its review of the applicant's programs, aging effects, and plant-specific and

industry operating experience, the staff determined that the ASME Section XI, Subsection IWF

Program effectively manages the loss of material due to MIC, pitting, and crevice corrosion of

stainless steel materials for supports for ASME Code Class MC components (i.e., vent header

column support pins exposed to treated water environment), as given in LRA Table 3.5.2-6.

3.5.2.3.7 Structures and Component Supports-HPC Building-Summary of Aging

Management Evaluation-Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the

HPC building component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.8 Structures and Component Supports-Intake Structure-Summary of Aging

Management Evaluation-Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the

intake structure component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.9 Structures and Component Supports-Miscellaneous Station Blackout Yard

Structures-Summary of Aging Management Evaluation-Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the

miscellaneous SBO yard structures component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.10 Structures and Component Supports-Offgas Stack-Summary of Aging

Management Evaluation-Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for

the offgas stack component groups.

In RAI 3.5.2-4, dated September 28, 2005, the staff noted that Table 3.5.2-10 lists below-grade

concrete (Pedestal) as requiring no AMP. The applicant stated that no AMP is required to

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manage aging because, as described in Notes 501 and 506, (1) the plant initial licensing basis

did not include a program to monitor settlement, (2) no significant settlement has been

observed, (3) de-watering systems are not used, and (4) plant documents confirm that the

concrete had an air content between 3 and 6 percent and inspection of concrete in accessible

areas found no degradation related to freeze-thaw. The GALL Report recommends that

concrete should have a water-to-cement ratio of 0.35-0.45 to ensure no aging degradation.

related to freeze-thaw; therefore, the staff requested that the applicant verify the

water-to-cement ratio as 0.35-0.45. The staff noted that the applicant's statement is

inconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the

requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific

program for inaccessible areas." The staff raised the same question for below-grade concrete

(foundation, walls, slabs, grout) listed in Table 3.5.2-18.

In its response, by letter dated October 28, 2005, the applicant stated that the responses to

RAIs 3.5.2-1 and 3.5.2-2 are applicable to this question. The staff's review found the applicant's

response to RAI 3.5.2-4 acceptable. The staff's evaluation of these responses is described in

SER Section 3.5.2.3. Therefore, the staff's concern described in RAI 3.5.2-4 is resolved.

3.5.2.3.11 Structures and Component Supports-Offgas Storage and Compressor

Building-Summary of Aging Management Evaluation-Table 3.5.2-11

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for

the offgas storage and compressor building component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.12 Structures and Component Supports-Plant Control and Cable Spreading

Structure-Summary of Aging Management Evaluation-Table 3.5.2-12

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for

the plant control and cable spreading structure component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.13 Structures and Component Supports-Primary Containment-Summary of Aging

Management Evaluation-Table 3.5.2-13

The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for

the primary containment component groups.

The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion of

stainless steel materials for thermowells exposed to a treated water environment using the

Plant Chemistry, Primary Containment In-Service Inspection, and 10 CFR Part 50, Appendix J

Programs.

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The SER documents the staff's reviews and evaluations of the Plant Chemistry Program, the

Primary Containment In-Service Inspection Program, and the 10 CFR 50, Appendix J Program

in Sections 3.0.3.2.19, 3.0.3.1.6, and 3.0.3.2.1, respectively.

Pitting of stainless steel components relates primarily to the presence of detrimental ionic

species like chlorides, fluorides, and sulfates. Crevice corrosion of stainless steel components

relates primarily to the presence of significant levels of dissolved oxygen. The Plant Chemistry

Program manages these aging effects by ensuring that corrosive ion concentrations do not

exceed acceptance limits and that pH remains within an acceptable range. In addition, this

program controls the growth of organic substances, thus eliminating MIC.

The Primary Containment In-Service Inspection Program specifies visual examination of

accessible surfaces on the containment pressure-retaining boundary, internal vent system, and

steel components within the torus to detect indications of damage or deterioration that could

adversely affect the intended functions of the containment system.

The 10 CFR 50, Appendix J Program specifies pneumatic pressure tests and visual

examinations to verify the structural and leak integrity of the primary containment.

In RAI 3.5.2-5, dated September 28, 2005, the staff noted that, in describing the intended

functions of the three items in Table 3.5.2-13 related to concrete in air/gas, the applicant stated

that one of the intended functions is "non-safety support." Therefore, the staff requested that

the applicant clarify this characterization in terms of the CLB safety classification as well as in

terms of the criteria in 10 CFR 54.4, "Scope," and provide examples of how the components

provide nonsafety support.

In its response, by letter dated October 28, 2005, the applicant explained:

The primary containment in scope concrete components subject to an AMR with

the intended function, 'non-safety support' were identified in Table 2.4.13-1 with

AMR results provided in Table 3.5.2-13. Table 2.1-1 of the LRA included the

definition as,

'Provide structural support to non-safety related components whose failure

could prevent satisfactory accomplishment of any of the required safety

related functions.'

This component-level intended function was the specific function of the

component that supported system-level functions that formed the basis for

including the primary containment structure within the scope of license renewal.

The scoping methodology utilized by the NMC for the MNGP was consistent with

the guidance provided by the NRC in NUREG-1 800 and by the industry in

Nuclear Energy Institute (NEI) 95-10.

In terms of the MNGP CLB, this function was characterized in a license renewal

technical report as,

'The MNGP CLB includes a number of topics that identify NSR SSCs

credited for preventive or mitigative functions in support of safe shutdown for

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special events (e.g., external floods) or whose failure could prevent

satisfactory accomplishment of a Scoping Criterion 1 function (e.g.,

Seismic Il/I considerations). Based on a review of the CLB, those topics that

meet Scoping Criterion 2 are, High Energy Line Break (HELB)...Flooding

Events ...Missile Hazards...Overhead Handling Systems.. .Seismic

Interaction.'

In terms of 10 CFR 54.4, this function was characterized in a technical report for

license renewal as,

'[Non-safety related] NSR SSCs directly connected to Scoping Criterion 1

SSCs: The in-scope boundary for license renewal extends into the NSR

portion of the piping and supports up to and including the first equivalent

anchor beyond the safety/nonsafety interface. For Monticello, the first

equivalent anchor is that point beyond which failure of the piping system will

not prevent the satisfactory accomplishment of the Scoping Criterion 1

function of the connected SSCs.

NSR structures attached to, or next to, Scoping Criterion 1 structures are in

scope for license renewal if their failure could prevent a Scoping Criterion 1

SSC from performing its intended function.

NSR SSCs that are not directly connected to Scoping Criterion 1 SSCs: The

NSR SSCs may be in-scope if their failure could prevent the performance of

a Scoping Criterion 1 function.'

The license renewal technical report included further discussion on NSR SSCs

that are not directly connected to Scoping Criterion 1 SSCs with detailed

information on the identification process of spatial interactions, a process to

determine which NSR conduits, trays, junction boxes, and lighting fixtures to

consider in scope for license renewal, and the process for determining in scope

NSR HVAC ducts and supports.

An example of how concrete components provide nonsafety support would be an

attachment to the concrete of NSR light fixtures or NSR HVAC duct routed

near/above scoping Criteria 1 components.

The staff's review found the applicant's response to RAI 3.5.2-5 acceptable. The applicant

described the scoping process for NSR components (including the components that function as

supports). This description is sufficient to explain the nonsafety characterization of the

components, and the staff found the scoping process used in this contbxt acceptable.

Therefore, the staff's concern described in RAI 3.5.2-5 is resolved.

In RAI 3.5.2-6, dated September 28, 2005, the staff noted that Table 3.5.2-13 lists several

structural components (e.g., drywell equipment foundation, bioshield wall, RPV pedestal) under

the component type concrete in air/gas. LRA Section 3.5.2.2.1.3 and Note 508 describe and

justify the elevated temperatures around the reactor vessel based on the estimated

temperatures in the drywell; therefore, the staff requested that the applicant provide (1) a

summary description of the cooling system installed to control the temperatures inside the

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drywell and (2) the operating experience related to the effectiveness of the cooling system.

Relevant to this request, the staff inquired whether the shield wall temperatures or any other

parameter monitored will detect malfunctioning of the cooling system.

Furthermore, following the discussion of the elevated temperatures in and around the bioshield

wall in LRA Section 3.5.2.2.1.3, the staff agreed that the concrete properties will not be affected

significantly if the actual temperatures around the shield wall remain within the estimated limits;

however, additional shrinkage and loss of moisture due to radiation could degrade the concrete

in the long term. In this context the staff requested that the applicant summarize the results of

the last two inspections performed for (1) the bioshield wall, (2) RPV pedestal, (3) anchorages

of seismic stabilizer frame, and (4) masonry walls (if any) inside the drywell.

In its response, by letter dated October 28, 2005, the applicant provided the following

discussion:

a) Drywell fan coolers are used to control temperatures inside the drywell.

USAR Section 5.2 states that, 'The primary containment ventilating and

cooling system consists of four air coolers which cool the atmosphere to

below a 135 OF bulk average drywell temperature during normal plant

operation. The drywell atmosphere is circulated through the drywell and the

air coolers by fans, and the reactor building closed cooling water system is

employed to remove heat from the air coolers.'

b) Plant daily operating data confirms that the general area maximum normal

operating temperature inside drywell is below the NUREG-1 801 limit of

150 OF. Therefore the drywell fan coolers have proven their effectiveness in

controlling the drywell air temperature. Plant calculations determined that the

biological shield wall pipe penetrations were sufficiently designed in size,

insulation characteristics, and air gap to limit the local area maxinmum normal

operating temperatures to 179 OF, less than the NUREG-1 801 threshold local

area temperature of 200 OF.

c) Results of the 1996, 1998 and 2002. Periodic Structural Inspection Reports

found all concrete at the RPV Pedestal to be acceptable with no deficiencies

observed. The bioshield wall is complete encased in steeland therefore

cannot be inspected. Drywell structural steel components were found

acceptable with no deficiencies observed including stabilizer attachment

welds to the plated bioshield wall. USAR Section 12 states that the primary

function of the bioshield wall is, 'to protect equipment inside the drywell

against radiation and thermal effects. The structure is capablb of transmitting

loads due to seismic and jet forces acting on it. The biological shield is

composed of two steel cylinders interconnected with 27 WF (177 lb/ft)

columns and is filled with concrete. Because of the radiation and temperature

effects on the concrete only the lower 12 feet of concrete, up to the 959 foot

elevation, has been designed as structural concrete capable of resisting

forces and shears. Above the 959 foot elevation the two steel cylinders and

27 WE columns are structurally adequate and the concrete fill has not been

considered as adding to the support.'

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The staff's review found the applicant's response to RAI 3.5.2-6 acceptable. The response

adequately describes the temperatures in the drywell and the effectiveness of the cooling

system in keeping temperatures within the threshold limits. The response also describes the

condition of the vital concrete and structural components in the drywell. The staff found the

applicant's method of cooling the drywell atmosphere and monitoring the structural components

in the drywell acceptable; therefore, the staff's concern described in RAI 3.5.2-6 is resolved.

In RAI 3.5.2-10, dated September 28, 2005, the staff noted that a recent breakage of

T-quencher support bolts at the Edwin I. Hatch plant indicated that the Plant Chemistry

Program that controls the chemistry of treated water may not be adequate for managing the

aging of submerged support components; therefore, the staff requested that the applicant

address the adequacy of the Plant Chemistry Program alone to manage the aging degradation

of the submerged supports. The staff further noted that this RAI applies to all line items in

Table 3.5.2-13 identifying the Plant Chemistry Program as the sole AMP.

In its response, by letter dated October 28, 2005, the applicant confirmed the following:

All line items in Table 3.5.2-13 in a treated water environment (submerged) are

managed by the Plant Chemistry Program, in addition to the MNGP Primary

Containment In-Service Inspection Program, and in many cases, are also

managed by a third program, 10 CFR 50, Appendix J. Therefore, the applicant

asserted this RAI is not applicable to MNGP.

Additionally, the MNGP Primary Containment In-Service Inspection Program

includes activities that perform periodic visual inspections by divers (when the

torus is not drained) and by engineers (when drained) for submerged

components, including their support members, bolted connections, and welds.

Components inspected include such items as T-quenchers, SRV piping and

supports, ECCS strainers, vent header supports, catwalk supports, and other

submerged piping and supports not included in the IWE, VT-3 inspection.

Inspections are conducted periodically at intervals not to exceed five (5) years.

The MNGP Primary Containment In-Service Inspection Program manages aging

effects for visible degradation such as deformation, cracks, corrosion, loose

bolts, etc.

The staff's review found the applicant's response to RAI 3.5.2-10 acceptable. The response

indicates that the applicant plans to use the Primary Containment In-Service Inspection

Program and the 10 CFR Part 50, Appendix J Program, as appropriate, for managing aging of

components in these line items. The staff found the applicant's approach to managing the aging

of these components acceptable; therefore, the staff's concern described in RAI 3.5.2-10 is

resolved.

In RAI 3.5.2-11, dated September 28, 2005, the staff noted that for a number of items in

Table 3.5.2-13, the applicant identified the 10 CFR Part 50, Appendix J Program as the AMP to

manage aging. Option B of Appendix J will permit the applicant to conduct Type B leakage rate

tests of penetrations at 10-year intervals; therefore, the staff requested that the applicant

address the plant-specific process (e.g., test frequency and operating experience) credited with

managing degradation and leak tightness of the pressure boundary penetrations, including vent

bellows.

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In its response, by letter dated October 28, 2005, the applicant stated the following:

Type B tests, which are conducted at performance-based intervals not exceeding

120 months (plus an extension of 15 months if required by the refueling.

schedule), are performed to assess leakage through individual penetration

isolation barriers other than valves. Pursuant to NEI 94-01, air lock tests must be

performed at intervals not exceeding 30 months and at other times as

determined by air lock use. Also, bolted access-way cover seals are always

tested following end-of-outage closures of the access-ways. The default interval

between Type B tests is 30 months. The interval may be extended to 60 months

following two (2) consecutive tests with results that meet performance leakage

acceptance criteria and to 120 months following three (3) consecutive tests that

meet these criteria. The interval reverts to the default interval following a test

failure.

The MNGP operating history on bellow leakage/replacement is limited to one,

2-ply bellow. Leakage was identified during LLRT and not a result of cracks

observed during a visual examination. Leakage was identified at the outer-most

bellows from a small failure underneath the outer collar of the expansion joint

and consequently the bellow was replaced. No cracks in the weld metal were

identified. Industry operating history has also identified cracked bellows, but no

cracks in the weld metal.

The staff's review found the applicant's response to RAI 3.5.2-11 acceptable. The operating

history of the penetrations and vent bellows demonstrates that the applicant applies CLB

requirements for leak-rate testing of these pressure-retaining components; therefore, the staff

found the approach used by the applicant in ensuring the leaktightness of these components

acceptable, and the staff's concern described in RAI 3.5.2-11 is resolved.

In RAI 3.5.2-12, dated September 28, 2005, the staff noted that three line items in

Table 3.5.2-13 indicate that lubrite plates had been used at several locations in the primary

containment. In Note 556, the applicant stated that graphite plate material is not used for

drywell head and downcomers; therefore, the staff requested that the applicant clarify how

lubrite plates were used for drywell head and downcomers. In Note 559, the applicant stated

that beam seats in the drywell consist of carbon steel plate over a bronze plate lubricated with

graphite packed into trepanned depressions. The steel plate covers the graphite packing and

protects it from particulate contaminants. The staff believes that if the lubrite bearing is qualified

generally for use in the sustained temperatures and radiation existing in the drywell, the

accessible part of the bearing should be inspected to ensure proper functioning during

postulated environmental conditions. The staff requested the applicant to incorporate an

examination of the accessible portion of the lubrite bearings in an appropriate AMP.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Lubrite type material is not used for the drywell head or downcomers.

Table 3.5.2-13 line entry was necessary to demonstrate that aging effects in

NUREG-1801 line item II.B1.1.1-e were evaluated. The evaluation provided in

Table 3.5.2-13, note 556 stated that, 'The drywell head and downcomer pipes

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are carbon steel material. Graphite plate material is not used for these

components and therefore the aging effect is not applicable.'

NUREG-1 801 line item ll.B1 1.1 -e also includes fretting due to mechanical wear

of carbon steel. EPRI-1002950, Structural Tools, evaluated fretting as loss of

material occurring as a result of the relative motion between two components.

EPRI concluded that thermal cycling during plant heat-up, cool down (refueling

operations) and normal operation have insufficient relative motion and frequency

to result in significant wear. EPRI concluded that wear of carbon steel is a design

issue that incorporates sliding surfaces into the design. In accordance with the

EPRI evaluation, the drywell head and downcomers do not require aging

management for fretting. Note that the drywell head and downcomers are

managed for loss of material due to corrosion consistent with NUREG-1 801

line II.B13.1.1-a. See Table 3.5.2-13 for this evaluation.

On the subject of lubrite plates, the applicant explained the following:

Lubrite material incorporated into radial beam seat connections is used inside

drywell to connect platform steel to the drywell shell. The beam seat Lubrite plate

is sandwiched between larger steel plates which overhang it, and therefore,

inspection is not possible. These beam seats are well over 20 feet from the

reactor pressure vessel and outside the bioshield wall. This is the only

application of Lubrite type material in use inside the drywell where the higher

gamma radiation levels are expected. According to EPRI-1 002950 the only aging

effect for Lubrite is change in material properties, and only if Lubrite is exposed

to at least 104 Rads. Radiation levels outside the bioshield wall at the perimeter

of the drywell would be significantly less that the EPRI threshold limit. All other

Lubrite type material applications are outside the drywell where radiation levels

would typically be significantly less than inside the drywell.

The staff's review found the applicant's response to RAI 3.5.1-12 acceptable. The applicant

clarified its intention and approach in managing the line item components. The staff found the

applicant's aging management of lubrite materials acceptable; therefore, the staff's concern

described in RAI 3.5.2-12 is resolved.

The staff's review of the applicant's programs, the aging effects, and plant-specific and industry

operating experience determined that the Plant Chemistry Program, the Primary Containment

In-Service Inspection Program, and the 10 CFR Part 50, Appendix J Program effectively

manage the aging effect of loss of material due to MIC, pitting, and crevice corrosion of

stainless steel material exposed to a treated water environment. On this basis, the staff found

the applicant's management of loss of material due to MIC, pitting, and crevice corrosion in

primary containment acceptable.

3.5.2.3.14 Structures and Component Supports-Radioactive Waste Building-Summary of

Aging Management Evaluation-Table 3.5.2-14

The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations for

the radioactive waste building component groups.

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All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.15 Structures and Component Supports-Reactor Building-Summary of Aging

Management Evaluation-Table 3.5.2-15

The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations for

the reactor building component groups.

The staff also reviewed LRA Section 3.5.2.1.15, which identifies the materials, environments,

AERMs, and AMPs for the reactor building component group. The staff conducted its review,

described below, in accordance with SRP-LR Section 3.5 and the GALL Report.

The applicant has proposed to manage the reduction of neutron absorbing capacity and loss of

material due to corrosion of boral with the Plant Chemistry Program in conjunction with a

one-time inspection.

The applicant stated that the Plant Chemistry Program manages the aging effects of boral in a

treated water environment due to crevice, galvanic, and pitting corrosion and MIC, and the

aging effect of cracking due to SCC, by ensuring that corrosive ion concentrations do not

exceed acceptable limits and by limiting the amount of impurities in the water. The applicant

further stated that plant test results and industry experience indicate that use of the Plant

Chemistry Program during the period of extended operation will continue to manage the loss of

neutron absorption capacity aging effect effectively. The applicant will apply the One-Time

Inspection Program for added assurance that aging effects do not occur.

The staff's review of LRA Table 3.5.2-15 and LRA Section 3.5.2.1.15 identified areas in which

the staff needed additional information to complete its evaluation of the applicant's results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 3.5.2.1.15-1, dated August 18, 2005, the staff requested that the applicant provide

details of the plant's Boral Coupon Surveillance Program.

In its response, by letter dated September 16, 2005, the applicant stated the following:

...The program placed seven sets of coupons in the fuel pool to be removed on a

periodic basis and tested for degradation. To date, six of the seven coupon sets

have been removed and tested and no degradation has been found (see

response to RAI 3.5.2.1.15-3 for test results). Testing methods include physical

observations; neutron attenuation tests; weight, specific gravity, dimensional

checks; and analysis for boron content. The final (seventh) coupon set will be

removed and tested before the period of extended operation to satisfy the

requirement for a one-time inspection. No further testing is proposed during the

period of extended operation pending acceptable results from the final

inspection.

The applicant based its election not to continue coupon testing into the period of extended

operation partly on the results of the six previously tested coupons, which represent over 20

years of operating experience.

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In response to staff RAI 3.5.2.1.15-3, dated September 16, 2005, the applicant provided test

results for the past coupon inspections indicating that all coupons have retained the required

level of neutron absorption capability with no discernable degradation.

The staff needed additional information to complete its evaluation for the aging management of

boral. The applicant will not test boral coupons into the period of extended operation. For this

reason, the staff requested that the applicant provide details on its ability to identify a potential

aging effect in the plant's boral. Because the applicant will not test actual boral samples, it must

provide assurance that it will be able to identify and mitigate any degradation of boral over the

period of extended operation.

In a supplemental response, dated November 17, 2005, the applicant stated that it will remove

the unclad coupon in the final (seventh) coupon set from the pool and visually examine it before

the period of extended operation to satisfy the requirement for a one-time inspection. The

applicant will return the unclad coupon to the spent fuel pool immediately following the visual

examination, and the entire set of coupons will remain in the spent fuel pool until they are

removed for surveillance testing sometime during the period of extended operation.

The applicant's operating experience indicates that it is unlikely that the final boral coupon set

will exhibit degradation if tested before the period of extended operation. The applicant

maintains that the final coupon set will provide greater assurance of boral performance if it is

tested during the period of extended operation. The applicant's visual inspection of the unclad

coupon will satisfy the requirement for a one-time inspection and will provide additional

assurance that the boral has not experienced significant degradation since the examination of

the last coupon set.

The staff found the applicant's response to RAI 3.5.2.1.15-3 acceptable based on the conduct

of a one-time inspection of the remaining coupon to determine if there is any unacceptable

degradation of the neutron absorption capability. Therefore, the staff's concern described in

RAI 3.5.2.1.15-3 is resolved.

In RAI 3.5.2.1.5-3, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-15 and

3.5.2-17 refer to the Structures Monitoring Program as the AMP to manage aging effects for

rigid board (thermal insulating board) in an air/gas environment; therefore, the staff requested

that the applicant justify this conclusion.

In its response, by letter, dated September 16, 2005, the applicant stated the following:

LRA Tables 3.5.2-15 and 3.5.2-17 refer to the Structures Monitoring Program as

the AMP for managing the aging effects for gypsum board walls (rigid board)

with fire barrier and HELB barrier intended functions in an air/gas environment.

The scope of the Structures Monitoring Program described in the Structures

Monitoring Program PBD/AMP-027, Table 7.1 includes rigid board with the aging

effect loss of material in an air/gas environment. This is consistent with

LRA Tables 3.5.2-15 and 3.5.2-17.

Since gypsum board walls perform fire barrier and HELB intended functions,

both the Structures Monitoring Program and the Fire Protection Program will

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manage the aging effects, ensuring the intended functions will be maintained

consistent with the CLB for the period of extended operation.

The staff's review found the applicant's response to RAI 3.5.2.1.5-3 acceptable because the

scope of the Fire Protection Program in PBD/AMP-01 3, Table 7.1, includes gypsum board walls

(rigid board) with fire barrier and HELB barrier intended functions in an air/gas environment.

The staff's review of the applicant's Fire Protection Program, including PBD/AMP-01 3,

Table 7.1, found that components of the FP system will be managed for aging effects during

the period of extended. operation. The applicant also stated that both the Structures Monitoring

Program and the Fire Protection Program will manage the aging effect of gypsum board walls;

therefore, the staff's concern described in RAI 3.5.2.1.5-3 is resolved.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant adequately identified applicable

aging effects and the AMPs credited with managing them for the reactor building component

group not addressed by the GALL Report. The staff found the applicant's AMR results for the

reactor building component group acceptable.

3.5.2.3.16 Structures and Component Supports-Structures Affecting Safety-Summary of

Aging Management Evaluation-Table 3.5.2-16

The staff reviewed LRA Table 3.5.2-16, which summarizes the results of AMR evaluations for

the structures affecting safety component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

3.5.2.3.17 Structures and Component Supports-Turbine Building-Summary of Aging

Management Evaluation-Table 3.5.2-17

The staff reviewed LRA Table 3.5.2-17, which summarizes the results of AMR evaluations for

the turbine building component groups.

The staff also reviewed LRA Section 3.5.2.1.17, which identifies the materials, environments,

AERMs, and AMPs for the turbine building component group. The staff conducted its review,

described below, in accordance with SRP-LR Section 3.5 and the GALL Report.

As discussed in the resolution to RAI 3.5.2.1.5-3, the staff found that the Structures Monitoring

Program will properly manage the aging effects for gypsum board walls (rigid board) in an

air/gas environment.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant adequately identified applicable

aging effects and the AMPs credited with managing them for the turbine building component

group not addressed by the GALL Report. The staff found the applicant's AMR results for the

turbine building component group acceptable.

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3.5.2.3.18 Structures and Component Supports-Underground Duct Bank-Summary of Aging

Management Evaluation-Table 3.5.2-18

The staff reviewed LRA Table 3.5.2-18, which summarizes the results of AMR evaluations for

the underground duct bank component groups.

All line items in this table are consistent with the GALL Report or are included in the discussion

in Section 3.5.2.3 above.

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERMs, and AMP combinations that are not

evaluated in the GALL Report. The staff found that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.5.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the containments, structures, and component supports system components

that are within the scope of license renewal and subject to an AMR will be adequately managed

so that the intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited with managing aging of the containments,

structures, and component supports, as required by 10 CFR 54.21 (d).

3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff's review of the applicant's AMR results for the

electrical and instrumentation and controls (I&C) components associated with ther following:

* electrical penetrations commodity group

* •fuse holders commodity group

* non-environmental qualification (EQ) cables and connections commodity group

• offsite power/SBO recovery path commodity group

3.6.1 Summary of Technical Information in the Application

In LRA Section 3.6, the applicant provided AMR results for the electrical and I&C components.

In LRA Table 3.6.1, the applicant provided a summary comparison of its AMRs with the AMRs

evaluated in the GALL Report for the electrical and I&C components.

The applicant's AMRs incorporated applicable operating experience in the determination of

AERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site

personnel to identify AERMs. The applicant's review of industry operating experience included a

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review of the GALL Report and operating experience issues identified since the issuance of the

GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine if the applicant provided sufficient information

to demonstrate that the effects of aging for the electrical and I&C components that are within

the scope of license renewal and subject to an AMR will be adequately managed so that the

intended functions will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim that

certain identified AMRs are consistent with the GALL Report. The staff did not repeat its review

of the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA is applicable and that the applicant identified the appropriate GALL

Report AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP

audit and review report details the staff's audit evaluation, summarized in SER Section 3.6.2.1.

The staff also performed an onsite audit of those selected AMRs that are consistent with the

GALL Report and for which further evaluation is recommended. The staff confirmed that the

applicant's further evaluations are consistent with the acceptance criteria in SRP-LR

Section 3.6.2.2. The MNGP audit and review report documents the staff's audit evaluations,

summarized in SER Section 3.6.2.2.

The staff performed an onsite audit and conducted a technical review of the remaining AMRs

that are not consistent with, or not addressed in, the GALL Report. The audit and technical

review included evaluating whether the applicant identified all plausible aging effects and

whether the aging effects listed are appropriate for the combination of materials and

environments specified. The MNGP audit and review report documents the staff's audit

evaluations. SER Section 3.6.2.3 summarizes the staff's audit evaluations and documents the

staff's technical review.

Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensure

that they adequately describe the programs credited with managing or monitoring aging for the

electrical and I&C components.

Table 3.6-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,

and AMPs listed in LRA Section 3.6 that are addressed in the GALL Report.

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Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls Components

in the GALL Report _

,:Compopept Grop Aging Effectl Amp in.GALL AM &R~ Staff Evaluatio

Electrical Degradation due to Environmental TLAA This TLAA is

equipment subject various aging qualification of evaluated in Section

to 10 CFR 50.49 mechanisms electric components 4.7, Environmental

environmental Qualification of

qualification (EQ) Electrical

requirements Equipment (EQ)

(Item Number

3.6.1-01)

Electrical cables Embrittlement, Aging management Electrical Cables & Consistent with

and connections not cracking, melting, program for Connections Not GALL Report, which

subject to discoloration, electrical cables Subject to recommends no

10 CFR 50.49 EQ swelling, or loss of and connections not 10 CFR 50.49 further evaluation

requirements dielectric strength subject to Environmental

(Item Number leading to reduced 10 CFR 50.49 EQ Qualification

3.6.1-02) insulation requirements Requirements

resistance (IR); Program (B2.1.15)

electrical failure

caused by thermal/

thermoxidative

degradation of

organics; radiolysis

and photolysis

[ultraviolet (UV)

sensitive materials

only] of organics;

radiation-induced

oxidation; moisture

intrusion

Electrical cables Embrittlement, Aging management Electrical Cables Consistent with

used in cracking, melting, program for Not Subject to GALL Report, which

instrumentation discoloration, electrical cables 10 CFR 50.49 recommends no

circuits not subject swelling, or loss of used in Environmental further evaluation

to 10 CFR 50.49 dielectric strength instrumentation Qualification

EQ requirements leading to reduced circuits not subject Requirements Used

that are sensitive to IR; electrical failure to 10 CFR 50.49 in Instrumentation

reduction in caused by thermal/ EQ requirements Circuits Program

conductor insulation thermoxidative (B2.1.16)

resistance (IR) degradation of

(Item Number organics;

3.6.1-03) radiation-induced

oxidation; moisture

intrusion

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Component Group AigEffect/ AMP In GALL, AMP In LRA Staff Evaluation

Mechanism Re~portA~

Inaccessible Formation of water Aging management Inaccessible Consistent with

medium-voltage trees, localized program for Medium Voltage GALL Report, which

(2 kV to 15 kV) damage leading to inaccessible (2kV to 34.5kV) recommends no

,cables (e.g., electrical failure medium-voltage Cables Not Subject further evaluation

installed in conduit (breakdown of cables not subject to 10 CFR 50.49

or direct buried) not insulation), water to 10 CFR 50.49 EQ Requirements

subject to tress caused by EQ requirements Program (B2.1.21)

10 CFR 50.49 EQ moisture intrusion

requirements

(Item Number

3.6.1-04)

Electrical Corrosion of Boric acid corrosion Not applicable,

connectors not connector contact PWR only

subject to surfaces caused by

10 CFR 50.49 EQ intrusion of borated

requirements that water

are exposed to

borated water

leakage

(Item Number

3.6.1-05)

The staff's review of the MNGP component groups followed one of several approaches. One

approach, documented in SER Section 3.6.2.1, involves the staff's review of the AMR results

for electrical and I&C components that the applicant indicated are consistent with the GALL

Report and do not require further evaluation. Another approach, documented in SER

Section 3.6.2.2, involves the staff's review of the AMR results for electrical and I&C components

that the applicant indicated are consistent with the GALL Report and for which further

evaluation is recommended. A third approach, documented in SER Section 3.6.2.3, involves the

staff's review of the AMR results for electrical and I&C components that the applicant indicated

are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents

the staff's review of AMPs that are credited to manage or monitor aging effects of the electrical

and I&C components.

3.6.2.1 AMR Results That Are Consistent with the GALL Report

Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicant

identified the materials, environments, and AERMs. The applicant identified the following

programs that manage the aging effects related to the electrical and I&C components:

* Bus Duct Inspection Program (B2.1.6)

* Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Program (B2.1 .15)

Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program (B2.1.16)

Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ

Requirements Program (B2.1.21 )

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Staff Evaluation. In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant summarized the AMRs

for the electrical and I&C components and identified which AMRs it considered to be consistent

with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with the GALL Report, and for which the GALL Report does not recommend further

evaluation, the staff performed an audit and review to determine whether the GALL Report

evaluation bounds the plant-specific components contained in these GALL Report component

groups.

The applicant provided a note for each AMR line item. The notes describe how the information

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with

Notes A through E, which indicate that the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the AMP

identified in the GALL Report. The staff audited these line items to verify consistency with the

GALL Report and the validity of the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

AMP identified in the GALL Report. The staff audited these line items to verify consistency with

the GALL Report. The staff verified that it had reviewed and accepted the identified exceptions

to the GALL Report AMPs. The staff also determined whether the AMP identified by the

applicant is consistent with the AMP identified in the GALL Report and whether the AMR is valid

for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP is consistent

with the AMP identified by the GALL Report. This note indicates that the applicant could not find

a listing of some system components in the GALL Report; however, the applicant identified a

different component in the GALL Report that has the same material, environment, aging effect,

and AMP as the component under review. The staff audited these line items to verify

consistency with the GALL Report. The staff also determined whether the AMR line item of the

different component applies to the component under review and whether the AMR is valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different, is consistent with

the GALL Report for material, environment, and aging effect. In addition, the AMP takes some

exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component applies to the component under review. The staff verified whether it had reviewed

and accepted the identified exceptions to the GALL Report AMPs. The staff also determined

whether the AMP identified by the applicant is consistent with the AMP identified in the GALL

Report and whether the AMR is valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but the applicant credited a different AMP. The staff audited

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these line items to verify consistency with the GALL Report. The staff also determined whether

the identified AMP will manage the aging effect consistent with the AMP identified by the GALL

Report and whether the AMR is valid for the site-specific conditions.

The staff conducted an audit and review of the information provided in the LRA, as documented

in the MNGP audit and review report; The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA is applicable and that the applicant identified-the appropriate GALL Report AMRs.

The staff reviewed the LRA to confirm that the applicant (1) provided a brief description of the

system, components, materials, and environment; (2) stated that the GALL Report reviewed the

applicable aging effects, and (3) identified those aging effects for the electrical and I&C

components that are subject to an AMR. On the basis of its audit and review the staff

determined that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, the

applicant's references to the GALL Report are acceptable and no further staff review is

required.

Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. The

staff also reviewed information pertaining to the applicant's consideration of recent operating

experience and proposals for managing associated aging effects. The staff's review concluded

that the AMR results, which the applicant claimed to be consistent with the GALL Report, are

consistent with the AMRs in the GALL Report. Therefore, the staff concluded that the applicant

has demonstrated that the effects of aging for these components will be adequately managed

so that their intended functions will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.6.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further Evaluation

Is Recommended

Summary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicant

provided further evaluation of aging management as recommended by the GALL Report for the

electrical and I&C components. The applicant provided information concerning how it will

manage the aging effects in electrical equipment subject to EQ.

Staff Evaluation. For component groups evaluated in the GALL Report for which the applicant

has claimed consistency with the GALL Report, and for which the GALL Report recommends

further evaluation, the staff audited and reviewed the applicant's evaluation to determine

whether it adequately addresses the issues that were further evaluated. In addition, the staff

reviewed the applicant's further evaluations against the criteria contained in SRP-LR

Section 3.6.2.2. The staff's audit and review report details the staff's audit. The following

sections discuss the staff's evaluation of the aging effects.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

In LRA Section 3.6.2.2.1, the applicant stated that EQ is a TLAA, as defined in 10 CFR 54.3.

Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.7

documents the staff's review of the applicant's evaluation of this TLAA.

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Conclusion. On the basis of its review, for component groups evaluated in the GALL Report for

which the applicant has claimed consistency with the GALL Report, and for which the GALL

Report recommends further evaluation, the staff determined that the applicant adequately

addressed the issues that were further evaluated. The staff found that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

Summary of Technical Information in the Application. In LRA Tables 3.6.2-1 through 3.6.2-4,.

the staff reviewed additional details of the results of the AMRs for material, environment,

AERM, and AMP combinations that are not consistent with the GALL Report, or that are not

addressed in the GALL Report.

In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant indicated, via Notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report and provided information concerning how it will manage the aging

effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the

AMR line item component. Note G indicates that the GALL Report does not evaluate the

environment for the AMR line item component and material. Note H indicates that the GALL

Report does not evaluate the aging effect for the AMR line item component, material, and

environment combination. Note I indicates that the aging effect identified in the GALL Report for

the line item component, material, and environment combination is not applicable. Note J

indicates that the GALL Report does not evaluate either the component or the material and

environment combination for the line item.

Staff Evaluation. For component type, material, and environment combinations that are not

evaluated in the GALL Report, the staff reviewed the applicant's evaluation to determine

whether the applicant demonstrated that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB during the period of

extended operation. The following sections discuss the staff's evaluation.

In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant identified AMR line items for which the

aging review process identified no aging effects. The applicant stated that it identified no aging

effects for components fabricated from the materials and exposed to the environments

described below.

3.6.2.3.1 Electrical Components-Electrical Penetrations Commodity Group-Summary of

Aging Management Evaluation-Table 3.6.2-1

The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the

electrical penetrations commodity group component groups.

In LRA Table 3.6.2-1, the applicant stated that no aging effects occur when components

fabricated from epoxy, fiberglass, and hypalon paint material are exposed to heat, radiation,

and moisture environment. The applicant further stated that GE supplied the non-EQ

penetrations and that they are manufactured and tested to the same specifications as the GEsupplied EQ penetrations.

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The materials subject to aging that are installed in the penetrations are epoxy, fiberglass, and

hypalon paint. The applicant evaluated these materials as part of the EQ calculation associated

with GE penetrations. Fiberglass is a spun glass inert material not susceptible to significant

thermal degradation. Of the two organic materials, epoxy and hypalon paint, epoxy is

considered more susceptible to radiation effects. In accordance with the applicant's EQ

calculation, the lifetime of these two materials exceeds the required 60-year service life.

Because the evaluated temperature and radiation levels of the organic materials exceed those

to which the materials are actually exposed (service conditions for the drywell are 135 OF and

1.58x1 07 Rads), the materials are shown to have an expected lifetime in excess of 60 years.

When a component's expected lifetime exceeds its intended service life, there are no aging

effects which require management because the component remains capable of performing its

intended function; therefore, no aging effects are considered applicable to components

fabricated from epoxy, fiberglass, and hypalon paint material exposed to heat, radiation, and

moisture environments.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that heat, radiation, or moisture on epoxy, fiberglass,

and hypalon paint will not result in aging that will be of concern during the period of extended

operation. Therefore, the staff concluded that epoxy, fiberglass, and hypalon paint components

exposed to a heat, radiation, and moisture environment have no applicable AERMs and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended functions will be maintained during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.6.2.3.2 Electrical Components-Fuse Holders Commodity Group-Summary of Aging

Management Evaluation-Table 3.6.2-2

The staff reviewed LRA Table 3.6.2-2, which summarizes the results of AMR evaluations for the

fuse holders commodity group component groups.

In LRA Table 3.6.2-2, the applicant identified AMR line items for which the aging review process

identified no aging effects. Specifically, the applicant stated that it identified no aging effects for

(1) components fabricated from various insulating materials (e.g., Phenolic or Melamine)

exposed to heat and radiation environments and (2) components fabricated from copper, brass,

and steel material exposed to thermal cycling, vibration, electrical transients, mechanical

stresses, corrosion, chemical contamination, and oxidation environments.

Components Fabricated from Various Insulating Materials such as Phenolic or Melamine

Exposed to Heat or Radiation. The average temperature where fuse holders are located is

85 0F and the radiation exposure is 1.1 xl 05 Rads. These temperature and radiation levels are

less than the insulating material 60-year service-limiting temperature of 205 OF and radiation

dose of 5x1 07 Rads. Operating experience demonstrates no aging effect when insulating

materials such as Phenolic or Melamine are exposed for 60 years at a service-limiting

temperature of 205 OF and radiation dose of 5x1 07 Rads. No aging effects are considered

applicable for components fabricated from various insulating materials (e.g., Phenolic or

Melamine) exposed to heat and radiation environments.

On the basis of its review of current industry research and operating experience, the staff found

that heat and radiation on various insulating materials like Phenolic or Melamine will not result

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in aging that will be of concern during the period of extended operation. The applicant's fuse

holders are not exposed to temperatures at which operating experience demonstrates aging

effects of embrittlement, cracking, melting, or discoloration; therefore, the staff concluded that

insulating materials such as Phenolic or Melamine exposed to heat and radiation environments

have no applicable AERMs.

Components Fabricated from Copper, Brass, and/or Steel Exposed to Thermal Cycling.

Vibration, Electrical Transients, Mechanical Stress. Corrosion, Chemical Contamination, or

Oxidation.

Effect of thermal cycling-Thermal cycling is an aging effect associated with power circuit

operations. Operating low-current fuse holders below the design-current rating will eliminate the

aging effect of thermal cycling. Typically, control fuse holders are rated far in excess of the fuse

rating. The fuse will limit the current to values well below the rating of the fuse holder. The low

current values experienced by control circuits typically do not create thermal .cycling effects. No

aging effects are considered to apply to components fabricated from copper, brass, and/or steel

material exposed to a thermal cycling environment.

On the basis of its review of current industry research and operating experience, the staff found

that thermal cycling on copper, brass, and/or steel will not result in aging that will be of concern

during the period of extended operation. Fuse holders at MNGP are low current, and operating

experience shows that low currents do not create thermal cycling effects; therefore, the staff

concluded that copper, brass, and/or steel components exposed to a thermal cycling

environment have no applicable AERMs.

Effect of vibration-Vibration is a result of rapid mechanical movement about a specific point at

an elevated frequency. Fuse holders at MNGP are mounted on rigid walls and are not subject

to vibration. No aging effects are considered applicable to components fabricated from copper,

brass, and/or steel material exposed to a vibration environment.

On the basis of its review of current industry research and operating experience, the staff found

that vibration on the fuse holders metallic clamp fabricated from copper, brass, and/or steel will

not result in aging that will be of concern during the period of extended operation. Fuse holders

at MNGP are mounted on rigid walls and not subject to vibration; therefore, the staff concluded

that copper, brass, and/or steel components exposed to a vibration environment have no

AERMs.

Effect of electrical transients-Electrical transients of power applications (i.e., large-surge current transformers and power cables) create aging effects. These transients affect the

insulation of the device and if sufficiently frequent may weaken the insulation over time. Fuse

holders subject to an AMR at MNGP provide electrical power to fire detection components.

These components are low-voltage and low-current applications. No aging effects are

considered applicable to components fabricated from copper, brass, and/or steel material

exposed to electrical transients.

On the basis of its review of current industry research and operating experience, the staff found

that electrical transients on copper, brass, and/or steel will not result in aging that will be of

concern during the period of extended operation. Electrical transients in the low-current

application of fuse holders at MNGP are not sufficient to cause aging effects; therefore, the

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staff concluded that copper, brass, and/or steel components exposed to an electrical transient

environment have no applicable AERMs.

Effect of mechanical stress-Frequent manipulation is a result of removing and reinstalling the

fuse from the fuse holder in a frequent time period. Aging effects resulting from frequent

manipulation have a correlation to fatigue. Fuse holders at MNGP have no fuses removed and

reinstalled on a frequent basis. No aging effects are considered applicable to components

fabricated from copper, brass, and/or steel material exposed to a mechanically stressful

environment.

On the basis of its review of current industry research ,and operating experience, the staff found

that mechanical stress on copper, brass, and/or steel will not result in aging that will be of

concern during the period of extended operation. Fuses at MNGP are not frequently removed

and installed; therefore, the staff concluded that copper, brass, and/or steel components

exposed to a mechanically stressful environment have no applicable AERMs.

Effect of corrosion, chemical contamination, and oxidation-The aging stressors chemical

contamination, corrosion, and oxidation are related to environments in which chemical water

vapors create adverse localized environments. The indoor air environment is a controlled, mild

environment with no significant concentrations of chemical vapors and moisture to create an

adverse environment. Fuse holders at MNGP operate in an indoor air environment. No aging

effects are considered applicable to components fabricated from copper, brass, and/or steel

material exposed to chemical contamination, corrosion, and oxidation environments.

On the basis of its review of current industry research and operating experience, the staff found

that chemical contamination, corrosion, and oxidation on copper, brass, and/or steel will not

result in aging that will be of concern during the period of extended operation. Fuse holders at

MNGP are protected from moisture and chemical contamination. Therefore, the staff concluded

that copper, brass, and/or steel components exposed to chemical contamination, corrosion, and

oxidation environments have no applicable AERMs.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant demonstrated that the effects of

aging for fuse holders will be adequately managed so that the intended functions will be

maintained during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.6.2.3.3 Electrical Components-Non-EQ Cables and Connections Commodity

Group-Summary of Aging Management Evaluation-Table 3.6.2-3

The staff reviewed LRA Table 3.6.2-3, which summarizes the results of AMR evaluations for the

non-EQ cables and connections commodity group component groups.

In LRA Table 3.6.2-3, the applicant stated that it identified no aging effects for components

fabricated from various metal materials exposed to thermal cycling, ohmic heating, electrical

transients, vibration, chemical contamination, corrosion, and oxidation environments. As

supported by SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power

Plants-Electrical Cable and Terminations," issued September 1996, and the applicant's

operating experience, the likelihood of substantially increased effects or failure rates is

considered low from thermal cycling, ohmic heating, electrical transients, mechanical stress

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(vibration), chemical contamination, corrosion, and oxidation. No aging effects are considered

applicable to components fabricated from various metal materials exposed to thermal cycling,

ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation

environments.

The staff noted that operating experience shows loosening of metallic parts of cable

connections. Review of several licensee event reports revealed loose connections due to

corrosion, vibration, thermal cycling, and other factors. In RAI 3.6-2, dated November 7, 2005,

the staff requested that the applicant provide technical justification for not providing an AMP for

cable connections.

In its response, by letter dated December 7, 2005, the applicant stated that SAND96-0344

categorizes aging mechanisms as either "significant" or "significant and observed." According

to SAND96-0344, the aging mechanism listed is "significant."

Section 4.2 of SAND96-0344 emphasizes that "the applicability of some aging mechanisms to

actual cable systems (cable and connections) may be very limited or the frequency of their

occurrence may be extremely low." After a consideration of all stressors and the reported

incidence of their effects in the industry, SAND96-0344 concluded the following:

...the likelihood of substantially increased effects or failure rate resulting from

aging mechanisms currently categorized only as 'significant' is considered low.

This assessment, which is based on industry-wide observations, provides reasonable

assurance that these aging mechanisms will cause no loss of intended function if left

unmanaged during the period of extended operation. Based on the above, the applicant stated

that industry and plant-specific operating experience does not support the presence of aging

effects from thermal cycling, ohmic heating, electric transients, vibration, chemical

contamination, corrosion, and oxidation on the metallic parts of cable connections.

In a January 12, 2006, teleconference, the staff informed the applicant that its justification for

not having an AMP for cable connections-was inadequate because the operating experience

shows loosening of metallic parts of cable connections. The staff recommended that the

applicant implement an AMP for the metallic parts of cable connections in accordance with

GALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements." The applicant stated that it had implemented a plant-specific

thermography program for equipment that presents a significant risk to core protection, is

necessary to maintain full power production, or has the potential to reduce power. This

equipment, monitored at least semiannually, includes but is not limited to substation equipment,

4-kV breakers, load centers, motor control centers, control centers, control panels, direct

current equipment, motors, or generators. The licensee stated that it will consider expanding

the current thermography program to include cable connectors and switchyard bus connections

as well as transmission conductor connections that are within the scope of license renewal.

In its letter dated February 28, 2006, the applicant committed to implementing a new program

consistent with GALL AMP XI.E6, documented as commitment 55 in Table A.5. The staff found

this response acceptable, as it will provide assurance that the effects of aging on electrical

connections will be adequately managed. Therefore, the staff's concem described in RAI 3.6-2

is resolved.

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On the basis of the staff's review of the applicant's programs, the aging effects, and the

plant-specific and industry operating experience, the staff determined that the applicant

demonstrated that the effects of aging for non-EQ cables and connections will be adequately

managed so that the intended functions will be maintained during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.6.2.3.4 Electrical Components-Offsite Power/Station Blackout Recovery Path Commodity

Group-Summary of Aging Management Evaluation-Table 3.6.2-4

The staff reviewed LRA Table 3.6.2-4, which summarizes the results of AMR evaluations for the

offsite power/SBO recovery path commodity group component groups.

The applicant proposed to manage embrittlement, cracking, discoloration, oxidation, and

loosening of bolted connections for nonsegregated phase bus made from various metals and

organic polymers, porcelain, fiberglass, and silicon rubber in an indoor and outdoor air

environment using the Bus Duct Inspection Program. SER Section 3.0.3.3.1 documents the

staff evaluation of the Bus Duct Inspection Program.

Nonseqreqated Phase Bus

A nonsegregated phase bus connects two or more elements of an electrical power circuit and is

normally used to connect active electrical components such as generators, breakers, and

transformers. The intended function of a nonsegregated phase bus is to provide electrical

connections to specified sections of an electrical circuit to deliver voltage, current, or signals.

The applicant has identified the Bus Duct Inspection Program to manage aging effects in the

nonsegregated phase bus. SER Section 3.0.3.3.1 documents the staff evaluation of the Bus

Duct Inspection Program.

High-Voltage Insulators

In LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltage

insulators fabricated from porcelain, cement, and metal material exposed to an outdoor air

environment.

Effect of surface contamination on porcelain-The applicant stated that MNGP is located in a

rural area not close to saltwater environments. The nearest industrial facility discharging any

significant amount of airborne particulates is about 5 miles northwest of the plant. Since the

plant began operation in 1971, plant personnel have not conducted regularly scheduled

maintenance to remove surface contamination from the switchyard or transmission line

insulators. Additionally, operating experience indicates no age-related degradation of the highvoltage insulators from surface contamination. No aging effects are considered applicable to

components fabricated from porcelain material exposed to an outdoor air environment.

On the basis of its review of current industry research and operating experience, the staff found

that porcelain in an outdoor air environment will not result in aging that will be of concern during

the period of extended operation. The applicant's high-voltage insulators are not located in an

area subject to airborne contaminants. Therefore, the staff concluded that porcelain

components exposed to an outdoor air environment have no AERMs.

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Effect of cracking on porcelain--Cracks have also been known to occur in insulators used in

strain applications when the cement that binds the parts together expands enough to crack the

porcelain. This phenomenon, known as cement growth, is caused by improper manufacturing

process or materials that increase the cement's susceptibility to moisture penetration. Porcelain

cracking caused by cement growth has occurred only in isolated bad batches of insulators used

in strain applications. The dates of manufacture and brands of these problem insulators are

known and they have been removed from service. Cracking is not considered applicable to

components fabricated from porcelain and cement material exposed to an outdoor air

environment.

On the basis of its review of current industry research and operating experience, the staff found

that porcelain and cement in an outdoor air environment will not result in aging that will be of

concern during the period of extended operation. Operating experience using properly

manufactured cement shows no aging effects. Therefore, the staff concluded that porcelain and

cement components exposed to an outdoor air environment have no applicable AERMs.

Effect of loss of material due to wear-Loss of material due to mechanical wear is an aging

effect for strain and suspension insulators if they are subject to significant movement. Although

this mechanism is possible, experience shows that transmission conductors do not normally

swing, and when they do, because of strong winds, they dampen quickly once the wind

subsides. Routine inspections of high-voltage insulators have not identified wear, and loss of

material due to wear is not considered applicable for components fabricated from metal

material exposed to an outdoor air environment.

On the basis of its review of current industry research and operating experience, the staff found

that metal in an outdoor air environment will not result in loss of material due to wear that will be

of concern during the period of extended operation. Transmission conductors and high-voltage

insulators are not subject to significant movement; therefore, the staff concluded that metal

components exposed to an outdoor air environment have no applicable AERMs.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant had demonstrated that the effects

of aging for high-voltage insulators will be adequately managed so that the intended functions

will be maintained during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

High-Voltage Switchyard Bus

In LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltage

switchyard buses fabricated from aluminum and steel material exposed to an outdoor air

environment.

Effect of vibration on switchyard bus-Switchyard buses connected to flexible conductors that

normally do not vibrate are supported by insulators and ultimately by static, structural

components like concrete footings and structural steel. With no connections to moving or

vibrating equipment, vibration is not an applicable stressor. No aging effects are considered to

be applicable to components fabricated from aluminum and steel exposed to outdoor air and

vibration environments.

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On the basis of its review of current industry research and operating experience, the staff found

that outdoor air and vibration of aluminum and steel will not result in aging that will be of

concern during the period of extended operation. Switchyard bus is not subject to vibration.

Therefore, the staff concluded that for aluminum and steel components exposed to outdoor air

due to vibration have no applicable AERMs.

Effect of oxidation on switchyard bus and connections-All switchyard bus connections within

the offsite power/SBO recovery path boundaries are bolted, welded, or, for jumper cables,

crimped aluminum connections. Aluminum bus, solid and flexible connectors, and ground

straps are highly conductive but do not make good contact surfaces as aluminum exposed to

air forms nonconductive aluminum oxide on the surface. To prevent formation of aluminum

oxide, the connections are cleaned with a wire brush (to remove existing aluminum oxide) and

covered with No-Ox grease to prevent air from contacting the aluminum surface. After the

connection is completed, additional compound is applied and forced into every irregularity and

opening to seal the joint completely against moisture and corrosion. The grease prevents

oxidation of the aluminum surface, thereby maintaining good conductivity at the bus

connections. The grease is a consumable that is replaced during bus routine maintenance.

Routine maintenance thermography inspections monitor substation connections, which include

the SBO recovery path equipment connections, on a semiannual basis. These inspections

identify connections where conditions exist that have resulted in increased resistance and a

subsequent rise in temperature. The applicant schedules the inspections in the work control

process and performs them on a repetitive basis as part of routine maintenance. The

inspections have been effective in identifying conditions before any loss of the component

intended function. Oxidation is not considered applicable to components fabricated from

aluminum and steel exposed to outdoor air.

On the basis of its review of current industry research and operating experience, the staff found

that aluminum and steel in an outdoor air environment will not result in aging that will be of

concern during the period of extended operation. The application of grease and its periodic

replacement eliminates the effects from air on switchyard bus connections. In addition, the

applicant periodically inspects connections using thermography. Therefore, the staff concluded

that aluminum and steel components exposed to an outside air environment have no applicable

AERMs.

Hi gh-Volta-ge Transmission Conductors

In LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltage

transmission conductors fabricated from aluminum and steel material exposed to an outdoor air

environment.

Effect of loss of conductor strength due to corrosion-For transmission conductors, degradation

begins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on

air quality, which includes suspended particles chemistry, sulfur dioxide concentration in air,

precipitation, fog chemistry, and meteorological conditions. Corrosion of transmission

conductors is a very slow process that is even slower in rural areas with generally fewer

suspended particles and sulfur dioxide concentrations in the air than urban areas. MNGP is

located in a rural area with. low airborne particle and sulfur dioxide concentrations. No aging

effects are considered applicable to components fabricated from aluminum and steel exposed

to outdoor air.

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On the basis of its review of current industry research and operating experience, the staff found

that aluminum and steel in an outdoor air environment will not result in aging that will be of

concern during the period of extended operation. Corrosion is a slow process and is slower in

rural areas, where MNGP is located. Therefore, the staff concluded that loss of conductor

strength due to corrosion is not an applicable AERM for aluminum and steel components

exposed to an outside air environment.

Effect of vibration-Wind loading can cause transmission conductor vibration. Wind loading is

considered in the initial design and field installation of transmission conductors and high-voltage

insulators throughout the transmission and distribution network. Loss of material due to wear

and fatigue that could be caused by transmission conductor vibration or sway is not considered

an applicable aging effect because experience throughout the industry shows no significant

failures of this type. No aging effects are considered applicable to components fabricated from

aluminum and steel material exposed to an outdoor air environment.

On the basis of its review of current industry research and operating experience, the staff found

that aluminum and steel in an outdoor air environment will not result in aging that will be of

concern during the period of extended operation. There is no operating experience for failure of

transmission conductors due to vibration. Therefore, the-staff concluded that vibration will not

result in any applicable AERMs for aluminum and steel components exposed to an outside air

environment.

Electrical Cables and Connections Not Subiect to 10 CFR 50.49 EQ Requirements

SER Section 3.6.2.3.3 documents the staff evaluation for this area.

The staff's review of the applicant's programs, the aging effects, and the plant-specific and

industry operating experience determined that the applicant had demonstrated that the effects

of aging will be adequately managed so that the intended functions will be maintained during

the period of extended operation, as required by 10 CFR 54.21 (a)(3).

Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluated

AMR results involving material, environment, AERMs, and AMP combinations that are not

evaluated in the GALL Report. The staff found that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended functions will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.6.3 Conclusion

The staff concluded that the applicant provided sufficient information to demonstrate that the

effects of aging for the electrical and I&C components that are within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended functions will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

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The staff also reviewed the applicable USAR supplement program summaries and concluded

that they adequately describe the AMPs credited for managing aging of the electrical and I&C

components, as required by 10 CFR 54.21 (d).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3 and Appendix B to the LRA. On the basis

of its review of the AMR results and AMPs, the staff concluded that the applicant has

demonstrated that the aging effects will be adequately managed so that the intended functions

will be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the applicable USAR supplement program

summaries and concluded that the USAR supplement adequately describes the AMPs credited

for managing aging, as required by 10 CFR 54.21 (d).

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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section discusses the identification of time-limited aging analyses (TLAAs). Nuclear

Management Company, LLC (NMC or the applicant), discusses the TLAAs in Sections 4.2

through 4.10 of its license renewal application (LRA). Sections 4.2 through 4.11 of this safety

evaluation report (SER) document the review of the TLAAs conducted by the staff of the U.S.

Nuclear Regulatory Commission (NRC or the staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined

by the current operating term. Pursuant to Title 10, Section 54.21 (c)(1), of the Code of Federal

Regulations (10 CFR 54.21 (c)(1)), the applicant for license renewal must provide a list of

TLAAs, as defined in 10 CFR 54.3(a), and demonstrate that (i) the analyses will 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 functions will be adequately

managed for the period of extended operation. In accordance with 10 CFR 54.3(a), TLAAs are

those licensee calculations and analyses that meet the following six criteria:

(1) involve systems, structures, and components (SSCs) within the scope of license

renewal, as delineated in 10 CFR 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term, for example,

40 years

(4) were considered to be relevant by the licensee in making a safety determination

(5) involve conclusions or provide the basis for conclusions related to the capability of the

SSC to perform its intended functions, as delineated in 10 CFR 54.4(b)

(6) are contained or incorporated by reference in the current licensing basis (CLB)

In addition, pursuant to 10 CFR 54.21 (c)(2), an applicant must provide a list of plant-specific

exemptions granted under 10 CFR 50.12, "Specific Exemptions," that are based on TLAAs. For

any such exemptions, the applicant must provide an evaluation that justifies the continuation of

the exemptions for the period of extended operation.

4.1.1 Summary of Technical Information in the Application

To identify the TLAAs, the applicant evaluated calculations for the Monticello Nuclear

Generating Plant (MNGP) against the six criteria specified in 10 CFR 54.3, "Definitions." The

applicant indicated that it had identified the calculations that met the six criteria by searching the

CLB, which includes the Updated Safety Analysis Report (USAR), engineering calculations,

technical reports, engineering work requests, licensing correspondence, and applicable vendor

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reports. In LRA Table 4.1-1, "List of MNGP Time-Limited Aging Analyses (TLAAs)," the

applicant listed the applicable TLAAs in the following categories:

" neutron embrittlement of the reactor vessel and internals

" metal fatigue-RPV, internals and pressure boundary

* neutron embrittlement

• environmental fatigue

* fatigue of primary containment, piping, and components

* environmental qualification

* loss of preload

* plant-specific TLAAs

Pursuant to 10 CFR 54.21 (c)(2), the applicant stated that it did not identify any exemptions

granted under 10 CFR 50.12 that were based on a TLAA, as defined in 10 CFR 54.3.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to MNGP; the applicant also

discussed exemptions based on these TLAAs. The staff reviewed the information to determine

whether the applicant had provided adequate information to meet the requirements of

10 CFR 54.21 (c)(1) and 10 CFR 54.21 (c)(2).

The applicant provided a list of common TLAAs from NUREG-1 800, "Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants," dated July 2001. The

applicant listed those TLAAs that are applicable to MNGP in LRA Table 4.1-1.

As required by 10 CFR 54.21 (c)(2), an applicant must provide a list of all the exemptions

granted under 10 CFR 50.12 that are based on a TLAA and evaluated and justified for

continuation through the period of extended operation. In its LRA, the applicant stated that it

reviewed each active exemption to determine whether the exemption was based on a TLAA.

The applicant did not identify any TLAA-based exemptions. On the basis of the information

provided by the applicant with regard to the process used to identify TLAA-based exemptions,

as well as the results of the applicant's search, the staff concluded that the applicant did not

identify any TLAA-based exemptions that are justified for continuation through the period of

extended operation, in accordance with 10 CFR 54.21 (c)(2).

4.1.3 Conclusion

On the basis of its review, the staff concluded that the applicant provided an acceptable list of

TLAAs, as required by 10 CFR 54.21 (c)(1). The staff also confirmed that no exemptions under

10 CFR 50.12 have been granted on the basis of a TLAA, as required by 10 CFR 54.21 (c)(2).

4.2 Neutron Embrittlement of the Reactor Vessel and Internals

The materials of the reactor pressure vessel (RPV) and internals are subject to embrittlement

resulting from high energy (E > 1 million electron volts (MeV)) neutron exposure. Embrittlement

means the material has lower toughness (i.e., will absorb less strain energy during a crack or

rupture), thus allowing a crack to propagate more easily under thermal and/or pressure loading.

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Toughness (indirectly measured in foot-pounds (ft-lb) of absorbed energy in a Charpy impact

test) is temperature dependent in ferritic materials. An initial nil-ductility reference temperature

(RTNDT), the temperature associated with the transition from ductile to brittle behavior, is

determined for vessel materials through a combination of Charpy and drop weight testing.

Toughness increases with temperature up to a maximum value called the "upper-shelf energy"

(USE). Neutron embrittlement causes an increase in the RTNDT and a decrease in the USE of

RPV steels. The increase or shift in the initial nil ductility reference temperature (ARTNDT) means

higher temperatures are required for the material to continue to act in a ductile manner. To

reduce the potential for brittle fracture during RPV operation by accounting for the changes in

material toughness as a function of neutron radiation exposure (fluence), operating

pressure-temperature (P-T) limit curves are included in plant technical specifications (TSs). The

P-T curves account for the decrease in material toughness associated with a given fluence,

which is used to predict the loss in toughness of the RPV materials. Based on the projected

drop in toughness for a given fluence, the P-T curves are generated to provide a minimum

temperature limit associated with the vessel pressure. The P-T curves are determined by the

RTNDT and ,RTNDT values for the licensed operating period, along with appropriate margins.

4.2.1 RPV Materials USE Reduction Due to Neutron Embrittlement

4.2.1.1 Summary of Technical Information in the Application

In LRA Section 4.2.1, the applicant surhmarized the evaluation of the RPV materials USE

reduction from neutron embrittlement for the period of extended operation. USE is the standard

industry parameter used to indicate the maximum toughness of a material at high temperature.

Appendix G, "Fracture Toughness Requirements," to 10 CFR Part 50, "Domestic Licensing of

Production and Utilization Facilities," requires the predicted end-of-life Charpy impact test USE

for RPV materials to be at least 50 ft-lb (absorbed energy), unless an approved analysis

supports a lower value. Initial unirradiated test data are available for only one plate heat for the

MNGP RPV to demonstrate.a minimum 50 ft-lb USE by standard methods. End-of-life fracture

energy was evaluated by using an equivalent margin analysis (EMA) methodology approved by

the NRC in NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis for

Low Upper Shelf Energy in BWR/2-6 Vessels," February 1994. This analysis confirmed that an

adequate margin of safety against fracture, equivalent to the requirements of Appendix G to

10 CFR Part 50, does exist. The end-of-life USE calculations satisfy the criteria of

10 CFR 54.3(a), as described in SER Section 4.1. As such, these calculations are a TLAA.

Fluence was calculated for the MNGP RPV for the extended 60-year (54 effective full-power

years (EFPY)) licensed operating period using the methodology of NEDC-32983P, "General

Electric (GE) Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation,"

approved by the NRC in a letter dated September 14, 2001, from S.A. Richards, NRC, to J.F.

Klapproth, GE. The NRC found that, in general, this methodology adheres to the guidance in

Regulatory Guide (RG) 1.190, "Calculational and Dosimetry Methods for Determining Pressure

Vessel Neutron Fluence," March 2001, for neutron flux evaluation. For MNGP, 54 EFPY is

equivalent to 3.90x1 08 megawatt hours (MWh) through the end of Cycle 22 at 1775 megawatts

thermal (MWt) plus 4.76x1 0" MWh at 1880 MWt. Peak fluence was calculated at the RPV inner

surface (inner diameter) to evaluate USE. The value of neutron fluence was also calculated for

the 1/4-thickness (1/4T) location into the RPV wall measured radially from the inside

diameter (ID), using Equation 3 from Paragraph 1.1 of RG 1.99, Revision 2, "Radiation

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Embrittlement of Reactor Vessel Materials." This 1/4T depth is recommended in the American

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section Xl,

Appendix G, Subarticle G-2120 as the maximum postulated defect depth for calculating P-T

curves.

4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.2.1, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

Neutron Fluence Evaluation

LRA Section 4.2.1 indicates that the applicant calculated neutron fluence for the MNGP RPV for

the extended 60-year (54 EFPY) licensed operating period based on 3.90x10 8 MWh through

Cycle 22 at 1775 MWt plus 4.76x1 08 MWh at 1880 MWt. This calculation results in a peak

neutron fluence of 5.1 7x1 018 neutrons per square centimeter (n/cm2 ) (E>1.0 MeV), a peak 1/4T

fluence of 3.82x1 01' n/cm2 (E>1.0 MeV) for the RPV, and a neutron fluence at the inside of the

shroud of 3.84x1 021 n/cm2 (E>1.0 MeV) at the end of the extended operating period. Originally,

MNGP was licensed for 1670 MWt and uprated to 1775 MWt in October 1998 during fuel

cycle 19.

The staff's review of LRA Section 4,2.1 identified areas for which it needed additional

information to complete its evaluation of the applicant's neutron fluence evaluation. The

applicant responded to the staff's requests for additional information (RAIs) as discussed

below.

In RAI 4.2-1, dated September 28, 2005, the staff requested that the applicant provide the basis

for the neutron flux estimates in the TLAA.

In its response, by letter dated October 28, 2005, the applicant explained the following:

Flux estimates for the MNGP were performed in accordance with the General

Electric methodology for neutron flux calculation documented in Licensing

Topical Report (LTR) NEDC-32983P-A which has been approved by the NRC. In

general, this methodology adheres to the guidance in Regulatory Guide 1.190 for

neutron flux evaluation. A key input to this calculation was the total integrated

power (MWDth) through the first 22 cycles of operation. In addition, Cycle 22

core data was used as a basis for the calculation. Flux profiles were generated

from this data and, using the maximum flux, the integrated fluence at 54 EFPY

was determined. Fluence estimates at 54 EFPY were conservatively determined

using 1775 MWt for Cycles 1 through 22 (previous to rerate implementation in

the fall of 1998 the rated power was 1670 MWt) and 1880 MWt for the remainder

of the license renewal period of extended operation (54 EFPY). This resulted in

EFPYs of 25.09 and 28.91 respectively.,

In addition to the conservative methodology described above, a bias adjustment

derived from extensive benchmarking of the methodology against measured

data as well as an uncertainty related to the flux calculation was incorporated. To

account for variations in operation (e.g. capacity factor, core design, etc.), a

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multiplier of 1.3 was applied to the reactor pressure vessel to obtain a bounding

fluence...

In addition, in a letter dated June 10, 2005, the applicant confirmed that the 54 EFPY used in

the TLAA bounds plant-specific operation:

NMC has determined that the 54 Effective Full Power Years (EFPY) used for

Time-Limited Aging Analyses bounds the plant-specific EFPY for MNGP based

on a conservative evaluation of plant history and projected capacity factors. This

evaluation results in an expectation of less than 49.5 EFPY at the end of the

license renewal period of extended operation. Assuming a 100 percent capacity

factor over the same operating period also results in a projected less than

54 EFPY for MNGP.

Based on its review, the staff found the applicant's response to RAI 4.2-1 acceptable. Because

the applicant projected neutron fluence at the expiration of the extended period of operation by

an NRC-approved methodology using conservative inputs, the staff considered the neutron

fluence projection adequate for TLAA use for the RPV and shroud. Therefore, the staff's

concern described in RAI 4.2-1 is resolved.

USE Evaluation

Appendix G to 10 CFR Part 50, provides the staff's criteria for maintaining acceptable levels of

Charpy USE for the RPV beltline materials throughout the licensed lives of operating facilities.

The rule requires a minimum 75 ft-lb Charpy USE value for RPV beltline materials in the

unirradiated condition and a 50 ft-lb minimum Charpy USE value throughout the life of the

facility, unless analysis demonstrates that lower USE values will provide acceptable margins of

safety against fracture equivalent to those required by ASME Code Section XI, Appendix G.

The rule also requires methods for calculating Charpy USE values to account for the effects of

neutron irradiation on those values for the materials and to incorporate any relevant RPV

surveillance capsule data reported through a plant's RPV material surveillance program,

created pursuant to Appendix H, "Reactor Vessel Material Surveillance Program

Requirements," to 10 CFR Part 50.

RG 1.99, Revision 2, expands the discussion regarding the calculation of Charpy USE values

and describes two methods for calculating Charpy USE values for RPV beltline materials

depending on whether a given RPV beltline material is included in the plant's RPV Material

Surveillance Program (i.e., 10 CFR Part 50, Appendix H Program). If surveillance data are not

available, Charpy USE is determined in accordance with regulatory position 1.2 in RG 1.99,

Revision 2. If surveillance data are available, Charpy USE should be determined in accordance

with regulatory position 2.2 in RG 1.99, Revision 2. These methods refer to RG 1.99,

Revision 2, Figure 2, which indicates that the percentage drop in Charpy USE depends on the

amount of copper in the material and the neutron fluence. Since the analyses performed in

accordance with Appendix G to 10 CFR Part 50 are based on a flaw with a depth equal to 1/4T,

the neutron fluence used in the Charpy USE analysis is at the 1/4T depth location.

By letter dated April 30, 1993, the Boiling Water Reactor Owners Group (BWROG) submitted

NEDO-32205-A to demonstrate that boiling-water reactor (BWR) RPVs could meet margins of

safety against fracture equivalent to those required by ASME Code Section XA, Appendix G, for

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Charpy USE values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concluded

that the topical report demonstrated that the evaluated materials have margins of safety against

fracture equivalent to ASME Code Section Xl, Appendix G, in accordance with Appendix G to

10 CFR Part 50. In that report, the BWROG derived through statistical analysis the unirradiated

Charpy USE values for materials that originally had no documented unirradiated Charpy USE

values. Using these statistically derived Charpy USEvalues, the BWROG predicted the Charpy

USE values through 40 years of operation, in accordance with RG 1.99, Revision 2. The

BWROG analysis determined that the minimum allowable Charpy USE value in the transverse

direction for base metal and along the weld for weld material was 35 fl-lb.

Electric Power Research Institute (EPRI) Topical Report (TR)-1 13596, "BWR Vessel and

Internals Project (BWRVIP) BWR Reactor Pressure Vessel Inspection and Flaw Evaluation

Guidelines," BWRVIP-74, issued September 1999, documents the GE updated Charpy USE

evaluation. An October 18, 2001, letter from Mr. C.I. Grimes to Mr. C. Terry documented staff

review and approval of EPRI TR-1 13596. The analysis in EPRI TR-1 13596 used the

methodology in RG 1.99, Revision 2, to determine the reduction in the unirradiated Charpy USE

from neutron irradiation. Using this methodology and a correction factor of 65 percent for

conversion of the longitudinal properties to transverse properties, the lowest Charpy USE at

54 EFPY for all BWR/3-6 plates was projected to be 45 ft-lb. The correction factor for specimen

orientation in plates is based on NRC Branch Technical Position MTEB 5-2, "Fracture

Toughness Requirements." EMA acceptance criteria specified in the staff-approved report

BWRVIP-74 using the methodology in RG 1.99, Revision 2, are based on the percent reduction

in the unirradiated Charpy USE values from neutron radiation. The acceptance criteria specified

in the BWRVIP-74 report indicate that the maximum allowable percent reduction in USE value

is 23.5 percent for the plates and 39 percent for the welds.

In RAI 4.2-2, dated September 28, 2005, the staff noted that because the analysis in

BWRVIP-74 is generic, the applicant submitted plant-specific information in LRA Tables 4.2.1-1

and 4.2.1-2 for the limiting MNGP plates and welds to demonstrate that the RPV limiting beltline

materials meet the criteria in the BWRVIP-74 report for the end of the license renewal period.

These tables do not include an evaluation of surveillance plate and weld data. Surveillance data

were submitted to the NRC in a letter dated December 21, 1998, containing Report SIR-97-003,

Revision 2, "Review of the Results of Two Surveillance Capsules, and Recommendations for

the Materials Properties and P-T Curves to be Used for the Monticello Reactor Pressure

Vessel," which indicates that unirradiated Charpy USE data were available for surveillance

plates, but not for surveillance welds. Therefore, Charpy USE evaluations using surveillance

data could be performed for the plates but not the welds. The staff requested that the applicant

determine the impact of the surveillance plate data on the limiting beltline plate USE and

evaluate what impact, if any, these data have on the validity of the plate EMA.

In its response, by letter dated October 28, 2005, the applicant stated the following:

Using the '1 s Capsule' data for plate C2220-2 identified in Table 2-1 of

SIR-97-003, Revision 2 results in a measured decrease of 18.3 percent as

opposed to an 11.5 percent predicted decrease using RG 1.99 Figure 2 as noted

in LRA Table 4.2.1-1 at a fluence of 2.93xl 017 n/cm 2. Correspondingly, at the

54 EFPY 1/4T fluence of 3.82x1 0 Ta with an 18.3 percent measured decrease the

RG1.99 Position 2.2 adjusted decrease is 33.5 percent which exceeds the

margin to safety requirement of 23.5 percent defined in BWRVIP-74-A.

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Based on its review, the staff found the applicant's response to RAI 4.2-2 acceptable;, however,

in this response, the applicant demonstrated that the adjusted percent reduction obtained using

RG 1.99, position 2.2, also results in a 54 EFPY USE greater than 50 ft-lb for plate C2220-2. As

described above, using data from SIR-97-003 results in a position 2.2 Charpy USE reduction of

33.5 percent at the expiration of the extended period of operation. With a transverse

unirradiated USE of 86.5 ft-lb (0.65 x 133 ft-lbs), a 33.5 percent reduction results in a 54 EFPY

Charpy USE of 57.5 ft-lb, which exceeds the 50 ft-lb minimum identified in Appendix G to

10 CFR Part 50. Because the projected USE exceeds the minimum recommended by Appendix

G to 10 CFR Part 50, the staff found the applicant's response acceptable. Therefore, the staff's

concern described in RAI 4.2-2 is resolved.

There are four plates in the MNGP RPV beltline, one with USE greater than 50 ft-lbs, as

discussed in the previous paragraph. The other three plates have no surveillance data;

however, the applicant has used the RG 1.99, Revision 2, methodology to demonstrate that

these three plates will have less than a 23.5 percent reduction in Charpy USE value at the

expiration of the extended period of operation. Therefore, these plates satisfy BWRVIP-74-A

criteria and the margins of safety against fracture equivalent to ASME Code Section XI,

Appendix G, in accordance with Appendix G to 10 CFR Part 50.

In RAI 4.2-3, dated September 28, 2005, the staff noted that the weld materials used in the

MNGP RPV beltline were fabricated using the shielded metal arc weld (SMAW) process. Such

welds are low in copper because the weld electrodes used in this process are not copper

coated; therefore, the staff requested that the applicant calculate the projected Charpy USE for

the limiting weld and plate in the reactor vessel beltline at the 1/4T depth using the neutron

fluence at the end of the period of extended operation.

In its response, by letter dated October 28, 2005, the applicant analyzed the impact of neutron

radiation on the RPV beltline welds. In this analysis, the weld material was projected to have a

Charpy USE at the expiration of the extended period of operation of 68 ft-lb. The applicant

utilized an unirradiated Charpy USE of 84.5 ft-lb, which is the lower 95/95 confidence value for

the SMAW database reported in BWRVIP-74-A. The drop in Charpy USE was calculated by the

RG 1.99, Revision 2, methodology and a 0.10 percent copper. As the RPV beltline welds are

projected to have a Charpy USE at the expiration of the extended period of operation greater

than 50 ft-lb, the RPV beltline weld material meets the criteria of Appendix G to 10 CFR Part 50

criteria at that point.

LRA Table 4.2.2-1 indicates that N2 nozzles-are within the beltline of the RPV. The MNGP N2

nozzles were fabricated as forgings. In a letter dated February 27, 2006, the applicant provided

additional data to demonstrate that, at the end of the period of extended operation, the N2

nozzles will have Charpy USE values greater than 50 ft-lb. The applicant indicated:

Given the hot working normally associated with the fabrication of forgings

(resulting in a more refined grain structure), it is expected that the fracture

toughness properties of the A 508 Class 2 forging materials would be equivalent,

if not better than, the corresponding A 533 Grade B plate materials typically used

to fabricate beltline shell courses. 508 Class 2 forging materials (or equivalent)

have been used throughout the industry for fabrication of reactor vessel

components, including the MNGP recirculation inlet (N2) nozzles, and as such, a

4-7
significant amount of data has been reported on the fracture toughness of these

materials.

The applicant performed a study using the NRC Reactor Vessel Integrity Database, Revision 2

(RVID2), to determine a generic Charpy USE for A 508 Class 2 forgings. The study indicates

that the mean of the USE data for the forgings is 108 ft-lb, with a minimum observed USE of

70 ft-lb and a standard deviation of 24 ft-lb. As defined in NUREG-1 475, "Applying Statistics,"

for 95/95 confidence with a data set consisting of 67 data points, the K value is 1.9996. This

results in a Mean-Ko of 60 ft-lb. Using the RG 1.99 methodology for determining the impact of

neutron radiation on Charpy USE, the applicant determined that at the expiration of the

extended license the Charpy USE will be 52 ft-lb. The staff has confirmed this value.

The applicant compared the generic Charpy USE data from forgings with the generic Charpy

USE from plate material. The mean equivalent transverse Charpy USE was reported as

82.5 ft-lb for plate material in BWRVIP-74-A. The minimum observed Charpy USE was 59 ft-lb

and the Mean-Ko was 64.5 ft-lb for the plate material.

The applicant also evaluated the RVID2 database surveillance capsule results for forging

materials with respect to plate materials. These results indicate that application of the RG 1.99

prediction to forgings adequately predicts the irradiated behavior of these materials.

The applicant concluded the following:

Therefore, it has been demonstrated that the forging materials meet or exceed

the requirements for plate materials, and that the MNGP N2 nozzle case is

bounded by the [equivalent margins analysis] EMA plate requirements described

in BWRVIP-74-A. Further, it has been demonstrated that, in general, irradiated

forging materials behave in a manner consistent with the predictions of RG 1.99.

Based on the results of this evaluation, the USE of the N2 nozzle forgings will be

adequate for the period of extended operation.

The staff concluded that the analysis provided for the MNGP N2 nozzles demonstrates that the

nozzles will have Charpy USE greater than 50 ft-lb and will meet the requirements of Appendix

G to 10 CFR Part 50 at the expiration of the extended license. Therefore, the staff's concern

described in RAI 4.2-3 is resolved.

Table 4.2.1-1 of this SER summarizes the staff's review of the calculated USE values.

Table 4.2.1-1 Reactor Vessel Upper-Shelf Energy Analysis Summary

'R Beltllne Cornponent Acceptance Criterion for USE Component Valuie for

54 EFPY,

C2220-2 Umiting Plate > 50 ft-lb 57.5 ft-lb

Welds-shielded metal arc > 50 ft-lb 68 ft-lb

N2 Nozzle-forging > 50 ft-lb 52 ft-lb

4-8
4.2.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of RPV

materials USE reduction from neutron embrittlement in LRA Section A3.1. On the basis of its

review of the USAR supplement, the staff concluded that the summary description Qf the

applicant's actions to address the RPV materials USE reduction from neutron embrittlement is

adequate.

4.2.1.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the analyses of the RPV materials Charpy USE reduction from

neutron embrittlement have been projected to the end of the period of extended operation. The

staff also concluded that the USAR supplement contains an appropriate summary description of

this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.2.2 Adjusted Reference Temperature for RPV Materials Due to Neutron Embrittlement

4.2.2.1 Summary of Technical Information in the Application

In LRA Section 4.2.2, the applicant summarized the evaluation of the adjusted reference

temperature (ART) for RPV materials from neutron embrittlement for the period of extended

operation. The initial RTNOT is the temperature at which a nonirradiated metal (ferritic steel)

changes in fracture characteristics, going from ductile to brittle behavior. The applicant

evaluated the RTNDT according to the procedures in ASME Code, Paragraph NB-2331. Neutron

embrittlement raises the initial RTNDT. Appendix G to 10 CFR Part 50 defines the fracture

toughness requirements for the life of the vessel. The "RTNDT is evaluated as the difference in

the 30 ft-lb index temperatures from the average Charpy curves measured before and after

irradiation. This increase ("RTNDT) means that higher temperatures are required for the material

to continue to act in a ductile manner. The ART is defined as RTNDT + ARTNDT + margin. The

margin is defined in RG 1.99. The P-T curves are developed from the ART for the RPV

materials. These are determined by the unirradiated RTNDT and by the ARTNDT calculations for

the licensed operating period. RG 1.99 defines the calculation methods for ARTNDT, ART, and

end-of-life USE. The &RTNDT and ART calculations meet the criteria of 10 CFR 54.3(a). As such,

they are TLAAs.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

LRA Table 4.2.2-1 provides the ART values for all beltline materials at the expiration of the

extended operating period. The materials with the highest ART values are the C2220-1 and

C2220-2 plates, which have 0.17 percent copper and 0.65 percent nickel. Using the RG 1.99,

Revision 2, methodology and a neutron fluence of 3.82x10'8 n/cm2 (E>1 MeV) at the 1/4T

location, the ART for these plates is 157 OF at the expiration of the extended operating period.

4-9
The weld material, which has 0.10 percent copper and 0.99 percent nickel, has an ART of 97 OF

at the expiration of the extended operating period.

The N2 nozzles have an ART of 117 OF. The certified material test report includes nickel content

and initial RTNDT data, but not copper content data. The copper value (0.18 percent) in the

analysis is generic, derived from data from nine nozzles in other BWR beltline nozzles. The

value in the analysis is the mean plus one standard deviation value and is'acceptable to the

staff because it is consistent with the RG 1.99, Revision 2, criteria when copper is not reported

for the material.

The copper and nickel values for the plates and weld material are consistent with those

reported in RVID2. The staff confirmed the applicant's projected values of ART. These ART

values are used in the P-T limits evaluation. P-T limits in the MNGP TSs are periodically

updated (discussed in SER Section 4.2.5).

4.2.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA ART evaluation

for RPV materials from neutron embrittlement in LRA Section A3.1. On the basis of its review of

the USAR supplement, the staff concluded that the summary description of the applicant's

actions to address the ART for RPV materials from neutron embrittlement is adequate.

4.2.2.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the analyses of the ART for RPV materials from neutron

embrittlement have been projected to the end of the period of extended operation. The staff

also concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.2.3 Reflood Thermal Shock Analysis of the RPV

4.2.3.1 Summary of Technical Information in the Application

In LRA Section 4.2.3, the applicant summarized the evaluation of the reflood thermal shock

analysis of the RPV for the period of extended operation. The MNGP USAR includes an

end-of-life thermal shock analysis performed on the RPV for a design-basis loss-of-coolant

accident (LOCA) followed by a low-pressure coolant injection (LPCI). The effects of neutron

embrittlement assumed by this thermal shock analysis will change with an increase in the

licensed operating period. This analysis satisfies the criteria of 10 CFR 54.3(a). As such, this

analysis is a TLAA.

4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.2.3, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

4-10
The peak fluence at the RPV wall is 5.17xl 0"i n/cm2 (E>1 .0 MeV) for 54 EFPY of operation.

Based on this fluence value, the previous reflood thermal shock analysis of the RPV is not

bounding for the period of extended operation. The original analysis has been superseded by

an analysis for BWR-6 RPVs that is applicable to the MNGP BWR-3 RPV.

The BWR-6 RPV analysis applies to MNGP because it uses a bounding main steamline break

event and an RPV thickness similar to that of the MNGP RPV. This analysis assumes

end-of-license material toughness, which in turn depends on the end-of-license ART. The

critical location for the fracture mechanics analysis is at 1/4T RPV thickness. For the main

steamline break event, the peak stress intensity occurs approximately 300 seconds after

initiation of the event. The analysis shows that at that point in the thermal shock event, the

temperature of the vessel wall at 1.5 inches deep (1/4T depth for the BWR-6 RPV) is

approximately 400 OF. For the MNGP vessel, the 1/4T depth is 1.26 inches.

The staff's review of LRA Section 4.2.3 identified an area for which it needed additional

information to complete its evaluation of the applicant's neutron fluence evaluation. The

applicant responded to the staff's RAI as discussed below.

In RAI 4.2-4, dated September 28, 2005, the staff requested that the applicant provide the

fracture toughness (peak stress intensity value) required to prevent fracture of the RPV

resulting from reflood thermal shock.

In its response, dated October 28, 2005, the applicant identified the maximum applied stress

intensity for the thermal shock event as 103 kilopounds per square inch times the square root of

inches (ksi-in"2). Fracture toughness at approximately 300 seconds after initiation of the event

was estimated to be 200 ksi-in"2 . In its response, the applicant stated the following:

Paper G1/5, 'Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel

Following a Postulated Loss of Coolant Accident,' Ranganath, S., Fifth

International Conference on Structural Mechanics in Reactor Technology, Berlin,

Germany, August 1979, defines the basis for this evaluation. As noted in the

MNGP LRA submittal, the BWR/6 example in the paper referenced above

bounds the conditions at the MNGP. This was demonstrated in the submittal by

comparison of the parameters for the BWR/6 case versus the plant-specific

MNGP case. As shown in the submittal, the plant-specific temperature at 1/4T

depth into the vessel wall was determined to be 370 OF at 300 seconds into the

thermal shock event. It was also stated that using the highest 60 year Adjusted

Reference Temperature (ART), the beltline material reaches upper shelf

(200 ksi-in1 2) at 261 OF. Since this temperature is significantly lower than 370°F, it

is assured that the beltline material remains at upper shelf at 300 seconds into

the thermal shock event. Figure 5 of 'Fracture Mechanics Evaluation of a Boiling

Water Reactor Vessel Following a Postulated Loss of Coolant Accident,'

Ranganath, S., Fifth International Conference on Structural Mechanics in

Reactor Technology, Berlin, Germany, August 1979, Paper GI/5, further

demonstrates that at 300 seconds into the thermal shock event and at 1/4T

depth into the vessel wall, the maximum applied stress intensity is 103 ksi-in'12 .

Therefore, there is sufficient margin to prevent fracture due to reflood thermal

shock.

4-11
On the basis of its review, the staff found the applicant's response to RAI 4.2-4 acceptable

because the applicant demonstrated that the beitline materials will have adequate fracture

toughness (applied stress intensity is less than upper-shelf fracture toughness) at 300 seconds

into the event through the period of extended operation. The revised analysis demonstrates that

the reflood thermal shock analysis of the RPV applies for the extended period of operation.

Therefore, the staff's concern described in RAI 4.2-4 is resolved.

4.2.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

reflood thermal shock analysis of the RPV in LRA Section A3.1. On the basis of its review of the

USAR supplement, the staff concluded that the summary description of the applicant's actions

to address the reflood thermal shock analysis of the RPV is adequate.

4.2.3.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the analyses of the reflood thermal shock analysis of the RPV have

been projected to the end of the period of extended operation. The staff also concluded that the

USAR supplement contains an appropriate summary description of this TLAA evaluation,

sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.2.4 Reflood Thermal Shock Analysis of the RPV Core Shroud

4.2.4.1 Summary of Technical Information in the Application

In LRA Section 4.2.4, the applicant summarized the evaluation of the reflood thermal shock

analysis of the RPV core shroud for the period of extended operation. Radiation embrittlement

may affect the ability of RPV internals, particularly the core shroud, to withstand an LPCI

thermal shock transient. The analysis of core shroud strain from reflood thermal shock is a

TLAA because it is part of the CLB, supports a safety determination, and is based on the

calculated lifetime neutron fluence.

4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.2.4, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

Before license renewal, the RPV core shroud was evaluated for an LPCI reflood thermal shock

transient considering embrittlement effects of a 40-year radiation exposure (32 EFPY). The

core shroud receives the maximum irradiation on the inside surface opposite the midpoint of the

fuel centerline. The total integrated neutron flux at the end of 40 years of operation was

2.7x1 020 n/cm2 (greater than 1 MeV). The maximum thermal shock stress in this region is

155,700 pounds per square inch (psi), equivalent to 0.57-percent strain. This strain range of

0.57 percent was calculated at the midpoint of the shroud, the zone of highest neutron

irradiation.

4-12
However, using the approved fluence methodology discussed in SER Section 4.2.1.2, the

applicant revised the analysis for the period of extended operation by calculating the 54 EFPY

fluence at the most irradiated point on the core shroud to be 3.84x10 21 n/cm 2

. The applicant

indicated that the measured value of percent elongation for stainless steel weld metal is

4 percent for a temperature of 297 0C (567 OF) with a neutron fluence of 8x1 021 n/cm2 (greater

than 1 MeV), while the average value for base metal at 290 °C (554 OF) is 20 percent. The

calculated strain range of 0.57 percent represents a considerable margin of safety relative to

measured values of percent elongation for annealed Type 304 stainless steel irradiated to

8x1 021 n/cm2 (greater than 1 MeV). Because the measured value of elongation bounds the

calculated thermal shock strain amplitude of 0.57 percent, the calculated thermal shock strain

at the most irradiated location is acceptable, considering the embrittlement effects for a 60-year

operating period.

The revised analysis demonstrates that the reflood thermal shock analysis of the RPV core

shroud applies for the extended period of operation and satisfies 10 CFR 54.21 (c)(1)(ii)

because the applicant provided additional data to justify operation to a higher neutron fluence to

the end of the period of extended operation.

4.2.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

reflood thermal shock analysis of the RPV core shroud in LRA Section A3.1. On the basis of its

review of the USAR supplement, the staff concluded that the summary description of the

applicant's actions to address the reflood thermal shock analysis of the RPV core shroud is

adequate.

4.2.4.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1 )(ii), that the reflood thermal shock analyses of the RPV core shroud have

been projected to the end of the period of extended operation. The staff also concluded that the

USAR supplement contains an appropriate summary description of this TLAA evaluation,

sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.2.5 RPV Thermal Limit Analysis: Operating Pressure-Temperature Limits

4.2.5.1 Summary of Technical Information in the Application

In LRA Section 4.2.5, the applicant summarized the evaluation of the RPV thermal limit

analysis: operating P-T limits for the period of extended operation. The RPV thermal limit

analysis provides operating P-T limits for the period of extended operation and is dependent on

the ART. The ART is the value of initial RTNDT + ARTNDT + margins (for uncertainties) at a

specific location. Neutron embrittlement increases the ART. Thus, the minimum metal

temperature at which an RPV is allowed to be pressurized increases. The ART of the limiting

beltline material is used to correct the beltline P-T limits to account for irradiation effects.

Appendix G to 10 CFR Part 50 requires RPV thermal limit analyses to determine operating P-T

limits for boltup, hydrotest, pressure tests, and normal operating and anticipated operational

occurrences. Operating limits for pressure and temperature are required for three categories of

4-13
operation-(1) hydrostatic pressure tests and leak tests, referred to as Curve A, (2) nonnuclear

heatup/cooldown and low-level physics tests, referred to as Curve B, and (3) core-critical

operation, referred to as Curve C. P-T limits are developed for three vessel regions, the upper

vessel region, the core beltline region, and the lower vessel bottom head region. The

calculations associated with generation of the P-T curves satisfy the criteria of 10 CFR 54.3(a).

As such, this topic is a TLAA.

4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 4.2.5, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The MNGP TSs include P-T limit curves for core-critical operation, nonnuclear

heatup/cooldown, inservice leakage, and hydrostatic testing. They also limit the maximum rate

of change of reactor coolant temperature. The criticality curves provide limits for both heatup

and criticality calculated for a 32-EFPY operating period. The current TSs contain P-T curves

developed using the 1989 edition of the ASME Boiler and Pressure Vessel Code, incorporating

the effects of the 1998 power uprate, and ASME Code Case N-640, "Alternative Reference

Fracture Toughness for Development of P-T Limit Curves Section XI, Division 1."

P-T limit curves in the MNGP TS are updated periodically, most recently in a February 24,

2003, NRC letter. The staff's February 24, 2003, safety evaluation (SE) indicates that the staff

performed an independent assessment of the proposed curves. The assessment concluded

that the irradiated P-T limit curves for 32 EFPY generated at the plant will be at least as

conservative as those that will be generated with ASME Code Section XI, Appendix G, criteria

and methods, as modified by ASME Code Case N-640, and the limit curves met the minimum

temperature requirements in Table 1 of Appendix G to 10 CFR Part 50. The assessment was

performed for P-T limit curves in which the 1/4T ART value was 157 0F. Because SER

Section 4.2.2.2 indicates a 1/4T ART value of 157 OF at the expiration of the extended operating

period, the TS P-T limit curves apply to the end of the period of extended operation. This

conclusion will be reevaluated when surveillance data for the RPV are withdrawn and tested as

part of the BWRVIP Integrated Surveillance Program.

4.2.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of RPV

thermal limit analysis-operating P-T limits in LRA Section A3.1. On the basis of its review of

the USAR supplement, the staff concluded that the summary description of the applicant's

actions to address the RPV thermal limit analysis-operating P-T limits is adequate.

4.2.5.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the RPV thermal limit analysis-operating P-T limits analyses have

been projected to the end of the period of extended operation. The staff also concluded that the

USAR supplement contains an appropriate summary description of this TLAA evaluation,

sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4-14
4.2.6 RPV Circumferential Weld Examination Relief

4.2.6.1 Summary of Technical Information in the Application

In LRA Section 4.2.6, the applicant summarized the evaluation of the RPV circumferential weld

examination relief for the period of extended operation. Relief from RPV circumferential weld

examination requirements under Generic Letter 98-05, "Boiling Water Reactor Licensees Use

of the BWRVIP-05 Report to Request Relief from Augmented Inspection," is based on

probabilistic assessments that predict an acceptable probability of failure per reactor operating

year. The analysis is based on RPV metallurgical conditions, as well as flaw indication sizes

and frequencies of occurrence that are expected at the end of a licensed operating period.

MNGP has received this relief for the remaining 40-year licensed operating period. The

circumferential weld examination relief analysis meets the requirements of 10 CFR 54.3(a). As

such, it is a TLAA.

4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 4.2.6, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The technical basis for relief is discussed in the staff's final SER concerning the BWRVIP-05

report, "BWR Vessel and Internals Project (BWRVIP), BWR Reactor Pressure Vessel Weld

Inspection Requirements," enclosed in the letter dated July 28, 1998, from Mr. G.C. Laines,

NRC, to Mr. C. Terry, the BWRVIP Chairman. In this letter, the staff concluded that, because

the failure frequency for circumferential welds in BWR plants is significantly below the criterion

specified in RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal Shock

Safety Analysis Reports for Pressurized Water Reactors," and below the core damage

frequency of any BWR plant, continued inspection of the RPV circumferential welds will result in

a negligible decrease in an already acceptably low rate of RPV failure; therefore, elimination of

the inservice inspection (ISI) for RPV circumferential welds is justified. The staff's letter

indicated that BWR applicants may request relief from 10 CFR 50.55a(g) ISI requirements for

volumetric examination of circumferential RPV welds by demonstrating that (1) through the

expiration of the license period, the circumferential welds satisfy the limiting conditional failure

probability for circumferential welds in the NRC staff's July 28, 1998, evaluation and

(2) implementation of operator training and established procedures that limit the frequency of

cold overpressure events to the frequency specified in the staff's SER. 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 LRA;

therefore, the applicant must request relief from inspection of circumferential welds during the

license renewal period, pursuant to 10 CFR 50.55a.

Section A.4.5 of the BWRVIP-74 report indicates that the staff's SER of the BWRVIP-05 report

conservatively evaluated the BWR RPVs to 64 EFPY, which is 10 EFPY greater than

realistically expected for the end of the license renewal period. In the July 28, 1998, SER, the

staff used the mean RTNDT value for materials to evaluate failure probability of BWR

circumferential welds at 32 and 64 EFPY. The neutron fluence at the clad-weld (inner) interface

was used for this evaluation.

4-15
Since the staff analysis discussed in the BWRVIP-74 report is generic, the applicant submitted

plant-specific information to demonstrate that the MNGP RPV beltline materials meet the

criteria specified in the report. To demonstrate that the MNGP RPV has not become embrittled

beyond the basis for the relief, the applicant, in LRA Table 4.2.6.1, compared 54 EFPY material

data for the limiting MNGP circumferential weld with that of the 64 EFPY reference case in

Appendix E to the staff's SER on the BWRVIP-05 report. The MNGP material data included

amounts of copper and nickel, chemistry factor, the neutron fluence, FRTNDT, initial RTNDT, and

mean RTNDT of the limiting circumferential weld at the end of the renewal period. The staff has

verified the data for the copper and nickel contents and the initial RTNDT values for the MNGP

circumferential beltline weld material by comparing them with the corresponding data in RVID.

The 54 EFPY mean RTNDT value for the MNGP circumferential beltline weld is 47.4 OF. The staff

checked the applicant's calculations for the 54 EFPY mean RTNDT values for the limiting MNGP

circumferential welds using the data presented in LRA Table 4.2.6.1 and found them to be

accurate. This 54 EFPY mean RTNDT value for MNGP is bounded by the 64 EFPY mean RTNDT

value of 70.6 OF used by the NRC to determine conditional failure probability of a circumferential

weld in a Chicago Bridge and Iron (CB&I) fabricated RPV. The 64 EFPY mean RTNDT value

from the staff SER dated July 28, 1998, is for a CB&I weld because CB&I welded the

circumferential welds in the RPV. Because the 54 EFPY mean RTNDT value is less than the

64 EFPY value from the staff SER dated July 28, 1998, the staff concluded that the NRC

analysis bounds the MNGP RPV conditional failure probability.

The applicant stated that the procedures and training used to limit cold overpressure events will

be the same as those approved by the NRC when MNGP requested relief for the current

license period. A request for relief during the period of extended operation will be submitted to

the NRC before the period of extended operation.

SER Table 4.2.6-1 summarizes the results of the staff's evaluation regarding the RPV

circumferential weld examination relief.

Table 4.2.6-1 Effects of Irradiation on RPV Circumferential Weld Properties for MNGP

Valu 'B&I64'EFPY 1b - N~PP54 ýEFPY K

Cu 0.10 0.10

Ni (%) 0.99 0.99

CF 134.9 138.5

Fluence x 10'9 (n/cm2 ) 1.02 0.52

DRTNDT (OF) 135.6 113

RTNO- (TF) -65 -65.6

Mean RTNDT (OF) 70.6 47.4

Probability of a failure event (NRC) 1.78x1 0s Note 1

Note 1. If the plant-specific mean ARTNDT is less than the mean ARTNDT associated with

the limiting case study, the staff concludes that the probability of failure for the

plant-specific circumferential weld under review will be less than the conditional

probability of failure value for the limiting circumferential weld in the limiting case study.

4-16
4.2.6.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of RPV

circumferential weld examination relief in LRA Section A3.1. On the basis of its review of the

USAR supplement, the staff concluded that the summary description of the applicant's actions

to address the RPV circumferential weld examination relief is adequate.

4.2.6.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1 )(ii), that the analyses of the RPV circumferential weld examination relief

have been projected to the end of the period of extended operation. The staff also concluded

that the USAR supplement contains an appropriate summary description of this TLAA

evaluation, sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.2.7 RPV Axial Weld Failure Probability

4.2. 7.1 Summary of Technical Information in the Application

In LRA Section 4.2.7, the applicant summarized the evaluation of the RPV axial weld failure

probability for the period of extended operation. The BWRVIP recommendations for inspection

of RPV shell welds contain generic analyses supporting a6 NRC SER conclusion that the

generic-plant axial weld failure rate is no more than 5x1 06 per reactor year. BWRVIP-05

showed that this axial weld failure rate of 5x1 0" per reactor year is orders of magnitude greater

than the 40-year end-of-life circumferential weld failure probability and this analysis justified

relief from inspection of the circumferential welds, as described in Section 4.2.6. MNGP

received relief from the circumferential weld inspections for the remaining 40-year licensed

operating period. The axial weld failure probability analysis meets the requirements of

10 CFR 54.3(a). As such, it is a TLAA.

4.2.7.2 Staff Evaluation

The staff reviewed LRA Section 4.2.7, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

In its July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concern

about the failure frequency of axially oriented welds in BWR RPVs. In response to this concern,

the BWRVIP supplied evaluations of axial weld failure frequency in letters dated December 15,

1998, and November 12, 1999. The staff's SER on these analyses is enclosed in a March 7,

2000, letter from Mr. J. Strosnider (NRC) to Mr. C. Terry, BWRVIP Chairman. The staff

performed a generic analysis using Pilgrim as a model for BWR RPVs. The staff analysis

identified as Mod 2 that the vessel failure frequency will be 5.02 x 1 01-at a mean RTNDT at the

vessel inside surface of 114 *F.

LRA Table 4.2.7-1 compared 54 EFPY material data for the limiting RPV axial weld with that of

Mod 2 from the staff's SE in the March 7, 2000, letter. The MNGP material data included

copper and nickel amounts, chemistry factor, neutron fluence, ARTNDT, initial RTNDT, and mean

RTNDT of the limiting axial weld at the end of the renewal period. The applicant calculated, and

4-17
the staff confirmed, that the limiting axial weld mean RTNDT at the inside surface at the

expiration of the extended operating period is 47.4 OF. Because the mean RTNDT at the vessel

inside surface for the limiting axial weld is less than the value in the staff's Mod 2 analysis, the

failure frequencies for the MNGP RPV will be less than 5 x 10.6 per reactor year of operation at

the end of the period of extended operation; therefore, this analysis is acceptable.

SER Table 4.2.7-1 summarizes the results of the staff's evaluation regarding the RPV axial

weld failure probability.

Table 4.2.7-1 Effects of Irradiation on RPV Axial Weld Properties for MNGP

Value Y Mod 2 ~ M NPlP§4 EFPY

Cu(%) 0.219 0.10

Ni (%) 0.996 0.99

CF 138.5

Fluence x 1019 (n/cm2) 0.148 0.52

DRTNDr (OF) 116 113

RTNDr (OF) -2 -65.6

Mean RTNDT (OF) 114 47.4

Probability of a failure event (NRC) 5.02x10-6 Note 1

Note 1. If the plant-specific mean ARTNDT is less than the mean ARTNDT associated with

the limiting case study, the-staff concluded that probability of failure for the plant-specific

axial weld under review will be less than the conditional probability of failure value for the

limiting axial weld in the limiting case study.

4.2.7.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of RPV

axial weld failure probability in LRA Section A3.1. On the basis of its review of the USAR

supplement, the staff concluded that the summary description of the applicant's actions to

address the RPV axial weld failure probability is adequate.

4.2.7.4 Conclusion

The staff concluded that the applicant has provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the RPV axial weld failure probability analyses have been projected

to the end of the period of extended operation. The staff also concluded that the USAR

supplement contains an appropriate summary description of this TLAA evaluation, sufficient to

satisfy the requirements of 10 CFR 54.21 (d).

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4.3 Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure Boundary

Piping and Components

A metal component subject to cyclic loads less than the static design load may fail from fatigue.

Metal fatigue of components may have been evaluated based on an assumed number of

transients or cycles for the current operating term. The validity of such metal fatigue analysis is

reviewed for the period of extended operation.

The specific criterion for fatigue analysis of ASME Code Section III components involves

calculating the cumulative usage factor (CUF). The fatigue damage in the component caused

by each thermal or pressure transient depends on the magnitude of the stresses caused by the

transient. The CUF sums the fatigue damage from each transient. The ASME Code Section III

criterion requires that the CUF not exceed 1.0.

4.3.1 RPV Fatigue Analyses

4.3.1.1 Summary of Technical Information in the Application

In LRA Section 4.3.1, the applicant discussed that the RPV was designed to ASME Code,

Section II1. RPV fatigue analyses were performed for the vessel support skirt, shell, upper and

lower heads, closure flanges, nozzles and penetrations, nozzle safe ends, and closure studs.

The end of the 40-year license fatigue usage was determined for the normal and upset

pressure and thermal cycle events. After the original stress analyses, several hardware

changes, operational changes (e.g., the 1998 power rerate), and/or stress analysis revisions

have affected usage factors. Calculation of fatigue usage factors is part of the CLB and used to

support safety determinations. The RPV fatigue analyses are TLAAs.

The applicant stated that the 1998 MNGP power rerate included a reanalysis of the RPV. LRA

Table 4.3.1-1 lists the limiting design CUFs for the RPV components. The applicant stated that

the fatigue usage factors in Table 4.3.1-1 were determined using the actual transient cycles

from its Fatigue Monitoring Program (FMP). On the basis of the actual transient accumulation

rate, the applicant concluded that fatigue usage of the RPV components is not expected to

exceed the allowable limit of 1.0 during the period of extended operation. The applicant also

stated that the Fatigue Monitoring Program will monitor transients contributing to fatigue usage,

as described in Appendix B to the LRA.

4.3.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1, pursuant to 10 CFR 54.21 (c)(1)(iii), to verify that the

effects of aging on the intended functions will be adequately managed for the period of

extended operation, and, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been

projected to the end of the period of extended operation.

The RPV components were analyzed using the ASME Code fatigue requirements. LRA

Table 4.3.1-1 lists the design transients for the fatigue analysis of the RPV components. USAR

Table 4.2-1 lists the design transients for the RPV fatigue analysis. The staff confirmed that the

transients in LRA Table 4.3.1-1 are the same as those in USAR Table 4.2-1.

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The staff's review of LRA Section 4.3.1 identified an area for which it needed additional

information to complete its evaluation of the RPV fatigue analysis. The applicant responded to

the staff's RAI as discussed below.

Table 4.3.1-1 also provides the estimated 60-year fatigue usage factors for the RPV

components, which are all less than the ASME Code Section III allowable limit of 1.0. The

applicant indicated that these usage factors include the results of a reanalysis of RPV

components performed as part of the 1998 power rerate. The applicant also indicated that the

fatigue usage factors were determined from the FMP.

In RAI 4.3.1-1, dated June 21, 2005, the staff requested that the applicant describe how it had

calculated the revised fatigue usage factors.

In its response, dated July 21, 2005, the applicant stated that GE Document SASR 89-77,

"Accumulated Fatigue Usage for the Monticello Nuclear Generating Station Reactor Pressure,"

tabulates thermal transient (TT) cycles experienced by MNGP through July 1989. As discussed

in SASR 89-77, the number of transient cycles through July 1989 was determined from a review

of operator log books and plant records. The applicant stated that its FMP updates the number

of TT cycles once per refueling cycle. The applicant used these updated cycles to compute the

fatigue usage factors in LRA Table 4.3.1-1.

Based on its review, the staff found the applicant's response to RAI 4.3.1-1 acceptable because

use of the actual TT cycles to estimate the fatigue usage factors for the period of extended

operation is reasonable; therefore, the staff's concern described in RAI 4.3.1-1 is resolved.

The applicant will rely on its FMP to assure that the fatigue usage of the RPV components will

remain within ASME Code Section III allowable limits during the period of extended operation.

4.3.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of RPV

fatigue analyses in LRA Section A3.2. On the basis of its review of the USAR supplement, the

staff concluded that the summary description of the applicant's actions to address the RPV

fatigue analyses is adequate.

4.3.1.4 Conclusion

The staff reviewed the applicant's TLAA regarding the RPV fatigue analyses, as summarized in

LRA Section 4.3.1. The staff concluded that the applicant has demonstrated that, pursuant to

10 CFR 54.21 (c)(1)(iii), the effects of aging on the intended functions will be adequately

managed for the period of extended operation, and, pursuant to 10 CFR 54.21 (c)(1)(ii), the

analyses have been projected to the end of the period of extended operation. The staff also

concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation sufficient to satisfy 10 CFR 54.21 (d) requirements.

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4.3.2 Fatigue Analysis of RPV Internals

4.3.2.1 Summary of Technical Information in the Application

In LRA Section 4.3.2, the applicant discussed the fatigue analysis of the reactor vessel

internals (RIT), indicating that the analysis was performed using ASME Code, Section III

criteria. The applicant stated that the most significant fatigue loading occurs at the jet pump

diffuser-to-baffle plate weld location. The original 40-year calculation showed a CUF of

approximately 0.33. The applicant estimated the 60-year RIT fatigue usage by multiplying the

40-year fatigue usage by 1.5. The applicant concluded that the fatigue usage of the RIT will

remain below the allowable limit of 1.0 through the period of extended operation.

4.3.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The applicant stated that the RIT fatigue analysis was guided by ASME Code Section III

criteria. The applicant indicated that the most significant fatigue loading occurs at the jet pump

diffuser-to-baffle plate weld location. The applicant's evaluation included three transients, (1)

normal startup and shutdown, (2) improper start of a recirculation loop, and (3) design-basis

accident (DBA).

The applicant stated that the 60-year fatigue usage of the RIT was estimated by multiplying the

original fatigue usage by a factor of 1.5.

The staff's review of LRA Section 4.3.2 identified an area for which it needed additional

information to complete its evaluation of the RIT fatigue analysis. The applicant responded to

the staff's RAI as discussed below.

In RAI 4.3.2-1, dated June 21, 2005, the staff requested that the applicant confirm that the

extrapolation bounded the number of startup/shutdown design cycles listed in LRA

Section 4.3.1.

In its response, dated July 21, 2005, the applicant reiterated that the most significant fatigue

location for the RIT is at the jet pump diffuser-to-baffle plate weld. The applicant stated that the

startup/shutdown cycles had a negligible impact on fatigue usage at this location. The applicant

stated that the only significant contributor to fatigue for the jet pump-to-baffle plate weld is the

transient that includes improper recirculation pump startup and post-DBA flooding. USAR

Section 3.6.3.3 indicates that the RIT were originally evaluated for three improper recirculation

pump starts. The applicant evaluated the impact of the updated number of design cycles listed

in LRA Section 4.3.1 and found that the increase in the number of improper recirculation pump

starts had no significant impact on fatigue usage. Therefore, the applicant concluded that the

use of the 1.5 factor to estimate the 60-year fatigue usage was conservative.

Since the number of postulated DBA events does not increase for the period of extended

operation and the increase in the number of improper recirculation pump starts has no

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significant impact on fatigue usage, the staff concluded that the applicant had adequately

evaluated the RIT.

Based on its review, the staff found the applicant's response to RAI 4.3.2-1 acceptable because

the applicant performed an acceptable evaluation of the RIT for the period of extended

operation, in accordance with the 10 CFR 54.21 (c)(1)(ii) requirements; therefore, the staff's

concern described in RAI 4.3.2-1 is resolved.

4.3.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue analysis of RPV internals in LRA Section A3.2. On the basis of its review of the USAR

supplement, the staff concluded that the summary description of the applicant's actions to

address the fatigue analyses of RPV internals is adequate.

4.3.2.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analysis of RPV internals

summarized in LRA Section 4.3.2 and concluded that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to the

end of the period of extended operation. The staff also concluded that the USAR supplement

contains an appropriate summary description of this TLAA evaluation sufficient to satisfy

10 CFR 54.21(d) requirements.

4.3.3 ASME Section III Class 1 Reactor Coolant Pressure Boundary (RCPB) Piping and

Fatigue Analysis

4.3.3.1 Summary of Technical Information in the Application

In LRA Section 4.3.3, the applicant summarized the evaluation of the ASME Code Section III

Class 1 reactor coolant pressure boundary (RCPB) piping and fatigue analysis for the period of

extended operation. Piping systems were originally designed in accordance with American

Standards Association (ASA) B31.1 and United States of America Standard (USAS) B31.1.0

which did not require an explicit fatigue analysis. The applicant concluded that the analyses

demonstrate that the 40-year CUFs for the limiting components in all affected systems are

below the ASME Code Section III allowable value of 1.0.

4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.3, pursuant to 10 CFR 54.21 (c)(1)(iii), to verify that the

effects of aging on the intended functions will be adequately managed for the period of

extended operation.

The applicant indicated that RCPB piping was originally designed in accordance with

ASA B31.1 and USAS B31.1.0, which did not require explicit fatigue analyses of piping

components. The applicant stated that portions of the RCPB required fatigue analysis, in

accordance with ASME Code Section III for Nuclear Class I piping.

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The staff's review of LRA Section 4.3.3 identified an area for which it needed additional

information to complete its evaluation of the fatigue analysis. The applicant responded to the

staff's RAI as discussed below.

In RAI 4.3.3-1, dated June 21, 2005, the staff requested that the applicant provide the basis for

the requirement that RCPB portions be analyzed for fatigue, in accordance with the ASME

Code Section III for Nuclear Class 1 piping. The staff also requested that the applicant indicate

whether the number of TT cycles used to estimate the 60-year fatigue usage of the core spray

(CSP) valve joint is consistent with the number of TT cycles obtained from the FMP and used to

estimate the 60-year fatigue usage of the CSP nozzle.

In its response, dated July 21, 2005, the applicant indicated that replaced portions of the REC,

CSP, and residual heat removal (RHR) systems were evaluated using ASME Code Section III

fatigue analysis guidelines. Replacement of ASA B31.1 components with ASME Code Section

III components is acceptable. Replaced components must then satisfy ASME Code

requirements, including those for fatigue.

The applicant stated that the design fatigue usage at the limiting location for RCPB CSP piping

is less than 0.65 (CSP valve joint). The applicant estimated the 60-year fatigue usage by

multiplying the design value by 1.5 to obtain a fatigue usage slightly below the allowable limit of

1.0; however, in LRA Table 4.3.1-1, the applicant indicated that the projected 60-year fatigue

usage of the CSP nozzle is 0.65 based on the number of TT cycles counted by the FMP. In

responding to RAI 4.3.3-1, the applicant stated that portions of the CSP piping were replaced in

1986 and that, as discussed above, the replaced piping was evaluated using ASME Code

Section III fatigue guidelines. The applicant indicated that the evaluation considered 100

startup/shutdown cycles; therefore, extrapolation of the CSP piping usage factor by a factor of

1.5 should represent 150 startup/shutdown cycles. LRA Section 4.3.1 projects 207

startup/shutdown cycles for 60 years of plant operation. The staff reviewed data provided in

SASR 89-77 indicating that the most significant TT affecting the CSP nozzle fatigue usage is

startup/shutdown cycles. SASR 89-77 also indicated that 86 startup/shutdown cycles had

accumulated before the CSP piping replacement. Therefore, the number of expected

startup/shutdown cycles for the replaced CSP piping is 121 through the period of extended

operation.

Based on its review, the staff found the applicant's response to RAI 4.3.3-1 acceptable because

the applicant's evaluation of the CSP valve joint represents a conservative estimate for the

number of startup/shutdown cycles; therefore, the staff's concern described in RAI 4.3.3-1 is

resolved.

The applicant's FMP tracks the number of design cycles for RPV components. As discussed in

Appendix B to the LRA, the FMP scope also includes RCPB piping. The staff concluded that the

FMP provides an acceptable program to manage the fatigue usage of the RCPB components

during the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1)(iii).

4.3.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

ASME Code Section III Class 1 RCPB piping and fatigue analysis in.LRA Section A3.3. On the

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basis of its review of the USAR supplement, the staff concluded that the summary description

of the applicant's actions to address the fatigue analysis of ASME Code Section III Class 1

RCPB piping is adequate.

4.3.3.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analysis of ASME Code

Section III Class 1 RCPB piping, as summarized in LRA Section 4.3.3, and concluded that the

applicant has provided an acceptable demonstration that, pursuant to 10 CFR 54.21 (c)(1 )(iii),

the effects of aging on the intended functions will be adequately managed for the period of

extended operation. The staff also concluded that the USAR supplement contains an

appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d)

requirements.

4.3.4 RCPB Section III Class 2 and 3 Piping and Components

4.3.4.1 Summary of Technical Information in the Application

In LRA Section 4.3.4, the applicant summarized the evaluation of the RCPB ASME Code

Section III Class 2 and 3 piping and components for the period of extended operation. These

components were designed to ASA B31.1 and USAS B31.1.0 criteria, which did not require

explicit fatigue analyses of the piping components, but did require application of a stress

reduction factor to the allowable thermal bending stress range, if the number of full-range

cycles exceeds 7000. The applicant stated that the number of thermal cycles experienced by

these systems is not expected to exceed 7000 during the period of extended operation;

therefore, the applicant concluded that the analyses will remain valid for that period.

4.3.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.4, pursuant to 10 CFR 54.21 (c)(1 )(i), to verify that the

analyses will remain valid for the period of extended operation.

The applicant indicated that the remaining piping and components were designed to codes that

did not require explicit fatigue analyses. As discussed previously, the applicant performed

fatigue analyses of the replaced portions of the RCPB piping. The design of the remaining

piping systems is governed by the ASA B31.1 and USAS B31.1.0 criteria that limit the number

of full-range stress cycles from thermal bending to 7000. The applicant stated that the projected

number of thermal bending cycles will not exceed 7000 for any non-ASME Code Section III

Class 1 piping during the period of extended operation based on an assessment of the number

of thermal cycles for the FW nozzle. The applicant selected the FW nozzle because it was

subject to the largest number of TT cycles in the RPV nozzle fatigue analyses. The applicant

multiplied the number of FW nozzle TT design cycles by 1.5 to provide a bounding estimate for

the non-ASME Class 1 piping.

On the basis of its review, the staff concluded that the applicant's evaluation provides a

reasonable upper bound estimate of the number of full-range thermal bending cycles for

non-ASME Class 1 piping systems because the evaluation bounds the expected number of

TTs, including the number of expected startup/shutdown cycles for the facility. Therefore, the

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staff concluded that the applicant has adequately demonstrated that the analyses of the

non-ASME Class 1 piping and components will remain valid for the period of extended

operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(i).

4.3.4,3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

ASME Code Section III Class 2 and 3 piping and components in LRA Section A3.4. On the

basis of its review of the USAR supplement, the staff concluded that the summary description

of the applicant's actions to address the RCPB Section III Class 2 and 3 piping and components

is adequate.

4.3.4.4 Conclusion

The staff reviewed the applicant's TLAA regarding the RCPB Section III Class 2 and 3 piping

and components, summarized in LRA Section 4.3.4, and concluded that the applicant provided

an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i), that the analyses will remain

valid for the period of extended operation. The staff also concluded that the USAR supplement

contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy

10 CFR 54.21 (d) requirements.

4.4 Irradiation-Assisted Stress-Corrosion Cracking (IASCC)

4.4.1 Summary of Technical Information in the Application

In LRA Section 4.4, the applicant summarized the evaluation of irradiation-assisted stress

corrosion cracking (IASCC) for the period of extended operation. Austenitic stainless steel RPV

internal components exposed to a neutron fluence greater than 5x1 020 n/cm2 (E > 1 MeV) are

susceptible to IASCC in the BWR environment. As described in the SER to BWRVIP-26,

IASCC of RPV internals is a TLAA.

4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4, pursuant to 10 CFR 54.21 (c)(1)(iii), to verify that the aging

effects from IASSC on the intended functions will be adequately managed for the period of

extended operation.

The staff reviewed the information in the LRA and noted that the austenitic stainless steel

components exposed to a neutron fluence greater than 5x1 020 n/cm2 (E >1 MeV) are

considered susceptible to IASCC. These RPV internal components include the top guide, the

shroud, and the incore instrumentation dry tubes and guide tubes. The staff reviewed the

fluence calculations for the RPV and verified that other RPV internal components (e.g., the core

plate) are not expected to exceed a neutron fluence of 5x1 020 n/cm2 and thus are considered

not to be susceptible to IASCC. In the LRA, the applicant stated that the aging effects from

IASCC of these RPV components are managed by three aging management programs (AMPs),

B2.1.2, ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12,

BWR Vessel Internals; and B2.1.25, Plant Chemistry. The applicant stated that implementation

of these three AMPs will manage the aging effects from IASCC such that the RPV internal

4-25
components will continue to perform their intended functions consistently with the licensing

basis for the period of extended operation.

The staff reviewed other applicant documents pertaining to the RPV, BWRVIP documents, and

EPRI topical reports applying to generic RPVs. The staff observed that, while fluence level was

the primary contributor to IASCC, additional factors also contributed or increased component

susceptibility to IASCC. The staff observed that BWRVIP-41, "BWR Jet Pump Assembly

Inspection and Flaw Evaluation Guidelines," states that materials like austenitic stainless steel

used in jet pumps are not greatly susceptible to IASCC due to the low fluence levels in the

annulus region." The staff also observed that the June 5, 2001, SER that accepted

BWRVIP-41 stated that materials in a nonoxygenated environment are also not greatly

susceptible to IASCC, which becomes a concern only when cracks are already present in a

component. Thus, the SER stated that, when an applicant can show that cracks have not

occurred in components, loss of fracture toughness from IASCC will not be a significant aging

effect.

The staff asked the applicant to clarify its actions regarding the above additional factors. As to

the aggressive oxygenated environment, the applicant responded that it had implemented

hydrogen water chemistry (HWC) in 1989, which reduces the oxidizing environment of the

reactor coolant system (RCS) by injecting excess hydrogen to combine with free oxygen

produced by radiolysis. The dissolved oxygen content of FW is regulated to 20-50 parts per

billion (ppb) during power operation, which minimizes corrosion potential. The staff reviewed

historical data from the Water Chemistry Program and verified the low dissolved oxygen

content.

In a letter, dated June 10, 2005, the applicant stated that, in addition to those examinations

required by the ISI Program, which includes all pertinent examinations required by the BWRVIP

program, it will examine the top guide grid high-fluence locations using the EVT-1 visual

examination method. In the same letter, the applicant committed to inspections of 10 percent of

these locations within 12 years. The staff reviewed the applicant's operational experience and

observed that, to date, it has inspected 25 percent of the high-fluence locations of the top guide

grid and detected no evidence of cracking.

The staff reviewed the fluence calculations.for the RPV internals and observed that there was a

factor of 30 percent that was added to the calculated fluence level results. The staff asked the

applicant to clarify the purpose of this added factor. The applicant stated that this factor was

added for conservatism.

The staff reviewed the RPV components for IASCC, considering that (1) these components

were composed of a material that was- identified in BWRVIP-41 as not highly susceptible to

IASCC, (2) these components are in a nonaggressive, low-dissolved-oxygen environment, so,

as stated in the SER, the susceptibility of these components to IASCC is reduced, (3) no

evidence of cracks has been detected in the RPV inspections to date, so as stated in the SER,

significant loss of fracture toughness will not result, and (4) the fluence calculations that

determined the three RPV components susceptible to IASCC add a factor of 30 percent, for

conservatism. The staff concluded that the applicant's AMP B2.1.2, ASME Section XI

In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12, BWR Vessel Internals; and

B2.1.25, Plant Chemistry, will adequately manage the aging effects from IASCC for the period

of extended operation.

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During the audit and review, the staff identified an additional issue that required further

clarification by the applicant. The applicant has committed to perform additional top guide

examinations within the first 12 years of the period of extended operation; however, there is no

commitment to perform examinations during the remaining period of extended operation, nor a

commitment as to what the applicant will do if any RPV examination detects an indication. In

RAI 4.1-1, the staff requested that the applicant describe its actions for the remainder of the

period of extended operation.

In its response, by letter dated November 22, 2005, the applicant stated that it will perform an

inspection of a sampling of top guide high-fluence locations (i.e., where fluence exceeds

5.0x102" n/cm2 ) consistent with the lower plenum inspection and flaw evaluation guidelines

described in BWRVIP-47. Ten percent of the total high-fluence population will be inspected

within 12 years, with a minimum of 5 percent inspected within the first 6 years. If flaws are

detected, inspection of an additional 5 percent of the total high-fluence population will be

completed. This process will be repeated until no new flaws are detected. Any flaw exceeding

inspection limits will be evaluated and necessary corrective actions made that may include, but

are not limited to, accept as-is, accept as-is with required periodic reinspection, or remove

indication by metal removal. All corrective actions will be performed in accordance with

approved procedures. Indication mapping and sizing will be documented for use in industry

resolution of any related concerns. Reinspection scope and frequency during the entire period

of extended operation will depend on initial inspection results, as well as on related industry

experience. Therefore, the staff concluded this TLAA is acceptable and consistent with the

GALL Report, and the staff's concern described in RAI 4.1-1 is resolved.

4.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

IASCC in LRA Section A3.5. On the basis of its review of the USAR supplement, the staff

concluded that the summary description of the applicant's actions to address the IASCC is

adequate.

4.4.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(iii), that the aging effects from IASSC on the intended functions will be

adequately managed for the period of extended operation. The staff also concluded that the

USAR supplement contains an appropriate summary description of this TLAA evaluation,

sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.5 Effects of Reactor Coolant Environment

4.5.1 Summary of Technical Information in the Application

In LRA Section 4.5, the applicant summarized its evaluation of the effects of the reactor coolant

environment for the period of extended operation. The applicant evaluated the impact of the

reactor coolant environment on the fatigue life of the locations addressed in NUREG/CR-6260,

"Application of NUREG/CR-5999 Interim Fatigue Curves for Selected Nuclear Power Plant

Components." The applicant's evaluation indicated that the environmental fatigue usage for all

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locations is less than the allowable limit of 1.0 for the period of extended operation. The

applicant concluded that the effects of environmentally assisted fatigue were shown to be

acceptable through the period of extended operation. The applicant further indicated that the

FMP periodically reviews and updates fatigue analyses to ensure continued compliance with the

fatigue acceptance criteria.

4.5.2 Staff Evaluation

The staff reviewed LRA Section 4.5, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The applicant stated that the FMP will continue during the period of extended operation to

assure that design cycle limits are not exceeded. The applicant's FMP tracks transients and

cycles of RCS components with explicit design transient cycles to assure that these

components remain within their design bases. Generic Safety Issue (GSI)-1 66, "Adequacy of

the Fatigue Life of Metal Components," raised concerns about the conservatism of the fatigue

curves used in the design of the RCS components. Although GSI-1 66 was resolved for the

current 40-year design life of operating components, the staff identified GSI-1 90, "Fatigue

Evaluation of Metal Components for 60-Year Plant Life," to address license renewal. The NRC

closed GSI-190 in December 1999, after concluding the following:

The results of the probabilistic analyses, along with the sensitivity studies

performed, the iterations with industry (NEI and EPRI), and the different

approaches available to the licensees to manage the effects of aging, lead to the

conclusion that no generic regulatory action is required, and that GSI-1 90 is

closed. This conclusion is based primarily on the negligible calculated increases

in core damage frequency in going from 40 to 60-year lives. However, the

calculations supporting resolution of this issue, which included consideration of

environmental effects, and the nature of age-related degradation indicate the

potential for an increase in the frequency of pipe leaks as plants continue to

operate. Thus, the staff concluded that, consistent with existing requirements in

10 CFR 54.21, licensees should address the effects of coolant environment on

component fatigue life as aging management programs are formulated in

support of license renewal.

The staff compared the usage factors provided by the applicant with those in NUREG/CR-6260

for the older vintage BWR. NUREG/CR-6260 identified several locations for which the

environmental usage factor was projected to exceed 1.0, including the CSP nozzle safe end,

the FW nozzle, the FW line reactor core isolation cooling (RCIC) tee connection, and the RHR

return line tee.

The staff's review of LRA Section 4.5 identified an area for which it needed additional

information to complete its evaluation of the effects of the reactor coolant environment. The

applicant responded to the staff's RAI as discussed below.

The environmental fatigue usage for the CSP nozzle (safe end) in LRA Section 4.5 is much

lower than the fatigue usage of the CSP nozzle (without environmental effects) in LRA

Table 4.3.1-1. In RAI 4.5-1, dated June 21,2005, the staff requested that the applicant provide

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the basis for the reported usage factors in LRA Section 4.5. In addition, the staff requested that

the applicant discuss the calculation of the Fe, multipliers used for each of the NUREG/CR-6260

locations.

In its response, dated August 16, 2005, the applicant stated that the fatigue usage reported in

LRA Table 4.3.1-1 for the CSP nozzle was based on cycle counting, whereas, the

environmental usage factor in LRA Section 4.5 was based on a detailed stress analysis. During

a followup discussion on September 1, 2005, the applicant stated that the fatigue usage in

Table 4.3.1-1 resulted from considering all load cycles at the maximum stress, and the usage

factor in LRA Section 4.5 resulted from separating the individual load cycles by stress level. The

staff found this explanation reasonable.

The applicant indicated that MNGP used HWC. The NUREG/CR-6260 components were

evaluated for a high oxygen environment without HWC. Oxygen concentration has a significant

impact on the fatigue life of carbon and low-alloy steel components. HWC lowers the oxygen

concentration in BWRs to reduce the stress-corrosion cracking potential of stainless steel

components. The reduced oxygen concentration significantly reduces the environmental impact

on the fatigue life of carbon and low-alloy steel components compared to equivalent

NUREG/CR-6260 carbon and low-alloy steel components.

NUREG/CR-6260 identified high environmental fatigue usage at the stainless steel CSP nozzle

safe end. The applicant replaced the CSP safe ends in 1986. The applicant stated that the

replaced CSP safe ends are carbon steel. Because the applicant has implemented an HWC

program, the environmental impact on the fatigue usage of the carbon steel safe ends is not

significant; therefore, the staff concluded that the applicant's calculated environmental fatigue

usage for the CSP nozzle safe ends is reasonable and acceptable.

Because the applicant uses HWC, usage factors for the FW nozzle and the FW line RCIC tee

connection are not directly comparable to the NUREG/CR-6260 values. The applicant stated

that it had recently evaluated these locations in detail for environmental fatigue. The applicant

also stated that the environmental factors for the evaluations considered both the times HWC

had and had not been in operation. Since the FW nozzle safe ends were replaced in the 1980s,

the lower environmental factor reflects the greater operating exposure to HWC. Considering the

applicant's use of HWC and replacement of the FW nozzle safe ends in the 1980s, the reported

environmental factors are reasonable; therefore, the staff found the applicant's evaluation of the

environmental fatigue usage of the FW nozzle and the FW line RCIC tee connection

acceptable.

The applicant also evaluated the RHR piping tapered transition and RHR return line tee in detail

for environmental fatigue. The RHR return line tee was the bounding fatigue usage location.

Since the RHR return line tee was replaced in the 1980s, it will be subject to fewer years of

service than the component evaluated in NUREG/CR-6260. In addition, the environmental

fatigue criteria for the stainless evaluations in NUREG/CR-6260 were independent of

temperature. Later criteria in NUREG/CR-5704 found that the environmental effect on fatigue

usage is insignificant at temperatures less than 200 °C. The staff noted that RHR shutdown

cooling initiates at less than 200 °C. Considering the items discussed above, the applicant's

environmental fatigue usage of the RHR return line tee is reasonable. Therefore, the staff found

the applicant's evaluation of the environmental fatigue usage of the RHR return line tee

acceptable.

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Based on its review, the staff found the applicant's response to RAI 4.5-1 acceptable because

the applicant reasonably evaluated the environmental impact on the fatigue life of RCPB

components for the period of extended operation; therefore, the staff's concern described in

RAI 4.5-1 is resolved.

4.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of the

effects of the reactor coolant environment in LRA Section A3.7. On the basis of its review of the

USAR supplement, the staff concluded that the summary description of the applicant's actions

to address the effects of the reactor coolant environment is adequate.

4.5.4 Conclusion

The staff reviewed the applicant's TLAA regarding the effects of reactor coolant environment,

as summarized in LRA Section 4.5, and concluded that the applicant provided an acceptable

demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to the

end of the period of extended operation. The staff also concluded that the USAR supplement

contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the

requirements of 10 CFR 54.21 (d).

4.6 Fatigue Analyses of the Primary Containment, Attached Piping, and Components

The Mark I containment consists of a freestanding steel containment drywell, vent system, and

steel pressure suppression chamber (torus). Large-scale testing of the Mark III containment

and in-plant testing of Mark I primary containment systems identified additional hydrodynamic

loads not considered in the original containment design. The Mark I Owners Group initiated the

Mark I Containment Program to develop a generic load definition and structural analysis

techniques. The staff evaluation of the generic load definition and structural assessment

techniques is in NUREG-0661, "Safety Evaluation Report, Mark I Containment Long Term

Program, Resolution of Generic Technical Activity A-7," July 1980. The Mark I Containment

Long-Term Program evaluation of hydrodynamic loads included fatigue analyses of the torus

and vent system and of the torus attached piping (TAP).

The containment liner plates, penetration sleeves (including dissimilar metal welds), and

penetration bellows may be designed in accordance with the ASME Code, Section III,

requirements. If a plant's code of record requires a fatigue analysis, it may be a TLAA and must

be evaluated in accordance with 10 CFR 54.21 (c)(1) to ensure adequate management of the

effects of aging on the intended functions for the period of extended operation.

The staff reviewed the adequacy for the period of extended operation of the fatigue analyses of

the metal containment, containment liner plates (including welded joints), penetration sleeves,

dissimilar metal welds, and penetration bellows. SER Section 4.3 reviews the fatigue 'nalyses

of the pressure boundary of process piping, following the guidance in SRP-LR Section 4.3.

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4.6.1 Fatigue Analysis of the Suppression Chamber, Vents, and Downcomers

4.6.1.1 Summary of Technical Information in the Application

In LRA Section 4.6.1, the applicant discussed the suppression chamber and vent system

fatigue analysis. New hydrodynamic loads were identified subsequent to the original design of

the containment suppression chamber vents. These loads result from blowdown into the

suppression chamber during a postulated LOCA and during safety relief valve (SRV) operation

for plant transients. The applicant identified the vent header-downcomer intersection and the

torus shell as the limiting locations in terms of fatigue usage. The applicant stated that the only

contribution to fatigue usage during normal operation is from SRV operation and that the

number of SRV actuations is not expected to exceed the design number through the period of

extended operation.

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6.1, pursuant to 10 CFR 54.21 (c)(1)(i), to verify that the

analyses will remain valid for the period of extended operation, and, pursuant to

10 CFR 54.21 (c)(1)(iii), to verify that the effects of aging on the intended functions will be

adequately managed for the period of extended operation.

The applicant stated that the Mark I Containment Program evaluated the suppression chamber

and vent header system, including fatigue analyses of the torus shell and vent header system.

The applicant's Mark I Containment Program Plant Unique Analysis Report summarized these

analyses. The applicant subsequently reevaluated these locations for the increased number of

SRV actuations postulated as a result of the 1998 power rerate. The resulting fatigue usage,

considering the increase in SRV cycles, was less than the 1.0 allowable limit. The applicant

estimated that the number of SRV cycles will not exceed the number used for the evaluation of

the suppression chamber and vent header system during the period of extended operation. In

addition, the applicant indicated that the Fatigue Monitoring Program monitors the number of

SRV lifts to assure that the usage factor remains below 1.0 for the limiting components.

The staff found that the applicant's FMP will ensure that fatigue usage of the suppression

chamber vents and downcomers will remain below 1.0 for the period of extended operation, in

accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

4.6.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue analysis of the suppression chamber, vents, and downcomers in LRA Section A3.8. On

the basis of its review of the USAR supplement, the staff concluded that the summary

description of the applicant's actions to address the fatigue analysis of the suppression

chamber, vents, and downcomers is adequate.

4.6.1.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppression

chamber, vents, and downcomers, as summarized in LRA Section 4.6.1, and concluded that

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the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1)(i), that

the analyses will remain valid for the period of extended operation. In addition, the staff

concluded that, pursuant to 10 CFR 54.21 (c)(1)(iii), the effects of aging on the intended

functions will be adequately managed for the period of extended operation. The staff also

concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation, sufficient to satisfy 10 CFR 54.21 (d) requirements.

4.6.2 Fatigue Analysis of the SRV Piping Inside the Suppression Chamber and Internal

Structures

4.6.2.1 Summary of Technical Information in the Application

In LRA Section 4.6.2, the applicant discussed the suppression chamber piping and internals

structure fatigue evaluations. The reactor pressure relief system includes SRVs located on the

main steamlines within the drywell between the reactor vessel and the first isolation valve. The

applicant stated that it had not performed fatigue analyses for torus internal structures (i.e.,

catwalk and monorail). The applicant indicated that it had performed fatigue analyses for the

SRV piping inside the torus. The applicant also stated that the SRV piping analyses will remain

valid for the period of extended operation.

4.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.6.2, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The applicant stated that the fatigue analyses of the torus internal SRV piping had been part of

the Mark I Containment Program. The applicant also indicated that the piping had been

evaluated for the 26-percent increase in the number of SRV cycles resulting from the 1998

power rerate. The resulting 40-year fatigue usage was well below the allowable limit of 1.0. The

applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for

60 years of plant operation.

Because the applicant indicated that the number of SRV cycles used in the power rerate

evaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative

estimate for the period of extended operation; therefore, the staff found that the applicant

adequately demonstrated that the fatigue usage of the torus SRV piping will remain within

acceptable limits for the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1)(ii).

4.6.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue analysis of the SRV piping inside the suppression chamber and internal structures in

LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that

the summary description of the applicant's actions to address the fatigue analysis of the SRV

piping inside the suppression chamber and internal structures is adequate.

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4.6.2.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analysis of the SRV piping inside

the suppression chamber and internal structures, as summarized in LRA Section 4.6.2, and

concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the analyses have been projected to the end of the period of

extended operation. The staff also concluded that the USAR supplement contains an

appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21 (d)

requirements.

4.6.3 Fatigue Analysis of Suppression Chamber External Piping and Penetrations

4.6.3.1 Summary of Technical Information in the Application

In LRA Section 4.6.3, the applicant discussed the fatigue analysis of suppression chamber

external piping and penetrations. These analyses included the large- and small-bore TAP,

suppression chamber penetrations, and the emergency core cooling system (ECCS) suction

header and were based on cycles postulated to occur within the 40-year operating life of the

plant. The applicant stated that these analyses will remain valid for the period of extended

operation.

4.6.3.2 Staff Evaluation

The staff reviewed LRA Section 4.6.3, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation and, pursuant to

10 CFR 54.21 (c)(1 )(iii), that the effects of aging on the intended functions will be adequately

managed for the period of extended operation.

The applicant stated that fatigue effects were specifically addressed for the suppression

chamber TAP penetrations and the suction header in the Mark I Containment Program. The

applicant indicated that it evaluated the TAP penetration fatigue analyses for the 26-percent

increase in SRV cycles resulting from the 1998 power uprate. The resulting 40-year fatigue

usage was less than the allowable limit of 1.0. The applicant indicated that the Fatigue

Monitoring Program monitors the number of SRV lifts to assure that the usage factor remains

below 1.0 for the limiting components.

Because the number of SRV lifts is monitored, the staff found that the applicant's FMP will

assure that the TAP penetrations fatigue usage will remain below 1.0 for the period of extended

operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

The applicant also stated that the Mark I Owner's Group had generically addressed TAP piping

for all Mark I plants. The applicant identified the SRV piping as the limiting location and

evaluated it for a 26-percent increase in the number of SRV cycles as a result of the 1998

power rerate. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The

applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate fatigue usage for 60

years of plant operation.

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Because the applicant indicated that the number of SRV cycles used in the power rerate

evaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative

estimate for the period of extended operation; therefore, the staff found that the applicant

adequately demonstrated that the fatigue usage of the torus SRV piping will remain within

acceptable limits for the period of extended operation, in accordance with the requirements of

10 CFR 54.21 (c)(1)(ii).

4.6.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of the

fatigue analysis of suppression chamber external piping and penetrations in LRA Section A3.8.

On the basis of its review of the USAR supplement, the staff concluded that the summary

description of the applicant's actions to address the fatigue analysis of the suppression

chamber external piping and penetrations is adequate.

4.6.3.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppression

chamber external piping and penetrations, as summarized in LRA Section 4.6.3, and concluded

that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii),

that the analyses have been projected to the end of the period of extended operation. In

addition, pursuant to 10 CFR 54.21 (c)(1)(iii), the staff concluded that the effects of aging on the

intended functions will be adequately managed for the period of extended operation. The staff

also concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation, sufficient to satisfy 10 CFR 54.21 (d) requirements.

4.6.4 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue Analysis

4.6.4.1 Summary of Technical Information in the Application

In LRA Section 4.6.4, the applicant discussed the fatigue analysis of the drywell-to-suppression

chamber vent line bellows. The applicant stated that the vent line bellows stresses are primarily

caused by differential thermal expansion during startup/shutdown and accident conditions. The

applicant projected that the number of startup/shutdown cycles in the design will not be

exceeded during the period of extended operation; therefore, the applicant concluded that the

analysis remains valid for that period.

4.6.4.2 Staff Evaluation

The staff reviewed LRA Section 4.6.4, pursuant to i0 CFR 54.21 (c)(1)(i), to verify that the

analyses will remain valid for the period of extended operation.

The applicant stated that the drywell-to-suppression chamber vent line bellows stresses are

primarily caused by differential thermal expansion of the reactor suppression chamber and

drywell during normal startup and shutdown operations. The applicant stated that the design

assumes 300 startup/shutdown cycles. As indicated in LRA Section 4.3, the applicant projected

fewer than 300 startup/shutdown cycles through the period of extended operation.

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4.6.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

drywell-to-suppression chamber vent line bellows fatigue analysis in LRA Section A3.8. On the

basis of its review of the USAR supplement, the staff concluded that the summary description

of the applicant's actions to address the drywell-to-suppression chamber vent line bellows

fatigue analysis is adequate.

4.6.4.4 Conclusion

The staff reviewed the applicant's TLAA regarding the drywell-to-suppression chamber vent line

bellows fatigue analysis, as summarized in LRA Section 4.6.4, and concluded that the applicant

provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1 )(i), that the analyses will

remain valid for the period of extended operation. The staff also concluded that the USAR

supplement contains an appropriate summary description of this TLAA evaluation, sufficient to

satisfy the requirements of 10 CFR 54.21 (d).

4.6.5 Primary Containment Process Penetration Bellows Fatigue Analysis

4.6.5.1 Summary of Technical Information in the Application

In LRA Section 4.6.5, the applicant discussed the primary containment process bellows fatigue

analysis. Containment pipe penetrations required to accommodate thermal movement have

expansion bellows. The applicant stated that these containment process bellows involve piping

systems that penetrate the drywell shell and that these bellows were designed for a minimum of

7000 operating cycles. The applicant indicated that the number of expected operating cycles

through the period of extended operation is much fewer than 7000; therefore, the applicant

concluded that the analysis of the containment process bellows will remain valid for the period

of extended operation.

4.6.5.2 Staff Evaluation

The staff reviewed LRA Section 4.6.5, pursuant to 10 CFR 54.21 (c)(1)(i), to verify that the

analyses will remain valid for the period of extended operation.

The applicant stated that the containment process piping penetration bellows were designed to

ASME Code Section III, Class B requirements, which do not require a formal fatigue analysis;

however, the criteria for the attached process piping limit the number of full-range bending

cycles. As discussed in SER Section 4.3, the applicant indicated that the number of expected

operating cycles for the process piping is much fewer than 7000; therefore, the applicant

concluded that the analyses of the containment process piping bellows will remain valid for the

period of extended operation.

The staff found that the applicant's evaluation of the process piping provides a reasonable

upper-bound estimate of the number of full-range thermal bending cycles for the process piping

penetration bellows because the evaluation bounds the expected number of TTs, including the

number of expected startup/shutdown cycles, for the facility.

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4.6.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

primary containment process penetration bellows fatigue analysis in LRA Section A3.8. On the

basis of its review of the USAR supplement, the staff concluded that the summary description

of the applicant's actions to address the primary containment process penetration bellows

fatigue analysis is adequate.

4.6.5.4 Conclusion

The staff reviewed the applicant's TLAA of the primary containment process penetration

bellows fatigue analysis summarized in LRA Section 4.6.5 and concluded that the applicant

provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1)(i), that the analyses will

remain valid for the period of extended operation. The staff also concluded that the USAR

supplement contains an appropriate summary description of this TLAA evaluation, sufficient to

satisfy the requirements of 10 CFR 54.21 (d).

4.7 Environmental Qualification of Electrical Equipment (EQ)

4.7.1 Summary of Technical Information in the Application

The 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for

Nuclear Power Plants," environmental qualification (EQ) program has been identified as a TLAA

for the purposes of license renewal. The TLAA of EQ electrical components includes all

long-lived, passive electrical components and instrumentation and controls (I&C) components

that are important to safety and located in a harsh environment. The harsh environments of the

plant are those areas that are subject to environmental effects by a LOCA or a high-energy line

break (HELB). The EQ equipment comprises safety-related (SR) and Q-list equipment,

nonsafety-related (NSR) equipment whose failure could prevent satisfactory accomplishment of

any SR function, and necessary post-accident monitoring equipment.

The applicant's EQ Program manages component thermal, radiation, and cyclic aging through

aging evaluations based on 10 CFR 50.49(f) qualification methods. Environmentally qualified

equipment must be refurbished, replaced, or have its qualification extended before reaching the

aging limits established in the aging evaluation. Aging evaluations for environmentally qualified

equipment that specify the qualified life of at least 40 years are considered TLAAs for license

renewal.

4.7.2 Staff Evaluation

The staff reviewed LRA Section 4.7, pursuant to 10 CFR 54.21 (c)(1)(iii), to verify that the

effects of aging on the intended functions will be adequately managed for the period of

extended operation.

The results of the electrical equipment EQ in LRA Section 4.7 indicate that the aging effects of

electrical equipment EQ identified in the TLAA will be managed during the extended period of

operation under 10 CFR 54.21 (c)(1)(iii); however, the applicant did not submit information on

the attribute of a reanalysis of an aging evaluation to extend the qualification life of such

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electrical equipment identified in the TLAA. The important attributes of a reanalysis are the

analytical methods, the data collection and reduction methods, the underlying assumptions, the

acceptance criteria, and the corrective actions. In RAI 4.7-1, dated November 7, 2005, the staff

requested that the applicant provide information about the important attributes of reanalysis of

an aging evaluation of electrical equipment identified in the TLAA to extend the qualification

under 10 CFR 50.49(e).

In its response, by letter dated December 7, 2005, the applicant stated that the reanalysis of an

aging evaluation normally extends the qualification by reducing excess conservatism

incorporated in the prior evaluation. The staff reviewed this information and found the

applicant's response satisfactory; therefore, the staff's concern described in RAI 4.7-1 is

resolved.

The staff also reviewed the EQ Program to determine whether it will assure that the electrical

components covered under this program will continue to perform their intended function

consistently with the CLB for the period of extended operation. The staff's evaluation of the

component qualification focused on how the program manages the aging effects through

effective incorporation of the following 10 elements-program scope, preventive action,

parameters monitored or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience.

Program Scope

Pursuant to 10 CFR 50.49, the EQ Program evaluates harsh environments in which electrical

equipment important to safety may be required to operate. The applicant stated that an

equipment master list, maintained at MNGP, includes SR electrical equipment, NSR equipment

whose failure could prevent accomplishment of safety functions, and certain post-accident

monitoring equipment. The staff considered the scope of the program acceptable.

Preventive Actions

The ongoing EQ Program ensures that electrical equipment important to safety is capable of

performing its intended function in a harsh environment, in accordancewith 10 CFR 50.49.

Although 10 CFR 50.49 does not require actions that prevent aging effects, EQ Program

actions that could be viewed as preventive actions include (1) establishing the component

service condition tolerance and aging limits (e.g., qualified life or condition limit) and (2) where

applicable, requiring specific installation, inspection, monitoring, or periodic maintenance

actions to manage equipment aging effects within the qualification. The staff considered these

actions acceptable because 10 CFR 50.49 does not require actions that prevent aging effects.

Parameters Monitored or Inspected

The applicant stated that qualified life is not based on condition or performance monitoring.

Pursuant to 10 CFR 50.49(e), the qualification must include and be based on temperature and

pressure, humidity, chemical effects, radiation, aging, submergence, synergistic effects, and

margins. Pursuant to RG 1.89, Revision 1, "Environmental Qualification of Certain Electric

Equipment Important to Safety for Nuclear Power Plants," issued June 1984, monitoring or

inspection of certain environmental conditions or component parameters may be used to

ensure that the component is within the bounds of its qualification basis or as a means to

modify the qualified life. The applicant's EQ Coordinator is responsible for reviewing program

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data and industry information. Deviations are documented in the Corrective Action Program.

(CAP) and actions to correct identified issues may include monitoring, inspection, reanalysis, or

testing. For example, the EQ Coordinator monitors radiation protection surveys for changes in

radiation levels and has initiated a temperature monitoring program in areas containing EQ

equipment. The staff considered this monitoring approach appropriate because the program

objective is to ensure that the established qualified life of devices is not exceeded.

Detection of Aging Effects

10 CFR 50.49 does not require the detection of aging effects for inservice components. The

applicant stated that the CAP, the Preventive Maintenance Program, and the Quality Control

Program will identify any aging effects of EQ equipment and initiate corrective action required to

maintain equipment qualification. In addition, monitoring and inspection of certain environmental

conditions or component parameters may be used to ensure that the component-is within the

bounds of its qualification basis, or as a means to modify the qualified life. The staff considered

the applicant's above programs to detect aging effects acceptable.

Monitoring and Trending

10 CFR 50.49 does not require monitoring and trending of component condition or performance

parameters of inservice components to manage the effects of aging. The EQ Program actions

that could be viewed as monitoring include monitoring how long qualified components have

been installed. Monitoring or inspecting certain environmental, condition, or component

parameters may be used to ensure that a component is within its qualification or as a means to

modify the qualification. The staff considered this program acceptable because 10 CFR 50.49

does not require monitoring and trending of component condition or performance parameters of

inservice components to manage the effects of aging.

Acceptance Criteria

10 CFR 50.49 acceptance criteria require that an inservice EQ component is maintained within

its qualification including its (a) established aging limits and (b) continued qualification for the

projected accident conditions. 10 CFR 50.49 requires refurbishment, replacement, or

requalification before exceeding the aging limits of each installed device. The applicant stated

that its program has identified all components subject to the 10 CFR 50.49 acceptance criteria

on an SR equipment master list. The EQ Coordinator maintains calculations supporting

equipment qualification, which include such information as location, environmental conditions,

qualification methods, and acceptance criteria. Before reaching the-end of qualified life,

affected components are refurbished, requalified, or replaced to ensure continued functionality

of the installed components. The staff considered this program acceptable since it is consistent

with 10 CFR 50.49 requirements of refurbishment, replacement, or requalification before

exceeding the qualified life of each installed device.

Corrective Actions, Confirmation Process, and Administrative Controls

The applicant stated that if an EQ component is found to be outside the bounds of its

qualification basis, it implements corrective actions in accordance with the station's CAP. When

operational or maintenance activities identify unexpected adverse conditions affecting the

environment of a qualified component, it is evaluated and the applicant takes appropriate

corrective actions, which may include changes to the qualification bases and conclusions.

When an emerging industry aging issue is identified that affects the qualification of an EQ

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component, it is evaluated and the applicant takes appropriate corrective actions, which may

include changes to the qualification bases and conclusions. The staff considered this

acceptable because the corrective actions are implemented in accordance with the

requirements of Appendix B to 10 CFR Part 50, which ensures the adequacy of corrective

actions. SER Section 3.0.4 addresses the evaluations of these program elements.

Operating Experience

The EQ Program includes monitoring and assessment of industry information to assess its

impact on EQ components. The applicant stated that the EQ Coordinator is responsible for

reviewing the disposition of such information, as well as subsequent assignment of actions to

be taken on such information and confirmation that the completion of the actions satisfactorily

address potential EQ aging issues. The staff found that the applicant adequately addressed

operating experience.

4.7.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

electrical equipment EQ in LRA Section A3.9. On the basis of its review of the USAR

supplement, the staff concluded that the summary description of the applicant's actions to

address electrical equipment EQ is adequate.

4.7.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration regarding

electrical equipment EQ, pursuant to 10 CFR 54.21 (c)(1)(iii), that the effects of aging on the

intended functions will be adequately managed for the period of extended operation. The staff

also concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.8 Stress Relaxation of Rim Holddown Bolts

4.8.1 Summary of Technical Information in the Application

In LRA Section 4.8, the applicant summarized the evaluation of the stress relaxation of rim

holddown bolts for the.period of extended operation. As described in the SER to BWRVIP-25,

plants must consider relaxation of the rim holddown bolts as a TLAA issue. Because MNGP has

not installed core plate wedges, the loss of preload must be considered in the TLAA evaluation.

4.8.2 Staff Evaluation

The staff reviewed LRA Section 4.8, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The LRA states that, for the period of extended operation, the expected preload loss for the rim

holddown bolts was assumed to be 19 percent, which bounds the original BWRVIP analysis.

With a 19-percent preload loss, the core plate will maintain sufficient preload to prevent sliding

under both normal and accident conditions.

In a letter dated June 10, 2005, the applicant provided additional details of the analysis for the

rim holddown bolts:

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To more accurately address MNGP for License Renewal, a plant-specific

calculation was performed that incorporated the MNGP core plate geometry, an

operating temperature of 288 °C (550 OF) and a MNGP fluence calculation that

was performed specifically for License Renewal in accordance with guidance

provided in Regulatory Guide 1.190, 'Calculational and Dosimetry Methods for

Determining Pressure Vessel Neutron Fluence,' March 2001, (LRA

Section 4.2.1). The maximum fluence applicable to the bolts in the highest

fluence region of the core plate was determined to be 2.2x1 019 n/cm 2 at the end

of the 60-year plant life. The resultant relaxation was determined to be 8 percent

based on GE Design Documents. The analysis assumed that all of the bolts

were at this fluence even though many bolts experience a lower fluence

depending on their specific location...

In RAI 4.8-2, dated September 28, 2005, the staff requested that the applicant provide the

stress relaxation curves, information regarding the material type, the loads used to develop the

stress relaxation curves, and show that the axial and bending stresses for the mean and

highest loaded holddown bolts will not exceed the ASME allowable stresses.

In its response, dated October 28, 2005, the applicant provided, "The Relaxation of Irradiated

Austenitic Steels and Ni-GE Mean Design Curve," based on a model that assumed a

stress-linear, primary plus secondary creep law form and was fit to the shown data using

stepwise multiple regression.

The rim holddown bolts are Type 304 stainless steel. The data used to develop the curve

include several austenitic materials. The applicant analyzed the impact of austenitic material

type on stress relaxation from neutron radiation. In its letter, dated October 28, 2005, the

applicant stated the following:

Relaxation of irradiated, structural materials from radiation creep is much less

sensitive to 'normal material variations' (e.g., in austenitic stainless steels) than

other radiation properties. Radiation segregation and hardening characteristics

are similar for all austenitic stainless steels, although some experience

presegregation (from annealing). Also, neutron relaxation is among the most

consistent and reproducible phenomenon, and little variation is observed in

stainless steel (e.g., 304,316, 321, 347/8, L-grade and nuclear grade). The

relaxation behavior of these stainless steels is often used for many different

austenitic alloys such as Nitronic 50, Alloy X-750 and Alloy 718.

To support the conclusion that the GE design curves apply to Type 304 stainless steel, the

applicant presented stress relaxation data from the BWRVIP-99 report, "Crack Growth Rates in

Irradiated Stainless Steels in BWR Internal Components," and from J.P. Foster and Halden.

The GE design curve predicts higher relaxation levels (i.e., lower fraction of load remaining)

than observed from the Foster and Halden data and is thus conservative compared to these

data.

The analysis included the impact of test temperature and neutron flux on stress relaxation:

More than 80 percent of the tests, shown in Figure 1, were conducted at a

temperature of 550 OF and a majority of these were conducted in an operating

BWR environment. The other tests, were conducted at either 570 or 600 OF

which is expected to produce more relaxation. Since such a large portion of the

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data was conducted at typical BWR operating conditions, the data temperature is

considered fully representative of the core plate bolts.

While the cumulative fluence information was available as part of the original test

reports and the GE Design Curve documentation, the flux conditions were not

directly available. Many of the tests were associated with springs which had

reached fluences ranging from 8x1 020 to 8x1 021 n/cm2. Based on a reasonable

exposure time, the flux will be expected to range from 7x1 012 to 9x1 0 " n/cm 2

/s.

The fluxes defined for two of the smaller sets of test data were 2.7x1 014 and

2x1 017 n/cm2

/s, respectively. Review of the data over these four orders of

magnitude showed no discernable flux dependence; however, the neutron flux

levels were at least 100 times higher than that experienced by the core plate

bolts. As described above, the temperature data are representative for use in the

core plate bolt evaluation. The neutron flux data, however, was measured in

specimens subject to fluxes ranging from lxi 013 to 2xl 017 n/cm2

/s, which is

higher than the 8.5xl 09 n/cm2

/s average flux experienced by the core plate bolts

themselves. Given the large range of higher flux for which the properties are the

same, the impact of the lower flux to which the bolts are exposed is viewed as

negligible.

Based on the. analysis and supporting data, the staff agreed with the applicant that the GE

design curves apply to Type 304 stainless steel used in the core plate bolts.

Based on the GE design curves and a neutron fluence of 2.2x1 019 n/cm2 (E > 1.0 MeV), the

applicant determined that the amount of stress relaxation at the end of the period of extended

operation would be 8 percent. This neutron fluence was calculated using a procedure which is

in accordance with the guidance in RG 1.190 and corresponds to the maximum fluence

applicable to the bolts at the end of the period of extended operation.

The applicant also performed a plant-specific analysis to show that the axial and bending

stresses in the core plate holddown bolts, considering the loss of preload (8 percent) at the end

of the period of extended operation, will not exceed the ASME Code, Section III allowable Pm

(membrane) and Pm + Pb (membrane + bending) stresses. The analysis was based on the

assumption that sufficiently high frictional forces, resulting from the preload forces in the bolts

and coefficient of static friction test data between the rim and the support surfaces, will be

induced between the core plate rim and the shroud support to prevent sliding of the core plate

under design-basis loading resulting from maximum horizontal and vertical seismic and

*accident loads. Under this scenario, no bending stresses are induced in the holddown bolts.

The only stresses sustained by the holddown bolts are axial, resulting from the preload and the

vertical loading (differential pressure and seismic) on the plate. These stresses were shown to

be considerably lower than the ASME Section III allowable Pm stress.

The staff evaluated this analysis and concluded that the postulated coefficient of static friction

was not applicable under the reactor fluid operating environment because of other coefficients

of friction data indicating that a lower value may be appropriate. A smaller coefficient of static

friction permits sliding of the core plate under horizontal acceleration and induces bending

stresses in the bolts. This analysis was, therefore, faund to be unacceptable.

Inspection and flaw evaluation guidelines of BWR core support plates were previously

submitted to the NRC in BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation

Guidelines," issued December 1996. Appendix A to this report contains a prototypical core plate

4-41
holddown bolt analysis under representative horizontal and vertical seismic and accidentloading conditions. The analysis was based on a finite element analysis of the core plate and

the holddown bolts and did not credit friction between the core rim and the shroud support. This

analysis demonstrated that the mean axial and axial + bending stresses in the holddown bolts

meet the ASME Section III bolt stress criteria in the report under typical accident loading. The

staff reviewed this report and found it acceptable for referencing in LRAs, as stated by letter

dated September 6, 2000. Therefore, the staff requested that the applicant perform an analysis,

consistent with the methodology used in Appendix A to BWRVIP-25, and demonstrate that the

bolt axial and bending stresses meet the ASME Section III Pm and Pm + Pb stress criteria in

the report.

By letter dated February 27, 2006, the applicant provided GE technical report

GE-NE-0000-0050-5900P, "Comparative Evaluation of the Monticello Core Plate Rim

Hold-down Bolts and BWRVIP-25, Appendix A Analysis," issued February 2006. This analysis

demonstrates that the MNGP mean axial and bending core plate holddown bolt stresses,

considering holddown bolt stress relaxation, were bounded by the analysis approved in

BWRVIP-25. However, the horizontal and vertical loads used in the analysis were considerably

smaller than those used in the BWRVIP-25 analysis, resulting from the exclusion of certain

accident loads, such as SRV hydrodynamic loads, that were considered in the BWRVIP-25

analysis. The staff requested that the applicant provide justification for the exclusion of these

loads. In its response, dated March 31, 2006, the applicant stated that all applicable DBA loads

specific to the MNGP core plate were applied and provided the horizontal and vertical

accelerations at the core plate level. The applicant justified the exclusion of the hydrodynamic

loads on the basis that these are not applicable to the MNGP vessel and internals since the

MNGP is a BWR/3 Mark I design. The Mark I torus is structurally isolated from the containment

by the use of flexible bellows, and the hydrodynamic loads caused by SRV lift and LOCA are,

therefore, not transmitted to the containment or the vessel. The staff found this justification

reasonable and acceptable.

The BWRVIP-25 analysis is based on a finite element analysis of the core plate and holddown

bolts. It was originally performed to help utilities determine a strategy for core plate inspections,

wherein conservative geometric conditions and bounding, postulated worst-case scenarios

were considered. Because of the similarities in the MNGP and the BWRVIP-25 plates, the

applicant/GE used data from the BWRVIP-25 core plate finite element analysis, an analytical

procedure, and a comparison to the MNGP specific core plate and loads to extrapolate the

BWRVIP-25 analysis to the MNGP core plate and holddown bolts. The applicant showed that

the mean core plate bolt axial and axial + bending stresses met the ASME Section III stress

criteria in BWRVIP-25. However, the BWRVIP-25 analysis also indicated that not all holddown

bolts are uniformly loaded under horizontal and vertical loading. Based on data shown in

BWRVIP-25, the staff also determined that the axial + bending stresses in the highest loaded

MNGP holddown bolts could exceed the Pm + Pb stress criterion of BWRVIP-25, but by an

insignificant margin. However, the applicant's analysis also included bending stresses in the

holddown bolts from core plate bowing, which the BWRVIP-25 analysis did not consider. The

staff evaluated the applicant's analysis and concluded that it is acceptable because it conforms

with accepted structural analysis practice. Therefore, the staff's concern described in RAI 4.8-2

is resolved.

4.8.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

stress relaxation of rim holddown bolts in LRA Section A3.6. In its letter, dated April 10, 2006,

4-42
the applicant provided a revised USAR supplement description which summarized the results of

the analysis provided in the GE technical report. On the basis of its review of the USAR

supplement description provided in the applicant's letter, dated April 10, 2006, the staff

concluded that the summary description of the applicant's actions to address the stress

relaxation of rim holddown bolts adequately describes the analysis characterized in the GE

technical report.

4.8.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(ii), that the stress relaxation of rim holddown bolts analyses have been

projected to the end of the period of extended operation. The staff also concluded that the

USAR supplement contains an appropriate summary description of this TLAA evaluation,

sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.9 Reactor Building Crane Load Cycles

4.9.1 Summary of Technical Information in the Application

In LRA Section 4.9, the applicant summarized the evaluation of the reactor building crane load

cycles for the period of extended operation. The MNGP reactor building crane system consists

of an 85-ton bridge crane. The crane is capable of handling the drywell head, reactor vessel

head, pool plugs, and spent fuel pool shipping cask. A refueling service platform, with

necessary handling and grappling fixtures, services the refueling area and the spent fuel pool.

The reactor building crane system has been modified to incorporate redundant safety features

which were not a part of the original design. The modification consists of a new trolley with

redundant design features and a capacity of 85 tons on the main hook with redundancy

features and an auxiliary 5-ton capacity hook. This modification was implemented for handling

heavy loads, both during refueling operations and during operations involving the offsite

shipment of spent fuel. Such offsite shipments of fuel can take place when the plant is

operating or shut down. The redundant crane was installed to reduce the probability of a heavy

load drop to the category of an incredible event. NUREG-0612 suggests that cranes should be

designed to meet the applicable criteria and guidelines of Chapter 2-1 of American National

Standards Institute (ANSI) B30.2-1976, "Overhead and Gantry Cranes," and of Crane

Manufacturers Association of America (CMAA)-70, "Specifications for Electric Overhead

Traveling Cranes." The reactor building crane, manufactured before the issuance of CMAA-70

and ANSI B30.2-1976, was designed to meet Electric Overhead Crane Institute (EOCI) 61.

Since the evaluation used, as a basis, an expected number of load cycles over the 40-year life

of the plant, reactor building crane load cycles are a TLAA.

4.9.2 Staff Evaluation

The staff reviewed LRA Section 4.9, pursuant to 10 CFR 54.21 (c)(11)(i), to verify that the

analyses will remain valid for the period of extended operation.

In LRA Section 4.9, which is related to the reactor building crane load cycles TLAA, the

applicant stated that the current analysis of the fatigue life remains valid for the 60-year

extended operating period. It is the staff's understanding that this crane will also handle spent

fuel pool shipping casks. A refueling service platform with handling and grappling fixtures

services the refueling area and the spent fuel pool.

4-43
The staff's review of LRA Section 4.9 identified an area for which it needed additional

information to complete its evaluation of the applicant's results. The applicant responded to the

staff's RAI as discussed below.

In RAI 4.9-1, dated July 20, 2005, the staff indicated concerns regarding the fatigue analysis for

the reactor building crane. Therefore, the staff requested that the applicant provide a fatigue

analysis associated with lifts of spent fuel casks and explain how the heavy-load fatigue

analysis in LRA Section 4.9 governs the TLAA.

In its response, dated August 16, 2005, the applicant stated the following:

Section 4.9 of the LRA accounted for cycles due to anticipated lifts of spent fuel

casks by the addition of heavy lift cycles. The current analysis conservatively

assumed 1,120 cycles (for 40 years of operation) due to lifts of reactor building

shield blocks and plugs, the reactor vessel head, the drywell vessel head, the

steam separator assembly, and the steam dryer assembly. The difference

between 1,120 to 2,000 cycles identified in Section 4.9 includes consideration of

additional spent fuel cask lifts, as well as additional current design basis lifts

attributable to the license renewal period of extended operation.

The reactor building crane is currently being upgraded from 85 tons to 105 tons

in anticipation of spent fuel cask duty. Crane calculations are being performed in

accordance with CMAA 70-1975, which identifies stress ranges and allowable

cycles. Preliminary calculations demonstrate that the maximum stress range for

the upgrade design is less than the allowable stress range for the most severe

crane classification operating up to 100,000 cycles. The remaining crane

components are being designed with a 5:1 safety factor, which assures that the

fatigue threshold for 1 do,000 cycles will not be exceeded. Assuming that

offloading of fuel to a spent fuel storage facility must begin with the next refueling

outage at a rate equal to fuel replenishments, as well as spent fuel pool

off loading due to decommissioning activities; the total number of additional

cycles is not expected to exceed 120. This includes the conservative

consideration that both cask placement for acceptance of spent fuel and removal

of the loaded cask to the spent fuel transfer vehicle are at fully loaded conditions.

This results in a total number of cycles, at maximum load for 60 years of

operation, of 1,800 out of 70,000 allowable cycles identified in the LRA.

The crane upgrade calculations have not been completed. Upon completion of

the modification analysis, an evaluation will be made to determine the effect, if

any, on Section 4.9. If the results are not bounded by the current LRA

evaluation/disposition, a revised Section 4.9 will be included with the first Annual

LRA Supplement required by 10 CFR 54, § 54.21 (b).

In its letter, dated February 28, 2006, the applicant verified that the new calculations were

completed and were bounded by the original evaluation; therefore, the staff's concern described

in RAI 4.9-1 is resolved.

4.9.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

reactor building crane load cycles in LRA Section A3.10. On the basis of its review of the USAR

4-44
supplement, the staff concluded that the summary description of the applicant's actions to

address the reactor building crane load cycles is adequate.

4.9.4 Conclusion

The staff concluded that the applicant provided an acceptable demonstration, pursuant to

10 CFR 54.21 (c)(1)(i), that the reactor building crane load cycles analyses will remain valid for

the period of extended operation. The staff also concluded that the USAR supplement contains

an appropriate summary description of this TLAA evaluation, sufficient to satisfy

10 CFR 54.21(d) requirements.

4.10 Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations

4.10.1 Summary of Technical Information in the Application

In LRA Section 4.10, the applicant discussed the evaluation of the high-pressure coolant

injection (HPCI) and RCIC turbine exhaust penetrations fatigue analyses. The applicant

evaluated these penetrations for the combination of SRV actuations, LOCA loads, and

operational testing of the turbines and concluded that the fatigue usage of the HPCI and RCIC

turbine exhaust penetrations will remain below 1.0 during the period of extended operation.

4.10.2 Staff Evaluation

The staff reviewed LRA Section 4.10, pursuant to 10 CFR 54.21 (c)(1)(ii), to verify that the

analyses have been projected to the end of the period of extended operation.

The applicant evaluated the HPCI and RCIC turbine exhaust penetrations for an increased

number of SRV cycles resulting from the 1998 power rerate. The applicant combined the

fatigue usage from SRV actuations with the LOCA and operating-basis earthquake (OBE)

fatigue usage. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The

applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for

60 years of plant operation. The resulting fatigue usage was well below the 1.0 allowable limit.

Based on its review, the staff concluded that the 1.5 factor provides a conservative estimate of

the fatigue usage from SRV actuations, simultaneously with a LOCA and OBE, for the period of

extended operation.

The applicant evaluated the fatigue usage from operational testing of the HPCI and RCIC

turbines separately. The applicant instrumented these nozzles to measure temperatures during

the operational tests and calculated the maximum fatigue usage for the RCIC turbine exhaust

penetration from these operational tests. The RCIC turbine exhaust penetration had the

greatest fatigue usage. The applicant determined that the total fatigue usage will be acceptable,

considering more than five RCIC turbine tests per month over the 60-year extended life.

Therefore, the applicant concluded that the analyses of the HPCI and RCIC turbine exhaust

penetrations will remain valid for the period of extended operation. The staff agreed that the

number of HPCI and RCIC turbine tests will average fewer than five per month.

Based on its review of the applicant's analysis, the staff found that the applicant adequately

demonstrated that the fatigue usage of the HPCI and RCIC turbine exhaust penetrations will

remain within acceptable limits for the period of extended operation, in accordance with

10 CFR 54.21 (c)(1)(ii) requirements.

4-45
4.10.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue analyses of HPCI and RCIC turbine exhaust penetrations in LRA Section A3.1 1. On the

basis of its review of the USAR supplement, the staff concluded that the summary description

of the applicant's actions to address the fatigue analyses of HPCI and RCIC turbine exhaust

penetrations is adequate.

4.10.4 Conclusion

The staff reviewed the applicant's TLAA regarding the fatigue analyses of HPCI and RCIC

turbine exhaust penetrations, as summarized in LRA Section 4.10, and concluded that the

applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21 (c)(1)(ii), that

the analyses have been projected to the end of the period of extended operation. The staff also

concluded that the USAR supplement contains an appropriate summary description of this

TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21 (d).

4.11 Conclusion for Time-Limited ALginaq Analyses

The staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On the

basis of its review, the staff concluded that the applicant provided an adequate list of TLAAs, as

defined in 10 CFR 54.3. Further, the staff concluded that the applicant demonstrated that

(1) the TLAAs will remain valid for the period of extended operation, as required by

10 CFR 54.21 (c)(1)(i), (2) the TLAAs have been projected to the end of the period of extended

operation, as required by 10 CFR 54.21 (c)(1)(ii), or (3) that the aging effects will be adequately

managed for the period of extended operation, as required by 10 CFR 54.21 (c)(1)(iii). The staff

also reviewed the USAR supplement for the TLAAs and found that the USAR supplement

contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21 (d). In

addition, the staff concluded that no plant-specific exemptions are in effect that are based on

TLAAs, as required by 10 CFR 54.21 (c)(2).

4-46
SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) related to the renewal of the operating

license for the Monticello Nuclear Generating Plant (MNGP) on April 26, 2006. On May 30,

2006 the applicant presented its license renewal application, and the staff presented its review

findings to the ACRS Plant License Renewal Subcommittee. The staff reviewed the applicant's

comments on the SER and completed its review of the license renewal application. The staffs

evaluation is documented in a final SER that was issued by letter dated July 28, 2006.

Durirng the 5351h meeting of the ACRS, September 7, 2006, the ACRS completed its review of

the MNGP license renewal application and the NRC staff's SER. The ACRS documented its

findings in a letter to the Commission dated September 19, 2006. A copy of this letter is

provided on the following pages of this SER Section.

5-1

September 19, 2006

The Honorable Dale E. Klein

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 2005-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE MONTICELLO NUCLEAR GENERATING PLANT

Dear Chairman Klein:

During the 5 3 5 t meeting of the Advisory Committee on Reactor Safeguards,

September 7-8, 2006, we completed our review of the license renewal application for

the Monticello Nuclear Generating Plant (MNGP) and the final Safety Evaluation Report

(SER) prepared by the NRC staff. Our Plant License Renewal Subcommittee also

reviewed this matter during a meeting on May 30, 2006. During our review, we had the

benefit of discussions with representatives of the NRC staff and the applicant, Nuclear

Management Company, LLC (NMC). We also had the benefit of the documents

referenced. This report fulfills the requirements of 10 CFR 54.25 that the ACRS review

and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

The programs established and committed to by the applicant to manage age-related

degradation provide reasonable assurance that MNGP can be operated in accordance

with its current licensing basis for the period of extended operation without undue risk to

the health and safety of the public.

The NMC application for renewal of the operating license for MNGP should be

approved.

BACKGROUND AND DISCUSSION

MNGP is a General Electric Boiling Water Reactor-3 (BWR-3) within a Mark-I

containment. The current power rating of 1775 MWt includes a 6.3% power uprate that

was implemented in 1998. NMC requested renewal of the MNGP operating license for

20 years beyond the current license term, which expires on September 8, 2010.

In the final SER, the staff documented its review of the license renewal application and

other information submitted by NMC and obtained during the audits and inspections

conducted at the plant site. The staff reviewed the completeness of the applicant's

identification of structures, systems, and components (SSCs) that are within the scope

of license renewal; the integrated plant assessment process; the applicant's

identification of the plausible aging mechanisms associated with passive, long-lived

components; the adequacy of the applicant's Aging Management Programs (AMPs);

and the identification and assessment of time-limited aging analyses (TLAAs) requiring

review.

5-3
The NMC application is largely consistent with the Generic Aging Lessons Learned

(GALL) Report. All deviations from the approaches specified in the GALL Report are

documented in the application. The applicant identified the SSCs that fall within the scope

of license renewal and performed a comprehensive aging management review

for these SSCs. Based on the results of this review, the applicant will implement 36

AMPs for license renewal including existing, enhanced, and new programs. In the

SER, the staff concluded that the applicant has appropriately identified the SSCs iýVithin

the scope of license renewal and that the AMPs described by the applicant are

appropriate and sufficient to manage aging of long-lived passive components that are

within the scope of license renewal. We concur with this conclusion.

The staff conducted an inspection and an audit. The inspection verified that the

scoping and screening methodologies are consistent with the regulations and are

adequately reflected in the application. The audit verified the appropriateness of the

AMPs and the aging management reviews. Based on the inspection and audit, the staff

concluded that these programs are consistent with the descriptions contained in the

NMC license renewal application. The staff also concluded that the existing programs,

to be credited as AMPs for license renewal, are generally functioning well and that an

implementation plan has been established in the applicant's commitment tracking

system to ensure timely completion of the license renewal commitments.

During our meetings with the staff and the applicant, we discussed the adequacy of

programs proposed by NMC to manage aging of certain components that are a current

focus of the staff and the industry, as described below.

Aging of the drywell shell of MNGP will be managed through the use of the ASME

Section Xl, Subsection IWE Program. We agree with this approach. Even though this

Program does not include ultrasonic testing, this approach was chosen by NMC and

accepted by the staff because the plant has several design features that prevent water

accumulation behind the shell. During each refueling outage, water leakage is

monitored from the refueling seal bellows, the drywell air gap drains, and the sandpocket drains. The refueling seal is within the scope of license renewal. Ultrasonic

inspections performed in the past did not identify any degradation.

MNGP has experienced shroud cracking. This cracking was identified through the

required licensee inspection process. Periodic inspections of up to 75% of the shroud

welds are performed according to the guidelines of the Boiling Water Reactor Vessel

and Internals Project (BWRVIP). Previously identified flaws have exhibited no

significant crack growth since the introduction of hydrogen water chemistry at MNGP.

Aging of the shroud will continue to be managed by using the guidelines in the

BWRVIP-76. We find this AMP appropriate.

The MNGP steam dryers are within the scope of license renewal. A 1998 inspection

identified an indication that was not structurally significant. A 2001 inspection revealed

no change in this indication and no additional indications were identified. A

comprehensive inspection conducted in 2005 to examine areas where steam dryer

failures had occurred at other plants found new indications on the dryer shell. These

indications were evaluated and determined to be acceptable by the applicant. Another

inspection is planned for 2007. Aging of the steam dryers will continue to be managed

in accordance with the guidelines in the BWRVIP-139 program. We find this AMP appropriate.

5-4
The applicant identified the systems and components requiring TLAAs and reevaluated

them for 20 more years of operation. Affected TLAAs included those associated with

neutron embrittlement, metal fatigue, irradiation-assisted stress corrosion cracking,

environmental qualification of electrical equipment, and stress relaxation of hold-down

bolts. The staff concluded that the applicant has provided an adequate list of TLAAs.

Further, the staff concluded that in all cases the applicant has met the requirements of

the license renewal rule by demonstrating that the TLAAs will remain valid for the period

of extended operation, or that the TLAAs have been projected to the end of the period

of extended operation, or that the aging effects will be adequately managed for the

period of extended operation. We concur with the staff that MNGP TLAAs have been

properly identified and that criteria supporting 20 more years of operation have been

met.

We agree with the staff that there are no issues related to the matters described in

10 CFR 54.29(a)(1) and (a)(2) that preclude renewal of the operating license for MNGP.

The programs established and committed to by NMC provide reasonable assurance

that MNGP'can be operated in accordance with its current licensing basis for the period

of extended operation without undue risk to the health and safety of the public. The

-NMC application for renewal of the operating license for MNGP should be approved.

Sincerely,

/RA/

Graham B. Wallis

Chairman

References:

1) Safety Evaluation Report Related to the License Renewal of the Monticello

Nuclear Generating Plant, dated August 2, 2006.

2) Monticello Nuclear Generating Plant - Application for Renewed Operating

License, dated March 16, 2005.

3) Audit and Review Report for Plant Aging Management Programs (AMPs) and

Aging Management Reviews (AMRs) -Monticello Nuclear Generating Plant, dated

October 12, 2005.

4) Monticello Nuclear Generating Plant, Inspection Report 05000263/2006006,

dated March 30, 2006.

5) BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw

Evaluation Guidelines (BWRVIP-76), EPRI Report TR-1 14232, November 1999.

6) BWR Vessel and Internals Project, Steam Dryer Inspection and Flaw Evaluation

Guidelines (BWRVIP-1 39), EPRI Report TR-1011463, April 2005.

5-5

SECTION 6

CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) reviewed the license

renewal application (LRA) for the Monticello Nuclear Generating Plant (MNGP), in accordance

with the NRC regulations and NUREG-1 800, "Standard Review Plan for Review of License

Renewal Applications for Nuclear Power Plants," dated July 2001. Title 10, Section 54.29,

"Standards for Issuance of a Renewed License," of the Code of Federal Regulations

(10 CFR 54.29) provides the standards for issuance of a renewed license.

On the basis of its review, the staff concluded that the applicant adequately identified those

systems and components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those systems and components that are subject to an aging management

review, as required by 10 CFR 54.21 (a)(1). The staff also concluded that the applicant

demonstrated that the aging effects will be adequately managed so that the intended functions

will be maintained consistent with the current licensing basis (CLB) for the period of extended.

operation, as required by 10 CFR 54.21 (a)(3). Further, the staff concluded that the applicant

demonstrated that (1) the time-limited aging analyses (TLAAs) will remain valid for the period of

extended operation, as required by 10 CFR 54.21 (c)(1 )(i), (2) the TLAAs had been projected to

the end of the period of extended operation, as required by 10 CFR 54.21 (c)(1)(ii), or (3) that

the aging effects will be adequately managed for the period of extended operation, as required

by 10 CFR 54.21 (c)(1)(iii). On the basis of its evaluation of the LRA, the staff determined that

the requirements of 10 CFR 54.29(a) have been met, 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 plant's CLB in order to comply with this

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

The staff notes that any requirements of Subpart A, "National Environmental Policy

Act-Regulations Implementing Section 102(2)," of 10 CFR Part 51, "Environmental Protection

Regulations for Domestic Licensing and Related Regulatory Functions," are documented in

draft Supplement 26 to NUREG-1437, "Generic Environmental Impact Statement for License

Renewal of Nuclear Plants: Regarding Monticello Nuclear Generating Plant Final Report,"

dated January 23, 2006.

6-1

APPENDIX A

COMMITMENTS.FOR LICENSE RENEWAL OFIMNGP

During the review of the Monticello Nuclear Generating Plant license renewal application, the

applicant made commitments to manage the aging effects of structures and components before

the period of extended operation. The following table lists these commitments, along with the

implementation schedule and the source of the commitment.

A-1

APPENDIX A: COMMITMENTS FORLCENSE RENEWAL OF MNGP

Item No. Commitment Implementation Source.

___________________________________________Schedule._________

Each year, following the submittal of the MNGP License Annually LRA Section 1.4

Renewal Application and at least 3 months before the scheduled

completion of the NRC review, NMC will submit amendments to

the MNGP application pursuant to 10 CFR 54.21 (b). These

revisions will identify any changes to the CLB that materially

affect the contents of the LRA, including the USAR supplements

and any other aspects of the application.

2 In accordance with the guidance of Appendix A.3.2.1.2 to Annually LRA Section 3.0.7

NUREG-1 800, Appendix B to the latest issued supplement to

NUREG-0933 will be reviewed for new GSIs designated as

USI-, HIGH-, or MEDIUM-priority. Any GSIs identified that

involve TLAAs or aging effects for structures and components

subject to an aging management review will be included in the

annual update of the LRA.

3 Inspection of the steam dryer is to be accomplished using the As Required LRA Table

guidelines in the approved BWRVIP topical report(s) for steam 3.1.2-3, Note 136

dryer inspection. In the event a new steam dryer is installed,

NMC will reevaluate the inspection requirements.

4 The interior of the diesel fire pump house masonry block walls is As Required LRA Table

covered with insulation. The MNGP Structures Monitoring 3.5.2-8, Note 516

Program will require the interior surfaces of the walls to be

examined if exterior wall surfaces show evidence of significant

aging effects.

A-3
APPENDIX A: COMMITMENTS'FORELICENSEIRENEWAL OF MNGP

fe t No.Comt•mitment- Impleme"tation Source

5 The procedures and training used to limit RPV cold As Required LRA Section

overpressure events will be the same as those approved by the 4.2.6

NRC when MNGP requested approval of the BWRVIP-05

technical alternative for the term of the current operating

license. A request for extension for the 60-year

extended operating period will be submitted to the NRC before

the period of extended operation.

6 MNGP site-specific administrative work instructions will be Prior to Period of LRA Section

applicable to both safety- and nonsafety-related systems, Extended Operation B13.3

structures, and components that are subject to an aging

management review consistent with the current licensing basis

during the period of extended operation.

7 Site documents that implement aging management activities for Prior to Period of LRA Section

license renewal will be enhanced to ensure that an AR is Extended Operation B1.3

prepared in accordance with plant procedures whenever

nonconforming conditions are found (i.e., the acceptance criteria

is not met).

8 Revisions will be made to procedures and instructions that Prior to Period LRA Section

implement or administer aging management programs and/or of Extended B1.3

activities for the purpose of managing the associated aging Operation

effects for the duration of extended operation.

9 The MNGP ASME Section Xl, Subsection IWF Program will be Prior to Period LRA Section

enhanced to provide inspections of Class MC component of Extended B2.1.3

supports consistent with NUREG-1801, Chapter III, Section Operation

B1.3.

A-4
APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL.OF MNGP

Item No. Commitment implementation ISource .. ..______ __,,,_:_____,_,_____ -__ ,___, _____• __• __"_• , .Schedule _ _ _ _ _

10 The guidance for performing visual bolting inspections-contained Prior to Period LRA Section

in EPRI TR-1 04213, Bolted Joint Maintenance & Application of Extended B2.1.4

Guide, and the Good Bolting Practices Handbook (EPRI Operation

NP-5067 Volumes I and 2) will be included in the Bus Duct

Inspection Program, Inspection of Overhead Heavy Load and

Light Load (Related to Refueling) Handling Systems Program,

Structures Monitoring Program, and the System Condition

Monitoring Program. '_

11 The Buried Piping and Tanks Inspection Program will update the Prior to Period LRA Section

implementing procedures to include inspections of buried of Extended Operation B2.1.5

components when they are uncovered.

12 The diesel fuel oil storage tank, T-44, internal inspection will be Prior to Period LRA Section

added to the list of scheduled inspections in the Buried Piping of Extended B2.1.5

and Tanks Inspection Program. OperationI

13 The Buried Piping and Tanks Inspection Program will be revised Prior to Period LRA Section

to include a provision that if evaluations of pipe wall thickness of Extended B2.1.5

show a susceptibility to corrosion, further evaluation as to the Operation

extent of susceptibility will be performed.

14 The Buried Piping and Tanks Inspection Program will be revised Prior to Period LRA Section

to specify a 10-year buried pipe inspection frequency. of Extended B2.1 .6

Operation

15 The Buried Piping and Tanks Inspection Program will be revised Prior to Period LRA Section

to specify a 10-year inspection frequency for diesel fuel oil of Extended B2.1.5

storage tank, T-44. Operation

A-5
_____ •!..APPENDIX _ A: COMMITMENTS FOR LICENSE RENEWAL OF MNGP

Item No. Commitment implementation Source

___________ _________l_______________ __________________ i Schedule _______ ______,

16 The Buried Piping and Tanks Inspection Program will be revised Prior to Period LRA Section

to include a review of previous buried piping issues to determine of Extended Operation. B2.1.5

possible susceptible locations.

17 The Bus Duct Inspection Program will be implemented Prior to Period LRA Section

consistent with the appropriate 10 elements described in of Extended B2.1.0

Appendix A to NUREG-1 800, Standard Review Plan for Review Operation

of License Renewal Applications for Nuclear Power i

Plants.

18 The BWR Feedwater Nozzle Program will be enhanced so the Prior to Period LRA Section

parameters monitored and inspected are consistent with the of Extended B2.1.8

recommendations of GE NE-523-A71-0594-A, Revision 1. Operation _

19 The BWR Feedwater Nozzle Program will be enhanced so the Prior to Period LRA Section

regions being inspected, examination techniques, personnel of Extende~d B2.1.$

qualifications, and inspection schedule are consistent with the Operation

recommendations of GE NE-523-A71-0594-A, Revision 1. O,

20 The BWR Feedwater Nozzle Program will be enhanced so that Prior to Period LRA Section

inspections will be scheduled in accordance with the of Extended B2.1 .8

recommendations of GE NE-523-A71-0594-A, Revision 1. Operation _

21 The repair/replacement guidelines in BWRVIP-16,19, 44, 45, Prior to Period LRA Section

50, 51, 52, 57, and 58 will be added, as applicable, to the of Extended B2.1 .1,2

MNGP BWR Vessel Internals Program. Operation __

A-6
APPENDIX A: COMMITMENTS FORULCENSE RENEWAL OF MNGP.,. _______

Item NO. Commitment Implementation..; Source

Schedule. I

22 NMC will perform top guide grid inspections, using the EVT-1 During the LRA Section

method of examination, for the high-fluence locations (grid Period of B2.1 .12

beam and beam-to-beam crevice slot locations with fluence Extended

exceeding 5.0x1 20 n/cm2). Ten percent of the total population Operation

will be inspected within 12 years, with a minimum of 5 percent

inspected within the first 6 years.

23 A one-time inspection will be performed to monitor the effects of Prior to Period LRA Section

corrosion on select portions of closed-cycle cooling water of Extended B2.1 .1 3

systems that perform a pressure-integrity intended function. Operation

24 The Compressed Air Monitoring Program procedures will be Prior to Period LRA Section

revised to include corrective action requirements, if the of Extended B2.1).14

acceptance limits for water vapor, oil content, or particulate are Operation

not met. In addition, the acceptance criteria for oil content

testing will be clarified and the basis for the acceptance limits for

the water vapor, oil content, and particulate tests will be

provided.

25 The Compressed Air Monitoring Program will be revised to Prior to Period LRA Section

include inspection of air distribution piping based on the of Extended B2.1 .1,4

recommendations of EPRI T"R-108147. Operation

26 The MNGP Electrical Cables & Connections Not Subject To Prior to Period LRA Section

10 CFR 50.49 Environmental Qualification Requirements of Extended B2.1.15

Program will be implemented as a new program consistent with Operation

the recommendations of GALL AMP XI.E1. The program will

manage the aging of conductor insulation material on cables,.

connectors, and other electrical insulation materials that are

installed in an adverse localized environment caused by heat,

radiation, or moisture.

A-7
APPENDIX• •AOMMITMENTSFOR LICENSE RENEWAL 0ýFMNGP I

Item. No.. Commitment Implementattion Source

_____ _____ _____ _____ _____ ____ _____ _____ _____ _____ ____Sched ule _ _ _ _ _ _ _ _

27 The Electrical Cables Not Subject to 10 CFR 50.49 Prior to Period LRA Section

Environmental Qualification Requirements Used in of Extended B2.1 .16

Instrumentation Circuits Program will be implemented as a new Operation

program. With exceptions, it will be consistent with the

recommendations of GALL AMP XI.E2.

28 The MNGP Fire Protection Program will be revised to include a Prior to Period LRA Section

visual inspection of the halon fire suppression system to detect of Extended B2.1 .J7

any signs of d~gradation, such as corrosion and mechanical Operation

damage. This visual inspection will provide aging management

for external surfaces of the halon fire suppression system.

29 The Fire Protection Program plan document will be revised to Prior to Period LRA Section

include qualification criteria for individuals performing visual of Extended B2.1 .17

inspections of penetration seals, fire barriers, and fire doors. Operation

The qualification criteria will be in accordance with VT-1 or

equivalent and VT-3 or equivalent, as applicable.

30 The Fire Water System Program implementing procedures will Prior to Period LRA Section

be revised to include the extrapolation of inspection results to of Extended B2.1 .18

below-grade fire water piping with similar conditions that exist Operation

within the above-grade fire water piping.

31 The Fire Water System Program sprinkler heads will be Prior to Period LRA Section

inspected and tested based on NFPA requirements or replaced of Extended B2.1 .,18

before the end of the 50-year sprinkler head service life and at Operation

10-year intervals thereafter during the extended period of

operation to ensure that signs of degradation, such as

corrosion, are detected in a timely manner.

A-8
APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGP

Item No. Commitment Implementation Source

____ ___ ____ ____ _ ___ _ ____ ____ ____ ___ ____ ___ ____ ___Schedule _ _ _ _ _ _ _ _

32 NMC will verify the procedures to be used for aging Prior to Period LRA Section

management activities of the fire water system and apply testing of Extended B2.1.18

in accordance with applicable NFPA codes and standards. Operation

Relevant procedures will be revised, as appropriate.

33 The MNGP procedures related to the diesel fuel oil system will Prior to Period LRA Section

be revised to include requirements to check for general, pitting, of Extended B2.1.20

crevice, galvanic, MIC, and cracking. Operation

34 The MNGP Fuel Oil Chemistry Program procedures will be Prior to Period LRA Section

revised to require tank draining, cleaning, and inspection, if of Extended B2.1.20

deemed necessary based on the trends indicated by the results Operation

of the diesel fuel oil analysis, or as recommended by the system

engineer based on equipment operating experience.

35 Existing procedures in the MNGP Fuel Oil Chemistry Program Prior to Period LRA Section

will be developed or revised to require periodic tank inspections of Extended B2.1.20

of the diesel fuel oil tanks. Operation

36 The MNGP Inaccessible Medium Voltage (2 kV to 34.5 kV) Prior to Period LRA Section

Cables Not Subject to 10 CFR 50.49 EQ Requ.irements Program of Extended B2.1.21

will be implemented as a new program consistent with the Operation

recommendations of GALL AMP XI.E3.

37 The Inspection of Overhead Heavy Load and Light Load Prior to Period LRA Section

(Related to Refueling) Handling Systems Program will be of Extended B2.1.22

enhanced to specify a 5-year inspection frequency for the fuel Operation

preparation machines. II_ I

A-9
APPENDIX A: COMMITMENTS FOR LICENSE, RENEWAL OF -MNGP_______

Item No. Commitm'ent,ý Implementation< Source

___________________________________________________Schedule.________

38 The MNGP One-Time Inspection Program will be implemented Prior to Period LRA Section

as a new program consistent with the recommendations of of Extended B2.1.23

GALL AMP XI.M32, "One-Time Inspection." This program will Operation

include measures to verify the effectiveness of the following

aging management programs: Plant Chemistry Program and

Fuel Oil Chemistry Program. This program will also confirm the

absence of age degradation in selected. components (e.g., flow

restrictors, venturis) within the scope of license renewal.

39 The MNGP Protective Coating Maintenance and Monitoring Prior to Period LRA Section

Program procedures will be updated to include inspection of all of Extended B2.1.27

accessible painted surfaces inside containment. Operation

40 The MNGP Protective Coating Maintenance and Monitoring Prior to Period LRA Section - Program will be revised to include a preinspection review of the of Extended B2.1.27

previous two inspection reports so that trends can be identified. Operation

41 The MNGP Protective Coating Maintenance and Monitoring Prior to Period LRA Section

Program implementation procedures will be revised to include of Extended B2.1.27

provisions for analysis of suspected reasons for coating failure. Operation

42 NMC intends to use the Integrated Surveillance Program for Prior to Period LRA Section

MNGP during the period of extended operation by implementing of Extended B2.1.29

the requirements of BWRVIP-1 16, which is currently being Operation

reviewed by the NRC.

43 NMC will retain the capsules removed from the MNGP reactor Prior to and LRA Section

vessel as part of the Reactor Vessel Surveillance Program. During the B2.1.29

Period of

Extended

Operation

A-10
APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MN4GP

Item No. Commitment Implementation Source

Schedule

44 The MNGP Selective Leaching of Materials Program will be Prior to Period LRA Section

implemented as a new program consistent, with exceptions, to of Extended B2.1.30

the recommendations of GALL AMP XI.M33. The program will Operation

be developed and implemented before the start of the period of

extended operation. The program includes a one-time visual

inspection and hardness measurement of selected components

that are susceptible to selective leaching. In situations in which

hardness testing is not practical, a qualitative method by other

NDE or metallurgical methods will be used to determine the

presence and extent of selective leaching. The

program will determine whether selective leaching is occurring

for selected components.

45 The MNGP Structures Monitoring Program will be expanded, as Prior to Period LRA Section

necessary, to include inspections of structures and structural of Extended B2.1.31

elements within the scope of license renewal that are not Operation

inspected as part of another aging management program.

46 The MNGP Structures Monitoring Program implementing Prior to Period LRA Section

procedures will be enhanced to ensure that structural of Extended B2.1.31

inspections are performed on submerged portions of the intake Operation

structure from the service water bays to the wing walls.

47 The MNGP Structures Monitoring Program implementing Prior to Period LRA Section

procedures will be revised to include the monitoring/inspection of Extended B2.1.31

parameters for structural components within the scope of Operation

license renewal.

48 The MNGP Structures Monitoring Program will be enhanced to Prior to Period LRA Section

include a requirement to sample groundwater for pH, chloride of Extended B2.1.31

concentration, and sulfate concentration. Operation

A-11
APPENDIX A: COMMITMENTS FORý LICENSE RENEWAL OF MNGP!'

Item NO. Commitment Implementation Source

_____ _______"________________________"_________'..... __...... .. Schedule•. 1____________

49 The MNGP Structures Monitoring Program will be enhanced to Prior to Period LRA Section

include concrete evaluations of inaccessible areas if of Extended B2.1.31

degradation of accessible areas is detected. Operation

50 The MNGP Structures Monitoring Program implementing Prior to Period LRA Section

procedures will be enhanced to include acceptance criteria for of Extended B2.1.31

structural inspections of submerged portions of the intake Operation

structure.

51 Implementing instructions and procedures for the System Prior to Period LRA Section

Condition Monitoring Program will be revised to describe of Extended B2.1.32

specific age degradation parameters to be monitored and Operation

inspected. Acceptance criteria will also be included.

52 Requirements for inclusion of NUREG/CR-6260 locations will be Prior to Period LRA Section

incorporated in the implementing procedures for the MNGP of Extended B3.2

Thermal Fatigue Monitoring Program. Operation

53 The NMC fleet procedure for the Flow Accelerated Corrosion Prior to Period LRA Section

Program will be revised to include the accepted 87.5 percent of of Extended B2.1.19

nominal pipe wall thickness for nonsafety-related piping as a Operation

trigger point for engineering analysis.

.54 Prior to the period of extended operation, coating inspectors will Prior to Period LRA Section

meet the requirements of ANSI N45.2.6. of Extended B2.1.27

Operation

55 NMC will implement a new program at MNGP which is Prior to Period Response to

consistent with GALL AMP XI.E6. of Extended followup to RAI

Operation 3.6-2, dated

February 27, 2006

A-12
APPENDIX A:, COMMITMENTS FOR LICENSE, RENEWAL OF MNGP.

Itm:o.Commitment Implementation Source _______:___,• ___ _ _ _ __ _ _ _ _ __ _ _ 'i _ __ _ _ . _ ... _ 1 Schedlule : __ _ _ _ _ _ _

56 NMC has inspected the incore monitoring dry tubes on an During the Period of LRA Section 4.4

every-other refueling outage periodicity and will continue to Extended Operation and B2.1.12

perform this inspection during the period of extended operation,

as recommended by the guidance provided in GE SIL-409.

57 NMC is an active member of the BWRVIP and will continue to During the Period of LRA Section B13.6

follow applicable inspection guidelines and recommendations, Extended Operation and B2.1.12

which have been reviewed and approved by the executive

committee of the BWRVIP, throughout the period of extended

operation.

58 NMC will follow the guidance provided in BWRVIP-139, Steam During the Period of LRA Section

Dryer Inspection and Flaw Evaluation Guidelines (April 2005), Extended Operation 2.1.4.2.2 and

for the MNGP steam dryer inspections. B2. 1.12

59 NMC will add inspection requirements for the P1, P2, and P3 Prior to the Period of LRA Section B13.6

core spray piping welds at MNGP, in accordance with guidance Extended Operation and B2.1.12

provided in BWRVIP-18 or subsequent revisions.

A-13
APPENDIXA: 1COMMITMENTS FOR LICENSE RENEWAL OF 'MNGP_______

Itm ;No-. Commitment' Implementation Source

'Schedulei

60 NMC will adhere to BWRVIP inspection guidelines for core plate, Prior to the Period of LRA Section

holddown bolts by implementation of one or more of the Extended Operation B2.1.12

following:

1. Develop an alternative to the inspections identified in the

BWRVIP which will, at a minimum, satisfy the intent of the

BWRVIP in terms of assuring core plate functional integrity

throughout the period of extended operation. NMC will

provide the alternative to the inspection program to the NRC

staff for their review and approval at least 1 year before

entering the period of extended operation.

2. Inspect the core plate bolts using either UT, some other

volumetric inspections, EVT-1 from below the core plate, or

other approved inspections, in accordance with BWRVIP-25,

to assure an adequate number of core plate bolts are intact

to prevent lateral displacement of the core plate.

3. Install core plate wedges to structurally replace the lateral

load resistance provided by the rim holddown bolts and

perform no inspections.

. A-14
APPENDIX B

CHRONOLOGY

This appendix contains a chronological listing of the routine licensing correspondence between

the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) and the Nuclear

Management Company, LLC (NIMC), and other correspondence regarding the NRC staff's

reviews of the Monticello Nuclear Generating Plant (MNGP) (Docket No. 50-263) license

renewal application (LRA).

March 16, 2005

March 24, 2005

March 31, 2005

April 6, 2005

April 14, 2005

April 25, 2005

May 5, 2005

May 9, 2005

May 9, 2005

Letter from T. Palmisano, NMC, to the NRC Transmitting Application for

Renewed Operating License for the Monticello Nuclear Generating Plant

(ADAMS Accession No. ML050880241)

NRC Press Release-05-053-NRC Announces Availability of License

Renewal Application for Monticello (ADAMS Accession

No. ML050830481)

Letter from P.T. Kuo, NRC, to T. Palmisano, NMC, Acknowledging the

Receipt and Availability of the LRA for MNGP (ADAMS Accession

No. ML050900052)

Notice of April 20, 2005, Meeting for the NRC to Describe the License

Renewal Process (ADAMS Accession No. ML050960308)

NRC Press Release-111-05-01 6-NRC Staff Schedules Public Meeting for

April 20 to Discuss License Renewal Process for Monticello Nuclear

Generating Plant (ADAMS Accession No. ML051040142)

Notice of May 11, 2005, Meeting-Between the NRC and NMC to Discuss

the LRA for MNGP (ADAMS Accession No. ML051150221)

Determination of Acceptability and Sufficiency for Docketing, Proposed

Review Schedule, and Opportunity for a Hearing Regarding the

Application for Renewal of the Operating License for MNGP (ADAMS

Accession No. ML051260029)

Letter from J. Davis, NRC, to M. Askin regarding maintenance of

reference material at the Monticello Public Library for the MNGP LRA

(ADAMS Accession No. 051300167)

Letter from J. Davis, NRC, to A. Wittmann regarding maintenance of

reference material at the Buffalo Public Library for the MNGP LRA

(ADAMS Accession No. 051300195)

B-1
May 12, 2005

May 12, 2005

May 13, 2005

May 18, 2005

May 18, 2005

May 25, 2005

June 2, 2005

June 10, 2005

June 17, 2005

June 21, 2005

July 6, 2005

July 9, 2005

July 12, 2005

NRC Press Release-05-081-NRC Announces Opportunity for Hearing

on Application to Renew Operating License for MNGP (ADAMS

Accession No. ML051320170)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML051330005)

Summary of the Public Information Session Held April 20, 2005, for the

NRC to Describe the License Renewal Process (ADAMS Accession

No. ML051310174)

Summary of Meeting Held May 11, 2005, between the NRC and NMC to

Discuss the MNGP LRA (ADAMS Accession No. ML051400115)

Revision of Schedule for the Review of the MNGP LRA (ADAMS

Accession No. ML051400234)

Notice of June 24, 2005, Exit Meeting for the License Renewal Scoping

and Screening Methodology Audit for the MNGP LRA (ADAMS Accession

No. ML051450575)

NRC Audit and Review Plan for Plant Aging Management Reviews and

Programs for MNGP (ADAMS Accession No. ML051600008)

NMC Response to Request for Additional Information and Submittal of

Additional Information in Support of the Monticello LRA (ADAMS

Accession No. ML051680145).

Summary of Telephone Conference Held on June 9, 2005, between the

NRC and NMC Concerning Draft Requests for Additional Information

Pertaining to the MNGP LRA (ADAMS Accession No. ML051680443)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML051720593)

Summary of Meeting Held June 24, 2005, between the NRC and NMC to

Discuss the Results of the Scoping and Screening Methodology Audit for

the MNGP LRA (ADAMS Accession No. ML051880402)

Request for a Hearing and Petition for Leave to Intervene by the North

American Water Office (ADAMS Accession No. ML052280043)

Revision of Schedule for the Review of the MNGP LRA (ADAMS

Accession No. ML051950002)

B-2
July 13, 2005

July 13, 2005

July 18, 2005

July 20, 2005

July 21, 2005

July 28, 2005

July 28, 2005

August 3, 2005

August 3, 2005

August 3, 2005

August 8, 2005

August 9, 2005

August 11,2005

August 11,2005

Notice of August 18, 2005, Exit Meeting With NMC on License Renewal

Audits of Aging Management Programs and Reviews for MNGP (ADAMS

Accession No. ML051940509)

Summary of Telephone Conference Held on July 6, 2005, between the

NRC and NMC Concerning Draft Requests for Additional Information

Pertaining to the MNGP LRA (ADAMS Accession No. ML051950060)

Audit Trip Report Regarding the NMC Application for License Renewal

for MNGP (ADAMS Accession No. ML051990091)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052020005)

NMC Response to Request for Additional Information Regarding the

Monticello LRA (ADAMS Accession No. ML052080040)

Summary of Telephone Conference Held on July 14, 2005, between the

NRC and NMC Concerning Draft Requests for Additional Information

Pertaining to the MNGP LRA (ADAMS Accession No. ML052100060)

Summary of Public Scoping Meetings to Support Review of the MNGP

LRA (ADAMS Accession No. ML052110002)

NRC Staff Answer to Petition to Intervene and Request for Hearing of the

North American Water Office (ADAMS Accession No. ML052200245)

Notice of Appearance of David R. Lewis on Behalf of NMC (ADAMS Accession No. ML052280129)

NMC Answer to Request for Hearing and Petition to Intervene by the

North American Water Office (ADAMS Accession No. ML052280136)

Memorandum of the Secretary referring the Petition for Leave to

Intervene Submitted by the North American Water Office (ADAMS

Accession No. ML052270368)

Reply Comment of the North American Water Office (ADAMS Accession

No. ML052300291)

Summary of Telephone Conference Held on August 4, 2005, between the

NRC and NMC Concerning Information Pertaining to the MNGP LRA

(ADAMS Accession No. ML052230323)

NMC Responses to Aging Management Program and .Aging

Management Review Audits for the Monticello LRA (ADAMS Accession

No. ML052280269)

B-3
August 12, 2005

August 16, 2005

August 18, 2005

August 18, 2005

August 18, 2005

August 19, 2005

August 29, 2005

August 31, 2005

August 31, 2005

September 6, 2005

September 15, 2005

September 16, 2005

September 16, 2005

September 26, 2005

Establishment of Atomic Safety and Licensing Board (ADAMS Accession

No. ML052270406)

NMC Response to Request for Additional Information Regarding the

Monticello LRA (ADAMS Accession No. ML0523405110)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML0523110013)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052310044)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052310055)

NRC Staff Motion to Strike Comment of the North American Water Office

(ADAMS Accession No. ML0523110573)

Reply of North American Water Office to the NRC Staff Motion to Strike

Comment of the North American Water Office (ADAMS Accession

No. ML052500328)

Summary of Telephone Conference Held on August 15, 2005, between

the NRC and NMC Concerning Information Pertaining to the MNGP LRA

(ADAMS Accession No. ML052430782)

NMC Additional Information in Response to Aging Management Program

and Aging Management Review Audits of the Monticello LRA (ADAMS

Accession No. ML052500294)

Summary of Meeting Held August 18, 2005, between the NRC and NMC

to Discuss the Results for Aging Management Programs and Reviews for

the MNGP LRA (ADAMS Accession No. ML052520251)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052620622)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052620609)

NMC Response to Three Requests for Additional Information Regarding

the Monticello LRA (ADAMS Accession No. ML052630320)

Docketing of Additional Information Pertaining to the LRA for MNGP

(ADAMS Accession No. ML052700535)

B-4
September 27, 2005 Summary of Telephone Conference Held on September 1, 2005,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML052700456)

September 27, 2005 Summary of Telephone Conference Held on September 7, 2005,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML052700227)

September 28, 2005 NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML052730175)

October 11, 2005 Letter from G. Crocker to Administrative Judge McDade discussing

incompleteness of the MNGP LRA (ADAMS Accession

No. ML052930174)

October 12, 2005 Audit and Review Report for Plant Aging Management Reviews and

Programs for Monticello Nuclear Generating Plant (ADAMS Accession

No. ML052850461)

October 14, 2005 NMC Response to Two Requests for Additional Information Regarding

the MNGP LRA (ADAMS Accession No. ML052910370)

October 17, 2005 NRC Staff Answer to the Motion of the North American Water Office to

Find the License Renewal Application for the MNGP Incomplete (ADAMS

Accession No. ML052900401)

October 17, 2005 NMC Response to North American Water Office's Motion to Find the

Application Incomplete (ADAMS Accession No. ML052970399)

October 21, 2005 Summary of Telephone Conference Held on October 6, 2005, between

the NRC and NMC Concerning Information Pertaining to the MNGP LRA

(ADAMS Accession No. ML052970210)

October 28, 2005 NMC Response to Requests for Additional Information Regarding the

MNGP LRA (ADAMS Accession No. ML053070217)

October 31, 2005 NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML053050436)

November 1, 2005 Memorandum and Order, Ruling on Standing and Contention

Admissibility (ADAMS Accession No. ML053050414)

November 2, 2005 Summary of Telephone Conference Call Held on October 11, 2005,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML0530701112)

B-5
November 7, 2005

November 8, 2005

November 14, 2005

November 16, 2005

November 17, 2005

November 18, 2005

November 22, 2005

November 22, 2005

December 7, 2005

December 16, 2005

January 10, 2006

January 30, 2006

January 30, 2006

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML053120003)

Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding Public

Availability of Audit and Review Report (ADAMS Accession

No. ML053140265)

NRC Request for Additional Information for the Review of the MNGP LRA

(ADAMS Accession No. ML053190429)

Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding Public

Availability of Audit Report for Scoping and Screening Methodology

(ADAMS Accession No. ML053220358)

NMC Supplement to Responses for Requests for Additional Information

Regarding the MNGP LRA (ADAMS Accession No. ML053250099)

Summary of Telephone Conference Call Held on November 9, 2005,

between NRC and NMC Concerning Information Pertaining to the MNGP

LRA (ADAMS Accession No. ML053250489)

Summary of Telephone Conference Held on November 15, 2005,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML053290157)

NMC Response to Two Requests for Additional Information Regarding

the MNGP LRA (ADAMS Accession No. ML053340269)

NMC Response to Request for Additional Information Regarding the

MNGP LRA (ADAMS Accession No. ML053460242)

NMC Supplement to Responses to Requests for Additional Information

Regarding the MNGP LRA (ADAMS Accession No. ML053550250)

Summary of Telephone Conference Call Held on December 21, 2005,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML060130004)

Summary of Telephone Conference Call Held on January 9, 2006,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML060310635)

Summary of Telephone Conference Call Held on January 12, 2006,

between the NRC and NMC Concerning Information Pertaining to the

MNGP LRA (ADAMS Accession No. ML060340200)

B-6
February 8, 2006

February 27, 2006

February 28, 2006

March 15, 2006

March 30, 2006

March 31, 2006

April 10, 2006

April 26, 2006

June 15, 2006

June 23, 2006

July 24, 2006

July 28, 2006

August 18, 2006

September 19, 2006

Meeting Notice Regarding Public Exit Meeting to Discuss the Results of

the License Renewal Inspections for the Review of the MNGP LRA

(ADAMS Accession No. ML060390125)

NMC Supplement to Responses to Requests for Additional Information

Regarding the MNGP LRA (ADAMS Accession No. ML060610583)

Confirmatory Items Response Regarding the MNGP LRA (ADAMS

Accession No. ML060620056)

NMC License Renewal Application Annual Update Letter (ADAMS

Accession No. ML060800360)

NRC License Renewal Scoping, Screening, and Aging Management

Inspection Report (ADAMS Accession No. ML060940194)

NMC Supplemental Information and Response to Requests for Additional

Information Regarding the MNGP LRA (ADAMS Accession

No. ML060940124)

NMC Supplemental Information Regarding the MNGP LRA (ADAMS

Accession No. ML061030406)

NRC Letter to NMC Transmitting the Safety Evaluation Report Related to

the License Renewal of MNGP (ADAMS Accession No. ML061'170035)

NMC Comments Regarding the Safety Evaluation Report for the MNGP

License Renewal Application (ADAMS Accession No. ML061710264)

NMC Supplemental Information Regarding the MNGP LRA (ADAMS

Accession No. ML061780532)

Memorandum from Regional Administrator, NRC Region III, to J. Dyer,

Director, Office of Nuclear Reactor Regulation regarding the MNGP

License Renewal Application (ADAMS Accession No. ML062140148)

NRC Letter to NMC Transmitting the Safety Evaluation Report for the

MNGP License Renewal Application (ADAMS Accession No.

ML061800030)

NMC Letter to NRC regarding MNGP License Renewal Application

Update (ADAMS Accession No. ML062370318)

ACRS Report on the Safety Aspects of the License Renewal Application

for the Monticello Nuclear Generating Plant (ADAMS Accession No.

ML062690249)

B-7

APPENDIX C

PRINCIPAL CONTRIBUTORS

NAME

F. Akstulewicz

H. Ashar

W. Bateman

B. Boger

E. Brown

T. Chan

K. Chang

0. Chopra

G. Cranston

R. Dennig

N. Dudley

B. Elliot

J. Fair

T. Ford

G. Galletti

G. Georgiev

F. Gillespie

R. Goel

V. Goel

J. Grobe

M. Hartzman

R. Hernandez

A. Hodgdon

N. Iqbal

R. Jenkins

S. Jones

R. Karas

K. Kavanagh

J. Knox

P. Kuo

C. Lauron

S. Lee

C. Li

Y. Li

M. Lintz

P. Lougheed

L. Lund

J. Lyons

RESPONSIBILITY

Management Oversight

Structural Engineering

Management Oversight

Management Oversight

Management Oversight

Management Oversight

GALL Audit and Review

Electrical Engineering

GALL Audit and Review

Management Oversight

GALL Audit.and Review

Material Engineering

Mechanical Engineering

Reactor Systems

Quality Assurance

Mechanical Engineering

Management Oversight

Mechanical Engineering

Electrical Engineering

.Management Oversight

Mechanical Engineering

Plant Systems

Legal Counsel

Fire Protection

Management Oversight

Management Oversight

Management Oversight

Quality Assurance

Electrical Engineering

Management Oversight

Material Engineering

Management Oversight

Plant Systems

Mechanical Engineering

GALL Audit and Review

Region III Inspection

Management Oversight

Management Oversight

C-1
J. Ma

K. Manoly

T. Martin

D. Matthews

M. Mayfield

R. McNally

D. Merzke

M. Mitchell

J.. Rajan

J. Raval

B. Rogers

J. Rowley

D. Shum

D. Solario

J. Strnisha

D. Thatcher

S. Tingen

M. Tschiltz

S. Weerakkody

P. Wen

G. Wilson

R. Wolfgang

M. Woods

M. Yoder

J. Zimmerman

Mechanical Engineering

Management Oversight

Management Oversight

Management Oversight

Management Oversight

Mechanical Engineering

Lead Project Manager

Management Oversight

Mechanical Engineering

Mechanical Engineering

Quality Assurance

Project Management

Plant Systems

Management Oversight

Mechanical Engineering

Management Oversight

Quality Assurance

Management Oversight

Management Oversight

GALL Audit and Review

Management Oversight

Fire Protection

Legal Counsel

Material Engineering

Management Oversight

CONTRACTORS

TECHNICAL AREA

SER Support

GALL Audit and Report

Plant Systems

CONTRACTOR

Legin Group, Inc.

Advanced Technologies and

Laboratories International, Inc.

Pacific Northwest National

Laboratory

C-2.
APPENDIX D

REFERENCES

This appendix contains a listing of the references used in the preparation of the Safety

Evaluation Report developed during the review of the license renewal application for Monticello

Nuclear Generating Plant (MNGP), Docket Number 50-263.

Boiling Water Reactor Vessel and Internals Project (BWRVIP)

BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals

Examination Guidelines."

BWRVIP-1 8, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines."

BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."

BWRVIP-26, "BWR Top Guide Inspection and Flaw Evaluation Guidelines."

BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core

Plate DP Inspection and Flaw Evaluation Guidelines."

BWRVIP-29, "BWR Water Chemistry Guidelines-1 993 Revision," EPRI Topical Report,

TR-1 03515.

BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines."

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

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

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

Report TR-1 08724.

BWRVIP-49, "BWR Instrument Penetration Inspection and Flaw Evaluation Guidelines."

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

License Renewal."

BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan."

BWRVIP-86, "BWR Vessel and Internals Project: BWR Integrated Surveillance Program (ISP)

Implementation."

BWRVIP-130, "BWR Water Chemistry Guidelines-2004 Revision," EPRI Topical Report,

TR-1 008192.

Code of Federal Regulations

Title 10; Part 50, "Domestic Licensing of Production and Utilization Facilities," of the Code of

Federal Regulations.

Title 10, Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel

Processing Plants,"of the Code of Federal Regulations.

Title 10, Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements," of

the Code of Federal Regulations.

D-1
Title 10, Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled

Power Reactors," of the Code of Federal Regulations.

Title 10, Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating

Prior to January 1, 1979," of the Code of Federal Regulations.

Title 10, Part 51, "Environmental Protectioin Regulations for Domestic Licensing and Related

Regulatory Functions," of the Code of Federal Regulations.

Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants,"

of the Code of Federal Regulations.

Title 10, Part 100, "Reactor Site Criteria," of the Code of Federal Regulations.

Electric Power Research Institute (EPRI)

EPRI NP-5067, Volumes 1 and 2, "Good Bolting Practices."

EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants."

EPRI Report 1002950, Revision 1, "Aging Effects for Structures and Structural Components

(Structural Tools)," May 2003.

EPRI Report 1003056, Revision 3, "Non-Class 1 Mechanical Implementation Guideline and

Mechanical Tools."

EPRI Report 1007933, "Aging Assessment Field Guide," December 2003.

EPRI Report 1008035, Revision 1, "Expansion Joint Maintenance Guide," May 2003.

EPRI Topical Report, TR-1007820, "Closed Cooling Water Chemistry Guideline."

EPRI Topical Report, TR-1 03595, "Report of the Instrument Air Working Group."

EPRI TR-104213, "Bolted Joint Maintenance & Application Guide."

EPRI Topical Report, TR-1 08147, "Compressor and Instrument Air System Maintenance

Guide," March 1998.

EPRI Topical Report, TR-1 12657, Revision B-A, "Revised Risk Informed In-Service Inspection

Evaluation Procedure."

NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program,"

.Electric Power Research Institute.

(

Miscellaneous

American Concrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety Related

Concrete Structures."

American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Section

Xl, Subsection IWB, IWC, and IWD.

ASME, Boiler and Pressure Vessel Code, Section XI, Subsection IWE.

ASME, Boiler and Pressure Vessel Code, Section Xl, Subsection IWF.

ASME, Boiler and Pressure Vessel Code, Section XI, Subsection NF.

American Society for Testing and Materials (ASTM) D 6217, 'Test Method for Particulate

Contamination in Middle Distillate Fuels by Laboratory Filtration."

D-2
American National Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3,

"Quality Standard for Instrument Air."

ANSI/ISA Z86.1-1973, "Commodity Specification for Air and Drager Operating Instruction."

ANSI N45*2.6, "Qualification of Inspection, Examination, and Testing Personnel for the

Construction Phase of Nuclear Power Plants."

ANSI N45.2.9, "Requirements for Collection, Storage, and Maintenance of Quality Assurance

Records for Nuclear Power Plants," 1974.

ASTM D 5163-96, "Standard Guide for Establishing Procedures To Monitor the Performance of

Safety Related Coatings in an Operating Nuclear Power Plant."

Audit and Review Plan for Plant Aging Management Reviews and Programs for Monticello

Nuclear Generating Plant, June 2, 2005.

Audit and Review Report for Plant Aging Management Reviews and Programs for Monticello

Nuclear Generating Plant, October 12, 2005.

Fire Protection Safety Evaluation Report, August 29, 1979.

J.P. Foster, "Analysis of In-reactor Stress Relaxation Using Irradiation Creep Models," ASTM

STP61 1, Irradiation Effects on the Microstructure and Properties of Metals, 1976.

General Electric Document SASR 89-77, "Accumulated Fatigue Usage for the Monticello

Nuclear Generating Station Reactor Pressure."

General Electric Service Information Letter (SIL)-409, "Incore Dry Tube Cracks"

General Electric Topical Report, GE-NE-523-A71-0594,.Revision 1, "Alternate BWR Feedwater

Nozzle Inspection Requirements."

General Electric Topical Report NEDC-32983P, "General Electric (GE) Methodology for

Reactor Pressure Vessel Fast Neutron Flux Evaluation."

Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Risk Informed In-Service

Inspection Program (TAC NO. MB3819)," July 24, 2002.

Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Fourth 10-Year In-Service

Inspection Interval Request for Relief No. 4 (TAC No. MC2222)," January 6, 2005.

Letter from NRC to Nuclear Energy Institute and Union of Concerned Scientists, "Standardized

Format for License Renewal Applications (MB7344)," April 7, 2003.

"Metals Handbook," Ninth Edition, American Society for Metals International.

Monticello Nuclear Generating Plant Updated Safety Analysis Report (USAR), Revision 21.

NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis for Low Upper

Shelf Energy in BWR/2-6 Vessels," February 1994.

NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50,

Appendix J," March 1996.

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

License Renewal Rule," Revision 3, March 2001.

NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness of

Maintenance at Nuclear Power Plants," April 1996.

D-3
SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-Electrical

Cable and Terminations," Sandia National Laboratories, September 1996.

NRC Generic Communications

NRC GL 80-95, "Generic Activity A-10," November 13, 1980.

NRC GL 81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking

(NUREG-0619)," February 29, 1981.

NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping,"

January 25, 1988.

NRC GL 88-14, "Instrument Air Supply System Problems Affecting Safety Equipment,"

August 8, 1988.

NRC Generic Letter (GL) 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," May 2,1989.

NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment,"

July 18,1989.

NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System (ECCS) and

the Containment Spray System after a Loss-of-Cooling Accident because of Construction and

Protective Coating Deficiencies and Foreign Material in Containment," July 14, 1998.

NRC GL 98-05, "Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to Request

Relief from Augmented Inspection."

NRC IN 81-38, "Potentially Significant Equipment Failures Resulting from Contamination of

Air-Operated Systems," December 17, 1981.

NRC IN 87-28, "Air System Problems at U.S. Light Water Reactors," June 22, 1987.

NRC IN 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response

to IE Bulletin 80-11," December 31, 1987.

NRC Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-Related

ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor," June 12,

2001.

NRC Regulatory Guides

NRC RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with Nuclear

Power Plants," March 1978.

NRC RG 1.147, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section XI,

Division 1," January 2004.

NRC RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power

Plants," March 1997.

NRC RG 1.163, "Performance-Based Containment Leak-Test Program," September 1995.

NRC RG 1.174, Revision 1, "An Approach'for Using Probabilistic Risk Assessment in

Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," November 2002.

NRC RG 1.178, Revision 1, "An Approach for Plant-Specific Risk-Informed Decision-Making for

In-Service Inspection of Piping," September 2003.

NRC RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel

Neutron Fluence," March 2001.

NRC RG 1.54, "Service Level 1, 11, and III Protective Coatings Applied to Nuclear Power Plants,"

June 1973.

NRC RG 1.65, "Materials and Inspections for Reactor Vessel Closure Studs," October 1973.

NRC RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," May 1988.

NUREG Series Reports

D-4
NUREG-0313, 'Technical Report on Material Selection and Processing Guidelines for BWR

Coolant Pressure Boundary Piping," Revision 2, January 1988.

NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking:

Resolution of Generic Technical Activity A-10," November 1980.

NUREG-0661, "Safety Evaluation Report, Mark I Containment Long Term Program, Resolution

of Generic Technical Activity A-7," July 1980.

NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in

Nuclear Power Plants."

NUREG-1344, "Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power

Plants," 1989.

NUREG-1743, "Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear

One, Unit 1," April 2001.

NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants," April 2001.

NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," July 2001.

NUREG/CR-5643, "Insights Gained from Aging Research," March 1992.

NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves of

Austenitic Stainless Steels," April 1999.

NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for Selected

Nuclear Power Plant Components."

NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon

and Low-Alloy Steels," February 1998.

D-5

NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-2004) (Assigned by NRC, Add Vol., Supp., Rev.,

NRCMD 3.7 and Addendum Numbers, IH any.)

BIBLIOGRAPHIC DATA SHEET

(See istructions on the reverse) NUREG-1865

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

.Safety Evaluation Report Related to the License Renewal of the Monticello Nuclear Generating MONTH YEAR

Plant October 2006

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Daniel J. Merzke

7. PERIOD COVERED (Inclusive Dates)

03/24/2005-09129/2006

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 License Renewal

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (it NRC, type 'Same as above'; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission,

and mailing address.)

Same as above*

10. SUPPLEMENTARY NOTES

Docket No. 50-263

11. ABSTRACT (200 words or less)

This safety evaluation report documents the technical review of the Monticello Nuclear Generating Plant (MNGP) license

renewal application (LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC). By letter dated March 16, 2005,

Nuclear Management Company, LLC (NMC or the applicant), submitted the LRA for MNGP in accordance with Title 10, Part 54,

of the Code of Federal Regulations (10 CFR Part 54). NMC is requesting renewal of the operating license for MNGP (Facility

Operating License Number DPR-22) for a period of 20 years beyond the current expiration date of midnight, September 8,

2010.

MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issued the construction permit for

MNGP on June 19, 1967. The NRC issued the operating license for MNGP on January 9, 1981. MNGP is a single-cycle,

General Electric BWR-3, a boiling-water reactor producing steam for direct use in a steam turbine. MNGP operates at a

licensed power output of 1775 megawatts thermal, with a gross electrical output of approximately 600 megawatts electric.

The staff reviewed the MNGP LRA in accordance with Commission regulations and NUREG-1800, "Standard Review Plan for

Review of License Renewal Applications for Nuclear Power Plants," dated July 2001. Section 6 of this SER provides the staff's

conclusion of its review of the MNGP LRA.

1 2 . KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT

10 CFR Part 54, license renewal, Monticello, scoping and screening, aging management, time-limited unlimited

aging analysis, safety evaluation report 14. SECURITY CLASSIFICATION

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC ORM 351-200) PINTE ON ECYLED APE NRIC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
Federal Recycling Program