II

NUREG-1787

Safety Evaluation Report

Related to the License Renewal of

the Virgil C. Summer Nuclear Station

Docket No. 50-395

South Carolina Electric & Gas Company

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Washington, DC 20555-0001 .s ,A
NUREG-1787

Safety Evaluation Report

Related to the License Renewal of

the Virgil C. Summer Nuclear Station

Docket No. 50-395

South Carolina Electric & Gas Company

Manuscript Completed: March 2004

Date Published: March 2004

Prepared by

R. Auluck

Division of Regulatory Improvement Programs

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
-iiiABSTRACT

This safety evaluation report (SER) documents the technical review of the Virgil C. Summer

Nuclear Station (VCSNS), license renewal application (LRA) by the U.S. Nuclear Regulatory

Commission staff. By letter dated August 6, 2002, South Carolina Electric & Gas Company

(SCE&G or the applicant) submitted the LRA for VCSNS in accordance with Title 10 of the

Code of Federal Regulations, Part 54 (10 CFR Part 54 or the Rule). SCE&G is requesting

renewal of the operating license for VCSNS (License No. NPF-12) for a period of 20 years

beyond the current license expiration of midnight, August 6, 2022. 

The VCSNS plant is located in Fairfield County, in predominantly rural north-central South

Carolina. It is situated on the shore of the Monticello Reservoir about 42 kilometers (26 miles)

northwest of Columbia, the State capital. The VCSNS unit consists of a Westinghouse

pressurized-water reactor with nuclear steam supply system designed to operate at core power

levels up to 2900 megawatts-thermal, or approximately 966 megawatts-electric. Details

concerning the plant and the site are found in the Updated Final Safety Analysis Report

(UFSAR) for VCSNS.

This staff reviewed the VCSNS license renewal application in accordance with Commission

regulations and NUREG-1800, “Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants,” dated July 2001. The staff’s conclusion of its review of

the VCSNS LRA can be found in Section 6 of this SER.

The NRC VCSNS license renewal project manager is Rajender Auluck. Dr. Auluck may be

reached at (301)415-1025. Written correspondence should be addressed to the License

Renewal and Environmental Impacts Program, U.S. Nuclear Regulatory Commission,

Washington, DC 20555-0001, Attention: Rajender Auluck, Mail Stop O-11F1.
-ivTHIS PAGE IS INTENTIONALLY LEFT BLANK
-vTABLE OF CONTENTS

ABSTRACT .............................................................. -iiiTABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -vABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -xxiii1 INTRODUCTION AND GENERAL DISCUSSION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1

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

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

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

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

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

1.3.1 Westinghouse Topical Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-6

1.4 Interim Staff Guidance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-7

1.5 Summary of Open Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9

1.6 Summary of Confirmatory Items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9

1.7 Summary of Proposed License Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9

2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING STRUCTURES AND

COMPONENTS SUBJECT TO AGING MANAGEMENT REVIEW, AND

IMPLEMENTATION RESULTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1

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

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

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

2.1.2.1 Scoping Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2

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

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3

2.1.2.1.2 Documentation Sources Used for Scoping and

Screening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-4

2.1.2.1.3 Plant and System Level Scoping . . . . . . . . . . . . . . . 2-5

2.1.2.1.4 Component Level Scoping . . . . . . . . . . . . . . . . . . . 2-6

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

2.1.2.2.1 Mechanical Component Screening . . . . . . . . . . . . . 2-8

2.1.2.2.2 Structures Component Screening . . . . . . . . . . . . . . 2-9

2.1.2.2.3 Electrical and Instrumentation and Control Component

Screening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-10

2.1.2.2.4 Commodity Groups Screening . . . . . . . . . . . . . . . 2-11

2.1.3 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-11

2.1.3.1 Evaluation Methodology for Identifying Systems, Structures, and

Components Within the Scope of License Renewal . . . . . . . 2-12

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

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-13

2.1.3.1.2 Plant Level Scoping of Systems and Structures . . 2-17

2.1.3.1.3 System Level Scoping . . . . . . . . . . . . . . . . . . . . . . 2-18
-vi2.1.3.2 Evaluation Methodology for Identifying Structures and

Components Subject to an Aging Management Review . . . 2-20

2.1.3.2.1 Mechanical Component Screening . . . . . . . . . . . . 2-21

2.1.3.2.2 Structural Component Screening . . . . . . . . . . . . . 2-22

2.1.3.2.3 Electrical and Instrumentation and Control Component

Screening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-22

2.1.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-23

2.1.5 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-23

2.2 Plant Level Scoping Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-26

2.2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-26

2.2.2 Summary of Technical Information in the Application . . . . . . . . . . . . . 2-26

2.2.2.1 Systems, Structures, and Components Within the Scope of

License Renewal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-27

2.2.2.2 Systems and Structures Not Within the Scope of License

Renewal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-27

2.2.3 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-27

2.2.4 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-30

2.2.5 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-30

2.3 Scoping and Screening Results: Mechanical Systems . . . . . . . . . . . . . . . . . . 2-30

2.3.1 Reactor Vessel, Internals and Reactor Coolant System . . . . . . . . . . . 2-30

2.3.1.1 Reactor Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-31

2.3.1.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-31

2.3.1.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-32

2.3.1.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-33

2.3.1.2 Piping, Valves and Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . 2-33

2.3.1.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-33

2.3.1.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-34

2.3.1.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-35

2.3.1.3 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-35

2.3.1.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-35

2.3.1.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-35

2.3.1.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-36

2.3.1.4 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-36

2.3.1.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-37

2.3.1.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-38

2.3.1.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-38

2.3.1.5 Incore Instrumentation System . . . . . . . . . . . . . . . . . . . . . . 2-39

2.3.1.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-39

2.3.1.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-39

2.3.1.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-40

2.3.1.6 Pressurizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-40

2.3.1.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-40

2.3.1.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-41
-vii2.3.1.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-43

2.3.1.7 Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-43

2.3.1.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-43

2.3.1.7.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-43

2.3.1.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-44

2.3.2 Engineered Safety Features Systems . . . . . . . . . . . . . . . . . . . . . . . . 2-44

2.3.2.1 Chemical and Volume Control . . . . . . . . . . . . . . . . . . . . . . . 2-44

2.3.2.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-45

2.3.2.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-46

2.3.2.2 Containment Isolation System . . . . . . . . . . . . . . . . . . . . . . . 2-46

2.3.2.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-46

2.3.2.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-47

2.3.2.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-47

2.3.2.3 Hydrogen Removal — Post Accident System . . . . . . . . . . . 2-47

2.3.2.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-47

2.3.2.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-48

2.3.2.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-48

2.3.2.4 Reactor Building Spray System . . . . . . . . . . . . . . . . . . . . . . 2-48

2.3.2.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-48

2.3.2.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-49

2.3.2.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-49

2.3.2.5 Refueling Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-49

2.3.2.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-49

2.3.2.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-50

2.3.2.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-50

2.3.2.6 Residual Heat Removal System . . . . . . . . . . . . . . . . . . . . . 2-50

2.3.2.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-50

2.3.2.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-51

2.3.2.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-51

2.3.2.7 Safety Injection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-52

2.3.2.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-52

2.3.2.7.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-53

2.3.2.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-54

2.3.3 Auxiliary Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-54

2.3.3.1 Air Handling and Local Ventilation and Cooling Systems . . . 2-54

2.3.3.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-54

2.3.3.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-64

2.3.3.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-76

2.3.3.2 Boron Recycle System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-76
-viii2.3.3.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-76

2.3.3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-77

2.3.3.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-78

2.3.3.3 Building Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-78

2.3.3.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-78

2.3.3.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-78

2.3.3.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-79

2.3.3.4 Chilled Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-79

2.3.3.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-79

2.3.3.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-79

2.3.3.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-80

2.3.3.5 Circulating Water System . . . . . . . . . . . . . . . . . . . . . . . . . . 2-80

2.3.3.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-80

2.3.3.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-80

2.3.3.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-81

2.3.3.6 Component Cooling Water System . . . . . . . . . . . . . . . . . . . 2-81

2.3.3.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-81

2.3.3.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-82

2.3.3.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-82

2.3.3.7 Diesel Generator Services Systems . . . . . . . . . . . . . . . . . . 2-82

2.3.3.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-83

2.3.3.7.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-85

2.3.3.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-86

2.3.3.8 Fire Service System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-86

2.3.3.8.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-86

2.3.3.8.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-88

2.3.3.8.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-92

2.3.3.9 Fuel Handling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-92

2.3.3.9.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-92

2.3.3.9.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-92

2.3.3.9.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-93

2.3.3.10 Gaseous Waste Processing System . . . . . . . . . . . . . . . . . 2-93

2.3.3.10.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-93

2.3.3.10.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-94

2.3.3.10.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-95

2.3.3.11 Industrial Cooler System . . . . . . . . . . . . . . . . . . . . . . . . . . 2-95

2.3.3.11.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-95

2.3.3.11.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-95

2.3.3.11.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-96
-ix2.3.3.12 Instrument Air Supply System . . . . . . . . . . . . . . . . . . . . . . 2-96

2.3.3.12.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-96

2.3.3.12.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-96

2.3.3.12.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-98

2.3.3.13 Leak Detection System . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-98

2.3.3.13.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-98

2.3.3.13.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-99

2.3.3.13.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-99

2.3.3.14 Liquid Waste Processing System . . . . . . . . . . . . . . . . . . . 2-99

2.3.3.14.1 Summary of Technical Information in the Application

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

2.3.3.14.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-100

2.3.3.14.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-100

2.3.3.15 Nuclear and Non-nuclear Plant Drains . . . . . . . . . . . . . . . 2-101

2.3.3.15.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-101

2.3.3.15.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-101

2.3.3.15.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-101

2.3.3.16 Nuclear Sampling System . . . . . . . . . . . . . . . . . . . . . . . . 2-102

2.3.3.16.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-102

2.3.3.16.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-102

2.3.3.16.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-102

2.3.3.17 Radiation Monitoring System . . . . . . . . . . . . . . . . . . . . . . 2-103

2.3.3.17.1 Summary of Technical Information in the Application

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

2.3.3.17.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-103

2.3.3.17.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-104

2.3.3.18 Reactor Makeup Water Supply System . . . . . . . . . . . . . . 2-105

2.3.3.18.1 Summary of Technical Information in the Application

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

2.3.3.18.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-105

2.3.3.18.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-106

2.3.3.19 Roof Drains System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-106

2.3.3.19.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-106

2.3.3.19.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-106

2.3.3.19.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-107

2.3.3.20 Station Service Air System . . . . . . . . . . . . . . . . . . . . . . . 2-107

2.3.3.20.1 Technical Information in the Application . . . . . . 2-107

2.3.3.20.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-107

2.3.3.20.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-108

2.3.3.21 Service Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-108

2.3.3.21.1 Summary of Technical Information in the Application

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

2.3.3.21.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-108

2.3.3.21.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-109
-x2.3.3.22 Spent Fuel Cooling System . . . . . . . . . . . . . . . . . . . . . . . 2-110

2.3.3.22.1 Summary of Technical Information in the Application

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

2.3.3.22.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-110

2.3.3.22.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-110

2.3.3.23 Thermal Regeneration System . . . . . . . . . . . . . . . . . . . . 2-110

2.3.3.23.1 Summary of Technical Information in the Application

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

2.3.3.23.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-111

2.3.3.23.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-112

2.3.4 Steam and Power Conversion Systems . . . . . . . . . . . . . . . . . . . . . . 2-112

2.3.4.1 Auxiliary Boiler Steam and Feedwater System . . . . . . . . . 2-112

2.3.4.1.1 Summary of Technical Information in the Application

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

2.3.4.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-112

2.3.4.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-113

2.3.4.2 Condensate System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-113

2.3.4.2.1 Summary of Technical Information in the Application

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

2.3.4.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-113

2.3.4.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-114

2.3.4.3 Emergency Feedwater System

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-114

2.3.4.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-115

2.3.4.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-115

2.3.4.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-116

2.3.4.4 Extraction Steam System . . . . . . . . . . . . . . . . . . . . . . . . . 2-116

2.3.4.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-116

2.3.4.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-116

2.3.4.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-116

2.3.4.5 Feedwater System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-117

2.3.4.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-117

2.3.4.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-117

2.3.4.6 Gland Sealing Steam System . . . . . . . . . . . . . . . . . . . . . . 2-117

2.3.4.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-117

2.3.4.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-118

2.3.4.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-118

2.3.4.7 Main Steam System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-119

2.3.4.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-119

2.3.4.7.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-119

2.3.4.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-120

2.3.4.8 Main Steam Dump System . . . . . . . . . . . . . . . . . . . . . . . . 2-120

2.3.4.8.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-120
-xi2.3.4.8.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-120

2.3.4.8.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-121

2.3.4.9 Main Turbine and Turbine Accessories Systems . . . . . . . . 2-121

2.3.4.9.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-121

2.3.4.9.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-121

2.3.4.9.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-122

2.3.4.10 Turbine Cycle Sampling System . . . . . . . . . . . . . . . . . . . 2-122

2.3.4.10.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-122

2.3.4.10.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-122

2.3.4.10.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-122

2.3.4.11 Steam Generator Blowdown System . . . . . . . . . . . . . . . . 2-123

2.3.4.11.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-123

2.3.4.11.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-123

2.3.4.11.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-123

2.3.4.12 Turbine Electro-Hydraulic System . . . . . . . . . . . . . . . . . . 2-124

2.3.4.12.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-124

2.3.4.12.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . 2-124

2.3.4.12.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-124

2.3.5 Criterion 2 Supplement to the License Renewal Application . . . . . . 2-125

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

2.3.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-125

2.3.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-130

2.3.5.4 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-130

2.4 Scoping and Screening Results: Structures . . . . . . . . . . . . . . . . . . . . . . . . . . 2-130

2.4.1 Reactor Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-131

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

2.4.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-133

2.4.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-136

2.4.2 Other Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-136

2.4.2.1 Auxiliary Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-137

2.4.2.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-137

2.4.2.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-138

2.4.2.1.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-140

2.4.2.2 Control Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-140

2.4.2.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-140

2.4.2.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-141

2.4.2.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-142

2.4.2.3 Diesel Generator Building . . . . . . . . . . . . . . . . . . . . . . . . . 2-142

2.4.2.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-142

2.4.2.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-143

2.4.2.3.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-143

2.4.2.4 Fuel Handling Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-143
-xii2.4.2.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-144

2.4.2.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-144

2.4.2.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-145

2.4.2.5 Intermediate Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-145

2.4.2.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-145

2.4.2.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-146

2.4.2.5.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147

2.4.2.6 Turbine Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147

2.4.2.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-147

2.4.2.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-148

2.4.2.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-148

2.4.2.7 Service Water Pumphouse, Intake, and Discharge Structures

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-149

2.4.2.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-149

2.4.2.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-151

2.4.2.8 Yard Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-151

2.4.2.8.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-151

2.4.2.8.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . 2-154

2.4.2.8.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-155

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-156

2.5.1 Summary of Technical Information in the Application . . . . . . . . . . . . 2-156

2.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-156

2.5.2.1 Identification of Passive Components . . . . . . . . . . . . . . . . 2-156

2.5.2.2 Identification of Components that are Passive but Not Long-Lived

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-158

2.5.2.3 Identification of Components Not Within the Scope of License

Renewal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-158

2.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-160

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

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

3.0.1 The GALL Format for the License Renewal Application . . . . . . . . . . . . 3-2

3.0.2 The Staff’s Review Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-3

3.0.3 Common Aging Management Programs . . . . . . . . . . . . . . . . . . . . . . . 3-4

3.0.3.1 Boric Acid Corrosion Surveillances Program . . . . . . . . . . . . . 3-5

3.0.3.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-5

3.0.3.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-6

3.0.3.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-9

3.0.3.2 Chemistry Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10

3.0.3.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10

3.0.3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10
-xiii3.0.3.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15

3.0.3.3 Fire Protection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15

3.0.3.3.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-15

3.0.3.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-17

3.0.3.3.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-20

3.0.3.4 Maintenance Rule Structures Program . . . . . . . . . . . . . . . . 3-21

3.0.3.4.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-21

3.0.3.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-22

3.0.3.4.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-23

3.0.3.5 Above Ground Tank Inspection Program . . . . . . . . . . . . . . . 3-24

3.0.3.5.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-24

3.0.3.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-25

3.0.3.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28

3.0.3.6 Buried Piping and Tanks Inspection Program . . . . . . . . . . . . 3-28

3.0.3.6.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-28

3.0.3.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-29

3.0.3.6.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-31

3.0.3.7 Inspections for Mechanical Components . . . . . . . . . . . . . . . 3-32

3.0.3.7.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-32

3.0.3.7.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-32

3.0.3.7.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-40

3.0.3.8 Heat Exchanger Inspections . . . . . . . . . . . . . . . . . . . . . . . . 3-41

3.0.3.8.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-41

3.0.3.8.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-41

3.0.3.8.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-45

3.0.3.9 Area-Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-46

3.0.3.9.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-46

3.0.3.9.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-46

3.0.3.9.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-48

3.0.4 VCSNS Quality Assurance Program . . . . . . . . . . . . . . . . . . . . . . . . . 3-49

3.0.4.1 Summary of Technical Information in Application . . . . . . . . 3-49

3.0.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-49

3.0.4.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-50

3.0.5 Aging Management Review of Systems, Structures, and Components

Under Refined Criterion 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-50

3.0.5.1 Summary of Technical Information in the Application . . . . . 3-50

3.0.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-52

3.0.5.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-57

3.0.6 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-57
-xiv3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-57

3.1.1 Summary of Technical Information in the Application . . . . . . . . . . . . . 3-58

3.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-59

3.1.2.1 Aging Management Evaluations in the GALL Report that are

Relied on for License Renewal, that Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-64

3.1.2.2 Aging Management Evaluations in the Gall Report That Are

Relied on for License Renewal, for Which Gall Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-65

3.1.2.2.1 Cumulative Fatigue Damage . . . . . . . . . . . . . . . . . 3-65

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-65

3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation

Embrittlement (TLAA) . . . . . . . . . . . . . . . . . . . . . . . . 3-66

3.1.2.2.5 Loss of Fracture Toughness Due to Neutron Irradiation

Embrittlement and Void Swelling . . . . . . . . . . . . . . . 3-67

3.1.2.2.6 Crack Initiation and Growth Due to Stress-Corrosion

Cracking, Intergranular Stress Corrosion Cracking, and

Thermal and Mechanical Loading . . . . . . . . . . . . . . . 3-68

3.1.2.2.7 Crack Growth Due to Cyclic Loading . . . . . . . . . . . 3-69

3.1.2.2.8 Changes in Dimension Due to Void Swelling . . . . 3-70

3.1.2.2.9 Crack Initiation and Growth Due to Stress Corrosion

Cracking and/or Primary Water Stress-Corrosion

Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-71

3.1.2.2.10 Crack Initiation and Growth Due to Stress Corrosion

Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-72

3.1.2.2.11 Crack Initiation and Growth Due to Primary Water

Stress-Crossion Cracking . . . . . . . . . . . . . . . . . . . . . 3-73

3.1.2.2.12 Crack Initiation and Growth Due to Stress-Corrosion

Cracking and Irradiation- Assisted Stress-Corrosion

Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-73

3.1.2.2.13 Loss of Preload Due to Stress Relaxation . . . . . . 3-74

3.1.2.2.14 Loss of Section Thickness Due to Erosion . . . . . 3-75

3.1.2.2.15 Crack Initiation and Growth Due to Primary Water

Stress-Corrosion Cracking, Outside Diameter Stress

Corrosion Cracking and/or Intergranular Attack; Loss of

Material Due to Wastage and Pitting Corrosion and

Fretting and Wear; or Deformation Due to Corrosion at

Tube Support Plate Intersections . . . . . . . . . . . . . . . 3-75

3.1.2.3 Aging Management Programs for Reactor Vessel, Internals, and

Reactor Coolant System Components . . . . . . . . . . . . . . . . . 3-77

3.1.2.3.1 Alloy 600 Aging Management Program . . . . . . . . . 3-78

3.1.2.3.2 Bottom-Mounted Instrumentation Inspection Program

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-81

3.1.2.3.3 In-Service Inspection Plan (ISI) . . . . . . . . . . . . . . . 3-83

3.1.2.3.4 Reactor Head Closure Studs Program . . . . . . . . . 3-85

3.1.2.3.5 Steam Generator Management Program . . . . . . . 3-86
-xv3.1.2.3.6 Reactor Vessel Surveillance Program . . . . . . . . . . 3-88

3.1.2.3.7 Reactor Vessel Internals Inspection Program . . . . 3-90

3.1.2.3.8 Small Bore Class 1 Piping Inspection . . . . . . . . . . . 3-92

3.1.2.4 Aging Management Review of Plant-Specific Reactor Vessel,

Internals, and Reactor Coolant Components. . . . . . . . . . . . . 3-94

3.1.2.4.1 Reactor Coolant System . . . . . . . . . . . . . . . . . . . . 3-95

3.1.2.4.2 Reactor Coolant Piping, Valves, and Pumps . . . . . 3-99

3.1.2.4.3 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . 3-106

3.1.2.4.4 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . 3-114

3.1.2.4.5 In-Core Instrumentation System . . . . . . . . . . . . . 3-120

3.1.2.4.6 Pressurizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-126

3.1.2.4.7 Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . 3-134

3.2 Engineered Safety Features Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-145

3.2.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-146

3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-146

3.2.2.1 Aging Management Evaluations in the GALL Report That Are

Relied On for License Renewal, That Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-148

3.2.2.2 Aging Management Evaluations in the GALL Report That Are

Relied on for License Renewal, For Which GALL Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-149

3.2.2.2.1 Cumulative Fatigue Damage . . . . . . . . . . . . . . . . 3-149

3.2.2.2.2 Loss of Material Due to General Corrosion . . . . . 3-149

3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice

Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-150

3.2.2.2.4 Local Loss of Material Due to Microbiologically

Influenced Corrosion . . . . . . . . . . . . . . . . . . . . . . . . 3-151

3.2.2.3 Aging Management Programs for Engineered Safety Features

Systems Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-153

3.2.2.4 Aging Management Review of Plant-Specific Engineered Safety

Features Systems Components . . . . . . . . . . . . . . . . . . . . . 3-153

3.2.2.4.1 Chemical and Volume Control System . . . . . . . . 3-154

3.2.2.4.2 Containment Isolation System . . . . . . . . . . . . . . . 3-159

3.2.2.4.3 Hydrogen Removal — Post Accident System . . . 3-161

3.2.2.4.4 Reactor Building Spray System . . . . . . . . . . . . . . 3-163

3.2.2.4.5 Refueling Water System . . . . . . . . . . . . . . . . . . . 3-165

3.2.2.4.6 Residual Heat Removal System . . . . . . . . . . . . . 3-167

3.2.2.4.7 Safety Injection System . . . . . . . . . . . . . . . . . . . . 3-169

3.3 Aging Management of Auxiliary Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-171

3.3.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-172

3.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-172

3.3.2.1 Aging Management Evaluations in the GALL Report That Are

Relied On for License Renewal, That Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-178

3.3.2.2 Aging Management Evaluations in the GALL Report That Are

Relied On for License Renewal, For Which GALL Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-178

3.3.2.2.1 Loss of Material Due to General, Pitting, and Crevice

Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-178
-xvi3.3.2.2.2 Hardening and Cracking or Loss of Strength Due to

Elastomer Degradation or Loss of Material Due to

Wear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-179

3.3.2.2.3 Cumulative Fatigue Damage . . . . . . . . . . . . . . . . 3-180

3.3.2.2.4 Crack Initiation and Growth Due to Cracking or StressCorrosion Cracking . . . . . . . . . . . . . . . . . . . . . . . . . 3-180

3.3.2.2.5 Loss of Material Due to General, Microbiologically

Influenced, Pitting, and Crevice Corrosion . . . . . . . . 3-180

3.3.2.2.6 Loss of Material Due to General, Galvanic, Pitting, and

Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . 3-181

3.3.2.2.7 Loss of Material Due to General, Pitting, Crevice, and

Microbiologically Influenced Corrosion and Biofouling

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-182

3.3.2.2.8 Crack Initiation and Growth Due to Stress-Corrosion

Cracking and Cyclic Loading . . . . . . . . . . . . . . . . . . 3-183

3.3.2.2.9 Reduction of Neutron-Absorbing Capacity and Loss of

Material Due to General Corrosion . . . . . . . . . . . . . 3-183

3.3.2.2.10 Loss of Material Due to General, Pitting, Crevice, and

Microbiologically Influenced Corrosion . . . . . . . . . . 3-184

3.3.2.3 Aging Management Programs for Auxiliary Systems Components

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-184

3.3.2.3.1 Service Water System Reliability and In-Service Testing

Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-185

3.3.2.3.2 Material Handling System Inspection Program . . 3-187

3.3.2.3.3 Preventive Maintenance Activities—Ventilation Systems

Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-190

3.3.2.3.4 Diesel Generator Systems Inspection Program . . 3-194

3.3.2.3.5 Liquid Waste System Inspection Program . . . . . 3-197

3.3.2.3.6 Reactor Building Cooling Unit Inspection Program

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-200

3.3.2.3.7 Service Air System Inspection Program . . . . . . . 3-204

3.3.2.3.8 Waste Gas System Inspection Program . . . . . . . 3-208

3.3.2.4 Aging Management Review of Plant-Specific Auxiliary Systems

Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-211

3.3.2.4.1 Air Handling And Local Ventilation and Cooling Systems

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

3.3.2.4.2 Boron Recycle System . . . . . . . . . . . . . . . . . . . . 3-215

3.3.2.4.3 Building Services System . . . . . . . . . . . . . . . . . . 3-217

3.3.2.4.4 Chilled Water System . . . . . . . . . . . . . . . . . . . . . 3-219

3.3.2.4.5 Circulating Water System . . . . . . . . . . . . . . . . . . 3-223

3.3.2.4.6 Component Cooling Water System . . . . . . . . . . . 3-224

3.3.2.4.7 Diesel Generator Service Systems . . . . . . . . . . . 3-229

3.3.2.4.8 Fire Service System . . . . . . . . . . . . . . . . . . . . . . 3-236

3.3.2.4.9 Fuel Handling System . . . . . . . . . . . . . . . . . . . . . 3-238

3.3.2.4.10 Gaseous Waste Processing System . . . . . . . . . 3-239

3.3.2.4.11 Industrial Cooler System . . . . . . . . . . . . . . . . . . 3-242

3.3.2.4.12 Instrument Air Supply System . . . . . . . . . . . . . . 3-242

3.3.2.4.13 Leak Detection System . . . . . . . . . . . . . . . . . . . 3-245

3.3.2.4.14 Liquid Waste Processing System . . . . . . . . . . . 3-245
-xvii3.3.2.4.15 Nuclear and Nonnuclear Plant Drains System . . 3-249

3.3.2.4.16 Nuclear Sampling System . . . . . . . . . . . . . . . . . 3-251

3.3.2.4.17 Radiation Monitoring System . . . . . . . . . . . . . . 3-256

3.3.2.4.18 Reactor Makeup Water Supply System . . . . . . . 3-259

3.3.2.4.19 Roof Drains System . . . . . . . . . . . . . . . . . . . . . 3-262

3.3.2.4.20 Station Service Air System . . . . . . . . . . . . . . . . 3-264

3.3.2.4.21 Service Water System . . . . . . . . . . . . . . . . . . . 3-267

3.3.2.4.22 Spent Fuel Cooling System . . . . . . . . . . . . . . . . 3-273

3.3.2.4.23 Thermal Regeneration System . . . . . . . . . . . . . 3-276

3.3.2.5 General AMR Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-279

3.3.2.5.1 Plant Specific Environment Characteristics . . . . . 3-279

3.3.2.5.2 Carbon Steel Components in Sheltered Environment

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-281

3.3.2.5.3 Stainless Steel Components in Sheltered Environment

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-283

3.4 Steam and Power Conversion Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-284

3.4.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-285

3.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-285

3.4.2.1 Aging Management Evaluations in the GALL Report That Are

Relied On For License Renewal, Which Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-288

3.4.2.2 Aging Management Evaluations in the GALL Report That Are

Relied On For License Renewal, For Which GALL Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-289

3.4.2.2.1 Cumulative Fatigue Damage . . . . . . . . . . . . . . . . 3-289

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice

Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-290

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice

Corrosion, Microbiologically Influenced Corrosion, and

Biofouling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-292

3.4.2.2.4 Loss of Material Due to General Corrosion . . . . . 3-293

3.4.2.2.5 Loss of Material Due to General, Pitting, and Crevice

Corrosion and Microbiologically Influenced Corrosion

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-294

3.4.2.3 Aging Management Programs for Steam and Power Conversion

Systems Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-295

3.4.2.3.1 Flow-Accelerated Corrosion Monitoring Program

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-296

3.4.2.3.2 Preventive Maintenance Activities — Terry Turbine

Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-300

3.4.2.4 Aging Management Review of Plant-Specific Steam and Power

Conversion Systems Components . . . . . . . . . . . . . . . . . . . 3-303

3.4.2.4.1 Auxiliary Boiler Steam and Feedwater System . . 3-303

3.4.2.4.2 Condensate System . . . . . . . . . . . . . . . . . . . . . . 3-305

3.4.2.4.3 Emergency Feedwater System . . . . . . . . . . . . . . 3-308

3.4.2.4.4 Extraction Steam System . . . . . . . . . . . . . . . . . . 3-311

3.4.2.4.5 Feedwater System . . . . . . . . . . . . . . . . . . . . . . . 3-314

3.4.2.4.6 Gland Sealing Steam System . . . . . . . . . . . . . . . 3-316

3.4.2.4.7 Main Steam System . . . . . . . . . . . . . . . . . . . . . . 3-318
-xviii3.4.2.4.8 Main Steam Dump System . . . . . . . . . . . . . . . . . 3-320

3.4.2.4.9 Main Turbine and Turbine Accessories Systems

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-322

3.4.2.4.10 Turbine Cycle Sampling System . . . . . . . . . . . . 3-323

3.4.2.4.11 Steam Generator Blowdown System . . . . . . . . . 3-325

3.4.2.4.12 Electro-Hydraulic Control System . . . . . . . . . . . 3-327

3.4.2.4.13 Generic RAI Issues . . . . . . . . . . . . . . . . . . . . . . 3-328

3.5 Containment, Structures, and Component Supports . . . . . . . . . . . . . . . . . . . . 3-330

3.5.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-330

3.5.1.1 Description of Containment, Structures, and Component

Supports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-330

3.5.1.2 Aging Management Review Methodology . . . . . . . . . . . . . 3-331

3.5.1.3 Operating Experience Review . . . . . . . . . . . . . . . . . . . . . . 3-332

3.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-332

3.5.2.1 Aging Management Evaluations in the GALL Report That Are

Relied On For License Renewal, Which Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-340

3.5.2.2 Aging Management Evaluations in the GALL Report That Are

Relied On For License Renewal, For Which GALL Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-341

3.5.2.2.1 Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-341

3.5.2.2.2 Class I Structures . . . . . . . . . . . . . . . . . . . . . . . . 3-352

3.5.2.2.3 Component Supports . . . . . . . . . . . . . . . . . . . . . 3-354

3.5.2.3 Aging Management Programs for Containment, Structures, and

Component Supports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-355

3.5.2.3.1 10 CFR Part 50 Appendix J General Visual Inspection

Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-356

3.5.2.3.2 10 CFR Part 50 Appendix J Leak Rate Testing Program

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-357

3.5.2.3.3 ASME Section XI ISI Program — IWF (B.1.13) . . 3-360

3.5.2.3.4 Battery Rack Inspection Program . . . . . . . . . . . . 3-363

3.5.2.3.5 Containment Coating Monitoring and Maintenance

Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-365

3.5.2.3.6 Containment Inservice Inspection Program — IWE/IWL

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-368

3.5.2.3.7 Flood Barrier Inspection Program . . . . . . . . . . . . 3-370

3.5.2.3.8 Pressure Door Inspection Program . . . . . . . . . . . 3-373

3.5.2.3.9 Service Water Pond Dam Inspection Program . . 3-376

3.5.2.3.10 Service Water Structures Survey Monitoring Program

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-379

3.5.2.3.11 Underwater Inspection Program (SWIS and SWPH)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-383

3.5.2.3.12 Tendon Surveillance Program . . . . . . . . . . . . . . 3-386

3.5.2.4 Aging Management Review of Plant-Specific Structures and

Structural Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-389

3.5.2.4.1 Reactor Building (Structure and Foundation,

Containment Liner, Penetrations) . . . . . . . . . . . . . . 3-389

3.5.2.4.2 Other Building Structures (Auxiliary Building, Control

Building, Diesel Generator Building, Fuel Handling
-xixBuilding, Intermediate Building, Turbine Building,

Containment Internal Structures) . . . . . . . . . . . . . . . 3-397

3.5.2.4.3 Service Water Pump House, Intake and Discharge

Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-406

3.5.2.4.4 Yard Structures (Condensate Storage Tank Foundation,

Fire Service Pumphouse, Electrical Manhole MH-2,

Electrical Substation and Transformer Area) . . . . . . 3-408

3.5.2.4.5 Earthen Embankments . . . . . . . . . . . . . . . . . . . . 3-410

3.6 Electrical and Instrumentation and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . 3-412

3.6.1 Summary of Technical Information in the Application . . . . . . . . . . . . 3-412

3.6.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-413

3.6.2.1 Aging Management Evaluation in the GALL Report That Are

Relied On for License Renewal, That Do Not Require Further

Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-415

3.6.2.2 Aging Management Evaluations in the GALL Report That Are

Relied On For License Renewal, For Which GALL Recommends

Further Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-415

3.6.2.2.1 Electrical Equipment Subject to Environmental

Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-416

3.6.2.3 Aging Management Programs for Electrical and Instrumentation

and Controls Components . . . . . . . . . . . . . . . . . . . . . . . . . 3-416

3.6.2.3.1 Electrical Cables and Connections Not Subject to 10

CFR 50.49 Environmental Qualification Requirements

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-416

3.6.2.3.2 Electrical Cables and Connections Not Subject to 10

CFR50.49 Environmental Qualification Requirement Used

in Instrumentation Circuits . . . . . . . . . . . . . . . . . . . . 3-422

3.6.2.3.3 Inaccessible Medium-Voltage Cables Not Subject to 10

CFR 50.49 Environmental Qualification Requirements

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-426

3.6.2.4 Aging Management Review of Plant-Specific Electrical

Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-429

3.6.2.4.1 Non-EQ Electrical Penetration Assemblies . . . . . 3-429

3.6.2.4.2 High Voltage Electrical Switchyard Bus . . . . . . . . 3-432

3.6.2.4.3 High Voltage Transmission Conductors and

Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-433

3.6.2.4.4 High Voltage Insulators . . . . . . . . . . . . . . . . . . . . 3-436

3.6.3 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-439

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 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3

4.2 Reactor Vessel Neutron Embrittlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3

4.2.1 Upper Shelf Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3

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

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

4.2.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-6
-xx4.2.2 Pressurized Thermal Shock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-6

4.2.2.1 Summary of Technical Information in the Application . . . . . . 4-6

4.2.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-7

4.2.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-8

4.2.3 Pressure-Temperature Limits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9

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

4.2.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9

4.2.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-10

4.3 Metal Fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11

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

4.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-11

4.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-16

4.4 Environmental Qualification of Electrical Equipment . . . . . . . . . . . . . . . . . . . . . 4-17

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

4.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-21

4.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-23

4.5 Concrete Containment Tendon Prestress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-23

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

4.5.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-24

4.5.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-25

4.6 Containment (Reactor Building) Liner Plate, Metal Containment, and 

Penetration Fatigue Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-25

4.6.1 Containment (reactor building) Liner . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.6.1.1 Summary of Technical Information in the Application . . . . . 4-26

4.6.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.6.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.6.2 Metal Containments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-26

4.6.3 Containment (Reactor Building) Isolation . . . . . . . . . . . . . . . . . . . . . . 4-26

4.6.3.1 Containment (Reactor Building) Isolation Bellows . . . . . . . . 4-27

4.6.3.1.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-27

4.6.3.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-27

4.6.3.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28

4.6.3.2 Containment (Reactor Building) Isolation - Fracture Toughness

and Effects of Radiation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28

4.6.3.2.1 Summary of Technical Information in the Application

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28

4.6.3.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28

4.6.3.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-28

4.7 Other Plant-Specific Time-Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . 4-29

4.7.1 Reactor Coolant Pump Flywheel . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-29

4.7.1.1 Summary of Technical Information in the Application . . . . . 4-29

4.7.1.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-29

4.7.1.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31

4.7.2 Leak-Before-Break Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31

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

4.7.2.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-31

4.7.2.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-32

4.7.3 Crane Load Cycle Limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-33
-xxi4.7.3.1 Summary of Technical Information in The Application . . . . . 4-33

4.7.3.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-34

4.7.3.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-35

4.7.4 Service Water Intake Structure Settlement . . . . . . . . . . . . . . . . . . . . 4-35

4.7.4.1 Summary of Technical Information in the Application . . . . . 4-35

4.7.4.2 Staff Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-36

4.7.4.3 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-36

4.8 Conclusion for Time-Limited Aging Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . 4-36

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

6 CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1

APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL . . . . . . . . . . . . . . . . . . . . . . . . . A-1

APPENDIX B: CHRONOLOGY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

APPENDIX C: REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

APPENDIX D: PRINCIPAL CONTRIBUTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1
-xxiiTHIS PAGE IS INTENTIONALLY LEFT BLANK
-xxiiiABBREVIATIONS

AC auxiliary coolant

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ACSR aluminum conductor steel reinforced

AFW auxiliary feedwater

AISC American Institute of Steel Construction

AMP aging management program

AMR aging management review

ANS American Nuclear Society

ANSI American National Standards Institute

APCSB auxiliary and power conversion systems branch

ARAVS auxiliary and radwaste area ventilation system

ART adjusted reference temperature

AS auxiliary system

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWSanticipated transient without scram

AVB antivibration bar

AWWA American Water Works Association

BMI bottom-mounted instrumentation

BS building services

BSS building services system

BTP branch technical position

BTRS (boron) thermal regeneration system

B&W Babcock and Wilcox Co.

BWR boiling-water reactor

CASS cast austenitic stainless steel

CBAVS control building area ventilation systems

CC component cooling

CCW component cooling water

CCWS component cooling water system

CER condition evaluation report

CFR Code of Federal Regulations

CHAMPS component history and maintenance planning system

CLB current licensing basis

CRD control rod drive

CRDMcontrol rod drive mechanism

CREP control room evacuation panels

CS carbon steel

CUF cumulative usage factor
-xxivCVCS chemical and volume control system

CW circulating water

DBD design basis document

DBE design basis event

DN demineralized water - nuclear services

DOJ U.S. Department of Justice

DW demineralized water

ECCS emergency core cooling system

ECT eddy current testing

EDG emergency diesel generator

EFPY effective full power year

EOF emergency offsite facility

EOL end of life

EPR ethylene propylene rubber

EPRI Electric Power Research Institute

EQ environmental qualification 

EQDB equipment qualification database

ES engineering services

ESF engineered safety features

FAC flow-accelerated corrosion

FERC Federal Energy Regulatory Commission 

FHA fire hazard analysis

FHBV fuel handling building ventilation

FMP fatigue monitoring program

FO fuel oil handling

FP fire protection

FPP fire protection program

FRP fiberglass reinforced plastic

FSAR final safety analysis report

FSER final safety evaluation report

GALL generic aging lessons learned 

GDC general design criterion

GEIS generic environmental impact statement

GL generic letter

gpm gallons per minute

GSI generic safety issue

GSSS gland sealing steam system

GWPS gaseous waste processing system

HAZ heat-affected zone

HEI heat exchanger inspections
-xxvHELB high energy line break

HEPA high efficiency particulate air

HMWPE high molecular weight polyethylene

HN hydrogen-nuclear plant use

HV high voltage

HVAC heating, ventilation, and air conditioning

IBVS intermediate building ventilation systems

IA instrument air 

IASCC irradiation-assisted stress corrosion cracking

I&C instrumentation and controls

ID inside diameter

IEB Inspection and Enforcement Bulletin

IEEE Institute of Electrical and Electronics Engineers

IGA intergranular attack

IGSCC intergranular stress corrosion cracking

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

IR insulation resistance

ISG Interim staff guidance

ISI inservice inspection

ITG issues task group or Industry 

LBB leak before break

LOCA loss-of-coolant accident

LR reactor building leak rate testing

LR license renewal

LRA license renewal application

LOTP low-temperature overpressure protection

LTOPS low temperature overpressure protection system

LW liquid effluent from nuclear plant to pent stock

LWPS liquid waste procession system

MBVCS miscellaneous building ventilation and cooling systems

MCC motor control center

MIC microbiologically induced or influenced corrosion

mm millimeter

MOS2 molybdenum disulfide

MRP Materials Reliability Project

MS main steam

MSIP mechanical stress improvement process

MSIV main steam isolation valve

MT magnetic particle technique

MWe megawatt-electric
-xxviNB nuclear blowdown processing

NCN nonconformance notice

ND nuclear plants drains

NDE nondestructive examination

NDT nil ductility temperature

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NG nitrogen blanketing

NN nitrogen-nuclear plant use

NPS nominal pipe size

NRC Nuclear Regulatory Commission

NSSS nuclear steam supply system

OBE operating-basis earthquake

ODSCC outer diameter stress corrosion cracking 

ON oxygen-nuclear plant use

P&ID piping and instrumentation diagram

PORV power operated relief valve

PTS pressurized thermal shock

P-T pressure-temperature

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance 

RAI request for additional information

RBCFS reactor building cooling and filtering systems

RBCU reactor building cooling units

RC reactor coolant 

RCCA rod cluster control assembly

RCDT reactor coolant drain tank

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RF refueling outage

RG regulatory guide

RHR residual heat removal

RPV reactor pressure vessel

RTPTS reference temperature for pressurized thermal shock

RTNDT reference nil ductility transition temperature

RV reactor vessel

RVI reactor vessel internals

RVID Reactor Vessel Integrity Database
-xxviiRW raw water

RWST refueling water storage tank

SA service air

SAS safety assessment system

SBO station blackout

SC structure and component

SCC stress corrosion cracking

SCE&G South Carolina Electric and Gas Company

SE sewer or safety evaluation

SER safety evaluation report

SG steam generator

SI safety injection

SMP structures monitoring program

SOC Statements of Consideration

SPC steam and power conversion

SPCS steam and power conversion systems

SRP Standard Review Plan

SRP-LR Standard Review Plan — License Renewal

SS stainless steel

SSC structure system and component

SSE safe shutdown earthquake

SW service water

SWIS service water intake structure

SWPH service water pump/house

TDR time domain reflectometry

TFMP Thermal Fatigue Management Program

TLAA time-limited aging analysis

TR topical or technical report

TS technical specification

UFSAR updated final safety analysis report

USE upper shelf energy

USI unresolved safety issue

UT ultrasonic testing

UV ultraviolet

VCSNS Virgil C. Summer Nuclear Station

VT visual test

WCAP Westinghouse Commercial Atomic Power 

WD radwaste solidification and solids handling

WE waste evaporation

WG waste gas
-xxviiiWL liquid waste processing

WOG Westinghouse Owner’s Group

WPAA west penetration access area

WX excess liquid waste

XLPE cross-linked polyethylene
1-1

1 INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a safety evaluation report (SER) on the application to renew the operating

license for the Virgil C. Summer Nuclear Station (VCSNS) as filed by the South Carolina

Electric and Gas Company (SCE&G or the applicant). By letter dated August 6, 2002, SCE&G

submitted its application to the U.S. Nuclear Regulatory Commission (NRC or the Agency) for

renewal of the VCSNS operating license for up to an additional 20 years. The NRC staff (the

staff) reviewed the VCSNS license renewal application (LRA) for compliance with the

requirements of Title 10 of the Code of Federal Regulations, Part 54 (10 CFR Part 54),

“Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” and prepared this

report to document the results of its safety review. The NRC license renewal project manager

for the V.C. Summer safety review is Rajender Auluck. Dr. Auluck may be contacted by

telephone at (301) 415-1025 or by electronic mail at rca@nrc.gov. Alternatively, written

correspondence may be sent to the following address:

License Renewal and Environmental Impacts Program

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: Dr. Rajender Auluck, P.E., Mail Stop O-11F1

In its August 6, 2002, submittal letter, the applicant requested renewal of the operating license

issued under Section 104b of the Atomic Energy Act of 1954, as amended, for VCSNS (License

No. NPF-12) for a period of 20 years beyond the current license expiration of midnight, August

6, 2022. The VCSNS Summer plant is located in Fairfield County, in predominantly rural northcentral South Carolina. It is situated on the shore of Monticello Reservoir about 42 kilometers

(26 miles) northwest of Columbia, the State Capital. The VCSNS unit consists of a

Westinghouse pressurized-water reactor with nuclear steam supply systems designed to

operate at core power levels up to 2900 megawatts-thermal, or approximately 966 megawattselectric. Details concerning the plant and the site are found in the updated final safety analysis

Report (UFSAR) for VCSNS.

The license renewal process proceeds along two tracks, the first of which is a technical review

of safety issues and the second, an environmental review. The requirements for these two

reviews are stated in 10 CFR Parts 54 and 51, respectively. The safety review is based on the

VCSNS LRA and on the applicant's answers to requests for additional information (RAIs) from

the NRC staff. In meetings and docketed correspondence, SCE&G has also supplemented its

answers to the RAIs. Unless otherwise noted, the staff reviewed and considered information

submitted through November 5, 2003. The public may review the LRA and all pertinent

information and material, including the UFSAR, at the NRC Public Document Room, 11555

Rockville Pike, Rockville, MD 20852-2738. In addition, the VCSNS LRA and significant

information and material related to the license renewal review are available on the NRC’s web

page at www.nrc.gov.

This SER summarizes the findings of the staff's safety review of the VCSNS LRA and describes

the technical details considered in evaluating the safety aspects of the proposed operation of

the plant for up to an additional 20 years beyond the term of the current operating license. The
1-2

staff reviewed the LRA in accordance with NRC regulations and the guidance presented in the

NRC's, “Standard Review Plan for the Review of License Renewal Applications for Nuclear

Power Plants (SRP-LR),” which was issued as NUREG-1800 in July 2001.

Sections 2 through 4 of the SER document the staff's evaluation of license renewal issues that

have been considered during the review of the LRA. Section 5 is reserved for the report of the

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

Section 6.

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

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

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

Appendix C is a bibliography of the references used during the course of the review. The NRC

staff principal reviewers and its contractors for the SER are listed in Appendix D. 

In accordance with 10 CFR Part 51, the staff is required to prepare a draft for comment and a

final plant-specific supplement to the generic environmental impact statement (GEIS). The

supplement discusses the environmental considerations related to renewing the license for

VCSNS. The draft plant-specific supplement to the GEIS was issued separately from this

report. Specifically, NUREG-1437, Supplement 15, “Generic Environmental Impact Statement

for License Renewal of Nuclear Plant Regarding Virgil C. Summer Nuclear Station,” issued July

11, 2003, and is the draft environmental impact statement for VCSNS.

1.2 License Renewal Background

 

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

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

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

basis of economic and antitrust considerations, 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 that 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 extending the life of 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 NRC participated

in an industry-sponsored demonstration program to apply the rule to a pilot plant and to develop

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

renewal, the rule defined age-related degradation unique to license renewal. However, during

the demonstration program, the NRC found that many aging mechanisms occur and are

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

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

implementation of the maintenance rule, which also manages plant aging phenomena.
1-3

As a result, in 1995, the NRC amended the license renewal rule. The amended 10 CFR Part

54 establishes a regulatory process that is simpler, more stable, and more predictable than the

previous license renewal rule. In particular, 10 CFR Part 54 was amended to focus on

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

unique to license renewal. The rule changes were intended 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 integrated plant assessment (IPA) process was

clarified and simplified to be consistent with the revised focus on passive, long-lived structures

and components (SCs).

In parallel with these efforts, the NRC pursued a separate rulemaking effort to amend 

10 CFR Part 51 to focus the scope of the review of the environmental impacts of license

renewal and to fulfill, in part, the NRC’s responsibilities under the National Environmental Policy

Act of 1969 (NEPA).

1.2.1 Safety Reviews

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

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

operating plants provides and maintains an acceptable level of safety, with the possible

exception of the detrimental effects of aging on the functionality of certain SSCs during 

the period of extended operation, as well as a few other issues related to safety during

the period of extended operation.

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

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

In implementing these two principles, the rule in 10 CFR 54.4 (the Rule) defines the scope of

license renewal as including those plant SSCs (1) that are safety-related, (2) whose failure

could affect safety-related 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 transients without scram (ATWS), and station blackout (SBO).

Pursuant to 10 CFR 54.21(a), the 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). SCs that are subject to an AMR are those that perform an intended function without

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

replacement based on a 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 the SCs that are within the scope of

license renewal will be maintained, consistent with the current licensing basis (CLB), for the

period of extended operation. Active equipment, however, is considered to be adequately

monitored and maintained by existing programs. In other words, the detrimental effects of

aging that may affect active equipment are more readily detectable and will be identified and

corrected through routine surveillance, performance monitoring, and maintenance activities. 

The surveillance and maintenance programs for active equipment, as well as other aspects of
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maintaining the plant design and licensing basis, are required to continue throughout the period

of extended operation.

Pursuant to 10 CFR 54.21(d), each LRA is required to include a supplement to the Final Safety

Analysis Report (FSAR). This FSAR supplement must contain a summary description of the

applicant’s programs and activities for managing the effects of aging.

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

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

the length of time the plant will be operated. These assumptions are incorporated into the

design calculations for several of the plant's SSCs. In accordance with 10 CFR 54.21(c)(1),

these calculations must be shown to be valid for the period of extended operation or the must

be projected to the end of the period of extended operation, or the applicant must demonstrate

that the effects of aging on these SSCs will be adequately managed for the period of extended

operation.

In 2001, the NRC developed and issued Regulatory Guide 1.188, Standard Format and

Content for Applications to Renew Nuclear Power Plant Operating Licenses.” This guide

endorses an implementation guideline prepared by the Nuclear Energy Institute (NEI) as an

acceptable method of implementing the license renewal rule. NEI 95-10, Revision 3, Industry

Guideline for Implementing the Requirements of 10 CFR Part 54—The License Renewal Rule,”

was issued in March 2001. The NRC also prepared the SRP-LR which was used to review this

application. 

SCE&G is the fourth license renewal applicant to fully utilize the process defined in NUREG1801, “Generic Aging Lessons Learned (GALL) Report,” dated July 2001. The purpose of

GALL is to provide the staff with a summary of staff-approved aging management programs

(AMPs) for the aging of most 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 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 structures and

components 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 will provide adequate aging management during the period of extended operation. 

1.2.2 Environmental Reviews

In December 1996, the staff revised the environmental protection regulations in 10 CFR Part 51

to facilitate environmental reviews for license renewal. The staff prepared a “Generic

Environmental Impact Statement (GEIS) for License Renewal of Nuclear Plants”

(NUREG-1437, Revision 1) to document its evaluation of the possible environmental impacts

associated with renewing licenses of nuclear power plants. For certain types of environmental

impacts, the GEIS establishes generic findings that are applicable to all nuclear power plants. 

These generic findings are identified as Category 1 issues in 10 CFR Part 51, Subpart A,

Appendix B. Pursuant to 10 CFR 51.53(c)(3)(i), an applicant for license renewal may

incorporate these generic findings in its environmental report. Analyses of environmental

impacts of license renewal that must be evaluated on a plant-specific basis, Category 2 issues,
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are required to be included in an environmental report in accordance with 10 CFR

51.53(c)(3)(ii).

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

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

new and significant information exist that was not considered in the GEIS. A public meeting

was held on December 11, 2002, at VCSNS as part of the NRC’s scoping process to identify

environmental issues specific to the plant. The results of the environmental review and a

preliminary recommendation on the license renewal action were documented in NRC draft

plant-specific Supplement 15 to the VCSNS GEIS, which was issued on July 11, 2003, for

VCSNS. After consideration of comments on the draft, the NRC will prepare and publish a final

plant-specific supplement to the GEIS. 

1.3 Principal Review Matters

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

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

with Commission guidance and the requirements of 10 CFR Part 54. The standards for

renewing a license are contained in 10 CFR 54.29. This SER describes the results of the staff’s

safety review.

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

information. The applicant provided this general information in Chapter 1 of its LRA for

VCSNS, submitted by letter dated August 6, 2002. The staff finds that the applicant has

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

In 10 CFR 54.19(b), the Commission requires that 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 Section 1.3.8 of its LRA

regarding this issue: 

The current indemnity agreement (No. B-86) for VCSNS states in Article VII that the agreement shall terminates

at the time of expiration of the license specified in Item 3 of the Attachment to the agreement, which is the last

to expire. Item 3 of the Attachment to the indemnity agreement, as revised by Amendment No. 2 lists two

license numbers (SNM-1834 and NPF-12). SCE&G requests that conforming changes be made to Article VII

of the indemnity agreement, and Item 3 of the Attachment to the agreement, specifying the extension of the

agreement until the expiration date of the renewed VCSNS facility operating license as sought in this

application. In addition, should the license numbers be changed upon issuance of the renewal license, SCE&G

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

agreement as appropriate.

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

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

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

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

nuclear facility contain the following information, (1) an IPA, (2) current licensing basis changes

that have occurred during staff review of the LRA, (3) an evaluation of TLAAs, and (d) an

UFSAR supplement. Sections 3 and 4 and Appendix B of the LRA address the license renewal
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requirements of 10 CFR 54.21(a) and (c). The license renewal requirements of 10 CFR

54.21(d) are in Appendix of the LRA.

In 10 CFR 54.21(b), the Commission requires that each year following submittal of the

application, and at least 3 months before scheduled completion of the staff’s review, an

amendment to the renewal application must be submitted that identifies any changes to the

CLB of the facility that materially affect the contents of the LRA, including the UFSAR

Supplement. The applicant submitted an update to the LRA in a letter dated July 31, 2003,

which summarizes changes to the CLB that have occurred at VCSNS during the staff’s review

of the LRA. This submittal satisfies the requirements of 10 CFR 54.21(b) and is still under staff

review.

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

Appendix D of the LRA, the applicant stated that no technical specification changes had been

identified as being necessary to support issuance of the renewed operating licenses for

VCSNS. This adequately addresses the requirements of 10 CFR 54.22.

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

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

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

and 4 of this SER.

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

in the final plant-specific supplement to the GEIS. This document will state the considerations

related to renewing the license for VCSNS and will be prepared by the staff separate from this

report. When the report of the ACRS, required by 10 CFR 54.25, is issued, it will be

incorporated into Section 5 of this SER. The findings required by 10 CFR 54.29 will be made in

Section 6 of this SER.

1.3.1 Westinghouse Topical Reports

In the LRA the applicant did not utilize the Westinghouse topical reports that other companies

with similar technologies have used for AMR. The only references to any Westinghouse

Commercial Atomic Power (WCAP) reports are in Sections 3 and 4 and Appendix B of the LRA

and in responses to requests for additional information. The applicant referenced the following

WCAP reports in the LRA.

• WCAP-12866, "Bottom Mounted Instrumentation Flux Thimble Wear," 1991.

• WCAP-13480, Revision 1, “Westinghouse Delta 75 Steam Generator Design and

Fabrication Information for the Virgil C. Summer Nuclear Station,” October 1993.

• WCAP-14422, Revision 2-A, "License Renewal Evaluation: Aging Management for

Reactor Coolant Supports," December 2000.

• WCAP-14535A, "Topical Report on Reactor Coolant Pump Flywheel Inspection

Elimination," November 1996.
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• WCAP 14574-A,“License Renewal Evaluation: Aging Management Evaluation for

Pressurizers,” December 2000.

• WCAP-14577, Rev. 1-A, "License Renewal Application: Aging Management Evaluation

for Reactor Internals," March 2001.

• WCAP-14575-A, “Aging Management Evaluation for Class 1 Piping and Associated

Pressure Boundary Components,” August 1996.

• WCAP-15101, “Analysis of Capsule W from the South Carolina Electric & Gas Company

V. C. Summer Unit 1 Reactor Vessel Radiation Surveillance Program,” dated September

1998.

• WCAP-15103, “Evaluation of Pressurized Thermal Shock for V. C. Summer Unit 1,”

September 1998.

• WCAP-15666, "Extension of Reactor Coolant Pump Motor Flywheel Examination,” Rev.

0, Non-Proprietary Class 3, July 2001.

The safety evaluations of the topical reports are intended to be stand-alone documents. An

applicant that incorporates the topical reports by reference into an LRA must ensure that the

conditions of approval stated in the safety evaluations are met. 

1.4 Interim Staff Guidance

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

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

lessons learned address the Agency’s performance goals of maintaining safety, improving

effectiveness and efficiency, reducing regulatory burden, and increasing public confidence. 

The lessons learned are captured in interim staff guidance (ISG) for use by the staff and

interested stakeholders until the improved license renewal guidance documents are revised.

The current set of relevant ISGs that have been issued by the staff, and the SER sections in

which the issues are addressed by staff, is provided in the following table: 
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ISG Issue

(Approved ISG No.)

Purpose SER Section

Station Blackout (SBO) Scoping

(ISG-02)

The license renewal rule 

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. 

3.6.2.4.2

3.6.2.4.3

Concrete Aging Management Program (ISG03)

Lessons learned from the GALL

demonstration project indicate that GALL

is not clear whether concrete needs any

AMPs.

3.5.2.2.1

3.5.2.4.2

Fire Protection (FP) System Piping (ISG-04) To clarify staff position for wall thinning of

FP piping system in GALL AMPs (XI.M26

and XI.M27).

New position is that there is no need to

disassemble FP piping, as oxygen can be

introduced in the FP piping which can

accelerate corrosion. Instead, use

nonintrusive method such as volumetric

inspection. 

Testing of sprinkler heads should be

performed every 50 years and 10 years

after initial service.

Eliminated Halon/carbon dioxide system

inspections for charging pressure, valve

line ups, and automatic mode of operation

test from GALL. The staff considers these

test verifications to be operational

activities. 

3.0.3.3

3.3.2.4.8
ISG Issue

(Approved ISG No.)

Purpose SER Section

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Identification and Treatment of Electrical Fuse

Holder (ISG-05)

To include fuse holder AMR and AMP (i.e.,

same 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.

3.6.2.3.1

1.5 Summary of Open Items

Open items are items for which the applicant has not presented a sufficient basis for resolution. 

There were no such items identified in the draft SER dated October 9, 2003.

1.6 Summary of Confirmatory Items

Confirmatory items are items for which the staff and the applicant have reached a satisfactory

resolution, but the resolution has not yet been formally submitted to the staff. There were no

such items identified in the draft SER dated October 9, 2003.

1.7 Summary of Proposed License Conditions

As a result of the staff’s review of the VCSNS application for license renewal, including the

additional information and clarifications provided by the applicant, the staff identified two

proposed license conditions. The first license condition requires the applicant to include the

UFSAR Supplement in the next UFSAR update required by 10 CFR 50.71(e) following issuance

of the renewed license. The second license condition requires that the future activities

identified in the UFSAR Supplement be completed prior to the period of extended operation.
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2 SCOPING AND SCREENING METHODOLOGY FOR IDENTIFYING

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW, AND IMPLEMENTATION RESULTS

This section documents the staff’s review of the methodology used by the applicant to identify

structures, systems, and components (SSCs) that are within the scope of the Maintenance Rule

- 10 CFR 50.65 (Rule), and to identify structures and components (SCs) that are within the

scope of the Rule and are subject to an aging management review (AMR). SCs subject to an

AMR are those that perform an intended function, as described in 10 CFR 54.4, and meet two

criteria:

• They perform such functions without moving parts or without a change in configuration

or properties, as set forth in 10 CFR 54.21(a)(1)(i) (denoted as “passive” SCs).

• They are not subject to replacement based on a qualified life or specified time period, as

set forth in 10 CFR (a)(1)(ii) (denoted as “long-lived” SCs).

The identification of the SSCs within the scope of license renewal is called “scoping.” For those

SSCs within the scope of license renewal, the identification of “passive,” “long-lived” SCs that

are subject to an AMR is called “screening.”

The staff's review of the scoping and screening methodology is presented in Section 2.1 of this

SER. The staff's review of the results of the implementation of the scoping and screening

methodology is presented in Sections 2.2 through 2.5 of this SER.

By letter dated August 6, 2002, the applicant submitted its request and application for renewal

of the operating license for V.C. Summer Nuclear Station (VCSNS). As an aid to the staff

during the review, the applicant provided evaluation boundary drawings that identified the

functional boundaries for systems and components within the scope of license renewal. These

evaluation boundary drawings are not part of the license renewal application (LRA).

On March 28, 2003, the staff issued requests for additional information (RAIs) regarding the

applicant’s methodology for identifying SSCs at VCSNS that are within the scope of license

renewal and subject to an AMR, and the results of the applicant’s scoping and screening

process. By letter dated June 12, 2003, the applicant provided responses to the F-RAIs. 

The staff conducted a scoping and screening inspection from June 23 – 27, 2003, to examine

activities that supported the LRA, including the inspection of procedures and representative

records and interviews with personnel regarding the process of scoping and screening plant

equipment to select SSCs within the scope of the Rule and subject to an AMR. The results of

the team inspection are contained in Inspection Report 50-395/03-07, dated June 13, 2003. On

this basis, the U.S. Nuclear Regulatory Commission (NRC) staff concluded that the applicant’s

scoping and screening process was successful in identifying those SSCs required to be

considered for aging management. In addition, for a sample of plant systems, the inspection

team performed visual examinations of accessible portions of the systems to observe any

effects of equipment aging. Finally, the inspection concluded that the scoping and screening

portion of the applicant’s license renewal activities were conducted as described in the LRA and

that documentation supporting the application is in an auditable and retrievable form. 
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2.1 Scoping and Screening Methodology

2.1.1 Introduction

Part 54 of Title 10 of the Code of Federal Regulations, (CFR), Requirements for Renewal of

Operating Licenses for Nuclear Power Plants,” Section 54.21, Contents of Application —

Technical Information,” requires that each application for license renewal contain an integrated

plant assessment (IPA). Furthermore, the IPA must list and identify those SCs that are subject

to an AMR from the SSCs that are within the scope of license renewal in accordance with 10

CFR 54.4. 

In Section 2.1, Scoping and Screening Methodology,” of the LRA, the applicant described the

scoping and screening methodology used to identify SSCs for the VCSNS that are within the

scope of license renewal and SCs that are subject to an AMR, pursuant to 10 CFR 54.21(a)(1). 

The staff reviewed the applicant’s scoping and screening methodology to determine if 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 methodology, the applicant considered the requirements of

the Rule, including the statements of consideration and the guidance presented by the Nuclear

Energy Institute (NEI), Industry Guideline for Implementing the Requirements of 10 CFR Part

54 - The License Renewal Rule,” Revision 3, March 2001 (NEI 95-10). In addition, the

applicant also considered the NRC staff’s correspondence with other applicants and with NEI in

the development of this methodology.

2.1.2 Summary of Technical Information in the Application

In Sections 2.0 and 3.0 of the LRA, the applicant provides the technical information required by

10 CFR 54.21(a). In Section 2.1, Scoping and Screening Methodology,” the applicant

describes the process used to identify the SSCs that meet the license renewal scoping criteria

under 10 CFR 54.4(a), as well as the process used to identify the SCs that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

Additionally, Section 2.2, Plant Level Scoping Results,” Section 2.3, System Scoping and

Screening Results: Mechanical,” Section 2.4, Structures and Structural Components Scoping

and Screening Results,” and Section 2.5, Scoping and Screening Results: Electrical and

Instrumentation and Control,” of the LRA amplify the process that the applicant used to identify

the SCs that are subject to an AMR. Chapter 3 of the LRA, Aging Management Review,”

contains the following information—Section 3.1, Aging Management of Reactor Vessel,

Internals, and 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 Systems,” Section 3.5, Aging Management of

Containments, Structures, and Component Supports,” and Section 3.6, Aging Management of

Electrical and Instrumentation and Controls.” Chapter 4, Time-Limited Aging Analysis,”

contains the applicant’s identification and evaluation of time-limited aging analyses (TLAAs).

2.1.2.1 Scoping Methodology

The IPA scoping process used by the applicant was performed for both plant and system level

scoping. The first step was the identification of all plant systems and structures as described in
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Section 2.1.1, Plant Level Scoping,” of the LRA. For those systems and structures determined

to be in scope, a system level scoping was performed to identify the components within the 

systems or structures which support their intended functions. The system level scoping step

was performed to compile a list of SCs that contribute to the ability to perform the intended

functions identified during the process for scoping of plant systems and structures. 

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

In Section 2.1.1 of the LRA, the applicant discussed the scoping methodology as it related to

safety-related criteria in accordance with 10 CFR 54.4(a)(1), non-safety-related criteria in

accordance with 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) for regulated events. In

Section 2.1.1.2, Safety-Related Criteria Pursuant to 10 CFR 54.4(a)(1),” of the LRA, the

applicant discussed the scoping methodology as it related to safety-related criteria in

accordance with 10 CFR 54.4(a)(1). The applicant stated that SSCs within the scope of license

renewal include safety-related SSCs, which are those relied upon to remain functional during

and following design basis events (DBEs), as defined in 10 CFR 50.49(b)(1). The applicant

initially relied on the use of specific component information contained in the component history

and maintenance planning system (CHAMPS) and the environmental qualification (EQ)

databases to identify safety-related SCs credited with remaining functional during and following

DBEs defined in the current licensing basis (CLB). With regard to the system level scoping, the

applicant stated that a system was initially identified as being in scope if one or more of the

following criteria were met:

 The system performs an intended function as described in the applicable system design

basis documents (DBDs) or in the Rule scoping step.

 The component data indicates that failure of a non-safety-related system could prevent

safety-related systems from fulfilling their functions.

 The system is relied upon in safety analyses or plant evaluations to perform a function

that demonstrates compliance with the Commission’s regulations pursuant to

10 CFR 54.4(a)(3), or has been identified in one of the applicant’s reports which

provided a detailed evaluation of the plant with respect to the requirements of

10 CFR 54.4(a)(2).

With regard to structure level scoping, all safety-related structures at VCSNS are designated as

Seismic Category I and are within the scope of license renewal. The classification of each

structure has been previously determined and documented in the updated final safety analysis

report (UFSAR). 

In Section 2.1.1.3, “Non-Safety Related Criteria Pursuant to 10 CFR 54.4(a)(2),” of the LRA, the

applicant discussed the scoping methodology as it related to the non-safety-related criteria in

accordance with 10 CFR 54.4(a)(2). The applicant stated that a review was performed to

identify the non-safety-related SSCs whose failure could prevent satisfactory accomplishment

of the safety-related intended functions identified in 10 CFR 54.4(a)(1). The applicant also

stated that all non safety-related SSCs whose failure could prevent satisfactory accomplishment

of any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii), are also within the scope of

license renewal. Additionally, non-safety-related systems and structures and non-safety-related

portions of safety-related systems and structures whose physical failure could damage
2-4

equipment that is performing a safety function and preventing it from performing that function

are also within scope pursuant to 10 CFR 54.4 (a)(2). During the applicant’s preparation of the

LRA, additional guidance emerged from the NRC regarding scoping of seismic II/I piping

systems and the identification and treatment of SSCs which meet 10 CFR 54.4(a)(2). To

address the staff’s concern in this area, the applicant stated in Section 2.1.1.3.1 of the LRA that

the review of insulation, ductwork, and piping would be provided later in a supplementary

submittal to the NRC. The applicant stated that they are participating in current industry efforts

to develop a methodology to address issues related to these components.

In Section 2.1.1.4, Regulated Events Pursuant to 10 CFR 54.4(a)(3),” of the LRA, the applicant

discussed the scoping methodology as it related to the regulated event criteria in accordance

with 10 CFR 54.4(a)(3). The applicant reviewed all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the Commission’s

regulations, pursuant to 10 CFR 54.4(a)(3), for fire protection, EQ, pressurized thermal shock,

anticipated transients without scram (ATWS), and station blackout (SBO) to ensure they were

adequately accounted for in the scoping methodology. This involved an extensive review of

safety evaluation reports, the VCSNS Fire Protection Evaluation Report (FPER), the UFSAR,

DBDs, licensee event technical reports, licensing correspondence, and other design and

licensing documentation. To support this review, the applicant developed a set of reports which

provided detailed design information for certain regulated events. The reports describe the

regulatory requirements, the system descriptions, and specific equipment relied on to comply

with the requirements including components and structures. 

 

2.1.2.1.2 Documentation Sources Used for Scoping and Screening

In Section 2.1.1 of the LRA, the applicant stated that the information sources relied upon in

performing scoping and screening activities included the UFSAR, technical specifications,

docketed licensing correspondence, DBDs, CLB, piping and instrumentation diagrams (P&IDs),

the FPER, the SBO Coping Plan, and specific component information for SSCs contained in

CHAMPS and the EQ databases. CHAMPS is a controlled database that contains as-built

information on a component level and consists of multiple data fields for each component, such

as design-related information, safety and seismic classifications, safety classification bases,

and component tag, type, and description information. The EQ database is a controlled

database that consists of multiple data fields for each component or subcomponent, such as

component identification, vendor, vendor model number, Regulatory Guide (RG) 1.97 category,

mild or harsh environment category, and maintenance requirements. In addition, the Rule

includes scoping criteria for non-safety-related SSCs which are similar to the license renewal

scoping criterion. 

Flow diagrams were used to delineate the mechanical systems screening boundaries and also

reflect American Society of Mechanical Engineers (ASME) Code boundaries and quality

grouping classifications. For vendor-supplied skid mounted packages, vendor drawings were

used to assist in the scoping and screening reviews. The drawings reflect the SSCs within a

skid package and the interfaces with the system it supports as outlined in the flow diagrams

discussed above. These sources were also used to develop the list of SSCs subject to an

AMR. The applicant used this information to identify the functions performed by plant systems

and structures and then compared this to the scoping criteria in 10 CFR 54(a)(1-3) to determine

if the associated plant SC performed a license renewal intended function. Additionally, 25
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technical reports, prepared specifically for license renewal, formed the basis documentation for

the LRA. 

2.1.2.1.3 Plant and System Level Scoping

In Section 2.1.1 of the LRA, the applicant discussed the scoping methodology as it related to

the safety-related criteria in accordance with 10 CFR 54.4(a)(1), non-safety-related criteria in

accordance with 10 CFR 54.4(a)(2), and other scoping criteria in accordance with

10 CFR 54.4(a)(3) for regulated events. The scoping process used to identify systems and

structures that satisfy the requirements of 10 CFR 54.4(a)(1-3) is performed using documents

which form the CLB and other information sources. The CLB for the VCSNS has been defined

in accordance with the definition provided in 10 CFR 54.3. The key information sources that

form the CLB include the UFSAR, technical specifications, and docketed licensing

correspondence. The aspects of the scoping process used to identify SSCs that satisfy the

requirements of 10 CFR 54.4(a)(1-3) are described in Subsections 2.1.1.2, 2.1.1.3, and 2.1.1.4

of the LRA. 

After the applicant identified the intended functions of systems or structures within the scope of

license renewal, a review was performed to determine which components of each in-scope

system and structure supported license renewal intended functions. The components that

supported intended functions were considered within the scope of license renewal and

screened to determine if an AMR was required. The applicant considered mechanical,

structural, and electrical component classifications during this stage of the scoping

methodology. For mechanical components, the applicant established evaluation boundaries,

determined components within those boundaries, and identified component intended functions.

This was accomplished by highlighting the flow paths, including the pressure boundary, on the

system drawings, and reviewing the P&IDs. The applicant verified that the mechanical

components identified within the highlighted portions of these boundary drawings were within

the scope of license renewal. All passive, long-lived mechanical components or component

groupings developed used plant system flow diagrams, design guidelines, and the plant

component database for consistency with standard plant usage. For structures, the applicant

verified the evaluation boundaries, which included the entire building and its foundation, as

identified on the civil structural drawings, to be within the scope of license renewal. The

applicant also verified that electrical equipment within mechanical systems or structures

considered within the scope of license renewal were carried forward as electrical commodity

groups and then screened for long-lived passive components.

Guidance contained in American Nuclear Society (ANS) ANS N18.2, Nuclear Safety Criteria

for the Design of Stationary Pressurized Water Reactor Plants” August 1970 Draft, RG 1.143,

“Design Guidance for Radioactive Waste Management Systems, Structures, and Components

Installed in Light-Water Cooled Nuclear Power Plants” November 2001, and RG 1.29, Seismic

Design Classification” were used by the applicant to establish those SSCs that satisfy the

scoping criteria in 10 CFR 54.4(a)(1). These plant SSCs are designated as Seismic Category I

in conformance with the recommendations of RG 1.29 for the balance of plant. Nuclear steam

supply system fluid system components important to safety are also classified in accordance

with ANS N18.2. Plant mechanical systems and components are categorized by safety

classification with system components or portions of systems having different classifications.

System piping classifications are shown on mechanical system flow diagrams. 
2-6

At VCSNS, Categories 1, 2a, 2b, 3, non-nuclear safety, and quality-related have been

established for the classification of components and are defined in the UFSAR. These

categories are based on ANS safety classes and reflect both safety-related and non-safetyrelated classifications. Comparison of the ANS N18.2 safety class criteria, as implemented at

VCSNS, to the criteria of 10 CFR 54.4(a)(1), shows that the safety classes encompass the

systems and equipment that meet the criteria of 10 CFR 54.4(a)(1)(i), (ii), and (iii). Scoping of

mechanical systems and mechanical portions of nonmechanical systems relies primarily on the

ANS N18.2 safety classifications. All safety-related mechanical systems, and mechanical

portions of nonmechanical systems, are considered to be within the scope of the Rule. The

system flow diagrams contain boundary flags which identify the safety classification of the

applicable components. Mechanical systems and components required for compliance with

10 CFR 54.4(a)(1) is shown in Section 2.2 of the LRA. On the basis of discussions with the

applicant’s engineering staff cognizant of the scoping and screening process, and a review of

selected design documentation in support of the process, the staff concluded that the

applicant’s staff understood the requirements and adequately implemented the scoping and

screening methodology established in the LRA.

2.1.2.1.4 Component Level Scoping

After the applicant identified systems and structures within the scope of license renewal, and

their associated intended functions, the applicant performed a review to identify the

components of each in-scope system and structure subject to an AMR. The scoping

methodology for each component classification is discussed below.

Mechanical Component Scoping

The applicant based the scoping activities on currently maintained flow diagrams which use

design basis information and DBDs to provided the basis for those mechanical systems

meeting the criteria of 10 CFR 54.4(a)(1, 2, or 3). The applicant used the guidance contained

in RG 1.26 and RG 1.29 to establish those mechanical systems which met the scoping criteria

of 10 CFR 54.4(a)(1). Piping Classes 1, 2a, 2b, and 3 were designated as safety-related and

subject to the requirements of 10 CFR 54.4(a)(1). The applicant identified the safety-related

mechanical boundaries using the flow diagrams. As defined by 10 CFR 54.4(a)(1-3), those

mechanical systems and components which are required to mitigate DBEs, or the failure of

which would prevent the successful mitigation of DBEs, or which are relied on in safety

analyses or plant evaluations to perform a function that demonstrates compliance with the

NRC’s regulated events are all within the scope of license renewal. DBEs are defined in

10 CFR 50.49 (b)(1) and include conditions of normal operation, including anticipated

operational occurrences, design basis accidents, external events, and natural phenomena. 

Non-safety-related mechanical systems, including non-nuclear safety-related and qualityrelated systems, that functionally support safety-related system function(s), or whose failure

could prevent the performance of a required intended function, are within the scope of license

renewal. This equipment may have already been identified by systems-interaction studies, by

classification of equipment as anti-falldown (seismic II/I), or by other considerations such as

flooding or heavy loads. To identify those applicable non-safety-related systems from the

appropriate reference documents, VCSNS staff located plant information sources that identify

the non-nuclear safety-related and quality-related systems which directly support the function of

a safety-related system or whose failure could prevent the performance of a required intended
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function. Technical information related to scoping activities was then incorporated into the

technical report in accordance with VCSNS procedures.

Structures Scoping

Structures at VCSNS are classified as either nuclear safety-related or non-safety-related. The

safety-related structures are designed to withstand the safe shutdown earthquake (SSE) and

are classified as Seismic Category I, while the non-safety-related structures, generally not

designed to SSE seismic levels, are classified as non-seismic. The classification of each

structure has been previously determined and documented in the UFSAR. A listing of

structures within the scope of license renewal is located in Section 2.2 of the LRA. All nonsafety-related SSCs whose failure could prevent satisfactory accomplishment of any of the

functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii) are also within the scope of license

renewal. Two types of systems and structures must be considered for inclusion within the

scope of license renewal per 10 CFR 54.4(a)(2) — (1) Non-safety-related systems and

structures, and non-safety-related portions of safety-related systems and structures whose

physical failure could damage equipment that is performing a safety function and prevent it from

performing that function and (2) non-safety-related SSCs whose failure could prevent

satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), or (iii). 

Structural supports that are considered to meet seismic or anti-falldown criteria or code break

criteria are within the scope of license renewal. These are not included in the mechanical

system scoping and screening but are treated as a structural commodity. 

Electrical and Instrumentation and Control Component Scoping

Electrical components at VCSNS are classified as either Class 1E, as defined in Institute of

Electrical and Electronics Engineers (IEEE) IEEE-380, Definitions of Terms Used in IEEE

Standards on Nuclear Power Generating Stations,” or as non-nuclear safety. Class 1E is the

safety classification of the electrical equipment and systems that are essential to emergency

reactor shutdown, containment isolation, reactor core cooling, and containment and reactor

heat removal, or are otherwise essential in preventing significant release of radioactive material

to the environment. These functions are the electrical equivalent to the functions specified in

the scoping criteria in 10 CFR 54.4(a)(1). All electrical systems that contain equipment

classified as Class 1E are considered to be safety-related and are within the scope of license

renewal. Class 1E equipment is identified through a review of the VCSNS component

database. The listing of electrical systems and components required for compliance with

10 CFR 54(a)(1) is found in Section 2.2 of the LRA. Electrical systems and portions of

electrical systems that are non-safety-related but whose failure could prevent the satisfactory

accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(i), (ii), and (iii) are within

the scope of license renewal pursuant to 10 CFR 54.4(a)(2). The electrical equipment and

components that perform these functions are designated as quality-related and are identified as

such in the VCSNS equipment database. 

2.1.2.2 Screening Methodology

Following the determination of SSCs within the scope of license renewal, the applicant

implemented a process for determining which SCs, contained in the SSCs which were 

determined to be within scope, would be subject to an AMR in accordance with the

requirements of 10 CFR 54.21(a)(1). In Section 2.1.2, Screening Methodology,” of the LRA,
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the applicant discussed these screening activities as they relate to the in-scope SSCs. The

specific screening activities for the various engineering disciplines are further described in the

application in Section 2.1.2.1 for mechanical systems, Section 2.1.2.2 for structures, and

Section 2.1.2.3 for electrical and instrumentation and control (I&C) components. These

screening activities consisted of the identification of passive components, long-lived

components, component intended functions, consumables, and component replacement based

on performance or condition. The applicant relied on the guidance in Appendix B to NEI 95-10

and Chapter 2 of NUREG-1800, Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants,” April 2001 (SRP-LR), to develop the plant-specific

listing of passive components of interest during the review.

2.1.2.2.1 Mechanical Component Screening

Following component level scoping for mechanical systems, the applicant performed screening,

in accordance with Section 2.1.2.1 of the LRA, to identify those mechanical components that

were subject to an AMR. The applicant stated that the mechanical screening process was

implemented on each of the systems that were identified during the scoping review phase to

identify the passive mechanical components that support one or more of the system’s intended

functions. The system’s intended functions, in conjunction with component information in

CHAMPS, regulated event reports, and the applicable system drawings, have been used to

identify the passive components within the scope of license renewal. For mechanical systems,

the screening process is performed on each system identified to be within the scope of license

renewal. The process includes the establishment of system evaluation boundaries,

determination of components within those boundaries, the identification of component intended

functions, the determination of components subject to an AMR, and the identification of

commodity groups (material and environment identification). Mechanical system evaluation

boundaries are established for each system within the scope of license renewal to assure that

all components required to support system intended functions, which meet the requirements of

10 CFR 54.4(a)(1, 2 and/or 3), are considered for an AMR. These boundaries are determined

by mapping the flow paths, including pressure boundary, that are necessary for the

accomplishment of identified system intended functions onto the system flow diagrams or other

drawings, such as UFSAR figures. The mechanical components found within the mapped

portions of these boundary drawings comprise the complete set of mechanical components

within the scope of license renewal. A menu listing all passive long-lived mechanical

components or component groupings was developed based on the guidance in Appendix B to

NEI 95-10. The components within the mapped areas of the license renewal evaluation

boundary diagrams for each system are compared to the menu as a step in listing the

components that are subject to an AMR.

A list of potential mechanical component intended functions is then developed for each

grouping of the components within the mechanical evaluation boundaries. In accordance with

10 CFR 54.21(a)(1), component intended functions are those component level functions that

are performed without moving parts or without a change in configuration or properties in

support of identified system intended functions. The result is a list of the potential intended

functions for each passive long-lived component type. Each mechanical component or

component group (commodity) within the license renewal evaluation boundaries is reviewed to

determine whether the potential intended functions must be performed by that component to

meet the requirements that are necessary to ensure that the identified system intended
2-9

functions for license renewal are accomplished. The functions that must be performed are the

actual component intended functions.

Consistent with the screening criterion of 10 CFR 54.21(a)(1)(i), only in-scope components that

perform an intended function without moving parts or without a change in configuration or

properties are subject to an AMR. Of these, components that are not subject to replacement

based on a qualified life or specified time period, pursuant to 10 CFR 54.21(a)(1)(ii), are

identified and documented as subject to an AMR. All other components in the scope of license

renewal are screened out. Mechanical indicating devices and electrical components that form

an integral part of the pressure-retaining boundary are subject to an AMR. Many components

are grouped together so that a single AMR is performed based on common characteristics,

such as material or environment. For each mechanical component and component type

(commodity) subject to an AMR, the internal and external operating environments to which the

component is subjected are established based on a review of plant design documents, the

UFSAR, plant drawings, and plant environmental data. The materials of construction for the

components and component types subject to an AMR are determined based on a similar review

of plant documentation. Components with similar design, materials of construction, and

subjected to similar environments within an individual system are evaluated as a commodity

group. Commodity groups are not used for components with unique design characteristics,

such as heat exchangers, pumps, and tanks, or Class 1 sub-components. 

2.1.2.2.2 Structures Component Screening

Section 2.1.2.2 of the LRA describes the methodology used to screen civil/structural

components, subject to an AMR, in accordance with 10 CFR 54.21(a)(1). The structural

components within the scope of 10 CFR Part 54 were reviewed to determine those

components. The purpose of structures screening was to identify the types of long-lived

passive structural items (e.g., hangers, cable trays, equipment supports, base plates, specialty

doors, curbs, penetration assemblies, jet shields, and instrument racks and frames) that

support the intended function of the structure. An AMR of a structural component is required if

the component performs an intended function without moving parts or without a change in

configuration or properties (i.e., passive), and if it is not subject to replacement on the basis of a

qualified life or specified time period (i.e., long-lived). Screening has been performed by the

applicant for each structure identified as being within the scope of license renewal.

To facilitate the identification of the structural components subject to an AMR, the applicant

established structure evaluation boundaries which included the entire building, foundation,

slabs, external and internal walls, roof, and steel columns and beams. Other long-lived passive

items within the building, such as structural supports (e.g., hangers, cable trays, miscellaneous

supports), equipment supports and base plates, specialty doors, curbs, penetration assemblies,

jet shields, and instrument racks and frames, are grouped as structural component types and

are subject to an AMR. A comprehensive list of the types of structural components that exist

within VCSNS evaluation boundary is developed based on a review of plant documentation,

including design drawings, specifications, DBDs, the UFSAR, and the component database. 

For concrete structures and structural components, VCSNS has used the 10 CFR Part 54

process, NUREG-1801, and industry guidelines to determine those specific aging effects that

are applicable and require an AMR for the extended period of operation. 
2-10

A list of potential structural component intended functions was developed using the guidance in

NEI 95-10 for each of the component types within the structural evaluation boundaries based

on the intended functions of the structure. For each passive, long-lived structural component,

the potential intended functions are reviewed to determine which of the functions could be

performed by the structural component type. The result is a list of the potential intended

functions for each passive, long-lived component type. Each structural component of the

identified component types is reviewed to determine whether the potential intended functions

must be performed by that structural component to meet the requirements that are the basis for

including the component within the scope of license renewal. The functions that must be

performed are the actual component intended functions. The passive, long-lived structural

components that perform at least one component intended function are subject to an AMR. To

establish commodity groupings, the structural components are divided into major groupings

based on materials of construction and operating environment. For each structural component

subject to an AMR, the internal and external operating environments to which the component is

subjected are established. Operating environments are established based on a review of plant

design documents, the UFSAR, and plant drawings. Components with similar design, materials

of construction, functions, and subjected to similar environments are evaluated as a commodity

group.

2.1.2.2.3 Electrical and Instrumentation and Control Component Screening

Following component level scoping for electrical and I&C systems, the applicant performed

screening to identify those electrical and I&C components that were subject to an AMR. In

Section 2.1.2.3 of the LRA, the applicant described the methodology used to screen electrical

and I&C components. The methodology used to determine which components are subject to

an AMR is organized differently than for the mechanical and structural evaluations. The

primary difference in the methodology is the order in which the component screening steps are

performed. Electrical equipment contained in mechanical systems or structures considered

within the scope of license renewal are carried forward as electrical commodities. Component

commodity groups are established at the start of the process and the screening criteria are

applied to the commodity groups. Since most electrical and I&C components are active, this

method provides the most efficient means for determining the components that require an

AMR, which is consistent with the guidance in NEI 95-10. The listing of commodity groups for

electrical and I&C components in Appendix B to NEI 95-10 is used as the starting point for the

establishment of electrical commodity groups. 

The initial listing of electrical commodity groups is compared to plant design information to

ensure that all electrical and I&C components are included. The intended functions for each of

the electrical commodity groups are then identified. The electrical components groupings are

adjusted, as necessary, based on similar design and function attributes. The intended

functions established for each of the electrical commodity groups are compared with the criteria

of 10 CFR 54.21(a)(1)(i) and (ii). The electrical and I&C components commodity groups that

perform an intended function without moving parts or without a change in configuration or

properties are identified based on the guidance in Appendix B to NEI 95-10. The passive

electrical commodity groups that are not subject to replacement based on a qualified life or

specified time period are identified as requiring an AMR. The applicant selected this method

since most electrical and I&C components are active. The initial listing of electrical commodity

groups is compared to plant design information to ensure that all electrical and I&C components

are included. After identifying the SSCs within the scope of license renewal, the applicant also
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performed a screening review to determine which electrical components would be subject to an

AMR. As part of this effort, the applicant relied on the requirements set forth in

10 CFR 54.21(a)(1)(i) and (ii) as supplemented by industry guidance to identify component

intended functions for each electrical commodity group. All of the other electrical and I&C

commodities identified are either active, subject to replacement based on a qualified life or

specified time period, or do not perform any intended functions and therefore, are not subject to

an AMR pursuant to 10 CFR 54.21(a)(1)(i) and industry guidance. The electrical screening

results are presented in the LRA which provides a description for each of the electrical and I&C

component types subject to an AMR, along with their component intended functions.

2.1.2.2.4 Commodity Groups Screening 

The applicant used commodity groups as a method to evaluate certain components which

share similar materials, perform the same intended functions, and operate under similar

environmental conditions for many systems. For each mechanical and structural component

and component type (commodity) subject to an AMR, the internal and external operating

environments to which the component is subjected are established. Operating environments

are established based on a review of plant design documents, the UFSAR, vendor drawings,

specifications, plant drawings, and environmental data. The materials of construction for the

components and component types subject to an AMR are determined based on a review of

similar plant documents. Components with similar design, materials of construction, and

subjected to similar environments within an individual system are evaluated as a commodity

group (e.g., pipe). Commodity groups are not used for components with unique design

characteristics, such as heat exchangers, pumps, and tanks, or Class 1 sub-components.

For electrical components, the intended functions for each of the electrical commodity groups

and active and passive determinations, are based on the guidance in NEI 95-10. The intended

functions established for each of the commodity groups are compared with the criteria of

10 CFR 54.21(a)(1)(i) and (ii). The electrical and I&C components commodity groups that

perform an intended function without moving parts or without a change in configuration or

properties are identified. Active and passive screening determinations are also based on the

guidance in NEI 95-10. The passive electrical commodity groups that are not subject to

replacement based on a qualified life or specified time period are identified as requiring an

AMR.

2.1.3 Staff Evaluation

As part of the review of the applicant’s LRA, the NRC staff evaluated the scoping and screening

activities described in Section 2.1, Scoping and Screening Methodology,” to ensure that the

applicant described a process for identifying SSCs that are within the scope of license renewal

in accordance with the requirements of 10 CFR 54.4(a)(1-3). In addition, the NRC staff

conducted a scoping and screening methodology audit at the VCSNS from January 28–31,

2003. The focus of the audit was to ensure that the applicant had developed and implemented

adequate guidance to conduct the scoping and screening of SSCs in accordance with the

methodologies described in the LRA and the requirements of the Rule. The audit team

reviewed procedures and engineering reports which describe the scoping and screening

methodology implemented by the applicant. In addition, the audit team conducted detailed

discussions with the cognizant staff on the implementation and control of the program and
2-12

reviewed administrative control documentation used by the applicant during the scoping and

screening process. The team further reviewed a sample of system scoping and screening

results reports for the emergency feedwater, component cooling water, main steam, and main

feedwater systems to ensure the methodology outlined in the administrative controls was

appropriately implemented and the results reports were consistent with the CLB, as described

in the supporting design documentation.

For mechanical components, the applicant established evaluation boundaries, determined

components within those boundaries, and identified component intended functions. This was

accomplished by highlighting flow paths on the system drawings and verifying that the

mechanical components, identified within the highlighted portions of the boundary drawings,

were within the scope of license renewal. All passive, long-lived mechanical components or

component groupings were developed using plant system flow diagrams, design guidelines,

and the plant component database. For structures, the team verified the evaluation boundaries

of structures, identified on the civil structural drawings, to be within the scope of license

renewal. The evaluation boundary of structures considered within the scope of license renewal

included the entire building and its foundations. The team also verified that electrical equipment

within mechanical systems or structures considered within the scope of license renewal were

carried forward as electrical commodity groups and then screened for long-lived passive

components.

2.1.3.1 Evaluation Methodology for Identifying Systems, Structures, and Components Within

the Scope of License Renewal 

In Section 2.1.1 of the LRA, the applicant discussed the scoping methodology related to the

safety and non-safety-related criteria and regulated events in compliance with

10 CFR 54.4(a)(1–3). The scoping process used to identify systems and structures that satisfy

these requirements is performed using documents which form the CLB and other plant

information sources. The CLB for the VCSNS has been defined in accordance with the

definition provided in 10 CFR 54.3. The key information sources that form the CLB include the

UFSAR, technical specifications, and docketed licensing correspondence. The aspects of the

scoping process used to identify SSCs that satisfy the requirements of the Rule are described

in Subsections 2.1.1.2, 2.1.1.3, and 2.1.1.4, respectively, of the LRA.

The staff reviewed implementation procedures and engineering reports which describe the

scoping methodology implemented by the applicant. These procedures included VCSNS

Technical Report (TR) TR00160-001, Mechanical Systems Scoping for License Renewal,”

dated July 3, 2002; TR00170-001, “Structures Scoping for License Renewal,” dated July 3,

2002; TR00150-001, Electrical Systems Scoping for License Renewal,” dated July 3, 2002;

Engineering Services Procedures (ES) ES-701, Mechanical System Scoping for License

Renewal,” Revision 1, dated July 31, 2000; ES-703, Mechanical Component Aging

Management Review for License Renewal,” Revision 2, dated July 8, 2002; ES-704, Electrical

Systems Scoping, Screening, and Aging Management Review,” Revision 2, dated February 5,

2002; ES-705, Civil/Structural Scoping, Screening, and Aging Management Review for License

Renewal,” Revision 2, dated September 24, 2001; and ES-706, Identification and Evaluation of

Time Limited Aging Analyses and Exemptions for License Renewal,” Revision 2.

The staff found that the scoping methodology instructions were consistent with Section 2.1 of

the LRA and were of sufficient detail to provide the applicant’s staff with concise guidance on
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the scoping and screening implementation process to be followed during the LRA activities. In

addition to the implementing procedures, the staff reviewed supplemental design information

including DBDs, system drawings, and selected licensing documentation, which were relied

upon by the applicant during the scoping and screening phases of the review. The staff found

these design documentation sources to be useful for ensuring that the initial scope of SSCs

identified by the applicant was consistent with the CLB. 

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

10 CFR 54.4(a)(1)

An applicant must consider all safety-related SSCs which are relied upon to remain functional

during and following DBEs to ensure the following functions — (1) the integrity of the reactor

coolant pressure boundary, (2) the ability to shut down the reactor and maintain it in a safe

shutdown condition, or (3) the capability to prevent or mitigate the consequences of accidents

which 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 Part 100.11, to be within the scope of the

license renewal. The applicant’s process used to scope safety-related SSCs is described in

several engineering procedures that require a search of CLB documentation (e.g., DBDs,

UFSAR, and the CHAMPS database) to identify systems and structures that meet the safetyrelated criteria. The staff reviewed a sample of the applicant’s safety-related components and

CHAMPS database tables to ensure that the applicant had adequately captured those

components. The staff reviewed CHAMPS and other documentation to sort through the

equipment data system records. The documentation reviewed provided concise tables of

component records on the basis of safety classification or specific intended functions of

interest, such as EQ and fire protection.

In Section 2.1.1.2 of the LRA, the applicant stated in the table that :

Plant systems, structures, and components within the scope of this part are -- (1) Safety-related systems,

structures, and components which are those relied upon to remain functional during and following design-basis

events (as defined in 10 CFR 50.49(b)(1)) to ensure the following functions -- ... (iii) The capability to prevent

or mitigate the consequences of accidents which could result in potential offsite exposures comparable to

those referred to in §50.34(a)(1), §50.67(b)(2), or §100.11 of this chapter, as applicable. 

However during the scoping and screening audit, the staff noted that Procedures TR00160-

001,TR00170-001, and TR00150-001 cited superseded regulatory text in establishing the

scoping criteria to be used in identifying SSCs in accordance with 10 CFR Part 54.4(a)(1)

requirements. Specifically referenced in the Procedures, 10 CFR 54.4(a)(1)(iii) states:

The capability to prevent or mitigate the consequences of accidents which could result in potential offsite

exposure comparable to those referred to in the 10 CFR Part 100 guidelines.

On March 28, 2003, the staff requested in RAI 2.1-1 that the applicant provide an evaluation

that addressed the impact, if any, of not having explicitly considered in its scoping methodology

those SSCs that are relied upon to ensure compliance with 10 CFR 50.49(b)(1)(iii), consistent

with the CLB. In its response dated June 12, 2003, the applicant stated that the text in the

technical reports (comparable to the 10 CFR Part 100 guidelines) was taken from the original

Rule (May 8, 1995) as published in NEI 95-10 which was later amended on December 11,

1996, to read, comparable to those referred to in 10 CFR 50.34(a)(1) or §100.11 of this
2-14

chapter, as applicable.” Another change was made on December 23, 1999, to make the Rule

read comparable to those referred to in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or

10 CFR 100.11 of this chapter, as applicable.” The applicant stated that this change had no

impact on how scoping was done and that 10 CFR Part 100.11 is the specific section of Part

100 that VCSNS used to define the site boundary and allowable doses to the public. 

The staff also reviewed various documentation and discussed the methodology and results with

the applicant’s cognizant staff during the audit. The staff verified that the applicant had

identified and used pertinent engineering and licensing information in order to determine the

SSCs required to be in scope in accordance with 10 CFR 54.4(a)(1). The staff also reviewed a

sample of the license renewal database 10 CFR 54(a)(1) scoping results, reviewed a sample of

the analyses and documentation to support these reviews, 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 in order to

determine the SSCs required to be in scope in accordance with the 10 CFR 54.4(a)(1) criteria. 

On the basis of this sample review, the staff’s onsite audit, discussions with the applicant, and

review of the applicant’s response to the staff’s RAI, the staff determined that the applicant’s

methodology for identifying systems and structures meeting the scoping criteria of

10 CFR 54(a)(1) was adequate. Therefore, RAI 2.1-1 is considered closed.

10 CFR 54.4(a)(2)

In Section 2.1.1.3.1 of the LRA, the applicant provided a discussion of the methodology used to

evaluate SSCs with respect to the 10 CFR 54.4(a)(2) criteria. The applicant’s methodology

consisted of the following:

 a review of all LRA boundary drawings including those drawings extending beyond the

scope of the license renewal boundaries

 a review of completed plant level scoping and screening evaluations

 review of systems and their drawings for identified systems that were not within the

scope of license renewal

 walkdowns of plant areas to identify the potential interactions

 review of design drawings to determine the potential for interference of non-safetyrelated SCs with safety-related SCs in instances where the drawing were of sufficient

detail to preclude the need to perform a physical plant walkdown

 review of industry and plant specific operating history of non-safety-related piping and

components to determine if further consideration of non safety-related versus safetyrelated is required

The applicant’s review initially encompassed all seismic II/I and non-seismic II/I systems

containing either steam or liquid as well as non-fluid-filled (i.e., air/gas) systems. With respect

to the non-fluid-filled systems, the applicant performed a review of NRC generic

communications and industry operating experience associated with non-fluid-filled systems and

did not identify any instances of failures due to age-related degradation of these systems which
2-15

could prevent safety-related equipment from performing their intended functions. The review of

plant-specific operating experience associated with non-fluid-filled systems also did not identify

any instances of such failures. As a result, no additional SSCs were brought into scope for

non- fluid-filled systems. For the remaining fluid-filled systems, all were included in the

supplemental review except for those systems which could not have an effect on safety-related

SSCs due to their location being remote (i.e., being physically separated from) from such

safety-related SSCs.

The staff reviewed the plant equipment database to identify non-safety-related components that 

could have an impact on the ability of nuclear safety-related SSCs to perform their required

functions. In addition, the Maintenance Rule includes scoping criteria for non-safety-related

SSCs which are similar to the license renewal scoping criterion. The staff reviewed several of

these information sources and verified that the applicant had adequately incorporated the

results of these efforts into the scoping methodology reports. The staff also discussed with the

applicant the current interim staff guidance (ISG) regarding the 10 CFR 54.4(a)(2) issue,

including the December 3, 2001, and March 15, 2002, letters to NEI which discussed the staff’s

position. The ISG discusses two types of systems and structures that must be considered for

inclusion within the scope of license renewal per 10 CFR 54.4(a)(2) — (1) Non-safety-related

systems and structures, and non-safety-related portions of safety-related systems and

structures whose physical failure could damage equipment that is performing a safety function

and prevent it from performing that function and (2) non-safety-related SSCs whose failure

could prevent satisfactory accomplishment of any of the functions identified in

10 CFR 54.4(a)(1)(i), (ii), or (iii). 

The letters described the areas to be considered and options the staff expects applicants to use

to determine what SSCs meet the (a)(2) criterion. The December letter provided specific

examples of operating experience which identified pipe failure events (summarized in 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”) and the

approaches the staff considers acceptable to determine which piping systems should be

included in scope. The March letter further described the staff’s expectations for the evaluation

of non-piping SSCs to determine which additional non safety-related SSCs are within scope. 

The position states that applicants should not consider hypothetical failures but rather should

base their evaluation on the plant’s CLB, engineering judgement and analyses, and relevant

operating experience. 

During the applicant’s preparation of the LRA, additional guidance was developed by the NRC

regarding scoping of seismic II/I piping systems and the identification and treatment of SSCs

which meet 10 CFR 54.4(a)(2). To address the staff’s concerns discussed in the NEI letters

and the ISG, the applicant stated in Section 2.1.1.3.1 of the LRA that the review of insulation,

ductwork, and piping would be provided later to the staff in a supplementary submittal. On

September 12, 2002, the applicant submitted to the staff its results of previously non-analyzed

insulation, piping, and duct work to address the staff’s concerns. The results were documented

in TR00160-018, Refined 10 CFR Part 54.4(a)(2) Criteria Evaluations for License Renewal,”

Revision 0, dated September 6, 2002. The reevaluation focused on AMRs of non-nuclear

safety-related piping whose failure may adversely impact nuclear safety-related equipment and

components due to spatial interactions (i.e., physical impact, pipe whip, jet impingement,

leakage and spray). Non-fluid containing mechanical system portions, as well as nonmechanical SSCs, were also addressed for completeness. In this submittal the applicant stated
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that systems containing non-nuclear safety-related and/or quality-related components that meet

the 10 CFR 54.4(a)(2) criteria were identified with respect to spatial interactions that could

adversely affect the performance of a safety-related function during the period of extended

operation. The results contained a list of systems having components which met the

10 CFR 54.4(a)(2) criteria. Included were 34 in-scope mechanical systems that had their scope

expanded to include non-nuclear safety and quality-related portions that have a potential for

adverse spatial interactions with nuclear safety-related equipment in certain designated

buildings, as well as 11 additional systems added to scope. The staff’s review of the applicant’s

scoping results and aging management evaluation of SCs in these systems is presented in

Sections 2.3.5 and 3.0.5 of this SER, respectively.

On the basis of the additional information supplied by the applicant, the staff concludes that the

applicant has applied sufficient scoping criteria to demonstrate that all SSCs that meet the

10 CFR 54.4(a)(2) scoping requirements are identified. This information included expansion of

the systems within the scope of license renewal, the addition of new portions of systems within

scope as a result of the revised methodology, determination of the credible failures which could

impact the ability of safety-related SSCs from performing their intended functions, evaluation of

relevant operating experience, incorporation of identified non-safety-related SSCs into the

applicant’s AMPs, and the results of NRC inspection and audit activities.

10 CFR 54.4(a)(3)

In addition to those SSCs relied upon to mitigate DBEs or whose failure could prevent

mitigation of such events, the systems that are credited to support compliance with NRC

regulations identified in 10 CFR 54.4(a)(3) must be identified for license renewal. This requires

that the applicant consider all SSCs relied on in safety analyses or plant evaluations to perform

a function that demonstrates compliance with the Commission’s regulations for fire protection

(10 CFR 50.48), EQ (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.63) to be within the scope of the license renewal. 

The staff reviewed several evaluations and source documents prepared by the applicant to 

demonstrate compliance with each of the regulated events of interest in accordance with the

regulations. The applicant’s evaluations focused on identifying and verifying that specific

systems or structures were relied upon in response to the particular regulated event. The

applicant reviewed all SSCs relied on in safety analyses or plant evaluations to perform a

function that demonstrates compliance with the Commission’s regulations to ensure they were

included in the scoping methodology. This involved an extensive review of safety evaluation

reports, the UFSAR, licensee event technical reports, licensing correspondence, the EQ list,

and other design and licensing documentation. 

The staff reviewed reports developed by the applicant which provided detailed design

information for certain regulated events and included an RG-1.154 evaluation to verify SSCs

met the pressurized thermal shock (PTS) criteria, docketed correspondence to address

regulatory commitments on ATWS, including documentation to support the installation of the

ATWS mitigation system actuation circuitry control system, and for SBO, the applicant

developed a coping plan to address the Rule. The reports described the regulatory

requirements, system descriptions, and specific equipment relied on to comply with the

requirements, including components and structures. For fire protection, the staff reviewed the

FPER which contained additional analyses on the essential elements of the program, including
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the fire hazards analysis, safe plant shutdown description, and a point-by-point comparison of

the program with the requirements of Appendix A to NRC Branch Technical Position APCSB,

Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976,” dated

August 23, 1976. 

The staff also discussed the methodology and results with the applicant’s cognizant staff,

reviewed a sample of the license renewal database 10 CFR 54.4(a)(3) scoping results,

reviewed a sample of the analyses and documentation to support these reviews, and discussed

the methodology and results with the applicant’s personnel responsible for these evaluations. 

The staff verified that the applicant had an acceptable process to identify and use pertinent

engineering and licensing information in order to determine the SSCs required to be in scope. 

Based on this review, the staff determined that the applicant’s methodology for identifying

systems and structures meeting the scoping criteria of 10 CFR 54(a)(3) was adequate.

2.1.3.1.2 Plant Level Scoping of Systems and Structures

To accomplish license renewal scoping, the applicant’s engineering procedures incorporated

the methodology used to identify systems and structures within the scope of license renewal. 

The applicant developed various system DBDs to assure plant engineering had a verified

source of detailed design information for plant systems and selected internal and external

events and anticipated operational occurrences, such as internal and external missiles, high

energy line breaks, fire protection, and seismic criteria. The staff reviewed a sample of the

DBD reports for both safety-related and non-safety-related systems to better understand the

approach used by the applicant to determine which SSCs would be initially placed in scope for

license renewal. The DBDs provide a concise, well documented discussion of the system,

including safety-related, non-safety-related, and NRC required functions, and also included brief

descriptions of system operation during normal and off-normal conditions, system maintenance,

and system and component design basis requirements. 

Included in each DBD was a detailed list of the sources of information which included specific

sources such as the UFSAR, technical specifications, calculations and analyses, as well as

non-plant-specific sources such as industry codes and standards, NUREGs, regulatory guides,

inspection and enforcement bulletins, notices, generic letters, and Commission orders. The

DBD documentation is controlled and maintained in accordance with the applicant’s site quality

assurance program. The staff reviewed the governing procedures and administrative controls

and determined that they presented adequate guidance for the preparation, control, and

maintenance of the DBDs. The applicant also explained the development of various

procedures and technical reports prepared by the applicant’s engineering staff to help ensure

that the scoping process identified and considered for inclusion in the scope of the LRA, all

SSCs in the CLB that address the requirements of 10 CFR 54.4(a)(1-3).

For scoping of structural components, the staff reviewed ES-705, Civil/Structural Scoping,

Screening, and Aging Management Review for License Renewal,” Revision 2, dated

September 24, 2001, which provided instructions for implementing the scoping and screening

review processes for structures and structural components in accordance with the requirements

of 10 CFR 54.4. The staff also reviewed TR00170-001, Structures Scoping for License

Renewal,” dated July 3, 2002, and TR00170-002, Structures Screening for License Renewal,”

dated July 3, 2002, which provided additional guidance. The applicant developed the structural

scoping process in accordance with the guidance contained in NEI 95-10 and also developed a
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list of structures derived from VCSNS document sources and included the master list in

TR00170-001. Structures within this list were evaluated against the 10 CFR 54.4(a) criteria to

determine those structures within the scope of license renewal. As stated in the LRA with

respect to structures meeting the requirements of 10 CFR 54.4(a)(1), all structures were

classified according to their design function and the degree of structural integrity required to

ensure the health and safety of the public. 

The applicant noted that Appendix A to 10 CFR 100, Seismic and Geological Siting Criteria for

Nuclear Power Plants,” requires that all nuclear power plants be designed such that, if an SSE

occurs, certain SSCs remain functional. These SSCs are those necessary to ensure (1) the

integrity of the reactor coolant pressure boundary, (2) the capability to shut down the reactor

and maintain it in a safe shutdown condition, or (3) the capability to prevent or mitigate the

consequences of accidents which could result in potential offsite exposures comparable to the

guideline exposures of 10 CFR Part 100. These three functions meet the requirements

specified in the scoping criteria in 10 CFR 54.4(a)(1). The specific structures that are required

to ensure these functions are satisfactorily implemented are identified in RG 1.29 as Seismic

Category I. All safety-related structures identified through a review of the UFSAR are

designated as Seismic Category I and are within the scope of license renewal. The applicant

also listed each in-scope system or structure and provided a detailed description of the

intended function(s) and the specific rule criteria the intended function satisfied. The staff

determined that the applicant had adequately captured the system intended functions from

those source documents and appropriately identified which 10 CFR 54.4 rule criteria that each

intended function satisfied.

2.1.3.1.3 System Level Scoping

VCSNS procedures ES-701, ES-704, and ES-705 provide the detailed instructions for

determining which of the many mechanical systems at VCSNS are within scope. Generally, the

scoping process described is at the system level for the majority of the SSCs. Because several

different criteria are included in 10 CFR 54.4, separate background material and guidance is

provided in the applicable subsections for each of the different criteria. 

Mechanical Component Scoping

In Section 2.1.1 of the LRA, the applicant discussed the scoping methodology as it related to

safety-related criteria in accordance with 10 CFR 54.4(a)(1), non-safety-related criteria in

accordance with 10 CFR 54.4(a)(2), and other scoping in accordance with 10 CFR 54.4(a)(3)

for regulated events. The applicant stated that a system was initially identified as being in

scope if one or more of the following criteria were met:

 The system performs an intended function as described in the applicable system DBDs

or in the Rule scoping step.

 The component data indicates that failure of a non-safety-related system could prevent

safety-related systems from fulfilling their safety-related functions.

 The system is relied upon in safety analyses or plant evaluations to perform a function

that demonstrates compliance with the Commission’s regulations pursuant to

10 CFR 54.4(a)(3), or has been identified in one of the applicant’s reports which
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provided a detailed evaluation of the plant with respect to the requirements of

10 CFR 54.4(a)(2).

The staff reviewed the applicant’s methodology used to identify SSCs relied upon to remain

functional during and following DBEs (as defined in 10 CFR 50.49(b)(1)) to ensure the following

functions – (1) the integrity of the reactor coolant pressure boundary, (2) the capability to shut

down the reactor and maintain it in a safe shut down condition, or (3) the capability to prevent or

mitigate the consequences of accidents that could result in potential offsite exposure

comparable to the guidelines in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11 of

this chapter, as applicable. The applicant initially relied on the use of specific component

information contained in CHAMPS and the EQ databases to identify safety-related components

and structures credited with remaining functional during and following DBEs defined in the CLB.

Several information sources were utilized for the identification of non-nuclear safety-related

SSCs that meet the requirements of 10 CFR 54.4(a)(2). The plant equipment database

identifies components that are not directly nuclear safety-related but that could have an impact

on the ability of nuclear safety-related SSCs to perform their required functions.

Structures Scoping

The staff reviewed ES-705, which provided instructions for implementing the scoping and

screening review processes for structures and structural components in accordance with the

requirements of 10 CFR 54.4. The staff also reviewed TR00170-001 and TR00170-002, which

provided additional guidance on structures scoping and screening, and documented the results. 

VCSNS developed the structural scoping process in accordance with the guidance contained in

NEI 95-10 and compiled the list of structures from several document sources including the

UFSAR, site facility drawings, DBDs, and plant walkdowns, and referenced such structures in

the master list of structures included in TR00170-001. The structures within this list were

evaluated against the 10 CFR 54.4(a) criteria to determine those structures within the scope of

license renewal. For compliance with 10 CFR 54.4(a)(1), all structures were classified in the

LRA according to their design function and the degree of structural integrity required to ensure

the health and safety of the public. The classification of each structure has been previously

determined and documented in UFSAR Table 3.2-2, Classification of Structures.” Category I

structures are identified through a review of the UFSAR. Nuclear safety-related structures had

been previously identified and all remained in scope.

For 10 CFR 54.4(a)(2), structures were classified as either nuclear safety-related or nonnuclear safety-related. The safety-related structures are designed to withstand the SSE and

are classified as Seismic Category I, while the non-safety-related structures are generally not

designed to withstand SSE seismic levels and are classified as non-seismic. Systems and

components that have been seismically mounted to meet anti-falldown (seismic II/I) criteria are

classified as Seismic Category II. There are no structures designated as Seismic Category II at

VCSNS. Non-safety-related structures whose failure could impair the function of safety-related

SSCs are designated as non-seismic but have been designed to withstand earthquake and

tornado loads to the extent required for prevention of damage to Seismic Category I structures. 

The staff reviewed the portion of the master list which had not been identified as nuclear safetyrelated for potential impact on safety-related components. The applicant identified three

structures which met the requirements of 10 CFR 54.4(a)(2) which were subsequently brought

into scope. One structure, the north berm for flood control which was not included in the Rule

scoping, was scoped in for license renewal purposes and also added to the Rule. The
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applicant also identified two structures which were brought into scope for potential structural

failure due to seismic or wind.

For 10 CFR 54.4(a)(3), the staff performed a sample review of safety evaluation reports, the 

UFSAR, DBDs, technical reports, calculations, technical requirement packages, licensing

correspondence files, and other appropriate design documents to verify that the scoping

methodology demonstrated compliance with the Commission’s regulations.

Electrical and Instrumentation and Control Component Scoping

The staff reviewed Sections 2.1.1.2.3 and 2.1.1.3.3 of the LRA to determine that the applicant

identified the electrical components within the scope of license renewal in accordance with 

10 CFR 54.4 and subject to an AMR, in accordance with the requirements of

10 CFR 54.21(a)(1). The staff discussed the methodology with applicant representatives and

reviewed various documents including ES-704, TR00150-001, and TR00150-002. These

documents describe the scoping and screening process used by the applicant to identify

electrical components subject to an AMR and present the results of that process. The applicant

assumed that all electrical systems were within the scope of license renewal unless a specific

scoping evaluation was performed that demonstrated otherwise. The purpose of electrical

system scoping was to identify those electrical systems which did not meet the requirements of

10CFR 54.4(a)(1-3) and, therefore, did not contain any components within the scope of license

renewal. In addition, many electrical components were assigned to mechanical systems (not

electrical systems). Following scoping, all electrical components were recombined into

electrical commodity groups where they were reviewed as part of the commodity group and not

as part of the system. The scoping evaluation described the system, component, or commodity

group functions and then evaluated these functions against the scoping criteria of

10 CFR 54.4(a). Those systems which were classified as “1E” were included within the scope

in accordance with 10 CFR 54.4(a)(1). The determination of which systems would be within

scope in accordance with 10 CFR 54.4(a)(2) was based upon the VCSNS definition of

quality-related as detailed in the system technical requirements packages and also from the

Maintenance Rule system worksheets. All electrical systems relied upon to perform a function

in compliance with NRC requirements for regulated events were also included within scope.

For all other scoping criteria, the applicant reviewed all SSCs relied on in safety analyses or

plant evaluations to perform a function that demonstrates compliance with the Commission’s

regulations, pursuant to 10 CFR 54.4(a)(3), to ensure they were adequately accounted for in

the scoping methodology. This involved an extensive review of SERs, the FPER, the UFSAR,

DBDs, licensee event technical reports, licensing correspondence, and other design and

licensing documentation. To support this review, the applicant developed a set of reports which

provided detailed design information for each regulated event. The reports described the

regulatory requirements, the system descriptions, and specific equipment relied on to comply

with the requirements including components and structures.

2.1.3.2 Evaluation Methodology for Identifying Structures and Components Subject to an Aging 

Management Review

After the applicant identified systems and structures within the scope of license renewal and

their associated intended functions, a review was performed to identify the components of each

in-scope system and structure subject to an AMR. To accomplish this, the staff reviewed
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implementation procedures and engineering reports which described the screening

methodology implemented by the applicant. These procedures included ES-702, Mechanical

Component Screening for License Renewal,” Revision 1, dated July 31, 2000; ES-703,

Mechanical Component Aging Management Review for License Renewal,” Revision 2, dated

July 8, 2002; ES-704, ES-705, and ES-706, Identification and Evaluation of Time Limited

Aging Analyses and Exemptions for License Renewal,” Revision 2. The staff also reviewed the

methodology used by the applicant to identify mechanical, structural, and electrical components

within the scope of license renewal that would be subject to an AMR. The applicant provided

the staff with a detailed discussion of the processes used for each discipline and provided

technical reports that described the screening methodology as well as a sample of the

engineering analyses for a selected group of safety-related and non-safety-related systems.

2.1.3.2.1 Mechanical Component Screening

Following identification of the SSCs within the scope of license renewal, the applicant

performed a screening review to determine which mechanical components would be subject to

an AMR in accordance with 10 CFR 54.21(a)(1). An AMR of a mechanical component is

required if the component performs an intended function without moving parts or without a

change in configuration or properties (i.e., passive) and if it is not subject to replacement on the

basis of a qualified life or specified time period (i.e., long-lived). The staff reviewed the

screening methodology which involved the establishment of license renewal evaluation

boundaries, determination of components within those boundaries, identification of mechanical

components subject to an AMR, and identification of the intended functions of each component

or component group. Identification of the components subject to an AMR was performed using

plant system flow diagrams, equipment databases, and the guidance of Appendix B to NEI

95-10. The intended functions were determined based on the system level function which had

been the basis for including the system within the scope of license renewal and the component

function which is required to enable the system to perform its intended function. The staff also

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 reviewed the implementation of this methodology by reviewing a sample of the

mechanical systems identified as being within the scope. The systems included safety

injection, component cooling water, main feedwater, and emergency feedwater. This included

a review of the evaluation boundaries drawn within those systems on the P&IDs, the resulting

components determined to be within the scope of the Rule, the corresponding component level

intended functions, and the resulting list of mechanical components subject to an AMR. The

staff reviewed the applicant’s methodology for establishment of system evaluation boundaries,

reviewed applicable procedures outlining the process, verified portions of the diagrams, and

held discussions with the responsible members of the applicant’s LRA staff. The initial step in

the component screening process was to establish the license renewal boundaries for each

system within the scope of license renewal, (i.e., the physical or functional boundaries that are

required to support identified system intended functions). Precise physical and functional

boundaries were necessary to assure that all components and component groups required to

support system intended functions were considered for inclusion. The system evaluation

boundaries were established by highlighting on system flow diagrams and other pertinent

drawings the flow paths that are involved with the system intended functions identified in

TR00160-001 and all other portions of the system that meet the scoping criteria of

10 CFR 54.4(a)(1-3). Once the system evaluation boundaries were established, the subject
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components or component types (commodities) located within the evaluation boundaries were

determined as described in ES-702. From the list of potential intended functions provided in

ES-702, the actual intended functions of the subject components were determined by reviewing

the UFSAR, system DBDs, and other appropriate design and licensing documents. Actual

intended functions were those that passively support the system intended functions provided in

TR00160-001. Based on this sample review of portions of the above listed systems, applicable

procedures and diagrams, and discussions with the applicant, the staff determined that the

screening methodology for mechanical systems was adequately implemented.

2.1.3.2.2 Structural Component Screening

Following identification of the SSCs within the scope of license renewal, the staff reviewed the

applicant’s screening review, in accordance with ES-705 and TR00170-002, to determine which

structural components would be subject to an AMR in accordance with 10 CFR 54.21(a)(1). An

AMR of a structural component is required if the component performs an intended function

without moving parts or without a change in configuration or properties (i.e., passive) and if it is

not subject to replacement on the basis of a qualified life or specified time period (i.e., longlived). The applicant used industry experience and NEI 95-10 to develop a master list of

component types and potential intended functions. The applicant established the structure

evaluation boundaries, identified structural component types, including long-lived passive

components within the evaluation boundaries, and identified potential and actual structural

component intended functions and components subject to an AMR. The staff reviewed the

methodology used by the applicant to identify and list the structural components and structural

commodities subject to an AMR, as well as the applicant’s technical justification for this

methodology. The staff reviewed a sample of plant structures (auxiliary building and turbine

building) identified as being within the scope, including the evaluation boundaries and resultant

components, the corresponding component level intended functions, and the resulting list of

structural components and structural commodity groups subject to an AMR. The staff also

reviewed a sample of the structural drawing packages assembled by the applicant and

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.

2.1.3.2.3 Electrical and Instrumentation and Control Component Screening

After identifying the SSCs within the scope of license renewal, the staff reviewed the applicant’s 

screening review to determine which electrical components would be subject to an AMR. As

part of this effort, the applicant relied on the requirements set forth in 10 CFR 54.21(a)(1)(i) as

supplemented by industry guidance in NEI 95-10 to develop a commodity evaluation approach

based on a plant-level evaluation of electrical equipment. The applicant reviewed the

component to determine whether the component was passive and long-lived. 

The process began with a list of generic electrical commodities from Appendix B to NEI 95-10. 

Next the applicant applied passive screening that eliminated from the list all commodities that

were active rather than passive (i.e.,components that performed an intended function without

moving parts or without a change in configuration). The applicant applied long-lived screening

to components that were to be replaced based on a qualified life and removed them from the

license renewal scope. The remaining passive commodities included non-EQ insulated cables,

connectors, splices, penetration assemblies and terminal blocks, and high voltage electrical
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switchyard busses, transmission conductors, connections, and insulators. The applicant also

indicated that non-EQ fuse blocks would be added to this group based upon the guidance in the

corresponding NRC ISG. The applicant concluded that all electrical components included in the

applicant’s EQ program were short-lived and were screened out of license renewal scope. The

staff also reviewed the methodology used by the applicant to identify and list the electrical

components and commodities subject to an AMR, as well as the applicant’s technical

justification for this methodology, and discussed the methodology and results with the

applicant’s LRA staff. The staff also sampled several engineering analyses to verify

implementation of the screening process for electrical and I&C components. Based on the

above, the staff determined that the screening methodology for electrical and I&C components

was adequately implemented.

2.1.4 Conclusions

The basis of the staff’s safety determination included the review of the information presented in

Section 2.1 of the LRA, the supporting information in the VCSNS UFSAR, the information

presented during the staff’s scoping and screening audit, NRC scoping and AMR inspections,

and the applicant’s responses to the staff’s RAIs. The staff verified that the applicant’s scoping

and screening methodology, including their supplemental 10 CFR 54.4(a)(2) review, which

brought additional non-safety-related piping segments and associated components into scope,

was consistent with the requirements of the Rule and the staff’s position on the treatment of

non-safety-related SSCs. On the basis of this review, the staff finds that 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 and 10 CFR 54.21(a)(1).

2.1.5 References

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

Nuclear Power Plants,” April 2001

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

License Renewal Rule, Revision 3,” August 2001

3. NUREG-1801, Generic Aging Lessons Learned Report (GALL),” April 2001

4. NRC Inspection Report No. 50-395/03-07 for the V.C. Summer Nuclear Station, dated June

13, 2003.

5. Letter from USNRC to SCE&G, Request for Additional Information for the Review of the

V.C. Summer Nuclear Station License Renewal Application,” dated March 28, 2003. 

6. Letter from SCE&G to USNRC, Responses to Request for Additional Information for the

Review of the License Renewal Application for the Virgil C. Summer Nuclear Station,” dated

June 16, 2003 (RC-03-0112).

7. ES-411, Equipment Classifications,” Revision 9.
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8. ES-412, Attachment 1, Appendix R Evaluation Phase II Composite Equipment List,” dated

September 30, 1998.

9. ES-427, Program/Issue Screening,” Revision 1, dated April 26, 2002.

10. ES-701, Mechanical System Scoping for License Renewal,” Revision 1, dated July 31,

2000.

11. ES-702, Mechanical Component Screening for License Renewal,” Revision 1, dated

July 31, 2000.

12. ES-703, Mechanical Component Aging Management Review for License Renewal,”

Revision 2, dated July 8, 2002.

13. ES-704, Electrical Systems Scoping, Screening, and Aging Management Review,”

Revision 2, dated February 5, 2002.

14. ES-705, Civil/Structural Scoping, Screening, and Aging Management Review for License

Renewal,” Revision 2, dated September 24, 2001.

15. ES-706, Identification and Evaluation of Time Limited Aging Analyses and Exemptions for

License Renewal,” Revision 2, dated August 27, 2001.

16. DBD, Feedwater System,” Revision 8, dated August 27, 2002.

17. DBD, Component Cooling Water System,” Revision 10, dated September 28, 2002.

18. DBD, Emergency Feedwater System,” Revision 11, dated August 28, 2001.

19. DBD, Safety Injection System,” Revision 10, dated November 17, 1999.

20. TR00150-001, Electrical Systems Scoping for License Renewal, Revision 0, dated July 3,

2002.”

21. TR00150-002, Electrical Screening for License Renewal, Revision 0, dated July 3, 2002.”

22. TR00150-003, Electrical Component Aging Management Review for License Renewal,”

Revision 0, dated July 3, 2002.

23. TR00160-001, Mechanical Systems Scoping for License Renewal,” Revision 0, dated July

3, 2002.

24. TR00160-003, Mechanical Component Screening for License Renewal (Treated Water

Systems,“ Revision 0, dated July 3, 2002.

25. TR00160-013, Mechanical Component Aging Management Review for License Renewal

(Treated Water Systems),“ Revision 0.
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26. TR00160-018, Refined 10 CFR Part 54.4(a)(2) Criteria Evaluations for License Renewal,“

Revision 0, dated September 6, 2002.

27. TR00170-001, Structural Scoping for License Renewal, Revision 0, dated July 3, 2002.”

28. TR00170-002, Structures Screening for License Renewal, Revision 0, dated 

July 3, 2002.”

29. TR00170-003, Structures Aging Management Review for License Renewal,” Revision 0,

dated July 3, 2002.

30. SAP-605, Application of CHAMPS,” Revision 7, dated December 16, 2002.

31. SAP-630, Procedure/Commitment Accountability Program,” Revision 6, dated

November 27, 2001.

32. SAP-1041, Statement of Responsibilities, Plant Life Extension,“ Revision 0, dated

November 11, 2002.

33. Duke Engineering & Services Task No. 7A, 8, 9, 10, 11& 12, Project Execution Plan,”

Revision 0, TM/W 210-01, “Plant License Renewal Fundamentals.”

34. Memorandum, Self-Assessment Report for the License Renewal Project,” dated May 24,

2002.

35. Report SA02-PX-02, License Renewal Self Assessment Report - Aging Management

Programs,” dated November 11, 2002.

36. TR Package No. 2, Fire Protection,” Revision 8.

37. EQ Report No. 984, Equipment Qualified to a Harsh Environment - Master Equipment

List,” dated November 13, 2002.

38. QA-SUR-200119-0, Plant Life Extension,” dated October 16, 2001.

39. Drawing D-302-083, Feedwater,” Revision 47.

40. Drawing D-302-085, Emergency Feedwater,” Revision 40.

41. Drawings E-302-691, 692, and 693.

42. Drawing D-302-661, Reactor Building Containment Spray System.”

43. Drawing D-302-651, Spent Fuel Pool Cooling.”

44. Drawings D-302-611, 612, and 613, Component Cooling System,” and D-302-614,

“Component Cooling System To NSSS Pumps.”

45. Drawings D-302-231, Fire Service,” Sheets 1 thru 5.
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46. Drawing E-302-641, Residual Heat Removal System.”

47. Drawing B-817-026, Control Air Signal Tubing Diagram.”

2.2 Plant Level Scoping Results

2.2.1 Introduction

The statements of consideration (SOC) for the License Renewal Rule (Federal Register,

Volume 60, No. 22478) indicate that an applicant has the flexibility to determine the set of SSCs

for which an AMR is performed. In LRA Section 2.1.1, the applicant described the methodology

for identifying the SSCs within the scope of license renewal. In LRA Section 2.2, the applicant

uses the scoping methodology to determine which of the SSCs are required or not required to

be included in the scope of license renewal. The staff reviewed the plant level scoping results

to determine whether the applicant has properly identified all plant level SSCs that are relied

upon to mitigate DBEs, as required by 10 CFR 54.4(a)(1), or whose failure could prevent

satisfactory accomplishment of any of the safety-related functions, as required by 10 CFR

54.4(a)(2), as well as the SSCs relied on in safety analysis or plant evaluations to perform a

function that is required by one of the regulations referenced in 10 CFR 54.4(a)(3). 

The staff reviewed the SSCs that the applicant did not identify as being within the scope of

license renewal to verify whether they have any intended functions that are within the scope of

license renewal. The staff also reviewed the selected SSCs that the applicant has identified as

being within the scope of license renewal to verify whether the applicant properly identified their

components within the evaluation boundary that are subject to an AMR, in accordance with the

requirements of 10 CFR 54.21(a)(1). To determine whether the applicant identified the SSCs

that are subject to an AMR, the staff reviewed the components that the applicant had not

identified as being subject to an AMR. 

2.2.2 Summary of Technical Information in the Application

This section addresses the plant level scoping results for the license renewal. Pursuant to

10 CFR 54.21(a)(1) the applicant is required to identify and list SCs subject to an AMR. These

are the passive and long-lived SCs that are within the scope of license renewal.

In LRA Table 2.2-1, the applicant lists plant level scoping results for mechanical systems, which

includes all the mechanical systems both in scope and not in scope. The plant level scoping

results for structures are listed in LRA Table 2.2-2, which include all the structures and buildings

both in scope and not in scope. The specific mechanical systems within the scope of license 

renewal are described in detail in LRA Section 2.3. The specific structures and buildings within

the scope of license renewal are described in detail in LRA Section 2.4. The electrical and I&C

systems that support the operation of both safety- and non-safety-related systems and

components are described in LRA Section 2.5. In the LRA, the electrical and I&C components

are treated as commodities. In scoping the electrical systems, only the electrical commodity

groups that perform a passive safety function are subject to an AMR. To verify whether the

applicant has properly implemented its methodology, the staff focused its review on the

implementation results to confirm that there is no omission of plant level systems and structures

within the scope of license renewal.
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2.2.2.1 Systems, Structures, and Components Within the Scope of License Renewal

In LRA Sections 2.2 through 2.5, the applicant describes the SSCs that are within the scope of

license renewal, and subject to an AMR, in accordance with the requirements of

10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. As described in LRA Section 2.1,

Scoping and Screening Methodology,” the scoping and screening of mechanical components

were performed using the plant’s DBDs, component databases, and flow diagrams (P&ID

drawings). The applicant uses two controlled databases to perform the scoping and screening

— component history and maintenance planning (CHAMPS) database and equipment

qualification database (EQDB). The CHAMPS is a controlled database that contains as-built

information on a component level that consists of multiple data field for each component. The

EQDB is a controlled database that consists of multiple data fields for each component or

subcomponent, including component identification, maintenance requirements, etc. The two

databases uniquely identify most of the mechanical components at the plant and provide links

to the associated systems. The applicant also identified those mechanical components in the

databases not assigned with unique component numbers by evaluating design drawings and

documents, and also by plant walkdowns. The items in the databases were treated as

commodities for the purposes of license renewal. 

LRA Table 2.2-1 provides the results of the applicant’s plant-wide scoping of the mechanical

systems. The table identifies which of the plant systems are within the scope of license renewal

and which of them are not. The table also indicates whether the intended functions of a given

system is needed to satisfactorily accomplish any of the functions identified in

10 CFR 54.4 (a)(1), (a)(2), and (a)(3). The LRA considers electrical and I&C systems as

generic and treated them as groups of commodities. The scoping results for the commodity

groups of electrical and I&C components are listed in LRA Table 2.2-3. 

Plant structures that satisfy one or more of the criteria in 10 CFR 54.4, and contain in-scope

mechanical and electrical components, are within the scope of license renewal and subject to

an AMR. All seismic Class I SCs are considered safety-related and are in scope. Non-safetyrelated SSCs whose failure could prevent satisfactory accomplishment of any of the functions

identified in 10 CFR 54.4(a)(1) are within the scope of license renewal. The applicant also

evaluated the non-safety-related systems that may have spatial relationships with safety-related

components such that their failure could adversely impact the performance of an intended

safety function (related to seismic II/I issues). The applicant documented the seismic II/I

evaluations in a technical report (i.e., RC-02-0159). The staff’s review of the technical report is

addressed in Section 2.3.5 of this SER.

2.2.2.2 Systems and Structures Not Within the Scope of License Renewal

In addition to the SSCs in scope, LRA Table 2.2-1 contains 54 mechanical systems that are not

within the scope of license renewal. Also, LRA Table 2.2-2 lists 67 structures or buildings and

LRA Table 2.2-3 lists 16 electrical systems that are not within the scope of license renewal. 

However, these tables do not provide reasons why the SSCs are not in scope (this is discussed

in Section 2.2.3 of this SER). 

2.2.3 Staff Evaluation
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The staff reviewed LRA Section 2.2 and Tables 2.2-1, 2.2-2, and 2.2-3 to determine whether

the applicant has properly identified all plant level SSCs that are within the scope of license

renewal, as required by 10 CFR 54.4. The staff’s review was conducted in accordance with

Section 2.2 of the SRP-LR NUREG-1800 and is described as follows.

In LRA Section 2.1, the applicant describes the process for identifying the SSCs that are within

the scope of license renewal and subject to an AMR. This methodology typically consists of a

review of all plant level SSCs to identify those that are within the scope of license renewal in

accordance with the requirements of 10 CFR 54.4. From those in-scope SSCs, the applicant

identifies and lists their components that are passive (that perform their intended functions

without moving parts, or without a change in configuration or properties), and are long-lived

(that are not replaced based on a qualified life or specified time period). The staff reviewed the

scoping and screening methodology and provided its evaluation in Section 2.1 of this SER. The

applicant documented its implementation of the methodology in LRA Sections 2.3 through 2.5. 

The staff’s evaluation of the applicant’s implementation is addressed in Sections 2.3 through

2.5 of this SER.

The staff reviewed LRA Section 2.1 to ensure that the scoping and screening methodologies

described in the section were properly implemented, and that the components that are subject

to an AMR were properly identified. The staff also reviewed LRA Section 2.2 and sampled the

contents of VCSNS UFSAR, based on the listing of systems and structures in LRA Tables 2.2-1

and 2.2-2, to determine whether there were systems or structures that may have intended

functions, as identified by 10 CFR 54.4, but were not included in the scope of license renewal.

During its review of LRA Section 2.2 and LRA Tables 2.2-1 and 2.2-2, the staff determined that

additional information and/or clarification was needed to complete its review. Because the

applicant did not justify the mechanical systems and structures in the LRA tables not in scope,

the staff was unable to determine whether some of these mechanical systems (in Table 2.2-1)

and plant structures (in Table 2.2-2) are required to be in scope. By letter dated

March 28, 2003, in RAI 2.2.2-1, the staff requested the applicant to explain why the following

mechanical systems and plant structures are not within the scope of license renewal:

• emergency offsite facility (EOF)

• emergency equipment

• liquid effluent from nuclear plant to pen stock (LW)

• radwaste solidification and solids handling (WD)

• auxiliary fire pump house

• containment access building (CAB)

• lighting masts (plant)

• radiological maintenance building
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In its response, dated June 12, 2003, the applicant provided the following clarification or

justification for the above systems and structures not in scope:

• The EOF is for emergency plan activities and has no direct license renewal function. 

Loss of system function will not result in the loss of any safety related functions.

• The Emergency Equipment system is inactive.

• The LW was not initially included in the license renewal scope. As a result of the

Criterion 2 reassessment, this non-safety-related system was added to the scope of

license renewal due to its potential spatial interactions with safety-related components. 

The Criterion 2 supplement to the LRA was submitted to the NRC separately in a

technical report (RC-02-0159) dated September 12, 2002.

• The WD was not initially included in the license renewal scope. As a result of the

Criterion 2 reassessment, this non-safety-related system was added to the scope of

license renewal due to its potential spatial interactions with safety-related components. 

• The auxiliary fire pump house is a structure that houses the auxiliary backup fire pumps

used during construction. There are no mechanical or electrical components in the

structure that are within the scope of license renewal.

• The CAB was constructed to facilitate containment access during the steam generator

replacement project and no longer serves a direct plant operational or access function. 

It is used for storage in the radiological maintenance area and performs no intended

function for license renewal. 

• The plant lighting masts are the high light pole structures located around the plant site. 

They are not used to support any of the regulated events and perform no intended

functions for license renewal. 

• The radiological maintenance building serves as a maintenance facility for contaminated

components and tools and performs no intended functions for license renewal.

The staff reviewed the applicant’s response and concurs with its decision to include the LW

system and WD system in the scope of license renewal based on Criterion 2 reevaluation. The

staff’s review of the Criterion 2 Supplement is addressed in Section 2.3.5 of this SER. The staff

also agreed with the applicant’s rationale for not requiring the remaining mechanical systems

and structures to be in scope, except plant lighting masts. The staff considered that the plant

lighting masts have an intended function to support plant lighting. Failure of lighting pole

structures may cause blackout of the plant site. Therefore, the light poles should be included in

the yard structures for license renewal. In a letter, dated June 12, 2003, the applicant further

explained that the high mast lighting poles should not be in scope. The applicant stated that

there are seven high mast light poles located around the plant site that serve as security

lighting. These high mast light poles are not used to support accident conditions or any of the

regulated events and thus perform no intended functions for license renewal. In addition to

these high mast light poles, exterior lighting also consists of standard height light poles and

wall-mounted lights along the perimeter of each structure within the protected area of the plant. 

All of the exterior lighting is supplied by 480-volt, single phase power from the nearest available
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480-volt load center. Because none of the exterior lights are credited for accident or any event

described in 10 CFR 54.4(a)(3), the plant lighting masts are not considered to be in the scope

of license renewal. 

The staff reviewed the applicant’s response and found its rationale acceptable because the

plant site has provided redundant lighting supplied from offsite power. The plant lighting masts

are not required to support normal plant lighting and, therefore, can be excluded from the

license renewal scope. On the basis of this review, the staff did not identify any omissions. 

2.2.4 Conclusions

The staff reviewed LRA Sections 2.2.1 and 2.2.2, supporting information in the plant’s UFSAR,

and the information provided in response to the staff’s RAI to determine whether any SSCs

within the scope of license renewal had not been identified by the applicant. As a result of this

review, the staff did not identify any omissions. On the basis of this review, the staff concludes

that the applicant has appropriately identified the SSCs that are within the scope of license

renewal, in accordance with the requirements of 10 CFR 54.4. The staff’s detailed review of

the SSCs that are subject to an AMR is provided in Section 2.3 through 2.5 of this SER.

2.2.5 References

1. 10 CFR 54, Requirements for Renewal of Operating License for Nuclear Power Plants, 60 

FR 22461, May 8, 1995.

2. NEI 95-10 (Revision 3), Industry Guideline for Implementing the Requirements of 10 CFR 

Part 54—The License Renewal Rule, August 2001.

3. VCSNS Final Safety Analysis Report (FSAR), Amendment 02–1.

4. NUREG-1800, Standard Review Plan for the Review of License Renewal Application for 

Nuclear Power Plants, July 2001.

5. Generic Aging Lessons Learns (GALL) Report, July 2001

2.3 Scoping and Screening Results: Mechanical Systems

Pursuant 10 CFR 54.21(a)(1) an applicant is required to identify and list SCs subject to an

AMR. These are passive, long-lived SCs that are within the scope of license renewal. To verify

that the applicant has properly implemented the scoping and screening methodology, the staff

focuses its review on the implementation results. Such a focus allows the staff to confirm that

the LRA has identified all the mechanical system components that would be subject to an AMR. 

2.3.1 Reactor Vessel, Internals and Reactor Coolant System

The reactor coolant system components consist of the reactor vessel, reactor vessel internals,

incore instrumentation system, pressurizer, steam generators, and associated reactor coolant

system piping.
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2.3.1.1 Reactor Coolant System

The applicant describes the reactor coolant system in LRA Section 2.3.1.1. The mechanical

component types and component intended functions for the reactor coolant system

components are listed in Table 2.3-1. Additional information about the reactor coolant system

can be found in UFSAR Chapter 5. 

2.3.1.1.1 Summary of Technical Information in the Application 

The reactor coolant system consists of three heat transfer loops connected in parallel to the

reactor vessel. Each loop contains one steam generator, one reactor coolant pump, connecting

piping, and instrumentation. The reactor coolant system is designed to remove heat from the

reactor core and transfer it to the secondary (steam generating) system by the forced

circulation of pressurized water that serves both as a coolant and a neutron moderator. The

design pressure and temperature are 2500 psi and 650 F, respectively.

A pressurizer is connected to one of the reactor vessel outlet (hot leg) pipes by a surge line. 

The pressurizer controls and maintains reactor coolant system pressure. The pressurizer

contains steam and water, which are maintained in thermal equilibrium. Immersion heaters in

the pressurizer are energized to form steam, and subcooled water is sprayed into the

pressurizer steam space to condense steam. In this way, the pressurizer is used to maintain

operating pressure and limit pressure variations due to plant load transients. Overpressure

protection for the system is provided by three power-operated relief valves and three springloaded ASME Code safety valves. These valves discharge to the pressurizer relief tank where

the steam is released under water to be condensed and cooled. If the steam discharge

exceeds the capacity of the tank, the tank’s rupture disks open, at about 100 psi, and allow

steam to exit into the containment atmosphere. 

All components of the reactor coolant system are located within the containment building. The

reactor coolant system boundary is defined to include all the components in the reactor coolant

system except the reactor vessel and head. The main reactor coolant system components

include the reactor coolant pumps and motors, reactor coolant piping, pressurizer, pressurizer

heaters, power-operated relief valves and safety valves, steam generators, and associated

instrumentation and controls. The scoping and screening results for the pressurizer are

discussed in Section 2.3.1.6 of this report.

The steam generator boundaries are set at the ends of the nozzles connecting the steam

generators to other components or systems. The nozzles include main feedwater, emergency

feedwater, steam, reactor coolant system inlet and outlet, and instrumentation. The scoping

and screening results for the steam generators are discussed in Section 2.3.1.7 of this report.

The major system interfaces with the reactor coolant system are the chemical and volume

control system, safety injection system, and the reactor vessel.

The non-Class 1 reactor coolant system component types subject to AMR and their intended

functions, listed in Table 2.3-1 of the LRA, include the reactor coolant pump oil collection

system and oil cooler heat exchanger, various orifices, piping and tanks, valves (body only),

tubes and tube fittings, and flanges. The intended functions identified for these RC

components were pressure boundary, throttling, and fire protection.
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2.3.1.1.2 Staff Evaluation

The staff reviewed Section 2.3.1.1 of the LRA and Chapter 5 of the UFSAR to determine

whether the reactor coolant system and associated components and supporting structures

within the scope of license renewal and subject to AMR had been identified in accordance with

the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed Chapter 5 of the UFSAR for VCSNS for the

reactor coolant system and associated components and compared the information in the

UFSAR with the information in the LRA to identify those portions that the LRA did not identify as

being within the scope of license renewal and subject to an AMR. The staff then reviewed the

SCs that were identified as not being within the scope of license renewal to verify that these

SCs do not have any of the intended functions delineated under 10 CFR 54.4(a), and for those

SCs that have an applicable intended function(s), to verify that they either perform this

function(s) with moving parts or a change in configuration or properties, or that they are subject

to replacement based on a qualified life or specified time period, as described in 10 CFR

54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 

Since the reactor coolant system piping is largely composed of components that form the

pressure boundary, and that carry the reactor coolant to the reactor vessel and the steam

generators, the staff’s review was centered upon identification of the components that perform

the functions described in 10 CFR 54.4(a)(1). The staff’s review of long-lived, passive

components in the reactor coolant system has identified, and excluded, those components that

are periodically replaced, such as seals and gaskets, and active components, such as the

moving parts in pumps and valves.

Non-safety related components and piping were also considered (1) if they could fail in such a

manner as to prevent other SCs from completing any of the functions described in

10 CFR 54.4(a)(1), or (2) if they are required for compliance with the regulations for fire

protection, EQ, PTS protection, ATWS protection, or SBO protection, as listed in

10 CFR 54.4(a)(3). 

The applicant has not included the pressurizer relief tank in the pressure-retaining boundary.

The pressure-retaining boundary of the pressurizer relief tank will be maintained only until the

tank’s rupture disks give way, as designed, at about 100 psid. Basically, the pressurizer relief

tank could not be considered to be part of the pressure-retaining boundary since its rupture

disks are not designed to withstand pressure levels exceeding about 100 psi. The pressurizer

relief and safety valves are the components that protect the pressure-retaining boundary,

whereas the pressurizer relief tank serves as a coolant discharge collection device that is

situated downstream of the pressurizer relief and safety valves. The applicant’s categorization
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of the pressurizer relief tank, as being outside the scope of license renewal, is acceptable to the

staff.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.

2.3.1.1.3 Conclusions

The staff reviewed Section 2.3.1.1 of the LRA and Chapter 5 of the UFSAR to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

In addition, the staff performed an independent assessment to determine whether any

components subject to an AMR had not been identified by the applicant. No omissions were

found. On the basis of its review, the staff concludes that the applicant has adequately

identified the reactor coolant system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the reactor

coolant system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.2 Piping, Valves and Pumps

The applicant describes the piping, valves, and pumps in LRA Section 2.3.1.2. The mechanical

component types and component intended functions for the reactor coolant system Class 1

piping and associated pressure boundary components are listed in Table 2.3-2. UFSAR

Section 5.5, Component and Subsystem Design, provides additional information concerning

Class 1 piping and associated pressure boundary components.

2.3.1.2.1 Summary of Technical Information in the Application

The reactor coolant system Class 1 piping and associated pressure boundary components

consist of the following:

• primary loop piping interconnecting the reactor vessel, steam generators and reactor

coolant pumps

• the piping (including fittings, branch connections, safe ends, thermal sleeves, flow

restrictors, and thermowells) and valves leading to connecting auxiliary or support systems,

up to and including the second isolation valve (from the high pressure side) on each line

• pressure boundary portion of Class 1 valves (body, bonnet, and bolting)

• pressure boundary portion of the reactor coolant pumps (casing, main closure flange,

thermal barrier heat exchanger and bolting)

The primary loop piping consists of three closed reactor coolant loops interconnecting the

reactor vessel, steam generators, and reactor coolant pumps. Class 1 branch piping consists

of piping connected to the Class 1 primary loop piping out to and including the outermost

containment isolation valve in piping which penetrates primary containment, or the second of

two valves normally closed during normal reactor operation in piping which does not penetrate

primary containment. Some Class 1 branch lines and instrument lines are equipped with
2-34

3/8-inch inside diameter flow restrictors. These flow restrictors limit the maximum flow from a

break downstream of the flow restrictor to below the makeup capability of the charging system.

The pressure retaining portion of the Class 1 valves includes the body, bonnet, and bolting. 

The valves are welded into the piping, except for the pressurizer code safety valves, which have

flanged connections. The portions of the reactor coolant pumps that perform a pressure

boundary function are the pump casing, main closure flange, thermal barrier heat exchanger,

and bolting. The reactor coolant pumps are vertical, single stage, centrifugal pumps, equipped

with controlled leakage shaft seals. The shaft seals are excluded from AMR because they are

periodically replaced.

The Class 1 portion of the reactor coolant system includes portions of the chemical and volume

control system, emergency core cooling system, residual heat removal system, and safety

injection system.

The component types subject to AMR and their intended functions, listed in Table 2.3-2 of the

LRA, include reactor coolant pump main flange bolting materials, reactor coolant pump thermal

barrier flange, main closure flange, reactor coolant pump thermal barrier piping/tubing (less

than 4-inches normal pipe size (NPS), and reactor coolant pump casing. The intended

functions identified for these components were pressure boundary and throttling.

2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 5.5 to determine whether the

piping, valves and pumps and supporting structures within the scope of license renewal and

subject to an AMR had been identified in accordance with the requirements of 10 CFR 54.4 and

10 CFR 54.21(a)(1), respectively. The staff review was conducted in accordance with Section

2.3 of the SRP-LR (NUREG-1800) and is described below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for VCSNS for

the piping, valves, and pumps and associated pressure boundary components, and compared

the information in the UFSAR with the information in the LRA to identify those portions that the

LRA did not identify as being within the scope of license renewal and subject to an AMR. The

staff then reviewed the SCs that were identified as not being within the scope of license renewal

to verify that these SCs do not have any of the intended functions delineated under

10 CFR 54.4(a), and for those SCs that have an applicable intended function(s), to verify that

they either perform this function(s) with moving parts or a change in configuration or properties,

or that they are subject to replacement based on a qualified life or specified time period, as

described in 10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the period of extended operation.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.
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2.3.1.2.3 Conclusions

The staff reviewed LRA Section 2.3.1.2 and UFSAR Section 5.5 to determine whether any

piping, valves, and pumps within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components subject to an AMR had not been identified by the applicant. On the basis of its

review, the staff concludes that the applicant has adequately identified the piping, valve and

pump components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the reactor coolant system components that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

 

2.3.1.3 Reactor Vessel

The applicant describes the reactor vessel in LRA Section 2.3.1.3 and provides a list of

components that would be subject to an AMR in LRA Table 2.3.1.3-1. More information about

the reactor vessel can be found in UFSAR Section 5.4.

2.3.1.3.1 Summary of Technical Information in the Application

The reactor vessel is a three-loop vessel, with three coolant inlet nozzles and three coolant

outlet nozzles. The reactor vessel is cylindrical, with a welded hemispherical bottom head and

a removable, bolted, flanged, and gasketed hemispherical upper head. 

The vessel contains the core, core support structures, control rods, and other parts directly

associated with the core. The reactor vessel closure head contains head adaptors. These

head adaptors are tubular members, attached by partial penetration welds to the underside of

the closure head. The upper end of these adaptors contain acme threads for the assembly of

control rod drive mechanisms or instrumentation adaptors. The seal arrangement at the upper

end of these adaptors consists of a welded flexible canopy seal. Inlet and outlet nozzles are

located symmetrically around the vessel.

The bottom head of the vessel contains penetration nozzles for connection and entry of the

nuclear incore instrumentation. Each nozzle consists of a tubular member made of Inconel. 

Each tube is attached to the inside of the bottom head by a partial penetration weld. The

nuclear incore instrumentation system is discussed in Section 2.3.1.5 of this report.

The major system interfaces with the reactor vessel are the reactor coolant system, nuclear

incore instrumentation system, and the reactor vessel internals.

The list of reactor vessel component types subject to AMR and their intended functions, shown

in Table 2.3-3 of the LRA, includes the reactor vessel shell, ventilation shroud, inlet and outlet

nozzles, core support pads, closure head and flanges, cladding, closure head dome and lifting

lugs, nozzle supports, bottom head dome, control rod drive mechanism latch housing and rod

travel housing, and bottom head penetration tubes. All of the SSCs were identified as being

within the scope of license renewal and subject to an AMR because they were part of the

pressure-retaining boundary.

2.3.1.3.2 Staff Evaluation
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The staff reviewed LRA Section 2.3.1.3 and UFSAR Section 5.4 to determine whether the

reactor vessel and supporting structures within the scope of license renewal and subject to an

AMR had been identified in accordance with the requirements of 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively. The staff review was conducted in accordance with Section 2.3 of the

SRP-LR (NUREG-1800) and is described below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for VCSNS for

the reactor vessel and associated pressure boundary components and compared the

information in the UFSAR with the information in the LRA to identify those portions that the LRA

did not identify as being within the scope of license renewal and subject to an AMR. The staff

then reviewed the SCs that were identified as not being within the scope of license renewal to

verify that these SCs do not have any of the intended functions delineated under

10 CFR 54.4(a), and for those SCs that have an applicable intended function(s), to verify that

they either perform this function(s) with moving parts or a change in configuration or properties,

or that they are subject to replacement based on a qualified life or specified time period, as

described in 10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any functions delineated under 10 CFR 54.4(a) that

were not identified as intended functions in the LRA, to verify that the SSCs with such functions

will be adequately managed so that the functions will be maintained consistent with the CLB for

the period of extended operation.

The reactor vessel is the epitome of the class of passive, long-lived components that are within

the scope of license renewal. It is the key Class 1 component in the pressure-retaining

boundary, since it enables proper cooling of the core under normal and accident conditions. 

Therefore, the staff’s review of the reactor vessel, and its constituent components, as listed in

Table 2.3-3, has been mainly with respect to the requirements of 10 CFR 54.4(a). Since all the

components were in the pressure-retaining boundary, the review also focused upon the variety

of penetrations in the upper and lower vessel heads.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found. 

2.3.1.3.3 Conclusions

The staff reviewed LRA Section 2.3.1.3 and UFSAR Section 5.4 to determine whether any

SSCs within the scope of license renewal had not been identified by the applicant. In addition,

the staff performed an independent assessment to determine whether any components subject

to an AMR had not been identified by the applicant. No omissions were found during the

independent assessment. On the basis of its review, the staff concludes that the applicant has

adequately identified the reactor vessel components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

reactor vessel components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.4 Reactor Vessel Internals
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The applicant describes the reactor vessel internals in LRA Section 2.3.1.4 and provides a list

of components subject to an AMR in LRA Table 2.3-4. UFSAR Section 4.2.2, Reactor Vessel

Internals, provides additional information concerning the reactor vessel internals.

2.3.1.4.1 Summary of Technical Information in the Application

The components of the reactor internals are divided into three parts consisting of the lower core

support structure (including the entire core barrel and neutron shield pad assembly), the upper

core support structure. and the incore instrumentation support structure. The reactor internals

support the core, maintain fuel alignment, limit fuel assembly movement, maintain alignment

between fuel assemblies and control rod drive mechanisms, direct coolant flow past the fuel

elements, direct coolant flow to the pressure vessel head, provide gamma and neutron

shielding, and provide guides for the incore instrumentation.

The coolant flows from the vessel inlet nozzles, down the annulus between the core barrel and

the vessel wall, and into a plenum at the bottom of the vessel. The coolant then reverses

direction and flows up through the core support and lower core plates. After passing through

the core, the coolant enters the region of the upper support structure and then flows radially to

the core barrel outlet nozzles and directly through the vessel outlet nozzles.

All reactor vessel Internals components are considered Class 1 for seismic design. The effects

of neutron embrittlement on materials utilized and accident loadings on the internals have been

considered in the design analysis.

The license renewal boundary for the reactor vessel internals consists of all components

internal to the reactor vessel, excluding the reactor vessel and head, the control rod drive

mechanisms, (CRDMs) and integral attachments to the reactor vessel and head.

The components of the reactor vessel internals, subject to AMR, include the following major

components and their associated subcomponents:

• baffle and former assembly

• bottom mounted instrumentation columns

• clevis inserts

• core barrel and flange

• core barrel outlet nozzle

• guide tube

• lower core plate

• lower support columns

• lower support plate

• neutron panels

• radial keys

• upper core plate

• upper instrumentation conduit and supports

• upper support column

• upper support plate assembly
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The intended functions identified for the reactor vessel internals components were structure

functional support, flow distribution, control rod guidance and protection, and radiation

shielding.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and UFSAR Section 4.2.2, Reactor Vessel Internals, to

determine whether the reactor vessel internals and supporting structures within the scope of

license renewal, and subject to an AMR had been identified in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the reactor

vessel internals and associated pressure boundary components and compared the information

in the UFSAR with the information in the LRA to identify those portions that the LRA did not

identify as being within the scope of license renewal and subject to an AMR. The staff then

reviewed the SCs that were identified as not being within the scope of license renewal to verify

that these SCs do not have any of the intended functions delineated under 10 CFR 54.4(a), and

for those SCs that have an applicable intended function(s), to verify that they either perform this

function(s) with moving parts or a change in configuration or properties, or that they are subject

to replacement based on a qualified life or specified time period, as described in

10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation.

Many of the reactor vessel internals are identified as components that provide structural support

to safety-related components. They can provide, for example, the structural support needed to

maintain a coolable core geometry during a design basis loss of coolant accident (LOCA). 

Unlike many other long-lived, passive components, certain reactor internals are normally moved

(i.e., removed and set aside) to permit the movement of fuel assemblies during refueling. This

provides occasional opportunities to detect and remedy aging-related problems that might

affect these reactor vessel internals. Although these particular components would have the

benefit of periodic examination, they would still be included in the license renewal scope and

subject to aging management requirements.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.

2.3.1.4.3 Conclusions

The staff reviewed the information presented in Section 2.3.1.4 of the LRA and the supporting

information in UFSAR Section 4.2.2, Reactor Vessel Internals, to determine whether any SSCs

within the scope of license renewal had not been identified by the applicant. In addition, the
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staff performed an independent assessment to determine whether any components subject to

an AMR had not been identified by the applicant. No omissions were found. On this basis, the

staff concludes that the applicant has adequately identified the reactor vessel internals

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the reactor vessel internals components that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.5 Incore Instrumentation System

The applicant describes the incore instrumentation system in LRA Section 2.3.1.5 and provides

a list of components subject to an AMR, along with their component intended functions, in LRA

Table 2.3-5. The components are depicted in 1MS-44-014, 3-Loop Plant Bottom Mounted Inst.

Standard Layout.” UFSAR Section 4.4.5.1, Incore Instrumentation, provides additional

information concerning the incore instrumentation system.

2.3.1.5.1 Summary of Technical Information in the Application

The incore instrumentation system is comprised of thermocouples positioned to measure fuel

assembly coolant outlet temperatures at pre-selected positions, and fission chamber detectors

positioned in guide thimbles, which run the length of selected fuel assemblies, to measure

neutron flux distribution.

Instrumentation is located in the core so that by correlating movable neutron detector

information with fixed thermocouple information, radial, axial, and azimuthal core characteristics

may be obtained for all core quadrants. The incore instrumentation obtains data from which

fission power density distribution in the core, coolant enthalpy distribution in the core, and fuel

burnup distribution may be determined. The core-exit thermocouples provide a backup to the

flux monitoring instrumentation for monitoring power distribution.

2.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.5 and UFSAR Section 4.4.5.1, Incore Instrumentation, to

determine whether the incore instrumentation system components that are within the scope of

license renewal and subject to an AMR had been identified in accordance with the requirements

of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the incore

instrumentation system and associated pressure boundary components, and compared the

information in the UFSAR with the information in the LRA, to identify those portions that the

LRA did not identify as being within the scope of license renewal and subject to an AMR. The

staff then reviewed the structures and components that were identified as not being within the

scope of license renewal to verify that these structures and components do not have any of the

intended functions delineated under 10 CFR 54.4(a), and for those SCs that have an applicable

intended function(s), to verify that they either perform this function(s) with moving parts or a

change in configuration or properties, or that they are subject to replacement based on a

qualified life or specified time period, as described in 10 CFR 54.21(a)(1). 
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The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 

The components of the incore instrumentation system that would be within the scope of license

renewal, in accordance with the requirements of 10 CFR 54.4(a), are long-lived, passive

components, and pressure-retaining components. These are the incore neutron flux detector

thimbles, the pressure-retaining incore thermocouples, and various pressure-retaining tubes

and tube fittings. Unlike the surrounding fuel element assemblies, these incore instrumentation

system components are not replaced periodically. They provide guidance and pathways

through which instrument sensors are routed, and these pathways constitute part of the

pressure-retaining boundary. The incore instrumentation system components are basically

pressure-retaining tubes, made of a stainless steel and nickel based alloy, that must withstand

a borated water environment.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR,

were found.

2.3.1.5.3 Conclusions

The staff reviewed the information presented in Section 2.3.1.5 of the LRA and the supporting

information in UFSAR Section 4.4.5.1, Incore Instrumentation, to determine whether any SSCs

within the scope of license renewal had not been identified by the applicant. In addition, the

staff performed an independent assessment to determine whether any components subject to

an AMR had not been identified by the applicant. No omissions were found. On this basis, the

staff concludes that the applicant has adequately identified the incore instrumentation

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the reactor incore instrumentation components that

are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.1.6 Pressurizer

The applicant describes the pressurizer in LRA Section 2.3.1.6 and provides a list of

components subject to an AMR, along with their component intended functions, in LRA Table

2.3-6. UFSAR Section 5.5.10, pressurizer, provides additional information concerning the

pressurizer. 

2.3.1.6.1 Summary of Technical Information in the Application

The pressurizer is a vertical, cylindrical vessel with hemispherical top and bottom heads. A

pressurizer surge line connects the pressurizer to one of the hot legs in the reactor coolant

system. The line enables continuous coolant volume pressure adjustments between the

reactor coolant system and the pressurizer. The surge line nozzle and removable electric

heaters are installed in the bottom head of the vessel, while spray line nozzles and relief and

safety valve connections are located in the top head.

The components of the pressurizer, subject to an AMR, include the following major components

and their associated subcomponents:
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• pressurizer upper and lower heads

• immersion heater well assemblies

• manway cover and bolts

• nozzle safe ends and thermal sleeves

• shell barrel

• tubing (instrumentation and sample lines) and tube couplings

The intended functions identified for the pressurizer components were pressure boundary and

heat transfer.

2.3.1.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.6 and UFSAR Section 5.5.10 to determine whether the

pressurizer within the scope of license renewal and subject to an AMR had been identified in

accordance with 10 CFR 54.4 and 54.21(a)(1). 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

The pressurizer, a safety-related, in-scope component, contains a spray head, a non-safetyrelated component, which the applicant has not included in the license renewal scope. 

The spray head distributes normal and auxiliary pressurizer spray water into the pressurizer

steam bubble, which tends to depressurize the pressurizer, and hence the reactor coolant

system. Since the normal and auxiliary pressurizer sprays are not safety systems, they cannot

be relied upon to function during any of the Chapter 15 accident analyses, unless, in some

postulated analysis cases, pressurizer spray could have an aggravating effect upon the

transient results (e.g., by delaying a high pressurizer pressure reactor trip). Therefore, the

spray function is not credited for the mitigation of any accidents addressed in the UFSAR

accident analyses.

As a non-safety-related component that is wholly enclosed by the pressurizer, a safety-related

component, the pressurizer spray head would be subject to the requirements of

10 CFR 54.4(a)(2), which state, “Plant systems, structures, and components within the scope of

this part are .... All non-safety-related systems, structures, and components whose failure could

prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1)(i),

(ii), or (iii) of this section.” Paragraphs (a)(1)(i), (ii), and (iii) of this section address the integrity

of the reactor coolant pressure boundary, the capability to shut down the reactor and maintain it

in a safe shutdown condition, and the capability to prevent or mitigate the consequences of

accidents which could result in potential offsite exposures, respectively.

Normal and auxiliary pressurizer sprays are used to reduce the primary side coolant pressure,

and to end the primary to secondary side tube break flow, following a steam generator tube

rupture event. If, for some reason, the spray head fails in such a way as to block all spray flow,

then normal and auxiliary sprays would become unavailable for depressurization following a

steam generator tube rupture event. Since there is always some spray flow into the
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pressurizer, during normal operation, it is expected that such a failure would be promptly

detected and rectified. 

If the pressurizer spray head were to degrade and crack, and shed one or more pieces of the

head, these pieces could become loose parts inside the pressurizer. During a pressurization

transient, such as a loss of a normal feedwater event or a load rejection, the power-operated

relief valves, or even the code safety valves, might open. A loose part, inside the pressurizer,

might be drawn into the throat of a power-operated relief valve or a code safety valve, and

impede the ability of the pressurizer and its pressure relieving valves to protect the integrity of

the reactor coolant pressure boundary. Depending upon the position of the loose part, inside

the valve throat, the loose part might prevent the valve from reseating properly, and thereby

transform a pressurization event into a depressurization event.

Although loose pieces of the spray head are not likely to damage the pressurizer itself, these

pieces have the potential to impair certain safety-related functions of the pressurizer, such as

the power-operated relief valves or the safety valves, during pressurization transients. The

possibility that such loose parts might be generated and that they might impair certain safety

functions of the pressurizer is not, by itself, sufficient to require that the pressurizer spray head

be included in the license renewal scope. There must be some basis, in operating experience,

that such a scenario could be reasonably expected to occur sometime during the 20-year

license extension, following a 40-year aging period. To date, there have been no recorded

instances of this type of failure. Therefore, without an experiential basis, the requirements of

10 CFR 54.4(a)(2) would not be applicable to the pressurizer spray head.

By letter dated April 9, 2003, the staff requested the applicant to indicate whether the

pressurizer spray head is credited in the fire protection safe shutdown analysis to satisfy

10 CFR 50.48, Appendix R requirements. Section 54.4(a)(3) of Title 10 of the Code of Federal

Regulations requires that components that are used to satisfy the requirements of

10 CFR 50.48, Appendix R, must be included within the scope of license renewal. The specific

intended function of the spray head that is subject to the 10 CFR 54.4(a)(3) requirement is the

spray function. The spray head does not have a pressure boundary function. 

In response, the applicant stated that the pressurizer spray is not credited to depressurize the

reactor coolant system in the Appendix R event. Primary system depressurization is

accomplished by opening the pressurizer power-operated relief valves. Therefore, the

applicant has included the power-operated relief valves, not the pressurizer spray head, within

the scope of license renewal. At the staff’s request, the applicant has confirmed that the

pressurizer power-operated relief valves are included in the license renewal scope. They are

listed in Table 2.3-2, under Valves”.

Therefore, since the spray head (1) does not perform any intended functions, (2) its failure

would not prevent satisfactory accomplishment of any of the functions identified in 10 CFR

54.4(a)(1), and (3) it is not relied upon to depressurize the reactor coolant system in an

Appendix R scenario, the staff agrees with the applicant’s conclusion that the spray head need

not be within the scope of license renewal.

No omissions of SSCs that are within the scope of license renewal and subject to an Aging

Management Review, were found.
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2.3.1.6.3 Conclusions

The staff reviewed LRA Section 2.3.1.6 and UFSAR Section 5.5.10 to determine whether any

SSCs within the scope of license renewal had not been identified by the applicant. In addition,

the staff performed an independent assessment to determine whether any components subject

to an AMR had not been identified by the applicant. No omissions were found. On the basis of

this review, the staff concludes that the applicant has adequately identified the pressurizer

SSCs that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the pressurizer SSCs that are subject to an Aging

Management Review, as required by 10 CFR 54.21(a)(1).

2.3.1.7 Steam Generators

The applicant describes the steam generators in LRA Section 2.3.1.7 and provides a list of

components subject to an AMR, along with their component intended functions, in LRA Table

2.3-7. UFSAR Section 5.5.2, Steam Generators, provides additional information concerning the

steam generators.

2.3.1.7.1 Summary of Technical Information in the Application

VCSNS is equipped with three Westinghouse Delta-75 feedring-type steam generators. The

steam generators can be described as vertical shell and inverted U-tube evaporators with

integral moisture separating equipment. The reactor coolant flows through the U-tubes,

entering and leaving through the nozzles located in the hemispherical bottom head of the steam

generator. The head is divided into inlet and outlet chambers by a vertical partition plate

extending from the head to the tubesheet. Manways are provided for access to both sides of

the divided head. 

The feedwater enters at approximately two-thirds (2/3) of the steam generator height and is

distributed uniformly around the circumference of the steam generator shell, through a feedring.

Feedwater enters the tube bundle by flowing downward between the steam generator external

shell and inner wrapper barrel. An open area at the bottom of the wrapper barrel permits the

feedwater to enter the tube bundle. Steam is generated and flows upward through the moisture

separators and flow restrictor outlet nozzle at the top of the steam drum. High efficiency

centrifugal steam separators remove most of the entrained water. Dryers are employed to

increase the steam quality to a minimum of 99.90 percent (0.10 percent moisture).

The steam generators were installed during the Refuel 8 outage, in the fall of 1994. They

replaced the original equipment — Westinghouse model D3 steam generators. The D3 steam

generator design had employed an integral preheater at the feedwater inlet. The total steam

generator heat transfer surface area is relatively greater in the Delta-75, in order to account for

the thermal performance characteristics of the preheaters in the original D3 steam generators. 

In order to facilitate the replacement, key dimensions of the Delta-75 steam generators are

identical to those of the original D3 steam generators. The performance characteristics of the

Delta-75 steam generators match or exceed those of the original steam generators.

2.3.1.7.2 Staff Evaluation
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The staff reviewed LRA Section 2.3.1.7 and UFSAR Section 5.5.2 to determine whether the

steam generator components are within the scope of license renewal and subject to an AMR

had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

Among the components included in the license renewal scope are the steam generator

feedwater distribution rings and the integral steam outlet nozzle flow-limiting venturis.

The staff observes, only as a point of interest, that since the VCSNS steam generators were

replaced in 1994, they will be 48 years old by the end of the extended license period, in 2042. 

For these particular steam generators, therefore, the license extension period would amount to

8 years, not 20. 

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.

2.3.1.7.3 Conclusions

The staff reviewed LRA Section 2.3.1.7 and UFSAR Section 5.5.2, Steam Generators, to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components subject to an AMR had not been identified by the applicant. No omissions

were found. On the basis of this review, the staff concludes that the applicant has adequately

identified the steam generator SSCs that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the steam generator SSCs

that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2 Engineered Safety Features Systems

Engineered safety features (ESF) are provided to mitigate the consequences of postulated

accidents up to and including a design basis accident. The ESF systems provided for VCSNS

have sufficient redundancy and independence of components and power sources that, under

postulated accident conditions, (1) core cooling limits the core thermal transient, (2) reactor

building structural integrity is maintained, and (3) radiation dose to the public is maintained

within the limits of 10 CFR Part 100, are accomplished.

2.3.2.1 Chemical and Volume Control

The applicant describes the chemical and volume control system in LRA Section 2.3.2.1 and

provides a list of components subject to an AMR, along with their component intended

functions, in LRA Table 2.3-8. UFSAR Section 6.3, Emergency Core Cooling System, and

UFSAR Section 9.3.4, Chemical and Volume Control System, provide additional information

concerning the chemical and volume control system.
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2.3.2.1.1 Summary of Technical Information in the Application

The chemical and volume control system is designed to perform the following functions, with

respect to the reactor coolant system:

• maintenance of programmed water level in the pressurizer (i.e., maintain required water

inventory in the reactor coolant system

• maintenance of seal-water injection flow to the reactor coolant pumps

• control of reactor coolant water chemistry conditions, activity level, soluble chemical

neutron absorber concentration and makeup

• provide means for filling, draining, and pressure testing of the reactor coolant system

• emergency core cooling (part of the system is shared with the emergency core cooling

system)

The component types which were identified for the chemical and volume control system include

agitators and mixers, demineralizers, filters, flexible couplings, gearboxes, heat exchanger

channel heads, shells, tubesheets and tubes orifices, pipe, pressure-retaining instrumentation,

oil reservoirs, pump bearing housings and casings, tanks, tubes and tubefittings, and valve

bodies. The intended functions identified for the chemical and volume control system

components were pressure boundary, filtration, throttling, and heat transfer.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and UFSAR Sections 6.3 and 9.3.4 to determine

whether the chemical and volume control system components and supporting structures within

the scope of license renewal and subject to an AMR had been identified in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the

chemical and volume control system, and associated pressure boundary components, and

compared the information in the UFSAR with the information in the LRA to identify those

portions that the LRA did not identify as being within the scope of license renewal and subject

to an AMR. The staff then reviewed the SCs that were identified as not being within the scope

of license renewal to verify that these SCs do not have any of the intended functions delineated

under 10 CFR 54.4(a), and for those SCs that have an applicable intended function(s), to verify

that they either perform this function(s) with moving parts or a change in configuration or

properties, or that they are subject to replacement based on a qualified life or specified time

period, as described in 10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4 (a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such
2-46

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 

Since part of the chemical and volume control system (e.g., the charging pumps) is shared with

the emergency core cooling system (see Section 2.3.2.7 of this report, Safety Injection

System), certain components of the chemical and volume control system are used to perform

the safety-related functions specified in 10 CFR 54.4(a)(1). The chemical and volume control

system operates in conjunction with the refueling water, residual heat removal, and safety

injection systems to deliver borated emergency core cooling water to the reactor coolant system

following a LOCA. During the injection phase, the centrifugal charging pumps in the chemical

and volume control system, along with the residual heat removal pumps, draw suction from the

refueling water storage tank and inject borated water directly into the reactor coolant system.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.

2.3.2.1.3 Conclusions

The staff reviewed LRA Section 2.3.2.1 and UFSAR Sections 6.3 and 9.3.4 to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

In addition, the staff performed an independent assessment to determine whether any

components subject to an AMR had not been identified by the applicant. No omissions were

found. On this basis, the staff concludes that the applicant has adequately identified the

chemical and volume control system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the chemical

and volume control system components that are subject to an AMR, as required by 10 CFR

54.21(a)(1).

2.3.2.2 Containment Isolation System

2.3.2.2.1 Summary of Technical Information in the Application

The applicant describes the containment isolation system in LRA Section 2.3.2.2 and provides a

list of components subject to an AMR in LRA Tables 2.3-9, 2.3-10, 2.3-11, and 2.3-12. The

system is further described in UFSAR Section 6.2.4, Containment Isolation System.

The objective of the containment isolation system is to allow the passage of fluids through the

containment boundary under normal and accident conditions, while preserving the integrity of

the containment boundary, when required to prevent or limit the escape of fission products as a

result of a postulated LOCA.

The containment isolation system is not an independent system. Rather, the system is

comprised of specific features included in each piping system that penetrates the reactor

building. Actuation of containment isolation is accomplished through the engineered safety

features actuation system.

Four systems at VCSNS have been identified whose only mechanical license renewal function

is to provide containment isolation. These systems are — auxiliary coolant (closed loop)/CRDM
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cooling water (AC), demineralized water — nuclear services (DN), nitrogen blanketing (NG),

and reactor building leak rate testing (LR).

The auxiliary coolant/CRDM AC system is designed to remove heat from the containment air

used to cool the CRDM and dissipate this heat to the atmosphere via the industrial cooler.

The DN system is designed to distribute demineralized water to the nuclear steam supply

system (NSSS), secondary (turbine) cycle, and other miscellaneous plant systems.

The NG system is designed to provide pressurized nitrogen to hose connections located inside

containment.

The reactor building leak rate testing system is designed to permit containment leakage testing

in accordance with 10 CFR Part 50, Appendix J.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and UFSAR Section 6.2.4 to determine whether the

containment isolation system components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions. 

2.3.2.2.3 Conclusions

The staff reviewed the LRA, the accompanying scoping boundary drawings, and the applicant’s

RAI response to determine whether any SSCs within the scope of license renewal had not been

identified by the applicant. No omissions were found. In addition, the staff performed an

independent assessment to determine whether any components subject to an AMR had not

been identified by the applicant. No omissions were found. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the containment

isolation system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has adequately identified the components of the containment isolation

system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.3 Hydrogen Removal — Post Accident System

2.3.2.3.1 Summary of Technical Information in the Application

The applicant describes the hydrogen removal — post accident system in LRA Section 2.3.2.3

and provides a list of components subject to an AMR in LRA Table 2.3-13. The system is

further described in UFSAR Section 6.2.5, Combustible Gas Control in Reactor Building.
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The hydrogen removal — post accident system is designed for control of combustible hydrogen

concentrations in the reactor building following a LOCA. The system uses electric hydrogen

recombiners as a primary means of reducing hydrogen concentrations, while a purge system is

provided as a backup to the recombiners.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and UFSAR Section 6.2.5 to determine whether the

hydrogen removal—post accident system components within the scope of license renewal and

subject to an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1),

respectively. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions. 

2.3.2.3.3 Conclusions

The staff reviewed the LRA and the accompanying boundary drawings to determine whether

any SSCs within the scope of license renewal had not been identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the hydrogen removal—post accident system that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components of the hydrogen removal—post accident system that

are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.4 Reactor Building Spray System

2.3.2.4.1 Summary of Technical Information in the Application

The applicant describes the reactor building spray system in LRA Section 2.3.2.4 and provides

a list of components subject to an AMR in LRA Table 2.3-14. The system is further described

in UFSAR Section 6.2.2, Reactor Building Heat Removal Systems.

The basic functions of the reactor building spray system are to (1) remove the thermal energy

released to containment by a LOCA at a rate sufficient to limit the resulting over-pressurization

to a level below the design limit, thereby maintaining containment structural integrity, and (2) to

subsequently reduce the over-pressure to a level that minimizes the pressure differential which

induces leakage out of containment. An additional function of the reactor building spray system

is to reduce the concentration of airborne radioactive iodine in the containment atmosphere.

These functions are accomplished by spraying water containing sodium hydroxide into the

containment atmosphere to absorb heat, condense steam, and remove airborne radioactive

iodine from the steam-air atmosphere.
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During normal plant operation, the reactor building spray system is in a standby condition. 

Operation of the system is automatically initiated following a LOCA or main steam line break

(MSLB) by signals from the engineered safety features (ESF) actuation system, when the

reactor building pressure increases to the actuation set point.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and UFSAR Section 6.2.2 to determine whether the

reactor building spray system components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions. 

2.3.2.4.3 Conclusions

The staff reviewed the LRA and the accompanying boundary drawings to determine whether

any SSCs within the scope of license renewal had not been identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the reactor building spray system that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the reactor building spray system that are subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.2.5 Refueling Water System

2.3.2.5.1 Summary of Technical Information in the Application

The applicant describes the refueling water system in LRA Section 2.3.2.5 and provides a list of

components subject to an AMR in LRA Table 2.3-15. The system is further described in

UFSAR Section 6.3, Emergency Core Cooling System, and UFSAR Section 9.1.3, Spent Fuel

Cooling System.

The primary function of the refueling water system is to support refueling operations, refueling

water cleanup, spent fuel pool makeup, and other borated water needs associated with plant

operations. The refueling water system also operates in conjunction with the chemical and

volume control, residual heat removal, and safety injection systems to deliver borated

emergency core cooling water to the reactor coolant system following a LOCA. During the

injection phase, the refueling water storage tank provides an adequate supply of borated water

for the residual heat removal and centrifugal charging pumps for injection directly into the

reactor coolant system.
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2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 and UFSAR Sections 6.3 and 9.1.3 to determine

whether the refueling water system components within the scope of license renewal and subject

to an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. 

The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG1800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions. 

2.3.2.5.3 Conclusions

The staff reviewed the LRA and the accompanying boundary drawings to determine whether

any SSCs within the scope of license renewal had not been identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the refueling water system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the refueling water system that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.2.6 Residual Heat Removal System

The applicant describes the residual heat removal system in LRA Section 2.3.2.6 and provides

a list of components subject to an AMR, along with their component intended functions, in LRA

Table 2.3-16. The license renewal evaluation boundaries for the residual heat removal system

are depicted on drawing E-302-641, Residual Heat Removal. UFSAR Section 6.3, Emergency

Core Cooling System, provides additional information concerning the residual heat removal

system.

2.3.2.6.1 Summary of Technical Information in the Application

The primary function of the residual heat removal system is to remove radioactive decay heat

energy from the core, and sensible and pump heat from the reactor coolant system during plant

cooldown and refueling operations. The residual heat removal system also operates in

conjunction with the chemical and volume control, refueling water and safety injection systems

to deliver borated emergency core cooling water to the reactor coolant system following a

LOCA.

The system operation is categorized in two phases, injection and recirculation. During the

injection phase, the residual heat removal pumps, along with the centrifugal charging pumps in

the chemical and volume control system, draw suction from the refueling water storage tank

and inject borated water directly into the reactor coolant system. During the recirculation

phase, the residual heat removal pumps draw suction from the containment sump, remove
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decay heat via the residual heat removal system heat exchangers, and then deliver flow to the

charging pumps suction and to the reactor coolant system. As during the injection phase, the

charging pumps then inject borated water directly into the reactor coolant system.

The component types which were identified for the residual heat removal system include heat

exchanger channel heads, shells, tubesheets and tubes, orifices, pipe, tubes and tube fittings,

pump casings, and valve bodies. The intended functions identified for the residual heat

removal system components were pressure boundary, throttling, and heat transfer.

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 and UFSAR Section 6.3, Emergency Core Cooling

System, to determine whether the residual heat removal system components and supporting

structures within the scope of license renewal and subject to an AMR had been identified in

accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The

staff review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the residual

heat removal system and associated pressure boundary components and compared the

information in the UFSAR with the information in the LRA to identify those portions that the LRA

did not identify as being within the scope of license renewal and subject to an AMR. The staff

then reviewed the SCs that were identified as not being within the scope of license renewal to

verify that these SCs do not have any of the intended functions delineated under

10 CFR 54.4(a), and for those SCs that have an applicable intended function(s), to verify that

they either perform this function(s) with moving parts or a change in configuration or properties,

or that they are subject to replacement based on a qualified life or specified time period, as

described in 10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4(a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 

Since the residual heat removal system also operates in conjunction with the refueling water,

chemical and volume control, and safety injection systems to deliver borated emergency core

cooling water to the reactor coolant system following LOCA, certain components of the residual

heat removal system are used to perform the functions specified in 10 CFR 54.4(a)(1). 

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found. 

2.3.2.6.3 Conclusions

The staff reviewed LRA Section 2.3.2.6 and UFSAR Section 6.3, Emergency Core Cooling

System, to determine whether any SSCs within the scope of license renewal had not been

identified by the applicant. In addition, the staff performed an independent assessment to
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determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On this basis, the staff concludes that the applicant has adequately

identified the residual heat removal system components that are within the scope of license

renewal as required by 10 CFR 54.4(a) and that the applicant has adequately identified the

residual heat removal system components that are subject to an AMR as required by 10 CFR

54.21(a)(1).

2.3.2.7 Safety Injection System

The applicant describes the safety injection system in LRA Section 2.3.2.7 and provides a list of

components subject to an AMR, along with their component intended functions, in LRA Table

2.3-17. UFSAR Section 6.3, Emergency Core Cooling System, provides additional information

concerning the safety injection system.

2.3.2.7.1 Summary of Technical Information in the Application

The safety injection system pumps borated water into the reactor coolant system to provide

emergency core cooling following a LOCA. This provides core cooling to ensure there is no

significant alteration of core geometry, no clad melting, no fuel melting, and less than one

percent cladding water reaction. This also limits fission product release and ensures adequate

shutdown margin regardless of temperature. The safety injection system also provides

continuous long-term post-accident cooling of the core by recirculation of borated water from

the containment recirculation line inlet located in the containment sump.

In the event of an accident, two charging pumps are started automatically on receipt of a safety

injection signal and are automatically aligned to take suction from the refueling water storage

tank during injection. The centrifugal charging pumps deliver borated water at the prevailing

reactor coolant system pressure to the cold legs of the reactor coolant system. The residual

heat removal pumps take suction from the refueling water storage tank and deliver borated

water to the reactor coolant system. These pumps begin to deliver water to the reactor coolant

system only after the pressure has fallen below the pump shutoff head. During recirculation,

suction is provided by the residual heat removal pumps.

The safety injection signal is actuated by any of the following:

• low pressurizer pressure

• high reactor building pressure

• high differential pressure between any two steam lines

• low steam line pressure

• manual actuation

Operation of the emergency core cooling system during the injection mode is completely

automatic. The safety injection signal automatically initiates the following actions

• starts the emergency diesel generators, which if all other sources of power are lost,

supplies the engineered safety feature buses

• starts the charging pumps and the residual heat removal pumps
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• aligns the charging pumps for injection

The injection mode continues until the residual heat removal pumps have been realigned to the

recirculation mode. During the injection mode, all pumps take suction from the refueling water

storage tank until a lo-lo level signal from the refueling water storage tank aligns the residual

heat removal pumps to take suction from the reactor building sump.

After the injection operation, water collected in the reactor building sump is cooled and returned

to the reactor coolant system via the low/high head recirculation flow paths. The residual heat

removal pumps are aligned to take suction from the reactor building sump, to deliver directly to

the reactor coolant system and to supply suction to the charging pumps. The charging pumps

deliver flow directly to the reactor coolant system cold legs. This latter mode of operation

assures flow in the event of a small rupture where the depressurization proceeds more slowly

such that the reactor coolant system pressure is still in excess of the shutoff head of the

residual heat removal pumps at the onset of recirculation.

The safety injection system component types, listed in Table 2.3-17 of the LRA, include orifices,

pipe, tanks, tube and tube fittings, and valve bodies. The intended functions identified for the

safety injection system components were pressure-retaining boundary and throttling.

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.7 and UFSAR Section 6.3, Emergency Core Cooling

System, to determine whether the safety injection system components and supporting

structures within the scope of license renewal and subject to an AMR had been identified in

accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The

staff review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the safety

injection system and associated pressure boundary components and compared the information

in the UFSAR with the information in the LRA to identify those portions that the LRA did not

identify as being within the scope of license renewal and subject to an AMR. The staff then

reviewed the SCs that were identified as not being within the scope of license renewal to verify

that these structures and components do not have any of the intended functions delineated

under 10 CFR 54.4(a), and for those SCs that have an applicable intended function(s), to verify

that they either perform this function(s) with moving parts or a change in configuration or

properties, or that they are subject to replacement based on a qualified life or specified time

period, as described in 10 CFR 54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4 (a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.
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2.3.2.7.3 Conclusions

The staff reviewed LRA Section 2.3.2.7 and UFSAR Section 6.3, Emergency Core Cooling

System, to determine whether any SSCs within the scope of license renewal had not been

identified by the applicant. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On this basis, the staff concludes that the applicant has adequately

identified the safety injection system components that are within the scope of license renewal

as required by 10 CFR 54.4(a) and that the applicant has adequately identified the safety

injection system components that are subject to an AMR as required by 10 CFR 54.21(a)(1).

2.3.3 Auxiliary Systems

The auxiliary systems are those systems used to support normal and emergency plant

operations. The systems provide cooling, ventilation, sampling, and other required functions.

2.3.3.1 Air Handling and Local Ventilation and Cooling Systems

2.3.3.1.1 Summary of Technical Information in the Application

The applicant describes the air handling and local ventilation and cooling systems in LRA

Section 2.3.3.1 and provides a list of components subject to an AMR in LRA Table 2.3-18.

UFSAR Section 9.4, Air Conditioning, Heating, Cooling and Ventilation Systems, provides

additional information for these systems. 

The following systems are included in the air handling and local ventilation and cooling systems:

1.1 Control Building Area Ventilation Systems

1.2 Auxiliary and Radwaste Area Ventilation System

1.3 Fuel Handling Building Ventilation

1.4 Intermediate Building Ventilation Systems

1.5 Miscellaneous Building Ventilation and Cooling Systems

1.6 Reactor Building Cooling and Filtering Systems

These systems are described below.

Control Building Area Ventilation Systems

The control building area ventilation systems (CBAVS) consist of control room system, relay

room system, computer room system, controlled access area supply system, miscellaneous

room systems, controlled access area exhaust system, and computer rooms and safety

assessment system (SAS) room cooling system. The control room and relay room ventilation

systems are designed, protected and arranged with sufficient redundancy to ensure system

cooling and filtering operation after a LOCA. The ventilation systems in the control room and

relay room areas are independent of each other. Each area is served by two separated,

independent heating, ventilation, and air conditioning (HVAC) and filtering subsystems, which

are supplied from separate Class 1E electric power supplies.
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The control room ventilation system continuously supplies filtered, cooled, or heated air to the

control room, technical support center, and cable spreading area during normal conditions. 

Filtered and cooled air is provided during post accident and loss of offsite power conditions. 

The control room ventilation system consists of two 100 percent-capacity air handling units with

cooling coils, two 100 percent-capacity emergency filter systems, and electric reheat coils in the

supply ducts, controls, and associated dampers and ductwork. 

The relay room ventilation system continuously supplies filtered, cooled, or heated air to the

relay room under normal conditions. Filtered and cooled air is provided under post accident

and loss of offsite power conditions. The cooling coil is supplied by the safety-related chilled

water system. The relay room system consists of two 100 percent-capacity air handling units

with roughing filters, chilled water cooling coil and fan section, electric reheat coils in the supply

ducts, controls, and associated dampers and ductwork.

The gaseous activity channel of the radiation monitor automatically closes the outside air

dampers of the relay room and places both systems in recirculation or emergency mode upon

detection of high gaseous activity in the air supplied to the control room. 

During normal and emergency operations, the control room is pressurized through the

introduction of a fixed amount of outside air. The flow of outside air to the relay room is fixed

but is manually adjustable. In the emergency mode, control room air is filtered through

roughing, high efficiency particulate air (HEPA), and charcoal filters. Recirculated air in the

relay room is not filtered.

For smoke removal, system dampers for both control and relay room systems can be

positioned manually to purge with outside air at rates up to 100 percent. Prior to purging the

control room, the relief damper and outside air duct blanking plates must be removed in

conjunction with closing the system return air damper.

The computer room system continuously supplies filtered, cooled, or heated air to the computer

room under normal and post accident conditions whenever offsite power is available by two -

100 percent-capacity air handling units. The cooling coil is supplied by the non-safety-related

chilled water system. The units are connected to Class 1E power buses. The units are

normally operated from the control room.

The controlled access area supply system continuously supplies filtered, cooled, or heated air

to the four zones of the controlled access area under normal and post accident conditions

whenever offsite power is available. The system is connected to Class 1E buses.

The controlled access area exhaust system operates continuously under normal and

emergency conditions whenever offsite power is available. The main components of the

system include a 100 percent-capacity controlled access area filter plenum, including roughing

filters, HEPA filters, charcoal filters, and post-HEPA filters down stream of the charcoal filters.

The SAS/central processing unit (CPU) computer rooms cooling system continuously supplies

filtered, cooled, or heated air to the SAS/CPU computer rooms when normal power is available

by a 32 percent-capacity air handling unit and a 68 percent-capacity air handling unit including

roughing filters. Chilled water is provided by the non-safety-related chilled water system.
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The microwave relay room system continuously supplies filtered, cooled, or heated air to the

microwave relay room when normal power is available by a 100 percent-capacity air

conditioning unit, including refrigeration system, electric heating coil, and fan. 

The microwave battery room system continuously exhausts air from the microwave battery

room to the atmosphere when normal power is available by a 100 percent-capacity exhaust fan.

The control building office space system provides cooling for personnel comfort by a 100

percent-capacity air handling unit with roughing filter and refrigerant coil and a 100 percentcapacity remotely mounted condensing unit including compressor and controls.

The control building elevator machine room system cyclically exhausts air from the elevator

machine room to the atmosphere in response to a room thermostat by a 100 percent-capacity

exhaust fan and a 100 percent-capacity electric unit heater when normal power is available.

The license renewal boundaries of the CBAVS are depicted on the following P&ID drawings:

• D-806-001, Radiation Monitoring System Flow Diagram

• D-912-136, Relay and Computer Room Cooling System Flow Diagram

• D-912-140, Control Room Normal and Emergency Air Handling System Flow Diagram

• D-912-141, Technical Support Center and Main Control Board Ventilation Flow Diagram

• D-912-154, Computer Rooms and SAS Room Cooling Unit System Flow Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the CBAVS:

• to maintain ambient air temperatures in all areas as required for the comfort and safety

of personnel

• to satisfy environmental requirements of equipment

• to meet the radiation control requirements of 10 CFR Part 20

• to satisfy the design requirements of General Design Criterion 19, relative to the control

room

In LRA Table 2.3-18, the applicant identified the component types for the CBAVS that are

subject to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component

types and commodities groups (combinations of materials and environments) that are within the

AMP that are evaluated in NUREG-1801, Generic Aging Lessons Learned (GALL) Report.”

Auxiliary and Radwaste Area Ventilation System

The auxiliary and radwaste area ventilation system (ARAVS) consists of auxiliary building main

supply system, auxiliary building HEPA exhaust system, auxiliary building charcoal exhaust

system, auxiliary building main exhaust system, auxiliary building pump room and motor control

center cooling systems, hot machine shop ventilation system, and fuel handling building

charcoal exhaust system and air supply distribution. The ARAVS maintains ambient air

temperature in all areas between minimum and maximum levels suitable for personnel and
2-57

equipment. It also minimizes the release of radioactive airborne particulates and gaseous

activity to the atmosphere and provides filtration for the refueling water storage tank vent

discharge. 

The ARAVS, excluding pump room, motor control center, and switchgear cooling units

(elevations 412’ and 463’), is not a safety-related system. However, redundant fans are

provided for the main exhaust, the charcoal exhaust, and the HEPA exhaust systems. 

Charcoal exhaust fans and plenums are physically separated, housed in shielded concrete

enclosures, and the fans receive power from the Class 1E electric system. All charcoal and

HEPA filter plenums are constructed in accordance with Seismic Category I requirements. 

Radiation levels in the charcoal filters, the exhaust from the gas decay vent, and the main plant

vent exhaust are monitored from the control room. 

The auxiliary building pump room cooling system serves each charging pump, residual heat

removal and reactor building spray pump room with a 100 percent-capacity air handling unit

consisting of a fan section, chilled water coil, and a roughing filter. The air handling units are

powered from Class 1E electric system. The ventilation units are administratively controlled

from the control room during normal operation or refueling. 

The safety-class motor control center and switchgear areas of the auxiliary building (elevations

412’ and 463’) are served by three 100 percent-capacity air handling units. The safety-related

air handling units include a fan section, chilled water coil, and roughing filter. Power is suppled

to the safety-related units from separated and independent Class 1E power sources.

The license renewal boundaries for the ARAVS are depicted on the following P&ID drawings:

• D-912-132, Auxiliary Building Pump Room Cooling System Flow Diagram

• D-912-120, Auxiliary Building HEPA System Flow Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the ARAVS:

• to maintain ambient air temperatures in all areas between minimum and maximum

levels suitable for personnel and equipment

• to minimize the release of radioactive airborne particulate and gaseous activity to the

atmosphere

• to provide for filtration of the refueling water storage tank vent discharge

In LRA Table 2.3-18, the applicant identified the component types for the ARAVS that are

subject to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component

types and commodities groups (combinations of materials and environments) that are within the

AMP that are evaluated in the GALL Report.

Fuel Handling Building Ventilation

The fuel handling building ventilation (FHBV) consists of fuel handling building supply 
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and charcoal exhaust system. The FHBV continuously supplies outside air that has been

drawn through the auxiliary building supply air plenums where it is filtered and heated as

required. Ventilation exhaust air flow is directed from areas of low to progressively higher

activity. 

The total exhaust from the fuel handling building is drawn through the HEPA charcoal filters and

ducted to the auxiliary building main exhaust fans and the main plant vent. Both fuel handling

building exhaust fans operate following a loss of offsite power.

The exhaust system fans and filters are separated, shielded, and served by separate Class 1E

electric power supplies. The fans and filters are Seismic Category I located in a Seismic

Category I structure that are protected from floods, weather, external missiles, jet impingement,

or pipe whip.

The supply and exhaust system are administratively controlled during normal operation or

refueling. However, the exhaust system starts automatically upon loss of offsite power, thus

ensuring that a negative pressure is maintained in the fuel handling building. 

Exhaust air from the spent fuel area and from potentially radioactive areas of the fuel handling

building are monitored for particulate, iodine, and gaseous activity. A control room alarm is

actuated upon detection of high radiation. An ex-filtration analysis of the fuel handling building

has been performed to verify that offsite doses resulting from a fuel handling accident inside the

fuel handling building do not exceed 10 CFR Part 100 guidelines.

The license renewal boundaries of the FHBV are depicted on the following P&ID drawings:

• D-912-131, Fuel Handling Charcoal Exhaust/Air Supply Distrib. System Flow Diagram

• D-806-002, Radiation Monitoring System Flow Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the FHBV:

• to provide an environment suitable for personnel and equipment in the spent fuel pool

area and the fuel handling building

• to minimize condensation from the fuel pool area and the release of airborne

radioactivity

In LRA Table 2.3-18, the applicant identified the component types for the FHBV system that are

subject to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component

types and commodities groups (combinations of materials and environments) that are within the

AMP and are evaluated in the GALL Report.

Intermediate Building Ventilation Systems

The intermediate building ventilation systems (IBVS) consist of CRDM switchgear room cooling

system, ESF switchgear rooms and speed switchgear rooms cooling systems, battery room

systems, intermediate building ventilation system, intermediate building pump room cooling

systems, and water chiller area ventilation systems. The CRDM switchgear room cooling
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system, intermediate building ventilation system, and water chiller area ventilation systems

operate continuously during all normal and shutdown operations unless normal power is not

available. The intermediate building ventilation system provides heating, cooling, ventilation,

and exhaust for various IBVS to the extent indicated to maintain ambient air temperatures in all

areas between minimum and maximum levels suitable for personnel and equipment.

Because the IBVS are redundant, loss of one of the air handling units or fans will not prevent

system function. For the ESF switchgear rooms cooling systems, one air handling unit serves

the A-channel ESF switchgear and another separate air handling unit serves the B-channel

ESF switchgear.

Safety-related equipment is powered by separated Class 1E power supplies. The units are

administratively controlled from the control room. Upon receipt of a safety injection or loss of

offsite power signal, the ESF switchgear room air handling units and speed switchgear rooms

air handling units are automatically started and operated continuously.

ESF Switchgear Rooms and Speed Switch Room Cooling Systems:

The cooling system has one 100 percent-capacity air handling unit for each ESF switchgear

room, one 100 percent-capacity air handling unit for the “A/C” speed switch room and

evacuation panel room A, and one 100 percent-capacity air handling unit for the “B/C” speed

switch room and evacuation panel room B. Each air handling unit consisted of a roughing filter,

chilled water cooling coil, and a fan/motor section. The ventilation systems also have ductwork

and I&C devices.

Under emergency conditions, the thermostatic control is bypassed, and the air handling units

start and operate continuously following receipt of a safety injector or loss of an offsite power

signal. Power is supplied to the air handling units from separated, independent Class 1E power

sources. The air handling units are located in separate equipment rooms in the intermediate

building.

Battery Room Ventilation Systems:

The battery room ventilation systems have two 100 percent-capacity air handling units, each

with a roughing filter, electric heating coil, face and bypass section, safety-related chilled water

cooling coil, fan and motor section. The battery room also has two 100 percent-capacity

exhaust air fans, isolation dampers, and instrumentation and controls devices.

The battery room ventilation system operates during normal, shutdown, and emergency

conditions. Continuous system operation maintains suitable ambient temperatures and

prevents the accumulation of battery gases in these areas. The battery room air handling units

and exhaust fans are powered by separated Class 1E power sources.

Intermediate Building Pump Room Cooling Systems:

The intermediate building pump room cooling systems have two 100 percent-capacity air

handling units for each of the service water booster pump and emergency feedwater pump

areas. Each air handling unit consists of a roughing filter, safety-related chilled water cooling

coil, fan, and motor section.
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The pump room air handling units start automatically with their respective pump. The air

handling units remove heat generated due to normal equipment operation in the area. Upon

detection of high ambient temperature condition in the area (which may be caused by a high

energy line break), fan operation is prohibited until area temperatures return to design

parameter operational levels. Air handling units are powered by separated Class 1E power

sources and are located in separate equipment rooms in the intermediate building.

The license renewal boundaries for the IBVS are depicted on the following P&ID drawings:

• D-912-138, Battery Rm./Charger Rm./BOP Charger Area Ventilation System Flow

Diagram

• D-912-139, CRDM SWGR Rm. Cooling & Water Chill. Area Vent. System Flow Diagram

• D-912-157, ESF SWGR Rooms/Speed Switch Rooms Cooling Systems Flow Diagram 

• D-912-158, General Ventilation & Pump Area Cooling Systems Flow Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the IBVS:

• to maintain ambient air temperatures in all areas of the intermediate building between

minimum and maximum levels suitable for personnel and equipment

• to furnish continuous outside air ventilation for the battery room ventilation system

In LRA Table 2.3-18, the applicant identified the component types for the IBVS that are subject

to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component types and

commodity groups (combinations of materials and environments) that are within the AMP and

are evaluated in the GALL Report.

Miscellaneous Building Ventilation and Cooling Systems

The miscellaneous building ventilation and cooling systems (MBVCS) consist of diesel

generator building ventilation system, service water pumphouse ventilation system, safetyrelated chilled water system, service building ventilation system, substation relay house cooling

system, penetration access area ventilation system, miscellaneous pump room systems and

lube oil room system, and water treating area laboratory heating and cooling system. Heating,

cooling, ventilation, and exhaust are provided by various MBVCS that maintain ambient air

temperatures in the served areas between minimum and maximum levels suitable for personnel

and equipment. 

The service building ventilation system, substation relay house cooling system, penetration

access areas ventilation system, miscellaneous pump room systems and lube oil room system,

and water treating area laboratory heating and cooling system perform no safety function. The

substation battery room exhaust fan in the substation relay house cooling system prevents the

occurrence of any appreciable hydrogen concentration in the battery room.

The applicant evaluated component supports of the HVAC ductwork listed in LRA Table 3.5-1

for these nonsafety systems. The applicant performed a screening process on components

that support the operation of these HVAC systems in LRA Section 2.1.2.1. The staff’s scoping
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review of SC supports is addressed in Section 2.1.2.2 of this SER. Electrical and I&C

components in the HVAC systems are addressed in Section 2.1.2.3 of this SER. 

 

The diesel generator building ventilation subsystem, service water pumphouse ventilation

subsystem, and safety-related chilled water system of the MBVCS perform safety functions

because loss of heat removal capability of any of these subsystems could result in failure of

components credited for accident mitigation. Each of the subsystems is powered by separated

Class 1E power supplies. Operation of the service water pumphouse ventilation system and

the chilled water system are automatically initiated by receipt of a safety injection or loss of

offsite power signal. Safety-related systems are monitored and alarms are annunciated in the

control room. These subsystems are further discussed below.

Diesel Generator Building Ventilation Subsystem:

The diesel generator building ventilation subsystem is an ESF system. The main components

of the system for each diesel room include two 50 percent-capacity ventilation fans to supply

outside air to the diesel generator room, the diesel generator electric equipment room, and the

diesel generator cable-pipe-basement area.

The fans of the system cycle and associated dampers open and close in response to room

thermostats located in the diesel generator rooms and diesel generator electric equipment

rooms when the diesel generators are not operating. Both fans associated with a diesel 

generator room start automatically and operate continuously whenever the diesel generator in

that room operates. Ventilation air is drawn through roof openings which are shielded from

external tornado missiles and forced into the diesel generator room by fans.

Service Water Pumphouse Ventilation Subsystem:

The service water pumphouse ventilation subsystem is an ESF system. The main components

of the subsystem include two 100 percent-capacity ventilation supply fans that provide outside

air to various areas of the service water pumphouse. 

Either of the two supply fans operates continuously during normal operating periods. Both fans

start automatically following receipt of a safety injection or loss of offsite power signal. The fans

are powered from separate Class 1E power sources.

The license renewal boundaries for the MBVCS are depicted on the following P&ID drawings:

• D-912-134, Diesel Generator Areas System Flow Diagram

• D-912-155, Service Water Intake Screen/Pump House Bldg. Vent. System Flow

Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the MBVCS:

• to provide safety-related function of heat removal capability inside the diesel generator

rooms and diesel generator electric equipment rooms by maintaining these areas at

acceptable ambient air temperatures between minimum and maximum levels suitable

for personnel and equipment
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• to provide safety-related function of heat removal capability inside the service water

pump/screen room areas, related motor control center, and electrical switchgear rooms

by maintaining these areas at acceptable ambient air temperatures between minimum

and maximum levels suitable for personnel and equipment

In LRA Table 2.3-18, the applicant identified the component types for the MBVCS that are

subject to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component

types and commodities groups (combinations of materials and environments) that are within the

AMP and are evaluated in the GALL Report.

Reactor Building Cooling and Filtering Systems

The reactor building cooling and filtering systems (RBCFS) have the safety functions to (1)

maintain the ambient air temperature at a suitable level for continuous operation of equipment

within the building under normal operating and shutdown conditions, (2) provide cleanup of the

reactor building atmosphere to minimize the release of radioactivity to the environment before

purging, and (3) assist other heat removal systems during a post accident conditions.

The RBCFS consists of reactor building cooling system, reactor building purge supply and

exhaust system, post accident hydrogen removal and alternate reactor building purge system,

reactor building charcoal cleanup system, reactor building reactor compartment and cooling

system, reactor building secondary compartment cooling system, reactor building refueling

water surface system and rod position indication cooling system, reactor building CRDM shroud

cooling system, and reactor building elevator machine room system. These systems are further

described below.

Reactor Building Cooling System:

The two cooling units powered from channel-A of the Class 1E electric system are located on

the opposite side of the reactor building from the two cooling units supplied from channel-B. 

Also the cooling water supply and return mains to these units are physically separated as is the

A and B channel wiring. Each unit can operate independently of the others and the discharge

from each unit is isolated from the common air supply main by gravity operated dampers. 

Reactor building cooling system components that must remain intact following a LOCA include

four plenums and all internal components, plenum discharge ducts, common air supply main,

and six vertical supply ducts from the common air supply main to the lower elevation of the

reactor building. The components noted above are designed to remain intact following a LOCA.

Each plenum includes moisture separators, HEPA filters, filter bypass opening and dampers,

cooling coils, and an axial flow fan driven by separate high speed and slow speed motors.

The reactor building cooling unit fans operate at high speed during normal periods, and at slow

speeds during post LOCA periods and reactor building leak rate testing. The units are serviced

by cooling water from the industrial cooling system during normal operation and by service

water system during post LOCA or loss of offsite power conditions. For normal operation, three 

out of four fans operate. For LOCA, one fan in each train operates.
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The units, when operating in the normal mode, are tripped upon the receipt of a safety injection

or loss of offsite power signal, and are then automatically started at slow speed in accordance

with the ESF actuation system and the ESF loading sequence of the related emergency diesel

generator.

The reactor building cooling units can be manually operated from the control room at either high

or slow speed. In response to an ESF loading sequence signal, the unit speed selector

switches in the control room can determine which one of 2A and one of 2B electrical power

channel starts. The plenum unit HEPA filter bypass damper is in the open position during

normal operation and is automatically closed upon receipt of a safety injection signal.

Reactor Building Purge Supply and Exhaust System:

Containment isolation is safeguarded through the use of redundant, fail closed, butterfly valves

on both the purge supply and exhaust lines. Electrical interlocks allow no more than one valve

of a redundant pair of containment isolation valves to be open unless the exhaust system is

operating (one valve of the pair can be open for testing purposes). Automatic closure of the

four containment isolation valves of this system occurs upon receipt of a containment isolation

signal or a high radiation signal. These measures, combined with administrative control of

system operation, ensure that containment air is not released to the atmosphere through

uncontrolled paths. The purge supply and exhaust system are not required to operate during a

post accident period. The purge supply and exhaust isolation valves, as noted above, isolate

the containment and are redundant safety-related equipment.

Alternate Reactor Building Purge System:

Containment isolation is assured through the use of redundant, fail closed, gate valves on both

the alternate purge supply and exhaust lines. Automatic closure of the four containment

isolation valves in the alternate reactor building purge system occurs upon receipt of a

containment isolation signal or a high radiation signal. These measures, combined with

administrative control of system operation, ensure that containment air is not released to the

atmosphere through uncontrolled paths. The alternate reactor building purge system

containment isolation valves and accessories are safety-related.

Reactor Building Charcoal Cleanup System:

Redundancy of the reactor building cleanup units provides iodine removal capability even if one

of the units is not available. This condition extends the required cleanup time prior to purging,

but does not prevent eventual completion of system function. This system is not required to

operate under accident conditions and is not supplied from emergency power sources. The

system is not safety-related.

Reactor Building Reactor Compartment Cooling System, Secondary Compartment Cooling

System, and CRDM Shroud Cooling System:

For each of the three systems, adequate redundancy of system components is provided to

ensure that sufficient cooling capacity is delivered under varying conditions of component

availability. These systems are not required to operate under accident conditions and are not

safety-related.
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Reactor Building Elevator Machine Room System:

The reactor building elevator machine room ventilation system operates in response to the

room thermostat. The system has no post-accident safety function and is not safety-related.

The license renewal boundaries for the RBCFS are depicted on the following P&ID drawings:

• D-912-102, RB Cooling System Flow Diagram

• D-912-103, RB Purge Supply and Purge Exhaust Systems Flow Diagram

• D-912-105, RB Refueling Water Surface System Flow Diagram

In LRA Section 2.3.3.1 and UFSAR Section 9.4.1, the applicant identified the following intended

functions for the RBCFS:

• to maintain an average reactor building air temperature below a maximum of 120 °F

during normal power operation as assumed in the accident analyses and below 100 °F

during refueling operations for personnel comfort and safety

• to maintain an average reactor building air temperature above 60 °F during shutdown

conditions for personnel comfort and safety

• to provide forced air cooling in sufficient capacity to remove CRDM heat and reject it to

the general reactor building atmosphere

• to provide reactor building cleanup capacity to reduce airborne radioiodine levels prior to

personnel entry and to minimize radioactivity released during reactor building purging

In LRA Table 2.3-18, the applicant identified the component types for the RBCFS that are

subject to an AMR. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the component

types and commodities groups (combinations of materials and environments) that are within the

AMP and are evaluated in the GALL Report.

2.3.3.1.2 Staff Evaluation

Control Building Area Ventilation System

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9.4.1 to determine whether the

CBAVS components are within the scope of license renewal in accordance with 10 CFR 54.4

and are subject to an AMR in accordance with the requirements of 10 CFR 54.4 and 10 CFR

54.21(a)(1), respectively. The staff's review was conducted in accordance with Section 2.3 of

the SRP-LR (NUREG-1800) and is described below. 

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not 

omitted from the scope of the license renewal Rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted. 

During its review, the staff determined that additional information was needed to complete its

review. In a letter dated March 28, 2003, the staff asked the applicant in RAIs 2.3.3.1-1 and
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2.3.3.1-4 why the system damper and filter housings and their intended functions are not listed

in LRA Table 2.3-18. Also, in RAI 2.3.3.1-6, the staff asked whether the instrument housings

and their associated tubing are subject to an AMR. By letter dated June 12, 2003, the applicant

stated that the CBAVS damper and filter housings, and instrument housings and their

associated tubing, are subject to an AMR if they are in scope (if they are in the pressure

boundary of a system). The license renewal boundaries of these damper housings are

highlighted on the P&ID drawings and are included with ductwork in the application (Table

3.3-2, Item 2 for stainless steel and Item 3 for carbon and galvanized steel, provides more

description). The filter housings (with a license renewal intended function) are highlighted on

the P&ID drawings and are included in LRA Table 2.3-18 (in the groups of ductwork, fan, and

plenum housings). The applicant further clarified that the CBAVS instruments and instrument

tubing in scope are highlighted on the applicable P&ID drawings, and instrument tubing is listed

in LRA Table 2.3-18. However, the instruments are active components and are not listed in

LRA Table 2.3-18 for an AMR . 

The staff reviewed the applicant’s response and found it acceptable concerning the CBAVS

housings for dampers, filters and instruments, and associated instrument tubings because it

clarified the pertinent information on the system components that are within the scope of

license renewal, as required by 10 CFR 54.21(a)(1).

The staff also asked the applicant, in RAI 2.3.3.1-2, to clarify whether ductwork turning vanes,

ventilation system elastomer seals, ventilation equipment vibration isolator flexible connections,

ductwork test connections, and ductwork access doors are within the scope of license renewal

and subject to an AMR. By letter dated June 12, 2003, the applicant provided the following

clarification for the CBAVS components:

• ductwork turning vanes are part of the subcomponent of the ductwork and are made of

the same material as the ductwork (galvanized steel or stainless steel) and are bounded

by the AMP for the ductwork

• flexible seals between duct and housings are in scope and included in LRA Table

2.3-18, and its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are

considered as consumables that do not perform an intended function as a pressure

boundary and are not subject to an AMR

• ductwork flexible connections are in scope and are listed in LRA Table 2.3-18 (its AMP

is described in LRA Table 3.3-1, Item 2). The components with vibration isolator

flexible connections” are not within the scope of license renewal

• ductwork test connections and ductwork access doors are considered part of the

ductwork and are included in that component group in LRA Tables 2.3-18, 3.3-1 and

3.3-2. Ductwork test connections are typically holes that are normally filled with a push

penny.” The push penny is not required for the system to meet its license renewal

intended function

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the CBAVS components that are within the scope of license renewal

and subject to an AMR, as required by 10 CFR 54.21(a)(1).
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Additionally, the staff also asked the applicant, in RAIs 2.3.3.1-3 and 2.3.3.1-7, to clarify

whether structural sealants used to maintain the pressure boundary of the main control room

envelope at design pressure, with respect to the adjacent areas, are within the scope of license

renewal and subject to an AMR. The staff also requested the applicant to provide information

relating to structural sealants as referenced in Table 2.1-3 (on page 2.1-15) of NUREG 1800. 

By letter dated June 12, 2003, the applicant provided the following clarification for the CBAVS

components:

• the applicant’s position on consumables is consistent with NUREG-1800, Table 2.1-3. 

Packing, gaskets, component seals, and O-rings are subcomponents of structural

components that are excluded from an AMR for several reasons. ASME code indicates

that gaskets, packing, and O-rings do not serve as pressure boundaries and are

therefore excluded from an AMR. Seal material on components, such as doors, do not

perform system intended function. They are replaced periodically based on testing

results and are not subject to an AMR. Seals and O-rings for structural components are

not treated individually, but rather as parts of their host components (doors, airlocks,

hatches, etc.) which are managed under the AMPs and plant procedures. Oil, grease,

and component filters are short-lived with periodic replacement and are excluded from

an AMR. System filters, fire extinguishers, fire hoses, and air packs are discussed in

LRA Section 2.1.2.1.4:

• The terminology of structural sealants” as identified in RAI 2.3.3.1-3 and NUREG-1800

is not used at the plant. However, structural sealants would include fire door seals and

coatings, pressure seals, expansion joints, etc., all of which are addressed in the LRA. 

The applicant recognizes that locations exist where these materials or component types

are important in maintaining the integrity of the component to which they are connected. 

For these situations, the license renewal, or component intended function supported by

the sealant, is to maintain the building pressure boundary envelope. The pressure

boundary function is addressed by surveillance testing to demonstrate compliance with

technical specifications.

• These structural sealant materials (i.e., expansion joints, caulking, seals, etc.) discussed

above are considered to be consumables. Various inspection programs, as addressed

in the LRA (B.1.5, B.1.11, B.1.12, B.1.16, B.1.18, and B.1.20), will determine their

replacement. The life of these materials is based on identification of wear or damage

during these inspections. Programmatic actions are not to manage their life, but rather

to replace them when their conditions are no longer acceptable for service. These

materials are subject to periodic replacement and, therefore, are not subject to an AMR,

as required by 10 CFR 54.21(a)(1).

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the CBAVS components that are within the scope of license renewal

and subject to an AMR.

Auxiliary and Radwaste Area Ventilation System

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9..4.2 to determine whether the

ARAVS components within the scope of license renewal and subject to an AMR have been
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identified in accordance with 10 CFR 54.4 and 54.21(a)(1). The staff’s review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described below. 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the license renewal Rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted. 

During its review, the staff determined that additional information was needed to complete its

review. In a letter dated March 28, 2003, the staff asked the applicant, in RAIs 2.3.3.1-1 and

2.3.3.1-4, why the system damper housings and their intended functions are not listed in LRA

Table 2.3-18 for an AMR. The staff also asked the applicant, in RAI 2.3.3.1-6, whether the

instrument housings and their associated tubing are subject to an AMR. By letter dated June

12, 2003, the applicant stated that the ARAVS damper housings are considered subject to an

AMR if they are in the portion (pressure boundary) of a system that is in scope. These damper

housings are highlighted on the license renewal boundary drawings and are included with

ductwork in the application (Table 3.3-2, Item 2 for stainless steel and Item 3 for carbon and

galvanized steel, provides more description). The applicant clarified that the ARAVS

instruments and instrument tubing are highlighted on the applicable license renewal boundary

drawings, and the instrument tubing within the scope of license renewal is listed in Table

2.3-18. However, the instruments are active components and are not subject to an AMR.

The staff reviewed the applicant’s response and found it acceptable concerning the ARAVS

housings for dampers, instruments, and associated instrument tubings because it clarified the

pertinent information on the ARAVS components that are within the scope of license renewal

and subject to an AMR. 

The staff also asked the applicant, in RAI 2.3.3.1-2, to clarify whether ductwork turning vanes,

ventilation system elastomer seals, ventilation equipment vibration isolator flexible connections,

ductwork test connections, and ductwork access doors are within the scope of license renewal

and subject to an AMR. By letter dated June 12, 2003, the applicant provided the following

clarification for the ARAVS components:

• ductwork turning vanes are the subcomponents of the ductwork that are made of the

same material as the ductwork (galvanized steel or stainless steel) and are bounded by

the AMP

• flexible seals between the duct and housings are in scope and are listed in LRA Table

2.3-18. Its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are

considered consumables that do not perform an intended function as a pressure

boundary and, therefore, are not subject to an AMR

• ductwork flexible connections are in scope and are listed in LRA Table 2.3-18 (its AMP

is described in LRA Table 3.3-1, Item 2). The components with “vibration isolator

flexible connections” are not within the scope of license renewal

• ductwork test connections and ductwork access doors are part of the ductwork that are

included in LRA Tables 2.3-18, 3.3-1, and 3.3-2 as ductwork. The ductwork test
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connections are typically holes that are normally filled with a push penny.” The push

penny is not required for the system to perform its license renewal intended function

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the ARAVS components that are within the scope of license renewal

and subject to an AMR, as required by 10 CFR 54.21(a)(1).

Additionally, the staff also asked the applicant, in RAIs 2.3.3.1-3 and 2.3.3.1-7, to clarify

whether structural sealants used to maintain the pressure boundary at design pressure with

respect to the adjacent areas are within the scope of license renewal and subject to an AMR. 

Also, the staff requested the applicant to provide information relating to structural sealants as

referenced in Table 2.1-3 (on page 2.1-15) of NUREG-1800. 

By letter dated June 12, 2003, the applicant provided the following clarification for the ARAVS

components:

• The applicant’s position on consumables is consistent with NUREG-1800, Table 2.1-3. 

Packing, gaskets, component seals, and O-rings are subcomponents of structural

components that are excluded from AMR for several reasons. ASME code indicates

that gasket, packing and O-rings do not serve as pressure boundary components and,

therefore, are excluded from an AMR . Seal material on components, such as doors,

does not perform an intended function and is replaced periodically based on testing

results and, therefore, is not subject to an AMR . Seals and O-rings for structural

components are not treated individually as consumables, but rather as parts of their host

components (doors, airlocks, hatches, etc.) which are managed under the AMPs and

plant procedures. Oil, grease, and component filters are short lived with periodic

replacement and are excluded from an AMR. System filters, fire extinguishers, fire

hoses, and air packs are discussed in LRA Section 2.1.2.1.4

• The terminology of structural sealants” as identified in an RAI 2.3.3.1-3 and

NUREG-1800 is not used at the plant. However, structural sealants would include fire

door seals and coatings, pressure seals, expansion joints, etc., all of which are

addressed in the LRA. These materials or component types are important in

maintaining the integrity of the components to which they are connected. For these

situations, the license renewal, or component intended function supported by the

sealant, is to maintain the building pressure boundary envelope. The pressure

boundary function of these materials is determined by surveillance testing to

demonstrate compliance with technical specifications

• These structural sealant materials (expansion joints, caulking, seals, etc.) discussed

above are considered to be consumables. Various inspection programs as addressed in

the LRA (i.e., B.1.5, B.1.11, B.1.12, B.1.16, B.1.18, and B.1.20) will determine their

replacement. The life of these materials is determined based on wear or damage

identified during inspections. Programmatic actions are not to manage their life, but

rather to replace them when their condition indicates that they are no longer acceptable

for service. Therefore, these materials are replaced based on condition monitoring and

are not subject to an AMR, as required by 10 CFR 54.21(a)(1). 
2-69

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the ARAVS components that are within the scope of license renewal

and subject to an AMR, as required by 10 CFR 54.21(a)(1).

Fuel Handling Building Ventilation

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9.4.3 to determine whether the

FHBV components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1). The staff's review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described as below. 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the license renewal Rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted. 

During its review, the staff determined that additional information was needed to complete its

review. In a letter dated March 28, 2003, the staff asked the applicant, in RAIs 2.3.3.1-1 and

2.3.3.1-4, why the system damper and filter housings and their intended functions are not listed

in LRA Table 2.3-18. Also, the staff ask the applicant, in RAI 2.3.3.1-6, whether the instrument

housings and their associated tubing are subject to an AMR. By letter dated June 12, 2003,

the applicant stated that the FHBV damper, filter housings, and filter are considered subject to

an AMR if they are in the portion (pressure boundary) of a system that is in scope. These

damper housings are highlighted on the license renewal boundary drawings with ductwork in

the application (Table 3.3-2, Item 2 for stainless steel and Item 3 for carbon and galvanized

steel, provides more description). The filter housings (with a license renewal intended function)

are highlighted on the license renewal boundary drawings and are listed in Table 2.3-18 (in the

component groups of ductwork, fan, and plenum housings). The applicant clarified that FHBV

instruments and instrument tubing considered in scope are highlighted on the applicable P&ID

drawings, and the instrument tubing is listed in Table 2.3-18. However, the instruments are

active components and are not subject to an AMR.

The staff reviewed the applicant’s response and found it acceptable concerning the FHBV

housings for dampers, filters and instruments, and associated instrument tubings because it

clarified the pertinent information on the system components that are within the scope of

license renewal and subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff also asked the applicant, in RAI 2.3.3.1-2, to clarify whether ductwork turning vanes,

ventilation system elastomer seals, ventilation equipment vibration isolator flexible connections,

ductwork test connections, and ductwork access doors are within the scope of license renewal

and subject to an AMR. By letter dated June 12, 2003, the applicant provided clarification for

the FHBV components as follows:

• Ductwork turning vanes are part of the subcomponent of the ductwork that are made of

the same material as the ductwork (galvanized steel or stainless steel) and are bounded

by the AMP for the ductwork
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• Flexible seals between duct and housings are in scope and are listed in LRA Table

2.3-18. Its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are

considered as consumables that do not perform an intended function as pressure

boundary and are not subject to an AMR

• Ductwork flexible connections are in scope and listed in LRA Table 2.3-18 (its AMP is

described in LRA Table 3.3-1, Item 2). The plant does not mount in scope components

with vibration isolator flexible connections”

• Ductwork test connections and ductwork access doors are considered part of the

ductwork and are included in that component group in LRA Tables 2.3-18, 3.3-1, and

3.3-2. Ductwork test connections are typically holes that are normally filled with a “push

penny.” The push penny is not required for the system to meet its license renewal

intended function

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the FHBV components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and subject to an AMR, as required by 10 CFR 54.21(a)(1).

Additionally, the staff also asked the applicant, in RAIs 2.3.3.1-3 and 2.3.3.1-7, whether

structural sealants used to maintain the pressure boundary of design pressure with respect to

adjacent areas are within the scope of license renewal and subject to an AMR. Also, the staff

requested the applicant to provide information related to structural sealants as referenced in

Table 2.1 3 (on page 2.1-15) of NUREG-1800. 

By letter dated June 12, 2003, the applicant provided the following clarification for the FHBV

components:

• The applicant’s position on consumables is consistent with NUREG-1800, Table 2.1-3. 

Packing, gaskets, component seals, and O-rings are subcomponents of structural

components that are excluded from AMR for several reasons. ASME code indicates

that gasket, packing, and O-rings are not relied on as pressure boundary components

and are, therefore, excluded from an AMR. Seal material on components, such as

doors, does not perform an intended function and is replaced periodically based on

testing results, and is not subject to an AMR. Seals and O-rings for structural

components are not treated individually as consumables, but rather as parts of their host

components (doors, airlocks, hatches, etc.) which are managed under the AMPs and

plant procedures. Oil, grease, and component filters are short-lived with periodic

replacement and are excluded from an AMR. System filters, fire extinguishers, fire

hoses, and air packs are discussed in LRA Section 2.1.2.1.4

• The terminology, structural sealants,” as identified in RAI 2.3.3.1-3 and NUREG-1800,

is not used at the plant. However, structural sealants would include fire door seals and

coatings, pressure seals, expansion joints, etc., all of which are addressed in the LRA. 

The applicant recognizes that locations exist where these materials or component types

are important in maintaining the integrity of the component to which they are connected.

In these situations, the license renewal or component intended function supported by

the sealant is to maintain the building pressure boundary envelope. The pressure
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boundary function is addressed by surveillance testing to demonstrate compliance with

technical specifications

• These structural sealant materials (expansion joints, caulking, seals, etc.) discussed

above are considered to be consumables. Various inspection programs addressed in

the LRA (B.1.5, B.1.11, B.1.12, B.1.16, B.1.18, and B.1.20) will determine their

replacement. The life of these materials is based on the extent of wear or damage

identified during inspections. Programmatic actions are not to manage their life, but

rather to replace them when their condition indicates that they are no longer acceptable

for service. These materials are replaced based on condition monitoring and are not

subject to an AMR

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the FHBV components that are within the scope of license renewal and

subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff also requested the applicant, in RAI 2.3.3.1-8, to clarify whether the FHBV exhaust

ductwork is within the scope of license renewal and subject to an AMR. By letter dated

June 12, 2003, the applicant stated that the FHBV exhaust ductwork downstream of the fans

does not need to remain intact to perform its intended function. The FHBV’s functions are to

maintain a negative pressure in the fuel handling building, and remove airborne particulate and

radioiodines during fuel handling activities and blackout conditions within acceptable limits. The

pressure boundary of the ductwork downstream of the fans is located in the auxiliary building

that does not perform this function. Some portion of this ductwork is in scope for spatial

interaction concern that was included in a supplement submittal to the application. The staff

found the applicant’s response acceptable because it clarified the pertinent information on the

FHBV exhaust ductwork that need not to be in the scope of license renewal.

Intermediate Building Ventilation Systems

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9.4.6 to determine whether the

IBVS components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff's review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below. 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the license renewal Rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted. 

During its review, the staff determined that additional information was needed to complete its

review. In a letter dated March 28, 2003, the staff asked the applicant, in RAI 2.3.3.1-6,

whether the system instrument housings and their associated tubing are subject to an AMR. By

letter dated June 12, 2003, the applicant stated that the IBVS instruments and their instrument

tubing are subject to an AMR (if they are within the pressure boundary). The applicant further

clarified that the IBVS instruments and instrument tubing in scope are highlighted on the

applicable license renewal boundary drawings, and instrument tubing is listed in LRA Table

2.3-18. However, the instruments are active components and are not subject to an AMR. 
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The staff found the applicant’s response acceptable concerning the instrument housings and

associated instrument tubings because it clarified the pertinent information on the system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff also requested the applicant, in RAI 2.3.3.1-2, to clarify whether ductwork turning

vanes, ventilation system elastomer seals, ventilation equipment vibration isolator flexible

connections, ductwork test connections, and ductwork access doors are within the scope of

license renewal and subject to an AMR. By letter dated June 12, 2003, the applicant provided

the following clarification for the IBVS components:

• Ductwork turning vanes are part of the subcomponent of ductwork and are made of the

same material as the ductwork (galvanized steel or stainless steel) and are bounded by

the AMP for the ductwork

• Flexible seals between duct and housing are in scope and included in LRA Table 2.3-18,

and its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are the

consumables that do not perform an intended function as a pressure boundary and are

not subject to an AMR

• Ductwork flexible connections are in scope and included in LRA Table 2.3-18 (its AMP is

described in LRA Table 3.3-1, Item 2). The plant does not mount in scope components

with vibration isolator flexible connections”

• Ductwork test connections and ductwork access doors are considered part of the

ductwork and are included in that component group in LRA Tables 2.3-18, 3.3-1, and

3.3-2. Ductwork test connections are typically holes that are normally filled with a push

penny.” The push penny is not required for the system to perform its license renewal

intended function

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the IBVS components that are within the scope of license renewal and

subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff also requested the applicant, in RAI 2.3.3.1-5, to clarify whether the IBVS used to

support safe shutdown controls are within the scope of license renewal and subject to an AMR. 

By letter dated June 12, 2003, the applicant provided the following clarifications:

 The safe shutdown controls and panels at the plant are the control room evacuation

panels (CREP). The CREP are located in the speed switch room area of the plant, and

the cooling system for this area is shown on P&ID drawing D-912-157. The speed

switch room area cooling system is within the scope of license renewal and subject to an

AMR.

• Alternate or remote safe shutdown panels (requiring control room evacuation) is

achieved using the train B” equipment and controls by a variety of means, including

controls at the CREP, controls at switchgear and motor control centers, and controls

mounted on the local panels for the B” diesel generator and B" water chiller.
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The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the CREP served by the IBVS and the speed switch room area cooling

that is within the scope of license renewal and subject to an AMR.

Miscellaneous Building Ventilation and Cooling Systems

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9.4.7 to determine whether the

MBVCS components within the scope of license renewal and subject to an AMR have been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff's review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below. 

During its review, the staff determined that additional information was needed to complete its

review. In a letter dated March 28, 2003, the staff asked the applicant, in RAI 2.3.3.1-6,

whether the system instrument housings and their associated tubing are subject to an AMR. By

letter dated June 12, 2003, the applicant stated that MBVCS instruments and instrument tubing

are in scope. They are highlighted on the applicable license renewal boundary drawings and

the instrument tubing is listed in LRA Table 2.3-18. However, the instruments are active

components and are not listed in the table. 

The staff reviewed the applicant’s response and found it acceptable concerning the instrument

housings and associated instrument tubings because it clarified the pertinent information on the

MBVCS components that are within the scope of license renewal and subject to an AMR, as

required by 10 CFR 54.21(a)(1).

The staff also requested the applicant, in RAI 2.3.3.1-2, to clarify whether ductwork turning

vanes, ventilation system elastomer seals, ventilation equipment vibration isolator flexible

connections, ductwork test connections, and ductwork access doors are within the scope of

license renewal and subject to an AMR. By letter dated June 12, 2003, the applicant provided

the following clarification for the MBVCS components:

• Ductwork turning vanes are part of the subcomponent of the ductwork and are made of

the same material as the ductwork (galvanized steel or stainless steel) and are bounded

by the AMP for the ductwork

• Flexible seals between duct and housings are in scope and are listed in LRA Table

2.3-18, and its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are

considered as consumables that do not perform an intended function as pressure

boundary and, therefore, are not subject to an AMR

• Ductwork flexible connections are in scope and are listed in LRA Table 2.3-18 (its AMP

is described in LRA Table 3.3-1, Item 2). The plant does not mount in scope

components with vibration isolator flexible connections.”

• Ductwork test connections and ductwork access doors are considered part of the

ductwork and are included in that component group in LRA Tables 2.3-18, 3.3-1, and

3.3-2. Ductwork test connections are typically holes that are normally filled with a push

penny.” The push penny is not required for the system to perform its intended function.
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The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the MBVCS components that are within the scope of license renewal

and subject to an AMR, as required by 10 CFR 54.21(a)(1).

Reactor Building Cooling and Filtering Systems

The staff reviewed LRA Section 2.3.3.1 and UFSAR Section 9.4.8 to determine whether the

RBCFS components within the scope of license renewal and subject to an AMR have been

identified, in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff's review

was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below. 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the license renewal Rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information was needed to complete its

review. The staff asked the applicant, in RAIs 2.3.3.1-1 and 2.3.3.1-4, why the system damper

and filter housings and their intended functions are not listed in LRA Table 2.3-18. The staff

also asked the applicant, in RAI 2.3.3.1-6, whether the instrument housings and their

associated tubing are subject to an AMR. By letter dated June 12, 2003, the applicant stated

that the RBCFS damper and filter housings and filter are subject to an AMR if they are within

the pressure boundary of a system which is in scope. The damper housings are highlighted on

the applicable license renewal boundary drawings and are with the ductwork in scope (Table

3.3-2, Item 2 for stainless steel and Item 3 for carbon and galvanized steel, provides more

description). The filter housings are highlighted on the license renewal boundary drawings and

are included in Table 2.3-18 (in the groups of ductwork, fan, and plenum housings). Also, the

RBCFS instruments and instrument tubing in scope are highlighted on the applicable license

renewal boundary drawings and the instrument tubing is listed in Table 2.3-18. However, the

instruments are active components and are not listed in the table.

The staff reviewed the applicant’s response and found it acceptable concerning the RBCFS

housings for dampers, filters, and instruments, and associated instrument tubings because it

clarified the pertinent information on the system components that are within the scope of

license renewal and subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff also asked the applicant, in RAI 2.3.3.1-2, whether ductwork turning vanes, ventilation

system elastomer seals, ventilation equipment vibration isolator flexible connections, ductwork

test connections, and ductwork access doors are within the scope of license renewal and

subject to an AMR. By letter dated June 12, 2003, the applicant provided the following

clarification for the RBCFS components:

• Ductwork turning vanes are part of the subcomponent of the ductwork that are made of

same material as the ductwork (galvanized steel or stainless steel) and are bounded by

the AMP for the ductwork.

• Flexible seals between duct and housings are in scope and are listed in Table 2.3-18. 

Its AMP is described in LRA Table 3.3-1, Item 2. However, door seals are considered
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as consumables that do not perform an intended function as a pressure boundary and,

therefore, are not subject to an AMR.

• Ductwork flexible connections are in scope and are listed in Table 2.3-18. Its AMP is

described in LRA Table 3.3-1, Item 2). The plant does not mount in scope components

with vibration isolator flexible connections.”

• Ductwork test connections and ductwork access doors are considered part of the

ductwork and are included in that component group in LRA Tables 2.3-18, 3.3-1, and

3.3-2. Ductwork test connections are typically holes that are normally filled with a push

penny.” The push penny is not required for the system to meet its license renewal

intended function.

The staff reviewed the applicant’s response and found it acceptable because it clarified the

pertinent information on the RBCFS components that are within the scope of license renewal

and subject to an AMR, as required by 10 CFR 54.21(a)(1).

Additionally, the staff also asked the applicant, in RAIs 2.3.3.1-3 and 2.3.3.1-7, whether

structural sealants used to maintain the pressure boundary at design pressure with respect to

the adjacent areas are included in the scope of license renewal and subject to an AMR. The

staff also requested the applicant to provide information relating to structural sealants as

referenced in Table 2.1-3 (on page 2.1- 15) of NUREG 1800. 

By letter dated June 12, 2003, the applicant provided the following clarification for the RBCFS

components:

• The applicant’s position on consumables is consistent with NUREG-1800, Table 2.1-3. 

Packing, gaskets, component seals, and O-rings are the subcomponents of structural

components that are excluded from AMR for several reasons. ASME code indicates

that gaskets, packing, and O-rings are not pressure boundary components and are not

subject to an AMR. Seal material on components, such as doors, does not perform

system’s intended function and is periodically replaced based on testing results, and,

therefore, is not subject to an AMR. Seals and O-rings for structural components are

not treated individually as consumables, but rather as parts of their host components

(doors, airlocks, hatches, etc.) which are managed under the AMPs and plant

procedures. Oil, grease, and component filters are short-lived with periodic replacement

and are excluded from an AMR. System filters, fire extinguishers, fire hoses, and air

packs, are discussed in LRA Section 2.1.2.1.4.

• The terminology of structural sealants” as identified in RAI 2.3.3.1-3 and NUREG-1800

is not used at the plant. However, structural sealants would include fire door seals and

coatings, pressure seals, expansion joints, etc., all of which are addressed in the LRA. 

The applicant recognizes that locations exist where these materials or component types

are important in maintaining the integrity of the component to which they are connected.

For these situations, the license renewal or component intended function supported by

the sealant is to maintain the building envelope pressure boundary. The pressure

boundary function is checked by surveillance testing to demonstrate compliance with

technical specifications.
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• These structural sealant materials (expansion joints, caulking, seals, etc.) discussed

above are the consumables. Various inspection programs as addressed in the LRA

(i.e., B.1.5, B.1.11, B.1.12, B.1.16, B.1.18, and B.1.20) determine their replacement.

The life of these materials is based on the extent of wear or damage determined by

inspections. Programmatic actions are not to manage their life, rather to replace them

when their conditions are no longer acceptable for service. Therefore, these materials

are replaced based on condition monitoring and do not require an AMR.

The staff found the applicant’s response acceptable because it clarified the pertinent

information on the RBCFS components that are within the scope of license renewal and subject

to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.1.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the air handling and local ventilation and cooling

systems that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the air handling and local ventilation

and cooling systems that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.2 Boron Recycle System

The applicant describes the boron recycle system in LRA Section 2.3.3.2 and provides a list of

components subject to an AMR, along with their component intended functions, in LRA Table

2.3-19. The license renewal evaluation boundaries for the boron recycle system are depicted in

the E-302-751 boron recycle drawing and in the 1MS-09-269 Flow Diagram — Recycle

Evaporating Package. UFSAR Section 9.3.6, Boron Recycle System, provides additional

information concerning the boron recycle system. 

2.3.3.2.1 Summary of Technical Information in the Application

The boron recycle system collects recycled reactor coolant effluent for reuse of the boric acid

and makeup water. For the most part, this effluent is water from the letdown and drains. The

boron recycle system is designed to collect, via the letdown line in the chemical and volume

control system, the excess reactor coolant that results from certain plant operations during a

core cycle. The boron recycle system also collects water from the reactor coolant drain tank

(liquid waste processing system), the volume control tank and charging pump suction pressure

reliefs (chemical and volume control system) and residual heat removal pumps pressure reliefs

(emergency core cooling system), the boric acid blender (chemical and volume control system),

the spent fuel pool pumps (spent fuel cooling system), and various valve leakoffs and

equipment drains. The boron recycle system is designed to process the total volume of water

collected during a core cycle, as well as short-term surges.

When water is directed to the boron recycle system, the flow passes first through the recycle

evaporator feed demineralizers and filters, and then into the recycle holdup tanks. When
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sufficient water is accumulated to warrant evaporator operation, the recycle evaporator feed

pumps take suction from the selected recycle holdup tank and pumps the fluid through the

recycle evaporator, where dissolved gases (i.e., hydrogen, fission gases, and other gases) are

removed in the stripping column before the liquid enters the evaporator shell. These gases are

directed to the gaseous waste processing system.

The evaporator concentrates the boric acid solution until a 4-weight percent solution is

obtained. The accumulated batch is normally transferred directly to the boric acid tanks in the

chemical and volume control system through the recycle evaporator concentrates filter.

In this way, the system decontaminates the effluent by means of demineralization and gas

stripping, and uses evaporation to separate and recover the boric acid and makeup water. The

mechanical license renewal function of the boron recycle system is to maintain its system

boundary with the component cooling and chemical and volume control systems.

The boron recycle system mechanical component types, listed in Table 2.3-19, consist of

condenser channel heads, condenser tubes, condenser tubesheets, heat exchanger shells,

heat exchanger shell nozzles, heat exchanger tubes, exchanger tubesheets, heat exchanger

manifolds, and heat exchanger valve bodies. All of the listed components serve a pressureretaining boundary function.

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 9.3.6, Boron Recycle System, to

determine whether the boron recycle system components and supporting structures within the

scope of license renewal and subject to an AMR had been identified in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

As part of the evaluation, the staff determined whether the applicant had properly identified the

SSCs within the scope of license renewal and subject to an AMR, pursuant to 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1). The staff reviewed the relevant portions of the UFSAR for the boron

recycle system and associated pressure boundary components, and compared the information

in the UFSAR with the information in the LRA to identify those portions that the LRA did not

identify as being within the scope of license renewal and subject to an AMR. The staff then

reviewed the SCs that were identified as not being within the scope of license renewal to verify

that these SCs do not have any of the intended functions delineated under 10 CFR 54.4(a), and

for those SCs that have an applicable intended function(s), to verify that they either perform this

function(s) with moving parts or a change in configuration or properties, or that they are subject

to replacement based on a qualified life or specified time period, as described in 10 CFR

54.21(a)(1). 

The staff also reviewed the UFSAR for any function(s) delineated under 10 CFR 54.4 (a) that

were not identified as intended function(s) in the LRA, to verify that the SSCs with such

function(s) will be adequately managed so that the function(s) will be maintained consistent with

the CLB for the period of extended operation. 
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The principal area of review, for the boron recycle system, was to verify that all components in

the pressure-retaining boundary with the component cooling and chemical and volume control

systems have been included in the license renewal scope.

No omissions of SSCs that are within the scope of license renewal and subject to an AMR were

found.

2.3.3.2.3 Conclusions

The staff reviewed LRA Section 2.3.3.2 and UFSAR Section 9.3.6, Boron Recycle System, to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. In addition, the staff performed an independent assessment to determine whether

any components subject to an AMR had not been identified by the applicant. No omissions

were found. On this basis, the staff concludes that the applicant has adequately identified the

boron recycle system components that are within the scope of license renewal as required by

10 CFR 54.4(a) and that the applicant has adequately identified the boron recycle system

components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.3 Building Services

2.3.3.3.1 Summary of Technical Information in the Application

The applicant describes the building services system (BSS) in LRA Section 2.3.3.3, Building

Services, and provides a list of components subject to an AMR in LRA Table 2.3-20. The

system is further described in UFSAR Section 9.3.1, Compressed Air Systems.

The BSS provides means for structural integrity of various buildings on site. However, some of

the components of the BSS are mechanical components that are used to maintain a pressure

boundary for containment integrity, and their intended function is to provide containment

isolation. These components include valves, tubing, and piping in the station service air system

which supplies compressed air for the reactor building personnel, emergency personnel, and

equipment hatches. The BSS license renewal boundaries are highlighted on P&ID drawing D302-242, Station Air Supply to Personnel, Emergency Personnel and Equipment Hatches.”

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, the applicable portions of UFSAR Section 9.3.1, and

the P&ID drawing to determine whether the BSS components within the scope of license

renewal and subject to an AMR had been identified, in accordance with the requirements of 10

CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. The staff’s review was conducted based on

Section 2.3 of the SRP-LR (NUREG-1800) and is described below.

During the review, the staff selected system functions described in the UFSAR that were set

forth in 10 CFR 54.4 to verify that components having intended functions were not omitted from

the scope of the Rule. The staff reviewed the components listed in LRA Table 2.3-20 and

verified them with the P&ID drawing to ensure that components having intended functions were

not omitted from an AMR. The staff also focused on components that were not identified as

being subject to an AMR to determine if any components were omitted. The staff found that the

BSS components that have an intended function meeting the criteria of 10 CFR 54.4(a), have
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been identified as being within the scope of license renewal and subject to an AMR, in

accordance with the requirements of 10 CFR 54.21(a)(1). As a result of this review, the staff

did not identify any omissions.

2.3.3.3.3 Conclusions

The staff reviewed the LRA, UFSAR, and the accompanying license renewal boundary

drawings to determine whether any SSCs within the scope of license renewal had not been

identified by the applicant. No omissions were found. In addition, the staff performed an

independent assessment to determine whether any components subject to an AMR had not

been identified by the applicant. No omissions were found. On the basis of this review, the

staff concludes that the applicant has adequately identified the BSS components that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

appropriately identified the BSS components that are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.3.3.4 Chilled Water System

2.3.3.4.1 Summary of Technical Information in the Application

The applicant describes the chilled water system in LRA Section 2.3.3.4, Chilled Water System,

and provides a list of components subject to an AMR in LRA Table 2.3-21. The system is

further described in UFSAR Section 9.4.7, Miscellaneous Building Ventilation and Cooling

System.

The chilled water system provides cooling to various ventilation fan cooling units in different

areas of the plant. The chilled water system is a closed system with redundant supply and

return mains. Chiller condenser cooling water is supplied by the service water system. The

chilled water system license renewal boundaries are highlighted on the following P&ID

drawings:

• D-302-222, Service Water System

• D-302-841, Chilled Water Pump and Chiller Area

• D-302-842, Chilled Water to Cooling Coils

• D-302-843, Chilled Water to Cooling Coils

• 1MS-54-064-2, VU Mechanical Chillers

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4, the applicable portions of UFSAR Section 9.4.7, and

the P&ID drawings to determine whether the chilled water system components within the scope

of license renewal and subject to an AMR had been identified in accordance with the

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff’s review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described as

below.

During the review, the staff reviewed the components listed in LRA Table 2.3-21 and verified

them with the P&ID drawings to ensure that components having intended functions were not

omitted from the scope of license renewal. The staff also focused on components that were not
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identified as being subject to an AMR to determine if any components were omitted. The staff

found that the components of the chilled water system that have an intended function meeting

the criteria of 10 CFR 54.4(a) have been identified as being within the scope of license renewal

and subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). As a

result of this review, the staff did not identify any omissions.

2.3.3.4.3 Conclusions

The staff reviewed the LRA, the UFSAR, and the accompanying P&ID drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the chilled water system that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has appropriately

identified the chilled water system components that are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.3.3.5 Circulating Water System

2.3.3.5.1 Summary of Technical Information in the Application

The applicant describes the circulating water system (CWS) in LRA Section 2.3.3.5. The CWS

is further described in UFSAR Section 10.4.5, Circulating Water System.

The CWS removes thermal energy from the main and auxiliary condensers and dissipates this

energy to the Monticello Reservoir. The CWS is a non-safety-related cooling system and is not

required to function under plant emergency or faulted conditions. The only license renewal

intended function of the CWS is to provide level instruments that will trip the CWS pumps and

close several CWS valves to prevent flooding in the intermediate building and control building

as a result of pipe break in the CWS. There are no mechanical components required for the

CWS to perform its system intended function and, therefore, no AMR for the mechanical

components is required. Since instrumentation and controls are not required to be highlighted

on the flow diagrams as within license renewal boundaries, P&ID drawings were not provided in

the LRA to highlight the CWS license renewal boundaries.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5 and UFSAR Section 10.4.5 to determine whether the

CWS components within the scope of license renewal and subject to an AMR had been

identified in accordance with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1),

respectively. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below.

As described above, the only license renewal function of the CWS is to provide level

instruments that trip the CWS pumps and close several CWS valves to prevent the intermediate

building and control building from flooding in the event of a pipe break in the CWS. Therefore,

the applicant did not provide P&ID drawings in the LRA to highlight the license renewal

boundaries for the CWS. During its review of LRA Section 2.3.3.5, the staff determined that
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additional information regarding level instrumentations was needed to complete this review. By

letter dated March 28, 2003, in RAI 2.3.3.5-1, the staff requested that the applicant clarify

whether the level instruments were subject to an AMR, or justify their exclusion.

In its response, dated June 12, 2003, the applicant stated that the P&ID drawings provided for

the LRA are the tools for license renewal scoping. The level instruments are not mechanical

components and are not within the pressure boundary of the CWS. Therefore, P&ID drawings

for the CWS are not required to be provided in the LRA. In addition, these instruments are

active components that have no passive function and, therefore, are not subject to an AMR in

accordance with 10 CFR 54.21(a)(1).

The staff’s review finds the applicant’s rationale acceptable for the level instruments not subject

to an AMR. The staff agrees with the applicant that the level instruments are not mechanical

components within the pressure boundary of the CWS. They are active components and have

no passive intended function, and therefore, are exempted from AMR in accordance with

10 CFR 54.21(a)(1). As a result of this review, the staff did not identify any omissions.

2.3.3.5.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

had not been identified by the applicant. No omissions were found. In addition, the staff

performed an independent assessment to determine whether any components subject to an

AMR had not been identified by the applicant. No omissions were found. On the basis of this

review, the staff concludes that the applicant has adequately identified the CWS components

that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has determined that no CWS components are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.3.3.6 Component Cooling Water System

2.3.3.6.1 Summary of Technical Information in the Application

The applicant describes the component cooling water (CCW) system in LRA Section 2.3.3.6

and provides a list of components subject to an AMR in LRA Table 2.3-22. The system is

further described in UFSAR Section 9.2.2, Component Cooling Water System.

The CCW system serves as an intermediate, closed-loop cooling system to transfer heat from

systems and components important to safety, including those that may contain radioactive (or

potentially radioactive) fluids, to the service water system. The CCW system consists of two

separate and independent loops that are each provided with emergency makeup water from the

associated service water system train to makeup for leakage. The important to safety

components supplied with cooling water by the CCW system include the residual heat removal

pumps, the residual heat removal heat exchangers, and the centrifugal charging pumps. Thus,

upon loss of one CCW cooling loop, cooling water remains available to the redundant

component in each of these safety-related systems. The CCW system is also utilized during

normal plant operation to transfer heat from various systems and components that are not

important to safety, but could result in the release of radioactivity to the ultimate heat sink if

direct, open loop cooling were used. This latter type of service is referred to as nonessential.
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2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and UFSAR Section 9.2.2 to determine whether the

CCW system components within the scope of license renewal and subject to an AMR had been

identified in accordance with the requirements of 10 CFR 54.4 and 54.21(a)(1), respectively. 

The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

During the review of LRA Table 2.3-22, which lists component types subject to an AMR, the

staff noted that the table did not specifically describe flow venturis and radiation monitor

housings as component types subject to an AMR. However, license renewal drawing D-302-

612 indicated venturis at locations D4, D5, D6, and D7 were within scope, and drawing D-806-

005 indicated that the CCW system radiation monitor housing was within scope. Accordingly,

by letter dated March 28, 2003, in RAI 2.3.3.6-1, the staff requested that the applicant clarify

whether these component types are included in a component type already listed in the table, or

justify the exclusion of these component types from being subject to an AMR.

By letter dated June 12, 2003, the applicant responded to this RAI. The applicant stated that

the venturis are listed as orifices and are included in LRA Table 2.3-22. The applicant also

stated that the pressure boundary intended function of the radiation monitor housing is

addressed in LRA Section 2.3.3.17. Therefore, these components are identified in the LRA as

component types subject to an AMR.

By letter dated March 28, 2003, in RAI 2.3.3.6-2, the staff also requested that the applicant

clarify the configuration of temperature monitoring devices in the system and identify the

portions of these assemblies that are subject to an AMR. By letter dated June 12, 2003, the

applicant responded to this request for additional information and stated that thermowells are

used in temperature monitoring and are included in the scope of license renewal. Thermowells

are listed in LRA Table 2.3-22 as a component type subject to an AMR.

2.3.3.6.3 Conclusions

The staff reviewed the LRA and the accompanying boundary drawings to determine whether

any SSCs within the scope of license renewal had not been identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the CCW system that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the CCW system that are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.3.3.7 Diesel Generator Services Systems
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2.3.3.7.1 Summary of Technical Information in the Application

The applicant describes the emergency diesel generators (EDGs) and their support systems in 

LRA Section 2.3.3.7 and provides a list of components subject to an AMR in LRA Table 2.3-23. 

UFSAR Sections 9.5.4 and 9.5.8 provide additional information for the diesel generator services

systems.

The EDG system consists of two EDGs and their support systems. The Rule recognizes that

the EDGs are active components and are excluded from the group of equipment that are

subject to an AMR, as required by 10 CFR 54.21(a)(1). The following are the support systems

for each EDG:

• fuel oil storage and transfer system

• cooling water system

• starting air system

• lubrication system

• combustion air intake and exhaust system

The license renewal boundaries for the EDGs and their support systems are highlighted on the

following P&ID drawings: 

• D-302-222, Service Water System

• D-302-351, Diesel Generator Fuel Oil

• D-302-353, Diesel Generator Miscellaneous Service

• 1MS-32-005, Sheet 2, Fuel Oil System

• 1MS-32-005, Sheet 3, Lube Oil System

• 1MS-32-005 Sheet 4, Jacket Water System

• 1MS-32-005 Sheet 5, Intercooler & Injector Cooling System

• 1MS-32-005 Sheet 6, Starting & Control Air System

• 1MS-32-005 Sheet 7, Crank Case Vac Air Intake and Exhaust System

These supporting systems are further described in the following UFSAR Sections and are

summarized as below:

• 9.5.4 Diesel Generator Fuel Oil Storage and Transfer System

• 9.5.5 Diesel Generator Cooling Water System

• 9.5.6 Diesel Generator Starting Air System

• 9.5.7 Diesel Generator Lubrication System

• 9.5.8 Diesel Generator Combustion Air Intake and Exhaust System

Fuel Oil Storage and Transfer System

Each EDG fuel oil storage and transfer system consists of a day tank, a fuel oil storage tank,

two fuel oil transfer pumps, and its associated piping, valves, and I&Cs. Each day tank is

automatically filled by its own EDG fuel oil storage tank with its own EDG fuel oil transfer

pumps. A cross-tie with two normally closed valves is provided between the two EDGs at the

fuel oil transfer pump suctions that allows the fuel oil transfer pumps of either EDG to fill either

or both day tanks from either fuel oil storage tank. 
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Cooling Water System

The cooling water system consists of two subsystems — intercooler subsystem and jacket

water subsystem, as described below.

Intercooler Subsystem:

The intercooler subsystem supplies cooling water to the turbocharger air intercoolers, alternator

outboard bearing, and fuel injection nozzles. Circulation of cooling water is accomplished by an

engine-driven centrifugal pump. Heat from the cooling water is rejected to the service water

system through a thermostatically controlled heat exchanger. An expansion tank mounted on

top of a standpipe is provided to serve both the intercooler subsystem and the jacket water

subsystem. 

Jacket Water Subsystem:

The jacket water subsystem is a closed system that cools the diesel engine. Cooling water is

circulated through the cylinder liners, cylinder heads, and turbocharger cooling spaces by an

engine-driven pump. Heat from the cooling water is rejected to the service water system

through a thermostatically controlled heat exchanger. An electric heater and an auxiliary motordriven pump are provided to allow keep warm” operation under standby conditions.

Air Starting System

Each EDG is provided with two independent air starting systems, one for each bank of engine

cylinders. Each bank of engine cylinders has its own engine-driven air start distributor with a

connection to each cylinder. Using either or both banks can start the engine. Compressed air

is supplied by two air storage tanks which are charged by two separate a-c motor driven air

compressors. Because each of the air storage tanks is designed to store sufficient compressed

air that permits five successive EDG starts without recharge (e.g., using both air storage tanks,

10 successive EDGs can start without recharge), those portions of the system used for

charging the air storage tanks have no safety function. Therefore, the air compressors and

associated equipment are not highlighted in the P&ID drawings as being within the scope of

license renewal.

Lubrication System

The lubrication system consists of three subsystems — engine lube oil subsystem, rocker lube

subsystem, and auxiliary oil subsystem. The lube oil subsystem contains an engine-driven

pump which draws oil through a suction strainer from the engine sump and delivers it to a

thermostatically controlled lube oil cooler and then through a strainer to the main engine lube oil

header. The header supplies oil to all main bearings under pressure and, through a pressure

reducing valve, to the camshaft bearings, cam followers, fuel injection pumps, and valve push

rods. This subsystem also provides oil to the crank pin journals for piston cooling, as well as to

accessory gearing. A separate rocker lube subsystem supplies oil to each cylinder head rocker

assembly. An auxiliary oil subsystem permits continuous prelubrication of the engines at keep

warm” temperature during standby.

Combustion Air intake and Exhaust System
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The combustion air intake system consists of two filter/silencer units, mounted in a cubicle

above the associated EDG, with connecting piping to the intake manifold of the engine. Each

of the filter/silencer units serves one engine cylinder bank. The exhaust system consists of one 

muffler, mounted in a cubicle above the associated EDG, with connecting piping from the

engine exhaust manifolds. A short exhaust stack extends from the muffler through the roof to

the atmosphere. 

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and the cited UFSAR sections to determine whether the

components of EDGs and their support systems within the scope of license renewal and subject

to an AMR had been identified in accordance with the requirements of 10 CFR 54.4 and 10

CFR 54.21(a)(1), respectively. The staff’s review was conducted in accordance with Section

2.3 of the SRP-LR (NUREG-1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of license renewal. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

During its review, the staff determined that additional information regarding some components

in the EDGs and their support systems was needed to complete its review. The components of

diesel engine crankcase vacuum system (e.g., crankcase pump cases, oil separators, flex

connectors, valves, piping, etc.) are neither identified in the P&ID drawings as being within the

scope of license renewal nor included in LRA Table 2.3-23 for being subject to an AMR. The

staff believed that these components are long-lived with a passive function, and therefore,

should be subject to an AMR. In a letter dated March 28, 2003, in RAI 2.3.3.7-1, the staff

requested the applicant to clarify whether these system components were subject to an AMR,

or justify their exclusion.

In its response dated June 12, 2003, the applicant stated that these components do not have a

license renewal intended function. Crankcase vacuum is not required for the diesel to operate. 

Crankcase vacuum is required for pollution control which is not a license renewal requirement. 

The failure of the crankcase vacuum system components would not prohibit the diesel from

operating and meeting its license renewal intended function of supplying electric power. The

staff finds the applicant’s rationale acceptable for justifying the components of diesel engine

crankcase vacuum system not subject to an AMR.

With regard to the fuel oil storage and transfer system, the system components (i.e., the vent

line with flame arrestor for each fuel oil storage tank and each day tank, the manway for each

fuel oil storage tank, and the fuel oil fill lines) are neither identified in the P&ID drawings as

being within the scope of license renewal nor included in LRA Table 2.3-23 for being subject to

an AMR. The staff believed that these components are long-lived with a passive function and,

therefore, should be subject to an AMR. In a letter dated March 28, 2003, in RAI 2.3.3.7-2, the

staff requested the applicant to clarify whether these system components were subject to an

AMR, or justify their exclusion.
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In its response dated June 12, 2003, the applicant stated that these components do not have a

license renewal intended function. They are not required to contain the diesel fuel oil in the

system. Their failure would not prevent the required amount of diesel fuel oil from being 

supplied to their associated EDG. The staff finds the applicant’s rationale acceptable for

justifying the cited diesel fuel oil system components not in scope nor being subject to an AMR

for license renewal.

The components (i.e., expansion tanks, sight glasses, flex connectors, valves, piping, etc.) of

the jacket water system were neither identified in the P&ID drawings as being within the scope

of license renewal nor included in LRA Table 2.3-23 for an AMR. The staff believed that these

components are long-lived with a passive function and, therefore, subject to an AMR. In a letter

dated March 28, 2003, in RAI 2.3.3.7-3, the staff requested the applicant to clarify whether

these system components were subject to an AMR, or justify their exclusion.

In its response dated June 12, 2003, the applicant stated that these components do not have a

license renewal intended function. The 12-inch standpipe, which is within the scope of license

renewal and subject to an AMR, has sufficient capacity to meet the volume requirements for

containing the jacket cooling water. The expansion tank and components are provided for extra

surge capacity and static head to ensure proper filling after maintenance. The tank is

restrained such that it cannot fall and impact the EDG or any of its required auxiliaries. Their

failure would not prevent the EDG from being supplied with the required amount of coolant to

meet its license renewal intended function. The staff finds the applicant’s rationale acceptable

for justifying the jacket cooling system components not in scope nor being subject to an AMR

for license renewal. As a result of this review, the staff did not identify any omissions.

2.3.3.7.3 Conclusions

The staff reviewed the LRA, UFSAR, and the applicant’s response to the staff’s RAIs to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. No omissions were found. In addition, the staff performed an independent

assessment to determine whether any components subject to an AMR had not been identified

by the applicant. No omissions were found. On the basis of this review, the staff concludes

that the applicant has appropriately identified the components of the EDGs and their support

systems that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has appropriately identified the components of the EDGs and their support

systems that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.8 Fire Service System

2.3.3.8.1 Summary of Technical Information in the Application

The applicant describes the fire protection (FP) system in LRA Section 2.3.3.8, Fire Service

System, and provides a list of components subject to an AMR in LRA Table 2.3-23. UFSAR

Section 9.5.1, Fire Protection System, and Fire Protection Evaluation Report (FPER) provide

additional information concerning the interior and exterior FP system. 

The fire service system is designed to ensure adequate FP for each fire hazard. The total FP

system provides fire detection, audible and visual alarms, and extinguishment. The safety

functions of the fire service system include (1) fire protection water supply and distribution, (2)
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fire detection and alarm, (3) fire extinguishing, (4) cooling of equipment and building exposed to

fire, (5) control of fire spread, (6) inerting of hazardous atmospheres, and (7) efficient and

effective use of proper fire extinguishing agent. 

In accordance with 10 CFR 54.4(a)(3), the SSCs that are relied on in safety analyses or plant

evaluations to demonstrate compliance with10 CFR 50.48, Fire protection,” are included within

the scope of license renewal. The FP system at the plant is relied upon to meet the

requirements of 10 CFR 50.48. LRA Section 2.1.1.4.1, Fire Protection, identified that SSCs

relied upon in safety analyses or plant evaluations to perform a function that demonstrated

compliance with the FP rule in 10 CFR 50.48 are within the scope of license renewal. In LRA

Section 2.3.3.8, the applicant identified the FP flow diagrams (the P&ID drawings) that depict

the license renewal boundaries for the FP system. The applicant also identified the

components of the FP system that are evaluated in NUREG-1801 (AMPs), and that are not

evaluated in NUREG-1801 in LRA Tables 3.3-1 and 3.3-2, respectively. 

In accordance with 10 CFR 50.48, the applicant is required to implement and maintain a fire

protection program (FPP). As stated in LRA Section 2.1.1.4.1, the plant’s FPP is based on an

evaluation of potential fire hazards throughout areas containing safe shutdown equipment, as

well as potential fire hazards in various non-safe shutdown facilities and areas. The evaluation

of potential fire hazard assures that the capability exists to safely shutdown the unit following

loss of functions in any given fire area due to a fire, in compliance with Appendix A to 10 CFR

Part 50, General Design Criterion (GDC) 3, Fire Protection,” and Branch Technical Position

(BTP) Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, Appendix A, February

24, 1977. 

NUREG-0717, Safety Evaluation Report Related to the Operation of Virgil C. Summer Nuclear

Station, Unit 1,” issued February 1981, and its supplements, provide the staff’s evaluation which

documents the plant’s compliance with Appendix A to BTP APCSP 9.5-1 and in the CLB

document. In addition, the plant’s FPER contains the essential elements of the FPP. These

elements are the fire hazard analysis (FHA), safe plant shutdown description, and a point-bypoint comparison of the FPP with the guidance in Appendix A to BTP APCSP 9.5-1.

In LRA Section 2.1.1.4.1, the applicant states that although, the FP program is not considered

as safety-related, the quality assurance (QA) program for FP is part of the overall QA program,

and installation, testing, and subsequent operations of areas containing safety-related

equipment are processed by procedures similar to those for safety-related work. In addition, in

LRA Section 2.1.1.2.1, Safety-Related Mechanical Systems, the applicant uses a quality-related

(QR) designation code flag that applies to components, systems, and associated activities that

are non-safety-related, but warrant application of a quality plan or program to satisfy regulatory

requirements or management decisions. The plant’s QR designation applies to FP SSCs, and

services containing the equipment that demonstrate compliance are considered to be in the

license renewal scope.

In LRA Section 2.1.1.4.1, the applicant states that in order to ensure compliance with 10 CFR

Part 50, Appendix R (Sections III.G, III.J, and III.O), the plant has performed additional

analyses to provide further documentation of the ability of the unit to achieve safe shutdown in

the event of a fire. These analyses are documented in the FPER. To safely shutdown the plant

without control from the control room, an alternate shutdown system is provided consisting of

two independent shutdown panels and utilizing some local operator action. On the basis of the
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methodology described above, the applicant identified that the highlighted components, shown

on the FP flow diagrams and listed in LRA Section 2.3.3.8, are included within the scope of

license renewal. 

In LRA Table 2.3-24, the applicant identified that the FP system is within the scope of license

renewal. In LRA Tables 3.3-1 and 3.3-2, the applicant identified the components and

commodities groups (combinations of materials and environments) and the AMP evaluated in

NUREG-1801 that are relied on for license renewal of the auxiliary systems. 

2.3.3.8.2 Staff Evaluation

The NRC regulations in 10 CFR 54.21(a)(1), state that for those SSCs that are within the scope

of this part, as delineated in 10 CFR 54.4, the applicant must identify and list those SSCs that

are subject to an AMR. The staff reviewed LRA Section 2.3.3.8 to determine whether the

applicant has appropriately identified that the SSCs that serve FP intended functions are within

the scope of license renewal and subject to an AMR, in accordance with the requirements of 10

CFR 54.4 and 10 CFR 54.21(a)(1), respectively. The staff’s review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described below.

The staff sampled portions of the UFSAR to identify any additional FP system function that

meet the scoping requirements of 10 CFR 54.4, but that were not identified as an intended

function in the LRA. The staff also reviewed NUREG-0717 and its supplements. This NUREG

is referenced directly in the plant’s CLB documents, and summarizes the FP program and

commitments to 10 CFR 50.48 using the guidelines of Appendix A to BTP APCSB 9.5-1. The

staff reviewed NUREG-0717 and its supplements to verify that the function of the FP

components relied upon to satisfy the provisions of Appendix A to BTP APCSB 9.5-1 were

included in the scope of license renewal as intended functions in the LRA. 

The staff then compared the FP SSCs identified in the flow diagrams to verify that the required

components were highlighted as being within the evaluation boundaries on the flow diagram,

and were not excluded from the scope of license renewal. As part of the evaluation, the staff

also sampled portions of the same flow diagrams for the FP system to determine if there were

any additional portions of the system piping or components located outside of the evaluation

boundary that should have been identified as being within the scope of license renewal. 

After the staff’s initial review of the LRA, the staff identified several concerns on the scoping

and screening of FP SSCs required for compliance with 10 CFR 50.48. The staff identified a

technical concern regarding the appropriateness of applying the QR designation applied during

their scoping evaluation to identify all FP SSCs required for compliance with 10 CFR 50.48. 

The QR designation is the primary means relied upon by the applicant to identify FP SSCs. 

The applicant used QR flag on the LRA flow diagrams to identify FP SSCs that are in or out of

scope. The in-scope FP SSCs are located within QR flags and are highlighted on the LRA flow

diagrams, and the out-of-scope FP SSCs are outside of the QR flags that are isolated by

manual valves. The staff does not agree with the applicant that the QR designation completely

captured the FP SSCs required for compliance with 10 CFR 50.48. Therefore, the staff did not

find that the QR designation included in scope are all of the FP SSCs required for compliance

with 10 CFR 50.48. The scope of the SSCs required for compliance to GDC 3 and 10 CFR

50.48 goes beyond preserving the ability to maintain safe shutdown in the event of a fire. The

staff noted that several FP systems and components listed in the SER (NUREG-0717),
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including 20 gallons per minute (gpm) pressure maintenance pump (jockey pump), a sprinkler

system installed in the diesel generator building, and fire hose stations in various buildings,

which were excluded from the scope of license renewal, are required for compliance with 10

CFR 50.48. These concerns led to the issuance of RAIs, which were sent to the applicant in a

letter dated March 28, 2003. The applicant responded to the RAI in letters dated June 12 and

September 2, 2003, as discussed below. 

In RAI 2.3.3.8-1(1), staff requested the applicant to provide the basis for excluding the FP

piping leading to the alternate fire service (AFS) pump house, turbine building, a portion of the

circulating water (CW) pump house, and the FP components (including jockey pumps, valves,

piping, fittings, and diesel fuel tanks) from the scope of license renewal and subject to an AMR. 

In a letter dated June 12, 2003, the applicant responded that the AFS pumps are not credited

for FP, because these pumps were installed for fire service needs during the construction of the

station and are no longer used. However, the applicant expanded the scope to include the

jockey pump (20 gpm pressure maintenance pump) and associated piping and components in

the scope of license renewal. The applicant further stated that the components added by this

expansion of scoping are subject to screening. If screened in, the FPP will manage the aging

of these components. In a letter dated September 2, 2003, the applicant stated that it had

performed further review and determined that these components are passive, long-lived, and

support a license renewal intended function as a pressure boundary for fire service system. 

The FPP will manage the aging of these components for the period of extended operation.

The staff reviewed the applicant’s response and agrees with the applicant to include the jockey

pump and all the associated valves, piping, and fittings installed in the turbine building in the

scope of license renewal as a part of the FP SSCs subject to an AMR. The staff further agrees

that the AFS pump is not part of the fire suppression system. Therefore, the staff concurs with

the applicant that the AFS pump should not be within the scope of license renewal to meet 

10 CFR 50.48. 

By letter dated March 28, 2003, in RAI 2.3.3.8-1(2), the staff requested the applicant to provide

basis for excluding hydrants from the license renewal scope. These hydrants are in the system

flow diagram D-302-231, Sht. 2, at locations H12, K8, K9, K10, K11, and K12.

In response to RAI 2.3.3.8-1(2), dated June 12, 2003, the applicant clarified that the fire

hydrants in question are associated with fire hose houses 8, 9, 10, 17, 18, 19, and 20. All these

fire hose houses are located outside of the protected area and are not in scope. 

The staff finds the applicant’s response to RAI 2.3.3.8-1(2) to be acceptable.

By letter dated March 28, 2003, in RAI 2.3.3.8-1(3), the staff requested the applicant to explain

why the FP piping, fitting, valves, and fire hose stations at the reactor building (at locations E5,

E7, and E8), fire hose connections in the fuel handling building (at location B4), fire hose

connection in the auxiliary building (at location B13), fire hose connection in the intermediate

building (at location H4), and fire hose connections in the reactor building (at location E9) are

not highlighted in the system flow diagram (D-302-231, Sht. 3) as components within the scope

of license renewal.

In a letter dated June 12, 2003, the applicant stated that the portion of piping in question in the

reactor building (locations E5, E7, and E8 on LRA drawing D-302-231, Sht 3) is normally
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isolated per 10 CFR Part 50, Appendix A, GDC 56. The highlighted portion of this piping is in

scope for containment isolation only. The fire hose connections identified by the staff on

drawing D-302-231, Sht. 3, in the fuel building (at location B4), auxiliary building (at locations

B13 and E9), and the intermediate building (at location H4) are included in the expanded scope

for license renewal. The applicant further stated that the components added by this expansion

of scope are subject to screening. In a letter dated September 2, 2003, the applicant stated

that the plant had performed further review and determined that these components are passive,

long-lived, and support a license renewal intended function as a pressure boundary for fire

service system. The FPP will manage the aging of these components for the period of

extended operation.

The staff reviewed the applicant’s responses and agrees with the applicant that fire hose

stations should be included in the expanded scope for license renewal. The staff also agrees

with the applicant’s justification for excluding piping in the reactor building (at locations E5, E7,

and E8 on LRA drawing D-302-231, Sht 3) from scope of license renewal and from an AMR,

since this piping does not serve any pressure boundary function for the FP system. Therefore,

the staff finds the applicant’s response to RAI 2.3.3.8-1(3) to be acceptable.

In RAI 2.3.3.8-1(4), the staff requested that the applicant provide the basis for excluding

portions of the FP piping, fittings, valves, and fire connections from the scope of license

renewal. These components are shown on the system flow diagram (D-302-231, Sht. 4) in the

turbine building (at locations D6, E6, E7, E9, D10, F7, F8, F9, and F10). The staff disagrees

with the applicant’s QR designation to isolate portions of the FP components by manual valves.

In a letter dated June 12, 2003, the applicant stated that the fire hose stations are included in

the expanded scope for license renewal. The applicant further stated that the components

added by this expansion of scope are subject to screening. If screened in, FPP will manage the

aging of these components. In a letter dated September 2, 2003, the applicant stated that the

plant had performed further review and determined that these components are passive, longlived, and support a license renewal intended function as a pressure boundary for the fire

service system. The FPP will manage the aging of these components for the period of

extended operation. 

The staff reviewed the applicant’s response and agrees with the applicant’s decision to include

the FP piping, fittings, valves, and fire hose stations in the expanded scope for license renewal. 

Therefore, the staff finds the applicant’s response to RAI 2.3.3.8-1(4) to be acceptable.

In RAI 2.3.3.8-1(5), the staff requested that the applicant provide a basis for excluding FP

piping, fittings, and valves from the scope of license renewal and subject to an AMR. These

components are shown in system flow diagram (D-302-231, Sht. 5), in south area, El 412' (at

locations J6 to J9), of the turbine building.

In a letter dated June 12, 2003, the applicant stated that the valve manifolds are included in the

expanded scope for license renewal. The applicant further stated that the components added

by this expansion of scope are subject to screening. If screened in, FPP will manage the aging

of these components. In a letter September 2, 2003, the applicant stated that the plant had

performed further review and determined that these components are passive, long lived, and

support a license renewal intended function as a pressure boundary for fire service system. 

The FPP will manage the aging of these components for the period of extended operation.
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The staff reviewed the applicant’s response and agrees with the applicant that the valve

manifolds should be included in the expanded scope for license renewal. Therefore, the staff

finds the applicant’s response to RAI 2.3.3.8-1(5) to be acceptable.

In RAI 2.3.3.8-1(6), the staff requested that the applicant provide basis for excluding the carbon

dioxide (CO2) system electric control panels and the IF&S system (in P&ID drawing D-302-232)

from the scope of license renewal. 

In response to RAI 2.3.3.15-5, dated June 12, 2003, the applicant clarified that the CO2 system

electric control panels and IF&S system are not within scope because these are active

components.

The staff reviewed the applicant’s response and finds the applicant’s response to RAI 2.3.3.8-

1(6) to be acceptable.

In RAI 2.3.3.8-1(7), the staff requested that the applicant provide basis for excluding the valve

station system from the scope of license renewal. The system is shown in system flow diagram

(1MS-55-059) in the turbine building. These FP components perform a pressure boundary

intended function with the rest of the FP water supply system that is in scope.

In a letter dated June 12, 2003, the applicant stated that the valve manifolds will be included in

the expanded scope for license renewal. This is the same valve manifold as in RAI 2.3.8-1(5)

contained in a different drawing. The applicant further states that the components added by

this expansion of scope are subject to screening. If screened in, the FPP will manage the aging

of these components. In a letter September 2, 2003, the applicant stated that the plant had

performed further review and determined that these components are passive, long-lived, and

support a license renewal intended function as a pressure boundary for the fire service system. 

The FPP will manage the aging of these components for the period of extended operation.

The staff reviewed the applicant’s response and agrees with the applicant’s decision to include

the valve manifolds in the expanded scope for license renewal. Therefore, the staff finds the

applicant’s response to RAI 2.3.3.8-1(7) to be acceptable.

By letter dated March 28, 2003, in RAIs 2.3.3.8-1(8) and (10), the staff requested the applicant

to justify why the pre-action sprinkler system should not be in scope. The system is installed in

the diesel generator building and diesel fire pump room (as shown in system flow diagram 1MS55-085, Sht. 26). 

In its response dated June 12, 2003, the applicant stated that the fire suppression system for

the diesel generator building and diesel fire pump on drawing 1MS-55-085, Sht. 26, should be

highlighted as in scope. The system is listed as an FPER system by the plant procedures that

control the requirements for the FPP. The components in this system are subject to an AMR

and are encompassed by the component types listed in LRA Table 2.3.24.

The staff reviewed the applicant’s response and agrees with the applicant that the fire

suppression system is within the scope of license renewal. The staff, therefore, finds the

applicant’s response to RAIs 2.3.3.8-1(8) and (10) to be acceptable.
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By letter dated March 28, 2003, in RAI 2.3.3.8-1(9), the staff requested the applicant to justify

why the manual deluge sprinkler system for the charcoal filter plenum (XAA-40A-AH and XAA40b-AH) is not in scope. The system is in the auxiliary building, as seem in system flow

diagram 1MS-55-085-27-2. 

In their response dated June 12, 2003, the applicant stated that the emergency safeguards

feature filter system (i.e., control room emergency filter plenums and fuel handling charcoal

exhaust fire suppression system) is within the scope of license renewal, but the manual deluge

sprinkler system installed in charcoal filter plenums in the auxiliary building is not in scope. 

The staff review NUREG-0717, and its supplements, and the CLB for fire suppression in all

areas of the plant. The staff noted in NUREG-0717 (Supplement 3, August 1982) that no

automatic fire suppression system is required in charcoal filter plenums located in rooms 85-01,

88-25, 97-02, 00-02, 12-11 North, and 36-18 of the auxiliary building. The staff, therefore, finds

the applicant’s response to RAI 2.3.3.8-1(9) to be acceptable.

2.3.3.8.3 Conclusions

On the basis of its review described above, the staff concludes that the applicant has

adequately identified the FP SSCs that are within the scope of license renewal and subject to

an AMR in accordance with the requirements of 10 CFR 54.4(a) and 54.21(a)(1), respectively.

2.3.3.9 Fuel Handling System

2.3.3.9.1 Summary of Technical Information in the Application

The applicant describes the fuel handling system in LRA Section 2.3.3.9 and provides a list of

components subject to an AMR in LRA Table 2.3-25. The system is further described in

UFSAR Section 9.1.4, Fuel Handling System.

The fuel handling system consists of the equipment needed for transporting and handling

fuel. The associated fuel handling structures may be generally divided into the (1) refueling

cavity, (2) refueling canal and fuel transfer canal, which are flooded during plant shutdown for

refueling, (3) spent fuel pool, which is kept full of water and is accessible to operating

personnel, and (4) new fuel storage area. A fuel transfer tube connects the refueling canal and

the fuel transfer canal. This tube is fitted with a blind flange on the refueling canal end and a

gate valve on the fuel transfer canal end. This blind flange is always in place, except during

refueling, to ensure containment integrity. The fuel transfer tube is required to maintain

pressure boundary integrity.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and UFSAR Section 9.1.4 to determine whether the fuel

handling system components within the scope of license renewal and subject to an AMR had

been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff's

review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is

described below.
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In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During review of LRA Table 2.3-25, which lists component types subject to an AMR, the staff

noted that the table lists only the fuel transfer tube as a component subject to an AMR. 

However, license renewal boundary drawing D-302-651 indicated that the following components

are within scope — the fuel transfer tube, the fuel transfer tube blank flange, mechanical

fasteners for blank flange, the valve body for the fuel transfer tube gate valve, and the piping

and valve body for the vent line connected to the fuel transfer tube. Accordingly, by letter dated

March 28, 2003, in RAI 2.3.3.9-1, the staff requested that the applicant clarify whether these

components are included in a component type already listed in the table or justify the exclusion

of these components from being subject to an AMR.

By letter dated June 12, 2003, the applicant responded to this RAI. The applicant stated that

the mechanical component in the fuel handling system that is in scope is the transfer tube

shown on drawing D-302-651. The fuel transfer tube [XNF0009-FH], including pipe, blind

flange, and slip-on flange is installed inside a penetration sleeve. The fuel transfer tube is

welded to the penetration sleeve, which connects the fuel transfer canal in the sheltered

environment of the fuel handling building to the refueling cavity inside the reactor building. The

applicant classified the penetration sleeve itself as a civil/structural commodity. Drawing D-302-

651 also shows the spent fuel cooling system, which is described in LRA Section 2.3.3.22. The

fuel handling system only included the tube proper and the flange located in the reactor

building. The applicant stated that the associated gate valve body (XVM-06737-SF), the test

valve (XVG-06657-SF), and the test valve pipe are included with the spent fuel cooling system

in LRA Section 2.3.3.22. The applicant did not classify bolting as a separate component, but it

is subject to inspections required by ASME Code. This response clarifies how the individual

components that make up the fuel transfer tube assembly were included within the scope of

license renewal and were subject to an AMR.

2.3.3.9.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the fuel handling system that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the fuel handling system that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.3.10 Gaseous Waste Processing System

2.3.3.10.1 Summary of Technical Information in the Application
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The applicant describes the gaseous waste processing system (GWPS) in LRA Section

2.3.3.10 and provides a list of components subject to an AMR in LRA Table 2.3-26. The

system is further described in UFSAR Section 11.3, Gaseous Waste System.

The GWPS is designed to (1) remove fission product gases from the reactor coolant in the

volume control tank and (2) collect gases from the boron recycle and waste evaporators,

reactor coolant drain tank, recycle holdup tanks, and reactor vessel. The GWPS can hold

fission gases indefinitely.

The license renewal intended functions of the GWPS are to maintain containment isolation for

containment integrity and to maintain GWPS boundary with the component cooling water and

chemical and volume control systems.

LRA Table 2.3-26 lists the following components subject to an AMR — channel head, shell,

tubes, and tubesheet of heat exchangers; channel head, shell, spiral baffle, tube coils, and tube

manifolds of helical heat exchangers; pipe; tube and tube fittings; and body of valves. This

table also lists component intended functions.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and UFSAR Section 11.3 to determine whether the

gaseous waste disposal system components within the scope of license renewal and subject to

an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff's review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information regarding some components

in the GWPS was needed to complete its review. The system flow diagram drawing,

E-302-745, rev. 3 (catalytic hydrogen recombiner B) shows the piping of cooler condenser

continuing to drawing E-302-743. However, drawing E-302-743 is not included in the submittal

nor referenced in LRA Section 2.3.3.10. In a letter dated March 28, 2003, in RAI 2.3.3.10-1, the

staff requested the applicant to explain whether the license renewal boundary of gaseous waste

processing system extends to drawing E-302-743 and requested the applicant to supply

drawing E-302-743.

In its response, dated June 12, 2003, the applicant stated that drawing E-302-743 was not

supplied with the application but is available in the UFSAR as Figure 11.3-4, sheet 2. If drawing

E-302-743 were supplied as it highlighted, it would be the same as the recombiner shown on

drawing E-302-742, which was supplied with the application. Drawing E-302-744 provides the

detail of the A catalytic hydrogen recombiner. Drawing E-302-745 provides the detail of the B

catalytic hydrogen recombiner. The staff finds that the applicant’s response contained sufficient

information for the staff to complete its review.
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The system flow diagram drawing, E-302-742, rev. 11 (waste processing) does not identify the

heat-exchanger-shell-chemical-drain piping and valve 7938A to be within the scope of license

renewal. This piping and the housing of the valve provide a pressure retaining function. The

staff believed that these components are long-lived with passive function and, therefore, should

be within the scope of license renewal and subject to an AMR. In a letter dated March 28,

2003, in RAI 2.3.3.10-2, the staff requested the applicant to justify its exclusion of these

components from the scope of license renewal and subject to an AMR. 

In its response, dated June 12, 2003, the applicant stated that the piping up to and including

valves 7938A and 7938B is within scope. Drawings E-302-742, 743, 744, and 745 incorrectly

show the safety class as QRG” instead of safety class 2b (code class 3).” The staff finds the

applicant’s response acceptable because the component in scope is clarified.

2.3.3.10.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found except a scoping boundary drawing was not supplied with its

application. In addition, the staff performed an independent assessment to determine whether

any components subject to an AMR had not been identified by the applicant. No omissions

were found. On the basis of this review, the staff concludes that the applicant has adequately

identified the components of the GWPS that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the GWPS that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.11 Industrial Cooler System

2.3.3.11.1 Summary of Technical Information in the Application

The applicant describes the industrial cooler system in LRA Section 2.3.3.11. The applicant did

not identify any components of this system subject to an AMR in LRA. The system is further

described in UFSAR Section 9.4.7.2.5, Industrial Cooling System.

The industrial cooler system is a closed cooling system that supplies water to the cooling coils

of the reactor building cooling units during normal operation. The service water system cools

the reactor building cooling units during post-accident conditions following a loss of offsite

power. The activation of an ESF actuation system signal automatically transfers the source of

cooling water for the reactor building cooling units.

The only license renewal intended function of the industrial cooler system is to maintain reactor

building temperature monitoring capability during accident conditions. The applicant stated that

there are no mechanical components or component types required for the industrial cooler

system to perform its system intended function, thus requiring no AMR.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and UFSAR Section 9.4.7.2.5 to determine whether

the industrial cooler system components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). The staff's review
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was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not find any omissions.

2.3.3.11.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

had not been identified by the applicant. No omissions were found. In addition, the staff

performed an independent assessment to determine whether any components subject to an

AMR had not been identified by the applicant. No omissions were found during the

independent assessment. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the industrial cooler system that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the industrial cooler system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.12 Instrument Air Supply System

2.3.3.12.1 Summary of Technical Information in the Application

The applicant describes the instrument air system in LRA Section 2.3.3.12 and provides a list of

components subject to an AMR in LRA Table 2.3-27. The system is further described in

UFSAR Section 9.3.1, Compressed Air System.

The instrument air system, including the reactor building air system, provides clean, dry

air for instruments and controls. This system is not safety-related, with the exception of the

containment isolation valves for the reactor building air system and the piping between them. 

The containment isolation valves for the reactor building air system and the piping between

them are nuclear safety-related and in scope for license renewal because they form part of the

containment isolation boundary. With the exception of a few components, instruments and

controls served by the instrument air system fail in a safe position after a loss of air pressure. 

The following valves require air pressure to be placed in a safe position for certain design basis

events—the feedwater isolation valves, the control room outside air dampers, the emergency

feedwater system control valves, and the turbine driven emergency feedwater pump steam

isolation valve. These air-operated devices are equipped with safety-related air volume tanks

or accumulators, and these components are in scope for license renewal. Also in scope for

license renewal are the air accumulators and associated air components for various valves

required to perform a specified manipulation for event mitigation.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and UFSAR Section 9.3.1 to determine whether the

instrument air system components within the scope of license renewal and subject to an AMR

had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff's
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review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is

described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

Section 9.3.1.3 of the UFSAR identifies the feedwater isolation valves as valves that are

required to function following an accident and that do not fail in a safe position after a loss of air

supply. These air-operated valves are equipped with safety-related air accumulators to allow

operation of the valves following a loss of air supply from the instrument air system. However,

the applicant did not identify the accumulators and the related components necessary for

operation of the feedwater isolation valves among the components identified in the drawings

referenced in LRA Sections 2.3.3.12 and 2.3.4.5 as being within the scope of license renewal. 

Accordingly, by letter dated March 28, 2003, in RAI 2.3.3.12-1, the staff requested that the

applicant clarify whether the accumulators and the related components necessary for the

operation of the feedwater isolation valves are within the scope of license renewal and subject

to an AMR, or justify their exclusion from being subject to an AMR in accordance with the

requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1).

By letter dated June 12, 2003, the applicant responded to this RAI. The applicant stated that

many components are typically supplied with various combinations of external-to-actuator air

accumulator tanks, check valves, pressure regulators, and solenoid valves, which were

evaluated with the instrument air system. These components are identified by the referenced

drawings in LRA Section 2.3.3.12 and are included in the various line items of LRA Table 2.3-

27. The accumulator is included as a tank. The applicant described that the accumulator for

the feedwater isolation valve is integrated into the design of the valve actuator and is within the

scope of license renewal, as indicated on license renewal drawing 1MS-25-898, “Actuator

Cylinder Assembly.”

The staff reviewed the response and found the response incomplete in that the associated

piping and valves necessary to deliver air at adequate pressure from the accumulator to the

actuator have not been adequately identified. By letter dated September 2, 2003, the applicant

supplemented its response with additional details regarding boundaries for review within the

complex assembly. The dried compressed air supplied to the valve from the Instrument Air

System is split to supply two subcomponents. One subcomponent is the high-pressure air

storage cylinder on the top of the operator. It is charged by a non-safety related air intensifier

that increases the air pressure for the high-pressure air storage cylinder. The inlet to the highpressure air storage cylinder has a check valve, which does not have a component identifier in

the component database, that provides an isolation boundary. The inlet to the pilot air storage

tank also has a check valve (XVG-01611A, B, or C-CV-FW), which provides an isolation

boundary. The pressure retaining components downstream of these check valves provide an

isolation boundary and are within the scope for license renewal. The staff found this additional

clarification acceptable.

The license renewal drawings referenced in LRA Section 2.3.3.12 identified the air

accumulators for several valves and dampers that require air pressure to be positioned to their

safe position or to actuate for event mitigation. However, the actuator housings associated with
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these dampers and valves were not included in the scope of license renewal. By letter dated

March 28, 2003, in RAI 2.3.3.12-2, the staff requested that the applicant clarify whether the

portions of the associated actuator housings that perform a passive pressure boundary

intended function are within the scope of license renewal and subject to an AMR, or justify their

exclusion from being subject to an AMR in accordance with the requirements of 10 CFR 54.4(a)

and 10 CFR 54.21(a)(1).

By letter dated June 12, 2003, the applicant responded to this RAI. The applicant stated that

valve actuators are considered active components and are not subject to aging management

review based on 10 CFR 54.21(a)(1)(i). The internal environment of air actuators is dried air,

and the applicant stated that there are no aging effects that require management for these

carbon steel actuators in dry air. Most of the actuators are in areas where leaking boric acid is

not credible. Those in areas where leaking boric acid may be found would be subject to boric

acid corrosion surveillances. These surveillances are performed to monitor the effect of leaking

acid, not specific components. The external environment of the actuators is considered moist

air. These actuators are located in a sheltered (i.e., indoors, non-condensing) environment. In

this type of environment, pitting and crevice corrosion are not considered aging effects that

require management. Therefore, the applicant concluded that the actuator will remain dry and,

even if some general corrosion is experienced, it would not be severe enough to challenge the

actuator’s ability to perform its intended function. The staff found this justification acceptable.

UFSAR Section 9.2.1.2 states that the fire protection system serves as a standby means of

cooling the diesel generators. When the diesel generator is operating in the emergency mode,

the cross-connect valve automatically opens on high lube oil temperature or high jacket water

temperature. UFSAR Section 9.3.1.3 states that these fire protection system valves are

equipped with QR air accumulators. By letter dated Mach 28, 2003, in RAI 2.3.3.12-3, the staff

requested that the applicant clarify whether the accumulators and associated components are

within the scope of license renewal and subject to an AMR. By letter dated June 12, 2003, the

applicant responded to this RAI. The applicant stated that the accumulators and associated

components for these valves (XVG-03105A/B-SW) are shown on license renewal drawing B817-048 as in scope. Accumulators are listed as tanks in Table 2.3-27 of the LRA. The staff

found that this response provided acceptable clarification of the LRA.

2.3.3.12.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the instrument

air system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the instrument air system that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.13 Leak Detection System

2.3.3.13.1 Summary of Technical Information in the Application
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The applicant describes the leak detection system in LRA Section 2.3.3.13 but does not identify

any components of this system subject to an AMR. The system is further described in UFSAR

Section 7.6.5, Leakage Detection System.

The leak detection system detects leaks from the reactor coolant pressure boundary, ESF

systems in the auxiliary building, and the feedwater system, and inputs to the plant annunciator

system. The leak detection system isolates leaks in certain critical systems by pump tripping

and valve closing through I&C.

The license renewal intended function of the leak detection system is to detect leaks of critical

components by instruments comprising of level switches, level transmitters, temperature

elements, and flow switches. The applicant stated that these instruments are all active, nonpressure boundary components, thus requiring no AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and UFSAR Section 7.6.5 to determine whether the

leak detection system components within the scope of license renewal and subject to an AMR

had been identified in accordance with the requirements of 10 CFR 54.4 and 54.21(a)(1),

respectively. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below. In the performance of this review, the staff selected

system functions described in the UFSAR that were set forth in 10 CFR 54.4 to verify that

components having intended functions were not omitted from the scope of the Rule. The staff

also focused on components that were not identified as being subject to an AMR to determine if

any components were omitted. As a result of this review, the staff did not identify any

omissions.

2.3.3.13.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

had not been identified by the applicant. No omissions were found. In addition, the staff

performed an independent assessment to determine whether any components subject to an

AMR had not been identified by the applicant. No omissions were found during the

independent assessment. On the basis of this review, the staff concludes that the applicant

has adequately identified the components of the leak detection system that are within the scope

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately

identified the components of the leak detection system that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.3.14 Liquid Waste Processing System

2.3.3.14.1 Summary of Technical Information in the Application

The applicant describes the liquid waste processing system (LWPS) in LRA Section 2.3.3.14

and provides a list of components subject to an AMR in LRA Table 2.3-28. The system is

further described in UFSAR Section 11.2, Liquid Waste Systems.

The LWPS collects, segregates, and processes reactor-grade and non-reactor-grade liquid

wastes produced during plant operation, refueling, and maintenance activities. The processed
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reactor-grade stream is recycled for plant use. All the non-reactor-grade liquids are processed

and disposed in accordance with applicable NRC regulations.

The LWPS does not perform any safety-related functions with respect to reactor cooling,

shutdown, or accident mitigation. However, two of the lines in the system penetrate the

containment and portions of the system are safety-related. The system also maintains a

pressure boundary with safety-related systems, including the component cooling system and

spent fuel cooling system.

LRA Table 2.3-28 lists the following components subject to an AMR — channel head, tubes,

and tubesheet of condensers; shell, tubes, and tubesheet, manifold of heat exchangers; pipe;

and body of valves. This table also lists component intended functions.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and UFSAR Section 11.2 to determine whether the

liquid waste disposal system components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff's review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information regarding some components

in the LWPS was needed to complete its review. LRA Section 2.3.3.14 states that the licence

renewal boundaries for the liquid waste processing system are depicted in drawing E-302-735. 

LRA Table 2.3-28 lists condensers and heat exchangers as components subject to an AMR. 

However, only one heat exchanger was identified in drawing E-302-735 (i.e., reactor coolant

drain heat exchanger). In a letter dated March 28, 2003, in RAI 2.3.3.14-1, the staff requested

the applicant to explain where the other heat exchanger/s and condensers could be found in the

LRA.

In its response, dated June 12, 2003, the applicant stated that besides the components for the

reactor coolant drain tank, the components for the waste evaporator are also included in LRA

Section 2.3.3.14. The components for the waste evaporator can be found on drawing

1MS-09-238 which was provided as a license renewal boundary drawing. Drawing 1MS-09-238

should have been listed in LRA Section 2.3.3.14. The waste evaporator is shown on drawing

E-302-736, which is UFSAR Figure 11.2-2, sheet 2. This drawing was not provided as a license

renewal boundary drawing because it contains no components in scope. The staff finds the

applicant’s response acceptable because the components in scope are clarified.

2.3.3.14.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawing to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to
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determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the LWPS that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components of the LWPS that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.3.15 Nuclear and Non-nuclear Plant Drains

2.3.3.15.1 Summary of Technical Information in the Application

The applicant describes the nuclear and non-nuclear plant drains system in LRA Section

2.3.3.15 and provides a list of components subject to an AMR in LRA Table 2.3-29. UFSAR

Section 9.3.3 provides additional information for the system.

The nuclear and non-nuclear plant drains system provides drainage paths for potentially

radioactive and non-radioactive liquid wastes through separate systems. Both systems drain

and hold up the expected fire fighting water flow with floor drains and sumps, but without using

sump pumps and associated discharge piping. The non-nuclear plant drains system does not

require an AMR because it performs an active function to trip the circulating water pump in

order to prevent flooding in the control and intermediate buildings. The nuclear plant drains

system is subject to an AMR because it is passive and performs a license renewal intended

function to provide reactor cavity drainage and containment isolation.

LRA Table 2.3-29 lists pipe and body of valves as the components subject to an AMR. This

table also lists component intended functions.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and UFSAR Section 9.3.3 to determine whether the

components of the nuclear and non-nuclear plant drains system within the scope of license

renewal and subject to an AMR had been identified in accordance with the requirements of 10

CFR 54.4 and 54.21(a)(1), respectively. The staff’s review was conducted in accordance with

Section 2.3 of the SRP-LR (NUREG-1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.3.15.3 Conclusions

The staff reviewed the LRA, the UFSAR, and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. No omissions were found. In addition, the staff performed an independent

assessment to determine whether any components subject to an AMR had not been identified

by the applicant. No omissions were found during the independent assessment. On the basis

of this review, the staff concludes that the applicant has adequately identified the components
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of the nuclear and non-nuclear plant drains system that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the components

of the nuclear and non-nuclear plant drains system that are subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.3.16 Nuclear Sampling System

2.3.3.16.1 Summary of Technical Information in the Application

The applicant describes the nuclear sampling system in LRA Section 2.3.3.16 and provides a

list of components subject to an AMR in LRA Table 2.3-30. The system is further described in

UFSAR Section 9.3.2, Process Sampling System.

The nuclear sampling system is designed for centralized sampling of primary system fluids and

permits continuous steam generator blowdown flow to the secondary cycle sampling system for

analysis. Samples requiring cooling and depressurization and which are, or could be,

radioactive are piped to the nuclear sampling room. The nuclear sampling system includes

sample vessels used at various locations throughout the plant. It also monitors primary letdown

water for failed fuel detection.

The license renewal intended functions of the nuclear sampling system are (1) sampling reactor

coolant and containment atmosphere following an accident, (2) maintaining containment

isolation for containment integrity, and (3) maintaining system boundary with the component

cooling system.

LRA Table 2.3-30 lists the following components subject to an AMR — shell and tubes of heat

exchangers, pipe, casing of pumps, tanks, tube and tube fittings, and body of valves. This table

also lists component intended functions.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and UFSAR Section 9.3.2 to determine whether the

nuclear sampling system components within the scope of license renewal and subject to an

AMR had been identified in accordance with the requirements of 10 CFR 54.4 and 54.21(a)(1),

respectively. The staff's review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not 

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.3.16.3 Conclusions

The staff reviewed the LRA, the UFSAR, and the accompanying scoping boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified by the

applicant. No omissions were found. In addition, the staff performed an independent

assessment to determine whether any components subject to an AMR had not been identified
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by the applicant. No omissions were found during the independent assessment. On the basis

of this review, the staff concludes that the applicant has adequately identified the components

of the nuclear sampling system that are within the scope of license renewal, as required by 10

CFR 54.4(a), and that the applicant has adequately identified the components of the nuclear

sampling system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.17 Radiation Monitoring System

2.3.3.17.1 Summary of Technical Information in the Application

The applicant describes the radiation monitoring system in LRA Section 2.3.3.17 and provides a

list of components subject to an AMR in LRA Table 2.3-31. UFSAR Section 11.4 and Table

11.4-1 provide additional information for the system. 

As indicated in the LRA, the license renewal review boundaries are depicted on the following

P&ID drawings:

• D-302-611, Component Cooling

• D-302-651, Spent Fuel Cooling

• D-302-771, Nuclear Sampling

• D-806-010, Radiation Monitoring System Diagram Area Gamma

• D-806-011, Radiation Monitoring System Diagram Area Gamma

The radiation monitoring system is designed to monitor process and effluent streams from the

plant in order to record and control releases of radioactive materials generated in the plant as a

result of normal operations and during postulated accidents. The system continuously monitors

plant effluent discharge paths under steady-state, transient, or accident conditions. After an

accident, the system provides information to aid in determining the magnitude of the accident. 

The radiation monitoring system has an intended function to provide post-accident monitoring

capability for the containment activities. The system control panel and alarm in the control

room are part of the control instrumentation that are reviewed with the control room

instrumentation. The system’s monitor assemblies, detectors, effluent flow measurement, and

meteorological instrumentation are the active components of the system that are not within the

scope of license renewal. In LRA Table 2.3-31, the applicant lists pipe, tanks, tube and tube

fittings, and valves (body only) as the components of the radiation monitoring system subject to

an AMR. These components are passive and perform their intended function without moving

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

based on a qualified life or specified time period.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17, UFSAR Section 11.4, and the P&ID drawings to

determine whether the components of the radiation monitoring system within the scope of

license renewal and subject to an AMR had been identified in accordance with the requirements

of 10 CFR 54.4(a) and 54.21(a)(1), respectively. The staff’s review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described below.
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In performing this review, the staff selected system functions described in the UFSAR that were

set forth in 10 CFR 54.4(a) to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information regarding some components

in the system was needed to complete its review. LRA Section 2.3.3.17 indicates that one of

the license renewal functions of the radiation monitoring system is to maintain system

boundaries with the component cooling system, spent fuel cooling system, and chemical and

volume control system (CVCS). The license renewal boundary drawings, D-302-611

(component cooling), D-302-651 (spent fuel cooling), and D-302-771 (nuclear sampling)

highlight the piping and components within the scope of license renewal for these systems. 

However, the components of the radiation monitoring system in scope are not defined on these

drawings. In a letter dated March 4, 2003, in RAI-2.3.3.17-1, the staff requested the applicant

to highlight the license renewal boundaries for the radiation monitoring system in these P&ID

drawings.

In its response dated April 3, 2003, the applicant stated that the only license renewal intended

function for the liquid radiation monitors shown on these drawings is as pressure boundaries for

the component cooling, spent fuel cooling, and nuclear sampling systems. Drawing D-806-005,

which was not depicted in LRA Section 2.3.3.17, is the radiation monitoring system drawing that

shows all the components of the monitors for the component cooling, spent fuel cooling, and

nuclear sampling systems. The applicant stated that drawing D-806-005, rather than P&IDs D302-611, D-302-651, and D-302-771, should have been the reference for liquid radiation

monitors. In addition, the area monitors on P&IDs D-806-010 and D806-011 are not included in

the LRA. Because these radiation monitors provide the required post-accident containment

monitoring capability and are environmentally qualified. These monitors perform the safety

function using an ion chamber probe inserted into the atmosphere of the reactor building. 

Therefore, its intended function is being performed by instrumentation, not by mechanical

components. The instrumentation performs an active function and is excluded from the AMR,

according to 10 CFR 54.21(a)(1). 

The staff reviewed the applicant’s response and additional drawings (i.e., D-806-005, D-806-

010, and D-806-011) and found its rationale acceptable for defining the radiation monitoring

system license renewal boundaries. The applicant has highlighted all the components of the

radiation monitors on drawing D-806-005 that are within the scope of license renewal and listed

pipe, tanks, tube and tube fittings, and valve in LRA Table 2.3-31 as the components subject to

an AMR. As a result of this review, the staff did not identify any omissions.

2.3.3.17.3 Conclusions

The staff reviewed the LRA and the supplied P&ID drawings to determine whether any SSCs

within the scope of license renewal had not been identified by the applicant. No omissions were

found. In addition, the staff performed an independent assessment to determine whether any

components subject to an AMR had not been identified by the applicant. No omissions were

found during the independent assessment. On the basis of this review, the staff concludes that

the applicant has adequately identified the components of the radiation monitoring system that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant
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has adequately identified the components of the radiation monitoring system that are subject to

an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.18 Reactor Makeup Water Supply System

2.3.3.18.1 Summary of Technical Information in the Application

The applicant describes the reactor makeup water supply system in LRA Section 2.3.3.18 and

provides a list of components subject to an AMR in LRA Table 2.3-32. UFSAR Section 9.2.7

and Table 9.2-17 provide additional information for the system. 

The license renewal boundaries are depicted in the following P&ID drawings:

• D-302-651, Spent Fuel Cooling

• D-302-675, Chemical and Volume Control

• D-302-791, Reactor Makeup

The reactor makeup water supply system provides storage for the recycled primary coolant

grade water. The system is designed to perform the following functions:

• supply water to the chemical and volume control system

• supply makeup water to the spent fuel pool

• provide a backup water supply for spray cooling in the pressurizer relief tank

• provide a water supply for makeup to and flushing of the reactor auxiliary systems

• provide storage capacity equal to or greater than the total of 84,000 gallon capacity of

the recycle holdup tanks for the recycle primary coolant grade water produced in the

boron recovery system and liquid waste processing system

The reactor makeup water pumps take suction from the reactor makeup water storage tank to

perform various operations in makeup and flushing throughout the system. The portion of the

reactor makeup water supply system between the reactor makeup water storage tank and the

CVCS and spent fuel cooling system is safety-related, and the remainder of the system is nonsafety-related.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and UFSAR Section 9.2.7 to determine whether the

components of the reactor makeup water supply system within the scope of license renewal

and subject to an AMR had been identified in accordance with 10 CFR 54.4(a) and 54.21(a)(1),

respectively. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below.

In performing this review, the staff selected system functions described in the UFSAR that were

set forth in 10 CFR 54.4(a) to verify that components having intended functions were not
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omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

The staff reviewed LRA Table 3.2-32 and the P&ID drawings and did not find any omissions,

except for a question regarding flow restrictors. Drawing D-302-791 highlights flow restrictors

(i.e., xps-009-mu and xps-158-mu) as components of the reactor makeup water supply system

within the license renewal scope. However, these components are not included in LRA Table

3.2-32. The flow restrictors are passive and long-lived and perform a pressure boundary

intended function with the piping that is in scope. In RAI 2.3.3.18-2, the staff requested the

applicant to clarify whether these flow restrictors should be in scope or justify their exclusion.

In its response, the applicant stated that these components are listed in Table 3.2-32 as the

“orifices,” that are subject to an AMR. As a result of this review, the staff did not identify any

omissions.

2.3.3.18.3 Conclusions

The staff reviewed the LRA and the accompanying boundary drawings to determine whether

any SSCs within the scope of license renewal had not been identified by the applicant. No

omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the reactor

makeup water supply system that are within the scope of license renewal, as required by

10 CFR 54.4(a), and that the applicant has adequately identified the components of the reactor

makeup water system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.19 Roof Drains System

2.3.3.19.1 Summary of Technical Information in the Application

The applicant describes the roof drains system in LRA Section 2.3.3.19 and provides a list of

components subject to an AMR in LRA Table 2.3-33. The roof drains system is not described

in the UFSAR. 

The roof drains system discharges water away from the demister banks and plenums of the

reactor building cooling units (RBCUs). The RBCUs are capable of operation during

emergency conditions with potential exposure to reactor building spray solution. The intended

function of this system is to maintain the RBCU drain flow piping integrity. In LRA Table 2.3-33,

the applicant lists “pipe” as component type subject to an AMR, as it serves as the pressure

boundary for the roof drain system. The license renewal boundaries for the RBCU drains are

depicted in P&ID drawing D-302-824. 

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 and Table 2.3-33 to determine whether the roof drains

system components within the scope of license renewal and subject to an AMR had been

identified in accordance with 10 CFR 54.4(a) and 54.21(a)(1), respectively. The staff’s review
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was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.

The LRA states that the roof drains system provides drainage for various plant structures. The

applicant determined that the drain piping from the demister banks and plenums of the RBCUs

are within the scope of license renewal. These pipes are subject to an AMR because they are

long-lived and perform a passive function. The piping for the drainage system does not provide

any valves to control flow, because water in the plenums needs to be drained out continuously. 

The license renewal boundary drawing, D-302-824, highlights all the pipes from the plenums as

the components within the scope of license renewal and subject to an AMR. As a result of this

review, the staff did not identify any omissions. 

2.3.3.19.3 Conclusions

The staff reviewed the LRA and drawing D-302-824 to determine whether any SSCs within the

scope of license renewal had not been identified by the applicant. No omissions were found. In

addition, the staff performed an independent assessment to determine whether any

components subject to an AMR had not been identified by the applicant. No omissions were

found during the independent assessment. On the basis of this review, the staff concludes that

the applicant has adequately identified the components of the roof drains system that are within

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has

adequately identified the components of the roof drain system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.3.20 Station Service Air System

2.3.3.20.1 Technical Information in the Application 

The applicant describes the station service air system (SSAS) in LRA Section 2.3.3.20, Station

Service Air System, and provides a list of components subject to an AMR in LRA Table 2.3-34. 

The SSAS is further described in UFSAR Section 9.3.1, Compressed Air System.

 

The primary function of the SSAS is to provide compressed air for general plant use. The

SSAS serves no safety function and is not required to achieve a safe reactor shutdown or to

mitigate the consequences of a LOCA. Station service air is distributed via quick disconnect

hose connections throughout the plant. The license renewal intended functions of the system

are to provide means for containment integrity and to supply compressed air for the 

reactor building personnel, emergency personnel, and equipment hatches. The license renewal

boundaries for the system are highlighted on P&ID drawings, D-302-241, “Station Service Air,”

and D-302-242, “Station Air Supply to Personnel, Emergency Personnel and Equipment

Hatches.”

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20, the applicable portions of UFSAR Section 9.3.1, and

the P&ID drawings to determine whether the SSAS components within the scope of license

renewal and subject to an AMR had been identified in accordance with the requirements of 10

CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. The staff’s review was conducted in

accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described below.
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In the P&ID drawings, the applicant highlighted those portions, including valves, tubing, and

piping, in the containment penetrations, that are required for providing containment isolation

following a LOCA as being within the scope of license renewal. Also, the applicant identified

the components with their intended functions in LRA Table 2.3-34. 

During the review, the staff reviewed the components listed in LRA Table 2.3-34 and verified

them with the P&ID drawings to ensure that components having intended functions were not

omitted from the scope of license renewal. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. The staff

found that the components of the SSAS that have an intended function meeting the criteria of 

10 CFR 54.4(a) have been identified as being within the scope of license renewal and subject

to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). As a result of this

review, the staff did not identify any omissions. 

2.3.3.20.3 Conclusions

The staff reviewed the LRA, UFSAR, and the P&ID drawings to determine whether any SSCs

within the scope of license renewal had not been identified by the applicant. No omissions were

found. In addition, the staff performed an independent assessment to determine whether any

components subject to an AMR had not been identified by the applicant. No omissions were

found during the independent review. On the basis of its review, the staff concludes that the

applicant has appropriately identified the SSAS components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has appropriately identified the

SSAS components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.21 Service Water System

2.3.3.21.1 Summary of Technical Information in the Application

The applicant describes the service water system (SWS) in LRA Section 2.3.3.21 and provides

a list of components subject to an AMR in LRA Table 2.3-35. The system is further described

in UFSAR Section 9.2.1, Service Water System.

The SWS provides water from the service water pond for cooling of the emergency diesel

generators, component cooling heat exchangers, HVAC mechanical water chiller condensers,

and service water pumphouse cooling coils. During post-accident conditions, loss of offsite

power or testing, the SWS cools the RBCUs. In addition, this system is the backup water

source for the emergency feedwater and CCW systems. The system consists of two

independent full capacity loops with the capability of valving a third swing service water pump

into either loop. The SWS is safety-related and is designed such that a single failure does not

cause loss of cooling to more than one of the redundant loops.

2.3.3.21.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.21 and UFSAR Section 9.2.1 to determine whether the

SWS components within the scope of license renewal and subject to an AMR had been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff’s review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below. 
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In the performance of this review the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

By letter dated March 28, 2003, in RAI 2.3.3.21-1, the staff requested that the applicant clarify

the configuration of temperature monitoring devices in the system and identify the portions of

these assemblies that are subject to an AMR. By letter dated June 12, 2003, the applicant

responded to this RAI and stated that thermowells are used in temperature monitoring and are

included in the scope of license renewal. Thermowells are listed in LRA Table 2.3-35 as a

component type subject to an AMR.

The staff reviewed service water interfaces with other systems. License renewal boundary

drawing (D-302-222) shows that the service water piping extends to drawing D-302-085 at

locations D12 and H12 for backup supply to the emergency feedwater pump suction and to

drawing D-302-611 at locations B8 and G8 for supply of CCW system makeup water. 

However, LRA Section 2.3.3.21 fails to reference drawings D-302-085 and D-302-611 to

include service water piping on these flow diagrams within the AMPs identified for the SWS.

Tables 2.3-22 and 2.3-40 of the LRA, which present aging management results for the CCW

and emergency feedwater systems respectively, do not reference AMPs consistent with the

component exposure to a raw water environment. A related issue exists with regard to FP

system piping that extends onto SWS drawing D-302-222 at locations B8-9 and J8-9 for supply

of backup cooling water to the EDGs from the FP water system. By letter dated March 28,

2003, in RAI 2.3.3.21-2, the staff requested that the applicant clarify how these piping segments

have been included in an AMR and what AMPs apply to these piping segments.

By letter dated June 12, 2003, the applicant responded to this RAI. The applicant stated that

the emergency feedwater alternate supply piping from the SWS up to check valves

XVC-01034A/B-EF and XVC-01022A/B-EF is included in the scope of the SWS reliability and

inservice testing program. The applicant also stated that the CCW system emergency makeup

water supply piping from the SWS up to the check valves XVC-09680A/B-CC is included in the

scope of the SWS reliability and inservice testing program. With respect to the alternate diesel

generator cooling water supply from the FP water system, the applicant described that the SWS

piping starts at the first breakdown orifices XPS-0146A and XPS-147A, and this piping is

included in the scope of the SWS reliability and inservice testing program. The piping upstream

of orifices XPS-0146A and XPS-147A is included in the scope of the FPP. The staff reviewed

this information and found that the piping segments were included with appropriate systems

based on the internal environment of the piping.

2.3.3.21.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the SWS that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant
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has adequately identified the components of the SWS that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.3.22 Spent Fuel Cooling System

2.3.3.22.1 Summary of Technical Information in the Application

The applicant describes the spent fuel pool cooling system in LRA Section 2.3.3.22 and

provides a list of components subject to an AMR in LRA Table 2.3-36. The system is further

described in UFSAR Section 9.1.3, Spent Fuel Cooling System.

The spent fuel cooling system cools spent fuel pool water to remove decay heat from the spent

fuel elements. This system also (1) transfers water between the refueling water storage tank

(RWST) and refueling cavity, (2) maintains purity and clarity of water in spent fuel pool and/or

refueling cavity, (3) provides means for adding boric acid to the spent fuel pool, (4) provides

means for adding demineralized water to the spent fuel pool, (5) monitors spent fuel coolant for

excessive radioactivity due to defective fuel elements, (6) provides for filtering and/or

demineralization to clean the water in the RWST, and (7) maintains a water shield above spent

fuel elements to limit radiation levels in the area of the pool.

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22 and UFSAR Sections 9.1.2 and 9.1.3 to determine

whether the spent fuel cooling system components within the scope of license renewal and

subject to an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). The

staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below. 

In the performance of this review the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.3.22.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the spent fuel

cooling system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the components of the spent fuel pool cooling

system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.23 Thermal Regeneration System

2.3.3.23.1 Summary of Technical Information in the Application
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The applicant describes the thermal regeneration system (BTRS) in LRA Section 2.3.3.23 and

provides a list of components subject to an AMR in LRA Table 2.3-37. The system is further

described in UFSAR Section 9.3.4, Chemical and Volume Control System. The license renewal

boundaries for the system are depicted in P&ID drawing E-302-676.

The LRA indicates that the load following capabilities of the (boron) thermal regeneration

system were removed by plant modification MRF 21511. Now the BTRS continues to be used

as the deborating demineralizers that reduce reactor coolant boron concentration towards the

end of core life. The soluble neutron absorber (boric acid) concentration is controlled by the

BTRS and the reactor makeup control system. The BTRS is also used to cool the letdown flow

for enhanced reactor coolant pump (RCP) seal performance and to clean up the reactor coolant

system (RCS) before shutting down the reactor. The letdown flow leaving the demineralizers

may be directed to the BTRS. The coolant flows through the reactor coolant filter and then

flows into the volume control tank through a spray nozzle on top of the tank. The BTRS is one

of the subsystems of the CVCS that has an intended function to maintain a pressure boundary

with the CVCS. 

2.3.3.23.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.23, UFSAR Section 9.3.4, and the P&ID drawing to

determine whether the components of the BTRS within the scope of license renewal and

subject to an AMR had been identified in accordance with 10 CFR 54.4(a) and 54.21(a)(1),

respectively. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described below.

In performing this review, the staff selected system functions described in the UFSAR that were

set forth in 10 CFR 54.4 to verify that components having intended functions were not omitted

from the scope of the Rule. The staff also focused on components that were not identified as

being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information regarding some components

in the system was needed to complete its review. LRA Section 2.3.3.23 states that the BTRS is

used as a deborating demineralizer to reduce reactor coolant boron concentration towards the

end of core life. LRA Table 2.3-37 lists heat exchangers (channel head), heat exchangers

(shell), heat exchangers (tubes), and heat exchangers (tube sheets) as the components of the

BTRS subject to an AMR. LRA Table 2.3-8 lists heat exchangers as the components of the

CVCS subject to an AMR. However, drawing E-302-676, which contains both the BTRS and

the CVCS, shows that the heat exchangers are within the boundary of the CVCS. There are no

heat exchangers in the boundary of the BTRS. In RAI 2.3.3.23-1, the staff requested the

applicant to explain whether the heat exchangers in LRA Table 2.3-37 for the BTRS are those

in LRA Table 2.3-8 for the CVCS and, if so, why the same heat exchangers are listed in both

the tables.

In its response, the applicant stated that the letdown reheat, letdown chiller, and moderating

heat exchangers are the components of the BTRS listed in LRA Table 2.3-37. The license

renewal intended function for these components is to maintain a pressure boundary for the

CVCS. The heat exchangers listed in LRA Table 2.3-8 are the CVCS heat exchangers for

regenerative, excess letdown, seal water, and letdown. The licensee stated that drawings were

highlighted during the screening process according to individual systems. Because there may
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be more than one system on a particular drawing, as in the case of E-302-676, the screening

process resulted in multiple copies of a drawing showing highlighting for each system. These

working copies are available on site for inspection. The drawings supplied to the NRC are

composite drawings showing highlighting, in some instances, for multiple systems. Since the

applicant has clarified that the heat exchangers listed in LRA Table 2.3-37 are the components

of the BTRS being subject to an AMR, the staff finds the applicant’s response acceptable. 

The staff examined the SCs in LRA Table 2.3-37 to determine whether they are the only SCs

that are subject to an AMR in accordance with 10 CFR 54.21(a)(1). On the basis of the above

review, the staff did not find any omissions by the applicant.

2.3.3.23.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the BTRS that

are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant

has adequately identified the components of the system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4 Steam and Power Conversion Systems

The steam and power conversion systems act as a heat sink to remove heat from the nuclear

steam supply system and convert the heat generated in the reactor to the plant’s electrical

output.

2.3.4.1 Auxiliary Boiler Steam and Feedwater System

2.3.4.1.1 Summary of Technical Information in the Application

The applicant describes the auxiliary boiler steam and feedwater (AS) system in LRA Section

2.3.4.1 and provides a list of components subject to an AMR in LRA Table 2.3.38. 

The AS system provides steam to various plant equipment, as required during all modes of

operation. The system is non-safety-related and performs an intended function to isolate the

section of the AS piping supplying the auxiliary building in order to prevent a high energy fluid

piping rupture from affecting safety-related equipment in the auxiliary building. The license

renewal boundaries of the system are depicted on the P&ID drawing, D-302-051, Auxiliary

Steam.”

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 to determine whether the AS system components within

the scope of license renewal and subject to an AMR had been identified in accordance with 10
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CFR 54.4 and 54.21(a)(1). The staff’s review was conducted in accordance with Section 2.3 of

the SRP-LR (NUREG-1800) and is described below. 

In the performance of the review, the staff selected system functions described in LRA Section

2.3.4.1 that were set forth in 10 CFR 54.4 to verify that components having intended functions

were not omitted from the scope of the Rule. The staff also focused on components that were

not identified as being subject to an AMR to determine if any components were omitted. As a

result of this review, the staff did not identify any omissions.

2.3.4.1.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has appropriately identified the components of the AS system

that are within the scope of license renewal, as required by 10 CFR 54.4, and that the applicant

has appropriately identified the components of the AS system that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4.2 Condensate System

2.3.4.2.1 Summary of Technical Information in the Application

The applicant describes the condensate system in LRA Section 2.3.4.2 and provides a list of

components subject to an AMR in LRA Table 2.3.39. The system is further described in

UFSAR Section 10.4.7. 1, Condensate System.

The condensate system pumps condensed turbine exhaust steam from the main condenser

hotwell through the low pressure feedwater heaters to maintain deaerator storage tank level for

anticipated operating conditions. It also serves as a source of cooling water for the steam

packing condenser and steam blowdown heat exchanger, and provides sealing water for

various vacuum valves and feedwater pump seals. Except for the condensate storage tank

(CST), the condensate system is non-safety-related. The CST is safety-related because it is

the primary inventory source for the emergency feedwater system. The license renewal

boundaries for the system are depicted on the P&ID drawings, D-302-085 and 1MS-17-125.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and UFSAR Section 10.4.7.1 to determine whether the

condensate system components within the scope of license renewal and subject to an AMR had

been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). The staff’s review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below. 

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not
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omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff identified that the 10-inch atmospheric vent pipe on top of the CST

was not highlighted in drawing D-302-101(at location A12) as being in scope and subject to an

AMR for license renewal. Also, this vent pipe was not shown on the CST in drawing D-302-085.

The staff believes that the vent pipe has an intended function to provide vacuum protection for

the tank and is in scope. By letter dated March 28, 2003, in RAI 2.3.4.2-1, the staff requested

the applicant to explain why this 10-inch vent pipe was not within the scope of license renewal. 

In its response dated June 12, 2003, the applicant stated that the 10-inch vent pipe performs its

function by not being a pressure boundary and plugging of this vent pipe is not a credible event. 

In addition, the inspection of the tank by the inspections for mechanical components program

will detect any degradation of the vent pipe.

 

The staff reviewed the applicant’s response and found it acceptable because the applicant has

justified that the vent does not have a preserving pressure boundary function and is not in

scope nor subject to an AMR for license renewal. The applicant further explained that this vent

pipe was not shown on the CST in drawing D-302-085 because this drawing only shows

emergency feedwater connections. The staff found the applicant’s response acceptable

because it provides the reason for not showing the vent pipe on LRA drawing D-302-085.

During its review, the staff also identified that the piping attached to the CST, and up to the first

isolation valve, was not highlighted in drawing D-302-101 as components within the scope of

license renewal and subject to an AMR. By letter dated March 4, 2003, in RAI 2.3.4.2-2, the

staff asked the licensee to justify the exclusion of the piping attached to the CST from the

scope of license renewal. By letter dated April 3, 2003, the applicant stated that the CST is

designed to have a reserve volume dedicated for use by the emergency feedwater (EF) system,

that the connections below this reserve volume, and only those, are designated as EF

components and are, therefore, within the scope of license renewal. The applicant further

explained that other tank connections are located above this reserve volume, do not affect the

water supply to the EF system and, therefore, are not included in scope for license renewal. 

The staff found the applicant’s response acceptable because it explains why some of the piping

connected to the CST is not highlighted as components in the scope of license renewal. As a

result of this review, the staff did not identify any omissions.

2.3.4.2.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has adequately identified the components of the condensate

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has adequately identified the components of the condensate system that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.3 Emergency Feedwater System
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2.3.4.3.1 Summary of Technical Information in the Application

The applicant describes the emergency feedwater system in LRA Section 2.3.4.3 and provides

a list of components subject to an AMR in LRA Table 2.3.40. The system is further described in

UFSAR Section 10.4.9, Emergency Feedwater System.

The emergency feedwater system is designed to deliver feedwater to the steam generators for

cooldown subsequent to a loss of feedwater supply and during an ATWS event. The system

also supplies feedwater to the steam generators during testing, startup, shutdown, and layup

operations. During normal plant operation, the system is in a standby condition, with the

system controls set for automatic operation. The license renewal boundaries for the system are

depicted on the P&ID drawings, D-302-085 and 1MS-17-125.

2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and UFSAR Section 10.4.9 to determine whether the

emergency feedwater system components within the scope of license renewal and subject to

an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below. 

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff identified that on drawing D 302-085, the license renewal boundaries 

of the emergency feedwater system piping terminate at locked open valves,1026-EF (at

location G4), 1025A-EF (at location A5), and 1025B-EF (at location E5). It appeared that the

2-inch and 3-inch lines that extend upstream of these valves should be within the scope of

license renewal to meet the requirements of 10 CFR 54.4(a)(2). By letter dated March 28,

2003, in RAI 2.3.4.3-1, the staff asked the applicant to explain why the 2-inch and 3-inch lines

downstream of these valves and on the return path to the CST, up to and including check valve

1027-EF, are not highlighted as being within the scope of license renewal. 

In its response dated June 12, 2003, the applicant stated that failure of the non-safety-related

recirculation piping downstream of the breakdown orifices (located upstream of the locked open

valves listed above) would not affect the ability of the emergency feedwater system to deliver

380 gpm to 2/3 steam generators and that this position was accepted as a part of the licensing

basis. This is because failure to establish recirculation flow is mainly of concern when

approaching hot shutdown (RHR conditions) while EF flow is being throttled back. The

applicant further stated that the loss of condensate quality water due to postulated breakage of

the non-safety-related recirculation piping would not compromise safe shutdown based on the

provision of two trains of service water as backup. The staff found the applicant’s response

acceptable because the applicant demonstrated that failure of the non-safety-related

recirculation lines downstream of the breakdown orifices (located upstream of the locked open

valves listed above) would not prevent satisfactory accomplishment of the function identified in

10 CFR 54.4(a)(ii). As a result of this review, the staff did not identify any omissions.
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2.3.4.3.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCS within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes the applicant has appropriately identified the components of the emergency

feedwater system that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and that the applicant has appropriately identified the components of the emergency feedwater

system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.4 Extraction Steam System

2.3.4.4.1 Summary of Technical Information in the Application

The applicant describes the extraction steam system in LRA Section 2.3.4.4 and provides a list

of components subject to an AMR in LRA Table 2.3-41. The system is not described in the

UFSAR.

The extraction steam system supplies steam for heating the condensate and feedwater, and for

maintaining the auxiliary boilers in a hot stand-by condition. The license renewal intended

function of this system is to provide a means of main steam isolation for a steamline break

coincident with failure of a main steam isolation valve.

LRA Table 2.3-41 lists pipe and body of valves as components subject to an AMR. This table

also lists component intended functions. The license renewal boundaries of the system are

depicted on P&ID drawing, D-302-041.

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 to determine whether the extraction steam system

components within the scope of license renewal and subject to an AMR had been identified in

accordance with 10 CFR 54.4 and 54.21(a)(1). The staff’s review was conducted in accordance

with Section 2.3 of the SRP-LR (NUREG-1800) and is described below.

In the performance of this review, the staff selected system functions described in LRA Section

2.3.4.4 that were set forth in 10 CFR 54.4 to verify that components having intended functions

were not omitted from the scope of the Rule. The staff also focused on components that were

not identified as being subject to an AMR to determine if any components were omitted. As a

result of this review, the staff did not identify any omissions.

2.3.4.4.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawing to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the
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staff concludes that the applicant has adequately identified the components of the extraction

steam system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

that the applicant has adequately identified the components of the extraction steam system that

are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.5 Feedwater System

2.3.4.5.1 Summary of Technical Information in the Application

The applicant describes the feedwater system in LRA Section 2.3.4.5 and provides a list of

components subject to an AMR in LRA Table 2.3.4.2. The system is further described in

UFSAR Section 10.4.7.2, Feedwater System. 

The feedwater system pumps feedwater from the deaerator storage tank through two stages of

high pressure heaters to the steam generators. The operation of the system ensures that the

required amount of heated and deaerated water is available to maintain an adequate steam

generator water level during normal plant operation and transients. The nuclear portion of the

feedwater system conveys feedwater from the non-nuclear portion of the feedwater system (in

the turbine building) to the steam generators, and includes the containment isolation valves.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and UFSAR Section 10.4.7.2 to determine whether the

feedwater system components within the scope of license renewal and subject to an AMR had

been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff’s

review was conducted in accordance with section 2.3 of the SRP-LR (NUREG-1800) and is

described below. 

In the performance of the review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.4.5.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

No omissions were found during the independent assessment. On the basis of this review, the

staff concludes that the applicant has appropriately identified the components of the feedwater

system that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that

the applicant has appropriately identified the components of the feedwater system that are

subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.6 Gland Sealing Steam System

2.3.4.6.1 Summary of Technical Information in the Application
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The applicant describes the gland sealing steam system (GSSS) in LRA Section 2.3.4.6 and

provides a list of components subject to an AMR in LRA Table 2.3-43. The system is further

described in UFSAR Sections 10.4.3 and 10.3.2.3.

The GSSS supplies steam to the main turbine and feedwater pump turbine shaft seals to

prevent air leakage into and/or steam leakage out of the turbine casings. Sealing steam is

normally supplied to the GSSS by the main steam system under all load conditions, but also

can be supplied by the auxiliary boiler through the auxiliary steam system. The license renewal

intended function of this system is to provide a means of main steam isolation for a steamline

break coincident with failure of a main steam isolation valve.

LRA Table 2.3-43 lists pipe and body of valves as the components subject to an AMR. This

table also lists component intended functions. The license renewal boundaries of the system

are depicted on P&ID drawing D-302-141.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and UFSAR Sections 10.3.2.3 and 10.4.3 to determine

whether the GSSS components within the scope of license renewal and subject to an AMR had

been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff’s

review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is

described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted.

During its review, the staff determined that additional information regarding some components

in the GSSS was needed to complete its review. The license renewal boundary drawing of the

GSSS (in drawing D-302-141, rev. 15) does not highlight the stop valve (S.V. # 1) as one of the

components in the scope of license renewal. However, LRA Table 2.3-43 lists pipe and valve

body as the component types subject to an AMR. Based on this review, the staff was unable to

determine whether the stop valve was subject to an AMR. The valve body of the stop valve

provides a pressure retaining function and the component is passive and long-lived. Therefore,

the staff believed that this component should be in scope and subject to an AMR for license

renewal. In a letter dated December 11, 2002, in RAI 2.3.4.6-1, the staff requested the

applicant to clarify whether the valve body of the stop valve was in scope and subject to an

AMR, or justify its exclusion.

In its response, dated January 27, 2003, the applicant stated that the four stop valves (S.V. #1–

#4) are all in scope. They are shown on drawing D-302-012 and are included in LRA Section

2.3.4.7, Main Steam System. The staff finds the applicant’s response acceptable because the

applicant has clarified the components in scope. On the basis of the above review, the staff did

not find any omissions by the applicant.

2.3.4.6.3 Conclusions
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The staff reviewed the LRA and the accompanying scoping boundary drawing to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

Again, no omissions were found during the independent assessment. On the basis of this

review, the staff concludes that the applicant has adequately identified the components of the

GSSS that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the components of the GSSS that are subject to an AMR, as

required by 10 CFR 54.21(a)(1).

2.3.4.7 Main Steam System

2.3.4.7.1 Summary of Technical Information in the Application

The applicant describes the main steam (MS) system in LRA Section 2.3.4.7 and provides a list

of component types subject to an AMR along with their associated intended functions in LRA

Table 2.3-44. UFSAR Section 10.3, Main Steam System, provides additional information for

the MS system. 

The MS system conveys saturated steam from the three steam generators to the turbinegenerator. The system also supplies MS, through its branch lines, to the following systems and

components:

• main feedwater pump drive turbines

• emergency feedwater pump drive turbine

• moisture separator reheaters

• auxiliary steam system

• deaerating feedwater heater

• steam dumps to the condenser and atmosphere

The license renewal boundaries of the MS system are highlighted on the following P&ID

drawings:

• D-302-011, Main Steam (Nuclear)

• D-302-012, Main Steam (Non-Nuclear)

• D-302-014, Main & Reheat Steam (Non-Nuclear)

• D-302-121, Steam Drains

• D-302-122, Feed Pump Start-Up, Extraction & Mis. Steam Drains

• D-302-181, Turbine Cycle Sampling

• 1MS-17-125-5, Diagram-Terry Turbine Oil Piping

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.7 and UFSAR Section 10.3 to determine whether the MS

system components within the scope of license renewal and subject to an AMR had been

identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The staff’s review was

conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and is described

below.
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In the performance of this review, the staff selected system functions described in the UFSAR

that were required by 10 CFR 54.4 to verify that components having intended functions were

not omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.4.7.3 Conclusions

The staff reviewed the LRA and accompanying license renewal boundary drawings to

determine whether any SSCs within the scope of license renewal had not been identified, as

such, by the applicant. No omissions were found. In addition, the staff performed an

independent assessment to determine whether any components subject to an AMR had not

been identified by the applicant. Again, no omissions were found during the independent

assessment. On the basis of this review, the staff concludes that the applicant has

appropriately identified the components of the MS system that are within the scope of license

renewal, as required by 10 CFR 54.4, and that the applicant has appropriately identified the

components of the MS system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.8 Main Steam Dump System

2.3.4.8.1 Summary of Technical Information in the Application

The applicant describes the main steam dump system in LRA Section 2.3.4.8 and provides a

list of component types subject to an AMR along with their associated intended functions in

LRA Table 2.3-45. The system is further described in UFSAR Section 10.4.4, “Turbine Bypass

System.”

The MS system is capable of following a large turbine-generator load reduction without reactor

trip through actuation of the main steam dump system. This system bypasses main steam to

the main condenser and/or to the atmosphere. Steam dump valves permit unit operation at

turbine loads lower than the minimum power setting (15 percent reactor power) of the nuclear

steam supply system (NSSS) automatic control. In addition, the steam dump valves permit

reduction of turbine-generator load at a rate greater than the 5 percent per minute maximum

rate of load reduction for the NSSS.

The license renewal intended function of this system is to provide a means for main steamline

isolation (when used in conjunction with components of various other systems) following a main

steamline break coincident with the failure of a main steam isolation valve (MSIV). The license

renewal boundaries are depicted on P&ID drawing, D-302-031, Main Steam Dump System.”

2.3.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.8, and UFSAR Section 10.4.4 to determine whether the

main steam dump system components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. The

staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG-1800) and

is described below.
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In the performance of this review, the staff selected system functions described in the UFSAR

that were required by 10 CFR 54.4 to verify that components having intended functions were

not omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.4.8.3 Conclusions

The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

Again, no omissions were found during the independent assessment. On the basis of this

review, the staff concludes that the applicant has appropriately identified the components of the

main steam dump system that are within the scope of license renewal, as required by 10 CFR

54.4, and that the applicant has appropriately identified the components of the main steam

dump system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.9 Main Turbine and Turbine Accessories Systems

2.3.4.9.1 Summary of Technical Information in the Application

The applicant describes the main turbine and turbine accessories systems in LRA Section

2.3.4.9. The system is further described in UFSAR Section 10.2, Turbine Generator.

The main turbine system receives main steam from the steam generators, via the MS system,

and converts the steam energy into mechanical energy for the main generator. The turbine

accessories system supplies high pressure bearing lift oil to the turbine and generator bearings

to lift the shaft slightly and reduce the torque requirements on the turning gear. These two

systems provide turbine trip signals that have a license renewal intended function of providing a

means of main steam isolation (when used in conjunction with various other systems) following

a main steamline break coincident with the failure of a MSIV. There are no mechanical

components required for the main turbine or turbine accessories systems to perform their

system intended functions; therefore, no AMR is required and no P&ID drawings are provided

to depict these license renewal evaluation boundaries. 

2.3.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.9 and UFSAR Section 10.2 to determine whether the

components of the main turbine and turbine accessories system within the scope of license

renewal had been identified in accordance with 10 CFR 54.4. The staff also reviewed those

same components to determine whether any of them are subject to an AMR in accordance with

10 CFR 54.21(a)(1). The staff’s review was conducted in accordance with Section 2.3 of the

SRP-LR (NUREG-1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR 

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on those same components to
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determine if any of them should be subject to an AMR. As a result of this review, the staff did

not identify any omissions by the applicant.

2.3.4.9.3 Conclusions

The staff reviewed the LRA and the UFSAR to determine whether any SSCs within the scope of

license renewal had not been identified by the applicant. No omissions were found. In addition,

the staff performed an independent assessment to determine whether any components of the

main turbine and turbine accessories systems subject to an AMR had been identified by the

applicant. No components subject to an AMR were found. On the basis of this review, the staff

concludes that the applicant has appropriately identified the components of the main turbine

and turbine accessories systems that are within the scope of license renewal, as required by 10

CFR 54.4, and that the applicant has rationally concluded that there are no components of the

main turbine and turbine accessories systems that are subject to an AMR in accordance with

10 CFR 54.21(a)(1).

2.3.4.10 Turbine Cycle Sampling System

2.3.4.10.1 Summary of Technical Information in the Application

The applicant describes the turbine cycle sampling system in LRA Section 2.3.4.10 and

provides a list of component types subject to an AMR along with their associated intended

functions in LRA Table 2.3-46. The system is further described in UFSAR Section 10.3.5,

Water Chemistry

The turbine cycle sampling system provides sampling of secondary system fluids from locations

such as the main condenser hotwell, deaerator, feedwater booster pumps, high pressure heater

drains, emergency feedwater pumps, and main steam system. The license renewal intended

function of this system is to provide a means of main steam isolation (when used in conjunction

with various other systems) for a steamline break coincident with MSIV failure. The system

license renewal boundaries are highlighted on P&ID drawings D-302-012, “Main Steam

System,” and D-302-181, “Turbine Cycle Sampling.”

2.3.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.10 and UFSAR Section 10.3.5 to determine whether the

turbine cycle sampling system components within the scope of license renewal and subject to

an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. 

The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of license renewal. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. As a result

of this review, the staff did not identify any omissions.

2.3.4.10.3 Conclusions
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The staff reviewed the LRA and the accompanying scoping boundary drawings to determine

whether any SSCs within the scope of license renewal had not been identified by the applicant. 

No omissions were found. In addition, the staff performed an independent assessment to

determine whether any components subject to an AMR had not been identified by the applicant. 

Again, no omissions were found during the independent assessment. On the basis of this

review, the staff concludes that the applicant has appropriately identified the components of the

turbine cycle sampling system that are within the scope of license renewal, as required by 10

CFR 54.4, and that the applicant has appropriately identified the components of the turbine

cycle sampling system that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.4.11 Steam Generator Blowdown System

2.3.4.11.1 Summary of Technical Information in the Application

The applicant describes the steam generator blowdown system in LRA Section 2.3.4.11 and

provides a list of component types subject to an AMR along with their associated intended

functions in LRA Table 2.3-47. The system is further described in UFSAR Section 11.4.8,

Steam Generator Blowdown System.

The steam generator blowdown system continuously purges the steam generators of

concentrated impurities, thereby maintaining secondary side steam generator water chemistry. 

This system is non-safety-related, except for the portion inside the reactor building, up to and

including the containment isolation valves. The system license renewal boundaries are

highlighted on P&ID drawings D-302-771, “Nuclear Sampling,” and D-302-781, “Steam

Generator Blowdown.”

2.3.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.11 and UFSAR Section 11.4.8 to determine whether the

steam generator blowdown system components within the scope of license renewal and subject

to an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1), respectively. 

The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR (NUREG1800) and is described below.

In the performance of the review, the staff selected system functions described in the UFSAR

that are required by 10 CFR 54.4 to verify that components having intended functions had not

been omitted from the scope of license renewal rule. The staff also focused on components

that were not identified as being subject to an AMR to determine if any components were

omitted. As a result of this review, the staff did not identify any omissions.

2.3.4.11.3 Conclusions

The staff reviewed the LRA and accompanying license renewal boundary drawings to

determine whether any SSCs within the scope of license renewal had not identified been by the

applicant. No omissions were found. In addition, the staff performed an independent

assessment to determine whether any components subject to an AMR had not been identified

by the applicant. Again, no omissions were found during the independent assessment. On the

basis of this review, the staff concludes that the applicant has appropriately identified the

components of the steam generator blowdown system that are within the scope of license
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renewal, as required by 10 CFR 54.4, and that the applicant has appropriately identified the

components of the steam generator blowdown system that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.3.4.12 Turbine Electro-Hydraulic System

2.3.4.12.1 Summary of Technical Information in the Application

The applicant describes the turbine electro-hydraulic system in LRA Section 2.3.4.12, but does

not provide any table to list system components subject to an AMR. The system is further

described in UFSAR Section 10.2.2.2, Turbine Generator Control.

The turbine electro-hydraulic system actuates and controls the turbine steam valves. This

system is completely separated from the bearing oil supply. During normal plant operation,

reactor power is controlled to match turbine load as measured by turbine first stage pressure. 

The turbine electro-hydraulic control system establishes the desired turbine steady-state load. 

Stage pressure feedback compares stage pressure (actual load) with desired load and uses the

error signal to keep the actual load in agreement with the desired load. This system provides

turbine trip signals that have license renewal functions of ATWS mitigation and main steam

isolation (when used in conjunction with various other systems) for a main steamline break

coincident with MSIV failure. There are no mechanical components required for the system to

perform its system intended functions; therefore, no AMR is required and no P&ID drawings are

provided to depict these license renewal boundaries.

2.3.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.12 and UFSAR Section 10.2.2.2 to determine whether the

turbine electro-hydraulic control system components within the scope of license renewal had

been identified, in accordance with 10 CFR 54.4. The staff also reviewed those same

components to determine whether any of them are subject to an AMR, in accordance with 10

CFR 54.21(a)(1). The staff’s review was conducted in accordance with Section 2.3 of the SRPLR (NUREG-1800) and is described below.

In the performance of this review, the staff selected system functions described in the UFSAR 

that are required by 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of license renewal rule. The staff also focused on those same

components to determine if any of them should be subject to an AMR. As a result of this

review, the staff did not identify any omissions.

2.3.4.12.3 Conclusions

The staff reviewed the LRA and the UFSAR to determine whether any SSCs within the scope of

license renewal had not been identified by the applicant. No omissions were found. In addition,

the staff performed an independent assessment to determine whether any components of the

turbine electro-hydraulic control system subject to an AMR had not been identified by the

applicant. No components were found during the independent assessment. On the basis of

this review, the staff concludes that the applicant has appropriately identified the components of

the turbine electro-hydraulic control system that are within the scope of license renewal, as

required by 10 CFR 54.4, and that the applicant has rationally concluded that there are no
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components of the turbine electro-hydraulic control system that should be subject to an AMR, in

accordance with 10 CFR 54.21(a)(1).

2.3.5 Criterion 2 Supplement to the License Renewal Application

The SOC for the license renewal rule states that the object of a license renewal review is to

determine whether the detrimental effects of aging, which could adversely affect the

functionality of SSCs that the Commission determines require review for the period of extended

operation, are adequately managed. Section 54.4(a)(2) of Title 10 of the Code of Federal

Regulations requires all the non-safety-related SSCs whose failure could prevent satisfactory

accomplishment of any of the safety-related functions identified in 10 CFR 54.4(a)(1) to be

included in the scope of license renewal. The SOC also provides additional guidance on the

Criterion 2 scoping review. Specifically, the applicant is required to determine non-safetyrelated SSCs (related to seismic II/I issues) in scope based on the plant’s CLB, existing

engineering evaluations, and actual plant-specific experience, as well as appropriate industrywide operating experiences.

2.3.5.1 Summary of Technical Information in the Application

LRA Section 2.1.1.3 provides non-safety-related criteria pursuant to 10 CFR 54.4(a)(2). LRA

Subsection 2.1.1.3.1 describes the scoping and screening methodologies for identifying SSCs

that are within the scope of license renewal, in accordance with the requirements of 10 CFR

54.4(a)(2). The LRA also provides information on non-safety/safety interactions and methods

for identifying the non-safety-related system components to meet 10 CFR 54.4(a)(2). The

applicant documented its scoping and screening results in LRA Sections 2.3 and 2.4 and

highlighted the in-scope piping and components in P&ID drawings. However, the non-safetyrelated piping systems having a spatial relationship with safety-related components and

equipment are not evaluated in the LRA. The LRA states that Criterion 2 scoping results for

these non-safety-related SSCs are provided in a supplementary submittal to the NRC. 

On September 12, 2002, the applicant submitted a technical report (RC-02-0159), entitled 

Section 2 Scoping and Screening Refined Criterion 2,” to document its position on the

integrated plant assessment of non-safety-related system components that are spatially

oriented near safety-related components and equipment. The report provides the applicant’s

assessment results for non-safety-related system components to meet Criterion 2. These nonsafety-related components may require an AMR to ensure that their limited structural integrity

and/or pressure boundary are maintained. The applicant indicated that high energy piping,

alternate isolation of steam-lines, instrument air, flooding, insulation, seismic, code break, and

leaks are considered for Criterion 2 scoping of the non-safety-related components. As a result

of this reassessment, certain non-safety-related systems and components not initially included

in the license renewal scope were added to the expended scope for AMR due to spatial

interactions. These systems and components are required to maintain their limited structural

integrity and/or pressure boundary to preclude adverse affects on nearby safety-related

components and equipment. The following addresses the staff’s review of the technical report.

2.3.5.2 Staff Evaluation
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The staff reviewed the applicant’s technical report. Specifically, the staff carefully reviewed the

applicant’s scoping methodology and results for identifying seismic II/I piping systems and

components. The staff’s review was conducted in accordance with Section 2.3 of the SRP-LR

(NUREG-1800) and is described as below.

In the technical report, the applicant identified the following buildings containing both safetyrelated and non-safety-related components and equipment that may have spatial interactions:

• Auxiliary Building

• Control Building

• Diesel Generator Building

• Fuel Handling Building

• Intermediate Building

• Reactor Building

• Service Water Pump House 

The applicant reevaluated all plant systems or portions of the systems in these buildings that

have non-safety-related piping and components to identify their possible spatial relationship

with safety-related components. The systems having non-safety-related piping and piping

components in the designated buildings were first assumed to be in scope for spatial interaction

consideration. The applicant then evaluated plant design documents and routing/configuration

of system piping to determine whether certain non-safety-related portions can be removed from

this consideration. For those non-safety-related portions of the system found to be in scope,

the applicant further justified their inclusion. The technical report refers to the non-safetyrelated seismic II/I components as anti-falldown components and developed anti-falldown

criteria (i.e., refined Criterion 2). The staff reviewed the applicant’s anti-falldown criteria and

found the criteria acceptable on the basis that they conform with NRC guidance regarding

scoping seismic II/I piping systems.

Refined Criterion 2 has the concern not only that non-safety-related piping and components

could fall during the extended operation but also they would be subject to the same plausible

aging effects as the in-scope piping with the possible resulting degradation causing an adverse

spatial interaction with safety-related equipment. With this concern, the applicant reevaluated

pipe failures for (1) non-safety-related piping and components that are connected to safetyrelated piping systems (i.e., code breaks) and (2) non-safety-related piping that has a spatial

relationship such that its failure could adversely impact a safety-related system intended

function. The applicant evaluated the anti-falldown components against refined Criterion 2 in

the following areas.

Code Break Piping

Code break piping is the piping in non-safety-related piping systems from code pipe to the

outer-most code class break support. The applicant defined code-class break support as those

pipe supports on non-safety-related piping that are designed to ensure that significant stresses

are not induced into safety-related piping at safety-class boundaries. Code break supports

protect essential equipment by extending the design requirements for safety-related piping

beyond the class change until one support (at a minimum) in each of the three mutually

perpendicular transverse directions (or the equivalent) is provided. Code break piping is within

the scope of license renewal to preclude adverse effects on safety-related equipment and
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functions. The applicant evaluated the non-safety-related piping that is connected to safetyrelated piping to determine whether the environment of the safety-related portions in scope are

also applicable to the adjoining code break piping. As a result, the applicant identified the nonsafety-related piping between the non-safety-related cycle industrial cooler (CI) system and the

safety-related service water (SW) system in the expended scope for license renewal to meet

Criterion 2.

Non-Mechanical Component

The applicant indicated that anti-falldown requirements for various SCs are for structural

supports rather than assuming the function of the supported mechanical components. The

structural supports have been evaluated in LRA Sections 2.4 and 3.5. The applicant

determined that no further evaluation is required per refined Criterion 2. 

Insulation

The applicant assessed the insulation types (such as MIRROR, mechanically bonded glass

fiber blanket, calcium/silicate, and fiberglass) for possible age-related degradation of insulation

materials and their impact. The applicant did identify potential falling insulation materials on

safety-related components. Therefore, insulation needs to be included in the scope to meet

refined Criterion 2.

Ductwork

The applicant reevaluated the HVAC ductwork in the designated buildings to determine whether

it is anti-falldown ductwork. The applicant added those portions of the ductwork of concern in

the scope of license renewal. The existing IPA results are applicable to the anti-falldown

ductwork. The applicant determined that no further evaluation is required per refined Criterion

2.

Pipe Failure/Rupture

Safety-related high energy piping and associated protection devices, such as restraints,

barriers, and shields, were initially included in the license renewal scope and subject to an

AMR. The applicant determined that no further evaluation is required per refined Criterion 2.

Analyzed High-Energy Lines

To maintain the seismic design and retain a safety margin, the applicant classified certain nonsafety-related portions of several high energy lines as QR. The portions of the QR piping were

initially included in the scope of license renewal. The applicant determined that no further

evaluation is required per refined Criterion 2.

Unanalyzed High-Energy Lines

Portions of the piping in the steam generator blowdown (BD) system and several MS drains

were not analyzed and were not initially included in the scope of license renewal. The

applicant’s reevaluation determined the non-safety-related BD system piping from the
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containment isolation valves to the turbine building/intermediate building wall to be included in

the expended scope and subject to an AMR for license renewal per refined Criterion 2. The

non-safety-related MS drains in the auxiliary building and intermediate building are also

included in the scope of license renewal to meet refined Criterion 2.

Flow Limitation/Blockage

Certain non-safety-related portions of the mechanical systems were classified as QR to ensure

that function of the system would not be inhibited by restricted flow during or after a seismic

event. These QR portions were initially included in the scope of license renewal. The applicant

determined that no further evaluation is required per refined Criterion 2.

Wetting (Moderate or High-Energy)

The effects of wetting on safety-related components, such as wetting from spray or leakage,

are not explicitly addressed on building composite drawings. The areas identified on those

drawings containing safety-related equipment are the areas where wetting due to failure of nonsafety-related and/or QR fluid piping and components could adversely impact safety-related

components. The applicant evaluated the non-safety-related and/or QR fluid systems for

wetting considerations and included them in the scope of license renewal. 

Essential equipment in the reactor building is qualified for service in harsh environments, such

as spray, steam, or flooding. The applicant’s evaluation determined that failure of non-safetyrelated components will not result in the failure of safety-related components in that vicinity. 

Electrical equipment rooms and other unique locations are considered to be the most

susceptible to spray/leakage concerns. Spray-proof enclosures are used for termination boxes,

splice boxes, and for field-mounted equipment like fuse relays. Field-mounted devices, such as

transmitters, limit switches, solenoid valves, and valve motor operators are also designed for

spray-proof. The applicant’s reevaluation found that all the safety-related components and

equipment have been protected for wetting concerns.

Leakage cracks are postulated to occur in moderate-energy systems. UFSAR Section

3.6.2.1.4 provides information on the CLB of postulated moderate-energy piping leakage. The

applicant evaluated all non-safety-related moderate and high-energy fluid systems in the areas

of concern and found that the safety-related components and equipment have been protected

from wetting due to leakage.

Flooding and Leak Detection

Flooding due to large amounts of leakage from system components into nearby areas may

prevent the performance of a safety function. Systems that are credited for detection and

isolation of leaks to preclude adverse effects on safety-related equipment and functions are

within the scope of license renewal. The structural aspects of plant design (protective/mitigative

features) that preclude an adverse impact on safety-related components due to flooding are

included in scope. The applicant reviewed current flooding analysis and plant design

documents and concluded that no other SSCs needed to be included in the expanded scope for

license renewal per refined Criterion 2. 
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As a result of this reevaluation, the applicant identified 34 systems that had their scope

expanded to include non-safety-related systems and/or QR portions that have a potential for

adverse spatial interactions with safety-related equipment in the designated buildings. With the

exception of the interface between the safety-related SW system and non-safety-related CI

system, the applicant found that these systems do not have to expand their aging management

review due to spatial effects because they are the same material and environment combination

on each side of the code break. These systems were initially included in the scope of license

renewal and either sides of the code break are subject to an AMR.

The interfaces between the SW system and CI system are at the supply and return valves of

the RBCU. The process environment for the SW system (safety-related side of the code break)

is raw water, while the CI system (non-safety-related side of the code break) is closed-cycle

treated water. The SW system was included in the license renewal scope for its raw water

environment, but CI piping was not selected for AMR even though the treated water is mixing

with raw water. The applicant’s reevaluation determined to include the CI system piping in the

expended scope for license renewal and subject to AMR to meet refined Criterion 2. 

Based on the above reevaluation of the plant systems, the applicant added the following nonsafety-related systems to the expanded scope for license renewal due to the potential for

spatial interactions with safety-related SSCs in the designated buildings:

• Condenser Air Removal (AR)

• Demineralized Water (DW)

• Fuel Oil Handling (FO)

• Hydrogen-Nuclear Plant Use (HN)

• Liquid Effluents from Nuclear Plant to Penstock (LW)

• Nuclear Blowdown Processing (NB)

• Nitrogen-Nuclear Plant Use (NN)

• Oxygen-Nuclear Plant Use (ON)

• Sewer (SE)

• RW Solidification & Solids Handling (WD)

• Excess Liquid Waste (WX)

The applicant identified the components of these systems to be subject to an AMR using a

commodity approach rather than a systems approach. Systems, system portions, and

components meeting only refined Criterion 2 were grouped together according to the material

type and/or the environments experienced in the designated buildings. Table 1 of the technical

report lists the commodities that were determined to meet refined Criterion 2 for an AMR that

was not initially listed in the tables of LRA Section 2.3. Table 1 contains 17 groups of

component types; each group is provided with information on material, environment, and AMP. 

Some of these piping systems, ventilation ductwork, and component insulations in the table

were justified so that no AMP is required. These components in the table perform limited

structural integrity or limited pressure boundary function instead of supporting a specific system

intended function. 

The staff reviewed the non-safety-related SSCs in the above specified areas to meet

Criterion 2. Based on this review, the staff finds that the applicant has considered most aspects

in assessing the anti-falldown components and justified the areas of concern that need no

further evaluations. The reevaluation’s primary focus was on piping components in the fluid
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systems. However, the portions of non-fluid containing mechanical system (e.g., ventilation

ducts, instrument air valves, valve actuators, etc.) were not fully addressed in the report. 

Certain non-fluid components may not have safety functions but are spatially orientated near

safety-related components, such that their failure could adversely impact the performance of an

intended safety function. In a letter dated March 28, 2003, in RAI 2.3.5-1, the staff asked the

applicant to explain whether any component groups that contain no fluids should be identified

and reassessed to meet Criterion 2.

In its response, dated June 12, 2003, the applicant stated that piping and piping system

components, ventilation ductwork, and pipe and component insulation were specifically included

in the technical report. The evaluation in the technical report addresses all system piping and

ductwork regardless of the internal environment (i.e., steam, treated water, raw water, gases,

air, etc.). Piping and piping system components include valves, fittings, and various piping

components located in the seismic portion of the piping. Ventilation ductwork includes damper

housing when contained in the seismic portions of the system. Piping and component

insulation was included as the portions or sections of insulation may support other sections. 

The applicant did identify non-fluid containing, as well as fluid-containing, components that

need to be added to the expanded scope per refined Criterion 2.

The staff reviewed the technical report and the applicant’s response and found that the

applicant had included all the non-safety-related SSCs with the configuration to meet NRC

guidance and Criterion 2. Based on the above review, the staff concluded that the expanded

scoping and additional SSCs identified in the technical report are acceptable. 

2.3.5.3 Conclusions

The staff reviewed the information in the technical report, and its confirmation from the scoping

inspection and did not find any omissions in the scoping and screening of the Criterion 2 SSCs. 

On the basis of its review, the staff concludes that the applicant has appropriately identified the

Criterion 2 systems and components that are within the scope of license renewal and the

Criterion 2 systems and components that are subject to an AMR in accordance with 10 CFR

54.4(a)(2) and 10 CFR 54.21(a)(1), respectively.

2.3.5.4 References

1. Technical Report RC-02-0159, Criteria 2 Supplement to the Application for Operation

License,” September 12, 2002. Adams No. ML022630347.

2. NRC Letter to Nuclear Energy Institute, License Renewal Issue: Scoping of Seismic II/I 

Piping Systems,” December 3, 2001. Adams No. ML013380013.

3. NRC Letter to Nuclear Energy Institute, License Renewal Issue: Guidance on the 

Identification and Treatment of Structures, Systems, and Components Which Meet 10 CFR 

54.4(a)(2),” March 15, 2002. Adams No. ML020770026.

4. NRC Regulatory Guide 1.29, Seismic Design Classification.”

2.4 Scoping and Screening Results: Structures
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This section addresses the structures’ scoping and screening results for the VCSNS license

renewal application. The structures consist of the following:

• Reactor Building (Section 2.4.1)

• Other Structures (Section 2.4.2)

• Auxiliary Building (Section 2.4.2.1)

• Control Building (Section 2.4.2.2)

• Diesel Generator Building (Section 2.4.2.3)

• Fuel Handling Building (Section 2.4.2.4)

• Intermediate Building (Section 2.4.2.5)

• Turbine Building (Section 2.4.2.6)

• Service Water Pumphouse, Intake, and Discharge Structures (Section 2.4.2.7)

• Yard Structures (Section 2.4.2.8)

Pursuant to 10 CFR 54.21(a)(1) an applicant is required to identify and list SCs subject to an

AMR. These are passive, long-lived SCs that are within the scope of license renewal. To verify

that the applicant has properly implemented its methodology, the staff focuses its review on the

implementation results. Such a focus allows the staff to confirm that there is no omission of

structural components that are subject to an AMR. If the review identifies no omission, the staff

has the basis to find that the applicant has identified the structural components that are subject

to an AMR.

2.4.1 Reactor Building

2.4.1.1 Summary of Technical Information in the Application

The applicant describes the reactor building in LRA Section 2.4.1 and provides a list of

components subject to an AMR in LRA Table 2.4-2. The reactor building is described in

UFSAR Section 3.8.1, Concrete Reactor Building. The reactor building is a post tensioned,

reinforced concrete structure with an integral steel liner. The reactor building consists of a

cylindrical wall, a shallow dome roof, and a foundation mat with a depressed incore

instrumentation pit under the reactor vessel. The foundation mat bears on fill concrete that

extends to competent rock. At the underside of the reactor building foundation mat, a tendon

access gallery is formed into the top of the fill concrete. A retaining wall, extending

approximately one quarter (1/4) of the way around the reactor building, protects the belowgrade portions of the reactor building wall from the subgrade and groundwater. Adjacent

buildings surround the remaining three-quarters (3/4) of the reactor building.

The reactor building shell is post-tensioned by ungrouted tendons. The cylindrical wall

employs a three-buttress, 240-degree hoop tendon concept, with 115 vertical tendons and 150

hoop tendons. The dome contains a total of 99 tendons arranged in a three-way system with

33 tendons per band.

The reactor building is lined on the inside face with a carbon steel plate liner that forms an

essentially leak-tight membrane sealing the entire reactor building for any postulated conditions

which may be encountered throughout the operating life of the plant. At its base, in the haunch

area, a truncated conical transition section tapers inward to accommodate the thickened

concrete of the cylindrical shell. A dome closes the top of the cylindrical portion of the liner. 
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The bottom of the liner consists of flat floor liner plates welded to anchors that are embedded in

the mat concrete. The liner plate extends downward into the foundation mat to line the incore

instrumentation pit, the reactor building sump, the incore instrumentation pit sump, the residual

heat removal sumps, and the reactor building spray sumps. The incore instrumentation pit

walls are lined with carbon steel plates, while the pit bottom and the walls of the incore

instrumentation tunnel sump, and reactor building spray sump floors and sidewalls are lined

with stainless steel plate. Small diameter circular overlay plates are welded to the liner plate to

support piping, ducts, conduit, and electric cable trays. Studs or angle anchors are provided on

the liner behind the attachment plates to transfer loads on the pads into the concrete shell.

All reactor building penetrations are anchored to the concrete reactor building wall or foundation

mat so that loads are transferred from the penetrations to the concrete. All penetrations satisfy

the requirements of 10 CFR Part 50, Appendix J, Primary Reactor Containment Leakage

Testing for Water-Cooled Power Reactors. Piping penetrations consist of a sleeve around the

outside of the piping. The piping is joined to the sleeve inside the reactor building by an

attachment plate. Outside the reactor building, piping is attached to the sleeve by an

attachment plate or by a bellows assembly. Electrical penetration sleeves are provided to

accommodate electrical and instrumentation cables that pass through the reactor building wall.

The sleeves are welded to the reactor building inner reinforcing plates. The electrical leads are

installed in the penetration assemblies that are bolted to the electrical penetration sleeve. 

Spare penetrations consist of sleeves passing through the reactor building wall with the liner

reinforced around the sleeve. Both ends of the sleeve are sealed with butt-welded pipe caps.

A fuel transfer tube penetrates the reactor building connecting the refueling canal in the reactor

building and the fuel transfer canal in the fuel handling building. This penetration consists of a

pipe installed inside a sleeve. Two personnel airlocks are provided for access to the reactor

building, each with two doors, one on the inside and one on the outside. Each door is sealed

with double O-rings, which are tested and replaced when warranted by their condition. The Orings are not long-lived components and therefore do not require an AMR. An equipment

hatch, equipped with an inside-mounted hatch cover, is also provided for access to the reactor

building. A concrete shield located outside the reactor building acts as a missile and biological

shield. The hatch cover is sealed with double O-rings, which are tested and replaced when

warranted by their condition. The O-rings are not long-lived and therefore do not require an

AMR.

Table 2.4-2 lists 46 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

• structural and/or functional support to safety-related equipment

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)

• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant
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• pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

• radiation shielding

• shielding against high energy line breaks

• spray shield or curbs for directing flow

• missile barrier (internally or externally generated)

• pipe whip restraint

• shelter/protection to safety related equipment

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and UFSAR Sections 3.8.1 and 3.8.3 to determine

whether the reactor building structural components within the scope of license renewal and

subject to an AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). 

In the performance of its review, the staff selected system functions described in the UFSAR

that are set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the license renewal rule. The staff also focused on components that

were not identified as being subject to an AMR to determine if any components were omitted. 

Table 2.4-2 lists 46 component groups that require an AMR. These component groups are: 

1. anchorage 

2. anchorage/embedments (exposed surfaces) 

3. bellows (penetration)

4. cable tray and conduit 

5. cable tray and conduit supports

6. checkered plate 

7. compressible joints and seals 

8. control board (refuel cavity crane) 

9. crane rails and girders 

10. electrical and instrument panels and enclosures 

11. embedments 

12. equipment component supports 

13. equipment hatch 

14. equipment pads 

15. escape air lock 

16. expansion anchors 

17. fire barrier penetration seals 

18. fire barriers (walls, ceilings and floors) 

19. fire doors 

20. flood curbs (concrete) 

21. flood curbs (steel) 
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22. flood, pressure, and specialty doors 

23. foundations 

24. hatches (steel) 

25. HVAC duct supports

26. instrument line supports 

27. instrument racks and frames 

28. jet barriers (concrete and steel) 

29. lead shielding supports 

30. liner plate 

31. metal partition walls 

32. metal siding 

33. missile shields 

34. penetrations (mechanical and electrical) 

35. personnel air lock 

36. pipe supports 

37. pipe whip restraint 

38. post-tensioning system 

39. refueling canal liner plate 

40. reinforced concrete – beams, columns, floor slabs, and walls 

41. seismic joint filler 

42. stair, platform, and grating support 

43. structural steel – beams, columns, plates, and trusses 

44. sump screens 

45. sumps 

46. tube track 

The LRA states that the scoping process to identify systems and structures that satisfy the

requirements of 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), and 10 CFR 54.4(a)(3) is performed on

systems and structures using documents which form the CLB and other information sources. 

The CLB for the VCSNS has been defined in accordance with the definition provided in

10 CFR 54.3. The key information sources that form the CLB include the UFSAR, technical

specifications, and the docketed licensing correspondence. All safety-related structures at

VCSNS are designated as Seismic Category I and are within the scope of license renewal. The

classification of each structure has been previously determined and documented in UFSAR

Table 3.2-2, Classification of Structures. 

The LRA also states that the screening process is performed on each structure identified to be

within the scope of license renewal. The process is to determine whether a structure or a

structural component requires an AMR in accordance with 10 CFR 54.21(a)(1).

The LRA further states that the structural components are divided into major groupings based

on materials of construction and operating environment to facilitate the AMRs. For each

structural component subject to AMR, the internal and external operating environments to which

the component is subjected are established. Operating environments are established based on

a review of plant design documents, the UFSAR, plant drawings, and plant environmental data. 

For each structural component subject to AMR, the materials of construction are determined

based on a review of plant design documents, the UFSAR, vendor drawings, specifications, and

component databases. Components with similar design, materials of construction, functions,

and subjected to similar environments are evaluated as a commodity group.
2-135

LRA Table 2.4-2 lists Foundations” as a component type requiring an AMR, and Table 3.5-1,

Item 9, as an AMR result. Table 3.5-1, Item 9, lists reduction in foundation strength due to the

erosion of porous concrete subfoundation” as an aging effect/mechanism. In a letter dated

March 28, 2003, the staff requested, in RAI 2.4.1-1, to clarify what the foundations consist of

and why Table 3.5-1, Item 9, is listed as an AMR result only for the reactor building but not for

other buildings, such as the auxiliary building and control building, whose foundations are also

supported on a fill concrete subfoundation.

In a letter dated June 12, 2003, the applicant responded to RAI 2.4.1-1 as follows:

Table 3.5-1, Item 9, is addressed in the Application only for completeness in using the GALL tabular format and

listings. Porous concrete is not used at VCSNS.

1) Fill concrete is addressed in detail in Response to RAI 3.5-6, concluding that it does not perform an intended

function and does not require evaluation under any aging management programs. “Foundations” as listed in

Application Table 2.4-2 include only the design structural foundations which are above the fill concrete.

2) Table 3.5-1, Item 9, is not listed as an AMR result for the Auxiliary, Control, Fuel Handling, Intermediate,

Turbine, and Service Water Discharge Structures since the GALL did not identify this specific aging effect

(erosion of porous concrete) in the tabular listing for “Class 1 Structures”. In alignment with the GALL, this item

was only addressed under Reactor Building. [Note that only the Reactor, Auxiliary and Control Buildings have

underlying fill concrete.]

The staff finds the above response acceptable.

The staff requested the applicant, in RAI 2.4.1-2, to provide justifications for the O-rings, which

are used to seal the doors of two personnel airlocks and an equipment hatch, for not being

subjected to an AMR.

The applicant responded to RAI 2.4.1-2 as follows:

Containment hatches are “components” that meet the requirement of 10 CFR 54.21 (a)(1)(i) and are subject

to an AMR as described in the Application. O-rings are considered as “parts” of these components and are not

individually identified as meeting the requirements of 10 CFR 54.21(a)(1)(ii). Regardless, aging management

of containment hatches (including all parts) is required to meet 10 CFR 50 Appendix J; therefore,

implementation is under the Appendix J Leak Rate Testing Program (Application Appendix B.1.12). Plant

procedures require that hatch seal leakage be tested within seven days following any door operation to ensure

that containment integrity is achieved, thus ensuring functional integrity of the seals.

The staff finds the above response acceptable.

LRA Table 2.4-2 lists Anchorage,” Anchorage/Embedments (exposed surfaces),” and

“Embedments” as component types requiring AMR. The first half of the component type

Anchorage/Embedments is Anchorage, which is identical to the component type Anchorage,

and the second half is identical to the component type Embedments. The staff requested the

applicant, in RAI 2.4.1-3, to describe each of the component types.

The applicant responded to RAI 2.4.1-3 as follows:

At VCSNS, general definitions of these component types are as follows:

1) Anchorage - Cast in-place anchor bolts.

2) Anchorage / Embedments (exposed surfaces) - Includes support bearing plates, other anchor bolts

such as Hilti Bolts or embedments for attachment such as Unistrut. 3) Embedments - Flat plates
2-136

embedded in concrete surfaces (walls, ceilings, etc.) which are anchored with Nelson Studs. Flat

plates are used as attachment plates for welded supports.

The staff finds the above response acceptable.

The staff requested the applicant, in RAI 2.4.1-4, to identify whether there is any masonry block

wall in the reactor building.

The applicant responded that there are no masonry block walls in the Reactor Building. The

staff finds the above response acceptable.

The staff has reviewed the information in LRA Section 2.4.1, the UFSAR, and the additional

information submitted by the applicant in response to the staff’s RAIs. The staff finds the

responses satisfactory and that the applicant made no omissions in scoping and screening the

reactor building for license renewal. 

2.4.1.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the reactor building that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the structural

components of the reactor building that are subject to an AMR, as required by 10 CFR

54.21(a)(1).

2.4.2 Other Structures

The following structures are included in Section 2.4.2:

• Auxiliary Building (including Refueling Water Storage Tank and Reactor Make-up Water

Storage Tank Foundations, West Penetration Access Area, and Hot Machine Shop)

(Section 2.4.2.1)

• Control Building (Section 2.4.2.2)

• Diesel Generator Building (Section 2.4.2.3)

• Fuel Handling Building (Section 2.4.2.4)

• Intermediate Building (including East Penetration Access Area) (Section 2.4.2.5)

• Turbine Building (Section 2.4.2.6)

• Service Water Pumphouse, Intake and Discharge Structures (Section 2.4.2.7)

• Yard Structures (Condensate Storage Tank Foundation, Electrical Manhole MH-2, Fire

Service Pumphouse, Service Water Pond Dams and West Embankment, and North

Berm) (Section 2.4.2.8)
2-137

Waterstops are used in safety related structures at construction joints located below grade to

inhibit the intrusion of groundwater. Waterstops and waterproofing membrane are inaccessible

and considered to be subcomponents of the concrete walls and slabs.

2.4.2.1 Auxiliary Building

2.4.2.1.1 Summary of Technical Information in the Application

The applicant describes the auxiliary building in LRA Section 2.4.2.1 and provides a list of

components subject to an AMR in LRA Table 2.4-3.

The foundation system for the auxiliary building consists of a four-foot thick structural reinforced

concrete mat supported by fill concrete extending down to competent rock. A waterproofing

membrane is provided between the fill concrete and the structural mat. The auxiliary building is

a seismic Category I structure described in UFSAR Section 3.8.4.1.2. The main auxiliary

building superstructure is a reinforced concrete shear wall (box type) structure whose

foundation is comprised of a reinforced concrete structural mat. The exterior walls are

reinforced concrete designed to prevent damage to safety-related equipment from design basis

events, such as seismic and tornado-generated missiles.

The southwestern portion of the auxiliary building supports two large tanks, the refueling water

storage tank and the reactor makeup water storage tank. Concrete retaining walls provide

compartmental protection from tornado generated missiles. The southeastern portion of the

auxiliary building is designated the west penetration access area (WPAA), which houses the

containment personnel airlock (the emergency airlock connects to the fuel handling building). 

The WPAA utilizes structural steel framing to support the floor slabs up to the elevation of the

roof. The hot machine shop is a non-seismic Category I structure located just north of the

auxiliary building. The hot machine shop is a steel-framed building with metal siding designed

to withstand earthquake loads and tornado wind loads to the extent required for prevention of

damage to seismic Category I structures. The north wall of the auxiliary building is separated

from the hot machine shop by a seismic gap. The failure of the hot machine shop will not

prevent the satisfactory accomplishment of any required safety-related functions. The hot

machine shop is therefore not subject to an AMR. 

Table 2.4-3 lists 39 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

1. structural and/or functional support to safety-related equipment

2. structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions.

3. flood protection barrier (internal and external flooding event)

4. rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant
2-138

5. pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

6. radiation shielding

7. shielding against high energy line breaks

8. spray shield or curbs for directing flow

9. missile barrier (internally or externally generated)

10. pipe whip restraint

11. shelter/protection to safety-related equipment

2.4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.1 and UFSAR Sections 3.8.4.1.2, 3.8.4.4.2, and 3.8.5.1.2

to determine whether the auxiliary building structural components within the scope of license

renewal and subject to an AMR had been identified in accordance with 10 CFR 54.4 and

54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 

Table 2.4-3 lists 39 structural component groups that require an AMR. These component

groups are:

1. anchorage 

2. anchorage/embedments (exposed surfaces) 

3. bellows (RHR and reactor building spray system isolation valve chambers and guard

pipe)

4. blowout or blow-off panels 

5. cable tray and conduit 

6. cable tray and conduit supports 

7. compressible joints and seals 

8. crane rails and girders 

9. duct banks 

10. electrical and instrument panels and enclosures 

11. embedments 

12. equipment component supports 

13. equipment pads 

14. expansion anchors 

15. fire barrier penetration seals

16. fire barriers (walls, ceilings and floors) 

17. fire doors 

18. flood curbs (concrete) 

19. flood, pressure, and specialty doors 

20. foundations 
2-139

21. hatches (concrete) 

22. HVAC duct supports 

23. instrument line supports 

24. instrument racks and frames 

25. jet barriers 

26. lead shielding supports 

27. liner plate 

28. masonry block, brick walls, or knockdown walls 

29. metal spray shields 

30. missile shields 

31. pipe supports 

32. pipe whip restraint 

33. reinforced concrete — beams, columns, floor slabs, and walls 

34. roof slabs 

35. seismic joint filler 

36. stair, platform, and grating support 

37. structural steel – beams, columns, plates, and trusses 

38. sumps 

39. tube track.

LRA Table 2.2-2, Structural Scoping Results, lists the hot machine shop as in scope, and the

reason for being in scope is that its intended functions are those that meet the requirements of

10 CFR 54.4(a)(2), and involve a seismic II/I concern. The staff requested the applicant, in RAI

2.4.2-1, to clarify whether the hot machine shop is in scope and requires an AMR, and, if not in

scope, to provide a justification for its exclusion.

The applicant responded to RAI 2.4.2-1 as follows:

This RAI is correct in that the Application is contradictory for including the Hot Machine Shop in scope.

Application Table 2.2-2 was extracted from the VCSNS Scoping Report which identified the Hot Machine Shop

as initially in scope due to the potential for seismic interaction with the Auxiliary Building. During the Screening

process, it was subsequently determined that failure of the Hot Machine Shop would have an insignificant

impact on the Auxiliary Building, and would not prevent satisfactory accomplishment of any safety related

functions. Therefore, since it does not actually perform an intended function, it was taken out of scope.

The statement in Application Section 2.4.2.1 is correct in that the failure of the Hot Machine Shop will not

prevent the satisfactory accomplishment of any required safety related functions, and is thus not subject to an

aging management review. Supporting Technical Reports will be revised to delete the Hot Machine Shop from

the scope of license renewal.

The staff finds the above response acceptable.

The staff requested the applicant, in RAI 2.4.2-2, to identify whether the refueling water storage

tank and the reactor makeup water storage tank are in scope and subject to an AMR since they

are not listed in Table 2.4-3 and, if not, to provide a justification for their exclusion.

The applicant responded to RAI 2.4.2-2 as follows:

The Refueling Water Storage Tank and the Reactor Make-Up Water Storage Tank are both in scope and

included in the Application with their respective mechanical systems. The Refueling Water Storage Tank is
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discussed in Section 2.3.2.5 and Table 3.2-2, Items 1 and 7. The Reactor Make-Up Water Storage Tank is

discussed in Section 2.3.3.18 and Table 3.3-2, Items 1 and 20.

The staff finds the above response acceptable.

The staff requested the applicant, in RAI 2.4.2-3, to indicate whether grout is subject to an AMR

and, if not, provide a justification for its exclusion.

The applicant responded to RAI 2.4.2-3 as follows:

In the Application 2.4 Tables, grout is generically included as a component type under “Equipment Pads” for

each structure even though it is not specifically listed as an individual component type. In the supporting

technical reports, grout is not identified as an individual commodity type, rather included under the commodity

grouping of “concrete”, and subject to the same AMPs.

The staff finds the above response acceptable.

The staff has reviewed the information in LRA Section 2.4.2.1, the UFSAR, and the additional

information submitted by the applicant in response to the staff’s RAIs. The staff finds the

response satisfactory and that the applicant made no omissions in scoping and screening the

auxiliary building for license renewal. 

2.4.2.1.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the auxiliary building that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the structural

components of the auxiliary building that are subject to an AMR, as required by 10 CFR

54.21(a)(1).

2.4.2.2 Control Building

2.4.2.2.1 Summary of Technical Information in the Application

The applicant describes the control building in LRA Section 2.4.2.2 and provides a list of

components subject to an AMR in LRA Table 2.4-4.

The foundation system for the control building consists of a reinforced concrete mat designed

to transfer vertical load from superstructure columns to fill concrete extending down to

competent rock. Vertical reinforcing steel extends from exterior shear walls into fill concrete. 

The control building is a seismic Category I structure described in UFSAR Section 3.8.4.1.5.

The superstructure is a steel frame structure with concrete exterior shear walls containing four

main floor levels and a concrete roof, and is designed to withstand the various combinations of

dead and live loads, design basis event loads, and other generic design criteria loads as

defined in the UFSAR. 
2-141

Table 2.4-4 lists 37 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

1. structural and/or functional support to safety-related equipment

2. structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions 

3. flood protection barrier (internal and external flooding event)

4. rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

5. pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

6. radiation shielding

7. spray shield or curbs for directing flow

8. missile barrier (internally or externally generated)

9. shelter/protection to safety-related equipment

2.4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.2 and UFSAR Sections 3.8.4.1.5, 3.8.4.4.5, and 3.8.5.1.4

to determine whether the control building structural components within the scope of license

renewal and subject to an AMR had been identified in accordance with 10 CFR 54.4 and

54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 

Table 2.4-4 lists 37 structural component groups that require an AMR. These component

groups are: 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3. cable tray and

conduit, 4. cable tray and conduit supports, 5. checkered plate, 6. compressible joints and

seals, 7. control boards and panels, 8. control room ceiling, 9. crane rails and girders, 10. duct

banks, 11. electrical and instrument panels and enclosures, 12. embedments, 13. equipment

component supports, 14. equipment pads, 15. expansion anchors, 16. fire barrier penetration

seals, 17. fire barriers (walls, ceilings and floors), 18. fire doors, 19. flood barriers (elastomers),

20. flood curbs (concrete), 21. flood, pressure, and specialty doors, 22. foundations,

23. hatches (concrete), 24. HVAC duct supports, 25. instrument line supports, 26. instrument

racks and frames, 27. lead shielding supports, 28. masonry block, brick walls, or knockdown

walls, 29. metal partition walls, 30. missile shields, 31. pipe supports, 32. reinforced concrete –

beams, columns, floor slabs, and walls, 33. roof slabs, 34. seismic joint filler, 35. stair, platform,

and grating support, 36. structural steel – beams, columns, plates, and trusses, and 37. tube

track.
2-142

The staff has reviewed the information in LRA Section 2.4.2.2, and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the control building for license

renewal. 

2.4.2.2.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal and subject to an AMR had not been identified by the applicant. No omissions

were found. On the basis of this review, the staff concludes that the applicant has adequately

identified the structural components of the control building that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

structural components of the control building that are subject to an AMR, as required by 10

CFR 54.21(a)(1).

2.4.2.3 Diesel Generator Building

2.4.2.3.1 Summary of Technical Information in the Application

The applicant describes the diesel generator building in LRA Section 2.4.2.3 and provides a list

of components subject to an AMR in LRA Table 2.4-5.

The foundation system for the diesel generator building consists of a reinforced concrete slab

and grade beam system that is supported by reinforced concrete caissons drilled into

competent bedrock. The foundations for the diesel generators extend from the operating floor

level down to the basement floor mat.

The diesel generator building is a seismic Category I structure described in UFSAR Section

3.8.4.1.4. The superstructure is a reinforced concrete shear wall (box type) structure containing

three main floor levels above the foundation mat, and a roof, designed to withstand the various

combinations of dead and live loads, operating-basis earthquake (OBE) and SSE seismic

loads, wind loads, tornado loads, and other generic design criteria loads as defined in the

UFSAR. The entire building is separated from other buildings to prevent load transfer during an

OBE or SSE.

The primary function of the diesel generator building is to house the diesel generators that are

needed to supply emergency onsite power in the event that offsite power is lost. The diesel

generator building is designed to withstand the various combinations of dead and live loads,

design basis event loads, and other generic design criteria loads as defined in the UFSAR.

Table 2.4-5 lists 34 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

1. structural and/or functional support to safety related equipment

2. structural support to non nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

3. flood protection barrier (internal and external flooding event)
2-143

4. rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

5. spray shield or curbs for directing flow

6. missile barrier (internally or externally generated)

7. shelter/protection to safety-related equipment

2.4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.3 and UFSAR Sections 3.8.4.1.4, 3.8.4.4.4, and 3.8.5.1.6

to determine whether the structural components of the diesel generator building within the

scope of license renewal and subject to an AMR had been identified in accordance with 10 CFR

54.4 and 54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 

Table 2.4-5 lists 34 structural component groups that require an AMR. These component

groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3. cable tray and

conduit, 4. cable tray and conduit supports, 5. caissons, 6. compressible joints and seals,

7. crane rails and girders, 8. duct banks, 9. electrical and instrument panels and enclosures,

10. embedments, 11. equipment component supports, 12. equipment pads, 13. expansion

anchors, 14. fire barrier penetration seals, 15. fire barriers (walls, ceilings and floors), 16. fire

doors, 17. flood barriers (elastomers), 18. flood curbs (concrete), 19. flood, pressure, and

specialty doors, 20. foundations, 21. grating, 22. hatches (steel), 23. HVAC duct supports,

24. instrument line supports, 25. instrument racks and frames, 26. metal partition walls,

27. missile shields, 28. pipe supports, 29. reinforced concrete – beams, columns, floor slabs,

and walls, 30. roof slabs, 31. seismic joint filler, 32. stair, platform, and grating support,

33. structural steel – beams, columns, plates, and trusses, and 34. sumps.

The staff has reviewed the information in LRA Section 2.4.2.3 and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the Diesel generating building

for license renewal.

2.4.2.3.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the diesel generating building that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the

structural components of the diesel generating building that are subject to an AMR, as required

by 10 CFR 54.21(a)(1).

2.4.2.4 Fuel Handling Building
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2.4.2.4.1 Summary of Technical Information in the Application

The applicant describes the fuel handling building in LRA Section 2.4.2.4 and provides a list of

components subject to an AMR in LRA Table 2.4-6.

The foundation system for the fuel handling building consists of a reinforced concrete mat

formed by the bottom of the spent fuel pool and fuel cask pit and supported by reinforced

concrete piers that extend to the fill concrete adjacent to the reactor and auxiliary buildings, and

by reinforced concrete caissons that extend to competent rock on the north and east sides.

The fuel handling building is a Seismic Category I structure discussed in UFSAR Section

3.8.4.1.6. The superstructure is a steel frame structure containing two main floor levels and a

roof, designed to withstand the various combinations of dead and live loads, design basis event

loads, and other generic design criteria loads as defined in the UFSAR.

Table 2.4-6 lists 40 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

1. structural and/or functional support to safety-related equipment

2. structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

3. pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

4. flood protection barrier (internal and external flooding event)

5. radiation shielding

6. rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

7. spray shield or curbs for directing flow

8. missile barrier (internally or externally generated)

9. shelter/protection to safety related equipment

2.4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.4 and UFSAR Sections 3.8.4.1.6, 3.8.4.4.6, and 3.8.5.1.5

to determine whether the fuel handling building structural components within the scope of

license renewal and subject to an AMR had been identified in accordance with 10 CFR 54.4

and 54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 
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Table 2.4-6 lists 40 structural component groups that require an AMR. These component

groups are: 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3. cable tray and

conduit, 4. cable tray and conduit supports, 5. caissons, 6. checkered plate, 7. compressible

joints and seals, 8. crane rails and girders, 9. electrical and instrument panels and enclosures,

10. embedments, 11. equipment component supports, 12. equipment pads, 13. expansion

anchors, 14. fire barrier penetration seals, 15. fire barriers (walls, ceilings and floors), 16. fire

doors, 17. flood curbs (concrete), 18. foundations, 19. fuel transfer canal liner plate,

20. hatches (concrete), 21. hatches (steel), 22. HVAC duct supports, 23. instrument line

supports, 24. instrument racks and frames, 25. lead shielding supports, 26. masonry block,

brick walls, or knockdown walls, 27. metal siding, 28. missile shields, 29. neutron absorbing

sheets in spent fuel pool—boraflex, 30. piers (concrete), 31. pipe supports, 32. reinforced

concrete — beams, columns, floor slabs, and walls, 33. roof, 34. seismic joint filler, 35. spent

fuel pool liner, 36. spent fuel storage rack, 37. stair, platform, and grating support, 38. structural

steel - beams, columns, plates, and trusses, 39. sumps, and 40. tube track.

The staff has reviewed the information in LRA Section 2.4.2.4 and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the fuel handling building for

license renewal.

2.4.2.4.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the fuel handling building that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the components

of the fuel handling building that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.2.5 Intermediate Building

2.4.2.5.1 Summary of Technical Information in the Application

The applicant describes the intermediate building in LRA Section 2.4.2.5 and provides a list of

components subject to an AMR in LRA Table 2.4-7.

The foundation system for the intermediate building consists of a reinforced concrete basement

floor slab that acts in conjunction with a series of grade beams to transfer vertical loads to the

reinforced concrete caissons, shear/bearing walls, and concrete piers. The shear/bearing wall

foundations and reinforced concrete caissons are founded on competent bedrock. The piers

are founded on fill concrete that extends beyond the reactor building and auxiliary building.

Horizontal shears are transferred through the basement floor slab to the shear/bearing walls

and to the control building base mat.

The intermediate building is a seismic Category I structure described in UFSAR Section

3.8.4.1.3. The superstructure is an L-shaped reinforced concrete shear wall (box type)

structure containing two main floor levels above the foundation and extending up to the low

roof. Above the low roof is a partial third floor of reinforced concrete and a high roof. The

intermediate building is designed to withstand the various combinations of dead and live loads,

design basis event loads, and other generic design criteria loads as defined in the UFSAR.
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Table 2.4-7 lists 42 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

• structural and/or functional support to safety-related equipment

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)

• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

• pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

• radiation shielding

• shielding against high energy line breaks

• spray shield or curbs for directing flow

• missile barrier (internally or externally generated)

• pipe whip restraint

• shelter/protection to safety-related equipment

2.4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.5 and UFSAR Sections 3.8.4.1.3, 3.8.4.4.3, and 3.8.5.1.3

to determine whether the intermediate building structural components within the scope of

license renewal and subject to an AMR had been identified in accordance with 10 CFR 54.4

and 54.21(a)(1). 

In the performance of its review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

Table 2.4-7 lists 42 structural component groups that require an AMR. These component

groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3. battery racks, 

4. blowout or blow-off panels, 5. cable tray and conduit, 6. cable tray and conduit supports,

7. caissons, 8. compressible joints and seals, 9. crane rails and girders, 10. duct banks,

11. electrical and instrument panels and enclosures, 12. embedments, 13. equipment

component supports, 14. equipment pads, 15. expansion anchors, 16. fire barrier penetration

seals, 17. fire barriers (walls, ceilings and floors), 18. fire doors, 19. flood curbs (concrete),

20. flood, pressure, and specialty doors, 21. foundations, 22. hatches (concrete), 23. hatches
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(steel), 24. HVAC duct supports, 25. instrument line supports, 26. instrument racks and frames,

27. jet barriers, 28. lead shielding supports, 29. metal siding, 30. metal spray shields,

31. missile shields, 32. piers, 33. pipe supports, 34. pipe whip restraint, 35. reinforced concrete

— beams, columns, floor slabs, and walls, 36. roof slabs, 37. seismic joint filler, 38. stair,

platform, and grating support, 39. structural steel—beams, columns, plates, and trusses,

40. sumps, 41. trenches, and 42. tube track.

The staff has reviewed the information in LRA Section 2.4.2.5. The staff finds that the applicant

made no omissions in scoping and screening the intermediate building for license renewal.

2.4.2.5.3 Conclusion

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the intermediate building that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the structural

components of the intermediate building that are subject to an aging management review, as

required by 10 CFR 54.21(a)(1).

2.4.2.6 Turbine Building

2.4.2.6.1 Summary of Technical Information in the Application

The applicant describes the turbine building in LRA Section 2.4.2.6 and provides a list of

components subject to an AMR in LRA Table 2.4-8.

The foundation mat for the turbine building is comprised of a reinforced concrete mat supported

by Zone III fill (graded crushed stone) material. The reinforced concrete pedestal foundation

mats for the feedwater pumps and turbine generators are founded on fill concrete over bedrock.

The turbine building is a non-seismic Category I structure as described in UFSAR Section

3.8.4.1.1. The superstructure of steel framing, metal siding, and metal roof deck is supported

on a reinforced concrete substructure. The steel rigid frame structure is elastically supported at

the operating floor, which acts as a diaphragm. The subsurface portion of the east, west, and

south walls are reinforced concrete. The north wall is structural steel framing, with no siding,

that abuts the control, intermediate, and diesel buildings. The entire building is separated from

other buildings to prevent load transfer during seismic events.

The turbine building is designed to withstand the various combinations of dead and live loads,

seismic loads, wind loads, tornado loads, and other generic design criteria loads as defined in

the UFSAR. However, for earthquake loads and tornado wind loads, the turbine building is only

designed to the extent required to prevent damage to seismic Category I structures. The

primary function of the turbine building is to house the turbine generators. The functional

requirement of the building in the event of an earthquake or tornado is that no portion of the

building collapses and results in damage to seismic Category I structures.

Table 2.4-8 lists 34 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:
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• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)

• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

• pressure boundary or essentially leak tight barrier to protect public health and safety in

the event of any postulated design basis events

• spray shield or curbs for directing flow

• missile barrier (internally or externally generated)

• shelter/protection to safety-related equipment

• source of cooling water

2.4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.6 and UFSAR Section 3.8.4.1.1 to determine whether the

turbine building structural components within the scope of license renewal and subject to an

AMR had been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). 

In the performance of its review, the staff selected system functions described in the UFSAR

that were set forth in 10 CFR 54.4 to verify that components having intended functions were not

omitted from the scope of the Rule. The staff also focused on components that were not

identified as being subject to an AMR to determine if any components were omitted. 

Table 2.4-8 lists 34 structural component groups that require an AMR. These component

groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3. cable tray and

conduit, 4. cable tray and conduit supports, 5. compressible joints and seals, 6. crane rails and

girders, 7. duct banks, 8. electrical and instrument panels and enclosures, 9. embedments,

10. equipment component supports, 11. equipment pads, 12. expansion anchors, 13. fire

barrier penetration seals, 14. fire barriers (walls, ceilings and floors), 15. fire doors, 16. flood

curbs (concrete), 17. flood, pressure, and specialty doors, 18. foundations, 19. grating,

20. hatches (concrete), 21. hatches (steel), 22. HVAC duct supports, 23. instrument line

supports, 24. instrument racks and frames, 25. masonry block, brick walls, or knockdown walls,

26. metal siding, 27. pipe supports, 28. reinforced concrete — beams, columns, floor slabs, and

walls, 29. roof, 30. seismic joint filler, 31. stair, platform, and grating support, 32. structural steel

— beams, columns, plates, and trusses, 33. sumps, and 34. trenches. 

The staff has reviewed the information in LRA Section 2.4.2.6 and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the turbine building for license

renewal.

2.4.2.6.3 Conclusions
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The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On

the basis of this review, the staff concludes that the applicant has adequately identified that the

structural components of the turbine building that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the turbine building that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.2.7 Service Water Pumphouse, Intake, and Discharge Structures

2.4.2.7.1 Summary of Technical Information in the Application

The applicant describes the service water pumphouse, intake, and discharge structures in LRA

Section 2.4.2.7 and provides a list of components subject to an AMR in LRA Table 2.4-9.

Service Water Pumphouse

The foundation for the service water pumphouse consists of a reinforced concrete structural

mat. The discharge pipe pits on the south side and the control areas on the west side of the

service water pumphouse are supported by buried reinforced concrete columns, which extend

to the supporting foundation mat. The entire structural mat is supported on compact fill that is

in turn supported on a layer of in-situ soils (saprolite), then decomposed rock down to

competent rock. The service water pumphouse is a seismic Category I structure described in

UFSAR Section 3.8.4.1.7. The superstructure is a reinforced concrete building separated from

the service water intake structure and from buried connecting pipes and electrical duct banks by

flexible joints, which accommodate relative settlement and seismic movement. 

The service water pumphouse is designed to withstand the various combinations of dead and

live loads, OBE and SSE seismic loads, wind loads, tornado loads, and other generic design

criteria loads as defined in the UFSAR. The primary function of the service water pumphouse is

to house the service water pumps that pump water from the service water pond to supply the

service water system. The service water pumphouse is designed to withstand the various

combinations of dead and live loads, design basis event loads, and other generic design criteria

loads as defined in the UFSAR.

Service Water Intake And Discharge Structures

Service Water Intake Structure:

The foundation for the service water intake structure consists of a reinforced concrete mat

supported by compacted fill material, except for a portion of the inlet end, which rests on in-situ

soils.

The service water intake structure is a seismic Category I structure as described in UFSAR

Section 3.8.4.1.8. The structure is a reinforced concrete rectangular box culvert with two

reinforced concrete wing walls at the intake end. The foundation mat forms the floor of the

structure. An expansion joint separates the service water intake structure from the service

water pumphouse, which accommodates relative settlement and seismic movement. The

structure extends into the service water pond and is mostly buried in the west embankment

except for the intake end, which is submerged within the pond.
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The service water intake structure is designed to withstand the various combinations of dead

loads, OBE and SSE seismic loads, and other generic design criteria loads as defined in the

UFSAR. The primary function of the service water intake structure is to extend the point at

which water is drawn from the service water pond into the service water pumphouse. The

functional requirement of the service water intake structure during and following a design basis

event is that it does not collapse and result in a loss of supply water from the service water

pond to the service water pumphouse.

Service Water Discharge Structure:

The foundation for the service water discharge structure consists of a reinforced concrete mat

that bears partly on decomposed rock and partly on fill concrete that extends to the

decomposed rock. The service water discharge structure is a seismic Category I structure as

described in UFSAR Section 3.8.4.1.9. The structure is a reinforced concrete rectangular basin

mostly buried in the west embankment of the service water pond. The foundation mat forms

the floor of the basin. A 15-foot high abutment wall forms the west end of the basin, and a 3-

foot high sill wall forms the east end. Wing walls form the north and south sides of the basin. 

Two 30-inch diameter service water pipes terminate at the abutment wall and are connected to

the service water discharge structure by flexible connections.

The service water discharge structure is designed to withstand the various combinations of

dead loads, OBE and SSE seismic loads, and other generic design criteria loads as defined in

the UFSAR. The primary function of the service water discharge structure is to release service

water into the service water pond. The functional requirement of the service water discharge

structure during and following a design basis event is that it does not collapse and result in an

interruption of service water discharge.

Table 2.4-9 lists 34 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

these structural component groups provide for:

• structural and/or functional support to safety-related equipment

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)

• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

• spray shield or curbs for directing flow

• missile barrier (internally or externally generated)

2.4.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.7 and UFSAR Sections 3.8.4.1.7, 3.8.4.1.8, 3.8.4.1.9,

3.8.4.4.7, 3.8.4.4.8, 3.8.4.4.9, 3.8.5.1.7, 3.8.5.1.8, and 3.8.5.1.9 to determine whether the
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components of the service water pumphouse, intake, and discharge structures within the scope

of license renewal and subject to an AMR had been identified in accordance with 10 CFR 54.4

and 54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 

Table 2.4-9 lists 34 structural component groups that require an AMR. These

component groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3.

cable tray and conduit, 4. cable tray and conduit supports, 5. checkered plate, 6.

compressible joints and seals, 7. crane rails and girders, 8. duct banks, 9. electrical and

instrument panels and enclosures, 10. embedments, 11. equipment component

supports, 12. equipment pads, 13. expansion anchors, 14. fire barrier penetration seals,

15. fire barriers (walls, ceilings and floors), 16. fire doors, 17. flood curbs (concrete), 18.

flood, pressure, and specialty doors, 19. foundations, 20. grating, 21. hatches

(concrete), 22. HVAC duct supports, 23. instrument line supports, 24. instrument racks

and frames, 25. intake bays or canals, 26. intake screens, 27. missile shields, 28. pipe

supports, 29. reinforced concrete — beams, columns, floor slabs, and walls, 30. roof

slab, 31. seismic joint filler, 32. stair, platform, and grating support, 33. structural steel

— beams, columns, plates, and trusses, and 34. sumps. 

The staff has reviewed the information in LRA Section 2.4.2.7 and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the service water pumphouse,

intake and discharge structures for license renewal.

2.4.2.7.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs that should be within the scope of

license renewal and subject to an AMR had not been identified by the applicant. No omissions

were found. On the basis of this review, the staff concludes that the applicant has adequately

identified the structural components of the service water pumphouse, intake and discharge

structures are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the

applicant has adequately identified the components of the service water pumphouse, intake and

discharge structures that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.2.8 Yard Structures

2.4.2.8.1 Summary of Technical Information in the Application

The applicant describes the yard structures in LRA Section 2.4.2.8 and provides a list of

components subject to an AMR in LRA Table 2.4-10.

The following structures are included in yard structures:

• Condensate Storage Tank Foundation

• Fire Service Pumphouse 

• Electrical Manhole MH-2

• Earthen Embankments (Service Water Pond Dams, West Embankment, North Berm) 

• Electrical Substation and Transformer Area
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Condensate Storage Tank Foundation

The foundation for the condensate storage tank is designed to satisfy seismic Category I

requirements as defined in UFSAR Sections 2.5.4.10.3 and 9.2.6. The foundation consists of a

reinforced concrete mat supported by Zone III (graded crushed stone) fill material and an

integral reinforced concrete ring wall that extends above the top of the foundation mat. The

condensate storage tank is secured to the foundation by anchor bolts embedded in the ring

wall. The interior area of the ring wall is filled with clean dry sand to form a sand mat beneath

the tank. A reinforced concrete valve pit for the condensate storage tank drainpipe is integrated

into the south side of the foundation.

The primary function of the condensate storage tank foundation is to support the nuclear

safety-related condensate storage tank. The functional requirement of the foundation during

and following a design basis event is that its failure would not result in a loss of the condensate

storage tank contents. 

Table 2.4-10 lists 11 structural component groups requiring an AMR, provides a reference to

the results of the AMR for each component group, and identifies the following intended

functions provided for by these structural component groups:

• structural and/or functional support to safety-related equipment

• structural support to non nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

Fire Service Pumphouse

The fire service pumphouse is a concrete block building described in the FPER Section 4.10. 

The building is founded upon the reinforced concrete circulating water intake structure. Hollow

concrete blocks are used to form the exterior and interior walls of the building, and solid

concrete blocks are used under steel framing members. The composite roof is a built-up

insulated roof with gravel over steel decking and metal roof trusses. A reinforced concrete slab,

located on the east side of the fire service pumphouse and founded upon the circulating water

intake structure, is the foundation for the diesel engine-driven fire service pump fuel oil tank. 

The tank is secured to the foundation by embedded anchor bolts. The primary function of the

fire service pumphouse is to house one electric motor-driven fire pump and one diesel enginedriven fire pump.

Table 2.4-11 lists 25 structural component groups requiring an AMR, provides a reference to

the results of the AMR for each component group, and identifies the following intended

functions provided for by these structural component groups:

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)
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• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

• spray shield or curbs for directing flow

Electrical Manhole MH-2

The below-grade foundation for electrical manhole MH-2 consists of a reinforced concrete mat

supported by Zone I and II (earthen) fill material. The reinforced concrete exterior walls are set

in from the profile of the foundation mat and extend above finished grade. The manhole is

divided into two compartments by a reinforced concrete partition wall installed on the east-west

axis. The above-grade manhole cover is a reinforced concrete slab, containing two manways

with galvanized steel covers for access into the manhole compartments. Electrical manhole

MH-2 is a non-seismic structure described in FPER Section 4.9. The structure contains nuclear

safety-related Class 1E and non-nuclear safety-related electrical cables.

Table 2.4-12 lists 5 structural component groups requiring an AMR, provides a reference to the

results of the AMR for each component group, and identifies the following intended functions

provided for by these structural component groups:

• structural and/or functional support to safety-related equipment

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

• flood protection barrier (internal and external flooding event)

• rated fire barrier to confine or retard a fire from spreading to or from adjacent areas of

the plant

• shelter/protection to safety-related equipment

• missile barrier (internally or externally generated)

Earthen Embankments

Service Water Pond Dams and West Embankment:

Four earthen embankments—three dams (north dam, south dam, and east dam) and the west

embankment—form the service water pond, a safety class impoundment. These homogeneous

earth structures are seismic Category I and are designed to satisfy the intent of RGs 1.27 and

1.29.

The three dams and the west embankment, which merges with the west abutments of the north

and south dams, are designed to be stable under static and dynamic conditions, OBE and SSE

seismic loads, and for maximum wave run-up from the Monticello Reservoir as defined in

UFSAR Section 2.5.6.1. The primary function of the earthen structures is to form the service

water pond, which provides water for the service water system under normal and emergency

conditions. The functional requirement, assuming a loss of the Monticello Reservoir during a
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design basis event, is that no dam or embankment failure would result in a loss of cooling water

to the service water system.

North Berm:

The shoreline along Monticello Reservoir north of the plant and west of the north dam has an

earthen dike (the north berm) constructed three feet above site grade. The north berm is

classified as a nonseismic, non-nuclear safety-related structure whose primary function is to

protect the site from external flooding. The functional requirement of the north berm is to

protect nuclear SCs from any adverse effects due to flooding. Further description of the north

berm is provided in UFSAR Sections 2.4.3, 2.4.3.6.2, and 2.4.10.

Table 2.4-13 lists two structural component groups requiring an AMR, provides a reference to

the results of the AMR for each component group, and identifies the following intended

functions provided for by these structural component groups:

• flood protection barrier (internal and external flooding event)

• source of cooling water

• impound water

Electrical Substation and Transformer Area

Components that are part of the plant system portion of the offsite power grid are within the

scope of license renewal in accordance with the SBO scoping criterion, 10 CFR 54.4(a)(3). 

This power path includes portions of the power path from the power circuit breaker (PCB) in the

substation to the safety-related buses. The power path includes (1) portions of the 230 kV

substation system, and (2) portions of the Parr-Summer Safeguard 115 kV system. The

electrical substation provides structural support and/or shelter to components relied on during

an SBO event. The electrical substation yard, located south of the turbine building, contains

power circuit breakers, transformers, buslines, and electrical switching equipment. The

transformer area within the site-protected area is treated as part of the electrical substation for

license renewal purposes.

The entire surface of the electrical substation and transformer area, with the exception of the

paved roadways, is covered with several inches of “crusher run” stone and is enclosed by a

perimeter fence. Bus line and insulator supports are constructed of galvanized structural steel

mounted on concrete footings. Power circuit breakers, transformers, and other electrical

equipment are supported on concrete pads.

Table 2.4-14 lists 10 structural component groups requiring an AMR, provides a reference to

the results of the AMR for each component group, and identifies the following intended function

provide these structural component groups:

• structural support to non-nuclear safety-related components whose failure could prevent

satisfactory accomplishment of any of the required safety-related functions

2.4.2.8.2 Staff Evaluation
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The staff reviewed LRA Section 2.4.2.8 and UFSAR Section 3.8.4 to determine whether the

yard structures components within the scope of license renewal and subject to an AMR had

been identified in accordance with 10 CFR 54.4 and 54.21(a)(1). 

The staff also focused on components that were not identified as being subject to an AMR to

determine if any components were omitted. 

Table 2.4-10 lists 11 structural component groups that require an AMR. These

component groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3.

checkered plate, 4. expansion anchors, 5. foundation dowels, 6. foundations, 7.

instrument line supports, 8. instrument racks and frames, 9. pipe supports,10. reinforced

concrete — beams, columns, floor slabs, and walls, and 11. stair, platform, and grating

support. 

Table 2.4-11 lists 25 structural component groups that require an AMR. These

component groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3.

battery racks, 4. cable tray and conduit, 5. cable tray and conduit supports, 6. electrical

and instrument panels and enclosures, 7. embedments, 8. equipment component

supports, 9. equipment pads, 10. expansion anchors, 11. fire barrier penetration seals,

12. fire barriers (walls, ceilings and floors), 13. fire doors, 14. flood curbs (concrete), 15.

foundations, 16. hatches (steel), 17. HVAC duct supports, 18. instrument line supports,

19. instrument racks and frames, 20. masonry block, brick walls, or knockdown walls,

21. pipe supports, 22. reinforced concrete — beams, columns, floor slabs, and walls, 23.

structural steel—beams, columns, plates, and trusses, 24. sumps, and 25. trenches. 

Table 2.4-12 lists 5 structural component groups that require an AMR. These

component groups are 1. foundations, 2. manhole covers, 3. manholes, 4. missile

shields, and 5. reinforced concrete — beams, columns, floor slabs, and walls.

Table 2.4-13 lists 2 structural component groups that require an AMR. These

component groups are 1. service water pond dams (north dam, south dam, and east

dam) and west embankment, and 2. north berm.

Table 2.4-14 lists 10 structural component groups that require an AMR. These

component groups are 1. anchorage, 2. anchorage/embedments (exposed surfaces), 3.

cable tray and conduit, 4. cable tray and conduit supports, 5. electrical and instrument

panels and enclosures, 6. embedments, 7. equipment component supports, 8.

equipment pads (buslines, PCBs, and transformers), 9. reinforced concrete —

foundations and walls, 10. structural steel—beams, columns, plates, and trusses

(transmission towers).

The staff has reviewed the information in LRA Section 2.4.2.8 and the UFSAR. The staff finds

that the applicant made no omissions in scoping and screening the yard structure for license

renewal.

2.4.2.8.3 Conclusions

The staff reviewed the LRA to determine whether any SSCs within the scope of license renewal

and subject to an AMR had not been identified by the applicant. No omissions were found. On
2-156

the basis of this review, the staff concludes that the applicant has adequately identified the

structural components of the yard structures that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and that the applicant has adequately identified the components of

the yard structures 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 Control

The applicant identified electrical and I&C component commodity groups subject to an AMR in

Section 2.5, “Scoping and Screening Results: Electrical and Instrumentation and Control,” of

the LRA. The staff reviewed this section of the LRA to determine that all electrical component

commodity groups, which are subject to an AMR as required by 10 CFR 54.21(a)(3), have been

identified as required by 10 CFR 54.4(a) and 10 CFR Part 54.21(a)(1).

2.5.1 Summary of Technical Information in the Application

The applicant developed a listing of electrical and I&C component commodity groups for

systems and structures within the scope of license renewal as well as active/passive

determinations following the guidance of NEI 95-10, Appendix B. No commodity groups,

beyond those listed in Appendix B to NEI 95-10, were identified by the applicant for VCSNS.

The applicant reviewed these electrical component commodity groups (determined to be

passive) to identify those that are not subject to replacement based on a limited qualified life or

specified time period. 

Based on its review, the applicant determined that the following electrical and I&C component

commodity groups are subject to an AMR:

• insulated cables, connectors, splices, electrical penetration assemblies, and terminal

blocks that are not covered by the VCSNS 10 CFR 50.49 EQ program

• high voltage electrical switchyard bus 

• high voltage transmission conductors and connections

• high voltage insulators.

All other electrical and I&C component commodity groups are either (a) active (active/passive

screening), (b) subject to replacement based on a qualified life or specified time period (long

lived screening), or (c) not subject to an AMR because they do not perform any intended

functions (scoping).

2.5.2 Staff Evaluation

Section 2.1 of the LRA, Scoping and Screening Methodology, discussed the scoping

methodology as it related to the safety-related criteria pursuant to 10 CFR 54.4(a)(1),

non-safety-related criteria pursuant to 10 CFR 54.4(a)(2), and regulated events pursuant to 10

CFR 54.4(a)(3). Following the determination of the systems and structures within the scope of

license renewal, the applicant implemented a process for determining which components,
2-157

among those systems and structures that were determined to be within scope of license

renewal, would be subject to an AMR in accordance with the requirements of

10 CFR 54.21(a)(1).

2.5.2.1 Identification of Passive Components

The applicant developed a listing of passive electrical and I&C component commodity groups

for systems and structures within the scope of license renewal following the guidance of

NEI 95-10 (Revision 3), Appendix B. No commodity groups, beyond those listed in Appendix B

to NEI 95-10 (Revision 3), were identified by the applicant for VCSNS.

Guidance of NEI-95-10, Appendix B, utilized by the applicant for active/passive screening

determinations, identifies the following passive electrical and I&C component commodity groups

from typical nuclear plant systems and structures:

• cables and connections, bus, electrical portions of electrical and i&c penetration

assemblies (e.g., electrical penetration assembly cables and connections, connectors,

electrical splices, terminal blocks, power cables, control cables, instrument cables,

insulated cables, communication cables, uninsulated ground conductors, transmission

conductors, isolated-phase bus, nonsegregated-phase bus, segregated-phase bus,

switchyard bus)

• elements, resistance temperature detectors (RTD), sensors, thermocouples,

transducers (e.g., conductivity elements, flow elements, temperature sensors, radiation

sensors, watt transducers, thermocouples, RTDs, vibration probes, amp transducers,

frequency transducers, power factor transducers, speed transducers, variable

transducers, vibration transducers, voltage transducers) [passive for a pressure

boundary, if applicable]

• high-voltage insulators (e.g., porcelain switchyard insulators, transmission line

insulators)

Passive components (for which aging degradation is not readily monitored) are those that

perform an intended function without moving parts or without a change in configuration or

properties. As examples of passive components, 10 CFR 54.21(a)(1)(i) provides a list 

including, but not limited to, electrical penetrations, cables, and connections; and excluding, but

not limited to, motors, diesel generators, pressure transmitters, pressure indicators, water level

indicators, switchgears, cooling fans, transistors, batteries, breakers, relays, switches, power

inverters, circuit boards, battery chargers, and power supplies.

The staff reviewed the above identified component commodity groups to verify that the

applicant had not omitted any passive component commodity groups and the groups identified

met the above defined passive screening criteria and/or examples provided in 10 CFR

54.21(a)(1)(i). The staff concluded that the above identified component commodity groups are

consistent with the examples of passive components listed in 10 CFR 54.21(a)(1)(i), and are

therefore considered acceptable. In addition, these component commodity groups are the

same as the passive determinations described in NEI 95-10 (Revision 3), Appendix B, for

component commodity groups typically found in nuclear plants in the electrical category. The

staff has reviewed these NEI determinations and concluded (1) that each component
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commodity group identified performs its intended function without moving parts or without a

change in configuration or properties, and its aging degradation is not readily monitored, (2)

that these component commodity groups acceptably identify passive components pursuant to

10 CFR 54.21(a)(1)(i), and (3) fuse blocks/fuse clips will be added as part of the cable and

connections commodity group. Therefore, the staff agrees that the above identified subgroup

of electrical component commodity groups represents the passive electrical component

commodity groups that would be required to be included in an AMR if they also met scoping

and long-lived screening criteria. 

2.5.2.2 Identification of Components that are Passive but Not Long-Lived

From the above electrical and I&C component commodity groups determined to be passive, the

applicant identified the following component commodity groups as not meeting long-lived

screening criteria and thus not subject to an AMR:

• insulated cables and connections and terminal blocks that are included in the VCSNS

10 CFR 50.49 EQ program

• electrical portions of electrical and I&C penetration assemblies that are included in the

VCSNS 10 CFR 50.49 EQ program

A component that is not replaced either (1) on a specified interval based on the qualified life of

the component or (2) periodically in accordance with a specified time period, is deemed to be

“long-lived,” and therefore subject to an AMR.

Components subject to EQ aging requirements pursuant to 10 CFR 50.49(e)(5) are required to

be replaced or refurbished at the end of their designated life. These components, pursuant to

10 CFR 50.49(e)(5), are subject to replacement based on a qualified life or specified time

period. The applicant in the LRA indicated that the above identified components are included in

its 10 CFR 50.49 EQ program and subject to aging requirements of 10 CFR 50.49(e)(5). The

staff, therefore, agrees that the above identified components do not meet long-lived screening

criteria and are thus not subject to an AMR.

2.5.2.3 Identification of Components Not Within the Scope of License Renewal

In its review, the staff noted that the applicant had not identified the following passive

component commodity groups as within the scope of 10 CFR 54.4(a):

• uninsulated ground conductors

• isolated-phase bus, nonsegregated-phase bus, segregated-phase bus

• elements, RTDs, sensors, thermocouples, and transducers (e.g., conductivity elements,

flow elements, temperature sensors, radiation sensors, watt transducers,

thermocouples, RTDs, vibration probes, amp transducers, frequency transducers, power

factor transducers, speed transducers, variable transducers, vibration transducers,

voltage transducers that are passive for a pressure boundary only, if applicable) 
2-159

As part of its review, the staff requested the applicant to explain how each of these passive

component commodity groups were found not to meet any of the scoping criteria of 10 CFR

54.4(a).

Elements, RTDs, Sensors, Thermocouples, and Transducers — Section 2.5 of the LRA

indicates that the passive electrical component commodity group of elements, RTDs, sensors,

thermocouples, and transducers (e.g., conductivity elements, flow elements, temperature

sensors, radiation sensors, watt transducers, thermocouples, RTDs, vibration probes, amp

transducers, frequency transducers, power factor transducers, speed transducers, variable

transducers, vibration transducers, voltage transducers) that are passive because of their

pressure boundary function were found not to meet any of the scoping criteria of 10 CFR

54.4(a). Consequently, Section 2.5 of the LRA indicated that this commodity group is

considered outside the scope of license renewal. In a follow-up question, the staff requested

that the response to RAI 2.5-1 (requested by letter dated March 28, 2003) be expanded to

explain why this commodity group was found not to meet any of the scoping criteria of 10 CFR

54.4(a). In its response dated June 12, 2003, the applicant stated that from an electrical

standpoint, the “Elements” commodity group is active, and from a pressure boundary

standpoint, these elements are not pressure boundary at VCSNS, and were, thus, screened out

of consideration.

Based on its review, the staff concludes that there is no omission of electrical components (or

elements) at VCSNS that could maintain a pressure boundary; therefore, the screening of this

“Elements” commodity group from the scope of license renewal is considered acceptable. 

Isolated-phase bus, nonsegregated-phase bus, segregated-phase bus — Section 2.5 of the

LRA indicates that the passive electrical component commodity group of isolated-phase bus,

nonsegregated-phase bus, and segregated-phase bus were found not to meet any of the

scoping criteria of 10 CFR 54.4(a). Consequently, Section 2.5 of the LRA indicates that this

Bus” commodity group is considered outside the scope of license renewal. By letter dated

March 28, 2003, the staff requested, in RAI 2.5-1, the applicant to explain why this Bus”

commodity group was found not to meet any of the scoping criteria of 10 CFR 54.4(a). In its

response dated June 12, 2003, the applicant stated the following:

VCSNS has only one application for bus duct, the isolated phase bus duct from the Main Generator to the Main

Power Transformer in the Generator & Main Transformer (EG) System. This application is not in scope, as it

is not credited as one of the two preferred sources for providing offsite power. See response to RAI 2.5-4 for

further detail. Insulated cables are credited for providing offsite ESF power. These insulated cables on the plant

system portion of the offsite power grid will be included in the Non-EQ Insulated Cable and Connection

Inspection Program.

In addition, in its response to RAI 2.5-4 dated June 12, 2003, the applicant stated the following:

The EG system provides for the transmission of power from the site. The handling of plant loads, which are in

the LR scope, is provided by one of the two preferred paths of offsite power, which do not include system EG

[reference FSAR 8.1]. The Main Generator bus is not used by either of the two preferred sources of offsite

power and is isolated by the associated substation 230 KV circuit breaker OCB-8892. The main electrical

generator bus is not subject to aging management because it does not meet any of the criteria In 10 CFR

54.4(a). The main transformer is in the same category, and system EG is not relied upon for any in-scope

electrical back feed in response to an SBO event. The system is therefore not in the scope of license renewal

consideration.
2-160

The boundary of the plant systems portion of the offsite power grid for the two preferred sources of offsite power

Is shown on a drawing, which has been furnished for your information as requested.

It should be noted that the 230KV preferred source of offsite power comes from switchyard 230KV bus 3. A

mistake was made in the LRA Section 2.1.1.1.4, Table 2.2-2 [Electrical Substation; Transmission Towers and

Foundations], and Section 2.5.4, which refer to 230KV bus 1. The correct 230KV preferred source of offsite

power is 230KV bus 3.

Based on this response, the staff concludes that this “Bus” commodity group was screened out

from the scope of license renewal pursuant to 10 CFR 54.4(a) as part of applicant’s electrical

systems scoping review. Based on its review, the staff concludes that there is no omission of

electrical bus at VCSNS. The screening of this “Bus” commodity group from the scope of

license renewal pursuant to 10 CFR 54.4(a) is considered acceptable. 

Uninsulated ground conductors — Section 2.5 of the LRA indicates that the passive electrical

component commodity group of uninsulated ground conductors was found not to meet any of

the scoping criteria of 10 CFR 54.4(a). Consequently, this commodity group was considered

outside the scope of license renewal. After a series of RAIs and responses thereto, the staff

found that uninsulated ground conductors are part of the VCSNS CLB. In a letter dated

September 2, 2003, the applicant clarified that the uninsulated ground conductors within the EC

system are considered part of the CLB for VCSNS.

However, the staff’s conclusion on this matter, based on the plant’s conformance with single

failure criteria, is that no credible uninsulated ground conductor failure mode or mechanism

would prevent satisfactory accomplishment of any of the safety-related functions identified in 10

CFR 54.4(a)(1)(i),(ii), or (iii). Although the unavailability or failure of the uninsulated ground

conductor may increase the damage/impact to one train if a single failure occurs, uninsulated

ground conductors do not meet the non-safety-related scoping criterion of 10 CFR 54.4(a)(2). 

Therefore, the passive electrical commodity of uninsulated ground conductor is not within the

scope of license renewal. 

2.5.3 Conclusions

Based on its review, the staff did not find any omissions and, therefore, concludes that the

applicant has identified component commodity groups of the electrical and I&C systems that are

within the scope of license renewal pursuant to 10 CFR 54.21(a), and subject to an AMR

pursuant to passive screening criterion 10 CFR 54.21(a)(1)(i) and the long-lived screening

criterion 10 CFR 54.21(a)(1)(ii). 
3-1

3 AGING MANAGEMENT REVIEW

3.0 Aging Management Review Results

V.C. Summer Nuclear Station (VCSNS) fully utilized the Generic Aging Lessons Learned

(GALL) process found in NUREG-1801, “Generic Aging Lessons Learned (GALL) Report.” The

purpose of the GALL process is to provide the staff with a summary of staff-approved aging

management program (AMPs) for the aging of most structures and components (SCs) that are

subject to an aging management review (AMR). If an applicant commits to implementing these

staff-approved AMPs, the time, effort, and resources used to review an applicant’s license

renewal application (LRA) will be greatly reduced, thereby improving the efficiency and

effectiveness of the license renewal review process. The GALL Report is a compilation of

existing programs and activities used by commercial nuclear power plants to manage the aging

of SCs within the scope of license renewal and which are subject to an AMR. 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 staff of

the Nuclear Regulatory Commission (NRC) has determined will provide adequate aging

management during the period of extended operation. 

The GALL Report identifies (1) structures, systems, and components (SSCs), (2) component

materials, (3) the environments to which the components are exposed, (4) the aging effects

associated with the materials and environments, (5) the AMPs that are credited with managing

the aging effects, and (6) recommendations for further applicant evaluations of aging effects

and their management for certain specific components types. 

In order to determine whether the GALL process would improve the efficiency of the license

renewal review, the staff conducted a demonstration project to exercise the GALL process and

to determine the format and content of a safety evaluation based on this process. The results

of the demonstration project confirmed that the GALL process will improve the efficiency and

effectiveness of the LRA review while maintaining the staff’s safety focus. The standard review

plan for license renewal (SRP-LR) was prepared based on both the GALL model and the

lessons learned from the demonstration project. 

During its review of the VCSNS LRA, the staff performed an AMR inspection from August 4-8

and 18-22, 2003. The purpose of the inspection was to examine activities that support the LRA. 

It consisted of a selected examination of procedures, representative records, and interviews

with the applicant regarding proposed aging management activities. In addition, the inspection

team reviewed the proposed implementation of all AMPs credited in the LRA for managing

aging. During the AMR inspection, the staff evaluated specific issues raised by staff reviewers. 

On the basis of the information gathered during the inspection, the staff finds that the applicant

has adequately addressed the specific issues raised by the staff reviewers. The inspection

issues can be found in the staff’s Inspection Report 50-395/03-08, dated September 29, 2003.

The staff also performed an AMP audit on July 16-17, 2003. The purpose of the audit was to

verify the consistency of the applicant’s AMPs described in the LRA with the AMPs in GALL

Report. The audit team evaluated each of the 10 attributes of an applicant’s AMP that the

applicant claimed were consistent with the related attribute of the associated AMP described in
3-2

the GALL report. Those AMPs that were not claimed to be consistent with the GALL report,

and those attributes that were deviations from the attributes described in the GALL report

AMPs, were provided to the NRC staff for review. On the basis of the audit team’s review of the

AMPs, the staff verifies that the applicant’s determination of consistency between the

applicant’s AMPs and the AMPs described in the GALL Report. The audit issues can be found

in the staff’s audit report dated October 9, 2003.

3.0.1 The GALL Format for the License Renewal Application

The VCSNS LRA closely follows the standard LRA format. However, several important

changes within the format reflect the GALL process. First, the tables in LRA Section 2 that

identify the SCs that are subject to an AMR now include a third column which links plantspecific SCs in the Section 2 tables to generic GALL component groups in Section 3 (this is

discussed in more detail below). 

Second, there are no system-specific tables in Section 3 of the VCSNS LRA. The individual

components within a system have been included in a series of system group tables. For

example, there are 23 auxiliary systems at VCSNS. Each system has several components. In

the VCSNS LRA, there are no system tables. Instead all the components in the 23 auxiliary

systems are included in one of two auxiliary system tables. 

LRA Table 3.3-1 consists of auxiliary system components evaluated in the GALL Report and

auxiliary system components that were not evaluated in the GALL Report, but that the applicant

has determined can be managed using a GALL AMR and associated AMP. LRA Table 3.3-2

consists of VCSNS auxiliary system components that were not evaluated in the GALL Report. 

Similarly, the LRA tables for the other system groups (3.1 – reactor systems, 3.2 – engineered

safety feature systems, 3.4 – steam and power conversion systems, 3.5 – structures, and 3.6 –

electrical systems) have 3.X-1 LRA tables for components evaluated in the GALL Report and

for components that were not evaluated in the GALL Report, but that the applicant has

determined can be managed using a GALL AMR and associated AMP. Section 3 also includes

3.X-2 LRA tables for components that were not evaluated in the GALL Report.

The first four columns of Table 3.X-1 are derived from Tables 3.1-1 through 3.6-1 of the SRPLR. The final column provides a discussion of (1) information regarding the applicability of the

GALL Report component/commodity group to VCSNS, (2) any issues recommended in the

GALL Report that require further evaluation, (3) details regarding VCSNS components to be

included in the component/commodity group, and (4) a conclusion regarding consistency of the

AMR with the GALL Report. A conclusion that the AMR is consistent with the GALL Report

means that the combination of component material, environment, aging effect requiring

management, and AMR are the same as those specified in Volume 2 of the GALL Report. 

VCSNS considered an AMR to be consistent with the GALL Report despite differences in the

names of plant-specific components or commodities provided that the above combination of

material, environment, aging effect requiring management, and AMP were the same as those

identified in the GALL Report. In some cases, additional components/commodities beyond

those listed in the GALL Report have been added, but only if the combination of material,

environment, aging effect requiring management, and AMP were the same. In addition, plantspecific information that pertains to the evaluation of the component/commodity group has been

included in the discussion column. 
3-3

The 3.X-2 tables provide information regarding AMPs that are different from or not addressed in

the GALL Report. The columns of these tables list component/commodity group, material,

environment, aging effect/mechanism, and AMP, and include a discussion of the AMR results. 

The discussion typically identifies the differences from the GALL Report that form the basis for

including the information in Table 3.X-2 instead of Table 3.X-1. Also, the information in these

tables includes material/environment combinations that resulted in no aging effects requiring

management.

3.0.2 The Staff’s Review Process

The staff’s review of the VCSNS LRA was performed in three phases. In Phase 1, the staff

reviewed the applicant’s AMP descriptions and compared those AMPs for which the applicant

claimed consistency with those reviewed and approved in the GALL Report. For those AMPs

for which the applicant claimed consistency with the GALL AMPs, and for which the GALL

Report recommended no further evaluation, the staff conducted an audit to confirm that the

applicant’s AMPs were consistent with the GALL AMPs. For AMPs that were not consistent

with the GALL Report, or were not addressed in GALL, the staff’s review determined whether

the AMPs were adequate to manage the aging effects for which they were credited. 

Several VCSNS AMPs were described by the applicant as being consistent with the GALL

Report, but with some deviation from GALL. By letters dated March 28, 2003, and April 9,

2003, the staff issued requests for additional information (RAI) 3.0-1, requesting the applicant

to define the AMP deviations contained in the LRA. By letters dated June 12, 2003, and

September 2, 2003, the applicant addressed these RAIs and follow-up staff concerns by

defining the following two types of AMP deviations.

(1) Exceptions to GALL — An exception indicates that the VCSNS implementing procedure (or

other document) does not achieve consistency with some element of the related GALL Chapter

XI Program. Justification for the exception is provided. 

(2) Enhancements to GALL — An enhancement indicates that the VCSNS implementing

procedure (or other document) requires revision to achieve consistency with some element of

the related GALL Chapter XI or SRP-LR Appendix A.1 Program. 

For each AMP that had one or more of these deviations, the staff reviewed each deviation to

determine (1) whether the deviation is acceptable, and (2) whether the AMP, as modified, would

adequately manage the aging effect(s) for which it is credited. 

For those AMPs that were not evaluated in the GALL Report, the staff evaluated the AMP

against the 10 program elements (BTP RLSB-1 in Section A-1 of SRP-LR, Appendix A). 

The staff also reviewed the final safety analysis report (FSAR) supplement for each AMP to

determine whether it provided an adequate description of the program or activity, as required by

Section 54.21(d) of Title 10 of the U.S. Code of Federal Regulations (CFR).

The AMRs and associated AMPs in the GALL Report fall into two broad categories, (1) those

AMRs and associated AMPs that GALL concludes are adequate to manage aging of the

components referenced in GALL, and (2) those AMRs and associated AMPs for which GALL
3-4

concludes that aging management is adequate, but recommends further evaluation for certain

aspects of the aging management process. In Phase 2, the staff compared the applicant’s

AMR results and associated AMPs to the AMR results and associated AMPs reviewed and

approved in the GALL Report to determine their consistency. For those AMRs and associated

AMPs for which GALL recommended further evaluation, the staff reviewed the applicant’s

evaluation to determine whether it addressed the additional issues recommended in the GALL

report. Finally, for AMRs and associated AMPs that were not consistent with GALL, the staff

determined whether the AMRs and associated AMPs were adequate to manage the aging

effects for which they were credited.

Once it had determined that the applicant’s AMPs were adequate to manage aging, the staff

performed Phase 3 of its review by evaluating plant-specific SCs to determine whether the

applicant had demonstrated that the effects of aging 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). Specifically, this evaluation

involved a component-by-component review to determine whether the applicant properly

applied the GALL program to the aging management of components within the scope of license

renewal and subject to an AMR (i.e., the staff evaluated whether the applicant had properly

identified the aging effects, and the AMPs credited for managing these aging effects, for each

VCSNS SC within the scope of license renewal and subject to an AMR). For SCs evaluated in

the GALL Report, the staff reviewed the adequacy of aging management against the GALL

criteria. For SCs not evaluated in the GALL Report, the staff reviewed the adequacy of aging

management against the 10 criteria found in Appendix A of the SRP-LR. Some VCSNS SCs

were not evaluated in GALL, but the applicant determined that the GALL AMR results could be

applied and provided justification to support this determination. In these cases, the staff

reviewed the adequacy of aging management against the GALL criteria to determine whether

the GALL AMPs were adequate to manage the aging effects for which they were credited.

3.0.3 Common Aging Management Programs

Table 3.0.3-1 presents the common AMP, the associated GALL program, the system groups

that credit the program for management of component aging, and the SER section that

contains the staff’s review of the program. 

Table 3.0.3-1: Common Aging Management Programs

Applicant’s AMP (LRA

section) 

Associated GALL AMP LRA System Groups that Credit

the AMP for Aging Management

Staff Evaluation

(SER Section)

Boric Acid Corrosion

Surveillance Program

(B.1.2)

XI.M10 3.1 - RCS

3.2 - ESF

3.3 - AUX

3.4 - SP&C

3.5 - Civil (Structures)

3.6 - Electrical

3.0.3.1
Table 3.0.3-1: Common Aging Management Programs

Applicant’s AMP (LRA

section) 

Associated GALL AMP LRA System Groups that Credit

the AMP for Aging Management

Staff Evaluation

(SER Section)

3-5

Chemistry (B.1.4) XI.M2, XI.M30 3.1 - Reactor Systems

3.2 - ESF

3.3 - Auxiliary

3.4 - Steam and Power

Conversion

3.5 - Structures

3.0.3.2

Fire Protection Program (B

1.5)

XI.M26, XI.M33 3.3 - Auxiliary

3.5 - Structures

3.0.3.3

Maintenance Rule

Structures (B 1.18)

XI.S5, X1.S6 3.3 - Auxiliary

3.4 - SP&C

3.5 - Civil (Structures)

3.0.3.4

Above Ground Tank

Inspection Program (B 2.1)

XI.M32 3.2 - ESF

3.3 - Auxiliary

3.4 - Steam and Power

3.0.3.5

Buried Piping and Tanks

Inspection Program (B 2.10)

X1.M.34 3.3 - Auxiliary

3.4 - SP&C

3.0.3.6

Inspection for Mechanical

Components Programs (B

2.11)

None 3.2 - ESF

3.3 - Auxiliary

3.4 - Steam and Power

Conversion

3.0.3.7

Heat Exchanger Inspection

Program (B 2.12)

X.M32, XIM33 3.3 - Auxiliary

3.4 - Steam and Power

Conversion

3.0.3.8

Area Based Inspections for

Refined 10CFR 54.4(a)(2)

Criteria (B 2.13)

None 3.3 - Auxiliary

3.4 - Steam and Power

Conversion

3.0.3.9

3.0.3.1 Boric Acid Corrosion Surveillances Program

The Boric Acid Corrosion Surveillances (BACS) Program is described in Section B.1.2 of

Appendix B in the LRA. The LRA credits this surveillance program with the capability to identify

leaks from borated water systems, and subsequently manage the effect of boric acid corrosion

for the Virgil C. Summer Nuclear Station (VCSNS). The program monitors and assesses the

condition of components that may be affected by boric acid corrosion. The staff reviewed the

LRA to determine whether the applicant has demonstrated that the BACS Program will

adequately manage the applicable aging effects for the components that credit this program

throughout the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.0.3.1.1 Summary of Technical Information in the Application

The applicant’s BACS Program is discussed in LRA Section B.1.2, “Boric Acid Corrosion

Surveillances Program.” The applicant stated that the program is consistent with GALL AMP

XI.M10, “Boric Acid Corrosion,” with additional surveillances to address electrical connector

contacts that may be exposed to borated water leakage mentioned in Chapter VI, Item A.2.1 of

the Gall report. This aging management program (AMP) was originally implemented by the
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applicant in response to Generic Letter (GL) 88-05, “Boric Acid Corrosion of Carbon Steel

Reactor Pressure Boundary Components in PWR Plants.”

In Section B.1.2 and FSAR Supplement 18.2.7 of the LRA, the applicant described BACS

Program as an existing AMP that manages loss of material due to boric acid corrosion of

mechanical and structural components located in the reactor building and in specific areas of

the auxiliary, intermediate, and fuel buildings where borated water leakage is possible. Further,

the applicant stated that the BACS Program also manages boric acid intrusion into electrical

equipment located in proximity to borated water systems. Elements of the BACS Program

include the identification of leakage locations, procedures for locating small leaks, and

corrective actions to ensure that boric acid corrosion does not lead to degradation of structures

and components that could cause the loss of intended function. 

The BACS Program is credited in the AMR tables with managing the following aging effects

during the period of extended operation: (1) Loss of material due to boric acid corrosion of

external surfaces of carbon steel (CS), low-alloy steel (LAS), and cast iron components; and (2)

Loss of material due to boric acid corrosion and aggressive chemical attack of aluminum or

brass piping and piping system components (Table 3.4-2, AMR Item 2). The following systems

contain commodities/components for which this AMP is credited with managing the aging effect

of loss of material: reactor coolant, auxiliary, engineered safety features, steam and power

conversion, and structural and electrical systems.

In Section B.1.2 of the LRA, the applicant concluded that the Boric Acid Surveillances have

been demonstrated to be capable of identifying leaks from borated water systems, and

subsequently managing the effects of boric acid corrosion. The applicant also concluded that

the Boric Acid Corrosion Surveillances provide reasonable assurance that the aging effects will

be managed such that the components subject to aging management review will continue to

perform their intended functions consistent with the current licensing basis for the period of

extended operations.

By letter dated September 12, 2002, SCE&G supplemented the license renewal application for

VCSNS. The letter provided the results of the additional reviews based on the NRC staff

positions on scoping of seismic II/I piping systems in letters dated December 3, 2001, and

March 15, 2002. As a result, VCSNS added several additional SSC's into the scope of license

renewal and expanded the program description of several aging management programs

including Boric Acid Surveillances program. The staff evaluation is provided below. 

3.0.3.1.2 Staff Evaluation

In LRA Section B.1.2, “Boric Acid Corrosion Surveillances (BACS),” the applicant described its

program to manage the effects of boric acid corrosion within the scope of license renewal. The

LRA states that this program is consistent with GALL AMP XI.M10, “Boric Acid Corrosion.” The

staff confirmed the applicant’s claim of consistency during an AMR Audit on July 16 - 17, 2003. 

The staff verified that the BACS program, as described, is consistent with GALL AMP XI.M10. 

Based on the consistency of this program with the GALL report, the staff focused its review on

the operating history program element supporting the effectiveness of this program.

The staff reviewed the information in Section B.1.2 of Appendix B to the LRA, the summary

description of the program in the FSAR supplement (Section 18.2.7 of Appendix A to the LRA),
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and the applicant’s responses to the staff’s request for additional information (RAIs). The 10

program elements in GALL AMP XI.M10, “Boric Acid Corrosion,” provide detailed programmatic

characteristics and criteria that the staff considers to be necessary to manage the aging effects

in components. In LRA Section B.1.2, the applicant stated that the program elements for the

BACS program are consistent with those specified in AMP XI.M10 of the GALL report except for

enhancements related to dissimilar metal weld inspections. 

[Operating Experience] In LRA Section B.1.2, the applicant stated that the BACS Program was

enhanced following the incident of a weld cracking between the hot leg and RPV nozzle at

VCSNS on October 7, 2000. The enhancements included provisions to ensure that all

dissimilar metal welds were included in the population of components that are visually inspected

at refueling outages or when appropriate plant conditions permit access. By letter dated March

28, 2003, the staff requested, in RAI B.1.2-1, the applicant to clarify the post-GALL VCSNS

operating history and to discuss how the systems outside of containment will be inspected

under the enhanced BACS Program. 

In its response dated June 12, 2003, the applicant stated that the current BACS Program

focuses on GL 88-05 requirements. The applicant also noted that GALL is driving the industry

to make enhancements to the surveillances (i.e., to inspect systems outside of containment that

contain boric acid solutions). In addition, recent industry events are also driving the industry to

perform additional inspections. These events are described in NRC Bulletin 2002-01, “Reactor

Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity,” and

Bulletin 2002-02, “Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle

Inspection Programs.” The applicant stated that it intends to enhance the surveillance test

procedures, required by technical specifications, for leakage of primary coolant sources outside

containment (i.e., boron recycle, liquid waste, nuclear sampling, chemical and volume control,

residual heat removal, and RB spray systems). In addition, the applicant stated that it also

intends to enhance the leak tests performed for the SI accumulators and the spent fuel pool

cooling system. These enhanced leak tests would specify inspections for boric acid

crystallization on the system being tested and, in the cases when boric acid is found, also on

the surrounding systems. These enhancements will be noted on the procedures and

maintained as license renewal commitments. The applicant finally stated that the development

of an overall Boric Acid Corrosion Program will incorporate GL 88-05 requirements, license

renewal commitments, and the additional inspections that result from the NRC Bulletins. As

documented in a telecommunications discussion on July 9, 2003, these enhancements are

considered commitments. Applicant has agreed that this is a license renewal commitment and

this commitment is documented in Appendix A of this SER.

Based on the applicant’s responses to NRC Bulletins 2002-01 and 2002-02, its response to the

RAI, and the discussion of enhancements to this program, the staff finds the applicant 

response adequate in addressing the concerns related to the detection of cracking in dissimilar

metal welds. Therefore, RAI B.1.2-1 is considered closed. By letter dated November 5, 2003,

the applicant determined that, subsequent to the RAI response, the leakage assessments for

the chemical and volume control, residual heat removal, and RB spray systems were limited to

only portions of the systems. Therefore, the applicant decided that the BACS program should

credit the leak tests for these systems instead of the leakage assessments previously

discussed in the RAI response. Based on this determination the staff finds the credit of leak

tests an appropriate and conservative enhancement to the BACS program to manage systems
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outside containment since this test is not limited to portions of the systems. Therefore, RAI

B.1.2-1 remains closed.

By letter dated March 28, 2003, the staff requested, in RAI B.1.2-2, the applicant to list the

location of the other dissimilar metal welds exposed to borated coolant to be included within the

scope of the BACS Program in light of recent events. In its response dated June 12, 2003, the

applicant listed the welds provided in Attachment IX to the letter from Stephen A. Byrne to the

NRC Document Control Desk, dated January 24, 2003, entitled, “Response for Additional

Information Regarding 60 Day Response to NRC Bulletin 2002-01 Reactor Pressure Vessel

Head Degradation and Reactor Coolant Pressure Boundary Integrity.” 

The following dissimilar welds are included within the scope of the BACS Program:

• “A” hot leg weld to reactor vessel nozzle

• “A” cold leg weld to reactor vessel nozzle

• “B” hot leg weld to reactor vessel nozzle

• “B” cold leg weld to reactor vessel nozzle

• “C” hot Leg weld to reactor vessel nozzle

• “C” cold leg weld to reactor vessel nozzle

• Pressurizer surge line weld to pressurizer nozzle

• Pressurizer nozzle weld to “A” pressurizer safety valve

• Pressurizer nozzle weld to “B” pressurizer safety valve

• Pressurizer nozzle weld to “C” pressurizer safety valve

• Pressurizer nozzle weld to PORVs

• Pressurizer nozzle weld to spray piping

• “A” hot leg weld to steam generator nozzle

• “A” crossover weld to steam generator nozzle

• “B” hot leg weld to steam generator nozzle

• “B” crossover weld to steam generator nozzle

• “C” hot leg weld to steam generator nozzle

• “C” crossover weld to steam generator nozzle

Based on this response, the scope of this surveillance program includes the dissimilar welds

that may be susceptible to cracking as discussed in the recent NRC Bulletins. Therefore, the

staff finds the response satisfactory and considers RAI B.1.2-2 closed. 

The LRA credits the BACS Program for managing loss of material due to boric acid corrosion of

the pressurizer, CS and LAS components (e.g., shell, upper and lower heads, nozzles, integral

support, and manway cover and bolts), the external surfaces of CS components in the RCS

pressure boundary (LRA Table 3.1-1, AMR Item 26), and the steam generator (SG) elliptical

head and channel head (LRA Table 2.3-7). By letter dated March 28, 2003, the staff requested,

in RAIs B.1.2-3 and B.1.2-4, the applicant to discuss how the BACS Program sufficiently

manages the corrosive effects of boric acid leakage on the base metal of insulated components

during the extended period of operation (e.g., leakage from the pressurizer nozzle-to-vessel

welds, pressurizer nozzle-to-safe end welds, and pressurizer manway bolting materials). In

addition, the staff requested the applicant to discuss how the BACS Program would manage

VCSNS steam generator external surfaces in light of Bulletin 2002-01, and GL 88-05, “Boric

Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components In PWR Plants.”
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In its response dated June 12, 2003, the applicant stated that BACS Program will evaluate all

boric acid leaks, continue to remove insulation and inspect all joints for leakage during each

refueling outage, and apply corrective actions for boric acid leaks, as required, for the source

and the adjacent components, supports, or structures. The applicant also referenced the

response to Bulletin 2002-01 from Stephen A. Byrne of VCSNS to the NRC Document Control

Desk dated January 24, 2003, as a source of further information. The staff reviewed this

document and finds the detailed information provided on the inspection techniques, scope,

extent of coverage, frequency of inspections, personnel qualifications, and degree of insulation

removal is adequate in addressing the staff concerns. Therefore, RAIs B.1.2-3 and B.1.2-4 are

considered closed because the January 24, 2003 document describes how the BACS Program

would manage the corrosive effects of boric acid leakage on the base metal of insulated

components and steam generator external surfaces. 

The staff reviewed the criteria 2 supplemental information in Section B.1.2, "Boric Acid

Surveillances," in which the applicant credited this AMP for managing components located in

the Auxiliary, Intermediate, and Fuel Handling buildings. These components are constructed of

carbon steel, low-alloy steel, and other susceptible materials to loss of material due to boric

acid corrosion. The applicant concluded that revisions or clarifications to the previous

evaluation of this program is not needed to ensure management of these components. 

The staff concurs with the applicant’s conclusion because the materials of construction for

these components is similar to components within the scope of this AMP. The staff notes that

the scope of this AMP has been increased to include these components and finds that this AMP

is adequate in managing these components for loss of material due to boric acid corrosion.

Section 18.2.7 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Boric Acid Corrosion Surveillances (BACS) Program. The staff reviewed this section and finds

the program description consistent with the material contained in Section B.1.2 of Appendix B to

the LRA, except for the reference to GL 88-05 and the enhancements to the BACS Program

discussed in Section 3.0.3.1.2 of this SER. By letter dated September 2, 2003, the applicant

revised the FSAR supplement to include reliance of this program on the implementation of GL

88-05, as well as subsequent NRC bulletins and guidance, to monitor the reactor coolant

pressure boundary for borated water leakage. In addition, the program also includes

monitoring of borated water leakage in all systems containing borated water. Based on this

revision, the staff finds that the FSAR supplement provides an adequate summary of the

program activities are required by 10 CFR 54.21(d).

3.0.3.1.3 Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.2 Chemistry Program
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The Chemistry Program is described in Section B.1.4 of Appendix B in the LRA. The LRA

credits the Chemistry Program with managing loss of material, cracking, and fouling of

components exposed to borated water, closed cooling water, treated water, or fuel oil

environments for the Virgil C. Summer Nuclear Station (VCSNS). The staff reviewed the LRA

to determine whether the applicant has demonstrated that the Chemistry Program will

adequately manage the applicable aging effects for the components that credit this program

throughout the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.0.3.2.1 Summary of Technical Information in the Application

The applicant’s Chemistry Program is discussed in LRA Section B.1.4, “Chemistry Program.”

The applicant stated that the program is consistent with GALL AMP XI.M2, “Water Chemistry,”

and the chemistry-related portions of XI.M30, “Fuel Oil Chemistry,” with the following

clarifications concerning the detection of aging effects. The applicant indicated that the

Chemistry Program is a mitigation program; therefore, no aging effects are detected as part of

this program. In addition, plant operating experience confirms the effectiveness of the program

for managing aging during the period of extended operation. The applicant stated that based

on this experience, VCSNS does not commit to performing one-time inspections to verify the

effectiveness of the Chemistry Program as recommended by the GALL AMP XI.M2.

 

In LRA Section B.1.4 and FSAR Supplement 18.2.10, the applicant stated that aging effects will

be managed by the Chemistry Program such that the components subject to aging

management review (AMR) will continue to perform their intended functions consistent with the

current licensing basis (CLB) for the period of extended operations. The applicant stated that

the Chemistry Program is an ongoing program that incorporates the best practices of industry

organizations, vendors, utilities, and water treatment experts. This aging management program

(AMP) controls the water chemistry in plant systems to minimize contaminant concentrations

and adds chemicals, such as corrosion inhibitors and biocides, to manage loss of material,

cracking, and fouling. The applicant noted that the Chemistry Program is based on EPRI

guidelines for primary and secondary water chemistry. Analyzing and trending the water

chemistry specifications has been in effect since the initial implementation at VCSNS and is

considered acceptable based on industry operating experience. The Chemistry Program

includes specifications for chemical species, limits, sampling and analysis frequencies, and

corrective actions for primary, secondary, and auxiliary (borated or treated) water systems, as

well as for oil and fuel oil.

By letter dated September 12, 2003, SCE&G supplemented the license renewal application for

VCSNS. The letter provided the results of the additional reviews based on the NRC staff

positions on scoping of seismic II/I piping systems in letters dated December 3, 2001, and

March 15, 2002. As a result, VCSNS added several additional SSC's into the scope of the aging

management program, Chemistry Program”. The staff evaluation is provided below. 

3.0.3.2.2 Staff Evaluation

In LRA Section B.1.4, “Chemistry Program,” the applicant described its program to manage the

aging effects of components exposed to borated water, closed cooling water, or treated water. 

The LRA states that this program is consistent with GALL AMPs XI.M2, “Water Chemistry,”

and the chemistry related portions of XI.M30, “Fuel Oil Chemistry.” The staff confirmed the

applicant’s claim of consistency during the AMR Audit on July 16 - 17, 2003. The staff verified
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that the Chemistry Program, as described, is consistent with GALL AMPs XI.M2 and XI.M30. 

Based on the consistency of this program with the GALL Report, the staff focused its review on

the operating history program element supporting the effectiveness of this program.

[Operating Experience] The applicant stated that a review of the operating experience did not

reveal a loss of intended function for components that are exposed to borated water, closed

cooling water, or treated water that could be attributed to an inadequacy of the Chemistry

Program. Therefore, the applicant stated that no special one-time inspection will be performed

for the purpose of verifying the effectiveness of the Chemistry Program. This position deviates

from the recommendation in the GALL report for a one-time inspection in low-flow and/or

stagnant areas. 

By letter dated March 28, 2003, the staff requested, in RAI B.1.4-1, the applicant to clarify from

operating history, recent surveillances, and inspections that cracking and crevice, general,

pitting, and galvanic corrosion are adequately managed for carbon steel (CS) and stainless

steel (SS) components, and cited examples from the AMR Tables. In addition, the applicant

was asked to clarify if there is any inspection of the most susceptible locations (e.g., low-flow or

stagnant areas) for the aging effects of loss of material, cracking, and fouling. In its response

dated June 12, 2003, the applicant stated that the LRA lists the component-aging effect

combination where the Chemistry Program alone is credited for aging management and

presented evidence that such inspections are not required because a review of VCSNS

operating experience did not reveal a loss of intended function of components that are exposed

to borated water. In addition, the effects of pitting and crevice corrosion on SS components are

not significant in chemically treated borated water. The staff determined that the applicant had

not satisfactorily justified the effectiveness of the Chemistry Program in lieu of the one-time

inspection for loss of material for CS components and requested the applicant to further discuss

why the one-time inspection for low flow or stagnant locations is not needed. With respect to

SS non-Class 1 RCS components, the staff notes that these components are internally exposed

to chemically treated borated water and are subject to crack initiation and growth due to stress

corrosion cracking (SCC). Thus, the staff found that the applicant had not adequately justified

the management of cracking of non-Class 1 SS components and requested the applicant to

further discuss the aging management of these components. 

In subsequent correspondence dated September 2, 2003, the applicant stated that one-time

inspections will be performed in low flow areas of the different chemistry regimes prior to the

period of extended operation. The various chemistry regimes to be verified are found in the

feedwater (FW) system, the condensate (CO) system, the emergency feedwater (EF) system,

the component cooling (CC) system, the chilled water (VU) system, the local ventilation (VL)

system, the air handling (AH) system, and the diesel generator services (DG) system. The FW,

CO, and EF systems share one chemistry regime. The VU, VL, AH, and DG systems share

another chemistry regime. Therefore, the applicant concluded that an inspection of one system

per chemistry regime should be representative of the other systems. The CC system alone has

chromates. The applicant further stated that any abnormalities resulting from the visual

inspection of the low flow areas will be dispositioned through engineering evaluation and

addressed in site’s Corrective Actions Program. If further inspections are needed, quality

control inspectors will perform volumetric inspections at representative sites for the chemistry

regime of the VU, VL, AH, and DG systems. With respect to SCC of non-Class 1 SS piping,

the applicant stated that Table 3.1-2, AMR Item 6, lists the aging management of both SS Class

1 and non-Class 1 components susceptible to SCC. In addition, Table 3.1-1, AMR Item 6, lists
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the aging management of SS Class 1 piping with the Small Bore Class 1 Piping Inspection. 

This inspection activity will be representative of the conditions for SS piping and components

(Class 1 and non-Class 1) in borated water service. 

Based on the discussion above, the staff finds the applicant’s commitment to complete a onetime inspection of low flow areas of the different chemistry regimes satisfactory because it

provides a method of verifying the program’s effectiveness as recommended in the GALL

report. With respect to the aging management of SS non-Class 1 components, the staff

reviewed Table 3.1-1, AMR Item 24, which manages the aging effects of management of Class

1 SS components through the Chemistry Program and the In-Service Inspection (ISI) Plan. 

This AMR Item bounds the management of large bore non-Class 1 SS components. In

addition, the management of non-Class 1 SS small bore piping is bounded by the Small Bore

Class 1 Piping Inspection discussed in Table 3.1-1, AMR Item 6. Thus, the staff finds that the

applicant will adequately manage the aging effects of SS non-Class 1 components through a

combination of chemistry control and inspection. Therefore, RAI B.1.4-1 is considered closed. 

The staff notes that the applicant appears to have combined the aspects of several GALL

programs into its Chemistry Program. By letter dated March 28, 2003, the staff requested, in

RAI B.1.4-2, the applicant to clarify to what extent the Chemistry Program relies on the GALL

AMPs XI.M20, “Open-Cycle Cooling Water System,” and XI.M21, “Closed-Cycle Cooling Water

System.” In addition, the staff requested a discussion on how the features of these GALL

programs are incorporated into the VCSNS Chemistry Program. 

In its response dated June 12, 2003, the applicant stated that the Service Water System

Reliability and In Service Testing Program, not the Chemistry Program, is credited for meeting

the requirements of GALL AMP XI.M20, “Open-Cycle Cooling Water System.” The applicant

stated that this program meets the intent of GL 89-13, “Service Water System Problems

Affecting Safety-Related Equipment.” As a response to Recommended Action #2 of GL 89-13,

VCSNS evaluated its component cooling water, chemical volume and control, residual heat

removal, spent fuel cooling and chilled water systems. The results of the evaluation indicated

that the corrosion protection of these systems had not been compromised. This conclusion was

based on a review of the historical maintenance work requests from the time of adopting the

CHAMPS computer software (to track condition reports and work orders). VCSNS maintains

the chemical concentrations of its closed cycle cooling systems within the guidelines of EPRI

TR-107396, “Closed Cooling Water Chemistry Guidelines.” The applicant stated that, prior to

the period of extended operation, one-time inspections will be conducted in low flow areas of

various closed, treated water systems to demonstrate the effectiveness of the Chemistry

Program. 

The applicant’s response indicates that the requirements for GALL AMP XI.M20 are credited in

the Service Water System Reliability and In-Service Testing Program. Therefore, the

components managed by the open-cycle cooling water system, as defined in the GALL report,

are discussed and evaluated in Section 3.3.2.3.1 of this SER. With respect to the GALL

program requirements for the closed-cycle cooling water system, the staff finds that the

applicant appropriately applied the scoping requirements in the GALL report by treating the

aforementioned systems as open-cycle cooing water systems. This action is required in

response to GL 89-13 for which one or more of the following conditions is not satisfied: the

system is not subject to significant sources of contamination, the water chemistry is controlled,

and the heat is not directly rejected to a heat sink. Thus, the components normally managed by
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the closed-cycle cooling water system as defined in the GALL report are, for VCSNS, discussed

and evaluated in Section 3.3.2.3.1 of this SER. Based on the discussion above, the staff finds

that the applicant response satisfactorily addresses the staff concerns and RAI B.1.4-2 is

considered closed. 

The AMR Tables in the LRA refer to conditions in which CS components in a treated water

environment were subject to SCC. By letter dated March 28, 2003, the staff requested, in RAI

B.1.4-3, the applicant to clarify which aging management program is credited for the prevention,

detection, or mitigation of the effects of SCC in these CS components. The staff notes that

according to the ASM Handbook, Vol. 11, “Failure Analysis Prevention,” and EPRI TR-107396,

SCC occurs in CS usually in the presence of hydroxides, carbonates or nitrates. In its response

dated June 12, 2003, the applicant stated that, although industry data does not exhibit

widespread incidence of SCC in low strength CS, there was a reported case suspected to be

nitrate-induced SCC of CS in a treated water system. Thus, VCSNS conservatively listed SCC

as a possible aging mechanism in certain closed systems (such as the diesel generator, chilled

water, air handling, and local ventilation systems) where nitrates are added as a corrosion

inhibitor. The VCSNS Chemistry Program maintains nitrates levels within the EPRI TR-107396

guidelines; therefore, the applicant maintained that the Chemistry Program adequately

manages SCC of CS components in a treated water environment. Based on the applicant’s

application of the EPRI chemistry guidelines and a review of its operating history, the staff finds

that the applicant response satisfactorily addresses the staff concerns and RAI B.1.4-3 is

considered closed. 

The applicant stated that its Chemistry Program is consistent with the ten elements of GALL

AMP XI.M30, “Fuel Oil Chemistry”; however, the program does not verify the program’s

effectiveness at locations where contaminants may accumulate as recommended in the GALL

Report. Thus, by letter dated March 28, 2003, the staff requested, in RAI B.1.4-4, the applicant

to discuss the basis for not including the verification of the effectiveness of this program to

manage loss of material. In its response dated June 12, 2003, the applicant stated that the

details of the sampling of fuel oil, contained in plant procedures, are in accordance with

standards listed in the GALL report and thus meet the requirements of the GALL report for

sampling at different levels inside the fuel oil tanks. Per Technical Specification (TS)

4.8.1.1.2.i.1, the diesel generator fuel oil storage tanks are drained and cleaned every ten

years. The applicant further stated that operating experience at VCSNS for the fuel oil

components managed by this program reveals no history of age-related degradation for the

internal surfaces. The staff finds that the requirements in the TS and the review of the

operating history provide adequate verification of this program’s effectiveness; therefore, the

applicant response satisfactorily addresses the staff concerns and RAI B.1.4-4 is considered

closed.

The LRA credits the Chemistry Program for managing loss of material due to crevice and pitting

corrosion in the pressurizer shell and heads clad with austenitic SS, and SS components

internally exposed to chemically-treated borated coolant. However, the staff notes that these

components are susceptible to crevice and pitting corrosion due to high levels of oxygen, which

may be present in the reactor coolant. By letter dated March 28, 2003, the staff requested, in

RAI B.1.4-5, the applicant to discuss how the Chemistry Program will ensure a sufficient level of

hydrogen over pressurization to manage crevice corrosion in the pressurizer internal surfaces. 

In its response dated June 12, 2003, the applicant stated that the RCS environment, including

the primary side of the steam generators, is sampled and analyzed for chloride, fluoride, and
3-14

dissolved oxygen in accordance with EPRI guidelines. In addition, dissolved oxygen

concentrations are not permitted to exceed procedure limits for prolonged periods, and action

levels have been established to control these concentrations. The applicant further stated that

oxygen is controlled in makeup water as well as in the RCS with hydrogen controlled between

25-50 cc/kg H2O in the RCS to ensure scavenging of oxygen. The staff finds this response

partially acceptable because it is consistent with the water chemistry guidelines presented in 

EPRI TR-105714, “PWR Primary Water Chemistry Guidelines-Revision 4.” According to these

guidelines, the computation of production rates of oxidizing species by radiolysis suggests a

dissolved hydrogen concentration of significantly less than 15 cc/kg is sufficient to scavenge the

oxidizing species under all operating conditions. Since oxygen can also be added to the

coolant from other sources, an excess inventory of hydrogen must be maintained while the

reactor is at power. Therefore, the guidelines set a range of 25-50 cc/kg to provide a margin

against oxidizing conditions and to facilitate operational control. However, the staff determined

that the applicant has not adequately demonstrated, through operating history, that the

hydrogen overpressure level is maintained at this level to manage the loss of material due to

crevice corrosion under these conditions. 

In subsequent correspondence dated September 2, 2003, the applicant stated that the

chemistry samples are taken from the RCS letdown. Based on industry and plant specific

operating experience, this sample point has been determined to provide a good indication of the

liquid chemistry conditions. In addition, the applicant stated that the pressurizer gas space has

sufficient concentration of hydrogen gas which ensures oxygen is scavenged and, in turn,

ensures that the oxygen concentrations are also maintained very low. Based on this

discussion, the staff finds that the applicant has demonstrated that the hydrogen overpressure

level is maintained to manage the loss of material through chemistry sampling which ensures

that the level is within the recommendations of the EPRI guidelines and is supported by plant

specific operating experience.

The staff reviewed the criteria 2 supplemental information in Section B.1.4, "Chemistry

Program," in which the applicant credited the Chemistry Program to manage the relevant

conditions for onset and propagation of the same aging effects in the mechanical system

portions that meet the refined 10 CFR 54.4(a)(2) criteria and have similar materials of

construction and environment. As a result, the applicant provided clarifications to the program

scope, and monitoring and trending elements for this AMP.

[Program Scope] The applicant stated that the boundaries of many systems were expanded to

include newly identified piping. In addition, the demineralized water system (DW) was added to

the scope of this AMP. The staff finds that the increased scope of this AMP is appropriate and

acceptable in managing the identified components that meet 10 CFR 54.4(a)(2).

[Monitoring and Trending] The applicant stated that the DW provides treated water to various

plant locations and supplies the nuclear services (DN) portion in the auxiliary and reactor

buildings. The DW system treats filtered water for use as the source for the treated and

borated water systems and is continuously monitored for effluent conductivity. The

demineralized water storage tank (DWST) is sampled for chlorides, sulfate, sodium, silica,

magnesium, calcium, aluminum, potassium, total suspended solids (TSS), pH, and total organic

carbon (TOC). The staff finds the increased activities to monitor and trend the constituents of

this system adequate and appropriate for mitigating the aging effects through maintenance of

water quality.
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Section 18.2.10 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Chemistry Program at VCSNS. The staff reviewed this section and finds that the information

provided in the FSAR supplement for the aging management of systems and components

discussed above is equivalent to the information in the GALL report, and therefore, provides an

adequate summary of the program activities as required by 10 CFR 54.21. Although the

applicant noted that the Chemistry Program is based on EPRI guidelines for primary and

secondary water chemistry, the staff requested in RAI B.1.4-2 that the FSAR supplement

reference the specific EPRI documents that are consistent with the SRP-LR. By letter dated

September 2, 2003, the applicant revised the FSAR supplement to include the primary and

secondary water chemistry guidelines (i.e., EPRI TR-105714 and EPRI TR-102134). Based on

this revision, the staff finds that the FSAR supplement provides an adequate summary of the

program activities are required by 10 CFR 54.21(d).

3.0.3.2.3 Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds 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). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3 Fire Protection Program

The applicant described its Fire Protection Program (FPP) in Section B.1.5 of Appendix B to the

LRA, Fire Protection Program.” The applicant credits this program with managing the aging of

FP system components that are within the scope of license renewal and subject to an AMR. 

The staff reviewed LRA Section 3 and Section B.1.5 to determine whether the applicant has

demonstrated that the program will adequately manage the applicable effects of aging during

the period of extended operation, as required by 10 CFR 54.21(a)(3).

The applicant’s AMR identifies one or more AMPs to be used to demonstrate that the effects of

aging will be managed so that the intended functions will be maintained consistent with the CLB

for the period of extended operation. The programs to be used for managing the effects of

aging were compared to those listed in NUREG-1801, and were evaluated for consistency with

NUREG-1801 programs that are relied on for nuclear power plant license renewal. The results

are documented and discussed in LRA Section 3, Tables 3.3-1 and 3.3-2, using the format

suggested by NUREG-1800, Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants”.

3.0.3.3.1 Summary of Technical Information in the Application

Section B.1.5 of Appendix B to the LRA states that the FPP is consistent with XI.M26, Fire

Protection,” and XI.M27, Fire Water System,” as well as XI.M23, Selective Leaching of

Materials,” as identified in NUREG-1801 with the following enhancements that will be made to

the current plant program. The applicant’s fire door inspections monitor holes or breaks in the

door surface at a frequency of every 6 months rather than the recommended bimonthly
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frequency. Aging management of the fuel supply line for the diesel-driven fire pump at the

plant is credited to the chemistry program and is not managed by the FPP. The applicant

maintains proper clearances (gap) between doors, frame, and threshold in accordance with

station procedures. However, the applicant does not consider maintaining the clearances to be

an aging effect for license renewal. The applicant intends to perform ultrasonic testing of

selected FP piping to detect aging effects in lieu of disassembly of FP piping for inspection or

full-flow testing of stagnant portions of FP piping.

For operating experience, LRA Section B.1.5 states that the fire barrier and fire barrier

penetration seal inspection in the past five years do not indicate any fire barrier or fire barrier

penetration seal that is in non-conformance with the acceptance criteria. Non-conforming

conditions that were aging related cracks and separations were noted during surveillance of fire

barrier penetration seals. Conditions were repaired in accordance with station procedures. No

condition evaluations reports (CERs) were initiated for fire barriers of fire barriers penetrations

seals relevant to aging. Furthermore, LRA Table 3.3-1, Item 19, for the commodity groups of

doors and barrier penetration seals and concrete structures in fire protection, provides the

following discussions for the AMP:

The plant’s aging management programs for this group are generally consistent with those reviewed and

approved in NUREG-1801. The plant’s fire protection program (Appendix B.1.5) contains many activities to

achieve defense-in-depth and minimize the impact of a potential fire. 

The fire barrier and fire barrier seal inspections detect structural damage or degradation of fire barriers and fire

barrier penetration sealing devices. Fire barriers include walls, ceilings and floors. The corresponding aging

effects are cracking, separation from walls or components, separation of material layers, rupture or puncture

of seals, shrinkage and voids. 

The fire door inspections detect structural damage or degradation of fire rated doors. Inspections are credited

with managing loss of material of doors and door hardware for the period of extended operation. Excessive

wear for door appurtenances such as latches, strike plates, hinges, sills and closing devices, and maintaining

proper clearances (gaps) between the door, frame and threshold are also inspected, but these attributes are

not credited for license renewal. Loss of material due to wear of the door hardware and hinges is not

considered an aging effect but rather a consequence of frequent or rough usage.

According to LRA Section B.1.5, the plant has no failures or adverse trends for fire doors. 

Surveillance inspections in the last five years have not identified any non-conformance relative

to the acceptance criteria. No non-conformance notices (NCNs) or CERs were initiated for fire

doors relevant to aging.

The LRA states that monthly surveillance are conducted on the FP system consisting of flow

tests and pump start tests. Flow tests and flushes of the main distribution loops have been

conducted to ensure their functionality and have all met acceptance criteria. Working pressure

and flow pressure are measured during these tests. This will indicate fouling to an

unacceptable level and hence manage this aging effect. Fire hydrants and sprinklers are

visually inspected for aging effects. This visual inspection looks for painted, corroded,

damaged, or dirty sprinkler heads, obstruction of sprinkler heads, and proper orientation of

sprinkler heads. The fire hydrants are inspected for corrosion on the exterior surfaces that

might impede operation and standing water in the hydrant barrel that might indicate valve

leakage or fouling. 
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A NCN was generated in January of 1994 in association with low flow during flow testing of the

main distribution loop. As part of the resolution the piping was hydrolazed to remove the

accumulated deposits. Additionally, engineering evaluation determined that a reduction and 

redistribution of sprinkler heads was permissible and would restore the required pressure at the

sprinkler heads to ensure full spray pattern. The results of flow testing of the FP piping since

this occurrence have been found acceptable. 

On the basis of the information discussed above, the applicant concluded that the FPP has

been demonstrated to be effectively detecting and managing aging effects for the fire water

system, the fire barriers and fire barriers penetrations seals, and for fire doors. The FPP

provides reasonable assurance that the aging effects will be managed such that the

components subject to an AMR will continue to perform their intended functions consistent with

the CLB for the period of extended operation.

3.0.3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3.1 and Section B.1.5 of Appendix B to the LRA and LRA

Table 3.3-1, Item 19 to determine whether the applicant had demonstrated that the effects of

aging for the FP system will be adequately managed during the period of extended operation,

as required by 10 CFR 54.21(a)(3). The staff’s review was conducted in accordance with

Section 3.3 of the SRP-LR (NUREG-1800) and is described below.

In Section B.1.5 of Appendix B to the LRA, the applicant describes its AMP to manage the

aging of structures and components in the FP system. The LRA states that this AMP is

consistent with NUREG-1801 programs in Chapters XI.M26, Fire Protection,” and XI.M27,

Fire Water System.”

The NUREG-1801 programs in Chapter XI.M26 include a fire barrier inspection program and a

diesel-driven fire pump inspection program. The fire barrier inspection program requires

periodic visual inspection of fire barrier protection seals, fire barrier walls, ceilings, and floors,

and periodic visual inspection and functional tests of fire-rated doors to ensure that their

operability is maintained. The diesel-driven fire pump inspection program requires that the

pump be periodically tested to ensure that the fuel supply line can perform its intended function. 

The AMP also includes periodic inspection and testing of the halon/carbon dioxide fire

suppression system.

The NUREG-1801 programs in Chapter XI.M27 apply to water-based FP systems that consist

of sprinklers, nozzles, fittings, valves, hydrants, hose stations, stand pipes, water storage tanks,

and aboveground and underground piping and components that are tested in accordance with

the applicable codes and standards of the National Fire Protection Association (NFPA). Such

testing assures the minimum functionality of the systems. Also, these systems are normally

maintained at the required operating pressure and are monitored such that loss of system

pressure is immediately detected and corrective actions will be initiated. In addition to the

NFPA codes and standards, those portions of the FP sprinkler system that do not currently

contain programs to manage aging and are not routinely subjected to flow are to be subjected

to full flow tests at the maximum design flow and pressure before the period of extended

operation (and at not more than 5-year intervals thereafter). In addition, a sample of the

sprinkler heads is to be inspected by using the guidance of NFPA 25, Standard for the

Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems.” Section
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2.3.3.1 of NFPA 25 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. Finally, portions of the FP

suppression piping located above ground and exposed to water are disassembled and visually

inspected internally once every refueling outage. The purpose of full-flow testing and internal

visual inspections is to ensure that corrosion, microbiologically induced corrosion (MIC), or

biofouling aging effects are managed such that the system function is maintained.

LRA Section 3 identifies those components for which the FPP is identified as an AMP. The

staff reviewed and verified that the components in LRA Section 3 to which the program applies

are consistent with the intent of NUREG-1801 programs as described in Chapters X1.M.26 and

X1.M.27. The staff finds this acceptable. 

The staff also reviewed the enhancements to the applicant’s AMP that are identified in the LRA

and requested the applicant to provide additional information to address the staff’s concerns. In

a letter dated March 28, 2003, in RAI B.1.5-1 (1), the staff asked the applicant to confirm that

the guidance which will be added to the diesel fuel pump maintenance procedure will ensure

that the diesel-driven fire pump is under observation for detecting any degradation of the fuel

supply line during the performance tests (e.g., flow and discharge tests, sequential starting

capability tests, and controller function tests). In its June 12, 2003, response, the applicant

stated that, in present monthly surveillance test procedure for the diesel fire pump, a visual

inspection of any leaks or abnormalities of the pump is required and any degradation to the

diesel fire pump fuel oil line would be detected and documented during this pre-starting visual

inspection. The staff finds the applicant’s response acceptable, because it is consistent with

the GALL report. GALL requires the performance test to be at least once every refueling

outage.

In a letter dated March 28, 2003, in RAI B.2.5-1 (2), the staff asked the applicant to confirm that

(1) the guidance which will be added to the CO2 fire suppression system and the fire damper

inspection procedures will include periodic visual inspection to examine signs of degradation,

(2) the material conditions that may affect the performance of the system, such as corrosion,

mechanical damage, or damaged dampers, will be observed during inspection, and (3) the

inspection will be performed at least once every month to verify that the extinguishing agent

supply valves are open, and the system is in an automatic mode. 

By letter dated June 12, 2003, the applicant provided the following response:

The present surveillance test procedures for fire dampers require visual inspections of fire dampers that

specifically look for changes in appearance or abnormal degradations. These surveillance test procedures are

performed every 18 months. No aging effects have been identified for the internal surfaces for CO2 suppression

system components. Aging of the external surfaces for the components will be managed by the Inspections

for Mechanical Components program. At the plant, the CO2 fire suppression system valve lineup is required

by the FP program to be performed every 92 days. The interval for the carbon dioxide fire suppression system

valve lineup was changed from monthly to quarterly under the provisions of 10CFR50.59. 

The applicant takes exception to the GALL with regard to the inspection frequency of fire

dampers and testing for CO2 fire suppression system. GALL specifies semi-annual inspection,

whereas, the plant performs testing every eighteen months under the CLB. The applicant

clarified its position that no aging effects have been identified for internal surfaces for CO2
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suppression components. Aging of external surfaces for the components will be managed by

the inspection for mechanical components. Based on the operating experience provided by the

applicant and explanation of managing aging effects on fire dampers and CO2 fire suppression

system, the staff finds this extended inspection duration acceptable.

In a letter dated March 28, 2003, in RAI B.1.5-1 (3), the staff asked the applicant to confirm that

(1) the specific guidance which will be added related to the fire door inspections will ensure the

hollow metal fire doors to be visually inspected at least once bi-monthly for holes in the skin of

the door, (2) fire door clearances are also checked at least once bi-monthly as part of an

inspection program, and (3) the function tests of the fire doors are performed daily, weekly, or

monthly (which may be plant-specific) to verify the operability of automatic hold-open, release,

closing mechanisms, and latches. 

By letter dated June 12, 2003, the applicant provided the following response:

Current plant surveillance test procedures are performed on fire doors on a minimum frequency of six months.

These procedures require visual inspections of the following: (a) automatic closing mechanisms – to verify no

oil leaks, hardware fasteners are secure, and adjusting rods are in place and secure; and (b) door integrity –

to verify latches are securely in place, free movement of bolts, bolt engages door strike, knobs and surface

hardware are firmly attached, door closes and latches on its own power, no holes or breaks in the door skin,

and no broken, damaged or cracked door glass.

As noted in LRA Section B.1.5, the plant’s fire rated doors are inspected (as specified above) at a frequency

of every 6 months under the current licensing basis rather than the bi-monthly frequency recommended in

NUREG-1801, Section XI.M26. Based on the plant and industry operating experiences, the 6 month inspection

frequency provides reasonable assurance that degradation of a door is detected prior to loss of function.

The applicant takes exception to GALL with regard to the frequency of the aging inspection of

the fire doors. GALL specifies bi-monthly inspections, whereas the plant performs inspections

semi-annually under the CLB. The applicant states that surveillance inspections in the last five

years did not identify any non-conformance relative to the acceptance criteria and no NCNs and

CERs were initiated for fire doors relevant to aging. Furthermore, LRA Section B.1.5 states that

the fire doors inspections detect structural damage or degradation and inspection are credited

with managing loss of material of door and door hardware for the period of extended operation. 

The applicant further stated that the excessive wear for doors appurtenances such as latches,

strike plates, hinges, sill and closing devices, and maintaining proper clearances (gaps)

between the door, frame and threshold are also inspected, but these attributes are not credited

for license renewal. Based on the operating experience provided by the applicant and the

explanation of managing aging effects of fire doors, the staff finds this extended inspection

duration acceptable.

 

The staff has proposed a revision to NUREG-1801 program in Chapter XI.M27 related to

inspections for wall thinning of piping due to corrosion. The revised staff position states that

each time the system is opened, oxygen is introduced into the system, thus accelerating the

potential for general corrosion. Therefore, the staff has recommended that a non-intrusive

means of measuring wall thickness, such as ultrasonic inspection, be used to detect this aging

effect. The staff recommends that, in addition to a baseline ultrasonic inspection of the fire

protection piping that is performed before exceeding the current licensing term, the applicant

perform ultrasonic inspections at 10-year intervals thereafter. In a letter dated March 28, 2003,

in RAI B.1.5-1(4), the staff asked the applicant whether the inspection criteria for the FP SSCs
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conforms with the staff position in interim staff guidance (ISG)-04 (ADAMS Accession

ML022260137, dated December 12, 2002). 

By letter dated June 12, 2003, the applicant provided the following response:

Section B.1.5 of the LRA lists the wall thickness evaluations as an enhancement to the FP program. The plant

will perform the wall-thickness evaluations of above ground fire protection piping prior to the end of the current

operating term (i.e., August 6, 2022). Subsequent evaluations will occur at 10-year intervals thereafter. At the

plant, the internal surfaces of underground piping for fire service is cement lined. No aging effects have been

identified for the internal surfaces of cement lined piping in a raw water environment.

Section B.1.5 of the LRA lists the sprinkler testing/replacement as an enhancement to the FP program.

Testing/replacement will be performed in accordance with NFPA Code 25, which states that this should be done

prior to year 50 of sprinkler system life, with subsequent testing performed at 10-year intervals. To ensure

testing is performed prior to year 50 of sprinkler system life, the plant will perform this testing prior to the end

of the current operating term (August 6, 2022).

The staff has reviewed the above discussion to determine whether the AMP is adequate to

manage the aging effects for which it is credited. The staff finds that this AMP conforms with

the staff position in ISG-04 and, therefore, applicant’s response to RAI B.1.5-1(4), is

acceptable.

By the letter dated March 28, 2003, in RAI B.1.5-2, the staff informed the applicant about its

concern that the applicant’s FPP may not adequately manage aging of coatings in steel

structures, since neither XI.M26 nor XI.M27 address coatings. On this basis, the staff asked

the applicant to identify any steel structures within the scope of license renewal and subject to

an AMR which depend on coatings to protect the steel structures from age-related degradation,

and describe the AMP and activities that manage the aging effects for the coatings. 

In its June 12, 2003, letter, the applicant provided the following response:

The plant’s Fire Protection Program (as described in Application Section B.1.5) is focused primarily on the fire

protection system components, fire barriers and seals, and fire doors (consistent with GALL Sections XI.M26

and XI.M27). Steel structures (including structural steel components) within the scope of license renewal are

identified by building in LRA Section 2.4 and TR00170-003. Additionally, all structural steel has a protective

coating which provides protection against age-related degradation. As noted in LRA Table 3.5-1 (in Item 16),

aging of steel components is managed by the Maintenance Rule Structures Program as described in LRA

Section B.1.18. This program inspects structural steel for integrity via visual inspections of coatings for

degradation, such as peeling, flaking, blistering, rusting , scaling, etc. For containment steel structures (liner),

the AMPs described in LRA Sections B.1.11, B.1.15 and B.1.16 also apply.

The staff finds the applicant’s response acceptable because it addressed the concern.

3.0.3.3.3 Conclusion

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement
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for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.4 Maintenance Rule Structures Program

The applicant described its Maintenance Rule Structures Program in Section B.1.18 of

Appendix B to the LRA. The applicant credits this program with the capability of detecting and

managing the effects of aging for structures and structural components at VCSNS. The staff

reviewed the LRA to determine whether the applicant has demonstrated that the Maintenance

Rule Structures Program will adequately manage the applicable aging effects for the

components that credit this program throughout the period of extended operation, as required

by 10 CFR 54.21(a)(3).

3.0.3.4.1 Summary of Technical Information in the Application

In LRA Section B.1.18, the applicant states that the Maintenance Rule Structures Program is

consistent with XI.S6, Structures Monitoring Program, as identified in NUREG-1801. The

applicant further states that the following enhancements will be incorporated into the

Maintenance Rule Structures Program prior to the period of extended operation:

Future inspections will add:

• north berm

• electrical manhole EMH-2 interior inspection

• inaccessible areas when exposed by excavation

• flood barrier seals for control and diesel generator buildings

• portions of the power path from the power circuit breaker (PCB) in the substation to the

safety related buses

• groundwater chemical analyses

Groundwater chemical analyses will include: 

• ph

• Sulfates

• Chlorides

Groundwater chemical analyses will be used to monitor changes in aggressiveness of the

below grade environment.

The Maintenance Rule Structures Program is included in the discussion column of LRA Table

3.5-1. The structures and structural components that credit this program for license renewal

are identified in Report TR00170-003, Rev 0, Attachment II. 

In 1996, a baseline assessment concluded that the maintenance rule structures and structural

components were acceptable and were free of deficiencies or degradation that could lead to

possible failure. Therefore, these structures were determined to be capable of performing their

structural functions, including the protection and support of systems and components.
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The maintenance rule inspection report completed in 2000 noted that most of the maintenance

rule structures and structural components were evaluated to be “Acceptable” with regards to

continued function. However, nine items/areas were identified as “Acceptable with

Deficiencies” that exhibited a trend of aging. These conditions mostly deal with rust/corrosion

due to weathering, water in-leakage and ponding. The applicant determined that none of the

conditions have an immediate adverse effect on the ability of the structures or components to

perform their intended function(s). These items were entered into the plant corrective action

program for resolution. The next inspection is scheduled in 2005.

The applicant states that the Maintenance Rule Structures Program provides reasonable

assurance that the aging effects for structures and structural components will be managed such

that the components subject to aging management review will continue to perform their

intended functions consistent with the current licensing basis for the period of extended

operation.

3.0.3.4.2 Staff Evaluation

In LRA Section B.1.18, “Maintenance Rule Structures Program,” the applicant described its

AMP to manage aging in structures and structural components. The LRA stated that this AMP

is consistent with GALL AMP XI.S6, “Structures Monitoring Program,” with several

enhancements described in SER Section 3.0.3.4.1. The staff reviewed the enhancements to

determine whether the AMP, with the enhancements, remains adequate to manage the aging

effects for which it is credited, and reviewed the FSAR supplement to determine whether it

provides an adequate description of the revised program. The staff audit on July, 16-17, 2003

confirmed the applicant’s claim of consistency.

The staff noted several inconsistencies between the FSAR Supplement summary descriptions

of the aging management programs in LRA Appendix A and the scope of the aging

management programs identified in LRA Appendix B as “consistent with GALL.” In RAI 3.5-19,

the staff requested the applicant to verify that the complete scope of the aging management

program, as described in NUREG-1801, GALL Volume 2, is being credited for license renewal

aging management. If this is not the case, the applicant was requested to identify and

document the justification for each exception. In response to RAI 3.5-19, the applicant stated

the following:

As stated in the LRA, VCSNS maintains a Maintenance Rule Structures Program (B.1.18), which is consistent

with GALL XI.S6 and 10 CFR 50.65. Several enhancements to this program have been identified during the

license renewal evaluation process and are listed in the Application (B.1.18).

VCSNS does not believe that there are any further changes required for the Application Appendix A, since only

summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory Guides

are implicit in the development of each of these programs as described in Section 7 of TR00170-003.

LRA Section B.1.18 states that the Maintenance Rule Structures Program is consistent with

GALL XI.S6 with several listed enhancements that will be incorporated into the program prior to

the period of extended operation. In RAI 3.5-23, the staff requested that the applicant provide

the following information regarding this program:
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(a) Verify that the scope of this program includes visual inspection of concrete for aging effects

of loss of material, cracking and change in material properties and explain what this program

requires for VCSNS concrete structures.

(b) Since the North Berm, an earthen embankment, will be incorporated into the scope of this

program, clarify that this program is also completely consistent with all the attributes of GALL

XI.S7 and RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants.

(c) Since this program is credited for managing aging effects of masonry walls, clarify that this

program is also completely consistent with all the attributes of GALL XI.S5, Masonry Wall

Program.

(d) Clarify the apparent editorial mistake in the last sentence of the second paragraph of LRA

Section B.1.18.1 that states: “...including the protection and support of 0 systems and

components.”

(e) The commitment to incorporate the enhancements to this program discussed in LRA

Section B.1.18 should also be included in the FSAR Supplement, Appendix A, Section 18.2.22.

This section does not currently include such a commitment. 

In response to RAI 3.5-23, the applicant stated the following:

The Maintenance Rule Structures Program (B.1.18) includes visual inspection of concrete for all aging effects

including loss of material, cracking, and change in material properties. This program requires walkdowns of

all Important to Maintenance Rule Structures at VCSNS. Walkdowns are conducted by qualified engineering

(structural) personnel. Plant procedures and guidelines (as described in Section 7.12 of TR00170-003) define

inspection details and criteria for identifying aging mechanisms and effects. 

(a) Inspection of the North Berm will be performed under plant engineering services procedures, consistent with

the inspections required under the Service Water Pond Dam Inspection Program (RG 1.127), which is

consistent with the attributes of GALL XI.S7.

(b) By plant design, there are no masonry walls located within safety related structures; therefore, VCSNS had

no actions associated with IEB 80-11 and IN 87-67. However, masonry walls in non-safety related structures

are inspected under the Maintenance Rule Structures Program, consistent with the attributes of GALL XI.S5.

[Also see response to RAI 2.4.1-4.]

(c) The sentence in Application Section B.1.18.1 should read: “...including the protection and support of safetyrelated systems and components.”

(d) Consistent with NEI 95-10, VCSNS does not see the need to include these minor enhancements into the

very generic summary description of the Maintenance Rule Structures Program (Application Appendix A Section

18.2.22).

The staff finds the applicant’s responses to RAI 3.5-23 Parts (a) thru (c) to be acceptable since

they confirm the consistency of the program with the GALL Report. 

3.0.3.4.3 Conclusion

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the
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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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.5 Above Ground Tank Inspection Program

The Above Ground Tank Inspection Program is a new one-time inspection program described

in Section B.2.1 of Appendix B in the LRA. The LRA credits the Above Ground Tank Inspection

Program with detecting and characterizing loss of material due to galvanic and general

corrosion in an internal air space environment, and loss of material and cracking due to the

corrosive effects of alternate wetting and drying in treated or borated water environments. The

staff reviewed the LRA to determine whether the applicant has demonstrated that the inspection

will adequately verify the effectiveness of an aging management program and confirm the

absence of an aging effect prior to the period of extended operation as required by 10 CFR

54.21 (a) (3).

3.0.3.5.1 Summary of Technical Information in the Application

The applicant’s Above Ground Tank Inspection Program is discussed in LRA Section B.2.1,

“Above Ground Tank Inspection Program.” The applicant states that this program is a new

one-time inspection activity that will be consistent with GALL AMP XI.M32, “One-Time

Inspection,” and will be performed prior to the period of extended operation. This inspection will

determine if aging management is required for the internal surfaces of certain tanks and

associated components (including pipe and valves) during the period of extended operation, as

described in the FSAR supplement (Section 18.2.3 of Appendix A to the LRA). In addition, the

applicant states that implementation of the Above Ground Tank Inspection Program will either

verify that there are no aging effects requiring management for the subject components or

appropriate corrective actions will be taken so that the component intended functions will be

ensured for the period of extended operations. 

The LRA states that this program will detect and characterize loss of material due to galvanic

and general corrosion in locations with exposure to moist air conditions, loss of material due to

general corrosion in locations with exposure to treated water in which dissolved oxygen levels

are not controlled, and loss of material and/or cracking due to the corrosive effects of alternate

wetting and drying of treated or borated water. The Above Ground Tank Inspection will use

suitable examination techniques at the most susceptible (sample) locations.

The internal surfaces of the following components will be inspected by this one-time inspection:

• carbon steel tanks exposed to an internal air space environment in the condensate,

component cooling, and chilled water systems;

• carbon steel pipe and valves exposed to an internal air space environment in the

component cooling system;
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• carbon steel and stainless steel tanks exposed to a treated water environment in the 

condensate, component cooling, reactor makeup water supply and chilled water

systems;

• carbon steel tanks, pipe and valves exposed to treated water having uncontrolled

oxygen levels in the sodium hydroxide storage tank in the reactor building spray system;

and

• stainless steel tanks exposed to a borated water environment in the refueling water

system (refueling water storage tank).

3.0.3.5.2 Staff Evaluation

In LRA Section B.2.1, “Above Ground Tanks Inspection Program,” the applicant described its

AMP to manage the internal surfaces of certain tanks and associated components (including

pipe and valves). The LRA stated that this AMP is a new one-time inspection activity that will

be consistent with GALL AMP XI.M32, “One-Time Inspection,” and will be performed prior to the

period of extended operation. 

The staff reviewed this program using the guidance in Branch Technical Position RLSB-1 in

Appendix A of the SRP-LR and focused on how the program manages aging effects through

the effective incorporation of 10 elements (i.e., program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience.) 

The applicant indicated that the corrective actions, confirmation process, and administrative

controls are part of the site-controlled Quality Assurance Program. The staff’s evaluation of the

Quality Assurance Program is provided separately in Section 3.0.4 of this SER. The remaining

seven elements are discussed below. 

[Program Scope] The staff finds that the systems and components to be monitored by the

program, as listed in the LRA, are within the scope of license renewal as identified in Section

2.3 of the LRA. In addition, the scope of the program is acceptable, since it includes the

appropriate components within the scope of license renewal to be inspected for susceptibility to

loss of material due to galvanic and general corrosion and/or cracking.

[Preventive Actions] There will be no preventive or mitigative actions taken as part of this

program, and the staff did not identify the need for such actions. The staff notes that the onetime inspection is an inspection activity independent of methods to mitigate or prevent

degradation.

[Parameters Monitored or Inspected] The program will examine the metal tanks and associated

piping components in the condensate, component cooling, and chilled water systems;

component cooling system; reactor building spray system; and refueling water system for wall

thickness and visible evidence of corrosion, cracking or other age-related degradation. The

staff finds these parameters acceptable because they are directly related to the degradation of

metal tanks and associated piping components in the aforementioned systems.

[Detection of Aging Effects] The aging effects that will be detected and characterized by this

program are identified by proven visual and/or volumetric inspection techniques on a sampling
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of the subject components to be determined by engineering evaluation. The applicant stated

that the results of the inspection will be applied to the remainder of the components within the

scope of the inspection activity. In addition, for components exposed to borated and treated

water environments, the sample population should include locations near the air-water interface

within the stainless steel refueling water storage tank (RWST), and near the air-water interface

within one of the following carbon steel tanks: the condensate storage tank, the component

cooling surge tank, or one of the chilled water expansion tanks. An engineering evaluation is

expected to confirm that the borated water environment of the RWST is more likely to

concentrate contaminants at the air-water interface than the treated water environment of the

reactor makeup water supply tank. For components exposed to treated water with uncontrolled

oxygen levels, the sample population should include the submerged portions of the sodium

hydroxide tank and that for components exposed to an internal air space environment, the

sample population should include locations within the air space of one of the following carbon

steel tanks: the condensate storage tank, the component cooling surge tank, or one of the

chilled water expansion tanks. If possible, to simplify the inspection, the same tank chosen to

inspect for corrosive impacts of alternate wetting and drying should be selected for this

inspection. 

The staff finds that these inspection techniques are sufficient to provide reasonable assurance

that the aging effects for the components addressed by the Above Ground Tank Inspection will

be detected and evaluated before there is a component loss of intended function. Based on the

plant specific and industry operating experience, the use of one-time inspection is appropriate

for inspections where degradation is possible, but is not expected. This one-time inspection

provides for additional inspections should the corrective action process require additional

information to characterize the aging effects.

[Monitoring and Trending] The LRA states that no actions will be taken as a part of the Above

Ground Tank Inspection to trend inspection results. This is a one-time program used to

determine if further actions are required. The staff notes that the evaluation of the techniques

and the timing of the one-time inspection improve as plant-specific and industry-wide

experience increases. By letter dated March 28, 2002, the staff requested, in RAI B.2.1-1, that

the applicant address any changes made in the monitoring and trending of components

exposed to borated water as a result of the boric acid-induced corrosion of the Davis-Besse

vessel. In its response dated June 12, 2003, the applicant stated that both site-specific and

industry-wide operating experience was researched and is contained within the body of

technical work at VCSNS supporting the LRA. The applicant further stated that, since the aim

of the one-time inspection is to determine if further actions are required, there will be no action

to trend the inspection results. In addition, this one-time inspection is being developed because

it was determined that the aging effects were possible and not because these aging effects

were found at VCSNS. The staff finds the applicant response satisfactory since the applicant

has taken into account site-specific and industry-wide operating experience. In addition, this

inspection program will determine the extent to which the degradation is applicable at VCSNS. 

The staff notes that should the inspection results indicate that further inspections are needed,

the program’s corrective actions will be employed. Therefore, RAI B.2.1-1 is considered closed.

[Acceptance Criteria] The LRA states that the acceptance criteria for this program will be no

unacceptable loss of material or cracking of subject components that could result in a loss of

the component intended function(s) as determined by engineering evaluation. The staff

considers this engineering evaluation to be adequate to ensure that the component intended
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function(s) are maintained under all CLB design conditions during the period of extended

operation.

[Operating Experience] The LRA states that the Above Ground Tank Inspection is a new onetime inspection for which no operating experience exists. The staff finds that the inspection

proposed by the applicant will either verify that there are no aging effects requiring

management for the subject structures and components, or identify where appropriate

corrective actions need to be taken during the period of extended operation. 

The staff notes that the GALL AMP XI.M29, “Above Ground Carbon Steel Tanks,” defines

preventive measures to mitigate corrosion by protecting the external surface of carbon steel

tanks with paint or coatings in accordance with standard industry practice. This GALL AMP is

not credited for aging management in the VCSNS LRA. The staff also notes that Section

B.1.15, “Containment Coating Monitoring and Maintenance Program,” of the LRA, discusses an

existing AMP that manages the loss of material due to coating degradation. However, this AMP

is not credited with managing the external surfaces of the tanks. By letter dated March 28,

2003, the staff requested, in RAI B.2.1-2, the applicant to explain how the Above Ground Tank

Inspection Program adequately manages the external surface of the above ground tanks if this

program only inspects the internal surfaces of the tanks. 

In its response dated June 12, 2003, the applicant stated that the Above Ground Tank

Inspection is not the same as the GALL AMP XI.M29, “Above Ground Carbon Steel Tanks.” In

addition, tank foundations and supports are inspected under the Maintenance Rule Structures

Program (Section B.1.18 of Appendix B to the LRA). Outside above ground steel tanks

(condensate storage tank, refueling water storage tank, reactor make-up water storage tank,

and sodium hydroxide storage tank) are externally inspected under the Maintenance Rule

Structures Program and include visual inspections of the exterior surface of the tank, anchor

bolts and attachment anchorage plates/welds, concrete foundation support pads, piping

connections, and caulking between tank /foundation. Based on the applicant’s response and

the staff evaluation of the Maintenance Rule Structures Program in Section 3.0.3.4 of this SER,

the staff finds that the external surfaces of the tanks will be adequately managed for external

degradation. Therefore, RAI B.2.1-2 is considered closed. 

The LRA states that the Above Ground Tank Inspection Program will be consistent with the

GALL AMP XI.M32, “One-Time Inspection.” The staff compared this program with the one-time

inspection program defined in GALL report. As a result, by letter dated March 28, 2003, the

staff requested, in RAI B.2.1-3, the applicant to discuss the qualifications of the personnel

conducting the inspection and the design minimum wall thickness and criteria for verifying the

absence of cracking.

In its response dated June 12, 2003, the applicant stated that inspections required by this

program would be performed by personnel qualified in accordance with the ASME Boiler and

Pressure Vessel Code and 10 CFR 50 Appendix B. In accordance with the ASME code, the

minimum wall thickness will be determined by the design of the individual component and the

cracking will be detected by volumetric and visual inspections. The staff finds the applicant’s

response satisfactory because qualified personnel will perform the appropriate inspection

techniques in accordance with the ASME code and 10 CFR 50 Appendix B. Therefore, RAI

B.2.1-3 is considered closed. 
3-28

In summary, based on this review, the staff concluded that the Above Ground Tank Inspection

is consistent with the requirements of the 10 elements of Branch Technical Position RLSB-1 in

Appendix A of the SRP-LR. The staff confirmed the applicant’s claim of consistency during the

AMR Audit on July 16 - 17, 2003. The staff verified that this program, as described, is

consistent with GALL AMP XI.M32.

Section 18.2.3 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Above Ground Tank Inspection at VCSNS. The staff reviewed the FSAR supplement and finds

that the description of the Above Ground Tank Inspection is consistent with Section B.2.1 of the

LRA. Therefore, the staff finds that the information provided in the FSAR supplement provides

an adequate summary of the program activities as required by 10 CFR 54.21(d).

3.0.3.5.3 Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.6 Buried Piping and Tanks Inspection Program

The Buried Piping and Tanks Inspection Program is described in Section B.2.10 of Appendix B

in the LRA. The LRA credits this AMP with managing loss of material on the external surfaces

of buried carbon steel, cast iron, and ductile iron components exposed to an underground

environment in the diesel generator services, emergency feedwater, fire service, and service

water systems at the VCSNS. The staff reviewed the LRA to determine whether the applicant

has demonstrated that the Buried Piping and Tanks Inspection Program will adequately

manage the applicable aging effect (loss of material) for the components that credit this

program during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.0.3.6.1 Summary of Technical Information in the Application

The applicant’s Buried Piping and Tanks Inspection Program is described in LRA Section

B.2.10, “Buried Piping and Tanks Inspection Program.” The applicant states that this is a new

inspection activity and therefore summarizes the program in terms of the 10 element program

as described in Branch Technical Position RLSB-1 in Appendix A-1 of the SRP-LR. In addition,

this program will be consistent with GALL AMP XI.M34, “Buried Piping and Tanks Inspection,”

and will be performed prior to the period of extended operation. 

The LRA credits this inspection activity to manage loss of material due to crevice, galvanic,

general, pitting, and microbiologically influenced corrosion (MIC) on the external surfaces of

components exposed to an underground environment. In addition, the program will have

elements of a condition-monitoring program and a prevention program. The conditions of

coatings and wrappings will be determined by visual inspection whenever buried components

are excavated, such as for maintenance. Degraded coatings or wrappings are indicative of
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potential surface corrosion of the external piping or tank surfaces and will require further

evaluation as discussed in the FSAR supplement (Section 18.2.9 of Appendix A to the LRA). 

Within the auxiliary system, the following major components and systems will be monitored by

this aging management program: carbon steel (CS) pipes and couplings in the service water

system; ductile iron pipe and cast iron hydrants and valve bodies the in fire service system; CS

pipes in the emergency feedwater system; and CS fuel oil pipes, fittings, and tanks in the diesel

generator service systems. 

3.0.3.6.2 Staff Evaluation

In LRA Section B.2.10, “Buried Piping and Tanks Inspection Program,” the applicant described

its AMP to manage the loss of material of buried components. The staff’s evaluation of the

Buried Piping and Tanks Inspection focuses on how the program detects and characterizes

aging effects through the effective incorporation of the ten elements described in Branch

Technical Position RLSB-1 in Appendix A-1 of the SRP-LR. 

Since the applicant claimed consistency with GALL AMP XI.M34, this AMP was crossreferenced in the staff’s review. The 10 program elements in this GALL AMP define

programmatic characteristics and criteria to manage buried components except for the program

elements/attributes of detection of aging effects (regarding inspection frequency) and operating

experience. Thus, the staff further evaluates an applicant’s inspection frequency and operating

experience with buried components. The LRA indicates that the corrective actions and

confirmation process are implemented through the site corrective actions process, while the

administrative controls are implemented through the site procedures. The staff’s evaluation of

the corrective actions, confirmation process, and administrative controls is contained in Section

3.0.4, “Quality Assurance Program,” of this SER. The remaining elements are evaluated

below.

[Program Scope] The staff finds that the systems and components that will be monitored by

this program, as listed in the LRA, are within the scope of license renewal and identified in

Section 2.3 of the LRA. The staff finds that the scope of the program is acceptable since it

includes the buried components within the scope of license renewal exposed to an underground

environment.

[Preventive Actions] The applicant stated that underground components are coated and

wrapped during installation to prevent direct contact with the soil environment. Otherwise, no

actions will be taken as part of the buried piping and tanks inspection to prevent aging effects or

mitigate age-related degradation. By letter dated March 28, 2003, the staff requested, in RAI

B.2.10-1, the applicant to discuss the adequacy of coating techniques. In its response dated

June 12, 2003, the applicant stated that VCSNS coats and wraps underground components in

accordance with site procedures, available onsite for inspection. These procedures are based

on accepted industry standard American Water Works Association (AWWA) C-203, 1973. In

addition, operating experience for the diesel generator fuel oil storage tanks revealed negligible

wall thinning thereby verifying that the coating and wrapping techniques implemented are

effective. The staff subsequently requested the applicant to supply a copy of industry standard

AWWA C-203 or its equivalent for review and comparison with the industry standards

referenced in the GALL report. During the AMR audit conducted on July 16 - 17, 2003, the staff

received the mechanical maintenance procedure for applying coating on embedded piping. 
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Based on a review of this document, the staff finds this procedure meets the intent of

recommended practices of referenced in GALL AMP XI.M34 for surface preparation,

application, and inspection of coatings on embedded piping. Therefore, RAI B.2.10-1 is

considered closed.

[Parameters Monitored or Inspected] The applicant stated that the condition of coatings and

wrappings will be determined by visual inspection whenever buried components are excavated

for maintenance or for other reasons. The applicant later cited operating experience with

buried piping and tanks, which used the ultrasonic inspection technique (UT). By letter dated

March 28, 2003, the staff requested, in RAI B.2.10-2, the applicant to discuss if UT will

supplement or replace visual inspection, and the criteria used to determine the applicability of

the technique used. In its response dated June 12, 2003, the applicant stated that a visual

inspection of the wrapping and coating will be performed and evaluated upon initial excavation

of the component. If the wrapping or coating is damaged or removed as part of the

maintenance activity, then the underlying metal will be visually inspected for degradation. 

Depending on the condition of the underlying metal, subsequent inspections and the types of

inspections will be determined through the VCSNS Corrective Action Program. Based on the

applicant’s response, the staff finds that this program will appropriately monitor the parameters

directly related to the integrity of the external surface of buried carbon steel piping and tanks. 

Thus, RAI B.2.10-2 is considered closed.

[Detection of Aging Effects] The applicant claimed that the rate of wall thinning for components

within this program is very slow (or negligible). In addition, since the process of excavation

itself can damage protective coatings and wrappings, a specific inspection frequency for buried

components is not warranted. Instead, if buried components are excavated for maintenance or

for other reasons, the integrity of the coatings and wrappings will be evaluated. If the coatings

or wrappings are damaged or removed as part of the maintenance activity, the underlying metal

will be visually inspected for degradation. By letter dated March 28, 2003, the staff requested,

in RAI B.2.10-3, the applicant to discuss why periodic inspection of the most susceptible

locations is not needed especially in areas with the highest likelihood of corrosion and/or a

history of corrosion problems. In its responses dated June 12, 2003, the applicant stated that

GALL AMP XI.M34 allows the inspection frequency to be whenever underground piping is

excavated for maintenance depending on operating experience. In addition, VCSNS operating

experience has shown no history of corrosion problems for buried piping and tanks, as

evidenced by the negligible wall thinning of the diesel fuel oil storage tanks. Therefore, based

on this operating experience, the applicant concluded that an inspection frequency based upon

scheduled maintenance is justified. The staff finds that the applicant has not adequately

demonstrated that periodic inspection, at the most susceptible locations, is unnecessary. In

addition, the staff notes that the GALL Report states that the inspection frequency is plant

specific and depends on the plant operating experience. Therefore, the staff requested a

summary of the most recent excavations, including information about any age-related

degradation of systems and components within the scope of this program. In subsequent

correspondence dated September 2, 2003, the applicant stated that modification on the Fire

Service System piping in 1997 and 1998 required excavation and revealed no external

degradation. Based on this most recent operating history and the negligible wall thinning of the

diesel fuel oil storage tanks, the staff finds the inspection of buried components during

maintenance activities is acceptable. Therefore RAI B.2.10-3 is considered closed. 
3-31

[Monitoring and Trending] The applicant stated that no actions will be taken as a part of the

buried piping and tanks inspection to trend inspection results. The applicant further stated that

the results of an inspection may indicate the need for additional inspections to be performed. 

This need will be dispositioned through the applicant’s Corrective Action program. The staff

finds that applicant’s plan to use the results of previous inspections is a satisfactory approach to

identifying susceptible locations. 

[Acceptance Criteria] The applicant stated that the acceptance criteria for this program will be

“no unacceptable degradation of coatings and wrappings that could result in loss of material

and therefore a loss of component intended function, as determined by engineering evaluation.”

By letter dated March 28, 2003, the staff requested, in RAI B.2.10-4, the applicant to discuss

how the coating and wrapping degradation will be reported and evaluated (e.g., by site

corrective actions or other procedures). In its response dated June 12, 2003, the applicant

stated that any coating and wrapping degradation would be reported and evaluated according

to the VCSNS Corrective Action Program. The staff finds this response acceptable because

the degraded conditions will be reported and evaluated through the Corrective Action Program. 

In addition, the staff finds the applicant’s response consistent with the guidance in the GALL

report and therefore, RAI B.2.10-4 is considered closed.

[Operating Experience] The applicant stated that the Buried Piping and Tanks Inspection is a

new inspection activity. In addition, an inspection of the fuel oil storage tanks and associated

piping was performed as a result of the inadequacy of the cathodic protection system for these

components. By letter dated March 28, 2003, the staff requested, in RAI B.2.10-5, the

applicant to discuss the operating experience and inspection of the other storage tanks and

piping within the scope of this system. In its response dated June 12, 2003, the applicant

stated that the only buried tanks in scope for license renewal are the diesel fuel oil storage

tanks. In addition, the VCSNS operating experience has shown no history of corrosion

problems for buried piping. The staff finds the applicant’s response acceptable since there is

no adverse operating history of the components within the scope of this program. In addition,

the staff finds the applicant’s response consistent with the guidance in the GALL report and

therefore, RAI B.2.10-5 is considered closed.

In summary, based on this review, the staff concluded that the buried Piping and Tanks

Inspection program is consistent with the requirements of the 10 elements of Branch Technical

Position RLSB-1 in Appendix A of the SRP-LR. The staff confirmed the applicant’s claim of

consistency during the AMR Audit on July 16 - 17, 2003. The staff verified that this program, as

described, is consistent with GALL AMP XI.M34.

Section 18.2.9 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Buried Piping and Tanks Inspection program at VCSNS. The staff reviewed the FSAR

supplement and finds that the description of the Buried Piping and Tanks Inspection is

consistent with Section B.2.10 of the LRA. In addition, the staff finds that the information

contained in the FSAR supplement presents an adequate summary of the program activities as

required by 10 CFR 54.21(d).

3.0.3.6.3 Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are
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consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.7 Inspections for Mechanical Components

The Inspections for Mechanical Components program is described in Section B.2.11 of

Appendix B in the LRA. The LRA credits this AMP with managing loss of material for the

external surfaces of mechanical components constructed of carbon steel, low alloy steel, and

other susceptible materials exposed to ambient conditions at VCSNS. The staff reviewed the

LRA to determine whether the applicant has demonstrated that the Inspections for Mechanical

Components program will adequately manage the applicable aging effect (loss of material) for

the components that credit this program during the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.0.3.7.1 Summary of Technical Information in the Application

The applicant’s Inspections for Mechanical Components Program is discussed in LRA Section

B.2.11, “Inspections for Mechanical Components.” This AMP is not based on a GALL Report

AMP. The LRA credits this new inspection program at VCSNS with managing loss of material

due to galvanic, general, and pitting corrosion and cracking due to radiation and thermal

embrittlement for the external surfaces of those mechanical components within the scope of

license renewal that are exposed to ambient conditions. The applicant stated that this program

is a condition monitoring program. The inspections for mechanical components manage loss of

material and cracking for mechanical components constructed of susceptible materials and

exposed to ambient conditions. The inspections involve a visual examination of the exposed

external surfaces of representative mechanical components. The inspections and associated

evaluations also address conditions in locations susceptible to external pitting corrosion due to

the presence of insulation materials and the potential for condensation to occur (FSAR

Supplement 18.2.20).

In Section B.2.11 of the LRA, the applicant concluded that the Inspections for Mechanical

Components program will provide reasonable assurance that the aging effects will be managed

such that the components subject to AMR will continue to perform their intended functions

consistent with the CLB during the period of extended operation.

3.0.3.7.2 Staff Evaluation

In LRA Section B.2.11, “Inspections for Mechanical Components,” the applicant described its

AMP to manage loss of material due to galvanic, general, and pitting corrosion and cracking

due to radiation and thermal embrittlement for the external surfaces of mechanical components. 

The LRA states that this is a new plant-specific AMP; it is not based on a GALL Report AMP. 

Therefore, the staff reviewed the program using the guidance in Branch Technical Position 

(BTP) RLSB-1 in Appendix A to the SRP-LR. The staff’s evaluation focused on managing 

aging effects through incorporation of the 10 elements described in BTP RLSB-1—program

scope, preventive actions, parameters monitored or inspected, detection of aging effects,
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monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience. The applicant indicated that the corrective

actions, confirmation process, and administrative controls for license renewal are in accordance

with the site-controlled Quality Assurance Program. The staff’s evaluation of the applicant’s

Quality Assurance Program is provided separately in Section 3.0.4 of this SER; the evaluation

of the remaining seven elements is provided below. The staff also reviewed the FSAR

Supplement to determine whether it provides an adequate description of the program.

[Program Scope] The applicant stated that Inspections for Mechanical Components program is

a new inspection activity that will manage loss of material due to galvanic, general, and pitting

corrosion and cracking due to radiation and thermal embrittlement. The applicant stated that

this AMP will manage the relevant aging effects for mechanical components constructed of

carbon steel, low-alloy steel, and other susceptible materials in the following mechanical

systems:

• air handling (HVAC)

• auxiliary boiler steam and feed-water

• auxiliary coolant (closed loop)/CRDM cooling 

water

• boron recycle

• building services

• chemical and volume control

• chilled water

• component cooling

• condensate

• demineralized water—nuclear service

• diesel generator services

• emergency feedwater

• extraction steam

• feedwater

• fire service

• gaseous waste processing

• gland sealing steam

• hydrogen removal

• instrument air supply

• liquid waste processing

• local ventilation and cooling

• main steam

• main steam dump

• nitrogen blanketing

• nuclear sampling

• radiation monitoring

• reactor building leak rate testing

• reactor building spray

• reactor coolant

• reactor makeup water supply

• residual heat removal

• safety injection

• service water

• spent fuel cooling

• station service air

• steam generator blowdown

• thermal regeneration

Applicant letter RC-02-0159 dated September 12, 2002 submitted a supplement to include

additional systems which meet 10 CFR 54.4(a)(2) criteria. The following systems that meet the

refined criteria are not included with the above list of applicable systems in the scope portion of

the program/activity evaluation documented in the LRA Appendix B.2.11. These system’

pertinent commodities will be addressed by this aging management activity:

• Condenser Air Removal

• Industrial Cooler

• Demineralized Water (non-nuclear services 

 portions)

• Fuel Handling, Oil

• Hydrogen-Nuclear Plant Use

• Leak Detection

• RB Leak Rate Testing

• Nuclear Blowdown Processing

• Nitrogen Blanketing

• Nitrogen-Nuclear Plant Use

• Oxygen-Nuclear Plant Use

• Roof Drains

• Turbine Cycle Sampling

• Sewer
3-34

• Non-Nuclear Plant Drains

By letter dated March 28, 2003, the staff stated, in RAI B.2.11-1, that the relevant aging effect

of loss of material is identified in Element 1, Program Scope, as being due to galvanic, general,

and pitting corrosion. The staff requested clarification since the AMR (LRA Table 3.3-1, Item 5)

credits the Inspections for Mechanical Components program with managing loss of material due

to MIC. In its response dated June 12, 2003, the applicant stated that the Maintenance Rule

Structures Program (AMP B.1.18) manages loss of material due to MIC. The applicant

elaborated that plant operating experience has identified the accumulation of microorganisms,

due to ground water intrusion effects, on the external surfaces of some piping components at

building wall penetrations. Since the VCSNS ground water elevation is approximately 420',

piping, process tubing, and ductwork component types were conservatively considered to be

susceptible to external MIC if they either enter a building from outside or pass between

buildings included in the sheltered environment below the 425' elevation. Therefore, loss of

material due to MIC has been identified as an aging effect requiring system-specific evaluation

for carbon and low-alloy steel in sheltered environments for piping, process tubing, or ductwork

that passes between pertinent buildings through a nonfire seal penetration or enters the

building from outside (i.e., underground, embedded) below the 425' elevation. The applicant

concluded that building penetrations are inspected as part of the Maintenance Rule Structures

Program (LRA B.1.18) and that the VCSNS Corrective Action Program would disposition any

ground water in-leakage and resulting degradation. 

The staff identified that the VCSNS Maintenance Rule Structures Program, AMP B.1.18, should

also address MIC on external surfaces of mechanical components, and that FSAR supplement

summary description in Section 18.2.22 be revised to include inspections of building

penetrations and associated piping for MIC. By letter dated September 24, 2003, the applicant

provided the revised FSAR summary description. Studies by the Electric Power Research

Institute (EPRI) conclude that any wetted areas should be considered susceptible to MIC. 

During a telecommunication with the applicant on July 14, 2003, the staff requested the

applicant to justify, including relevant operating experience, why other sources of water (such

as water from condensation or water associated with raw water or fuel oil systems) are not

considered sources for MIC and why only ground water-related MIC is addressed. The

applicant clarified that there are not adequate nutrients to support MIC on external surfaces

from sources other than from ground water intrusion. By letter dated September 2, 2003, the

applicant confirmed that the ambient environment does not contain nutrients necessary to

promote external MIC in other types of water, such as water from condensation. In this letter,

the applicant further stated that external MIC has not been found at locations other than at

building penetrations. The staff finds that the applicant’s response satisfactorily addresses the

staff’s concerns and RAI B.2.11-1 is considered closed.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need

for such actions because this is a condition monitoring program.

[Parameters Monitored or Inspected] The applicant stated that this AMP involves a visual

examination of the exposed external surfaces of mechanical components for loss of material or

cracking. By letter dated March 28, 2003, the staff requested, in RAI B.2.11-2, that the

applicant expand the description of the program to provide the technical basis for the selection

of the component external surfaces to be inspected. The staff asked if these visual
3-35

examinations are conducted on an opportunistic basis with external surfaces already exposed

and accessible to visual examination during normal operation, or if the examinations include

external surfaces at susceptible locations that are exposed to visual examination due to

targeted planned actions that may or may not involve suspension of normal operation. The

staff requested that the applicant provide the technical basis for determining which additional

component external surfaces are to be inspected if unacceptable degradation is observed. 

In its response dated June 12, 2003, the applicant stated that the Inspections for Mechanical

Components program will generally examine external surfaces already exposed and accessible

to visual examination during normal operation.

The applicant also stated that operating experience revealed an instance of external pitting

below the insulation on chilled water (VU) system piping. Consequently, loose insulation

removal is necessary to permit visual inspection of systems for which the internal fluid

temperature is less than the external ambient temperature. The applicant stated that any

unacceptable degradation, whether found by these inspections or by planned maintenance

activities, would be determined by engineering evaluation and dispositioned in the Corrective

Action Program. The applicant concluded that, although the initial frequency for the inspections

is 5 years, the Corrective Action Program could increase not only the frequency, but also the

scope of the inspections. 

The staff required a clarification as to the extent of component surfaces inspected. During a

telecommunication on July 14, 2003, the applicant identified that a walkdown is made of all

accessible components and any degradation is thoroughly addressed by the Corrective Action

Program. By letter dated September 2, 2003, the applicant clarified that the Inspections for

Mechanical Components program will inspect external surfaces exposed and accessible to

visual inspection during normal operation in addition to removal of insulation to permit visual

examinations for systems where the internal fluid temperature is less than the ambient

temperature and the insulation is not tightly adhered to the components. The staff finds that the

applicant’s response satisfactorily addresses the staff’s concerns and RAI B.2.11-2 is

considered closed.

[Detection of Aging Effects] The applicant stated that, in accordance with guidance in

Element 5, “Detection of Aging Effects” for AMPs, the AMP will detect loss of material and

cracking prior to loss of component intended function. The applicant further stated that pitting

is a concern in locations where components are insulated and internal system fluid

temperatures are below the ambient temperature conditions. The staff finds that these

inspection techniques are sufficient to provide reasonable assurance that the aging effects for

the components managed by the Inspections for Mechanical Components program will be

detected and evaluated before a component has lost its intended function. 

[Monitoring and Trending] The applicant stated that the inspections will be performed and

documented in accordance with station procedures and, following baseline inspection, the

frequency of inspections will be determined based on inspection results and industry

experience. By letter dated March 28, 2003, the staff requested, in RAI B.2.11-4, that the

applicant provide the schedule for the baseline inspection. In its response dated June 12,

2003, the applicant stated that inspections follow the same frequency as maintenance rule

structures inspections (5 years) and the baseline inspection would occur within 5 years of

obtaining the new license. Based upon the results of these inspections, or any new industry
3-36

experience, the frequency may increase. The applicant also confirmed that “effective

components,” as written in Element 7, “Monitoring and Trending” for AMPs, should be corrected

to “affected components.” The staff finds that the applicant described and justified the

inspection frequency. Thus, the staff finds that the applicant’s response satisfactorily

addresses its concerns and RAI B.2.11-4 is considered closed. The staff finds that the overall

monitoring and trending proposed by the applicant is acceptable because periodic inspections

performed in accordance with station procedures will effect timely corrective actions.

[Acceptance Criteria] The applicant stated that the acceptance criterion is that no unacceptable

visible indications of loss of material or cracking exist. The applicant further stated that an

indication of a rate of deterioration due to loss of material or cracking that could cause the

component to fail its intended function prior to its next scheduled inspection, as determined by

engineering evaluation, is considered unacceptable. The staff considers the acceptance criteria

to be adequate to assure that the intended functions for components in the Inspections for

Mechanical Components program will be maintained under all CLB design conditions during the

period of extended operation.

By letter dated March 28, 2003, the staff stated, in RAI B.2.11-3, that the SRP-LR Section

A.1.2.3.6 indicates that qualitative inspections should be performed to some predetermined

criteria as quantitative inspections by personnel in accordance with American Society of

Mechanical Engineers (ASME) Code and through site-specific programs. The staff therefore

requested the applicant to stipulate the qualifications of inspection personnel conducting the

“visual examination of the exposed external surfaces of mechanical components for loss of

material or cracking.” In its response dated June 12, 2003, the applicant stated that site

engineering personnel will perform the visual inspections and that any degradation found during

the visual inspections would be dispositioned through the VCSNS Corrective Action Program. 

The applicant stated that further inspections and qualifications required for these inspections

would be determined through the Corrective Action Program, which generally requires

inspection by quality control personnel qualified in accordance with ASME Code and 10 CFR

Part 50 Appendix B. This response did not identify the qualifications of the personnel

performing the initial inspection. During a telecommunication on July 14, 2003, the applicant

identified that actual system engineers perform the initial walkdowns who observe and report

any degradation or abnormality. By letter dated September 2, 2003, the applicant clarified that

site engineering personnel will perform visual inspections to specific developed criteria. The

staff finds that the applicant’s response satisfactorily addresses the staff’s concerns and RAI

B.2.11-3 is considered closed.

[Operating Experience] The applicant stated that the Inspections for Mechanical Components

program is a new inspection activity. The applicant also described relevant operating

experience with the identification of pitting below the insulation in the chilled water system,

which were detected and repaired under existing inspection activities, and several instances of

leakage in the chilled water system, which were identified by surveillance procedures. By letter

dated March 28, 2003, the staff requested, in RAI B.2.11-5, that the applicant discuss any

additional operating experience relevant to the systems within scope, or provide confirmation

that this is the only system in the scope of this program with observed degraded conditions. In

its response dated June 12, 2003, the applicant stated that Inspections for Mechanical

Components program were developed because it was determined that the aging effects were

possible—not because they were found at VCSNS. The particular industry operating

experience concerning the chilled water system was included because it demonstrates the
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effectiveness of the industry-wide operating experience research conducted by VCSNS on

possible aging effects for various material-environment combinations. Using industry

references, it was determined that, because of the relatively unpolluted environment of the

area, contaminants would not concentrate in sufficient quantities to cause pitting corrosion. 

However, the operating history search at VCSNS revealed that pitting has occurred under

insulation in the chilled water system and therefore it is included as an aging effect to be

managed. The staff finds that the applicant described and justified the findings from its

historical evaluation of operating history. Thus, the staff finds that the applicant’s response

satisfactorily addresses the staff’s concerns and RAI B.2.11-5 is considered closed.

By letter dated March 28, 2003, the staff stated, in RAI B.2.11-6, that the Inspections for

Mechanical Components program is credited for managing loss of material of the chilled water

expansion tanks (LRA Table 3.3-1, AMR Item 5). The staff stated that GALL AMP XI.M29

addresses aboveground carbon steel tanks, including inaccessible areas, but the VCSNS LRA

does not include this program. The staff requested that the applicant describe how the

Inspections for Mechanical Components program addresses aboveground carbon steel tanks,

including inaccessible locations, and other elements addressed in AMP XI.M29. In its response

dated June 12, 2003, the applicant stated that VCSNS does not use GALL AMP XI.M29. The

applicant further stated that the chilled water (VU) expansion tanks are elevated such that the

bottoms are accessible; however, in other instances, conditions of inaccessible locations can be

inferred from the external conditions of accessible locations that are closest to the subject

component. Tanks are elevated, usually on elevated concrete pads, so that any accumulations

on the floor around a tank does not affect it. It is expected that, should there be any external

degradation of tank bottoms for the tanks on concrete pads, there would be telltale signs down

the sides of the elevated pad which would be addressed by the Corrective Action Program. 

The applicant also stated that any general corrosion on inaccessible tank bottoms would

degrade no further than an initial oxide layer, which would provide protection from further

general corrosion. The staff is concerned that inaccessible surfaces of outdoor tanks may not

have a verification program, such as a thickness measurement, as required by GALL XI.M29. 

During a telecommunication with the applicant on July 14, 2003, the staff requested further

technical justification for not measuring wall thickness in outdoor carbon steel tanks, such as

the condensate storage tank, to conclude that significant degradation does not occur in

inaccessible areas. The staff identified that inaccessible areas for the condensate storage tank

are being addressed by RAI 3.4-13. By letter dated September 2, 2003, the applicant clarified

that the condensate storage tank is the only carbon steel tank in a yard environment with an

inaccessible bottom. The staff finds that the applicant’s response satisfactorily addresses the

staff’s concerns and RAI B.2.11-6 is considered closed.

By letter dated March 28, 2003, the staff stated in RAI B.2.11-7 that the Inspections for

Mechanical Components AMP is credited for managing loss of material due to general

corrosion and crack initiation and growth caused by cyclic loading and stress-corrosion cracking

(SCC) of the carbon and alloy steel component/component types and inherently addresses their

closure bolting in the auxiliary systems (AS) and the steam and power conversion (SPC)

systems. The staff noted that in Table 3.2-1, AMR Item12 (engineered safety features (ESF));

Table 3.3-1, AMR Item 23 (AS); and Table 3.4-1, AMR Item 8 (SPC), the LRA states that the

specific bolting/fasteners materials within the scope of license renewal were not itemized as a

separate non-Class 1 component/component types. Rather, bolting was treated as piece-part”
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(or subcomponent/sub-part) of non-Class 1 components/component types. The staff stated

that the GALL Report credits AMP XI. M18, “Bolting Integrity,” for monitoring loss of material,

cracking, and loss of preload. In addition, accepted bolting integrity programs (such as EPRI

104213) recommend monitoring for loss of preload as one of the parameters monitored or

inspected. Monitoring for cracking of high-strength bolts (actual yield strength equal or greater

than 150 ksi) is also recommended. The staff subsequently requested the applicant to do the

following: 

• Identify the AMP that will manage the aging effects for ESF closure bolting (Table 3.2-1, 

Item 12).

• Justify how the AMPs credited in the VCSNS LRA for bolting are consistent with the

Bolting Integrity AMP. 

• Provide justification for concluding that loss of preload is not an applicable aging effect. 

• Confirm whether high-strength bolts are included within the boundary of these three

systems (engineered safety features, auxiliary, and steam and power conversion).

In its response dated June 12, 2003, the applicant stated that for bolted closures (i.e., pressureretaining) of components/component types subject to AMR, the design of critical closure joint

bolting involves enough redundancy to ensure joint integrity. The applicant stated that no aging

effects unique to bolting, over the components being joined/closed, require evaluation for

license renewal (discussed further below). The applicant stated that external aging degradation

of carbon and low-alloy steel components will be managed by the Inspections for Mechanical

Components program and, in locations where susceptible, the Boric Acid Corrosion

Surveillances program. 

The applicant stated that, although identified as an aging effect in various industry references,

loss of mechanical closure integrity is not considered to be an aging effect requiring evaluation

for non-Class 1 component bolted closures (i.e., pressure boundary closures) within the scope

of license renewal. 

The applicant stated that mechanical components within the scope of license renewal, both

Class 1 and non-Class 1, contain bolted closures that are necessary for the pressure boundary

of the components being joined/closed. As such, the bolted closure (including fastener set)

was considered to be a subcomponent (piece-part) of the components/component types within

the scope of license renewal and did not usually require evaluation separate from the

component. 

The applicant identified that loss of mechanical closure integrity could result in failure of the

mechanical joint, evidenced by leakage rather than joint failure. The applicant stated that this

loss of mechanical closure integrity can be attributed to one or more of the following effects—

loss of bolt preload (embedment, cyclic load embedment, gasket creep, etc.), loss of bolting

material (from general and/or boric acid corrosion), reduction of bolting material fracture

toughness, and cracking of high-strength bolting material. 

For non-Class 1 bolted closures, loss of preload was considered to be the result of inadequate

design or improper assembly (i.e., event-driven) that is not related to aging and that would
3-39

manifest itself during the current operating term and be corrected prior to the period of

extended operation. 

Thus, the applicant claimed that the mechanisms associated with loss of bolting preload are not

a license renewal concern for non-Class 1 components/component types. 

The applicant stated that loss of bolting material could ultimately result in the loss of a

component’s pressure boundary integrity; this requires evaluation for license renewal. 

However, loss of material is an aging effect requiring license renewal evaluation for carbon and

alloy steel components/component types subject to AMR. As such, no evaluation separate

from the subject components/component types is necessary and, for carbon and alloy steel

components/component types, the AMPs credited for managing external general corrosion will

inherently address their fasteners. 

Furthermore, the applicant stated that stainless steel fasteners are immune to loss of material

due to general corrosion. The applicant stated bolting is normally in a dry environment and is

coated with a lubricant, thus general corrosion of carbon and alloy steel bolting is not an issue. 

As is the case with components of similar material, the occurrence of general corrosion in

carbon and low-alloy steel fastener sets in the ambient environments is most likely in systems

with operating temperatures below ambient conditions that result in condensation, and in the

yard environment with repeated wetting/drying from outdoor exposure. 

The applicant stated that loss of material due to boric acid wastage (aggressive chemical

attack) is the most common aging effect that has been observed in the industry for ferritic

fasteners. The Boric Acid Corrosion Surveillances AMP, credited for managing external aging

of carbon and low-alloy steel in locations susceptible to leaking borated water, will also address

carbon and low-alloy steel fasteners in that location. Additionally, the applicant stated that the

Inspections for Mechanical Components program will address any general corrosion concerns

for carbon or low-alloy steel bolting in stainless steel components or component types. 

The applicant stated that reduction of fracture toughness of bolting material, caused by 

thermal/neutron effects, is a license renewal concern for the fasteners of components only due

to the associated elevated system operating temperatures and proximity to the reactor vessel

(RV) beltline region. This is applicable to bolting of some Class 1 components and is

addressed in the application. The applicant stated that reduction of fracture toughness for nonClass 1 bolting material is not a license renewal aging effect requiring management for the

fasteners of components. 

The applicant stated that SCC of bolting materials is a condition in which a fastener that is

statically loaded well below the material yield strength may suddenly fail. SCC-induced bolted

closure fastener failures have occurred in materials with apparently normal chemical and

mechanical properties. Although there have been a few industry instances of SCC-induced

bolting cracking, the applicant stressed that these have been attributed to high yield stress

materials and contaminants, such as the use of molybdenum disulfide (MoS2)-lubricants, which

VCSNS has not and does not use. Most bolting is normally in a dry environment and is coated

with a lubricant; in general, environmental conditions that could lead to SCC of bolting are not

expected to occur in non-Class 1 components. For quenched and tempered low-alloy steels

used for closure bolting (e.g., SA193 Grade B7), having lower yield strength minimizes material

susceptibility to SCC. EPRI Report NP-5769 (Volume I, page 11-5) indicates that SCC should
3-40

not be a concern for closure bolting in nuclear power plant applications if the specified yield

strength is below 150 ksi. The specification for the fabrication of nuclear piping specifies alloy

steel ASME SA 193, Class B7 bolts/studs, and ASME 194 Grade 2H nuts, which have minimum

yield strengths below 150 ksi (105 ksi). A minimum yield strength for bolting does not, in and of

itself, preclude SCC since the actual yield strength of the bolt could be above the threshold

value for SCC of low-alloy steel bolting/fasteners to occur (150 ksi). However, sound

maintenance bolt torquing practices can control bolting material stresses and the use of

appropriate material (such as ASTM A193 Gr. B7) for bolting reduces the potential for SCC to

occur. The applicant stated that a review of industry failure databases and NRC generic

communications supports the fact that proper material selection, proper maintenance and

torquing procedures, and removal of contaminants from lubricants have been effective in

eliminating the potential for SCC of bolting materials. The applicant stated that, as documented

in NRC Inspection Report No. 50-395/84-08, dated April 20, 1984, the recommended

preventive measures and practices of Inspection and Enforcement Bulletin (IEB) 82-02 have

been incorporated into the maintenance procedures at VCSNS. Therefore, the applicant stated

that SCC of bolting materials is not an aging effect requiring evaluation for license renewal for

non-Class 1 component types.

The applicant appropriately identified that loss of mechanical closure integrity due to aggressive

attack is an applicable effect for the carbon steel non-Class 1 bolting in the same manner it

identified that the aging effect was applicable to the reactor coolant system (RCS) Class 1

bolting fabricated from low-alloy steel. The Boric Acid Corrosion Surveillances and Inspections

for Mechanical Components programs are credited with managing loss of material for bolting. 

The applicant also addressed SCC and concluded that it is not an aging effect requiring further

evaluation on the basis of recommended preventive and maintenance practices consistent with

IEB 82-02. However, the applicant did not identify that loss of mechanical closure integrity is an

applicable aging effect for non-Class 1 bolting materials as a result of stress relaxation in high

temperature systems. It is expected that system temperatures may not exceed the threshold

where stress relaxation could occur. 

During a conference call with the applicant on July 14, 2003, the staff requested the applicant to

supplement the RAI response and provide further justification for not addressing loss of

preload due to stress relaxation for high temperature systems. By letter dated September 2,

2003, the applicant clarified that, since the operating temperature is below the threshold

temperature of 700F, stress relaxation was not identified as an applicable aging effect

mechanism for bolts in non-Class 1 RCS bolted connections. The staff finds that the

applicant’s response satisfactorily addresses the staff’s concerns and RAI B.2.11-7 is

considered closed.

Section 18.2.20 of Appendix A to the LRA contains the applicant’s FSAR Supplement for the 

Inspections for Mechanical Components program at VCSNS. The staff reviewed the FSAR

Supplement and found that the description of this program is consistent with Section B.2.11 of

the LRA. The staff finds that the information contained in the FSAR Supplement presents an

adequate summary of the program activities as required by 10 CFR 54.21(d).

3.0.3.7.3 Conclusions

On the basis of its review of the applicant’s program, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended
3-41

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 FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.0.3.8 Heat Exchanger Inspections

The Heat Exchanger Inspections program is described in Section B.2.12, of Appendix B in the

LRA. The LRA credits this AMP with detecting and characterizing loss of material for copper,

copper-nickel, and brass heat exchanger components exposed to a treated water environment

in the air handling, component cooling, chemical and volume control, diesel generator,

emergency feedwater, chilled water, and local ventilation and cooling systems at VCSNS. The

staff reviewed the LRA to determine whether the applicant has demonstrated that the Heat

Exchanger Inspections program will adequately manage the applicable aging effect (loss of

material) for the components that credit this program during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.0.3.8.1 Summary of Technical Information in the Application

The applicant’s Heat Exchanger Inspections (HEI) program is discussed in LRA Section B.2.12, 

“Heat Exchanger Inspections.” The applicant stated that this is a new program and

summarized the program in terms of the 10 elements as described in BTP RLSB in Appendix A

to the SRP-LR. The LRA credits this inspection with detecting and characterizing loss of

material due to selective leaching and flow-accelerated corrosion (FAC) (i.e., erosion/corrosion)

in the LRA, as well as heat exchanger fouling due to particulates for heat exchanger

components in a treated water environment at VCSNS. The applicant states that the Heat

Exchanger Inspections AMP is a new one-time inspection activity that will determine if aging

management is required for certain malleable heat exchanger components during the period of

extended operation. The Heat Exchanger Inspections program will detect and characterize loss

of material due to selective leaching and FAC, as well as particulate fouling. The heat

exchanger inspections will use a combination of volumetric and visual examination and

hardness measurement techniques at the most susceptible (sample) locations (FSAR

Supplement 18.2.40). The applicant stated that the Heat Exchanger Inspections program will

be consistent with GALL AMP XI.M32, “One-Time Inspection,” and GALL AMP XI.M33,

“Selective Leaching of Materials,” as identified in the GALL Report. The applicant also stated

that this one-time inspection will be performed prior to the period of extended operation.

In Section B.2.12 of the LRA, the applicant concluded that the implementation of the Heat

Exchanger Inspections program will either confirm that there are no aging effects requiring

management for the subject components or ensure that appropriate corrective actions will be

taken so that the component intended functions will be maintained for the period of extended

operation.

3.0.3.8.2 Staff Evaluation

In LRA Section B.2.12, “Heat Exchanger Inspections,” the applicant described its AMP to

manage loss of material due to selective leaching and FAC (i.e., erosion/corrosion) in the LRA,

as well as heat exchanger fouling due to particulates for heat exchanger components in a

treated water environment. The staff reviewed the information in Section B.2.12 of Appendix B
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to the LRA, the summary description of the program in the FSAR Supplement (Section 18.2.40

of Appendix A to the LRA), and the applicant’s responses to the staff’s RAIs. Since the

applicant stated that the HEI program is a new one-time inspection consistent with GALL AMPs

XI.M32 and XI.M33, the staff’s evaluation of this program, is based on the 10 element program

described in BTP RLSB in Appendix A to the SRP-LR. The ten program elements in the GALL

AMP for one-time inspection supply detailed programmatic characteristics and criteria that the

staff considers necessary to confer additional assurance that either aging is not occurring or the

evidence of aging is so insignificant that an AMP is not warranted. The ten program elements

in GALL AMP XI.M33 include a one-time visual inspection and hardness measurement of

selected components that may be susceptible to selective leaching to determine whether loss of

materials due to selective leaching is occurring, and whether the process will affect the ability of

the components to perform their intended function during the period of extended operation.

The staff’s evaluation focused on management of aging effects through incorporation of the

following 10 elements from BTP RLSB-1—program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience. 

The applicant indicated that the corrective actions, confirmation process, and administrative

controls for license renewal are in accordance with the site-controlled Quality Assurance

Program. The staff’s evaluation of the applicant’s Quality Assurance Program is provided

separately in Section 3.0.4 of this SER. The evaluation of the remaining seven elements is

provided below. The staff also reviewed the FSAR Supplement to determine whether it

provides an adequate description of the program.

[Program Scope] The applicant stated that this AMP is applicable to copper, copper-nickel, and

brass heat exchanger components (as well as brass thermowells) exposed to a treated water

environment in the air handling system, CCWS, chemical and volume control system, diesel

generator system, emergency feedwater system, chilled water system, and local ventilation and

cooling system. The staff finds that the components monitored by the HEI program, as listed

above and in Section B.2.12 of the LRA, cover the scope of license renewal as identified in

Section 2.3 of the LRA. The scope is acceptable to the staff because it includes those

components that rely on the program for aging management.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need

for such actions.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness as a measure of loss of material, material hardness as a

measure of selective leaching, and visual evidence of loss of material, heat exchanger fouling,

or other age-related degradation. The staff finds the above parameters acceptable because

they are directly related to the degradation of copper, copper-nickel, and brass heat exchanger

components in the specified VCSNS systems.

[Detection of Aging Effects] The applicant stated that this AMP will use a combination of

proven volumetric and visual examination techniques at sample locations in the various heat

exchangers determined by engineering evaluation to be most susceptible to the applicable

aging effects. The applicant stated that if no parameters are known that would distinguish the

susceptible locations, sample locations will be selected based on accessibility and radiological
3-43

concerns, and the results will be applied to the associated components. The inspection will

include a Brinnell Hardness Test, or equivalent, on a sample of susceptible components in

order to characterize a reduction of material hardness (loss of material) due to selective

leaching. Further, the applicant stated that the heat exchanger inspections will detect the

presence and extent of any loss of material and heat exchanger fouling prior to a loss of

component intended function. Inspection locations for heat exchanger fouling should focus on

heat exchanger components having an intended function of heat transfer and which are

normally in a standby condition with no flow. 

The HEI program is credited in LRA Section B.2.12 with detecting and characterizing loss of

material due to selective leaching and FAC, as well as heat exchanger fouling due to

particulates, for heat exchanger components in a treated water environment. By letter dated

March 28, 2003, the staff requested, in RAI B.2.12-1, that the applicant clarify management of

galvanic corrosion of heat exchanger tubes. In its response dated June 12, 2003, the applicant

stated that the heat exchanger inspections target certain aging effects for components in a

treated water environment. The applicant further stated that HEI program is being developed to

manage aging effects that are not already managed by other programs; the Chemistry Program

is credited to manage galvanic corrosion. EPRI Report 1003056, Appendix A, states that

treated water is a poor electrolyte, but concludes that components in treated water systems

may exhibit galvanic corrosion. The report identifies five methods for eliminating or minimizing

galvanic corrosion. During a telecommunication on July 14, 2003, the applicant identified that

chemical purity specifications assure that treated water is maintained within a range that

controls galvanic corrosion. By letter dated September 2, 2003, the applicant identified that the

makeup water for these systems is supplied from the demineralized water system with a

specified cation conductivity less than 1.0mho/cm. In this response, the applicant also stated

that VCSNS has no history of galvanic corrosion of components in these systems and

maintains that by following EPRI guidelines for chemistry control of these systems the

Chemistry Program manages galvanic corrosion in these systems. The staff finds that the

applicant’s response satisfactorily addresses the staff’s concerns and RAI B.2.12-1 is

considered closed.

By letter dated March 28, 2003, the staff requested, in RAI B.2.12-2, that the applicant discuss

whether the Chemistry Program and HEI program are used together to manage applicable

aging effects for all heat exchanger components in the component cooling water system

(CCWS). The staff stated that the LRA is unclear on this point because the Chemistry Program

explicitly exempts one-time inspection, but the LRA states that the Heat Exchanger Inspections

Program is consistent with GALL AMPs XI.M32 and XI.M33. The staff also requested that the

applicant discuss whether the HEI program is used to verify the effectiveness of the Chemistry

Program for the applicable aging effects. 

In its response dated June 12, 2003, the applicant stated that the heat exchanger inspections

AMP addresses particular aging effects for specified materials in a treated water environment

and that the purpose of the inspections is to manage aging effects not managed by any other

program. For the components encompassed by the HEI program, the Chemistry Program

would not manage loss of material due to leaching and FAC for certain materials, thus the HEI

program is necessary to manage those aging effects. The applicant added that since the

Chemistry Program is credited with managing heat exchanger fouling, the heat exchanger

inspections can serve to demonstrate the effectiveness of the Chemistry Program for that

particular aging effect. The staff notes that the applicant has demonstrated that the Chemistry
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Program has proven effective in managing aging effects in a treated water environment as

evidenced by review of operating history in response to NRC Generic Letter (GL) 89-13. Since

the applicant has also stated that, prior to the period of extended operation, one-time

inspections will be conducted in low-flow areas of the various closed, treated water systems to

demonstrate the effectiveness of the Chemistry Program, the staff’s concerns are resolved, and

RAI B.2.12-2 is considered closed. 

By letter dated March 28, 2003, the staff requested, in RAI B.2.12-3, that the applicant discuss

how the results of sampling would be taken into account for any future inspections (monitoring). 

In its response dated June 12, 2003, the applicant stated that, depending on the condition of

the component as determined by engineering evaluation, subsequent inspections would be

determined through the VCSNS Corrective Action Program. Should aging effects be detected

that require subsequent inspections, these inspections would be at the locations previously

inspected. The staff requires additional information to evaluate the ability of monitoring to

detect aging effects prior to loss of function. In a telecommunication on July 14, 2003, the staff

requested that the applicant provide more specific information about techniques to sample

susceptible areas and inaccessible areas, such as channel head components, motor cooler

heat exchangers, tubesheets, and tube bundles. By letter dated September 2, 2003, the

applicant stated that representative locations for these inspections would be based on the

combination of susceptible materials and chemistry regime. This response also identified that

no channel head components are susceptible to the aging effects/mechanisms and the majority

of the susceptible components are tubes for various heat exchangers in treated water systems,

as well as several thermowells in the diesel generator services system and the tubesheets for

the upper reactor coolant pump motor oil coolers. The applicant also stated that present

methods for inspecting tubes include volumetric examinations (e.g. eddy current testing) and

visual examinations (e.g. boroscopic inspections). Further, the applicant identified that present

methods for inspecting loss of material for thermowells include visual inspections and hardness

testing (e.g. Brinell hardness testing). The staff finds that the applicant’s response satisfactorily

addresses the staff’s concerns and RAI B.2.12-3 is considered closed.

The use of one-time inspection is appropriate for inspections where degradation is possible, but

is not expected based on plant-specific and industry operating experience. This one-time

inspection provides for additional inspections should the corrective action process require

additional information to characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the HEI

program to trend inspection results. This is a one-time inspection used to determine if further

actions are required. The staff did not identify the need for such actions.

[Acceptance Criteria] The applicant stated that the acceptance criteria are (1) no unacceptable

loss of material or (2) heat exchanger fouling of the subject components that could result in a

loss of the component intended function, as determined by engineering evaluation. By letter

dated March 28, 2003, the staff requested, in RAI B.2.12-4, that the applicant elaborate on the

acceptance criteria applied in the engineering evaluation with consideration to the rate of

damage and explain how a determination of no unacceptable loss of material or fouling of

subject components can be made on the basis of a one-time inspection. In its response dated

June 12, 2003, the applicant stated that any loss of material would be determined by

engineering evaluation based on the design of the individual component and, where applicable,

on the results of the hardness testing. Although the Chemistry Program controls heat
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exchanger fouling due to particulates, the heat exchanger inspections are an additional

verification of the effectiveness of the Chemistry Program. Any heat exchanger fouling will be

determined by engineering evaluation based on visual examination. Loss of material or heat

exchanger fouling would be evaluated and documented in the VCSNS Corrective Action

Program, with subsequent actions or inspections determined through the Corrective Action

Program. The applicant concluded that, if aging effects are detected that require subsequent

inspections, these inspections would be at previously inspected locations to be able to

determine damage kinetics. The staff is concerned that loss of heat transfer may not be

detected by visual examination for fouling prior to loss of the intended function. In a

telecommunication dated July 14, 2003, the applicant identified that no tube aging effects have

been observed and that heat transfer may not be a safety function for the heat exchangers 

included in the HEI program. By letter dated September 2, 2003, the applicant stated that the

visual examination for fouling, possibly through the use of a boroscope, will be performed on a

sample of heat exchanger tubes based on chemistry regime. The applicant also stated that it is

reasonable that the results of the examination would be indicative of the fouling for the tubes of

the other heat exchangers for that chemistry regime. Considering that heat exchanger fouling

will be determined by engineering evaluation based on visual examination, the staff finds that

the applicant’s response satisfactorily addresses the staff’s concerns and RAI B.2.12-4 is

considered closed.

[Operating Experience] The applicant stated that the HEI program is a new one-time inspection

for which there is no operating experience. By letter dated March 28, 2003, the staff requested,

in RAI B.2.12-5, that the applicant clarify any relevant operating experience for the systems that

will be managed by this program. In its response dated June 12, 2003, the applicant stated that

operating experience, both site-specific and industry-wide, was researched to identify the

possible aging effects for various combinations of material and environment. This new HEI

program was developed because it was determined that the aging effects were possible—not

because these aging effects were found at VCSNS. At VCSNS, there is no history of selective

leaching, FAC, or heat exchanger fouling occurring for the components managed by this

program. The staff is concerned that aging effects may not be evident unless maintenance

records are reviewed. During a telecommunication on July 14, 2003, the applicant identified

that maintenance records were not reviewed, but that no unacceptable degradation was

reported, fouling was only a problem for open-cycle cooling because the maintenance programs

have prevented any problems with closed cycle cooling system (components cooled with very

clean chilled water). By letter dated September 2, 2003, the applicant stated that the makeup

water is demineralized water and in these closed systems there is no other pathway for the

introduction of contaminants beyond the corrosion products of the system and the addition of

corrosion inhibitors. Considering that one-time inspections will be used to verify the

effectiveness of the chemistry program, the staff finds that the applicant’s response

satisfactorily addresses the staff’s concerns and RAI B.2.12-4 is considered closed.

Section 18.2.40 of Appendix A to the LRA contains the applicant’s FSAR Supplement for the

heat exchanger inspections at VCSNS. The staff reviewed the FSAR Supplement and found

that the description of the HEI program is consistent with Section B.2.12 of the LRA. The staff

finds that the information contained in the FSAR Supplement presents an adequate summary of

the program activities as required by 10 CFR 54.21(d).

3.0.3.8.3 Conclusions
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On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.0.3.9 Area-Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria

3.0.3.9.1 Summary of Technical Information in the Application

The applicant’s Area-Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria program is

described in Appendix B.2.13 of the document “Criteria 2 Supplement to the Application for

Renewed Operating License for VCSNS” submitted by applicant’s letter dated September 12,

2002. The LRA Criteria 2 Supplement credits this new one-time inspection program at VCSNS

with detecting and characterizing loss of material due to general, crevice, and pitting corrosion

resulting from exposure of carbon steel pipe to an unmonitored and uncontrolled water

environment (such as rainwater, leaking ground water and water drained from equipment).

In Section B.2.13 of the document, “Criteria 2 Supplement to the Application for Renewed

Operating License for VCSNS,” the applicant states that implementation of the Area-Based

Inspections for Refined 10 CFR 54.4(a)(2) Criteria program will either verify that there are no

aging effects requiring management for the subject components or appropriate corrective

actions will be taken so that the component intended functions will be ensured during the period

of extended operation.

3.0.3.9.2 Staff Evaluation

In Section B.2.13 of Appendix B to the document, “Criteria 2 Supplement to the Application for

Renewed Operating License for VCSNS,” the applicant describes its AMP to manage loss of

material due to general crevice and pitting, corrosion from exposure to an unmonitored and

uncontrolled water environment. The applicant stated that this is a new one-time inspection. 

Therefore, the staff reviewed the program using the guidance in STP RLSB-1 in Appendix A to

the SRP-LR. The staff’s evaluation focused on managing aging effects through the effective

incorporation of ten elements described in NUREG-1800, Appendix A-1 Aging Management

Review-Generic (Branch Technical Position RLSB-1), scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrections actions, confirmation process, administrative controls and the operating expertise.

The LRA Criteria 2 Supplement indicates that the corrective actions and confirmation process

are implemented through the site corrective actions process, while the administrative controls

are implemented through the site procedures. The staff’s evaluation of corrective actions,

confirmation process, and administrative controls is contained in Section 3.0.4 “Quality

Assurance Program” of this SER. The remaining seven (7) elements are evaluated below. The

staff also reviewed the FSAR supplement to determine whether it provides an adequate

description of the program.
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[Program Scope] The applicant stated that the Area-Based Inspections for Refined 10 CFR

54.4(A)(2) Criteria is a new inspection activity that will detect and characterize loss of material

due to general, crevice, and pitting corrosion resulting from exposure of carbon steel pipe to an

unmonitored and uncontrolled water environment (such as rainwater, leaking ground water

and water drained from equipment). The applicant states that this AMP will manage the relevant

aging effect for carbon steel pipe in the following systems: steam dump discharge piping, nonnuclear plant drains, main steam safety and relief valve discharge piping, roof drains, and

sewer. The scope is acceptable to the staff because it includes those components that rely on

the program for aging management.

[Preventive Actions] The applicant states that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need

for such actions.

[Parameters Monitored or Inspected] The applicant states that this AMP inspects wall thickness

as a measure of loss of material, and visual evidence of loss of material or other age-related

degradation. The staff finds the above parameters acceptable because they are directly related

to the degradation of carbon steel pipe exposed to an uncontrolled water environment in the

specified VCSNS systems.

[Detection of Aging Effects] The applicant states that this AMP will use a combination of

volumetric and visual examination techniques at sample locations in the drain lines determined

by engineering evaluation to be most susceptible to the applicable aging effects. The applicant

further states that as no parameters are known that would distinguish the susceptible locations,

sample locations will be selected based on accessibility and radiological concerns, and the

results applied to the associated piping. The applicant states that this AMP will detect the

presence and extent of any loss of material prior to a loss of component intended function and

the effective and proven volumetric and visual examination techniques will be selected for use

in performing the inspection. In a conference call on September 16, 2003, the staff requested,

in RAI B.2.13-1, Part a, that the applicant clarify how sample locations would be chosen. The

applicant was also asked to clarify if safety and relief valve discharge piping was susceptible to

erosion and to identify which systems are exposed to leaking ground water and how MIC is

managed for these systems. By letter dated September 24, 2003, the applicant responded by

stating that the aging mechanisms are not expected to challenge the structural integrity of these

piping systems and a one-time inspection based on accessibility and suitability will determine if

corrective actions such as future inspections or repair will be required. The applicant stated that

safety and relief valve lines are not subject to erosion due to their limited operating time at

design flow rates. The applicant also clarified that only the non-nuclear plant drains are

exposed to raw water and MIC induced leakage will be detected and appropriate action taken

before the loss of structural integrity. The staff finds that this response satisfactorily addresses

the staff’s concerns and RAI B.2.13-1, part a. is closed.

[Monitoring and Trending] The applicant states that no actions are taken as part of the Area

Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria to trend inspection results. 

Furthermore the applicant states that this is a one-time inspection used to determine if further

actions are needed. Trending is not applicable to a new one-time inspection. 

[Acceptance Criteria] The applicant maintained that the acceptance criteria for the Area Based

Inspections for Refined 10 CFR 54.4(a)(2) Criteria is no acceptable loss of material subject
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components that could result in a loss of the component intended function(s), as determined by

engineering evaluation. However, in the attribute “Corrective Actions” the applicant states that

if the engineering evaluation determines that additional information is required to more fully

characterize the aging effects, then additional inspections will be completed by other actions

taken in order to obtain the additional information.

In RAI B.2.13-1 Part b, the staff requested that the applicant clarify whether evaluation of the

inspection results will ensure that the minimum required wall thickness is preserved. By letter

dated September 24, 2003, the applicant responded by stating that aging mechanisms are not

expected to challenge the structural integrity of these piping systems and that a one-time

inspection will be able to predict the potential for through wall leakage occurring for those drains

lines over sensitive components. The staff finds that this response satisfactorily addresses the

staff’s concerns and RAI B.2.13-1, part b. is closed.

[Operating Experience] The applicant stated that the Area Based Inspections for Refined 10

CFR 54.4(a)(2) Criteria is a new inspection activity for which there is no operating experience. 

In RAI B.2.13-1 Part c, the staff requested that the applicant clarify any relevant operating

experience, both site-specific and industry-wide, for the systems that will be managed by this

program. The staff also requested confirmation that the operating experience review includes

plant operating and maintenance history for the systems managed by this program, as required

by Section 4.2.2.2 of NEI 95-10. By letter dated September 24, 2003, the applicant responded

by stating that the operating experience reviews performed identified aging issues regardless of

the component’s license renewal intended function and the operating experience identified no

new aging effects. This response further clarified that the review of non-conformance notices

was performed for a five year period. The staff finds that this response satisfactorily addresses

the staff’s concerns and RAI B.2.13-1, part c. is closed. 

Section 18.2.26 of the document, “Criteria 2 Supplement to the Application for Renewed

Operating License for VCSNS” containing the applicant’s FSAR supplement for the Area Based

Inspections for Refined 10 CFR 54.4(a)(2) Criteria is consistent with Section B.2.13 of this

Criteria 2 Supplement. The staff finds that the information contained in the FSAR supplement

presents an adequate summary of the program activities as required by 10 CFR 54.21(d).

3.0.3.9.3 Conclusion

On the basis of its review, the staff finds that the program adequately addresses the ten

program elements defined in Branch Technical Portion RLSB-1 in Appendix A-1 of the SRP-LR,

and that the program will adequately manage the aging effects for which it is credited. The staff

also reviewed the FSAR supplement for this AMP and finds that it provides an adequate

summary description of the program as required by 10 CFR 54.21(d). 

Therefore, on the basis of its review, the staff concludes that there is reasonable assurance that

the applicant has demonstrated that the Area Based Inspections for Refined 10 CFR 54.4(a)(2)

Criteria will effectively manage aging in the components for which this program is credited, to

ensure that the components will perform their intended functions in accordance with the current

licensing basis during the period of extended operation, as required by 10 CFR 54.21(a)(3). The

staff also reviewed the FSAR supplement for this AMP and finds that it provides an adequate

summary description of the program, as required by 10 CFR 54.21(d). 
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3.0.4 VCSNS Quality Assurance Program

The NRC staff reviewed Appendix B of the LRA, Aging Management Programs and Activities,”

in accordance with the requirements of 10 CFR 54.21(a)(3) and 10 CFR 54.21(d). The staff

evaluated the adequacy of certain aspects of the applicant’s programs to manage the effects of

aging, in particular, the three QA Program elements of corrective action, confirmation process,

and administrative controls, which the applicant addressed for all of the AMPs. A license

renewal applicant is required to demonstrate that the effects of aging on SCs that are subject to

an AMR will be adequately managed to ensure that their intended functions will be maintained

in a manner that is consistent with the CLB of the facility throughout the period of extended

operation. To manage these effects, applicants have developed new, or revised existing, AMPs

and applied those programs to the SSCs of interest. For each of these AMPs, the applicant’s

existing 10 CFR Part 50, Appendix B, Quality Assurance Program (QA) may be used to

address.

3.0.4.1 Summary of Technical Information in Application

Section 3.0, Aging Management Review Results,” of the LRA, provides an AMR summary for

SCs, or commodity groups, determined during the scoping and screening process to be subject

to an AMR. SCs subject to an AMR were evaluated to demonstrate that the effects of aging will

be managed so that the intended functions will be maintained consistent with the CLB for the

period of extended operation. 

Appendix B, Section B.1.0, “Existing Aging Management Activities”, and Section B.2.0, “New

Aging Management Activities,” of the LRA provide the aging management activity description

for each of these activities credited for managing aging effects. These activities are based

upon the AMR results provided in Sections 3.1 through 3.6 of the LRA. The applicant stated

that the existing VCSNS QA program addresses three of the AMP elements (corrective action,

confirmation process, and administrative control) for all of its AMPs, implements the

requirements of 10 CFR Part 50, Appendix B; and is consistent with the summary in Section

A.2 of NUREG-1800. The applicant further stated that these programs, credited for license

renewal, encompass both the safety-related and non-safety-related SCs that require aging

management during the period of extended operation. AMPs identified as existing or new, in

Appendix B, Sections B.1.0 and B.2.0, of the LRA provide descriptions of the specific attributes

of corrective action, confirmation process and administrative control. A correlation between 

NUREG-1801 and the VCSNS programs credited with aging management is provided in

Appendix B, Table B-1, of the LRA. 

3.0.4.2 Staff Evaluation

The staff evaluated the adequacy of certain aspects of the applicant’s programs to manage the

effects of aging. The particular aspects reviewed by the staff in this section encompass three

QA Program elements, namely corrective action, confirmation process, and administrative

control. These three attributes of the QA Program apply to all of the applicant’s AMPs. During

the scoping and screening methodology audit, performed by the NRC staff during the period

January 28—31, 2003, the staff reviewed the applicant’s programs described in Appendix A,

“FSAR Chapter 18,” and Appendix B, “Aging Management Programs and Activities,” to assure

that the aging management activities were consistent with the staff’s guidance described in
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Section A.2, “Quality Assurance for Aging Management Programs,” and BTP IQMB-1,

regarding quality assurance of the SRP-LRA. During the review, the applicant stated that the

attributes of corrective action, confirmation process, and administrative control are addressed in

the VCSNS QA program and that VCSNS will employ the Corrective Action and Document

Control Programs to address these program elements for both safety-related and non-safetyrelated SCs that require aging management during the period of extended operation. Based on

the staff’s evaluation, the description and applicability of the AMPs and their associated

attributes to all safety-related and non-safety-related SCs provided in Appendix A and

Appendix B of the LRA, the applicant’s program is consistent with the staff’s position regarding

quality assurance for aging management. However, the staff noted that the applicant had not

sufficiently described the use of the QA Program and its associated attributes (corrective action,

confirmation process, and administrative control) in Appendix A of the LRA. 

In a letter dated March 28, 2003, the staff submitted RAI 2.1-3 to the applicant, which requested

a revision to Appendix A to include a description of the QA Program elements, including

references to pertinent guidance, consistent with the level of detail discussed in Appendix B of

the LRA. In a letter dated June 16, 2003, the applicant provided a response to the staff’s RAI

which stated that the VCSNS QA program applies equally to both existing programs and new

programs being developed for license renewal, and that generic statements regarding the

applicability of the VCSNS QA program will be added to FSAR Section 18.1 for all of the

programs credited to manage aging effects for in-scope SSCs. The response also stated that

the implementing documents are subject to administrative controls, including a formal review

and approval process, and that the confirmation process is part of the AMP implementing

procedures and the VCSNS Corrective Action Program. The response stated that the aging

management activities required by this program would also identify any unsatisfactory

conditions due to ineffective corrective action and that both the implementing documents and

the confirmation process are implemented in accordance with the requirements of 10 CFR

Part 50, Appendix B, and American National Standards Institute (ANSI) N18.7-1976,

“Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power

Plants,” as committed to in the FSAR. 

Based on its review of the applicant’s response to RAI 2.1-3, the staff concludes that the

applicant has committed to include a description of the QA program elements consistent with

the level of detail currently provided in Appendix B. 

3.0.4.3 Conclusions

The staff finds that the quality assurance elements are consistent with 10 CFR 54.21(a)(3) and

the staff’s BTP IQMB-1. The staff also finds that the applicant’s supplemental response and

commitment to add generic statements to Appendix A of FSAR Chapter 18, specifically

Section 18.1 as discussed above, should provide sufficient description of the QA program

attribute and activities for managing the effects of aging as required by 10 CFR 54.21(d). This

commitment has also been identified in Appendix A of this SER.

3.0.5 Aging Management Review of Systems, Structures, and Components Under

Refined Criterion 2

3.0.5.1 Summary of Technical Information in the Application
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The description of the Criteria 2 systems and components can be found in Section 2.3.5 of this

SER. The passive, long-lived components in these systems that are subject to an AMR are

identified in Section 2.0 of the Criteria 2 Supplement to the LRA submitted by the applicant on

September 12, 2002. The components, aging effects, and aging management programs are

provided in Table 1 of the Criteria 2 Supplement. 

Aging Effects

Tables 1 and Section 2.0 of the Criteria 2 Supplement list individual components including

piping and components, insulation, ductwork, and non-mechanical components.

Loss of material due to crevice corrosion, pitting corrosion, and crack initiation and growth from 

stress corrosion cracking are identified as aging effects for stainless steel components exposed

to the environments of treated water, chemically treated borated water, or uncontrolled water.

No aging effect is identified for stainless steel, carbon steel, fiberglass insulation, and calcium

silicate insulation components exposed to the environment of air-gas. No aging effect is

identified for stainless steel and galvanized steel components exposed to the environment of

ambient air (dry for galvanized steel). For exposure to the environment of wet ambient air, loss

of material due to general and galvanic corrosion is identified as aging effect for galvanized

steel components. Loss of material due to boric acid leakage is identified as an aging effect for

carbon steel, and galvanized steel components exposed to the environment of ambient air with

boric acid leakage. Loss of material due to crevice corrosion, pitting corrosion, and flow

accelerated corrosion and crack initiation and growth/ stress corrosion cracking are identified as

aging effects for carbon steel components exposed to the environment of treated water. 

Carbon steel components in a raw water environment has the applicable aging effect of loss of

material due to crevice, pitting, general, and galvanic corrosion, as well as microbiologically

induced corrosion (MIC) and erosion. Loss of material due to general and/or galvanic corrosion

is identified as an aging effect for carbon steel components exposed to the environment of

ambient air and uncontrolled water while the additional aging effect due to crevice, and pitting

corrosion is applicable to carbon steel components in an environment of uncontrolled water. No

aging effect is identified for carbon steel components exposed to the fuel oil environment.

Aging Management Programs

The following AMPs are utilized to manage aging effects in the Criteria 2 systems:

• Boric Acid Corrosion Surveillances (Appendix B.1 .2),

• Chemistry Program (Appendix B.1 .4),

• Flow-Accelerated Corrosion Monitoring Program (Appendix B.1 .6),

• Inspections for Mechanical Components (Appendix B.2.11), 

• Service Water System Reliability and In-Service Testing Program (Appendix B.1 .9),

• Area Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria Commodities (Appendix

B.2.13).

With the exception of the new AMP B.2.13, “Area Based Inspections for Refined 10 CFR

54.4(a)(2) Criteria Commodities”, these AMPs are existing programs included in Appendix B of

the LRA. In Appendix B of the supplemental submittal, the applicant provided additional

information to supplement the original program discussion of these existing AMPs. In addition,

the applicant provided a detailed description of the new AMP B.2.13. The applicant concluded
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that the effect of aging associated with the components of the Criteria 2 systems will be

adequately managed by these AMPs during the period of extended operation.

3.0.5.2 Staff Evaluation

Aging Effect

The staff reviewed the information in the Criteria 2 Supplement. During its review, the staff

determined that additional information was needed to complete its review. 

In Item #6 of Table 1 in Criteria 2 Supplement under the “Discussion” column, the applicant

stated that component type listed in Item #6 also includes the internal surface of system

components that contain non-dried air. The applicant also stated that these components may

experience internal surface corrosion but they are not expected to have a loss of structural

integrity. During a telephone conference on September 16, 2003, the staff requested the

applicant to provide the basis, including any operating experience, for this conclusion and to

clarify whether any of these components has any intended function other than structural

integrity. 

In addition, the staff noted that the piping systems and components included in Item #6 are a

subset of those of Item # 4. For this subset, components, materials and environment (other

than external versus internal) are consistent in both items. However, the corresponding AMR

(for non-dried air in #6 or moist air in #4) led to different conclusions for components in the two

items (#4 and #6) regarding the need for aging management. The staff requested the applicant

to provide the basis for the different AMR conclusions for components in these two items.

In its response dated September 24, 2003, the applicant stated that all items included in the

Criteria 2 Supplement are included for the concern of potential interaction with safety related

SSCs. The requirements for these items are to maintain structural integrity. In addition to

structural integrity, a few components over sensitive components like electrical switchgear or

motor control centers are required not to leak fluid. VCSNS took a conservative approach to

Criteria 2 and included all piping in the areas of seismic concern in scope unless specifically

evaluated out. VCSNS also credited existing programs for aging management of added

components. 

The applicant further stated that the environments included in Table 1, Item #6 are not wet. 

Table 1, Item #6 includes interior of non-fluid containing carbon steel piping components. The

environments include dried air, process gasses (e.g., nitrogen), non-dried compressed air

(service air), condenser vacuum pump exhaust and connections for main steam(air removal),

and non-dried air from inside the plant. None of these environments is considered “aggressive”

and none of these systems’ pressure boundary is required for license renewal. Significant

internal corrosion is not expected for these applications, structural integrity will be maintained,

and the pressure boundary (though not required) will be maintained. Neither VCSNS nor the

industry have had any operating experience to indicate loss of structural integrity is a concern

for these material environment combinations.

The applicant clarified that Table 1, Item #4 is the external environment of carbon steel piping

systems. The applicant stated that VCSNS has conservatively included Item #4 piping within

the scope of the Inspections for Mechanical Components. Inspections for Mechanical
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Components is an inspection activity that will manage loss of material due to general and/or

galvanic corrosion on the external surface of susceptible materials such as carbon and low alloy

steel. The activity involves the visual examination of the exposed external surfaces of

mechanical components in areas of the plant containing components/component types in the

scope of license renewal. The applicant also stated that the external surfaces of components

should be dry and not subject to any significant corrosion; however, condensation, drips, spray,

leakage, and other external conditions may lead to aging that could require management. 

Provisions for removal of insulation to permit visual inspection are provided for selected

components. In addition, the applicant stated that this program will identify visible aging effects

and utilize the corrective action program to determine the extent and source of the degradation

and effect repairs and identify additional actions. Furthermore, the applicant stated that for

Table 1 Item 6 piping components that contain air and gasses, drips, spray, and leakage on the

internal surface are not postulated. Condensation may occur in air removal piping; however, its

effect is limited to corrosion on the bottom of the pipe. The applicant stated that even if a

through wall failure were to occur, it will not lead to a structural failure and the Inspections for

Mechanical Components will detect the through wall leak and repair the pipe. 

Therefore, in a response dated March 15, 2002, the applicant concluded that the VCSNS

position on Criteria 2 components were conservative when compared to the staff position on the

identification and treatment of structures, systems, and components that meet 10 CFR

54.4(a)(2) dated March 15, 2002. The applicant stated that VCSNS has included all piping,

ductwork, and insulation contained in seismic areas of the plant in scope unless it was

specifically evaluated out. Finally, the applicant stated that although pressure boundary is not

normally required, programs that manage pressure boundaries perform aging management of

most components included in the Criteria 2 Supplement. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has demonstrated that 1) VCSNS took a conservative approach to Criteria 2 and

included all piping in the areas of seismic concern in scope unless specifically evaluated out,

and that VCSNS has credited existing AMPs including the Inspections for Mechanical

Components program to manage the aging effects of the added components; and 2) neither

VCSNS nor the industry have had any operating experience to indicate loss of structural

integrity is a concern for the material environment combinations included in Table 1 Item 6.

In Item #7 of Table 1 in Criteria 2 Supplement under the “Discussion” column, the applicant

stated that raw water is part of uncontrolled water. However, the staff noted that loss of

material due to MIC and erosion in the raw water environment are not considered as applicable

aging effects/mechanisms for the components in Item #7. The staff also noted that for a

combination of components types/materials/environments in Item #11 that is consistent with

that of Item #7, loss of material due to MIC and erosion are considered to be applicable aging

effects/mechanisms for a raw water environment. During a telephone conference on

September 16, 2003, the staff requested the applicant to provide the basis, including

applicable operating experience, to justify the different AMR conclusions for components in

these two items. 

The staff also noted that for the aging management of the components considered in Item #11, 

the applicant credited the Service Water Reliability and In-Service Testing (B.1.9) to manage

the aging effects. For Item #7, the applicant utilized the Area Based Inspections for Refined 10

CFR 54.4(a)(2) Criteria (B.2.13). It should be noted that AMP B.1.9 is consistent with GALL
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AMP Open-Cycle Cooling Water System (XI.M20), which includes periodic inspections while

AMP B.2.13 uses one-time inspection. The staff requested the applicant to provide the basis,

including any applicable operating experience, to justify that periodic inspections are necessary

to manage the aging effects for Item #11, whereas one-time inspection is sufficient for the

aging management for Item #7.

In its response dated September 24, 2003, the applicant stated that Table 1, Item #7 includes

piping environments resulting from uncontrolled sources such as rainwater, leaking ground

water and water drained from equipment. For this discussion rainwater is not considered raw

water. The applicant also stated that these systems are not subject to erosion based on design

and operating conditions. Drain lines have very low flow rates; and safety and relief valves

have very limited operating time at design flow rates. The applicant further stated that piping on

the discharge of the non-nuclear plant drains [MD] sump pumps is exposed to raw water when

equipment is drained or from other sources. The applicant stated that the sump pump

discharge piping is the only piping in Item #7 that is normally filled. The applicant also stated

that leakage from the sump pump discharge piping is not a concern for license renewal. MIC

induced leakage will be detected and appropriate corrective action taken before the loss of

structural integrity. In addition, the applicant stated that other MD piping is normally dry or

partially wetted by drainage from non-raw water sources, such as condensate from air handling

units or rain. Furthermore, the applicant stated that systems included in Table 1, Item #7 (other

than MD) are not exposed to raw water. 

The applicant emphasized that Area Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria

is a new one-time inspection that will detect and characterize loss of material due to general,

crevice, and pitting corrosion resulting from exposure to an unmonitored and uncontrolled water

environment. If MIC is present it will also be detected. The applicant further stated that the

Area Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria was added to manage aging for

those components that were not suitable for inclusion into a program identified in the

Application. The applicant stated that the aging mechanisms are not expected to challenge the

structural integrity of these piping systems; therefore, a one-time inspection approach is applied

to confirm this conclusion. For those drain lines over sensitive components a one-time

inspection will be to predict the potential for through wall leakage occurring during the 60-year

plant life. In addition, the applicant stated that the inspections will determine if corrective

actions such as future inspections or repair will be required. Furthermore, the applicant clarified

that Inspections for Mechanical Components AMP is applicable for the exterior of these

components. Leakage in drain lines or the MD sump pump discharge due to degradation from

aging mechanisms such as crevice corrosion, pitting corrosion and MIC, would lead to

detectable external leakage prior to a loss of structural integrity. Finally, the applicant clarified

that Table 1 Item 11 is applicable to Service Water (SW). SW is a safety related system where

pressure boundary is required for license renewal and its aging effects are managed by the

Service Water System Reliability and In-service Testing Program. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has clarified that 1) MIC induced leakage will be detected and appropriate corrective

action taken before the loss of structural integrity, and that systems included in Table 1, Item #7

(other than MD) are not exposed to raw water; 2) the aging mechanisms of general, crevice,

pitting corrosion and MIC are not expected to challenge the structural integrity of these piping

systems; and therefore, a one-time inspection approach is applied to confirm this conclusion;
3-55

and 3) Table 1, Item #11 is applicable to SW for which the Service Water System Reliability and

In-service Testing Program will be utilized to manage the aging effects. 

In the discussion column of Item #16 of Table 1 in Criteria 2 Supplement, the applicant stated

that this grouping included fiberglass piping insulation exposed to a moist air environment. The

applicant further stated that at VCSNS the ambient environment did not contain contaminants

of sufficient concentration to cause aging effects that require aging management. However, the

staff noted that moisture infiltration into the fiberglass insulation materials may over time lead to

compression or settling of the fiberglass material. This may in turn lead to a reduction of the

insulating properties of the fiberglass. As a result, a different temperature distribution may arise

across the layer of fiberglass insulation material with a possibly lower temperature at the piping

/insulation interface. This may increase the likelihood of further moisture condensation and

consequently surface corrosion of the piping materials. During a telephone conversation on

September 16, 2003, the staff requested the applicant to clarify whether this aging effect is

applicable to the fiberglass piping insulation material for VCSNS and provide a basis, including

operating experience, for its conclusion. In addition, the staff requested the applicant to clarify

whether the fiberglass insulation material used at VCSNS has accompanying metal-foil based

(such as aluminum) vapor retarder component. If so, some parts of these metal-foil based

vapor retarder components may be in contact with the metallic surface (such as carbon steel) of

nearby metal piping of different material due to close spatial interaction. In the presence of

moisture this may give rise to galvanic corrosion. Therefore, the staff requested the applicant

to clarify whether loss of material due to galvanic corrosion is an applicable aging effect at

VCSNS arising from the process described above and provide a basis, including operating

experience, for its conclusion.

In its response dated September 24, 2003, the applicant stated that Table 1, Item #16 includes

fiberglass insulation on both stainless steel and carbon steel piping and ductwork. Fiberglass

insulation is used outside the reactor building. Insulation is included in the scope of license

renewal for potential interaction only. The insulating properties of insulation are not a license

renewal intended function. The applicant further stated that the structural aspects of plant

design (protective/mitigative features) that preclude an adverse impact on nuclear safetyrelated components due to flooding are also in the scope of license renewal. Outside the

reactor building, blockage of sumps does not adversely impact the plant flooding evaluations. 

In addition, the applicant clarified that three (3) types of insulation used inside the reactor

building include all stainless steel reflective insulation and two types of mass insulation

encapsulated in stainless steel. The stainless steel reflective insulation is used primarily on

piping. One type of mass insulation encapsulated in stainless steel is used only around the

reactor pressure vessel loop inlet and outlet nozzles and the portions of reactor coolant piping

that penetrate the primary shield wall. The other mass type encapsulated in stainless steel is

used on the pressurizer and steam generator level and flow instrument tubing. The applicant

stated that Insulation within the reactor building is included in Table 1, Item #5. Finally, the

applicant clarified that Inspections for Mechanical Components is an inspection activity that will

manage loss of material due to general and/or galvanic corrosion on the external surface of

susceptible materials such as carbon and low alloy steel. This program will manage effects of

condensate leaking from insulation on to carbon steel. The activity involves the visual

examination of the exposed external surfaces of mechanical components in areas of the plant

containing components/component types in the scope of license renewal. This program will

identify visible aging effects and will utilize the Corrective Action Program to effect repairs and

identify additional actions. 
3-56

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has demonstrated that 1) insulation is included in the scope of license renewal for

potential interaction only, and that the insulating properties of insulation are not a license

renewal intended function; and 2) the Inspections for Mechanical Components AMP will identify

visible aging effects and will utilize the Corrective Action Program to effect repairs and identify

additional actions. 

The aging effects identified in the LRA for systems, structures, and components under refined

Criterion 2 are consistent with industry operating experience for the materials and environments

listed. The staff finds that all the plausible aging effects were identified and that the aging

effects listed are appropriate for the combination of materials and environments specified.

Aging Management Programs

The applicant credited the following AMPs for managing the aging effects in the Criteria 2

systems: 

 Boric Acid Corrosion Surveillances (3.0.3.1)

 Chemistry Program (3.0.3.2)

 Flow-Accelerated Corrosion Monitoring Program (3.4.2.4.1),

 Inspections for Mechanical Components (3.0.3.7), 

 Service Water System Reliability and In-Service Testing Program (3.3.2.3.1),

 Area Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria Commodities (3.0.3.9).

The Boric Acid Corrosion Surveillances Program, the Chemistry Program, and the Inspections

for Mechanical Components are credited with managing the aging effects of several

components in different structures and systems and are, therefore, considered common aging

management programs. The staff has evaluated the additional information provided in the

Criteria 2 Supplement for these common AMPs and has found them to be acceptable for

managing the aging effects identified for these Criteria 2 systems. The staff’s evaluation of

these AMPs is documented in Sections 3.0.3.1, 3.0.3.2, and 3.0.3.7 of this SER.

The staff has evaluated the additional information provided in the Criteria 2 Supplement for the

system-specific AMPs Flow-Accelerated Corrosion Monitoring Program and Service Water

System Reliability and In-Service Testing Program and has found them to be acceptable for

managing the aging effects identified for these Criteria 2 systems. The staff’s evaluations of

these AMPs are documented in Sections 3.4.2.4.1 and 3.3.2.3.1 of this SER.

The staff has evaluated the new AMP Area Based Inspections for Refined 10 CFR 54.4(a)(2)

Criteria Commodities provided in Appendix B of the supplemental submittal and has found it to

be acceptable for managing the aging effects identified for these Criteria 2 systems. The staff’s

evaluation of this AMP is documented in Section 3.0.3.9 of this SER. 

After evaluating the applicant’s AMR for each of the components in the Criteria 2 systems, the

staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for these systems. For those components identified in Criteria 2

Supplement Table 1 that are consistent with LRA Table 3.3-1 , the staff verified that the

applicant credited the AMPs recommended by the GALL report. For the components identified

in Criteria 2 Supplement Table 1 that are different from or not addressed in GALL but are relied
3-57

on for license renewal, the staff verified that the applicant credited AMPs that are appropriate

for the identified aging effects. 

On the basis of its review, the staff finds that the AMPs credited in the LRA for the systems,

structures, and components under refined Criterion 2 will effectively manage or monitor the

aging effects identified in the LRA.

3.0.5.3 Conclusion

On the basis of its review, the staff concludes 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).

3.0.6 References

1. Letter from USNRC to SCE&G, “Request for Additional Information for the Review of the

V.C. Summer Nuclear Station License Renewal Application,” dated March 28, 2003. 

2. Letter from SCE&G to USNRC, “Responses to Request for Additional Information for the 

Review of the License Renewal Application for the Virgil C. Summer Nuclear Station,” dated 

June 16, 2003 (RC-03-0112).

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System

This section addresses the aging management of the components of the reactor vessel,

internals, and reactor coolant system. The systems that make up the reactor vessel, internals,

and reactor coolant system are described in the following SER sections:

• reactor coolant system (2.3.1.1)

• piping, valves and pumps (2.3.1.2)

• reactor vessel (2.3.1.3)

• reactor vessel internals (2.3.1.4)

• incore instrumentation system (2.3.1.5)

• pressurizer (2.3.1.6)

• steam generators (2.3.1.7)

The reactor coolant system (RCS) at the VCSNS consists of three primary coolant loops

interconnected at the reactor vessel. Each loop contains one reactor coolant pump (RCP), one

steam generator, valves, and interconnecting piping. The pressurizer, connected to one of the

hot legs, provides a means for controlling RCS pressure changes during reactor operations. 

The RCS also contains piping and components that allow venting of the reactor vessel and

pressurizer.

The reactor coolant piping at VCSNS consists of non-Class 1 and Class 1 components. The

applicant describes the system boundaries for the non-Class 1 components and Class 1 reactor

coolant (RC) piping and associated components in LRA Section 2.3.1, Reactor Vessel,

Internals and Reactor Coolant System.” The non-Class 1 portions of the RCS (excluding the
3-58

RCP motor oil collection subsystem) are relied upon to provide system pressure boundary

integrity. In addition, the orifices on the non-Class 1 piping are relied upon to provide throttling. 

The results from the AMR for the non-Class 1 portions of the RCS are described in Section 3.1,

“Reactor Vessel, Internals, and Reactor Coolant System,” LRA Section 3.2, Engineered Safety

Features,” and LRA Section 3.3, Auxiliary Systems,” and are summarized in LRA Tables 3.1-1,

3.1-2, 3.2-1, 3.2-2, 3.3-1, and 3.3-2. The staff’s evaluation of LRA Sections 3.2 and 3.3 is

described, in Section 3.2 and 3.3, respectively, of this SER.

The applicant’s AMR evaluations of the components in each of the seven RCS subsystems,

except for several non-Class I and a few Class 1 RCS components, are provided in either LRA

Table 3.1-1 or LRA 3.1-2. LRA Table 3.1-1 contains 35 items. The scope of AMR Items

18 through 35 of LRA Table 3.1-1 provides the AMR results that are consistent with GALL and

for which GALL has concluded that no additional evaluation is necessary beyond that which is

provided (discussed) in the AMR entry for the component in the corresponding GALL evaluation

table. The staff’s evaluation of LRA Table 3.1-1, Items 18 through 35 is provided in Sections

3.1.2.1 and 3.1.2.4 of this SER. The scope of AMR Items 1 through 17 of LRA Table 3.1-1

provides the AMR results that are consistent with GALL and for which the corresponding AMR

analysis in the GALL evaluation table has concluded is in need of additional evaluation. The

staff’s evaluation of LRA Table 3.1-1, Items 1 through 17 is described in Sections 3.1.2.2 and

3.1.2.4 of this SER.

The scope of LRA Table 3.1-2 consists of the AMR results for RCS components that are

different from the GALL Report, or not evaluated in the GALL Report. The applicant has

determined that the materials, environment, and aging effects for components in Table 3.1-2

are similar to those in GALL and proposes to manage the aging effects with the appropriate

GALL AMP. The staff’s evaluation of the AMRs for these components is included in Section

3.1.2.4 of this SER. In addition, the AMR for several non-Class 1 and a few Class 1 RCS

components is presented in Tables 3.2-1, 3.2-2, 3.3-1, and 3.3-2 of the LRA.

The staff’s evaluations of the AMPs that are specific to the RCS at VCSNS are provided in the

following subsections to Section 3.1.2.3 of this SER:

• Alloy 600 Aging Management Program (3.1.2.3.1)

• Bottom-mounted Instrumentation Inspection Program (3.1.2.3.2)

• Inservice Inspection Plan (3.1.2.3.3)

• Reactor Head Closure Studs Program (3.1.2.3.4)

• Steam Generator Management Program (3.1.2.3.5)

• Reactor Vessel Surveillance Program (3.1.2.3.6)

• Reactor Vessel Internals Inspection Program (3.1.2.3.7)

• Small Bore Class I Piping Inspection Program (3.1.2.3.8)

• Thermal Fatigue Program (3.1.2.3.9)

3.1.1 Summary of Technical Information in the Application

The description of the systems that comprise the reactor vessel, internals, and reactor coolant

system can be found in LRA Sections 2.3.1 and 3.1.1. The passive, long-lived components in

these systems that are subject to an AMR are identified in LRA Tables 2.3-1 to 2.3-7. The

applicant described the VCSNS AMRs for the reactor vessel, internals, and reactor coolant
3-59

system in LRA Section 3.1. For several non-Class 1 RCS components, the applicant described

its AMRs in LRA Sections 3.2 and 3.3.

The applicant followed the methods described in Section 4.2 of Nuclear Energy Institute (NEI)

95-10 for determining the aging effects for reactor vessel, internals, and reactor coolant system

components. In addition, the applicant applied the information contained in NRC-approved

industry generic topical reports for identifying the components requiring aging management and

the related AMPs. NRC-approved industry generic topical reports are discussed in

Section 3.1.2.1 of the LRA.

The applicant’s AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of (1) the Corrective Action

Program, (2) licensee event reports, (3) maintenance rule database, and (4) interviews with

systems engineers to identify aging effects that require management. These reviews

concluded that the aging effects requiring management, based on the VCSNS operating

experience, were consistent with aging effects identified using the methods described in the

preceding paragraph.

The applicant’s review of industry operating experience included a review of operating

experience since the effective date of NUREG-1801. No additional aging effects requiring

management were identified beyond those identified using the methods described earlier in this

section. The applicant’s ongoing review of plant-specific and industry-wide operating

experience is conducted in accordance with the VCSNS Operating Experience Program.

3.1.2 Staff Evaluation

In LRA Section 3.1, the applicant described its AMRs for the reactor vessel, internals, and

reactor coolant system at VCSNS. The staff reviewed LRA Section 3.1 to determine whether

the applicant had provided sufficient information to demonstrate that the effects of aging will be

adequately managed so that the intended functions will be maintained consistent with the CLB

throughout the period of extended operation, in accordance with the requirements of 10 CFR

54.21(a)(3), for the reactor vessel, internals, and reactor coolant system components that are

determined to be within the scope of license renewal and subject to an AMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of reactor system components for license renewal, as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

applicable, and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the FSAR

Supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the reactor system components.

In LRA Section 3.1, the applicant provided brief descriptions of the reactor systems and

summarized the results of its AMR of the reactor systems at VCSNS.
3-60

Table 3.1-1, below, provides a summary of the staff’s evaluation of the aging effects and AMPs

for the components of the RCS subsystems that are discussed in LRA Section 3.1, evaluated

by the applicant in Table 3.1-1 of the LRA, and addressed by the staff in the GALL Report.

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

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

Reactor coolant

pressure boundary

components

Cumulative

fatigue damage 

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

10 CFR 54.21(c)(1)(i)

Analyses remain

valid

Consistent with GALL

which recommends

further evaluation. 

(See Section 3.1.2.2.1,

below.)

Steam generator shell

assembly

Loss of material

due to pitting and

crevice corrosion

Inservice

inspection; water

chemistry

Chemistry Program

(Appendix B.1.4); ISI

Plan

(Appendix B.1.7)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.2,

below.)

Pressure vessel ferritic

materials that have a

neutron fluence greater

than 1017 n/cm2

(E>1 MeV)

Loss of fracture

toughness due to

neutron

irradiation

embrittlement

TLAA, evaluated in

accordance with

Appendix G of

10 CFR 50 and

RG 1.99

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.3,

below.)

Reactor vessel beltline

shell and welds 

Loss of fracture

toughness due to

neutron

irradiation

embrittlement

Reactor vessel

surveillance 

Reactor Vessel

Surveillance

Program (Appendix

B.1.24)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.4,

below.)

Westinghouse and

B&W baffle/former

bolts

Loss of fracture

toughness due to

neutron

irradiation

embrittlement and

void swelling

Plant-specific Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.5,

below)

Small bore reactor

coolant system and

connected systems

piping

Crack initiation

and growth due to

SCC, IGSCC, and

thermal and

mechanical

loading

Inservice

inspection; water

chemistry; onetime inspection

Small Bore Class 1

Piping Inspection

Program 

(Appendix B.2.7); the

Chemistry Program

(Appendix B.1.4);

and ISI Plan

(Appendix B.1.7)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.6,

below.)

Vessel shell Crack growth due

to cyclic loading

TLAA Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.7,

below.)

Reactor internals Changes in

dimension due to

void swelling

Plant-specific Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.8,

below.)
Table 3.1-1 Staff Evaluation Table for Reactor System Components in the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-61

PWR core support

pads, instrument tubes

(bottom head

penetrations),

pressurizer spray

heads, and nozzles for

the steam generator

instruments and drains

Crack initiation

and growth due to

SCC and/or

PWSCC

Plant-specific Alloy 600 Aging

Management

Program which

includes the

(Appendix B.1.1);

Chemistry Program

(Appendix B.1.4);

and ISI Plan 

(Appendix B.1.7)

Consistent with GALL,

which recommends

further evaluation. 

(See Section 3.1.2.2.9,

below.)

Cast austenitic

stainless steel (CASS)

in reactor coolant

system piping

Crack initiation

and growth due to

SCC 

Plant-specific Chemistry program

(Appendix B.1.4) and

in-service inspection

plan (Appendix

B.1.7)

Consistent with GALL,

which recommends

further evaluation (See

Section 3.1.2.2.10,

below.)

Pressurizer

instrumentation

penetrations and

heater sheaths and

sleeves made of Nickel

alloys

Crack initiation

and growth due to

PWSCC 

Inservice

inspection; water

chemistry

Alloy 600 aging

management

program which

includes the Water

Chemistry Program

(Appendix B.1.1)

Consistent with GALL,

which recommends

further evaluation. 

(See Section

3.1.2.2.11, below.)

Westinghouse and

B&W baffle former

bolts

Crack initiation

and growth due to

SCC and IASCC

Plant-specific Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4);

Chemistry program

(Appendix B.1.4)

Consistent with GALL,

which recommends

further evaluation. 

(See Section

3.1.2.2.12, below.)

Westinghouse and

B&W baffle former

bolts

Loss of preload

due to stress

relaxation

Plant-specific Reactor Vessel

Internals Inspection 

Program

(Appendix B.2.4)

Consistent with GALL,

which recommends

further evaluation. 

(See Section

3.1.2.2.13, below.)

Steam generator

feedwater impingement

plate and support

Loss of section

thickness due to

erosion 

Plant-specific Applicant states that

these components

do not have license

renewal function for

VCSNS

Consistent with GALL,

which recommends

further evaluation. 

(See Section

3.1.2.2.14, below.)

(Alloy 600) Steam

generator tubes, repair

sleeves, and plugs 

Crack initiation

and growth due to

PWSCC,

ODSCC, and/or

IGA or loss of

material due to

wastage and

pitting corrosion

and fretting and

wear, or

deformation due

to corrosion

at tube support

plate

intersections

Steam generator

tubing integrity;

water chemistry

Chemistry Program

(Appendix B.1.4);

Steam Generator

Management

Program

(Appendix B.1.10)

Consistent with GALL,

which recommends

further evaluation. 

(See Section

3.1.2.2.15, below.)
Table 3.1-1 Staff Evaluation Table for Reactor System Components in the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-62

Tube support lattice

bars made of carbon

steel

Loss of section

thickness due to

FAC

Plant-specific None This is not an

applicable aging effect

because it applies only

to Combustion

Engineering steam

generators.

Carbon steel tube

support plate

Ligament

cracking due to

corrosion

Plant-specific None This is not an

applicable aging effect

because the VCSNS

tube support plates are

made of Type 405

stainless steel, not

carbon steel.

Steam generator

feedwater inlet ring and

supports

Loss of material

due to FAC

Combustion

engineering (CE)

steam generator

feedwater ring

inspection

None This is not an

applicable aging effect

because it applies only

to Combustion

Engineering steam

generators.

Reactor vessel closure

studs and stud

assembly

Crack initiation

and growth due to

SCC and/or

IGSCC

Reactor head

closure studs

Reactor Head

Closure Studs

Program (Appendix

B.1.8)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

CASS pump casing

and valve body

Loss of fracture

toughness due to

thermal aging

embrittlement

Inservice

inspection

Inservice Inspection

Plan (Appendix

B.1.7)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

CASS piping and

fittings

Loss of fracture

toughness due to

thermal aging

embrittlement

Thermal aging

embrittlement of

CASS

None (See Section

3.1.2.4.2 of this SER

for discussion.)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.4.2,

below.)

PWR piping and

fittings; and steam

generator components

Wall thinning due

to FAC

Flow-accelerated

corrosion 

None (See Section

3.1.2.4.7 of this SER

for discussion.)

VCSNS has not

identified wall thinning

due to FAC as an

applicable aging effect

for its steam generator

components (See

Section 3.1.2.4.7,

below.)

Reactor coolant

pressure boundary

(RCPB) valve closure

bolting, manway and

holding bolting, and

closure bolting in high

pressure and high

temperature systems 

Loss of material

due to wear, loss

of preload due to

stress relaxation,

crack initiation

and growth due to

cyclic loading

and/or SCC 

Bolting integrity Inservice Inspection

Plan (Appendix

B.1.7)

A discussion of the

applicability of the ISI

program for bolting is

provided in SER

Section 3.1.2.3.3.)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below). Loss of

material due to wear

for the CRD flange

bolting is further

discussed in SER

Section 3.1.2.4.3
Table 3.1-1 Staff Evaluation Table for Reactor System Components in the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

3-63

CRD nozzle Crack initiation

and growth due to

PWSCC 

Nickel alloy

nozzles and

penetrations; water

chemistry

Alloy 600 Aging

Management

Program which

includes water

chemistry program

(Appendix B.1.1)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Reactor vessel nozzles

safe ends and CRD

housing and reactor

coolant system

components (except

CASS and bolting)

Crack initiation

and growth due to

cyclic loading,

and/or SCC, and

PWSCC 

Inservice

inspection; water

chemistry

Chemistry Program

(Appendix B.1.4); ISI

Plan (Appendix

B.1.7); Alloy 600 

AMP (Appendix

B.1.1) 

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Reactor vessel

internals CASS

components 

Loss of fracture

toughness due to

thermal aging,

neutron

irradiation

embrittlement,

and void swelling

Thermal aging and

neutron irradiation

embrittlement 

None VCSNS does not have

any CASS internals

that are within the

scope of license

renewal.

External surfaces of

carbon steel

components in reactor

coolant system

pressure boundary

Loss of material

due to boric acid

corrosion

Boric acid

corrosion 

Boric Acid Corrosion

Surveillances

Program 

(Appendix B.1.2)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Steam generator

secondary manways

and handholds

Loss of material

due to erosion

Inservice

inspection

None Applies only to B&W 

steam generators. 

VCSNS has

Westinghouse steam

generators.

Reactor internals,

reactor vessel closure

studs, and core support

pads

Loss of material

due to wear

Inservice

inspection

Reactor Vessel

Internals Inspection

Program 

(Appendix b.2.4);

Inservice Inspection

Plan (Appendix

B.1.7); Bottommounted

Instrumentation

Inspection Program

(Appendix B.1.3)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Pressurizer integral

support

Crack initiation

and growth due to

cyclic loading

Inservice

inspection

Inservice Inspection

Plan (Appendix

B.1.7)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Upper and lower

internals assembly

(Westinghouse)

Loss of preload

due to stress

relaxation

Inservice

inspection; loose

part and/or neutron

noise monitoring

Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4)

which includes a VT3 inspection in lieu of

the loose parts

monitoring program

Consistent with GALL,

except for the loose

parts monitoring

program. GALL

recommends no further

evaluation. (See

Sections 3.1.2.1 and

3.1.2.3.6, below.)
Table 3.1-1 Staff Evaluation Table for Reactor System Components in the GALL Report

Component Group Aging Effect/

Mechanism

AMP in GALL

Report

AMP in LRA Staff Evaluation

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Reactor vessel

internals in fuel zone

region (except

Westinghouse and

B&W baffle bolts)

Loss of fracture

toughness due to

neutron

irradiation

embrittlement and

void swelling

PWR vessel

internals

Reactor Vessel

Internals Inspection

Program

 which includes water

chemistry (Appendix

B.2.4)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Steam generator upper

and lower heads; 

tubesheets; primary

nozzles and safe ends

Crack initiation

and growth due to

SCC, PWSCC.

IASCC

Inservice 

inspection;

water chemistry

Chemistry program

(Appendix B.1.4);

Inservice Inspection

Plan

(Appendix B.1.7),

and Alloy 600 aging

management plan

(Appendix B.1.1) 

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Vessel internals

(except Westinghouse

and B&W baffle former

bolts)

Crack initiation

and growth due to

SCC and IASCC

PWR vessel

internals; water

chemistry

Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4);

Chemistry Program

(Appendix B.1.4)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Reactor internals (B&W

screws and bolts)

Loss of preload

due to stress

relaxation

Inservice

inspection; loose

part monitoring

Applies only to B&W

Plant. VCSNS is a

Westinghouse plant. 

Reactor vessel closure

studs and stud

assembly

Loss of material

due to wear

Reactor head

closure studs

Reactor Head

Closure Studs

Program (Appendix

B.1.8)

Consistent with GALL,

which recommends no

further evaluation. 

(See Section 3.1.2.1,

below.)

Reactor internals

(Westinghouse upper

and lower internal

assemblies; CE bolts

and tie rods)

Loss of preload

due to stress

relaxation

Inservice

inspection; loose

parts monitoring

Reactor Vessel

Internals Inspection

Program

(Appendix B.2.4)

which includes a VT3 inspection in lieu of

the loose parts

monitoring program.

Consistent with GALL,

with the exception of

the loose parts

monitoring program;

GALL recommends no

further evaluation. 

(See Sections 3.1.2.1

and 3.1.2.3.6 below.)

3.1.2.1 Aging Management Evaluations in the GALL Report that are Relied on for License

Renewal, that Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plant. The staff also identified several areas

where additional information or clarification was needed. The staff’s evaluation of applicants

responses to those RAIs is included in Section 3.1.2.4 of this SER. 

On the basis of its review of the inspection results, the staff verified the applicant’s claim of

consistency with the GALL report. The staff finds that the applicant has demonstrated that the

effects of aging for these components will be adequately managed so that their intended
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functions will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2 Aging Management Evaluations in the Gall Report That Are Relied on for License

Renewal, for Which Gall Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant’s

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

3.1.2.2.1 Cumulative Fatigue Damage

Fatigue is a time-limited aging analysis (TLAA) as defined in 10 CFR 54.3. The staff’s

evaluation of this TLAA is provided in Section 4.3 of this SER.

3.1.2.2.2 Loss of Material Due to Pitting and Crevice Corrosion

The SRP-LR (NUREG-1800) identifies loss of material due to pitting and crevice corrosion as

an aging effect that could occur in the low-alloy steel SG shell assembly. The GALL Report

recommends further evaluation of the effectiveness of the applicant’s AMP to ensure that this

aging effect is adequately managed. To manage this aging effect, the GALL Report identifies

the appropriate AMP as GALL AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections

IWB, IWC, and IWD” and GALL AMP XI.M2, “Water Chemistry” for pressurized water reactor

(PWR) secondary water. The GALL Report also cites NRC Information Notice (IN) 90-04,

“Cracking of the Upper Shell-to-Transition Cone Girth Welds in Steam Generators,” which

describes weld-zone cracking observed in the field that initiated at surface corrosion pits. 

IN 90-04 states that if general corrosion pitting of the SG shell is known to exist, the

requirements of ASME Section XI may not be sufficient to differentiate isolated cracks from

inherent geometric conditions. IN 90-04 recommends enhanced UT procedures and the

additional use of visual and magnetic particle testing (MT), as necessary, to detect surfaceconnected flaws.

The applicant addressed this aging effect in LRA Table 3.1-1, AMR Item 2. In its discussion,

the applicant stated that IN 90-04 contains only a general indication that surface pits serve as

crack initiation sites and does not indicate that pitting corrosion results in sufficient degradation

to cause loss of component function. The applicant further stated that no subsequent industry

experience has further identified pitting corrosion resulting in reportable indications for the SG

shell. The applicant indicated that cracking in the SG shell caused by flaw growth is managed

by its Inservice Inspection Plan (ISI) and general, pitting, and crevice corrosion are managed by

its Chemistry Program.

The applicant stated that its ISI Plan is consistent with GALL AMP XI.M1, which, in turn, is

based upon ASME Section XI, “Rules for Inservice Inspection of Nuclear Power Plant
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Components,” Subsections IWB, IWC, and IWD. However, GALL AMP XI.M1 states, “in certain

cases, the ASME Inservice Inspection Plan is to be augmented to manage effects of aging for

license renewal ....” 

In RAI 3.1.2.2.2-1, the staff requested the applicant to provide an enhanced condition

monitoring program that can reliably detect pitting and crevice corrosion at the inside surface of

the SG girth welds so that loss of material is effectively managed. In its response to RAI

3.1.2.2.2-1, dated June 12, 2003, the applicant stated that an enhanced condition monitoring

program is not needed because (1) pitting corrosion reported in IN 90-04 did not result in

sufficient degradation to cause loss of component intended function, and (2) no subsequent

industry experience has further identified pitting corrosion resulting in reportable indications for

the SG shell. 

The staff found the applicant’s response insufficient because the volumetric examination of the

shell welds, as required by ASME Section XI, is designed for detecting cracking and not pits. In

a discussion with the applicant on June 22, 2003, the staff requested that the applicant perform

a one-time inspection before entering into license renewal operation to verify whether loss of

material due to pitting and crevice corrosion is present on the inside surface of the SG shell. If

present, the applicant would need to provide an enhanced inspection plan to monitor loss of

material due to pitting corrosion and ensure that the component intended function will be

maintained during the extended period. In its additional response to RAI 3.1.2.2.2-1, in a letter

dated September 2, 2003, the applicant stated that each steam generator secondary-side

inspection does include a visual inspection of the accessible portions of the shell. The applicant

performs steam generator secondary-side inspections periodically. If loss of material due to

pitting corrosion is found in the inside surface of the SG shell, the applicant will take corrective

actions to mitigate and control the corrosion problem under its Steam Generator Management

Program as discussed in LRA B.1.10. The staff finds the applicant’s response to RAI

3.1.2.2.2-1 acceptable. The staff’s review of the Steam Generator Management Program is

discussed in Section 3.1.2.3.5 of this safety evaluation. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of material due to crevice and pitting corrosion for the

steam generator shell assembly, as recommended in the GALL report. Since the applicant’s

AMR results are otherwise consistent with the GALL report, the staff finds that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

functions will be maintained by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement (TLAA)

Certain aspects of neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3. 

The staff’s evaluation of these TLAAs are provided in Section 4.2 of this SER.

3.1.2.2.4 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement

Loss of fracture toughness due to neutron irradiation embrittlement could occur in the reactor

vessel. The Reactor Vessel Surveillance Program monitors neutron irradiation embrittlement of

the reactor vessel. Reactor Vessel Surveillance Programs are plant-specific, depending on

matters such as the composition of limiting materials, availability of surveillance capsules, and

projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant is
3-67

required to submit its proposed withdrawal schedule for approval prior to implementation. Thus,

further staff evaluation is required for license renewal. The GALL Report recommends further

evaluation of the Reactor Vessel Surveillance Program for the period of extended operation. 

The staff verifies that the applicant has proposed an adequate Reactor Vessel Surveillance

Program for the period of extended operation.

VCSNS has an existing Reactor Vessel Surveillance Program, described in LRA

Section B.1.24, for managing loss of fracture toughness in reactor vessel beltline shell and

welds due to neutron irradiation embrittlement. This program is consistent with GALL

AMP XI.M31, Reactor Vessel Surveillance Program. The evaluation of this existing program is

presented in Section 3.1.2.3.6 of this SER. The applicant stated that the VCSNS Reactor

Vessel Surveillance Program will manage radiation embrittlement by addressing the most

limiting subcomponents with respect to exposure to the greatest fluence postulated to occur

during the period of extended operation. The applicant concluded that upper shell and nozzles

are not limiting components for neutron irradiation embrittlement due to their physical distance

from the active fuel assembly. This is further evaluated in Section 3.1.2.3.6 of this SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of fracture toughness due to neutron irradiation

embrittlement for components in the reactor systems, as recommended in the GALL report. 

Since the applicant’s AMR results are otherwise consistent with the GALL report, the staff finds

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 current licensing basis for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.5 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void 

Swelling

Loss of fracture toughness due to neutron irradiation embrittlement and void swelling could

occur in Westinghouse and Babcock & Wilcox (B&W) baffle/former assembly bolts. The GALL

Report states that the applicant is to provide a plant-specific AMP to manage this potential

aging effect. Acceptance criteria are described in BTP RLSB-1 (Appendix A of the SRP-LR). 

The staff has reviewed the applicant’s proposed program to ensure that an adequate program

is in place to manage these aging effects.

VCSNS has instituted a new program, the Reactor Vessel Internals Inspection program (LRA

B.2.4), to manage loss of fracture toughness in the baffle/former assembly bolts. The loss of

fracture toughness has significant consequences only if cracks are present in the bolts. 

Therefore, the program manages loss of fracture toughness by inspecting for cracking. The

program relies on the use of visual and volumetric examination techniques to detect cracking. 

For accessible components, a visual inspection will be performed to detect the presence and

extent of cracking. For inaccessible locations, such as a juncture of baffle/former bolt head and

shank, a volumetric inspection will be performed to detect cracking. According to the

acceptance criteria for bolts, any detectable crack indication is unacceptable for a particular

bolt. This program assumes sufficient redundancy in bolt functions so that the plant can

continue to function safely with fewer than 100 percent of the bolts intact. The staff finds that

this approach is consistent with the one described in NUREG-1801, Section XI.M16, “PWR

Vessel Internals.” The evaluation of this new program is presented in Section 3.1.2.3.7 of this

SER.
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On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of fracture toughness for the baffle and former bolts, as

recommended in the GALL report. Since the applicant’s AMR results are otherwise consistent

with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.2.6 Crack Initiation and Growth Due to Stress-Corrosion Cracking, Intergranular Stress 

Corrosion Cracking, and Thermal and Mechanical Loading

Crack initiation and growth due to thermal and mechanical loading or SCC (including

intergranular stress corrosion cracking [IGSCC]) could occur in smallbore reactor coolant

system and connected system piping less than normal pipe size (NPS) 4. The existing program

relies on ASME Section XI Inservice inspection and on the 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 that the component intended function

will be maintained during the extended period. The AMPs should be augmented for verifying

that service-induced weld cracking is not occurring in the smallbore 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 that the component

intended function will be maintained during the period of extended operation. GALL AMP

XI.M32, One-Time Inspection” contains an acceptable verification method. 

The GALL Report recommends that the inspection include a representative sample of the

system population, and, where practical and prudent, focus on the bounding or lead

components most susceptible to aging due to time in service, severity of operating conditions,

and lowest design margin. For smallbore piping, actual inspection locations should be based

on physical accessibility, exposure levels, NDE examination techniques, and locations identified

in IN 97-46, “Unisolable Crack in High-Pressure Injection Piping.” Combinations of NDE,

including visual, ultrasonic, and surface techniques, are performed by qualified personnel

following procedures consistent with the ASME Code and 10 CFR Part 50, Appendix B. For

smallbore piping less than NPS 4, including pipe, fittings, and branch connections, a plantspecific destructive examination or NDE that permits inspection of the inside surfaces of the

piping should be conducted to ensure that cracking has not occurred. Follow up of

unacceptable inspection findings should include expansion of the inspection sample size and

locations. The inspection and test techniques prescribed by the program should verify the

existence of any aging effects because these techniques, used by qualified personnel, have

been proven effective and consistent with staff expectations. 

The staff’s review confirms that the program includes measures to verify that unacceptable

degradation is not occurring, thereby validating the effectiveness of existing programs, or

confirming that there is no need to manage aging-related degradation for the period of

extended operation. If an applicant proposes a one-time inspection of selected components

and susceptible locations to ensure that cracking is not occurring, the reviewer verifies that the

proposed inspection will be performed using techniques consistent with ASME Code and

American Society for Testing and Materials (ASTM) standards, including visual, ultrasonic, and
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surface techniques, to ensure that the component intended function will be maintained during

the period of extended operation.

The applicant has proposed a new program, “Small Bore Class 1 Piping Inspections,” along

with two existing programs, the Chemistry Program and Inservice Inspection Plan, to manage

cracking on the inside surface of the small bore Class 1 piping. This group of programs is

consistent with the group of programs recommended by GALL. The new program is consistent

with GALL AMP XI.M32. The evaluation of the new program is presented in Section 3.1.2.3.8

of this SER. Since the current volumetric examination methods are not reliable for detecting

flaws at the inside surface of the small diameter piping, the applicant proposes a use of

destructive testing of selected samples of the piping for more reliable inspection. The program

will identify the locations most susceptible to cracking based on engineering evaluation,

operating experience, current code requirements, and industry initiatives. Actual inspection

locations will be selected based on physical accessibility, exposure levels, and scheduling

requirements. The applicant further stated that the inspection locations will be selected by

engineering judgment, using risk-based approaches. The applicant has identified the

information sources that will be used in identifying the susceptible locations and in selecting the

sample locations for inspections. In response to an RAI asking the applicant whether it will

follow the EPRI-sponsored industry activities and whether the inspection locations would be the

bounding locations, the applicant stated that VCSNS intends to follow and implement the

recommendations of industry initiatives by the EPRI sponsored Materials Reliability Program

(MRP) Industry Task Group (ITG) on Thermal Fatigue on small bore piping. The applicant

further stated that the locations selected for inspection would be representative of the bounding

locations. The staff finds this response acceptable because implementation of the

recommendations of the EPRI-sponsored program, which is the main industry activity related to

smallbore piping, and inspection of bounding locations would provide assurance that the

smallbore piping will be safely operated during the extended period of operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation and growth due to thermal and mechanical

loading or stress corrosion cracking for small-bore reactor coolant system and connected

system piping, as recommended in the GALL report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.7 Crack Growth Due to Cyclic Loading

Crack growth due to cyclic loading could occur in the reactor vessel shell. Growth of

intergranular separations (underclad cracks) in low-alloy or carbon steel heat-affected zones

under austenitic stainless steel cladding is a TLAA that is to be evaluated for the period of

extended operation for all the SA 508-Cl 2 forgings where the cladding was deposited using

high heat input welding process. The methodology for evaluating underclad flaws should be

consistent with the current well established flaw evaluation procedures and criterion in the

ASME Section XI Code. Section 4.7, “Other Plant-Specific Time-Limited Aging Analysis,” of the

SRP-LR provides generic guidance for meeting the requirements of 10 CFR 54.21(c). The

GALL Report recommends further evaluation of programs to manage crack growth due to cyclic

loading in the reactor vessel shell and reactor coolant system piping and fittings. 
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In LRA Table 3.1-1, AMR Item 7, the applicant stated that the VCSNS vessel is constructed of

ASME SA 533 Grade B, Cl 1 plate material and not ASME SA 508 Cl 2 forgings. Therefore, the

aging effect of growth of underclad cracking is not applicable to the VCSNS vessel. However,

Table 5.2-8 of the VCSNS UFSAR identifies SA 508 Cl 2 as one of the materials for reactor

vessel shell, flange, and nozzle forgings and nozzle safe ends. In response to RAI 3.1.2.2.7-1,

the applicant clarified this discrepancy by stating that the reactor vessel shell (upper,

intermediate, and lower shell including beltline welds) is not made of ASME SA 508, Cl 2

material. Therefore, crack growth due to cyclic loading is not an applicable aging effect for the

reactor vessel shell. The applicant further stated that the vessel flange and nozzle forgings are

made of ASME SA 508, Cl 2 material; however, a high heat input welding process was not

utilized on the cladding. Therefore, the staff agreed that underclad cracking is not an applicable

aging effect for these forgings because the high heat input welding processes affecting

underclad cracking (i.e., strip clad and manual inert gas cladding processes) were not used to 

apply cladding to these components.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack growth due to cyclic loading for components in the

reactor systems, as recommended in the GALL report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.8 Changes in Dimension Due to Void Swelling

Changes in dimension due to void swelling could occur in the PWR reactor internals. The

GALL Report states that the applicant is to provide a plant-specific AMP or participate in

industry programs to investigate aging effects and determine an appropriate AMP. Otherwise,

the applicant is to provide the basis for concluding that void swelling is not an issue for the

component. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of the SRP-LR). 

The staff has reviewed the applicant’s proposed program to ensure that an adequate program

is in place to manage these aging effects.

VCSNS has instituted a new program, the Reactor Vessel Internals Inspection Program (LRA

B.2.4), to manage changes in dimension due to void swelling, which could occur in the PWR

reactor vessel internals. This new program is consistent with GALL AMP XI.M16, “PWR Vessel

Internals.” The evaluation of this program is provided in Section 3.1.2.3.7 of this SER. The

program relies on the use of visual and volumetric examination techniques to detect changes in

dimensions. For accessible components, enhanced visual inspections will be performed to

detect the presence and extent of changes in dimensions. For bolts and other inaccessible

components, a volumetric inspection will be performed to detect the presence and extent of

changes in dimensions due to irradiation creep and void swelling. The applicant further noted

that, with respect to changes in dimensions due to void swelling, industry activities are

underway to determine whether this is an aging effect requiring management for license

renewal, and, if necessary, to develop and qualify methods for detection and management. 

The applicant will continue to monitor these activities and implement the resulting methods, as

necessary. The applicant stated that specific acceptance criteria for changes in dimension due

to void swelling will be determined by analysis as part of the inspection plan. The staff finds the

applicant's approach for managing changes in dimension due to void swelling acceptable
3-71

because the approach will be based on the guidelines developed by the ongoing industry

activities related to void swelling. VCSNS will develop and implement reactor vessel internal

inspection program prior to the period of extended operation and will implement aging

management activities that are acceptable to the staff. The applicant has agreed that this is a

licensee commitment and this commitment is documented in Appendix A of the SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of changes in dimension due to void swelling for the baffle and

former plates, as recommended in the GALL report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.9 Crack Initiation and Growth Due to Stress Corrosion Cracking and/or Primary Water 

Stress-Corrosion Cracking

Crack initiation and growth due to SCC and primary water stress-corrosion cracking (PWSCC)

could occur in PWR core support pads (or core guide lugs), instrument tubes (bottom head

penetrations), pressurizer spray heads, and nozzles for the SG instruments and drains. The

GALL Report recommends further evaluation to ensure that these aging effects are adequately

managed. The GALL Report recommends that a plant-specific AMP be evaluated because

existing programs may not be capable of mitigating or detecting crack initiation and growth due

to SCC. Acceptance criteria are described in BTP RLSB-1 (Appendix of the SRP-LR). The

staff reviewed the applicant’s proposed program to ensure that an adequate program will be in

place for the management of these aging effects.

In LRA Table 3.1-1, AMR Item 9, the applicant includes two Nickel alloy components, core

support pads, and bottom head penetrations. The applicant credits (1) the Alloy 600 AMP (LRA

Appendix B.1.1), (2) the Chemistry Program (LRA Appendix B.1.4) and, (3) the ISI Plan (LRA

Appendix B.1.7) to manage crack initiation and growth due to PWSCC of these components. In

LRA Appendix B.1.1, the applicant stated that the Alloy 600 AMP is consistent with GALL AMP

XI.M11. However, according to Table 3.1-1 of NUREG-1800, the GALL AMP XI.M11 is credited

for managing cracking only in control rod drive (CRD) nozzles (i.e., vessel head penetrations)

and no other nickel alloy components. The staff issued RAI 3.1.2.2.9-1 requesting the applicant

to clarify this discrepancy. In response to RAI 3.1.2.2.9-1, in a letter dated June 12, 2003, the

applicant stated that the Alloy 600 AMP at VCSNS includes, in addition to the vessel head

penetrations, the other Alloy 600 components. The staff finds this clarification about the scope

of the program acceptable. However, it was not clear to the staff whether all Alloy 82/182 welds

are within the scope of the program. The staff raised this question during a June 22, 2003,

conference call. In response, the applicant stated that aging management of ASME Class 1

dissimilar welds (Alloy 82/182 welds) is within the scope of LRA Appendix B.1.1, the Alloy 600

AMP. The staff finds the response acceptable because it is consistent with the corresponding

AMR results presented in LRA Tables 3.1-1 and 3.1-2. The additional components and weld

locations that are within the scope of the Alloy 600 AMP are listed in Section 3.1.2.3.1 of this SER.

The ISI Plan specifies ASME Section XI VT-3 examination to detect cracking of the core

support pads. However, the staff does not believe that the VT-3 examinations are sufficient. 

The applicant needs to describe an AMP for managing cracking in core support pads and
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bottom head penetrations during the extended period of operation. Specifically, the applicant

was requested to submit the following information: (1) the inspection method used in detecting

cracking in these components, (2) the technical basis showing adequacy of this method to

detect cracking, (3) the inspection frequency and its justification, and (4) the acceptance

criteria. In response, the applicant stated that it will follow industry initiatives applicable to

inspection of cracking of core support pads and will have an inspection program in place prior to

the period of extended operation. The staff finds the applicant’s response acceptable because

the recommendations of the industry initiatives will be reviewed and approved by the staff. 

The GALL Report includes AMR of the pressurizer spray head. However, the applicant has not

presented AMR for the pressurizer spray head. This is acceptable because, according to a

Westinghouse report, “License Renewal Evaluation: Aging Management Evaluation for

Pressurizers,” Westinghouse Commercial Atomic Power (WCAP) 14574-A, December 2000,

the spray head is not within the scope of license renewal. The NRC staff has accepted this

position.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation and growth due to stress corrosion cracking or

primary water stress corrosion cracking 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, as recommended in the GALL report. Since the

applicant’s AMR results are otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.10 Crack Initiation and Growth Due to Stress Corrosion Cracking

Crack initiation and growth due to SCC could occur in PWR cast austenitic stainless steel

(CASS) reactor coolant system piping and fittings and the pressurizer surge line. The GALL

Report recommends further evaluation of the program for managing this aging effect. 

According to the GALL Report, the program is to include (1) adequate inspection methods to

ensure detection of cracks, and (2) flaw evaluation methodology for CASS components that are

susceptible to thermal aging management. The staff reviewed the applicant’s proposed

program to ensure that an adequate program will be in place for the management of these

aging effects.

VCSNS has an existing program for managing crack initiation and growth due to SCC, which

could occur in the PWR CASS reactor coolant system piping. The program relies on control of

chemistry to mitigate crack initiation and growth and an ISI Plan to detect and size cracks. The

VCSNS chemistry program is consistent with the GALL AMP XI.M2, “Water Chemistry.” The

ISI plan is consistent with GALL program XI.M1, “ASME Section XI Inservice Inspection,

Subsections IWB, IWC, IWD,” except that it is committed to an earlier edition of the ASME

Code, Section XI. The GALL program refers to the 1995 Edition through the 1996 Addenda,

whereas the VCSNS ISI Plan is committed to the 1989 Edition of ASME Section XI with no

addenda for the second 10-year inspection interval. VCSNS has, however, adopted the 1995

Edition with 1996 addenda for ultrasonic inspection. The staff finds that the VCSNS Chemistry
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Program and ISI Plan are adequate for managing cracking due to SCC in VCSNS CASS RCS

piping and fittings.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation and growth due to stress corrosion cracking of

the CASS reactor coolant system piping and fittings, as recommended in the GALL report. 

Since the applicant’s AMR results are otherwise consistent with the GALL report, the staff finds

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 current licensing basis for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.11 Crack Initiation and Growth Due to Primary Water Stress-Crossion Cracking

Crack initiation and growth due to PWSCC could occur in PWR pressurizer instrumentation

penetrations and heater sheaths and sleeves made of Nickel alloys. The existing program

relies on the ASME Section XI ISI program and on the control of water chemistry to mitigate

PWSCC. However, the existing program should be augmented to manage the effects of SCC

on the intended function of Nickel alloy components. The GALL Report recommends that the

applicant provide a plant-specific AMP or participate in industry programs to determine an

appropriate AMP for PWSCC of Inconel 182 welds. Acceptance criteria are described in BTP

RLSB-1 (Appendix of the SRP-LR). The staff reviewed the applicant’s proposed program to

ensure that an adequate program will be in place for the management of these aging effects.

According to WCAP 14574-A, “License Renewal Evaluation: Aging Management Evaluation for

Pressurizers,” the pressurizer instrumentation penetrations and immersion heater well

assemblies, including both heater sleeves and heater sheaths in Westinghouse-designed

plants, are made of austenitic stainless steel and, therefore, are not susceptible to PWSCC. 

These components are welded to stainless steel cladding with Alloy 82/182 welds, which are

susceptible to PWSCC. Therefore, the applicant presented the AMR results for these welds,

but not for the base metal of these components. The applicant credited the Alloy 600 AMP

(LRA Section B.1.1), which is a condition monitoring program, for managing cracking of these

welds due to PWSCC. The evaluation of this program is provided in Section 3.1.2.3.1 of the

SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation and growth due to stress corrosion cracking or

primary water stress corrosion cracking in PWR pressurizer instrumentation penetrations, and

heater sleeves and sheaths, as recommended in the GALL report. Since the applicant’s AMR

results are otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.12 Crack Initiation and Growth Due to Stress-Corrosion Cracking and IrradiationAssisted Stress-Corrosion Cracking

Crack initiation and growth due to SCC and irradiation-assisted stress-corrosion cracking 

(IASCC) could occur in the baffle/former assembly bolts. The GALL Report states that the

applicant is to provide a plant-specific AMP to manage this potential aging effect. Acceptance
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criteria are described in BTP RLSB-1 (Appendix A of the SRP-LR). The staff has reviewed the

applicant’s proposed program to ensure that an adequate program is in place to manage these

aging effects.

VCSNS has instituted the Reactor Vessel Internals Inspection Program (LRA Section B.2.4) to

manage crack initiation and growth due to SCC and IASCC in the baffle/former assembly bolts.

The program relies on the use of volumetric and visual examination techniques to detect the

aging effects. For accessible locations in the bolts, an enhanced visual inspection will be

performed to detect the presence and extent of cracking due to SCC and IASCC. For

inaccessible locations, such as the junctures of bolt heads and shanks, a volumetric inspection

will be performed to detect cracking due to SCC and IASCC.

GALL notes that, historically, the VT-3 visual examinations have not identified baffle/former

assembly bolt cracking because this cracking occurs at the junctures of the bolt heads and

shanks, which are not accessible for visual inspection. However, recent UT examinations of

these components have identified cracking in several plants. GALL states that the industry is

currently addressing the issue of baffle bolt cracking in the PWR MRP ITG activities to

determine, develop, and implement the necessary steps and plans to manage the applicable

aging effects on a plant-specific basis. The plant-specific basis selected by the applicant is

volumetric inspection under the Reactor Vessel Internals Inspection Program. The staff

requested, in RAI 3.1.2.2.12-1, that the applicant describe how it determines the threshold for

cracking due to IASCC of the baffle former bolts, what percentage of the bolts will be selected

for inspection, and what the technical basis is for this selection process. In response to the

RAI, the applicant stated that it would follow and implement the staff-approved

recommendations of the industry initiatives applicable to inspection of vessel internals for

cracking due to SCC and IASCC. The applicant has agreed that this is a licensee commitment

and this commitment is documented in Appendix A of this SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of crack initiation due to SCC and IASCC for the baffle/former

assembly bolts, as recommended in the GALL report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.13 Loss of Preload Due to Stress Relaxation

Loss of preload due to stress relaxation could occur in the baffle/former assembly bolts and the

upper and lower internals assembly. The GALL Report states that the applicant is to provide a

plant-specific AMP to manage this potential aging effect. Acceptance criteria are described in

BTP RLSB-1 (Appendix of the SRP-LR). The staff has reviewed the applicant’s proposed

program to ensure that an adequate program is in place to manage these aging effects.

VCSNS has instituted the Reactor Vessel Internals Inspection Program (LRA Section B.2.4) to

manage loss of preload due to stress relaxation, which could occur in the PWR reactor

internals, including the baffle/former assembly bolts, and the upper and lower internals

assembly. The program relies on the use of visual examination techniques to detect loose or

missing bolts. This is acceptable because the intended functions of reactor vessel internals can
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be maintained with fewer than 100 percent of the bolts intact. The applicant will determine the

number of bolts needed for maintaining the intended functions and their locations by analysis

prior to the inspection. The applicant also stated that VCSNS will follow the practices that are

developed from industry initiatives, specifically EPRI and Westinghouse Owners Group (WOG) 

activities, and operating experience for the Reactor Vessel Internals Inspection Program. The

review of this program is presented in Section 3.1.2.3.7 of this SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of preload due to stress relaxation for the baffle/former

assembly bolts, as recommended in the GALL report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.1.2.2.14 Loss of Section Thickness Due to Erosion

The SRP-LR identifies loss of section thickness due to erosion as an aging effect that could

occur at the feedwater impingement plate and support in the SGs. The GALL Report

recommends further evaluation of the effectiveness of the applicant’s plant-specific AMP to

ensure that this aging effect is adequately managed. The applicant addressed this aging effect

in LRA Table 3.1-1, Item 14. In its discussion, the applicant stated that the feedwater

impingement plate and support do not have a license renewal intended function for VCSNS and

aging management is therefore not required. However, the applicant provides no justification

for this conclusion. 

In RAI 3.1.2.2.14-1, the staff requested the applicant to provide the technical basis for excluding

the SG feedwater impingement plate and support from the scope of license renewal. In its

response to RAI 3.1.2.2.14-1, the applicant stated that the Delta 75 SGs in VCSNS do not have

a feedwater impingement plate. However, there is a similar component, a baffle plate,

designed to carry emergency feedwater to prevent cold water spraying on the hot shell during

filling or transients. But emergency feed is not used during normal operation. Therefore,

erosion of the baffle plate is not an aging effect requiring management.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of section thickness due to erosion, as recommended in the

GALL report. Since the applicant’s AMR results are otherwise consistent with the GALL report,

the staff finds 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 current licensing

basis for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.15 Crack Initiation and Growth Due to Primary Water Stress-Corrosion Cracking, 

Outside Diameter Stress Corrosion Cracking and/or Intergranular Attack; Loss of

Material Due to Wastage and Pitting Corrosion and Fretting and Wear; or

Deformation Due to Corrosion at Tube Support Plate Intersections

The SRP-LR identifies the following aging effects that could occur in Alloy 600 components of

the SG tubes, repair sleeves and plugs—crack initiation and growth due to PWSCC, outside

diameter stress-corrosion cracking ODSCC, or intergranular (IGA); loss of material due to
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wastage and pitting corrosion, and fretting and wear; or deformation due to corrosion at tube

support plate intersections. To manage these aging effects, the GALL Report identifies the

AMPs programs as GALL AMP XI.M19, “Steam Generator Tubing Integrity,” and GALL AMP

XI.M2, “Water Chemistry”.

The GALL Report further states that all PWR licensees have committed voluntarily to a steam

generator degradation management program described in NEI document, NEI 97-06, “Steam

Generator Program Guidelines.” The GALL Report recommends that an AMP based on the

recommendations of the NEI 97-06 guidelines, or some other alternate regulatory basis for SG

degradation management, should be developed to ensure that these aging effects are

adequately managed. 

Presently, the staff does not plan to endorse NEI 97-06 or the industry guidelines referenced

therein. The staff is working with the industry to revise plant technical specifications to

incorporate the essential elements of NEI 97-06 as necessary to ensure tube integrity is

maintained. This would require implementation of SG programs to ensure that performance

criteria for tube structural and leakage integrity are maintained, consistent with the plant design

and licensing basis. NEI 97-06 provides guidance on programmatic details for accomplishing

this objective. These guidelines apply to all degradation or damage mechanisms. However,

these programmatic details would be outside the scope of the technical specifications. 

As part of the NRC Reactor Oversight Program, the NRC would monitor the effectiveness of

these programs in terms of whether the bottom line goals of these programs are being met,

particularly whether the tube structural and leakage integrity performance criteria are in fact

being maintained. The staff reviewed the applicant’s proposed steam generator program to

ensure that an adequate program will be in place for the management of the aging effects

associated with the SG components for the period of extended operation.

The applicant stated that the original steam generators at VCSNS were replaced in 1994 with

Westinghouse Delta 75 steam generators. The replacement steam generators have thermally

treated Alloy 690 tubes rather than the Alloy 600 tubes identified in GALL, Chapter IV.D1. The

replacement steam generators have never been exposed to phosphate water chemistry;

therefore, loss of material due to wastage is not an applicable aging effect. In addition, the

replacement steam generators have support plates made of Type 405 stainless steel instead of

carbon steel. Therefore, deformation due to corrosion at the tube support plate intersections is

not an applicable aging effect. The applicant has proposed to manage the following applicable

aging effects to the SG tubes, repair sleeves, and plugs by the Steam Generator Management

Program (LRA Appendix B.1.10) and the Chemistry Program (LRA Appendix B.1.4)—(1) crack

initiation and growth due to PWSCC, ODSCC, or IGA, (2) loss of material due to pitting

corrosion, or (3) loss of section thickness due to fretting and wear. 

The applicant also stated that the Steam Generator Management Program is consistent with

GALL AMP XI.M19, “Steam Generator Tube Integrity,” and is structured to meet NEI 97-06.

The staff issued RAI 3.1.2.2.15-b, requesting the applicant to confirm whether there are any

alternate regulatory bases (i.e., alternate repair criteria) for VCSNS steam generators. In its

response to RAI 3.1.2.2.15-b, the applicant stated that there are no alternate repair criteria for

the replacement SGs at VCSNS. The staff’s review of the Steam Generator Management

Program is discussed in Section 3.1.2.3.5 of this SER. The staff’s review of the Chemistry

Program is discussed in Section 3.0.3.2 of this SER.
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The Delta 75 steam generator design incorporates the main characteristics of the

Westinghouse Model F design and is described in a Westinghouse report, “Westinghouse

Delta 75 Steam Generator Design and Fabrication Information for the Virgil C. Summer Nuclear

Station,” WCAP-13480, Revision 1, October 1993. The report states that the corrosion

resistance of thermally treated Alloy 690 tubes has been proven not only by years of laboratory

testing, but also in actual plant operation. The report further states that in 16 years of installing

Alloy 690 tubing in steam generator and in operating 8 Westinghouse steam generators with

Alloy 690 tubes, no indications on outer surface or inner surface tube corrosion have occurred. 

Also, EPRI report TE-106365-R14 states that virtually no cracking due to PWSCC, ODSCC, or

IGA, as well as no loss of material due to pitting corrosion of Alloy 690 tubes has occurred after

many years of operation in U.S. steam generator service. However, the EPRI report mentions

that a small number of Alloy 690 tubes have been plugged due to wear. 

In RAI 3.1.2.2.15-2, the staff requested the applicant to describe the design features

incorporated in Delta 75 steam generators at VCSNS to minimize tube degradation due to

wear. In its response to RAI 3.1.2.2.15-2, the applicant referred to the Westinghouse report, 

WCAP-13480, Revision 1, which identifies several enhancements to antivibration bars (AVB) to

minimize wear on tubes including (1) use of Type 405 stainless steel material, (2) adoption of

rectangular AVB configuration, (3) use of four sets of AVBs, and (4) tight control of AVB

insertion depth. Increasing the number of sets of AVBs reduces the number of tubes that are

potentially affected by the vibration mechanisms to which tube degradation has been attributed

in some conventional steam generators. In addition, Delta 75 steam generators have small

(0.003 in.) U-bend gaps and a tightly controlled U-bend tubing ovality. The report states that

these two features have been proven through analytical assessment to reduce wear potential

by more than an order of magnitude. The staff finds the applicant’s response to RAI

3.1.2.2.15-2, acceptable because the design of the replacement steam generator minimizes the

potential for tube degradation due to wear. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of (1) crack initiation and growth due to PWSCC, ODSCC, and/or

IGA, (2) loss of material due to wastage and pitting corrosion, (3) loss of material due to fretting

and wear, or (4) denting due to corrosion of carbon steel tube support plate in the SG tubes and

plugs, as recommended in the GALL Report. Since the applicant’s AMR results are otherwise

consistent with the GALL report, the staff finds that the applicant has demonstrated that these

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). 

3.1.2.3 Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant 

System Components

To perform its evaluation, the staff reviewed the components listed in LRA Tables 2.3-1 through

2.3-7 to determine whether the applicant had properly identified the applicable AMRs and AMPs

needed to adequately manage the aging effects for the components. This portion of the staff’s

review involved identification of the aging effects for each component, ensuring that each aging

effect was evaluated using the appropriate AMR in LRA Section 3, and ensuring that the

management of the aging effect was captured in the appropriate AMP.
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The staff also reviewed the FSAR supplements for the AMPs credited with managing aging in

reactor system components to determine whether the program descriptions adequately

describe the programs.

The applicant credits 12 AMPs to manage the aging effects associated with components in the

reactor systems. Three of these AMPs are credited to manage aging for components in other

system groups (common AMPs), whereas the remaining eight AMPs are credited with

managing aging only for reactor system components. The staff’s evaluation of the common

AMPs that are credited with managing aging in reactor system components is provided in

Section 3.0.3 of this SER. The common AMPs with respect to the RCS include the following

programs:

 Boric Acid Corrosion Surveillance Program

 Chemistry Program

 Inservice Inspection (ISI) Plan

The staff’s evaluation of the nine reactor system-specific AMPs is provided below.

3.1.2.3.1 Alloy 600 Aging Management Program

The applicant described its Alloy 600 Aging Management Program (AMP) in LRA Appendix

B.1.1. This is an existing program and the applicant stated that the program is consistent with

GALL AMP XI.M11, Nickel-Alloy Nozzles and Penetrations.” The AMP is credited for

managing cracking in Alloy 600 vessel head penetrations.

The staff reviewed the applicant’s description of the program in LRA Appendix B, Section B.1.1

to determine whether the applicant demonstrated that it will adequately manage the applicable

aging effects in VCSNS during the period of extended operation, as required by

10 CFR 54.21(a)(3).

Summary of Technical Information in the Application

The applicant stated that the program does not rely on an enhanced leakage detection system

for detection of small leaks caused by PWSCC during plant operation, as suggested by

GALL XI.M11. Instead, the program relies on detecting PWSCC cracks by means of inspecting

for signs of boric acid leakage during outages, and by monitoring primary coolant leakage, per

technical specifications, during plant operation before the intended function of the integrity of

the pressure boundary is compromised. In addition, the applicant stated that the program will

be enhanced according to the changes indicated by emerging regulatory requirements and

identified by industry programs. 

The applicant summarized its operating experience related to PWSCC cracking in Alloy 600

vessel head penetrations and in Alloy 82/182 weld between the RCS piping and the vessel

outlet nozzle. For vessel head penetrations, the applicant briefly described its responses to

NRC Bulletins 2001-01 and 2002-01. In describing recent industry experience, the applicant

mentioned that the VCSNS response to NRC Bulletin 2001-01 stated that VCSNS performed

VT-3 inspections of the interior surface of the reactor vessel head in April 1999 and found no

recordable indications. The applicant also stated that VCSNS addressed the three license

renewal issues identified in the NRC closure letter from K.R. Cotton to G.J. Taylor, dated
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December 17, 1999, in SCE&G response to GL 97-01. The applicant stated (1) VCSNS vessel

head penetrations have low susceptibility to PWSCC during the extended operating period,

(2) the vessel head penetrations are included within the scope of the Boric Acid Corrosion

Surveillances Program, and (3) the results of inspections are summarized as part of the

operating experience (no recordable indications found) and documented in the response to

NRC Bulletin 2001-01. 

Staff Evaluation

The applicant stated that its Alloy 600 AMP is consistent with GALL XI.M11, which describes a

program for managing cracking in the vessel head penetrations due to PWSCC. However, the

review of the aging management results for Alloy 600 components presented in the LRA implies

that the scope of the applicant’s program is broader. The staff issued RAI B.1.1-5, requesting

the applicant to clarify this discrepancy. In response to RAI B.1.1-5, in a letter dated June 12,

2003, the applicant stated that the scope of its program is broader and includes the following

Alloy 600 components, in addition to reactor head penetrations:

• reactor vessel bottom head penetration tubes

• pressurizer nozzle-safe end weld metal (alloy 82/182)

• other dissimilar metal welds (alloy 82/182 welds) 

• steam generator primary side tubesheet

• reactor vessel core support pads

The staff finds this explanation acceptable because it is consistent with the AMR results

presented in LRA Tables 3.1-1 and 3.1-2. 

As suggested in the NRC closure letter from K.R. Cotton to G.J. Taylor, dated December 17,

1999, for SCE&G response to Generic Letter 97-01, the LRA should include a summary of the

results of any inspections that have been completed on VCSNS vessel head penetrations prior

to the LRA. Therefore, the staff requested the applicant to provide information on the

(1) number of vessel head penetrations inspected and their locations on the vessel head,

(2) inspection methods used, (3) number of Alloy 82/182 attachment welds inspected, and

(4) inspection results. In response, the applicant states that a remote visual examination of the

area between the reactor vessel head insulation and the reactor vessel head was conducted

during RF-13. The examination included inspection of all reactor vessel head penetration

including vent pipe. The inspection showed no evidence of recent boric acid leakage from any

reactor vessel head penetration. The specific information for this examination may be found in

a letter from S.A. Byrne of SCE&G to the Public Document Room dated July 3, 2002. The

applicant also performed an inspection of the underside of the vessel head using a remotely

operated camera to detect any significant indication of cracking or loss of material. It did not

find any recordable indications.

The program relies on detecting PWSCC cracks in head penetrations by means of inspection

for signs of boric acid leakage during outages. The staff issued an RAI requesting the applicant

to (1) confirm that the boric acid leakage inspection includes inspection of bare vessel head, 

(2) confirm that after the inspection vessel head will be cleaned of any boric acid deposits,

(3) confirm whether an ASME VT-2 examination method is used to detect leakage through a

crack in the vessel head penetration, and (4) since the leakage through a PWSCC crack is

generally very small, provide the technical basis for ensuring that the boric acid leakage
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inspection will be able to detect such a small leakage. In response, the applicant stated that it

used ASME VT-2 examination for boric acid inspections of the reactor head during the refueling

outage (RF) 13. When leaks are found, the affected components are evaluated for impact,

corrective actions are implemented as appropriate, and boric acid residue is removed. 

The applicant further stated that in response to NRC Bulletin 2002-02, a “bare metal inspection”

of the reactor head is scheduled for the RF-14 using the guidance of the EPRI MRP report,

“PWR RPV Upper Head Penetrations Inspection Plan (MRP-75),” Revision 1, Report 1007337. 

A “bare metal inspection” consists of a detailed visual examination meeting the following three

requirements: 

• optical aids used should be able to resolve the 4-millimeter (mm) character height under

conditions similar to those for the actual inspection, 

• the entire intersection between the reactor pressure vessel (RPV) head and each

penetration should be readily viewed, as well as 12 mm (0.5 in.) of the adjacent bare

surface of the upper head

• additional examination of uncertain deposits to further discriminate between the possible

sources of origin may require additional optical aids with greater resolution. 

The applicant further stated that its experience with leaks is consistent with the assumption that

boric acid leakage inspection will detect leaks more reliably than leak rate surveillance. The

staff finds the applicant’s response acceptable because the boric acid inspections performed

following the EPRI MRP guidance will be capable of detecting very small leak rates. 

The applicant stated that the program will be enhanced according to the changes indicated by

emerging regulatory requirements and identified by industry programs. However, the Alloy 600

AMP, described in LRA Section B.1.1, does not specify whether the applicant would participate

in the industry program for managing PWSCC-type aging on vessel head penetrations and

implement its recommendations. Therefore, the staff issued an RAI about the applicant's 

involvement in the industry program. In response, the applicant stated that it is participating in

the industry program for managing PWSCC-type aging on vessel head penetrations. The staff

finds this response acceptable because the program carried out by the EPRI MRP is the main

industry program addressing the issue of PWSCC cracking of vessel head penetration and

other Alloy 600 components and Alloy 82/182 welds. The applicant has agreed that this is a

licensee commitment and this commitment is documented in Appendix A of this SER.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.4. The

supplement states that the pressurizer and steam generator subcomponents, in addition to the

vessel subcomponents, are within the scope of the program. The staff concludes that the

applicant’s FSAR Supplement provides an adequate description of the programs credited with

managing this aging effect, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, the
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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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.2 Bottom-Mounted Instrumentation Inspection Program

The applicant described its Bottom-mounted Instrumentation Inspection Program in LRA

Appendix B.1.3. This is an existing, plant-specific program. The applicant credits this AMP for

managing loss of material due to wear of the thimble tubes. There is no corresponding AMP in

GALL, but GALL suggests a program based on recommendations of NRC I&E Bulletin 88-09,

“Thimble Tube Thinning in Westinghouse Reactors."

Summary of Technical Information in the Application

The objective of the program is to identify loss of material, (i.e., tube wall thinning) due to

fretting wear in the bottom-mounted instrumentation (BMI) thimble tubes, prior to loss of their

intended function through leakage and loss of pressure boundary. The applicant stated that

the program is a condition monitoring program. The program includes inspection of all VCSNS

BMI thimble tubes using eddy current testing (ECT). The ECT data are trended, wear rates are

calculated, and inspections are planned prior to the refueling outage at which thimble tube wear

is predicted to exceed the acceptance criteria of 75 percent loss of initial wall thickness. The

corrective actions include capping, repositioning, or replacing a thimble tube if predicted tube

wear exceeds the acceptance criteria.

The applicant summarized its operating experience related to thimble tube wear by briefly

describing its response to NRC IEB 88-09. Since issuance of the bulletin, the applicant has

performed four inspections (RF-4 ,R-5, R-6, and RF-13) of BMI thimble tubes at VCSNS and

repositioned several of them. Based on the calculations performed using the results of these

inspections, the applicant determined that the next ECT is not required on the thimble tubes

until RF-17.

Staff Evaluation

The staff reviewed the applicant’s description of the program in LRA Appendix B.1.3 to

determine whether the applicant demonstrated that it will adequately manage the applicable

aging effects at VCSNS during the period of extended operation, as required by

10 CFR 54.21(a)(3).

[Program Scope] The objective of the subject program is to monitor tube wall degradation, (i.e.,

loss of wall due to fretting wear) of all thimble tubes installed in the VCSNS reactor pressure

vessel. The staff finds that the scope of the subject AMP is adequate because it includes

inspection of all thimble tubes that are susceptible to wall thinning due to fretting wear caused

by flow-induced vibrations.

[Preventive or Mitigative Actions] The subject program is a condition monitoring program. 

There are no preventive or mitigative attributes associated with the program, nor did the staff

identify a need for such.
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[Parameters Monitored/Inspected] The subject program monitors BMI thimble tube wall

degradation (loss of material due to fretting wear). The staff finds this acceptable because tube

wall degradation directly relates to the thimble tube capacity to perform its intended function of

maintaining the integrity of reactor coolant pressure boundary.

[Detection of Aging Effects] The subject program monitors tube wall degradation in

100 percent of the BMI thimble tubes using ECT. The staff issued RAI B.1.3-1, requesting the

applicant to submit information about whether the entire length of each thimble tube is

inspected, and if not, to present the technical basis for not doing so. In response to RAI

B.1.3-1, in a letter dated June 12, 2003, the applicant stated that the full length of each BMI

thimble tube is inspected. The applicant also stated that the eddy current inspection performed

during RF-4 detected wear occurring at the core plate or fuel assembly bottom nozzle area. 

The staff finds the response acceptable because these wear locations are consistent with the

wear locations reported in the NRC IEB 88-09 and NRC IN 87-44, “Thimble Tube Thinning in

Westinghouse Reactors.”

The applicant stated that the frequency of ECT examination is based on an analysis of data

obtained using the wear rate relationships developed based on Westinghouse research. The

staff issued RAI B.1.3-2, requesting the applicant to submit an explanation for the wear rate

relationships and describe the Westinghouse research. This RAI was discussed during a

June 22, 2003, conference call. As a result of the conference call, the applicant provided the

following additional information in response to RAI B.1.3-2. 

Research was performed for the WOG and is documented in WCAP-12866. WCAP-12866

includes an evaluation of a large amount of operating experience from multiple plants. Data

from multiple thimble tubes at these plants were evaluated for wear. The wear was typically

evaluated over one operating cycle, but two, and even three, cycles of wear data were used in

the research. Hot cell examination of worn thimbles was performed and its results were

compared with eddy current data. The comparison determined that eddy current data

conservatively predict the extent of loss of material due to wear. The staff finds the use of ECT

data from the Westinghouse research for developing wear rate relationship acceptable because

the wear data are obtained from thimble tubes in several plants, they cover one to three

operating cycles, and they conservatively predict the extent of loss of material due to wear.

[Monitoring and Trending] The applicant stated that the ECT results are trended, wear rates

are calculated, and inspections are planned prior to the refueling outage in which thimble tube

wear is predicted to exceed the acceptance criteria. Regarding the predicted wear rate, the

IEB 88-09 states that, based on the available data, it is not possible to accurately predict

thimble tube wear rates because several plant-specific factors affect the wear rate including the 

gap distance from the lower core plate to the fuel assembly instrument tube, the amount of

clearance between the thimble tube and the guide tube, the axial component of the local fluid

velocity, the thickness of the thimble tube, and the moment of inertia of the thimble tube. In

describing its operating experience, the applicant stated that, based on the analysis of the wear

rate data derived from the eddy current inspections performed at RF-4 and RF-5, the next

inspection of the thimble tubes is not required until RF-14. The staff issued RAI B.1.3-3,

requesting the applicant to explain and justify the use of this extrapolation of the limited

inspection results over nine refueling cycles for scheduling the next inspection of the thimble

tubes. 
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In response to RAI B.1.3-3, in a letter dated June 12, 2003, the applicant submitted the

following information. VCSNS now has four sets of data for wear of its thimble tubes. Data

have been gathered in RF-4, RF-5, RF-6 and RF-13. The highest recorded measurement in

RF-4 and RF-13, respectively, was 38 percent and 57 percent of the initial wall thickness. The

applicant used the wear rate relationship developed by Westinghouse to predict the wear

damage based on RF-13 measurements. The projections for wear at RF-17 are all below 75

percent of the initial wall thickness and the highest wear predicted for RF-18 is between 75

percent and 80 percent of the initial wall thickness. The acceptance criterion for wear damage

is 75 percent loss of initial wall thickness. VCSNS plans to perform the next inspection of

thimble tubes in RF-17. The staff finds the VCSNS monitoring and trending activities

acceptable because the extrapolation is based on inspection results from four refueling cycles. 

The relationship developed by Westinghouse conservatively predicts the extent of loss of

material due to wear for one to three operating cycles. The staff finds this acceptable because

the Westinghouse relationship will be periodically evaluated by the applicant

[Acceptance Criteria] The subject program uses 75 percent loss of initial wall thickness as an

acceptance criterion. The staff issued RAI B.1.3-4, requesting the applicant to submit the

technical justification for this criterion and explain how the allowances for such items as

inspection methodology and wear scar geometry uncertainties, which were identified in

IEB 88-09, are included in the criterion. In response to RAI B.1.3-4, in a letter dated June 12,

2003, the applicant stated that the wear relationship developed by Westinghouse makes

allowances for the uncertainties. The Westinghouse methodology has an acceptance criterion

of 80 percent, whereas VCSNS uses 75 percent for additional conservatism. The staff finds the

response acceptable because the acceptance criterion adopted by VCSNS is more

conservative than the one recommended by Westinghouse and it allows for the uncertainties as

identified by IEB 88-09. 

[Operating Experience] Since the issuance of IEB 88-09, the applicant has performed four

inspections (RF-4, -5, -6, and -13) of thimble tubes at VCSNS. The applicant reported that

several thimble tubes were repositioned in RF-5, but no thimble tubes have been capped or

required replacement.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.8. The

staff concludes that the applicant’s FSAR Supplement provides an adequate description of the

program credited with managing this aging effect, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.1.2.3.3 In-Service Inspection Plan (ISI)

The applicant described its In-Service Inspection (ISI) Plan in LRA Appendix B.1.7. The plan is

based on the ASME Code Section XI in-service inspection requirements. Throughout the
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service life of nuclear power plants, Class 1 components and associated Class 1 supports must

meet the requirements set forth in Section XI of the ASME Code and Addenda that are

incorporated by reference in 10 CFR 50.55a(b).

Inservice examinations and system pressure tests conducted during successive 120-month

inspection intervals, following the initial 120-month ISI interval, must comply with the

requirements of the latest edition and addenda of the Code incorporated by reference in

10 CFR 50.55a(b) twelve months prior to the start of the 120-month inspection interval, subject

to the limitations and modifications, such as code editions and addenda, as listed in paragraph

10 CFR 50.55a(b)(2)(i).

The period of extended operation will contain the fifth and sixth ISI interval. The ISI plan for

each interval of the renewed license period of extended operation for VCSNS will comply with

10 CFR 50.55a(g)(4)(ii) except that if an examination required by the Code or Addenda is

determined to be impractical, then the applicant will submit a relief request to the Commission

in accordance with the requirements contained in 10 CFR 50.55a(g)(5)(iii) and (iv), for

Commission evaluation, as required by 10 CFR 50.55a(g)(6)(i).

Summary of Technical Information in the Application

The Inservice Inspection Plan is an existing program. The applicant states that the program is

consistent with GALL AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB,

IWC, IWD,” with the following clarification: VCSNS is committed to the 1989 Edition of ASME

Section XI with no addenda for the second ten-year inspection interval. In addition, VCSNS has

adopted the 1995 Edition of ASME Section XI with 1996 Addenda for ultrasonic examination

requirements, which includes mandatory Appendices VII and VIII. VCSNS has performed

Inservice inspections in accordance with the relevant portions of approved editions of ASME

Code Section XI from the beginning of its operation in 1982. 

As part of the operating experience, the applicant mentions the primary water SCC of the

reactor vessel “A” hot leg nozzle that resulted in leakage, which was discovered in 2000 during

RF-12. The applicant states that the leakage was detected by virtue of boric acid residue, and

confirmed by volumetric examination. The crack was inspected, evaluated and repaired in

accordance with ASME Section XI criteria.

Staff Evaluation

In LRA Appendix B.1.7, “In-Service Inspection (ISI) Plan,” the applicant describes its AMP for

detecting and managing aging effects of ASME code components in the reactor coolant

system. The LRA states that this AMP is consistent with GALL AMP XI.M1, “ASME Section XI

Inservice Inspection, Subsections IWB, IWC, IWD,” with no deviation. The staff confirmed the

applicant’s claim of consistency during the AMR inspection. In addition, for VCSNS, the staff

determined whether the applicant properly applied the GALL program to its facility.

The plant operating experience, described in the LRA, has indicated that the VCSNS ISI plan

has been effective in detecting and managing aging effects in ASME code components in the

reactor coolant system identified in Tables 3.1-1 and 3.1-2 of the LRA for which the ISI plan is

identified as an AMP. The staff, therefore, has determined that the applicant’s ISI plan will
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adequately manage the aging effects in the components identified in the tables during the

period of extended operation.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.19. The

staff concludes that the applicant’s FSAR Supplement provides an adequate description of the

program credited with detecting and managing aging effects in ASME code components in the

reactor coolant system, as required by 10 CFR 54.21(d).

Conclusion

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.4 Reactor Head Closure Studs Program

The applicant describes its reactor head closure studs program in LRA Appendix B.1.8. This is 

an existing program and the applicant states that the program is consistent with GALL AMP

XI.M3, "Reactor Head Closure Studs." The AMP is credited for managing loss of mechanical

closure integrity for the reactor head closure stud bolting subject to SCC, stress relaxation, and

wear. The staff reviewed the applicant’s description of the program in LRA Appendix B,

Section B.1.8, to determine whether the applicant has demonstrated that it will adequately

manage the applicable aging effects in VCSNS during the period of extended operation as

required by 10 CFR 54.21(a)(3).

Summary of Technical Information in the Application

The applicant states that the program will manage aging effect of loss of closure integrity rather

than loss of material, loss of preload and cracking of closure studs. The program is largely

dependent upon the Inservice inspection plan, which includes ASME Code Section XI

inspections. VCSNS has performed Inservice inspections in accordance with the relevant

portions of ASME Code Section XI from the beginning of its operation in 1982, and no damage

to the reactor head closure studs has been detected. 

Staff Evaluation

In LRA Table 3.1-1, AMR Item 18, the applicant states that the aging effect requiring

management is loss of closure integrity rather than loss of material, loss of preload, and

cracking of closure studs, which are managed by GALL AMP XI.M3. The staff requested the

applicant to describe the difference between loss of closure integrity and the aging effects

managed by GALL XI.M3. In response, the applicant stated that loss of mechanical closure

integrity can result in failure of the mechanical joint and is evidenced by leakage rather than

joint failure. This failure can be attributed to loss of bolt preload, loss of bolting material by

wear, and cracking of high strength bolting material. Therefore, management of loss of closure
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integrity is the same as management of loss of preload, loss of material, and cracking of bolting

materials. The applicant is managing the loss of closure integrity with the ISI plan, which

includes surface and volumetric inspections for detecting cracking and loss of material in

closure head studs, nuts, threads in flange, washers and bushings at each refueling outage

when the reactor closure head is disassembled and reassembled. Retorquing of the closure

studs during reassembly will establish the desired preload. Thus, any loss of preload that might

have occurred during previous operation would be removed during a refueling outage. 

Therefore, the applicant’s management of loss of mechanical closure integrity is adequate for

managing the aging effects of loss of material, cracking, and loss of preload.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.27. The

staff concludes that the applicant’s FSAR Supplement provides an adequate description of the

programs credited with managing this aging effect, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.5 Steam Generator Management Program

The applicant described its Steam Generator Management Program in LRA Appendix B,

Section B.1.10. This is an existing program, and the applicant stated that the program is

consistent with GALL AMP XI.M19, “Steam Generator Tube Integrity.” This AMP, along with

the Chemistry Program described in LRA Appendix B, Section B.1.4 is credited with managing

cracking and loss of material in steam generator tubes, tube plugs, shell, and internals.

The staff reviewed the applicant’s description of the program in LRA Appendix B, Section

B.1.10 to determine whether the applicant demonstrated that the program will adequately

manage the applicable aging effects in VCSNS SGs during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Summary of Technical Information in the Application

The replacement steam generators were installed during RF-8 in 1994. The applicant stated

that the existing Steam Generator Management Program was first applied to the replacement

steam generators when a partial eddy current inspection of steam generators A and B was

conducted and a moisture carryover modification was carried out during RF-9. During RF-10

and RF-11, the applicant partially inspected steam generators A, B, and C. During RF-12, the

applicant inspected tubes in all three SGs and performed a full secondary-side inspection. The

applicant stated that no significant degradation was found during any of these inspections.

Staff Evaluation
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In LRA Appendix B, Section B.1.10, the applicant stated that the Steam Generator

Management Program is consistent with GALL AMP XI.M19; no deviations were noted. In RAI

B.1.10-3, the staff requested the applicant’s clarification regarding why the scope of the

applicant’s AMP is different from GALL AMP XI.M19. In its response to RAI B.1.10-3, the

applicant explained that the scope of GALL AMP XI.M19 is specific to SG tubes, whereas the

scope of the applicant’s AMP includes SG shell and internals, such as AVBs and the feedwater

distributor, in addition to tubes and plugs. The staff finds the applicant’s response to RAI

B.1.10-3, acceptable because the applicant’s Steam Generator Management Program is more

comprehensive than GALL XI.M19 in the management of steam generator components.

The application of the applicant’s AMP for managing crack initiation and growth due to PWSCC,

ODSCC, or IGA; loss of material due to wastage and pitting corrosion and fretting and wear; or

deformation due to corrosion in Alloy 690 components of the SG tubes and plugs is reviewed in

Section 3.1.2.2.15 of this SER. The staff finds that these are the applicable aging effects for

SG tubes and that the applicant’s Steam Generator Management Program will adequately

manage the applicable aging effects for Alloy 690 tubes and plugs. 

The applicant stated that a 100 percent secondary-side inspection was performed during

RF-12. The staff issued RAI 3.1.2.2.2-1, requesting the applicant to submit a summary

description of this inspection, including a list of components inspected, type of inspection

performed, and frequency of such inspection during the extended period of operation. This RAI

was further discussed with the applicant during a June 22, 2003, conference call. In its

additional response to RAI 3.1.2.2.2-1, in a letter dated September 2, the applicant provided the

following additional information. The applicant states that the secondary-side visual inspections

were performed for evidence of corrosion, erosion, deposits, and hardware conditions in four

locations in the replacement steam generators, including the upper steam drum region,

mid/lower steam drum region, 9th tube support and U-bend region, and tubesheet and lower

tube bundle region. Access to the inspection locations was provided by several different

openings in the SGs. The inspections utilized several different types of remote camera

equipment and delivery tooling depending on the component being viewed. None of the

components inspected showed any sign of erosion, corrosion, or degradation. The applicant

stated that the frequency of SG secondary side inspection at VCSNS is determined based on

the inspection results and is performed periodically. The components that will be inspected

during the extended period of operation are included in the Steam Generator Management

Program (LRA B.1.10) and are similar to the components discussed above. The staff finds that

the applicant’s response to RAI 3.1.2.2.2-1 is acceptable because its SG management program

will adequately manage the applicable aging effects on the secondary-side components. 

The FSAR Supplement for the Steam Generator Management Program is presented in LRA

Appendix A, Section 18.2.35. The supplement states that the program implements the

requirements of VCSNS Technical Specification 4.4.5 and follows the recommendations

provided by NEI and EPRI guidelines. In RAI B.1.10-3, the staff requested the applicant to

update the FSAR Supplement to include NEI 97-06. In its response to RAI B.1.10-3 dated

June 12, 2003, the applicant revised the FSAR Supplement to indicate that the scope of the

Steam Generator Management Program includes inspection of other steam generator 

components, in addition to tubes and plugs. However, the applicant did not revise the FSAR

Supplement to include NEI 97-06 because it stated that the staff had not approved NEI 97-06

and that NEI 97-06 may be revised in the future. The staff found that FSAR Supplement

18.2.35 was inadequate without a reference to NEI 97-06 because the industry has been using
3-88

the guidance in NEI 97-06 in its SG tube inspection. In addition, NEI 97-06 is referenced in

GALL XI.M19 and NUREG-1800 as a document that is related to the SG tube inspection. In a

letter dated September 2, 2003, the applicant revised FSAR Supplement 18.2.35 to include

NEI 97-06. The staff concludes that the applicant’s FSAR Supplement provides an adequate

description of the programs credited with managing the aging effects in steam generator 

components subject to AMR, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.6 Reactor Vessel Surveillance Program

The applicant described its Reactor Vessel Surveillance Program in LRA Appendix B.1.24. This

is an existing program and the applicant stated that the program is consistent with GALL AMP

XI.M31, “Reactor Vessel Surveillance.” The AMP is credited for managing loss of fracture

toughness in reactor vessel materials due to neutron irradiation embrittlement.

The staff reviewed the applicant’s description of the program in LRA Appendix B, Section

B.1.24 to determine whether the applicant demonstrated that it will adequately manage the

applicable aging effects at VCSNS during the period of extended operation, as required by

10 CFR 54.21(a)(3).

Summary of Technical Information in the Application

The applicant identified two enhancements to be incorporated into the Reactor Vessel

Surveillance Program prior to the period of extended operation. The first included a one-time

analysis to demonstrate that the materials in the inlet and outlet nozzles and upper shell course

will not become limiting materials during the period of extended operation. The second called

for removal of the two remaining surveillance capsules during RF-14 in accordance with the

recommendations of Item 6 of the December 3, 1999, C. Grimes (NRC) letter to D. Walters

(NEI). The applicant stated that the analysis of the VCSNS surveillance capsules removed to

date demonstrates that changes of pressure vessel beltline material properties are well-known

and will not result in brittle failure. By letter dated November 5, 2003, the applicant indicated

that it had originally intended to establish operating restrictions for control of vessel fluence. 

However, VCSNS, has since reconsidered the use of operating restrictions and has determined

to leave one of the two remaining capsules in the vessel for one additional cycle. During RF15, VCSNS intends to remove the last remaining capsule and place it in storage for possible

future use. Also, the applicant indicated that during RF-15, VCSNS intends to install alternative

dosimetry to monitor vessel fluence. The applicant also stated that the VCSNS Fuel Loading

Program was revised to implement a low-leakage pattern that reduced the neutron flux and,

therefore, neutron embrittlement of the reactor vessel.
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Staff Evaluation

The applicant stated that its program is consistent with GALL AMP XI.M31. The

recommendations of GALL AMP XI.M31 are similar to those of the December 3, 1999,

C. Grimes letter to D. Walters (NEI). The VCSNS Reactor Vessel Surveillance Program

consists of capsules with a projected fluence exceeding the 60-year fluence at the end of 40

years.

In the LRA, the applicant indicated that it will remove the two remaining surveillance capsules

during RF-14. As a result, no surveillance capsules will be left in the vessel during the

extended period of operation. Therefore, the staff identified in RAI B.1.24-1 that the applicant

needs to confirm whether the operating restrictions will be established at the end of RF-14 to

ensure that the plant is operated under conditions to which the surveillance capsules were

exposed and that the exposure conditions of the reactor vessel will be monitored to ensure that

they continue to be consistent with those used to project the effects of embrittlement to the end

of license.

In addition, the applicant did not make any commitments for installing an alternative dosimetry

for monitoring neutron fluence during the period of extended operation. GALL AMP Chapter

XI.M31, “Reactor Vessel Surveillance,” recommends the use of alternative dosimetry for

applicants without in-vessel capsules. In response to RAI B.1.24-1, the applicant stated that a

program will be established at the end of RF-14 to ensure that the plant is operated under

conditions to which the surveillance capsules were exposed and that the exposure conditions of

the reactor vessel will be monitored to ensure that they continue to be consistent with those

used to project the effects of embrittlement to the end of license. The applicant further states

that this program may be supplemented or revised by using alternative dosimetry or other

effective neutron monitoring techniques during the period of extended operation.

By letter dated November 5, 2003, the applicant indicated that it has since reconsidered the use

of operating restrictions discussed above and has determined to leave one of the two remaining

capsules in the vessel for one additional cycle. During RF-15, VCSNS intends to remove the

last remaining capsule and place it in storage for possible future use. Also, the applicant

indicated that during RF-15, VCSNS intends to install alternative dosimetry to monitor vessel

fluence. The staff finds this acceptable because the applicant’s approach is in accordance with

the recommendations of GALL AMP XI.M31.

By RAI B.1.24-3, the staff requested that the applicant describe the analysis for demonstrating

that the materials in the inlet and outlet nozzles and upper shell course will not become limiting

materials during the period of extended operation. In response, the applicant stated that it has

performed an analysis for such demonstration. Since no information about the copper and

nickel contents for the nozzle forgings was found in the material test reports for the vessel, the

applicant used the values of 0.35 percent copper and 1.00 percent nickel, which are

recommended in 10 CFR 50.61 when the values are not available. The highest temperature for

the unirradiated reference temperature is 0 °F for one of the inlet nozzles. The applicant used

this reference temperature in its analysis. For the nozzle, a distance of 8 feet from the core

midplane to the edge of the nozzle was used for estimating the fluence value at the nozzle. 

Using these data, the applicant conservatively projected that the RTPTS for the nozzle material at

the 54 EFPY end of life (EOL) value is 145.2 °F. Therefore, the staff agrees with the applicant

that the vessel nozzles do not become limiting for a 60-year plant life because the highest
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projected value for the vessel nozzles is below the limiting beltline plate material of 158.1 °F. A

detailed discussion of the pressurized thermal shock (PTS) is provided in Section 4.2.2 of this

SER. 

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.29. The

staff concludes that the applicant’s FSAR Supplement provides an adequate description of the

programs credited with managing this aging effect, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.7 Reactor Vessel Internals Inspection Program

The applicant described its Reactor Vessel Internals Inspection Program in LRA Appendix

B.2.4. This is a new program and the applicant stated that the program is consistent with GALL

AMP XI.M16, PWR Vessel Internals,” with clarifications. 

The staff reviewed the applicant’s description of the program in LRA Appendix B, Section B.2.4

to determine whether the applicant demonstrated that it will adequately manage the applicable

aging effects at VCSNS during the period of extended operation, as required by 10 CFR

54.21(a)(3).

Summary of Technical Information in the Application

The applicant’s Reactor Vessel Internals Inspection Program is discussed in LRA Appendix B,

Section B.2.4, and in Appendix A, FSAR Section 18.2.28. This is a new program, and the

applicant stated that the program will be consistent with GALL AMP XI.M16, “PWR Vessel

Internals.” However, the applicant added the clarification that the VCSNS resolution criterion

for the enhanced VT-1 inspection is expected to be less than that specified in the GALL

program.

This new AMP is credited with managing the following aging effects:

• loss of fracture toughness in baffle/former bolts and other reactor vessel internals

• changes in dimension due to void swelling in reactor vessel internals, crack initiation and

growth in baffle/former bolts, and other reactor vessel internals

• loss of preload in baffle/former bolts and other reactor internals and

• loss of material due to wear in reactor vessel internals
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The applicant stated that this new inspection program will supplement the existing ISI Plan to

assess the condition of RV internals. The applicant has identified the components that will be

inspected under this program. For those components that are accessible or can be rendered

accessible by the removal of the core and other internals for examination, a visual inspection

will be performed to detect the presence and extent of cracking and loss of material. For bolts

and other inaccessible components, a volumetric inspection will be performed to detect the

presence and extent of changes in dimensions, cracking, loss of preload, and reduction of

fracture toughness.

Staff Evaluation

In LRA Appendix B, Section B.2.4, the applicant describes its AMP to manage aging processes

in RV internals. The LRA states that this AMP is consistent with GALL AMP XI.M16, with the

clarification that the resolution criterion for the enhanced VT-1 examination at the VCSNS is

expected to be less than that specified in the GALL program. The staff requested in RAI

B.2.4-1 that the applicant explain why it plans to use less than a 0.0005-in. resolution for the

enhanced VT-1 examination to be employed at VCSNS. In response, the applicant stated that

the capability to achieve a 0.0005-in. resolution for visual inspection has not been demonstrated

in the field. The staff does not agree with the applicant because the boiling water reactor

(BWR) Vessel Internals Program has developed such an enhanced visual inspection method

for detecting cracks in BWR vessel internals. However, the applicant stated that the details of

the Reactor Vessel Internals Inspection Program are not yet developed. The applicant further

stated that it will follow industry initiatives and have a program in place prior to the period of

extended operation. The staff finds the applicant’s response acceptable because the

recommendations of the industry initiatives will be reviewed and approved by the staff prior to

entering its license renewal period.

The applicant does not provide information about the neutron fluence threshold that it will use to

identify the vessel internals that are susceptible to loss of fracture toughness due to neutron

irradiation embrittlement of the RV internal components. The staff issued RAI B.2.4-2,

requesting the applicant to submit the neutron threshold value that it may use for identifying the

vessel internals susceptible to loss of fracture toughness due to neutron irradiation

embrittlement. In response to RAI B.2.4-2, in a letter dated June 12, 2003, the applicant stated

that the details of the Reactor Vessel Internals Inspection Program have not been developed. 

The applicant further stated that VCSNS will follow industry initiatives and will have a program

in place prior to the period of extended operation.

During a June 22, 2003, conference call, the staff requested that the applicant be more specific

about how it will identify the vessel internals susceptible to loss of fracture toughness due to

neutron embrittlement. In response, the applicant stated that it will consider operating

experience gained from aging management activities performed by plants that were originally

licensed before VCSNS. The staff finds this response acceptable because the applicant will

develop the details of the Reactor Vessel Internals Inspection Program based on the operating

experience of the plants that were originally licensed before VCSNS and have renewed their

licenses. These plants would have several years of extended operating experience before

VCSNS begins its extended period of operation. VCSNS will develop and implement a reactor

vessel internals inspection program prior to the period of extended operation and will implement
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aging management activities that are acceptable to the staff. The applicant has agreed that this

is a licensee commitment and this commitment is documented in Appendix A of this SER.

The staff also requested the applicant to provide information on how it will identify the RV

internals components susceptible to IASCC and select them for inspection. In response, the

applicant stated that it will follow industry initiatives and will have an inspection program in place

prior to the period of extended operation. The staff finds the applicant’s response acceptable

because the recommendations of the industry initiatives will be reviewed and approved by the

staff. The applicant has agreed.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.28. The

staff reviewed that section and concluded that the applicant’s FSAR Supplement provides an

adequate description of the programs credited with managing this aging effect, as required by

10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds 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

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.1.2.3.8 Small Bore Class 1 Piping Inspection

The applicant described its Small Bore Class 1 Piping Inspection program in LRA Appendix B,

Section B.2.7. This is a new program and the applicant stated that the program will be

consistent with GALL AMP XI.M32, “One-Time Inspection.”

This AMP, along with two existing AMPs, is credited with managing cracking in small-bore RCS

and connected systems piping. The existing AMPs include the Chemistry Program described in

LRA Appendix B, Section B.1.4 and the ISI Plan described in LRA Appendix B, Section B.1.7.

The staff reviewed the applicant’s description of the program in LRA Appendix B, Section B.2.7

to determine whether the applicant demonstrated that it will adequately manage the applicable

aging effects at VCSNS during the period of extended operation, as required by

10 CFR 54.21(a)(3).

Summary of Technical Information in the Application

The applicant states that this new program will help in assessing the current condition of small

bore piping that does not receive a volumetric examination. The applicant plans to perform the

inspection near the end of the second period of the fourth ISI interval. The applicant plans to

perform this inspection using destructive testing of selected samples. The applicant will identify

the locations most susceptible to cracking based on engineering evaluation, operating

experience, current code requirements, and industry initiatives. The applicant further stated
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that inspection locations will be selected by engineering judgment, using risk-based

approaches. One of the sample locations will be a butt weld. Since the program plans to use

destructive testing and replace the piping according to ASME Section XI, the applicant did not

see a need to define a corrective action prior to inspection.

Staff Evaluation

In LRA Appendix B, Section B.2.7, the applicant describes its AMP to manage cracking in small

bore piping. The LRA states that this AMP is consistent with GALL AMP XI.M32, with no

deviations. As stated in Section 3.1.2.2.6, the applicant will follow ongoing industry activities

related to failure mechanisms for small bore piping, including the recommendations of the

EPRI-sponsored MRP ITG on Thermal Fatigue. The applicant presented a reasonable

approach for identifying piping locations susceptible to damage. In response to an RAI, the

applicant stated that it will select those sample locations for inspection that are bounding

locations for Class 1 small bore piping within the scope of license renewal. Therefore, the

applicant’s approach for identifying susceptible locations and in selecting the sample locations

for inspections is acceptable. 

In response to an RAI regarding the inspection method, the applicant stated that it will inspect

the small bore Class 1 piping using a methodology that is approved by the staff. However, the

applicant does not want to commit to currently approved destructive examination techniques for

inspecting small bore piping during the extended period of operation because industry may

develop new, improved inspection techniques that VCSNS may want to employ at that time. 

The staff finds the applicant’s commitment for inspecting the small-bore piping with an NRCapproved methodology acceptable.

The FSAR Supplement for this program is presented in LRA Appendix A, Section 18.2.34. The

staff concludes that the applicant’s FSAR Supplement provides an adequate description of the

programs credited with managing this aging effect, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.1.2.3.9 Thermal Fatigue Management Program

The applicant described its Thermal Fatigue Management Program in Section B3.2 of the LRA. 

This program monitors loading cycles due to pressure and temperature transients for selected

critical components. The staff reviewed the applicant’s description of the program in LRA

Appendix B, Section B.3.2 to determine whether the applicant demonstrated that it will

adequately manage the applicable aging effects at VCSNS during the period of extended

operation, as required by 10 CFR 54.21(a)(3).
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Summary of Technical Information in the Application

The applicant indicated that this AMP is consistent with GALL AMP X.M1, with enhancements,

and the scope of the program had been enhanced to incorporate the new guidance in EPRI

Report MRP-47. In addition, the applicant committed to evaluate the effects of the reactor

coolant environment on the component locations identified in NUREG/CR-6260 using the

appropriate environmental fatigue factors. The applicant stated that the Thermal Fatigue

Monitoring Program (FMP) includes reviews of both industry and plant-specific operating

experience regarding fatigue cracking for applicability to VCSNS. 

Staff Evaluation

The applicant discussed the scope of the FMP in Section B3.2 of the LRA. The applicant

indicated that the scope of the program was enhanced to incorporate new guidance in EPRI

Report MRP-47. As discussed in Section 4.3 of this SER, the staff has not endorsed the

guidelines provided in EPRI Report MRP-47. As a consequence, the staff did not rely on the

guidance provided in MRP-47 for its review. 

The VCSNS program monitors loading cycles due to pressure and thermal transients for the

selected critical components discussed in Section 4.3 of this SER. The staff reviewed the

transients monitored by the program and the applicant’s evaluation of the effects of the reactor

environment. The staff evaluation of the transients monitored by the TFMP and the applicant’s

evaluation of the effects of the reactor water environment are discussed in Section 4.3 of this

SER. The staff found that the applicant identified the thermal transients that are significant

contributors to the design fatigue usage of RCS components. 

The staff also confirmed that the components monitored by the TFMP include the components

identified in NUREG/CR-6260. As discussed in Section 4.3 of this SER, the applicant has

committed to evaluate the impact of the reactor water environment of the components identified

in NUREG/CR-6260 prior to the period of extended operation. In LRA Section B3.2, the

applicant also committed to revise the TFMP acceptance criteria to account for the reactor

water environmental effects prior to the period of extended operation. The staff finds that the

applicant’s proposed acceptance criteria is consistent with GALL AMP X.M1.

Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the enhancements to the

GALL program and finds 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

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.1.2.4 Aging Management Review of Plant-Specific Reactor Vessel, Internals, and Reactor

Coolant Components.
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The reactor coolant mechanical components at VCSNS that requiring an AMR are described in

the following sections of the LRA:

• reactor coolant system (2.3.1.1)

• piping, valves and pumps (2.3.1.2)

• reactor vessel (2.3.1.3)

• reactor vessel internals (2.3.1.4)

• in-core instrumentation system (2.3.1.5)

• pressurizer (2.3.1.6)

• steam generators (2.3.1.7)

The applicant described the results from the AMR for the Class 1 portions of the RCS, including

the Class 1 piping, valves and pumps, reactor vessel, reactor vessel internals, in-core

instrumentation system, pressurizer, and SGs in LRA Section 3.1, “Aging Management of

Reactor Vessel, Internals, and Reactor Coolant System.” LRA Table 3.1-1, “Summary of Aging

Management Programs for the Reactor Coolant System Evaluated in NUREG-1801 that are

Relied on for License Renewal,” summarizes the results from the AMR for these RCS

components. The applicant described the applicable AMPs for these components in LRA

Appendix B, “Aging Management Programs and Activities.” This section of the SER presents 

the staff’s review of the AMR results presented in LRA Section 3.1 including the mechanical

components for all seven RCS subsystems identified above.

3.1.2.4.1 Reactor Coolant System

The reactor coolant system non-Class 1 components at VCSNS include the RCP oil collection

system components, piping and tubing, and valve bodies. The piping and tubing include

instrumentation tubing downstream of flow restrictors, piping downstream of Class 1 boundary

valves, charging system and letdown piping outside of the Class 1 boundary valves, vent and

drain piping connecting to the charging system RCP seal cooling piping, discharge piping from

relief valves and pressure control valves, valve leak-off piping, and the RCP oil collection

system. The piping downstream of Class 1 boundary valves includes piping connecting to the

emergency core cooling system (ECCS) check valve testing system, test connection piping

associated with the safety injection system, and sampling system piping.

Summary of Technical Information in the Application

The applicant identified the non-Class 1 RCS components within the scope of license renewal

in LRA Section 2.3.1.1. In three different LRA sections (3.1, 3.2, and 3.3), the applicant

described its AMPs process for non-Class 1 components and the aging management programs

that will be used to manage aging effects in these components during the period of extended

operation for VCSNS. This information is presented in LRA Tables 3.1-1, 3.1-2, 3.2-1, 3.2-2,

3.3-1, and 3.3-2, and is evaluated here.

The applicant identified the following TLAAs applicable to non-Class 1 piping in LRA Table

3.1-1:

• metal fatigue for ASME Section III

• class 2 and 3 piping fatigue 
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Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following aging effects for the nonClass 1 RCS components that are subject to an AMR:

• loss of material

• crack initiation and growth

In LRA Table 3.1-2, the AMR results identify no aging effect for stainless steel (including CASS)

non-Class 1 components exposed to moist or dry air environment, or deaerated distilled water. 

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identified that the Chemistry Program will manage

the aging effects associated with the non-Class 1 RCS components that are subject to AMRs.

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in Section

3.1, and in LRA Tables 3.1-1 and 3.1-2, and in pertinent sections of the LRA Appendices A and

B regarding the applicant’s demonstration that the effects of aging will be adequately managed

so that the intended functions of the non-Class 1 RCS components will be maintained

consistent with the CLB throughout the period of extended operation, as required by

10 CFR 54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant listed the non-Class 1 RCS components within the

scope of license renewal with their material groups and environment. The intended functions

of these components are listed in LRA Table 2.3-1. In LRA Tables 3.1-1 and 3.1-2, the

applicant also identified the aging effects requiring management and the plant-specific AMPs

required for managing them during the period of extended operation. The components within

the scope of license renewal are grouped according to component types.

In LRA Section 3.1, the applicant identifies the following TLAAs that are applicable to nonClass 1 RCS components:

• metal fatigue for ASME Section III

• Class 2 and 3 piping fatigue

The application of these TLAA is evaluated in Section 4.3 of this SER.

Aging Effects:

The material of construction for the non-Class 1 RCS components included in LRA Section 3.1

is primarily stainless steel (including CASS) for piping and piping system components and

capillary tubes and associated components. These components are exposed to chemically

treated borated water, treated water, and/or air-gas environments. The applicant performed a

review of industry experience and NRC generic communications related to the non-Class 1

components to provide reasonable assurance that the aging effects that require management

for a specific material-environment combination are the only aging effects of concern for
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VCSNS. This review also included a review of VCSNS plant-specific operating experience. 

LRA Tables 3.1-1 and 3.1-2 identify that loss of material and cracking are the only aging effects

applicable to the non-Class 1 RCS components requiring AMRs and included in LRA

Section 3.1.

Loss of material due to general corrosion is not normally an issue for austenitic stainless steel

(including CASS) non-Class 1 RCS components because the materials are normally inherently

tough and resistant to general corrosion; however, loss of material may be an applicable effect

for these components under wet conditions if the components have creviced areas that may be

exposed to the fluids or have areas where stagnant fluid may be present. The applicant 

identified that loss of material is an applicable aging effect for all stainless steel non-Class 1

RCS components with interior surfaces exposed to borated or treated water environments. The

staff finds this identification of loss of material as an aging effect acceptable because it

accounts for loss of material that could be caused by pitting or crevice corrosion.

LRA Table 3.1-2, AMR Item 1, states that the stainless steel tubing and CASS valve bodies

externally exposed to moist air environment have no aging effects requiring management. 

Similarly, LRA Table 3.3-1, AMR Item 6, states that there is no applicable aging effect for the

stainless steel oil collection system components. The applicant stated that the VCSNS ambient

environment does not contain contaminants of sufficient concentration to cause aging effects

that require aging management. The staff issued an RAI 3.1.2.4.2-8, requesting the applicant

to submit additional information supporting its determination that no aging effect requires 

management. In response to RAI 3.1.2.4.2-8, in a letter dated June 12, 2003, the applicant

stated that VCSNS is located well inland and does not see salt or other corrosive materials in

the air from agriculture or industry. The applicant further stated that moist air is not dry, but it is

noncondensing for the oil collection components, as well as most other components. The

review of operating experience at VCSNS has not identified any aging effects for these

components. Therefore, the staff finds the applicant’s statement of no applicable aging effect

to be acceptable for stainless piping, oil collection components, and CASS valve bodies

exposed to moist air environment.

LRA Table 3.1-2, AMR Item 6, identifies crack initiation and growth as an aging effect for the

non-Class 1 stainless steel pipe, orifices, tube and tube fittings, and valve bodies exposed to

chemically treated borated coolant. The staff finds this identification of cracking as an

applicable aging effect acceptable because stainless steel components exposed to the borated

coolant are susceptible to crack initiation and growth, especially when the coolant temperature

is greater than 93 °C (200 °F).

LRA Table 3.1-2, AMR Items 12 and 15, states that the stainless steel components exposed to

deaerated distilled water or air-gas environment have no aging effects requiring management. 

This is acceptable because the environment to which these components are exposed does not

contain moisture or contaminants that could cause corrosion damage.

LRA Table 3.2-2, AMR Item 4, states that the carbon steel and copper-nickel components

exposed to lubricating oil have no aging effects requiring management. This is acceptable

because these components are not subject to wetting and their surfaces always remain oilcoated because they are continuously in service.
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LRA Table 3.3-1, AMR Item 14, states that the RCP thermal barrier flange that is exposed to

treated water will have loss of material due to general, pitting, and crevice corrosion, and MIC,

and thus require aging management. This determination is acceptable because this AMR result

is consistent with the GALL Report.

Aging Management Programs:

The applicant identified the Chemistry Program in LRA Appendix B.1.4 for managing loss of

material and cracking in stainless steel non-Class 1 RCS components. The staff’s evaluation of

this program is presented in Section 3.0.3 of this SER.

LRA Table 3.1-2, AMR Item 5, states that stainless steel non-Class 1 RCS components are

internally exposed to chemically treated borated water and subject to loss of material due to

crevice and pitting corrosion. The Chemistry Program, LRA Appendix B.1.4, is credited with

managing this aging effect. These components include non-Class 1 orifices, pipe, tube, tube

fittings, and valve bodies. The applicant states that the Chemistry Program is similar to GALL

AMP XI.M2, except that it does not include a one-time inspection of selected components to

verify the effectiveness of the program. In RAI B.1.4-1, the staff requested the applicant to

explain why a one-time inspection is not needed to verify the absence of loss of material due to

pitting and crevice corrosion. In its response to RAI B.1.4-1, in a letter dated June 12, 2003,

the applicant stated that such inspections are not required because a review of VCSNS

operating experience did not reveal a loss of intended function of components that are exposed

to borated water. The staff finds the applicant’s explanation acceptable because the effects of

pitting and crevice corrosion on stainless steel components are not significant in chemically

treated borated water. Therefore, inspection of selected components for verifying the absence

of loss of material is not required.

LRA Table 3.1-2, AMR Item 6, states that stainless steel non-Class 1 RCS components are

internally exposed to chemically treated borated water and subject to crack initiation and growth

due to SCC; the Chemistry Program, LRA Appendix B.1.4, is credited with managing this aging

effect. These components include non-Class 1 orifices, pipe, tube, tube fittings, and valve

bodies. The applicant stated that the Chemistry Program is similar to GALL AMP XI.M2, except

that it does not include a one-time inspection of selected components to verify the effectiveness

of the program. In RAI B.1.4-1, the staff requested the applicant to explain why a one-time

inspection is not needed to verify the absence of cracking due to SCC. In its response to RAI

B.1.4-1, in a letter dated June 12, 2003, the applicant stated that such inspections are not

required because a review of VCSNS operating experience did not reveal any cracking in

components that are exposed to borated water. The staff finds the applicant’s explanation

acceptable. These chemistry related issues are discussed in Section 3.0.3.2 of this SER.

LRA Table 3.1-2, AMR Item 14, states that stainless steel piping and piping system

components, including non-Class 1 pipe and valve bodies, are internally exposed to treated

water from the reactor makeup water system for pressurizer relief tank spray. As a result,

these components are subject to loss of material due to crevice and pitting corrosion, and the

Chemistry Program, LRA Appendix B.1.4, is credited with managing this aging effect for these

components. The applicant stated that the Chemistry Program is similar to GALL AMP XI.M2,

except that it does not include inspection of selected components to verify the effectiveness of

the program. The staff finds the applicant’s explanation acceptable for not including inspection
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of selected components for verifying the absence of loss of material because the effects of

pitting and crevice corrosion on stainless steel components are not significant in treated water.

According to LRA Table 3.3-1, AMR Item 14, the applicant credits the Chemistry Program (LRA

Appendix B.1.4) for managing loss of material in RCP thermal barrier flange and piping in lieu

of GALL AMP XI.M21. However, the Chemistry Program does not require inspection of the

flange to determine whether loss of material due to corrosion is taking place, whereas the GALL

AMP XI.M21 requires such inspection. The applicant stated that the Chemistry Program has

been in effect since initial plant startup and has been proven effective in maintaining system

chemistry. The applicant further stated that a review of the operating experience confirmed the

effectiveness of this program. Therefore, the staff finds that the applicant’s use of the

Chemistry Program alone is acceptable for managing loss of material in RCP thermal barrier

flange and piping.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.2 Reactor Coolant Piping, Valves, and Pumps

The reactor coolant piping, valves, and pumps include Class 1 piping and valves, and reactor

coolant pumps. The Westinghouse-supplied primary piping includes fittings, safe ends, branch

connection nozzles, thermal sleeves, flow restrictors, and thermowells. The Class 1 portion of

the RCS includes portions of the chemical and volume control system, emergency core cooling

system, residual heat removal system, and safety injection system.

ASME Class 1 piping includes piping connected to the Westinghouse-supplied primary loop

piping out to and including (1) the outermost containment isolation valve in piping which

penetrates primary containment or (2) the second of two valves usually closed during normal

reactor operation in piping which does not penetrate primary containment. Some branch

connections and instrument connections in the RCS are equipped with 3/8 in. inside diameter

(ID) flow restricting orifices that limit the maximum flow from a break downstream of the flow

restrictor to below the makeup capability of the RCS. This orifice is used instead of double

isolation valves to establish the division from Class 1 to Class 2.

For Class 1 valves, the pressure-retaining portion of the component consists of the valve body,

bonnet, and closure bolting. The valves are welded in place with the exception of the

pressurizer safety valves that have flanged connections. For the reactor coolant pumps, the

pressure-retaining portion includes the pump casing, the main closure flange, the thermal

barrier heat exchanger flange and piping, and the pressure-retaining bolting.

Summary of Technical Information in the Application

The applicant identified the Class 1 RCS piping, valves, and pumps within the scope of license

renewal in LRA Section 2.3.1.2. In Section 3.1 of the application, the applicant described its

AMR process for ASME Code Class 1 components and the AMPs that will be used to manage
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aging effects in these components during the periods of extended operation for VCSNS. In

LRA Tables 3.1-1 and 3.1-2, the applicant identified that the following Class 1 RCS piping,

valves, and pumps within the scope of license renewal require AMRs:

• Westinghouse-supplied primary loop Class 1 piping of the RCS pressure boundary that

is connected to the reactor vessel, the SGs (primary side), and the reactor coolant pump

• Class 1 piping of other support systems that is attached to the primary loop piping

• pressure boundary portion of Class 1 valves (bodies and bonnets, bolting)

• pressure boundary portion of the RCP (casing, main closure flange, thermal barrier heat

exchanger and bolting).

The applicant described its AMR of the Class 1 piping and associated components for license

renewal in LRA Section 3.1.1 and in LRA Tables 3.1-1 and 3.1-2. The staff reviewed this LRA

section to determine whether the applicant demonstrated that the effects of aging on the RC

Class 1 piping, valves, and pump casings will be adequately managed during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

The applicant stated that the RCS Class 1 piping, valve, and pump components within the

scope of license renewal have been designed to meet the requirements of ASME Boiler and

Pressure Vessel Code, Section III, Subsection NB for Class 1 components. The predominant

material of construction for the Class 1 components, including piping and pipe fittings, is

stainless steel, including CASS. The internal surfaces of all Class 1 piping and associated

components wetted by borated water are stainless steel. Some bolting and exterior surfaces of

the pressure boundary components are identified as carbon or low-alloy steel. Design and

welding considerations in the selection of materials for RCS components reduce the

susceptibility of Class 1 piping and component materials to sensitization.

The Class 1 piping and associated components that are within the scope of license renewal are

internally exposed to borated reactor coolant water at approximately 315.6 o

C (600 oF) and

15.41 MPa (2235 psig). These components are located in the reactor building (i.e.,

containment) and are externally exposed to an air environment. External surfaces near

mechanical piping connections (e.g., flanges) may also be exposed to borated water leakage. 

The thermal barrier heat exchangers for the RCPs are also exposed to treated water.

In LRA Section 4.0, the applicant identified the following three TLAAs applicable to RCS piping

and associated components; only the first one is specifically identified in LRA Table 3.1.1:

Metal fatigue for ASME class 1 components

RCP flywheel fatigue

Leak-before-break analyses

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following aging effects for the RCS

Class 1 piping and associated components that are subject to an AMR:
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• cracking

• loss of material

• reduction in fracture toughness

• loss of preload

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following four AMPs to manage the

aging effects associated with reactor coolant piping, valves, and pumps:

• Boric Acid Corrosion Surveillances

• Chemistry Program

• Inservice Inspection Plan

• Small Bore Class 1 Piping Inspection

The first three programs are existing, whereas the last one is a new program at VCSNS. The

applicant concluded that these AMPs will manage the effects of aging such that the intended

function of the RCS Class 1 piping and associated components will be maintained consistent

with the CLB under all design-loading conditions throughout the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA

Section 3.1, Tables 3.1-1 and 3.1-2, and pertinent sections of LRA Appendices A and B

regarding the applicant’s demonstration that the effects of aging will be adequately managed so

that the intended functions of the reactor coolant piping, valves, and pumps will be maintained

consistent with the CLB throughout the period of extended operation, as required by

10 CFR 54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant listed the reactor coolant piping, valves, and

pumps within the scope of the license renewal with their material groups and environment. The

intended functions of these components are listed in LRA Table 2.3-2. In the LRA tables, the

applicant also identified the aging effects requiring management, and the plant-specific AMPs

for managing them during the period of extended operation. The components within the scope

of license renewal are grouped in according to their component types, and these groups are

listed in these tables.

In LRA Section 4.0, the applicant identified the following three TLAAs applicable to reactor

coolant piping and associated components:

• metal fatigue for ASME Class 1 components (Section 4.3)

• RCP flywheel fatigue (Section 4.7.1)

• leak-before-break analyses (Section 4.7.2)

Aging Effects:

In accordance with LRA Section 3.1, the applicant performed a review of industry experience,

NRC generic communications, and VCSNS plant-specific operating experience related to the
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RCS Class 1 piping, valves, and pumps to present reasonable assurance that the aging effects

that require management for a specific material-environment combination are the only aging

effects of concern for VCSNS.

The material of construction for the RCS Class 1 piping, valves, and pumps subject to an AMR

is primarily stainless steel (including CASS). Carbon steel and low-alloy steel are used for RCP

main flange bolting. Most RCS piping and associated components are exposed to borated

water, treated water, and/or air. The applicant performed a review of industry experience and

NRC generic communications related to the reactor coolant piping and associated components

to provide reasonable assurance that the aging effects that require management for a specific

material-environment combination are the only aging effects of concern for VCSNS. This

review also included a review of VCSNS plant-specific operating experience. In LRA Tables

3.1-1 and 3.3-1, the applicant identified the following aging effects that are applicable to the

RCS Class 1 piping, valves, and pumps requiring AMRs:

• loss of closure integrity of stainless steel and low-alloy steel bolting in the reactor

building (i.e., air) environment

• loss of material for low-alloy steel bolting externally exposed to leaking borated coolant

• cracking of CASS RCS nozzles and elbows internally exposed to chemically treated

borated coolant

• cracking of austenitic stainless steel small-bore RCS piping internally exposed to

chemically treated borated coolant

• reduction in fracture toughness of CASS components (including valve bodies and

bonnets, and RCP casings and main closure flanges) in a high temperature borated

water environment

The applicant stated that the identification of the above aging effects in LRA Table 3.1-1 is

consistent with the GALL Report, with one exception. For stainless steel and low-alloy steel

bolting, the applicant identified loss of closure integrity, rather than loss of preload and cracking, 

as an aging effect requiring management. In RAI 3.1.2.4.2-1b, the staff requested the applicant

to describe the difference between loss of closure integrity and the aging effects of cracking,

loss of material, and loss of preload. In a response to RAI 3.1.2.4.2-1b, in a letter dated

June 12, 2003, the applicant stated that loss of mechanical closure integrity can result in failure

of the mechanical joint and is evidenced by leakage rather than joint failure. The applicant

further stated that this failure of mechanical joint can be attributed to loss of bolt preload, loss of

bolting material by wear, and cracking of high-strength bolting material. Therefore, loss of

closure integrity includes the effects of loss of preload, loss of material, and cracking of bolting

materials. The staff finds this explanation acceptable because, as discussed in Section

3.1.2.4.2, the management of loss of closure integrity also provides management of loss of

preload, loss of material, and cracking of bolting material.

LRA Table 3.1-1, AMR Item 20, states that the CASS elbows and nozzles of the RCS Class 1

piping are not susceptible to loss of fracture toughness because these components have low

molybdenum content and have delta ferrite levels of less than 20 percent. The staff finds this
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acceptable because the molybdenum content and the delta ferrite levels for these components

meet the screening criteria set forth in a letter dated March 19, 2000, from Christopher Grimes,

NRC, to Douglas Walters, NEI. 

In LRA Table 3.1-1, AMR Item 24, the applicant identified the following discrepancy in the GALL

Report (NUREG-1801). The NUREG-1801, Table 1 “Component” column presents an

exception for cast stainless steel components (i.e., valve bodies and bonnets, and RCP pump

casings). However, the column entitled, “Item Number in GALL” includes these components.

Therefore, the applicant has included the AMR results for these components in LRA Table

3.1-1, AMR Item 24. The staff has reviewed Table 1 and Table IV.C2 of the GALL Report and

confirmed that the applicant’s finding is correct and that the applicant1s AMR for these CASS

components is consistent with GALL.

The austenitic stainless steel RCS piping is susceptible to SCC at the external surface if it

comes in contact with halogens that may be present in the thermal insulation. The applicant,

however, does not identify cracking as an aging effect at the external surface of these

components. The staff issued RAI 3.1.2.4.2-3, requesting the applicant to submit a description

of all insulation used on austenitic stainless steel RCS piping to ensure that the piping is not

susceptible to stress-corrosion cracking from halogens. In response to RAI 3.1.2.4.2-3, in a

letter dated June 12, 2003, the applicant stated that stainless steel reflective insulation is the

most commonly used insulation type on stainless steel piping and components. Various other

types of insulation used on stainless steel are encapsulated in stainless steel. The applicant

further stated that, unlike fibrous insulation, the stainless steel does not need controls for

halogens. The staff agrees with the applicant that the external surface of the stainless steel

RCS piping is not susceptible to cracking due to SCC because VCSNS uses stainless steel

insulation which does not contain halogens. 

The staff reviewed NUREG-1801, Chapter IV.C2, “Reactor Coolant System and Connected

Lines,” and confirmed that the applicant1s identification of the aging effects for RCS Class 1

piping, valves, pumps, and closure bolting in Table 3.1-1 is consistent with the GALL Report,

and therefore acceptable.

In Table 3.1-2, the applicant identified the following additional aging effect for Class 1 RCS

piping:

• loss of material in stainless steel components (including CASS) internally exposed to

chemically treated borated coolant

The stainless steel components are inherently tough and resistant to general corrosion;

however, loss of material due to crevice and pitting corrosion may be an applicable effect for

these components under wet conditions, especially if the components have creviced areas that

may be exposed to the fluids. Therefore, the applicant's identification of loss of material as an

aging effect for stainless steel components internally exposed to chemically treated borated

coolant is acceptable because it conservatively accounts for loss of material that could be

induced by these corrosion mechanisms, even though these components do not have creviced

regions. 

LRA Table 3.1-2, AMR Item 1, states that the stainless steel piping (including CASS) exposed

to a moist air environment is not susceptible to any aging effect requiring management. The
3-104

staff finds this acceptable because the stainless steel components are resistant to general

corrosion and the ambient environment at VCSNS does not contain contaminants of sufficient

concentration to cause any aging effect requiring management.

The aging effects identified in the LRA for the Class 1 portion of the RCS piping, valves, and

pumps are consistent with industry operating experience for the materials and environments

listed. The staff finds that all the plausible aging effects were identified and that the aging

effects listed are appropriate for the combination of materials and environments specified.

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identified the following four AMPs to manage the

aging effects associated with reactor coolant piping, valves, and pumps: 

• Boric Acid Corrosion Surveillance Program

• Chemistry Program

• Inservice Inspection Plan

• Small Bore Class 1 Piping Inspection

The Boric Acid Corrosion Surveillance program (LRA Section B.1.2) was developed by the

applicant in response to NRC GL 88-05. Inspections are performed to present reasonable

assurance that borated water leakage from the reactor coolant pressure boundary does not

lead to undetected loss of material on the external surface of carbon steel or low-alloy steel

bolting. The staff has evaluated this common AMP and found it to be acceptable for managing

the aging effect of loss of material identified for the RCS pressure boundary closure bolting. 

The staff’s evaluation of this AMP is documented in Section 3.0.3.1 of this SER.

According to LRA Table 2.3-2, AMR Item 6 of LRA Table 3.1-1 and AMR Item 6 of LRA Table

3.1-2 present the results for austenitic stainless steel piping and fittings (less than NPS 4) and

orifices exposed to chemically treated borated coolant. Both AMR items identify the same

aging effect (i.e., cracking) but different AMPs. AMR Item 6 of LRA Table 3.1-1 credits three

programs, the Chemistry Program (LRA Appendix B.1.4), the ISI Plan, (LRA Appendix B.1.7),

and the Small Bore Class 1 Piping Inspections (LRA Appendix B.2.7) for managing cracking. 

However, AMR Item 6 of LRA Table 3.1-2 credits only one program, the Chemistry Program

(LRA Appendix B.1.4), for managing cracking. The staff issued RAI 3.1.2.4.2-6, requesting the

applicant to explain this apparent discrepancy. In its response to RAI 3.1.2.4.2-6, in a letter

dated June 12, 2003, the applicant stated that Table 3.1-1, Item 6, includes only Class 1 piping,

whereas Table 3.1-2, Item 6, includes thermocouple seals, reactor coolant tubing and fittings,

RCP thermal barrier flange, and non-Class 1 piping. The applicant asserted that the Chemistry

Program alone is adequate for managing cracking in these stainless steel, non-Class 1 piping

components. The applicant supported its assertion by referring to GALL, Chapter V, which

states that the Chemistry Program alone can be acceptable AMP for crack initiation and growth

for stainless steel components.

The staff’s review of GALL, Chapter V revealed that GALL has accepted the Chemistry

Program alone for managing cracking in the stainless steel components exposed to chemically

treated borated coolant because the coolant temperature is less than 93 °C (200 °C); below this

temperature, stainless steel has significantly low susceptibility to cracking due to SCC. 

Therefore, the staff accepts the applicant’s use of the Chemistry Program alone for managing
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cracking in the stainless steel components, provided that these components are exposed to

borated coolant at a temperature less than 93 °C. Otherwise, the use of the Chemistry

Program alone is not adequate for managing cracking on the inside surface of the non-Class 1

stainless steel components, and the applicant needs to provide a program to verify that

cracking is not occurring on the inside surface of these components. These chemistry related

issues are discussed in Section 3.0.3.2 of this SER. 

The applicant credited the ISI Plan (LRA Section B.1.7) and the Chemistry Program (LRA

Section B.1.4) for managing crack initiation and growth in the RCS Class 1 austenitic stainless

steel piping, CASS elbows and nozzles, and CASS valve bodies and pump casings. The staff

evaluations of the ISI Plan and Chemistry Program are documented in Sections 3.1.2.3.3 and

3.0.3.2, respectively, of this SER. The scope of the ISI Plan for the Class 1 components

complies with the requirements of ASME Section XI, Subsection IWB. Depending on the

examination category, the methods of inspection may include visual, surface, and/or volumetric

examination of the welded portion of the components susceptible to aging degradation. The

staff finds the use of the ISI Plan and Chemistry Program for managing cracking in Class 1

stainless steel components acceptable because the operating experience indicates that these 

programs have been effective in managing cracking in stainless steel components.

The applicant credited the ISI Plan (LRA Appendix B.1.7) for managing loss of closure integrity

in the RCS Class 1 closure bolting, including RCP main flange bolting. In RAI 3.1.2.4.2-1a, the

staff requested the applicant to explain how the management of loss of closure integrity by the

ISI Plan would ensure that the intended function of the bolted joint would be maintained during

the extended period of operation. In response to RAI 3.1.2.4.2-1a, in a letter dated June 12,

2003, the applicant stated that the management of the loss of closure integrity with the ISI Plan

includes surface and volumetric examinations for detecting cracking and loss of material in

bolts and nuts during each inspection interval or when a closure is disassembled. When

closure bolting is disassembled, retorquing of the bolting during reassembly establishes the

desired preload. Thus, any loss of preload that might have occurred during previous operation

would be removed when a closure bolting is disassembled and then reassembled. The staff

accepts the applicant’s response because the applicant’s management of loss of mechanical

closure integrity with the ISI Plan is adequate for managing the aging effects of loss of material,

cracking, and loss of preload. Therefore, it ensures that the intended function of the closure

bolting would be maintained during the extended period of operation.

The NRC IN 2000-17, “Crack in Weld Area of Reactor Coolant System Hot Leg Piping at V.C.

Summer,” reports a through-wall crack in Alloy 182/82 weld between the A hot-leg nozzle and

stainless steel piping caused by PWSCC. The applicant described this event as operating

experience in LRA Appendix B.1.1, Alloy 600 AMP. A spool piece was used to replace the

affected weld and was installed using Alloy 52 and 152 weld materials, in effect removing the

susceptible material. The applicant also reported that further inspection of the other RCS

nozzle safe end-to-pipe welds detected minor indications of cracking in B and C hot-leg

nozzles. The staff issued RAI 3.1.2.4.2-4 to confirm whether the Alloy 600 AMP is credited for

managing PWSCC cracking in Alloy 82/182 welds in RCS Class 1 piping. This RAI was

discussed during a June 22, 2003, conference call. In response, the applicant stated that aging

management of ASME Class 1 dissimilar welds (Alloy 82/182 welds) is within the scope of LRA

Appendix B.1.1, Alloy 600 AMP. The staff finds the response acceptable because it is

consistent with the AMR results presented in LRA Table 3.1-1.
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In RAI 3.1.2.4.2-4, the staff also requested the applicant to identify any mitigative actions taken

since the submittal of the LRA to minimize the growth of existing PWSCC cracks in B and C

hot-leg nozzles. In response to RAI 3.1.2.4.2-4, in a letter dated June 12, 2003, the applicant

stated that VCSNS has implemented a mechanical stress improvement process (MSIP) for the

B and C hot-leg nozzles that were not repaired. The applicant further stated that because of

the application of MSIP, the leak-before-break analysis does not need to be revised. For

further information, the applicant referred to a letter from K.R. Cotton (NRC) to S.A. Bryan,

“Safety Evaluation of Flaws Detected in V. C. Summer Nozzle-to-Pipe Welds in the Hot Legs of

Loops B and C (TAC No. MB4870),” October 1, 2002. The letter states that the application of

MSIP has reduced the VCSNS plant-specific PWSCC crack growth rate and the driving force

for the cracks has been either eliminated or greatly reduced. The applicant plans to perform

inspection of the nozzles during the next refueling cycle (RF-14) and submit the inspection

results to the staff for review so that the adequacy of the applicant’s future inspection plans for

the detected flaws can be assessed. The applicant’s approach for managing the detected flaws

in the two hot-leg nozzle-to-piping welds is acceptable because it will be reviewed and approved

by the staff.

The Chemistry Program (LRA Appendix B.1.4) references water quality that is compatible with

the materials of construction used in the Class 1 piping and associated components in order to

minimize loss of material and cracking. This program incorporates EPRI and Institute of

Nuclear Power Operations (INPO) guidelines, which reflect industry experience, and the

“lessons learned” from VCSNS and external industry operating experience. However, the

applicant does not identify any specific document for the water chemistry guidelines. The GALL

AMP XI.M2, “Water Chemistry,” refers to EPRI TR-105714, :PWR Primary Water Chemistry

Guidelines—Revision 3.” In RAI 3.1.2.4.2-5, the staff requested the applicant to confirm

whether the Chemistry Program incorporates the guidelines in EPRI TR-105714, Revision 3 or

a later revision. In its response to RAI 3.1.2.4.2-5, dated June 12, 2003, the applicant stated 

that the VCSNS Chemistry Program incorporates the guidelines of EPRI TR-105714, Revision

4. Although the applicant follows the guidelines of Revision 4 instead of Revision 3 of the EPRI

report, the staff finds the applicant’s response acceptable because Revision 4 accounts for the

industry experience since the publication of Revision 3.

In LRA Table 3.1-2, AMR Items 5 and 7, the applicant credited the Chemistry Program (Section

B.1.4) for managing loss of material in the austenitic stainless steel components (including

CASS). This is adequate because the stainless steel components are inherently tough and

resistant to general corrosion. As stated in Section 3.1.2.4.2 of the SER, these components

under wet conditions could experience loss of material due to pitting and crevice corrosion,

especially if the components have creviced areas exposed to the fluids. The staff issued RAI

B.1.4-1, requesting the applicant to explain why a one-time inspection is not needed for

verifying the absence of loss of material due to pitting and crevice corrosion. In response to

RAI B.1.4-1, in a letter dated June 12, 2003, the applicant stated that such inspections are not

required because a review of VCSNS operating experience did not reveal a loss of intended

function of components that are exposed to borated water. In addition, these stainless steel

components do not have creviced regions. The staff finds the applicant’s explanation

acceptable for not including inspection of selected components to verify the absence of loss of

material because the effects of pitting and crevice corrosion on stainless steel components are

not significant in chemically treated borated water.
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The applicant proposed a new program, the Small Bore Class 1 Piping Inspections Program,

along with two existing programs, the Chemistry Program and ISI Plan, to manage cracking of

the small-bore Class 1 RCS piping. The staff’s evaluation of the adequacy of these three

programs for managing cracking of the small-bore Class 1 RCS piping is presented in Section

3.1.2.2.6 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the Class 1

portion of the RCS piping, valves, and pumps will effectively manage or monitor the aging

effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.3 Reactor Vessel

The VCSNS vessel, fabricated by Chicago Bridge and Iron, Inc., is cylindrical, with a welded

hemispherical bottom head and a removable, bolted, flanged, and gasketed, hemispherical

upper head. The reactor vessel flange and head are sealed by two hollow metallic O-rings. 

Seal leakage is detected by means of two leakoff lines. The vessel contains the core, core

support structures, control rods, and other parts directly associated with the core. The reactor

vessel closure head contains adapters for connecting the control rod drive mechanisms

(CRDM) and instrumentation. The vessel has an inlet and an outlet nozzle for each of the three

primary piping loops located just below the flange. Coolant enters through the inlet nozzles,

flows down the core barrel-vessel annulus, turns at the bottom and flows through the core to

the outlet nozzles. Inlet and outlet nozzles are located symmetrically around the vessel. The

bottom head of the vessel contains penetration nozzles for connection and entry of the nuclear

in-core instrumentation.

The reactor vessel is classified as a Class 1 component and, therefore, the design and

fabrication of the vessel was carried out in accordance with ASME Code, Section III, Class 1

requirements. The use of sensitized stainless steel as a pressure boundary material was

eliminated by either a choice of material or by programming the method of assembly. The

carbon/low-alloy steel vessels are clad on their internal surfaces with austenitic stainless steel

to prevent the carbon/low-alloy steel materials from being in direct contact with the primary

coolant.

The cylindrical portion of the VCSNS reactor vessel is made of several shells, each consisting

of formed plates joined by full penetration, longitudinal and circumferential welds. The

hemispherical heads are made from dished plates. The vessel flange, nozzles, and nozzle safe

ends are made of forgings. The vessel plates and forgings are joined by welding. 

LRA Section 2.3.1.3 and UFSAR Section 5.4.2 describe the VCSNS reactor vessel and its

appurtenances.

Summary of Technical Information in the Application
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The applicant describes its AMR of the reactor vessel in LRA Section 3.1, “Aging Management

of Reactor Vessel, Internals, and Reactor Coolant System.” The staff reviewed this section of

the LRA to determine whether the applicant has demonstrated that the effects of aging on the

reactor vessel and its appurtenances will be adequately managed during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Fourteen component groups are listed in LRA Tables 3.1-1 and 3.1-2. They include shell

components, nozzles, head penetrations, and CRDM housings. The intended function of all of

these components is to provide the pressure boundary. The reactor vessel core support pads

support the reactor vessel internals. 

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following aging effects for the reactor

vessel and its appurtenances that are subject to an AMR:

• cracking

• loss of material

• loss of fracture toughness

• loss of closure integrity

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following six existing AMPs to

manage the aging effects associated with reactor vessel and its appurtenances:

• boric acid corrosion surveillance program

• chemistry program

• Inservice inspection plan

• reactor vessel surveillance program

• alloy 600 aging management program

• reactor head closure studs program

The applicant concluded that these AMPs will manage the effects of aging such that the

intended function of the reactor vessel and its appurtenances will be maintained consistent with

the CLB under all design loading conditions throughout the period of extended operation, as

required by 10 CFR 54.21(a)(3).

The applicant does not specifically identify any TLAAs in Section 3.1 of the LRA that is

applicable to reactor vessel and its appurtenances. However, Section 4.0 of the LRA includes

the following TLAAs applicable to the reactor pressure vessel and its appurtenances:

• reactor vessel neutron embrittlement (Section 4.2 of the LRA)

• metal fatigue (Section 4.3 of the LRA)

The staff’s evaluations of these TLAAs are presented in Sections 4.2 and 4.3, respectively, of

this SER.

Staff Evaluation
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In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA

Section 3.1, Tables 3.1-1 and 3.1-2, and the pertinent sections of LRA Appendices A and B,

regarding the applicant’s demonstration that the effects of aging will be adequately managed so

that the intended function(s) of the reactor vessel will be maintained consistent with the CLB

throughout the period of extended operation, as required by 10 CFR 54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant lists the reactor vessel and its appurtenances

within the scope of the license renewal with their material groups and environment. The

intended functions of these components are listed in LRA Table 2.3-3. In the LRA tables, the

applicant also identifies the aging effects requiring management and the plant-specific AMPs

required to manage these aging effects during the period of extended operation. The

components within the scope of license renewal are grouped in accordance with their

component types, and these groups are listed in these tables. 

In LRA Section 4.0, the applicant identifies the following two TLAAs applicable to the reactor

vessel and its appurtenances:

• reactor vessel neutron embrittlement (Section 4.2)

• metal fatigue (Section 4.3)

Aging Effects:

In accordance with LRA Section 3.1, the applicant has performed a review of industry

experience and NRC generic communications relative to the reactor vessel and its

appurtenances to present reasonable assurance that the aging effects that require

management for a specific material-environment combination are the only aging effects of

concern for VCSNS. This also included the plant-specific operating experience at VCSNS.

The materials of construction for the reactor pressure vessel and its appurtenances subject to

an AMR are low-alloy steel for vessel shell, closure head, bottom head, and flange (including

stainless steel cladding); carbon steel or low-alloy steel for vessel support; stainless steel for

CRDM housings; Alloy 600 for head penetrations and reactor vessel core support pads; and

high-strength low-alloy steel for reactor vessel closure studs. The inside surface of reactor

vessel components are exposed to borated water and the external surfaces of reactor vessel

components are exposed to air. In LRA Table 3.1-1, the applicant identifies the following aging

effects applicable to the reactor vessel and its appurtenances requiring an AMR:

• loss of fracture toughness for low-alloy steel reactor vessel beltline shell and welds

internally exposed to chemically treated borated coolant

• cracking of stainless steel reactor vessel nozzle safe ends and CRD housings, and

cladding on low-alloy steel vessel shell, heads and nozzles exposed to chemically

treated borated coolant

• cracking of Alloy 600 closure head and bottom head penetrations, and core support

pads exposed to chemically treated borated coolant

• loss of closure integrity of high strength low alloy reactor vessel closure studs exposed

to containment environment (i.e., air)
3-110

• loss of material due to wear of reactor vessel flange, closure studs and core support

pads

• loss of material in low alloy steel reactor vessel shell and heads, carbon steel vessel

support and closure studs exposed to leaking borated coolant 

The applicant states that the identification of the above aging effects in LRA Table 3.1-1 is

consistent with the GALL report. In LRA Table 3.1-1, AMR Item 7, the applicant states that the

vessel shell materials at VCSNS do not include ASME SA-508, Class 2 material, which is

susceptible to underclad cracking if the cladding was deposited on it with a high-heat input

welding process. Since the VCSNS vessel shell does not include ASME SA-508, Class 2

material, it is not susceptible to underclad cracking. However, as discussed in Section 3.1.2.2.7

of this SER, the vessel flange and nozzle forgings are made of ASME SA 508, Cl2 material. 

The underclad cracking is not an applicable aging effect for these forgings because the highheat input welding processes affecting underclad cracking were not used for application of

cladding to these components. The staff accepts that underclad cracking is not an applicable

aging effect for the VCSNS vessel components made of ASME SA-508, Class 2 material

because the high-heat input welding processes were not used for application of cladding to

these components.

LRA Table 3.1-1, AMR Item 9, represents the AMR results for various Ni alloy components

except CRD nozzles exposed to the chemically treated borated coolant. The applicant states

that at VCSNS, only, the core support pads and bottom head penetration tubes are included in

this item. The applicant identifies crack initiation and growth due to PWSCC as an applicable

aging effect for these components. The staff finds this identification acceptable because it is

consistent with industry experience.

In LRA Table 3.1-1, AMR Item 18, the applicant states that for closure studs, the aging effect

requiring management is loss of closure integrity rather than cracking. The staff has evaluated

the management of aging effects for reactor vessel closure studs in Section 3.1.2.3.4 and

determined that management of loss of closure integrity includes the management of cracking

of closure studs.

In LRA Table 3.1-1, AMR Item 22, the applicant states that loss of material due to wear is not

considered a valid aging effect for the control rod drive flange bolting requiring management. 

This statement implies that VCSNS has installed control rod drive flange bolting. However,

Section 5.4.2 of the VCSNS UFSAR states that the upper ends of the CRD nozzles have a

welded flexible canopy seal and not bolting. The staff issued RAI 3.1.2.4.3-2, requesting the

applicant explain this discrepancy. In response to RAI 3.1.2.4.3-2, in a letter dated June 12,

2003, the applicant states that the VCSNS CRD nozzles are seal welded to the CRDMs. 

Therefore, the pressure boundary is not a bolted connection. The applicant further states that

bolts are used for the magnetic housings; however, they do not constitute pressure boundary

and are not in scope. Therefore, the staff finds the applicant’s clarification acceptable because

it is consistent with the design of the Westinghouse plants where the upper end of the CRD

nozzles are welded to the flexible canopy seal.

LRA Table 2.3-3 refers to LRA Table 3.1-1, AMR Item 28, for the AMR results for the reactor

vessel closure studs assembly. However, LRA Table 3.1-1, AMR Item 28, presents the AMR
3-111

results for vessel and vessel closure head flanges and not for closure studs assembly. The

staff issued RAI 3.1.2.4.3-3, requesting the applicant to explain this discrepancy. In response

to RAI 3.1.2.4.3-3, in a letter dated June 12, 2003, the applicant states that the reactor vessel

closure studs are not included in Table 3.1-1, Item 28. The staff finds the response acceptable

because it is consistent with GALL.

The staff has reviewed NUREG-1801 Chapter IV.A2, Reactor Vessel, and confirmed that the

applicant’s identification of the aging effects in Table 3.1-1 for the reactor vessel and its

appurtenances is consistent with the GALL report, except for the discrepancies noted in SER

Table 3.1-1, and therefore acceptable.

LRA Table 3.1-2, AMR Items 1 and 2, state that the stainless steel CRD housings, Alloy 600

vessel closure head and bottom head penetrations, and Alloy 82/182 welds between the vessel

nozzle safe ends and main coolant loop piping are exposed to moist air environment. These

components are not susceptible to any aging effects requiring management. This is acceptable

because the stainless steel and Ni-alloy based components are resistant to general corrosion

and the ambient environment at VCSNS does not contain contaminants of sufficient

concentration to cause an aging effect requiring management.

In Table 3.1-2, AMR Item 7, the applicant identifies loss of material as an aging effect for

stainless steel and Ni-alloy components attached to the reactor vessel.

The stainless steel components are inherently tough and resistant to general corrosion;

however, loss of material due to crevice and pitting corrosion may be an applicable aging effect

for these components under wet conditions, especially if the components have creviced areas

that may be exposed to the fluids. Therefore, the applicant's identification of loss of material as

an aging effect for stainless steel components internally exposed to chemically treated borated

coolant is acceptable.

LRA Table 2.3-3 refers to LRA Table 3.1-1, AMR Item 23, and LRA Table 3.1-2, AMR Item 11,

for AMR results for Alloy 600 reactor vessel closure head penetration tubes. Both AMR Items

address cracking as an aging effect for these tubes. AMR Item 23 proposes the Alloy 600

aging management program whereas AMR Item 11 proposes the chemistry program. The staff

issued RAI 3.1.2.4.3-5, requesting the applicant to explain this discrepancy. In response to RAI

3.1.2.4.3-5, in a letter dated June 12, 2003, the applicant states that LRA Table 3.1-2, Item 11,

should not be referenced in LRA Table 2.3-3 for RV closure head penetration tubes. The staff

finds this explanation acceptable because it is consistent with the AMR results presented in the

LRA. 

The austenitic stainless steel and Ni-alloy based reactor vessel appurtenances (i.e., CRD

housings, vessel head penetrations, and Alloy 82/182 welds) are susceptible to stress corrosion

cracking at the external surface if they come in contact with halogens that may be present in

the thermal insulation. The applicant has not identified cracking as an aging effect at the

external surface of these components. The staff issued RAI 3.1.2.4.3-4, requesting the

applicant to submit a description of all insulation used on austenitic stainless steel RCS piping

to ensure that the reactor vessel appurtenances are not susceptible to stress-corrosion

cracking from halogens. In response to RAI 3.1.2.4.3-4, in a letter dated June 12, 2003, the

applicant states that stainless steel reflective insulation is the most commonly used insulation

type on stainless steel piping and components. Various other types of insulation used on
3-112

stainless steel are encapsulated in stainless steel. The applicant further states that unlike

fibrous insulation, stainless steel does not need controls for halogens. The staff agrees with the

applicant that the external surface of the stainless steel and Ni-alloy based reactor vessel

appurtenances is not susceptible to cracking due to halogen induced SCC, because VCSNS

uses stainless steel insulation, which does not contain halogens. 

The AMR results for the PWR reactor vessel leak detection line (GALL Item IV.A2.1-f) are

presented in Table 1 of NUREG-1801. Therefore, AMR Item 9 in LRA Table 3.1-1 should also

include these AMR results. The staff issued RAI 3.1.2.4.3-6, requesting the applicant to

confirm whether the AMR results for the reactor vessel leak detection line are included in LRA

Table 3.1-1, AMR Item 9. In response to RAI 3.1.2.4.3-6, in a letter dated June 12, 2003, the

applicant states that the reactor vessel flange leak detection line components are classified as

Code Class 2 components and the corresponding AMR results for these components are

presented in LRA Table 3.1-2, Items 1, 5, and 6. The applicable aging effects are loss of

material and cracking at the inside surface of the line. The staff finds the response acceptable

because stainless steel components are susceptible to loss of material due to crevice and

pitting corrosion and cracking due to SCC when exposed to chemically treated borated coolant. 

The aging effects identified in the LRA for the reactor vessel and its appurtenances are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant has identified the following six AMPs for managing

the aging effects associated with reactor vessel and its appurtenances:

• boric acid corrosion surveillance program

• chemistry program

• Inservice inspection plan

• reactor vessel surveillance program

• alloy 600 aging management program

• reactor head closure studs program

The boric acid corrosion surveillance program (LRA Section B.1.2) was developed by the

applicant in response to NRC Generic Letter 88-05. Inspections are performed to present

reasonable assurance that borated water leakage from the reactor coolant pressure boundary

does not lead to undetected loss of material on the external surface of carbon steel or low alloy

steel bolting. The staff has evaluated this common AMP and found it to be acceptable for

managing the aging effect of loss of material identified for the RCS pressure boundary closure

bolting. The staff’s evaluation of this AMP is documented in Section 3.0.3.1 of this SER. The

evaluation of this AMP, as it is applied for managing PWSCC cracking in the reactor vessel

closure head penetrations, is presented in Section 3.1.2.3.1 of this SER.

The applicant credits the Inservice inspection plan (LRA Section B.1.7), the chemistry program

(LRA Section B.1.4), and the Alloy 600 aging management program (LRA Section B.1.1) for

managing aging effect of cracking in core support pads and bottom head penetration tubes. 

The staff’s evaluation of these AMR results is presented in Section 3.1.2.2.9 of this SER and
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concluded that the three programs proposed by the applicant will adequately manage cracking

in core support pads and bottom head penetrations.

The applicant also credits the Inservice inspection plan (LRA Section B.1.7), the chemistry

program (LRA Section B.1.4), and the Alloy 600 aging management program (LRA Section

B.1.1) for managing the aging effects of cracking due to SCC and PWSCC in stainless steel

and Ni –alloy components including the CRDM housings and vent plugs; cladding on the

closure head, flanges, and bottom heads; and safe ends. The applicant states that the ISI plan

provides condition monitoring for weld regions, whereas chemistry program provides

management of cracking in non-welded regions of stainless steel components. The staff finds

this acceptable because the ISI plan includes inspections of the welds and the adjacent heat

affected zones. Cracking due to SCC takes place in the heat-affected zones of the weld

regions. The staff presented its evaluation of the Alloy 600 aging management program in

Section 3.1.2.3.1 of this SER and concluded that the alloy 600 aging management program will

effectively manage cracking in the Ni-alloy components.

The applicant credits the Inservice inspection plan (LRA Section B.1.7) for managing loss of

material in the reactor vessel closure head and vessel flanges. The staff has evaluated this

AMP and found it to be acceptable for managing the aging effects identified for the reactor

vessel and its appurtenances. The staff’s evaluation of this AMP is documented in Section

3.1.2.3.3 of this SER.

The chemistry program (LRA Appendix B.1.4) references water quality that is compatible with

the materials of construction used in the Class 1 components in order to minimize loss of

material and cracking. This program incorporates Electric Power Research Institute (EPRI) and

Institute of Nuclear Power Operations (INPO) guidelines, which reflect industry experience, and

the “lessons learned” from VCSNS and external industry operating experience. The staff has

evaluated this common AMP and found it to be acceptable for managing the aging effects

identified for the reactor vessel and its appurtenances. The staff’s evaluation of this AMP is

documented in Section 3.0.3.2 of this SER.

The chemistry program (LRA Section B.1.4) manages loss of material in stainless steel and Nialloy reactor vessel components (i.e., CRD housings, cladding, vent plug, bottom head and

closure head penetration tubes, reactor vessel core support pads, and nozzle safe ends)

internally exposed to chemically treated borated coolant. The staff finds the use of the

chemistry program, alone, acceptable for managing loss of material in stainless steel and Nialloy components because these components have good resistance against pitting and crevice

corrosion and it is consistent with GALL.

As mentioned in Section 3.1.2.4.3 of this SER, the applicant in response to RAI 3.1.2.4.3-6,

states that loss of material and cracking are the applicable aging effects for the PWR reactor

vessel flange leak detection line if exposed to chemically treated borated coolant. The

applicant, however, further states that at VCSNS the leak detection line is monitored and found

to remain dry. Therefore, management of cracking and loss of material in the leak detection

line is not required because these aging effects are not present. The staff accepted that the

leak detection line does not need management for loss of material or cracking as long as the

line is monitored for leakage and it is found to remain dry. By letter dated September 24, 2003,

the applicant indicated that the reactor vessel flange leak detection components are classified

as Code Class 2 components and are not normally filled with borated water. In addition, the
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applicant stated that the leak detection line connects between the two vessel o-rings to allow for

monitoring of vessel o-ring leakage. The applicant confirmed that vessel o-ring leakage had not

been a problem at VCSNS and the line has been dry during normal plant operations. Also, an

alarm exists on the main control board to identify leakage and there are preplanned actions

associated with the main control board alarms that include isolation of the line to contain the

RCS leakage. If leakage is detected during plant operation, the applicant will follow its

Corrective Action Program.

The reactor vessel surveillance program (LRA Section B.1.24) manages loss of fracture

toughness in the reactor vessel beltline materials. The staff has evaluated this AMP and found it

to be acceptable for managing loss of fracture toughness in the reactor vessel beltline

materials. The staff’s evaluation of this AMP is documented in Section 3.1.2.3.6 of this SER.

The Alloy 600 aging management program (LRA Section B.1.1) and the chemistry program

(LRA Section B.1.4) manage cracking in the Alloy 600 vessel closure head penetrations. The

staff has evaluated this AMP and found it to be acceptable for managing cracking in Alloy 600

vessel closure head penetrations. The staff’s evaluation of this AMP is documented in Section

3.1.2.3.1 of this SER. As mentioned earlier in this section, the Alloy 600 aging management

program also manages cracking in core support pads, bottom head penetration tubes, and safe

ends, i.e., Alloy 82/182 welds at the ends of the safe ends.

The reactor vessel closure studs program (LRA Section B.1.8) manages loss of closure

integrity and loss of material in the reactor vessel closure stud assemblies. The staff has

evaluated this AMP and found it to be acceptable for managing loss of closure integrity and loss

of material in the reactor vessel closure stud assemblies. The staff’s evaluation of this AMP is

documented in Section 3.1.2.3.4 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the reactor

vessel and its appurtenances will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.4 Reactor Vessel Internals

The components of the reactor vessel internals are divided into three parts, consisting of the

lower core support structure (including the entire core barrel and neutron shield pad assembly),

the upper core support structure, and the in-core instrumentation support structure. The

reactor internals perform the following functions:

• provide core support

• maintain fuel alignment

• limit fuel assembly movement

• maintain alignment between fuel assemblies and control rod drive mechanisms
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• direct coolant flow past the fuel elements

• direct coolant flow to the pressure vessel head

• provide gamma and neutron shielding

• provide guides for the in-core instrumentation

The coolant flows from the vessel inlet nozzles, down the annulus between the core barrel and

the vessel wall, and then into a plenum at the bottom of the vessel. It then reverses and flows

up through the core support and through the lower core plate. The lower core plate is sized to

provide the desired inlet flow distribution to the core. After passing through the core, the

coolant enters the region of the upper support structure and then flows radially to the core

barrel outlet nozzles and directly through the vessel outlet nozzles.

Summary of Technical Information in the Application

The description of the reactor vessel internals can be found in LRA Section 2.3.1.4. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-4. The components, aging effects, and aging management programs are discussed

in Section 3.1 of the LRA, and are listed in LRA Tables 3.1-1 and 3.1-2. The staff reviewed

Section 3.1 of the LRA to determine whether the applicant had demonstrated that the effects of

aging on the RV internals will be adequately managed during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

All of the major RV internals are fabricated from Type 304 stainless steel except for (a) the bolts

and dowel pins, which are fabricated from Type 316 stainless steel; (b) the radial support key

bolts, which are fabricated from Alloy X-750; and (c) the radial support clevis inserts and clevis

insert bolts, which are fabricated from Alloy 600. There are no cast austenitic stainless steel

(CASS) RV internal components within the scope of license renewal.

The RV internals that are within the scope of license renewal are exposed to borated reactor

coolant water at approximately 315.6 °C (600 °F) and 15.41 MPa (2235 psig). These

components are all located within the reactor pressure vessel.

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following applicable aging effects for

the RV internal components subject to an AMR:

• loss of fracture toughness

• changes in dimension

• crack initiation and growth

• loss of preload

• loss of material

As previously noted in Section 3.1.2.2.7 of this SER, the applicant states that, with respect to

changes in dimensions due to void swelling, industry activities are under way to determine

whether this is an aging effect requiring management for license renewal, and, if necessary, to

develop and qualify methods for detection and management. The applicant proposes to

monitor these activities and implement the resulting methods, as necessary.
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Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following two AMPs to manage the

aging effects associated with RV internals:

• reactor vessel internals inspection program

• chemistry program

The reactor vessel internals inspection program is a new program developed by the applicant to

manage the aging effects impacting the RV internals. It supplements the applicant’s existing inservice inspection plan. The chemistry program is credited with managing the aging effects of

several components in different structures and systems and is, therefore, considered a

common aging management program. The applicant concluded that these two AMPs will

manage the effects of aging such that the intended function of the reactor vessel internal

components will be maintained consistent with the CLB under all design loading conditions

throughout the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in Section

3.1, and in LRA Tables 3.1-1 and 3.1-2 and pertinent sections of the LRA Appendices A and B,

regarding the applicant’s demonstration that the effects of aging will be adequately managed so

that the intended function(s) of the reactor vessel internal components will be maintained

consistent with the CLB throughout the period of extended operation, as required by 10 CFR

54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant lists the reactor vessel internal components within

the scope of the license renewal with their material groups and environment. The intended

functions of these components are listed in LRA Table 2.3-4. LRA Tables 3.1-1 and 3.1-2

identify the aging effects requiring management and the plant-specific AMPs required for

managing these aging effects during the period of extended operation. The list of components

within the scope of license renewal is grouped in accordance with their component types.

In LRA Table 3.1-1, the applicant identifies metal fatigue for ASME Class 1 components as the

TLAA that is applicable to the reactor vessel internals. The staff’s evaluation of this TLAA is

presented in Section 4.3 of this SER.

Aging Effects:

In accordance with LRA Section 3.1, the applicant has performed a review of industry

experience and NRC generic communications, relative to the reactor vessel internal

components, to provide reasonable assurance that the aging effects that require management

for a specific material-environment combination are the only aging effects of concern for

VCSNS. This also included the VCSNS plant-specific operating experience.

As mentioned above, the material of construction for the reactor vessel internal components

included in LRA Section 3.1 is Type 304 stainless steel except for (a) the bolts and dowel pins,

which are fabricated from Type 316 stainless steel; (b) the radial support key bolts, which are

fabricated from Alloy X-750; and (c) the radial support clevis inserts and clevis insert bolts,
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which are fabricated from Alloy 600. There are no cast austenitic stainless steel (CASS) RV

internal components within the scope of license renewal. These components are exposed to

chemically treated borated water. The applicant performed a review of industry experience and

NRC generic communications, relative to the RV internal components, to provide reasonable

assurance that the aging effects that require management for a specific material-environment

combination are the only aging effects of concern for VCSNS. This review also included a

review of VCSNS plant-specific operating experience.

In LRA Table 3.1-1, the applicant identifies the following aging effects that are applicable to the

reactor vessel internal components requiring AMRs:

• loss of fracture toughness in baffle/former bolts and other RV internals due to neutron

irradiation embrittlement and void swelling

• changes in dimension of stainless steel and nickel-based alloy components due to void

swelling

• crack initiation and growth in baffle/former bolts and other RV internals due to SCC and

IASCC

• loss of preload in baffle/former bolts and other RV internals due to stress relaxation

• loss of material in RV internals due to wear

The applicant states that the identification of the above aging effects in LRA Table 3.1-1 is

consistent with NUREG-1801 with one clarification. For changes in dimension due to void

swelling, the applicant states that the clevis inserts are a nickel-based alloy at the Summer

Plant rather than stainless steel as specified in NUREG-1801. The staff finds this clarification

acceptable.

As described in topical report WCAP-14577, Rev. 1-A, “License Renewal Evaluation: Aging

Management for Reactor Internals,” and the associated staff’s final safety evaluation report

(FSER), the aging mechanisms potentially applicable to the RV internals are neutron irradiation

embrittlement, stress corrosion cracking (SCC), irradiation-assisted stress corrosion cracking

(IASCC), erosion and corrosion processes, creep/irradiation creep, stress relaxation, wear,

thermal aging, fatigue, and void swelling. However, the RV internals at VCSNS are made from

materials that are resistant to loss of material by general corrosion and flow-assisted corrosion

(erosion/corrosion). The RV internals at VCSNS are also not exposed to a high enough

temperature (>540 °C or 1000 °F) where creep-induced degradation would become an aging

concern for the internals.

Cracking of RV internals due to either SCC or IASCC is an applicable aging effect for RV

internals. SCC results from the synergistic effects of tensile stresses and a corrosive

environment on a susceptible material. SCC is a particular concern for bolting, given the

potential for occluded environmental conditions in crevice areas. IASCC is SCC that is

enhanced by exposure of the materials to ionizing radiation. In LRA Table 3.1-1, the applicant

has identified cracking as an applicable aging effect for all RV internals. This is acceptable to

the staff because the applicant has accounted for cracking of the RV internals that could be

induced by either SCC or IASCC.
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Loss of material from wear of RV internals occurs due to relative motion between the interfaces

and mating surfaces of components caused by flow-induced vibration during plant operation;

differential thermal expansion and contraction movements during plant heatup and cooldown;

and changes in power operating cycles. The severity of the wear depends on the frequency of

motion, duration, and component loadings. The applicant identifies loss of material as an

applicable aging effect for all RV internals in Table 3.1-1 of the application. This is acceptable

to the staff because the LRA is in agreement with NUREG-1801, in that loss of material is an

applicable effect for the RV internals of PWRs and because it specifically accounts for loss of

material that could be induced by wear.

Stress relaxation may be defined as the unloading of preloaded components under conditions

of long-term exposure of RV internal materials to high constant strain, elevated temperatures,

and/or neutron irradiation. Loss of preload due to stress relaxation is an applicable aging effect

for those RV internals with substantial preload (e.g., hold down spring, bolted connections). A

loss of preload in these components could result in higher cyclic and transient loads, and a loss

of function. The combination of bolt stress relaxation, changes in transient and high-cycle

vibration of the RV internals, and the effects of increased RV internals fatigue susceptibility may

be significant for the license renewal period. The RV internals susceptible to loss of preload

due to stress relaxation are the upper and lower support column bolts, the hold down spring,

and the clevis insert bolts. In LRA Table 3.1-1, the applicant has identified loss of preload as an

applicable aging effect for the upper and lower internals assembly, baffle/former bolts, and

hold-down spring.

The rod control cluster assembly (RCCA) guide tube support pins used in Westinghouse RV

internals have a history of degradation. Several Westinghouse plants experienced cracking of

guide tube support pins manufactured from Alloy X-750. The cracking of the Alloy X-750

material was attributed to the combination of high stress and undesirable microstructure. In

WCAP-14577, Rev. 1-A, Westinghouse stated that cracking of the support pins will not result in

a significant misalignment and the intended function will be maintained. However, these pins

are being replaced at a number of plants. Replacement is considered to be a sound

maintenance practice to preclude degradation when industry experience indicates that such

degradation has been observed. In Table 3.1-1 of the LRA, the applicant lists the RCCA guide

tube support pins as a separate entry. Since the guide tube support pins (split pins) are

fabricated from cold-worked Type 316 stainless steel, they have the same aging effects

applicable to the other stainless steel components in the guide tube assemblies. This is

acceptable to the staff because it agrees with Table 3.1-1 of NUREG-1800 that cracking is an

applicable effect for these components.

In LRA Table 3.1-1, AMR Items 5 and 31, the applicant identifies loss of fracture toughness due

to irradiation as one of the applicable aging effects for the stainless steel reactor vessel

internals in the fuel zone region. The applicant identifies all of the reactor vessel internals in the

fuel zone region as being susceptible to loss of fracture toughness due to irradiation. The staff

issued RAI 3.1.2.4.4-1, requesting the applicant to explain why the reactor vessel internals

outside the fuel zone region are not considered susceptible to loss of fracture toughness due to

irradiation and to submit a criterion used to identify the vessel internals that are susceptible to

loss of fracture toughness due to neutron irradiation along with its technical basis.

In response to RAI 3.1.2.4.4-1, in a letter dated June 12, 2003, the applicant states that the

details of the reactor vessel internals inspection program have not been developed. The
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applicant further stated that VCSNS will follow industry initiatives and will have a program in

place prior to the period of extended operation. During the June 22, 2003, conference call, the

staff requested the applicant to be more specific about how it will identify the vessel internals

susceptible to loss of fracture toughness due to neutron embrittlement. In response, the

applicant stated that it would consider operating experience gained from aging management

activities performed by plants that were originally licensed before VCSNS. The staff finds this

response acceptable because the applicant will develop the details of the reactor vessel

internals inspection program based on the operating experience of the plants that were

originally licensed before VCSNS and have renewed their licenses. These plants would have

several years of extended period of operating experience before VCSNS begins its extended

period of operation. VCSNS will develop and implement reactor vessel internal inspection

program prior to the period of extended operation and will implement aging management

activities that are acceptable to the staff. 

Void swelling is defined as a gradual increase in dimensions of the RV internals. Under

irradiation conditions for the reactor vessel internals, helium is generated as a nuclear

transmutation reaction product. At sufficiently high temperatures, helium bubbles expand to a

critical diameter and coalesce (unite) into larger bubbles. These bubbles create void areas

(gaps) in the materials and may result in the swelling of the material. Swelling changes the

dimensions of the material and may affect the ability of the particular RV internal component to

perform its intended functions. Although void swelling has not been observed to date, the staff

is concerned that void swelling may become significant during the period of extended operation. 

Until the industry has developed sufficient data to demonstrate that void swelling is not a

significant aging mechanism, the staff believes that void swelling should be considered

significant, and applicants for license renewal should describe their aging management plan to

address void swelling. In LRA Table 3.1-1, the applicant has identified changes in dimension

as an applicable aging effect for the RV internals. The applicant’s identification of the reactor

vessel internals as being susceptible to dimensional changes due to void swelling is acceptable

to the staff because it accounts for material degradation that could be induced by this

mechanism.

The staff reviewed NUREG-1801 Chapter IV.B2, “Reactor Vessel Internals (PWR)

Westinghouse,” and confirmed that the applicant1s identification of the aging effects for the

reactor vessel internal components in Table 3.1-1 is consistent with the GALL report and

therefore acceptable.

In LRA Table 3.1-2, AMR Item 7, the applicant has also listed loss of material due to crevice

and pitting corrosion as a potential aging effect for the RV internals. The stainless steel and

nickel-based alloy reactor vessel internal components are inherently resistant to general

corrosion; however, loss of material due to crevice and pitting corrosion may be an applicable

effect for these components under wet conditions, especially if the components have creviced

areas that may be exposed to the fluids. Therefore, the staff finds that the applicant's

identification of loss of material, as an aging effect for stainless steel components exposed to

chemically treated borated coolant, is acceptable.

The aging effects identified in the LRA for the RV internal components are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.
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Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following two AMPs to manage the

aging effects associated with the reactor vessel internal components:

• reactor vessel internals inspection program

• chemistry program

The applicant credits the reactor vessel internals inspection program (LRA Appendix B.2.4)

alone for managing loss of preload due to stress relaxation in VCSNS hold-down spring, clevis

insert bolts, and upper and lower support column bolts (LRA Table 3.1-1, AMR Items 30 and

35). In contrast, NUREG-1801 specifies that both Inservice inspection and loose parts

monitoring for managing loss of preload due to stress relaxation in the lower and upper support

column bolts (GALL Items IV, B2.1-k and B2.5-h). For the hold-down spring (GALL Item B2.1-

d) and clevis insert bolts (GALL Item IV, B2.5-i), NUREG-1801 states that either loose parts

monitoring or neutron noise monitoring is to be used in addition to Inservice inspection to

manage loss of preload.

The staff issued RAI 3.1.2.4.4-2, requesting the applicant to explain how the reactor vessels

internals inspection program, alone, in the absence of either a loose parts monitoring or neutron

noise monitoring program will adequately manage this aging effect for these components. In

response to RAI 3.1.2.4.4-2, in a letter dated June 12, 2003, the applicant states that VCSNS

reactor vessel internals inspection program has not yet been developed but will be developed

and implemented prior to the period of extended operation. The applicant further states that

VCSNS will follow the practices that are developed from industry initiatives (specifically EPRI

and WOG initiatives) and operating experience related to the inspection of reactor vessel

internals. Additionally, in response to an action item resulting from the June 22, 2003,

conference call, the applicant further states that VCSNS will implement aging management

activities that are acceptable to the staff. The applicant has agreed that this is a licensee

commitment and this commitment is documented in Appendix A of this SER.

The Chemistry Program (LRA Appendix B.1.4) references water quality that is compatible with

the materials of construction used in the reactor vessel internal components in order to

minimize loss of material and cracking. This program incorporates EPRI and Institute of

Nuclear Power Operations (INPO) guidelines, which reflect industry experience, and the

“lessons learned” from VCSNS and external industry operating experience. As discussed in

Section 3.1.2.4.2 of this SER, the applicant, in response to RAI 3.1.2.4.2-5, states that the

VCSNS chemistry program incorporates the guidelines of EPRI TR-105714, Revision 4. The

staff finds the response acceptable because GALL AMP XI.M2, Water Chemistry, refers to

Revision 3 of the same report. Revision 4 of the report is acceptable because it accounts for

the industry experience since the publication of Revision 3.

The Chemistry Program is credited with managing the aging effects of several components in

different structures and systems and is, therefore, considered a common aging management

program. The staff has evaluated this common AMP and found it to be acceptable for

managing the aging effects identified for this system. The staff’s evaluation of this AMP is

presented in Section 3.0.3.2 of this SER.
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The staff’s evaluation of the reactor vessel internals inspection program is documented in

Section 3.1.2.3.5 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the RV internal

components will effectively manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.5 In-Core Instrumentation System

The VCSNS in-core instrumentation system is comprised of thermocouples positioned to

measure fuel assembly coolant outlet temperatures at preselected positions, and fission

chamber detectors, i.e., in-core neutron (flux) detectors, positioned in guide thimbles, which run

the length of selected fuel assembly, to measure the neutron fluence distribution. 

The in-core flux detectors are directed through the reactor vessel bottom head via thimble

tubes, and core exit thermocouples are brought in through the reactor vessel top head. The

thimble tubes normally extend from a 10-path transfer device through the seal table, through

the bottom of the reactor vessel, and into the selected fuel assemblies. The thimble tubes are

retractable, and insertion/retraction of these tubes is directed by long-radius guides below the

bottom head and by internals guides between the vessel head and fuel assemblies. 

The thimble tubes are sealed at the leading (reactor) end but are open at the 10-path transfer

device to allow insertion of an in-core neutron detector. Mechanical high-pressure seals,

located at the seal table, are used to seal the area between the thimble tubes and the longradius guides. This seal serves as a reactor coolant system pressure boundary. The thimble

tube wall also serves as a pressure boundary because a leak in a thimble tube results in

degradation of the RCS pressure boundary by creating a path for reactor coolant to bypass the

mechanical seal.

LRA Section 2.3.1.5 and UFSAR Section 4.4.5.1 describe the VCSNS in-core instrumentation

system. 

Technical Information in the Application

The applicant describes its AMR of the in-core instrumentation system in LRA Section 3.1,

“Aging Management of Reactor Vessel, Internals, and Reactor Coolant System.” The staff

reviewed this section of the LRA to determine whether the applicant has demonstrated that the

effect of aging on the in-core instrumentation system components will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Seven component groups are listed in LRA Tables 3.1-1 and 3.1-2. They include in-core

neutron detector thimbles, in-core thermocouples, and tube and tube fittings for in-core neutron

detector conduits. The intended functions of these components are to provide in-core guidance
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and protection and to provide pressure boundary. The tube and tube fittings also provide

support to in-core neutron detector conduits.

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following aging effects for the in-core

instrumentation system that are subject to an AMR:

• loss of material

• cracking

• loss of mechanical closure integrity

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following three existing AMPs to

manage the aging effects associated with in-core instrumentation system components:

• bottom-mounted instrumentation inspection

• chemistry program

• Inservice inspection plan

The applicant concluded that these AMPs will manage the effects of aging such that the

intended functions of the in-core instrumentation system components will be maintained

consistent with the CLB under all design loading conditions throughout the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA

Section 3.1, Tables 3.1-1 and 3.1-2, and pertinent sections of LRA Appendices A and B,

regarding the applicant’s demonstration that the effects of aging will be adequately managed so

that the intended function(s) of the in-core instrumentation system components will be

maintained consistent with the CLB throughout the period of extended operation, as required by

10 CFR 54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant lists the in-core instrumentation system

components within the scope of the license renewal with their material groups and environment. 

The intended functions of these components are listed in LRA Table 2.3-5. The tables also

identify the aging effects requiring management and the plant-specific AMPs required for

managing these aging effects during the period of extended operation. The components within

the scope of license renewal are grouped in accordance with their component types, and these

groups are listed in these tables.

Aging Effects:

In accordance with LRA Section 3.1, the applicant has performed a review of industry

experience and NRC generic communications relative to the in-core instrumentation system

components to present reasonable assurance that the aging effects that require management
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for a specific material-environment combination are the only aging effects of concern for

VCSNS. This also included the plant-specific operating experience at VCSNS.

The materials of construction for the in-core instrumentation components include stainless steel

and Ni-based alloys. In LRA Table 3.1-1, the applicant identifies the following aging effect

applicable to the in-core neutron detector thimble tubes requiring AMR:

• loss of material due to fretting wear of in-core neutron detector thimble tubes caused by

flow induced vibrations

The applicant states that the identification of the above aging effect in LRA Table 3.1-1 is

consistent with the GALL report.

The staff has reviewed NUREG-1801 Chapter IV.B2, Reactor Vessel Internals (PWR) –

Westinghouse, and confirmed that the applicant’s identification of the aging effect in LRA Table

3.1-1 for in-core instrumentation system components is consistent with the GALL report, and,

therefore, acceptable.

In Table 3.1-2, the applicant identifies the following aging effects for the in-core instrumentation

system components:

• loss of material due to crevice and pitting corrosion of all the in-core instrumentation

components (except bolted connection for in-core thermocouple seal assemblies), which

are made of stainless steel and Ni alloy and exposed to chemically treated borated

coolant

• cracking due to stress corrosion cracking of all the in-core instrumentation components

(except bolted connection for in-core thermocouple seal assemblies), which are made of

stainless steel and Ni alloy and exposed to chemically treated borated coolant

• loss of mechanical closure integrity due to stress relaxation, stress corrosion cracking,

and wear of bolted closures for in-core thermocouple seal assemblies

The stainless steel and Ni alloy components are inherently tough and resistant to general

corrosion. However, loss of material due to crevice and pitting corrosion may be an applicable

effect for these components under wet conditions, especially if the components have creviced

areas that may be exposed to the fluids. Therefore, the applicant’s identification of loss of

material as an aging effect for in-core instrument system stainless steel and Ni alloy

components internally exposed to chemically treated borated coolant is acceptable.

The stainless steel and Ni alloy components exposed to PWR reactor coolant (chemically

treated borated coolant) are susceptible to cracking due to stress corrosion cracking. 

Therefore, the applicant’s identification of cracking as an aging effect for in-core instrument

system stainless steel and Ni alloy components internally exposed to chemically treated borated

coolant is acceptable.

In LRA Table 3.1-2, AMR Item 4 identifies stainless steel as material for in-core thermocouple

seal bolting. However, in Discussion Column for this AMR item, the applicant refers to high

strength material for this bolting. The staff issued RAI 3.1.2.4.5-1a, requesting the applicant
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needs to clarify this discrepancy. The staff was concerned because if high-strength, low-alloy

steel is the bolting material, then the applicant needs to identify loss of material due to boric

acid corrosion as an aging effect for this bolting material. In response to RAI 3.1.2.4.5-1a, in a

letter dated June 12, 2003, the applicant states that bolting for the in-core thermocouple seal is

made of stainless steel. The staff has taken into account this clarification in its evaluation of the

AMR results for in-core thermocouple seal bolting. 

The applicant identifies loss of closure integrity rather than loss of preload, loss of material and

cracking as an applicable aging effect requiring management for closure bolting for in-core

thermocouple seals. The staff issued RAI 3.1.2.4.5-1b, requesting the applicant to explain

whether loss of closure integrity includes effects of loss of preload, loss of material, and

cracking. In response to RAI 3.1.2.4.5-1b, in a letter dated June 12, 2003, the applicant states

that the stainless steel bolting is immune to loss of material due to general corrosion or boric

acid corrosion and is normally in a dry environment limiting the concerns for pitting and crevice

corrosion. However, bolting could experience loss of material due to wear because incore

thermocouple seals are disassembled and assembled at each refueling. The applicant further

states that cracking is not an applicable aging effect for the bolting material because cracking of

bolting in industry is attributed to the use of high yield strength low-alloy steel material and

contaminants such as lubricants containing MoS2. VCSNS has not and does not use lubricants

containing MoS2, and bolting material for in-core thermocouple seals is stainless steel and not

high-strength low alloy steel. So the only applicable aging effects for this bolting are loss of

material due to wear and loss of preload. The staff finds this response acceptable because it is

consistent with the industry experience, i.e., stainless steel bolting exposed to dry containment

environment is not susceptible to cracking or loss of material due to corrosion.

In Westinghouse-designed PWRs, mechanical high-pressure seals, located at the seal table,

are used to seal the area between the thimble tubes and the long-radius guides. If a bolted

connection is employed, then the applicant needs to identify applicable aging effects and

present an AMP for managing these effects. The staff issued RAI 3.1.2.4.5-c, requesting the

applicant to describe how the sealing of the area between the thimble tube and the guide is

obtained. In response to RAI 3.1.2.4.5-c, in a letter dated June 12, 2003, the applicant states

that the connection between the in-core instrument thimble tube and the guide tube is made

with the standard Westinghouse type tube fitting arrangement. The applicant identifies loss of

material due to corrosion and cracking due to SCC as applicable aging effects for the fitting and

also for the guide tubes and thimble tubes. The staff finds this identification of aging effects

acceptable, as these components are exposed to the chemically treated borated coolant and,

therefore, are susceptible to loss of material and cracking.

The aging effects identified in the LRA for the in-core instrumentation system components are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant has identified the following three AMPs for

managing the aging effects associated with in-core instrumentation system components:

• bottom-mounted instrumentation inspection program
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• chemistry program

• Inservice inspection plan

The bottom-mounted instrumentation inspection program (LRA Section B.1.3) is credited for

managing loss of material due to fretting wear of the BMI thimble tubes. The staff has

evaluated this AMP in Section 3.1.2.3.6 of this SER.

The Chemistry Program (LRA Section B.1.4) is credited for managing the aging effect of loss of

material and cracking on the outside surface of the BMI thimble tubes and the pressure

retaining portion of the in-core thermocouples, as well as the inside surface of the guide tubes

supporting the thimble tubes between the seal table and vessel lower head. The use of

chemistry program alone may not be adequate for managing loss of material and cracking of

thimble tubes and guide tubes for the following reason: According to LRA Drawing 1MS-44-

014-1, the seal table elevation is the same as the vessel flange elevation. Since the reactor

coolant is exposed to containment environment during refueling, the stagnant reactor coolant

near the seal table may be oxygenated because of the high elevation. As a result, the stagnant

coolant in the guide tubes would be more aggressive than the normal RCS coolant. Therefore,

the applicant needs to provide an aging management program to ensure that loss of material

and cracking are not taking place at the inside surface of the guide tube and the outside

surface of the thimble tube surrounded by the guide tube. 

The staff issued RAI B.1.4-1, requesting the applicant to address its concern about potentially

accumulated oxygen in the guide tube near the seal table. The response to RAI B.1.4-1, was

discussed in the June 22, 2003, conference call between the staff and the applicant. In

response to an action item based on this conference call in a letter dated September 2, 2003,

the applicant states that buildup of oxygen in the guide tube is not a significant concern. The

area between the outside surface of the BMI tubes and the inside surface of the guide tubes

supporting the thimble tubes between the seal table and vessel lower head remains filled during

refueling and is not opened and drained. If during refueling there is a leakage while the

thimbles are withdrawn or inserted, coolant will leak out but air will not leak into the region of

concern. The staff does not agree with the applicant that oxygen buildup may not take place in

upper portion of the guide tubes. High levels of oxygen may be introduced into the primary

system during shutdown operations as a result of exposing the reactor coolant system to the

outside air. This oxygen may accumulate in the upper portion of the guide tubes because the

elevation of the seal table, which is same as the vessel flange elevation. The applicant,

accumulated oxygen is not of concern because except very near the vessel the temperature of

the thimble tube and guide tube is at ambient air temperature. At the seal table the

temperature is less than 49°C (120°F), which significantly reduces the potential of loss of

material and cracking of the fitting. Therefore, the staff accepts the applicant’s position that the

chemistry program is adequate for managing loss of material and cracking of the thimble tube

and guide tube between the vessel lower head and seal table except very near the vessel

where temperature are higher than 93°C (200°F). 

In a conference call on September 16, 2003, the staff informed the applicant that their

September 2, 2003 response did not provide aging management for cracking due to SCC of the

stainless steel guide tube in close proximity to the reactor vessel. In a response, by letter dated

September 24, 2003, the applicant states that the stainless steel in-core neutron detector

conduits (guide tubes) are welded to the nickel-based alloy bottom head penetration tubes. 

The staff reviews aging management of bottom head penetrations, as proposed by the
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applicant, in Section 3.1.2.2.9 of this SER and finds it adequate. The applicant credits the Alloy

600 aging management program (LRA Appendix B.1.1) in addition to the chemistry program

(LRA Appendix B.1.4) for managing cracking in the bottom head penetration tubes. The Alloy

600 aging management program provides for inspecting the signs of boric acid leakage from

the bottom head penetration, including its weld with the guide tube, during outages and

monitoring primary coolant leakage per Technical Specifications during plant operation. 

The applicant further states that the bottom head penetrations extend over eight inches from

the bottom surface of the vessel where they are welded to in-core neutron detector conduits. 

The configuration of the conduits tends to allow a significant temperature reduction from the

RCS temperature. In addition, chemistry controls of the reactor coolant significantly reduce the

source of contaminates and measures were taken to prevent sensitization during fabrication. 

The applicant concludes that the combination of these factors reduces the likelihood of stress

corrosion cracking of the conduit and, therefore, the chemistry program alone is adequate for

managing cracking due to SCC of the conduit and a one-time inspection is not required. The

staff finds the use of the chemistry program alone for managing cracking due to SCC in the incore neutron detector conduit that is in close proximity of the vessel bottom head acceptable

because the weld between the conduit and the bottom head penetration will be inspected as

part of the aging management of the bottom head penetrations. In addition, this weld is the

bounding location for the guide tube as far as cracking due to SCC is concerned because the

temperature at the weld will be higher than at any other locations on the conduit. This closes

the RAI B.1.4-1.

The applicant credits the ISI plan (LRA Section B.1.7) for managing loss of closure integrity of

the closure bolting. The staff issued RAI 3.1.2.4.5-1b, requesting the applicant to explain how

ISI plan would manage loss of closure integrity, i.e., loss of material due to wear and loss of

preload, and ensure that the pressure boundary of the bolted joint would be maintained during

the extended period of operation. In response to RAI 3.1.2.4.5-1b, in a letter dated June 12,

2003, the applicant states that this bolting is disassembled and assembled at each refueling. 

The ISI plan requires surface examination of all bolting when it is disassembled, i.e., at each

refueling. The surface examination will detect any loss of material due to wear. Retorquing to

the desired preload during each refueling will remove the loss of preload that might have taken

place during the preceding fuel cycle. The staff accepts the applicant response because the

applicant is adequately managing the applicable aging effects for the closure bolting for in-core

thermocouple seals by managing loss of closure integrity of this bolting.

The staff has evaluated this common AMP and, found it acceptable for managing the aging

effects for the in-core instrumentation system components. The staff’s evaluation of this AMP

is presented in Section 3.0.3 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the in-core

instrumentation system components will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent
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with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.6 Pressurizer

The VCSNS pressurizer is a vertical, cylindrical vessel with a hemispherical top and bottom

heads constructed of low alloy steel (SA533 Grade A Class 2), with austenitic stainless steel

cladding on all surfaces exposed to the reactor coolant. A stainless steel liner, i.e., thermal

sleeve, is used in some nozzles. The surge line nozzle and removable electric heaters are

installed in the bottom head. A thermal sleeve is provided to minimize stresses in the surge line

nozzle. Spray line nozzles, relief, and safety valve connections are located in the top head of

the pressurizer. The skirt type support is attached to the lower head and extends for a full 360

degrees around the vessel. The lower part of the skirt terminates in a bolting flange with bolt

holes securing to its foundation. The VCSNS pressurizer is designed and constructed in

accordance with the ASME Code, Section III.

The VCSNS pressurizer instrumentation includes 2 temperature detectors, one in the steam

phase and 1 in the water phase, 6 pressure transmitters, and 5 liquid level transmitters.

During an outsurge from the pressurizer, flashing of water to steam, and the generation of

steam by automatic actuation of the heaters keep the pressure above the minimum allowable

limit. During an insurge from the RCS, the spray system, which is fed from two cold legs,

condenses steam in the vessel to prevent the pressurizer pressure from reaching the set point

of the power operated relief valves for normal operating transients. Heaters are energized on

high water level during insurge to heat the subcooled surge water that enters the pressurizer

from the reactor coolant loop.

UFSAR Sections 5.5.10 and 5.6 describe the VCSNS pressurizer design and LRA Section

2.3.1.6 identifies the pressurizer components that are within the scope of license renewal and

their intended functions.

Technical Information in the Application

The applicant describes its AMR of the pressurizer components in LRA Section 3.1, “Aging

Management of Pressurizer.” The staff reviewed this section of the LRA to determine whether

the applicant has demonstrated that the effects of aging on the pressurizer will be adequately

managed during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Ten component groups associated with the pressurizer are listed in LRA Tables 3.1-1 and 3.1-

2. They include shell components, nozzles, head penetrations, and CRDM housings. The

intended function of all of these components is to provide a pressure boundary. The reactor

vessel core support pads support the reactor vessel internals.

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following aging effects for the

pressurizer components that are subject to an AMR:

• cracking
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• loss of material

• loss of closure integrity

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following existing AMPs to manage

the aging effects associated with the pressurizer:

• alloy 600 aging management program

• chemistry program

• Inservice inspection plan

• boric acid corrosion surveillance program

The applicant concluded that these AMPs will manage the effects of aging such that the

intended functions of the pressurizer components will be maintained consistent with the CLB

under all design loading conditions throughout the period of extended operation, as required by

10 CFR 54.21(a)(3). The applicant identifies metal fatigue (Section 4.3 of the LRA) as a TLAA

in Section 3.1 of the LRA that is applicable to pressurizer components.

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA

Section 3.1, Tables 3.1-1 and 3.1-2, and pertinent sections of LRA Appendices A and B,

regarding the applicant’s demonstration that the effects of aging will be adequately managed so

that the intended function(s) of the pressurizer will be maintained consistent with the CLB

throughout the period of extended operation, as required by 10 CFR 54.21(a)(3).

In LRA Tables 3.1-1 and 3.1-2, the applicant lists the pressurizer components within the scope

of the license renewal with their material groups and environment. The intended functions of

these components are listed in LRA Table 2.3-6. The tables also identify the aging effects

requiring management and the plant-specific AMPs required managing these aging effects

during the period of extended operation. The components within the scope of license renewal

are grouped in accordance with their component types, and these groups are listed in these

tables. In LRA Section 4.3, the applicant identifies metal fatigue as a TLAA that is applicable to

pressurizer components. The staff’s evaluation of this TLAA is presented in Section 4.3 of this

SER.

Aging Effects:

In accordance with LRA Section 3.1, the applicant has performed a review of industry

experience and NRC generic communications, relative to the pressurizer components, to

provide reasonable assurance that the aging effects that require management for a specific

material-environment combination are the only aging effects of concern for VCSNS. This also

included the VCSNS plant-specific operating experience.

The material of construction for the pressurizer components subject to an AMR are low-alloy

steels (SA533 Grade A, Cl 2 and SA508 Cl 2A) for the pressure retaining components including

shell and heads; austenitic stainless steels for nozzle safe ends, thermal sleeves, and heater

wells; stainless steel weld metal for cladding and buttering; SA193 Gr B-7 for closure bolting;
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and Alloy 82/182 weld metal for bimetallic welds and partial attachment welds. In LRA Table

3.1-1, the applicant identifies the following aging effects applicable to the pressurizer

components requiring an AMR:

• cracking of Alloy 82/182 welds between pressurizer nozzles and safe ends, between

thermal sleeves and safe ends, and between heater sleeves and the pressurizer lower

head, exposed to chemically treated borated coolant

• cracking of stainless steel instrument and sample lines, heater sleeves, thermal sleeves,

and safe ends exposed to chemically treated borated coolant

• cracking of pressurizer shells, heads, and nozzle cladding with stainless steel and

internally exposed to chemically treated borated coolant

• cracking of pressurizer integral supports

• loss of material in low-alloy steel pressurizer shells and heads, and closure bolting

externally exposed to leaking borated coolant

The applicant states that the identification of the above aging effects in LRA Table 3.1-1 is

consistent with the GALL report. However, the GALL report presents an AMR for six additional

pressurizer components (pressurizer seismic lugs, heater elements (heater sheaths), manway

pad gasket seating surface, safety valves, relief valves, and spray nozzles) that are not

addressed in the LRA. The staff issued RAI 3.1.2.4.6-1, requesting that the applicant submit an

explanation for not presenting an AMR for the following pressurizer components: seismic lugs,

heater elements, manway pad gasket seating surface, safety valves, and relief valves. In

response to RAI 3.1.2.4.6-1, in a letter dated June 12, 2003, the applicant submitted the

following explanation for the first three components. The pressurizer seismic lugs are included

with the pressurizer shell and are not included as a separate component. Immersion heater

well assemblies is the component name used at VCSNS for the heater sheaths and they are

included in LRA Table 3.1-1, Item 24, and LRA Table 3.1-2 Items 1 and 7. The manway pad

gasket-seating surface is the stainless steel clad mating surface of the manway nozzle and is

not called out as a separate component. The staff finds the explanation acceptable because

the AMR results for the three components are included in the LRA. In response to RAI

3.1.2.4.6-1, the applicant further states that the AMR results for the pressurizer safety and relief

valves are included in LRA Table 3.1-1, Items 19 and 24, and LRA Table 3.1-2, Items 1 and 5. 

The staff finds the response acceptable because the applicant includes these valves within the

scope of license renewal. The staff’s evaluation of the AMR results for these valves is

presented in Section 3.1.2.4.2 of this SER. As discussed in Section 2.3.1.6.2 of this SER,

pressurizer spray head is not within the scope of license renewal. 

According to LRA Table 2.3-6, the applicant presents the AMR results for the pressurizer

nozzles and safe ends. However, it is not clear to the staff about which specific nozzles are

addressed by the LRA. The staff issued RAI 3.1.2.4.6-2, requesting the applicant to confirm

whether the following five pressurizer nozzles and safe ends are included within the scope of

the LRA: surge nozzles, spray nozzles, safety nozzles, relief nozzles, and their safe ends, and

instrument nozzles. In response to RAI 3.1.2.4.6-2, in a letter dated June 12, 2003, the

applicant states that the five nozzles and safe ends are within the scope of the LRA. The staff
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finds the response acceptable because the same nozzles and safe ends are identified as the

components within the scope of license renewal by the Westinghouse report WCAP 14574-A.

In LRA Table 2.3-6, the applicant presents the AMR results of the pressurizer manway cover

(Row 4), manway cover (Row 6) and manway forgings (Row 7) exposed to chemically treated

borated coolant. The staff issued RAI 3.1.2.4.6-3, requesting that the applicant explain the

difference between the manway cover and the manway forgings. In response to RAI

3.1.2.4.6-3, in a letter dated June 12, 2003, the applicant explains that the manway cover listed

in Row 4 of LRA Table 2.3-6 is a non-structural stainless steel insert. The staff finds the

response related to the manway cover (Row 4) acceptable because it is consistent with the

corresponding AMR results presented in the LRA. However, the staff determined that the

remaining part of the applicant’s explanation was not clear. Therefore, the staff further

discussed this RAI with the applicant during the June 22, 2003, conference call which is

discussed below.

Based on the conference call, the applicant submitted the following additional information in

response to RAI 3.1.2.4.6-3. The major components of the pressurizer manway include the 

manway forgings, manway covers, and manway cover inserts. The manway covers and

forgings are made of low-alloy steel, whereas the manway cover insert is made of stainless

steel, as mentioned earlier. The manway forging is welded to the pressurizer shell. The

applicant further indicated that the manway cover is a pressure-retaining component that is

bolted to the manway forging. The stainless steel insert prevents the manway cover from being

in direct contact with the reactor coolant. The aging effect that the applicant identified for the

manway covers and forgings is loss of material due to boric acid corrosion. An additional aging

effect for the manway forgings is cumulative fatigue damage. The aging effects for the

manway cover inserts are loss of material due to pitting and crevice corrosion and cracking due

to stress corrosion cracking. The staff finds the information provided by the applicant in its

response to the staff acceptable because the identification of aging effects is consistent with

GALL.

The staff reviewed NUREG-1801 Chapter IV.C2, Reactor Coolant System and Connected

Lines, and confirmed that the applicant’s identification of the aging effects in Table 3.1-1 for the

pressurizer components is consistent with the GALL report, and, therefore, acceptable.

In Table 3.1-2, AMR Items 7 and 11, the applicant identifies the following two aging effects for

the pressurizer components:

• loss of material due to pitting and crevice corrosion of the pressurizer shells, heads,

manway cover inserts, and nozzles with stainless steel cladding, and safe ends, safe

end weld metals, thermal sleeves, heater wells, instrument lines and sample lines

• cracking due to SCC of the manway cover insert, heater wells, and instrument and

sample lines and their couplings

The stainless steel and Ni alloy components are inherently tough and resistant to general

corrosion. However, loss of material due to crevice and pitting corrosion may be an applicable

aging effect for these components under wet conditions, especially if the components have

creviced areas that may be exposed to the fluids. Therefore, the applicant's identification of
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loss of material as an aging effect for the in-core instrumentation system stainless steel and Ni

alloy components internally exposed to chemically treated borated coolant is acceptable.

Identification of cracking due to SCC as an applicable aging effect for the manway cover insert,

heater wells, and instrument and sample lines and their couplings, is consistent with GALL (see

GALL Items IV.C2.2-f, IV.C2.5-m, IV.C2.5-r). Therefore, this identification is acceptable.

According to Section 3.2.5 of the Westinghouse report, WCAP-14574-A, four components of

the pressurizer for which an AMR is performed, are exposed to fluid flows that have the

potential to result in erosion of the components: surge nozzle thermal sleeves and safe ends,

and spray nozzle thermal sleeves and safe ends. The staff, however, considered the

discussion in the WCAP report regarding the loss of material due to erosion unclear. 

Therefore, the staff issued RAI 3.1.2.4.6-4, requesting the applicant to explain why loss of

material due to erosion is not an applicable aging effect for these identified pressurizer

components at VCSNS.

In response to RAI 3.1.2.4.6-4, in a letter dated June 12, 2003, the applicant submitted the

following explanation. The applicant states that these components are made of stainless steel,

an erosion resistant material, and are not normally exposed to high velocity flow or two-phase

flow. In addition, the pressurizer pressure control is operated in a manner to reduce the spray

flow to a minimal amount. As a result, spray flow is normally several gallons a minute verses

the 750 gallons a minute design flow. Therefore, the applicant states that this low flow rate into

the pressurizer through the 4-inch spray nozzle and 14-inch surge nozzle safe ends and

associated thermal sleeves is insignificant to require erosion evaluations. The staff agrees with

the applicant’s explanation that loss of material due to erosion is not an applicable aging effect

for the pressurizer safe ends and nozzles because the actual flow velocities are much lower

than the design flow velocities and would not cause erosion.

The attachment welds at the inside surface of the pressurizer may be susceptible to crack

initiation and growth due to stress corrosion cracking and fatigue. The applicant does not

identify cracking as an applicable aging effect for the attachment welds. The staff issued RAI

3.1.2.4.6-5, requesting the applicant to identify the components that are welded to the

inside surface of the pressurizer and to submit its technical justification for whether cracking

due to SCC is an applicable aging effect. In response to RAI 3.1.2.4.6-5, in a letter dated June

12, 2003, the applicant stated that the support brackets for the heater supports are the only

components welded to the pressurizer clad. The applicant further stated that these materials

are not sensitized and referred to Section 5.2.5.2, Prevention of Intergranular Attack of

Unstabilized Austenitic Stainless Steels, of the VCSNS UFSAR, for further information

supporting its statement.

UFSAR Section 5.2.5.2 states that the Westinghouse design provides control of welding

processes and procedures to avoid heat-affected zone sensitization and control of the primary

water chemistry to ensure a benign environment. These controls prevent stress corrosion

cracking of wrought stainless steel weldments. However, the UFSAR does not provide a

discussion of the VCSNS plant-specific procedures and quality assurance requirements for the

welding and testing of the attachment welds and their associated heat-affected zones. The

applicant does not state whether the control of welding processes and procedures provided by

the Westinghouse design are consistent with the regulatory position presented in Regulatory

Guide 1.44, Control of the Use of Sensitized Stainless Steel. Although the applicant does not
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identify cracking as an aging effect for the attachment welds, the VCSNS aging management

activities evaluated in the next section (Section 3.1.2.4.6) also manages cracking of the

attachment welds. Therefore, not identifying cracking as an applicable aging effect for the

pressurizer attachment welds, does not have significant safety consequences. The staff finds

this acceptable because cracking of the attachment welds will be managed, even though the

applicant has not identified it as an applicable aging effect.

The aging effects identified in the LRA for the pressurizer components are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

In LRA Tables 3.1-1 and 3.1-2, the applicant has identified the following four AMPs for

managing the aging effects associated with pressurizer:

• boric acid corrosion surveillance program

• alloy 600 aging management program

• chemistry program

• Inservice inspection plan

The boric acid corrosion surveillance program (LRA Section B.1.2) was developed by the

applicant in response to NRC Generic Letter 88-05. Inspections are performed to present

reasonable assurance that borated water leakage from the reactor coolant pressure boundary

does not lead to undetected loss of material on the external surfaces of carbon steel or low

alloy steel components. The staff has evaluated this common AMP and found it to be

acceptable for managing the aging effect of loss of material identified for the RCS pressure

boundary components made of carbon steel or low-alloy steel. The staff’s evaluation of the

boric acid corrosion surveillance program is documented in Section 3.0.3 of this SER. The

evaluation of the alloy 600 program, as it is applied for managing PWSCC cracking of the Alloy

82/182 welds, is presented in Section 3.1.2.3.1 of this SER.

In LRA Table 3.1-2, AMR Item 7, the applicant credits the chemistry program (LRA Appendix

B.1.4) for managing loss of material due to crevice and pitting corrosion in pressurizer shell and

head cladding with austenitic stainless steel and stainless steel components internally exposed

to chemically treated borated coolant, i.e., PWR primary water. These components are

susceptible to crevice and pitting corrosion because high levels of oxygen may be present in

the PWR reactor coolant. However, PWR licensees maintain hydrogen overpressure in the

reactor coolant, and if the overpressure reaches a sufficiently high level, it would provide

protection in creviced geometries on the internal surfaces of the pressurizer. 

 In RAI B.1.4-5, the staff requested the applicant to discuss how the chemistry program will

provide for a sufficient level of hydrogen overpressure to manage crevice corrosion of the

internal surfaces of the pressurizer. In response to RAI B.1.4-5, the applicant states that the

chemistry program alone is adequate for managing loss of material due to crevice and pitting

corrosion in the pressurizer stainless steel components including cladding because hydrogen in

the borated coolant is controlled as recommended by the EPRI PWR water chemistry

guidelines. These guidelines are presented in an EPRI report, “PWR Primary Water Chemistry
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Guidelines-Revision 4,” EPRI TR-105714. According to these guidelines, hydrogen is

controlled between 25-50 cc/kg H2O in the RCS to ensure scavenging of oxygen and, thus,

protection against crevice and pitting corrosion. In EPRI TR-105714, it is stated that the

computations of production rates of oxidizing species by radiolysis suggest a dissolved

hydrogen concentration of significantly less than 15 cc/kg is sufficient to scavenge the oxidizing

species under all operating conditions. Since oxygen can also be added to the coolant from

other sources, an excess inventory of hydrogen must be maintained while the reactor is at

power. Therefore, the guidelines set a range of 25-50 cc/kg to provide a margin against the

oxidizing conditions and to facilitate operational control. The staff finds it acceptable that the

chemistry program alone is adequate for managing crevice and pitting corrosion in the VCSNS

pressurizer stainless steel components including cladding because the applicant follows the

EPRI primary water chemistry guidelines that ensure scavenging of oxygen from the PWR

primary water.

LRA Table 3.1-1, AMR Item 24, credits the chemistry program (LRA Appendix B.1.4) and the inservice inspection plan (LRA Appendix B.1.7) for managing cracking of the pressurizer shell,

and lower head and upper head cladding with austenitic stainless steel and internally exposed

to chemically treated borated coolant. The in-service inspection plan is mainly directed at

structural welds in the pressurizer shell and heads and not at the stainless steel cladding. 

However, in 1990, crack like indications were discovered in the Haddam Neck pressurizer

cladding. Thermal fatigue can initiate and propagate such cracking through the cladding and

into the ferritic base metal or weld metal beneath the clad. In RAI 3.1.2.4.6-6, the staff

requested the applicant to submit an AMP to verify whether thermal fatigue-induced cracking

has initiated in the clad and propagated through it into the ferritic base metal or weld metal

beneath the clad. In response to RAI 3.1.2.4.6-6, in a letter dated June 12, 2003, the applicant

states that the pressurizer shell design considers fatigue usage and the pressurizer surge line

nozzle as the limiting location from a fatigue usage perspective. The applicant further states

that the inspection of the surge line nozzle weld is included in the ISI plan (LRA Appendix

B.1.7). Therefore, inspection of the surge line nozzle weld indirectly provides condition

monitoring of the pressurizer cladding; therefore, a specific aging management program to

address cracking of the pressurizer cladding due to fatigue is not required. The staff accepts

the applicant’s response because the surge line weld is most susceptible to fatigue cracking

and its inspection would bound the other locations on the pressurizer cladding.

The staff has evaluated the chemistry program (LRA Appendix B.1.4) and found it acceptable

for managing cracking of pressurizer shells, lower head and upper head cladding with austenitic

stainless steel internally exposed to chemically treated borated coolant. The staff’s evaluation

of this AMP is presented in Section 3.0.3 of this SER.

LRA Table 3.1-1, AMR Item 26, credits the boric acid corrosion surveillance program (LRA

Appendix B.1.2) for managing loss of material due to boric acid corrosion of the following

pressurizer carbon steel and low alloy steel components: shells, upper and lower heads,

nozzles, integral supports, and manway covers and bolts. The staff identified that the applicant

does not present sufficient detail about how the program will be sufficient to manage the

corrosive effects of boric acid leakage on these components during the extended period of

operation, including postulated leakage from the pressurizer nozzle-to-vessel welds, pressurizer

nozzle-to-safe end welds, and pressurizer manway bolting materials.
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In RAI B.1.2-3, the staff requested the applicant to discuss how this program will be sufficient to

manage the corrosive effects of boric acid leakage on the base metal of these insulated

components during the extended period of operation. In response to RAI B.1.2-3, in a letter

dated June 12, 2003, the applicant states that the insulation on the mechanical joints on the

pressurizer is removed and the joints are inspected for leakage at each refueling. Corrective

actions for boric acid leaks are required for the source as well as the adjacent supports, or

structures and detected boric acid deposits are removed. For additional information, the

applicant refers to a letter from S. A. Byrne to the Document Control Desk, dated January 24,

2003, “Response for Additional Information Regarding 60-Day Response to NRC Bulletin 2002-

01 Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary

Integrity.” The letter states that the pressurizer manways and dissimilar welds on the

pressurizer nozzles and their adjacent areas are examined for boric acid residue. The

dissimilar welds include pressurizer nozzle welds to pressurizer safety valves, PORVs, spray

piping, and surge lines. The staff finds the response acceptable because the boric acid

corrosion surveillance program includes examination of Alloy 82/182 welds (dissimilar welds) on

the pressurizer nozzles and of the adjacent areas. The staff noted that not all of the inspections

include removal of insulation. The staff is pursuing further action with respect to removal of the

insulation during these inspections on a generic basis. The staff has evaluated the boric acid

corrosion surveillances program (LRA Appendix B.1.2) and found it acceptable for managing

loss of material due to boric acid corrosion of the external surfaces of the pressurizer carbon

steel and low alloy steel components. The staff’s evaluation of this AMP is presented in Section

3.0.3.1 of this SER.

LRA Table 3.1-1, AMR Item 22, credits the in-service inspection plan (LRA Appendix B.1.7) for

managing loss of mechanical closure integrity, which includes loss of preload, loss of material

and cracking, of the bolted closures for the pressurizer manway cover bolts. The Inservice

inspection plan, which is based on ASME Section XI, Subsection IWB, requires volumetric, and

VT-1 and VT-2 visual examinations of bolts. As discussed in Section 3.1.2.4.7 of this SER, the

staff finds that management of closure integrity by the ISI plan is adequate for managing loss of

material, cracking, and loss of preload in bolted closures. The staff has evaluated the inservice inspection plan and found it acceptable for managing the aging effects for the pressure

boundary components bolting. The staff’s evaluation of this AMP is presented in Section

3.1.2.3.3 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the pressurizer

components will effectively manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.1.2.4.7 Steam Generators

The VCSNS replacement Westinghouse Delta-75 steam generators are described in detail in

the UFSAR Section 5.5.2. To facilitate replacement in the plant, the geometric characteristics

of these replacement steam generators are identical to the original Westinghouse D-3 steam
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generators. The replacement steam generators were designed and analyzed in accordance

with Section III of the ASME Code, 1971 Edition (through summer 1971 Addenda) and were

constructed in accordance with the 1986 edition. 

The Delta-75 steam generator utilizes a vertical shell and U-tube evaporator with integral

moisture separation equipment. The reactor coolant flows through the inverted U-tubes,

entering and leaving through the nozzles located in the hemispherical bottom head (channel

head) of the steam generator. The channel head is divided into inlet and outlet chambers by a

vertical partition plate extending from the head to the tubesheet. Manways are provided for

access to both sides of the divided channel head. The feedwater inlet is located at

approximately 2/3 of the steam generator height and feedwater is distributed equally around the

circumference of the steam generator shell. Feedwater enters the tube bundle by flowing

downward between the steam generator external shell and inner wrapper barrel. An open area

at the bottom of the wrapper barrel permits the feedwater to enter the tube bundle. Steam is

generated and flows upward through the moisture separators and through the flow restrictor

outlet nozzle at the top of the steam drum. The steam generator utilizes high efficiency

centrifugal steam separators, which remove most of the entrained water. Chevron dryers are

employed to increase the steam quality to a minimum of 99.90% (0.10% moisture).

The steam generator channel head and tubesheet are protected from the primary water by

applying an autogenous weld deposited stainless steel cladding to the primary surfaces of the

channel head and Inconel to the tubesheet The cladding surface is machined to a smooth

condition and electropolished, thereby reducing the collection of radioactive contamination

inside the steam generators during refueling and maintenance periods. The 17.46-mm (11/16-

in.) diameter steam generator tubes are fabricated of thermally treated Alloy 690 and are fulldepth hydraulically expanded into the tubesheet. The tube support plates are fabricated of

Type 405 stainless steel with broached trefoil holes. The U-bends in the first nine rows of tubes

are heat treated to relieve residual stresses from bending.

Summary of Technical Information in the Application

The passive, long-lived steam generator components that are subject to an AMR are identified

in LRA Table 2.3-7. The components, aging effects, and aging management programs are

discussed in LRA Section 3.1 and they are listed in LRA Tables 3.1-1 and 3.1-2. The staff

reviewed Section 3.1 of the LRA to determine whether the applicant has demonstrated that the

effects of aging on the steam generator components will be adequately managed during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

Aging Effects:

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following applicable aging effects for

the steam generator components subject to an AMR: cumulative fatigue damage, loss of

material, and crack initiation and growth. In Table 2.3-7 and Table 3.1-2, item 2, the applicant

identifies no applicable aging effects for the stainless steel primary-side nozzle safe ends with

nickel-based welds.

Aging Management Programs:
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In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the following five AMPs to manage the

aging effects associated with the steam generator components:

• Steam Generator Management Program (LRA Appendix B.1.10)

• Chemistry program (LRA Appendix B.1.4)

• Boric acid corrosion surveillances (LRA Appendix B.1.2)

• In-service inspection plan (LRA Appendix B.1.7)

• Alloy 600 aging management program (LRA Appendix B.1.1)

The steam generator management program is an existing program developed by the applicant

specifically to manage cracking and loss of material in steam generator tubes and plugs. The

Alloy 600 management program is an existing program developed by the applicant to manage

primary water stress corrosion cracking of nickel-based alloy sub-components of the steam

generators that are exposed to borated water to ensure that the pressure boundary function is

maintained during the period of extended operation. The Alloy 600 Aging Management

Program includes elements of the boric acid corrosion surveillances and the ASME Section XI

System Pressure Test Program and the ASME Section XI Inservice Examination Program. The

applicant’s Inservice inspection (ISI) plan, chemistry program, and boric acid corrosion

surveillances are common AMPs that are credited by the applicant with managing aging effects

in several system component groups, and are evaluated in Section 3.0.3 of this SER.

The applicant concluded that these five AMPs will manage the effects of aging such that the

intended function of the steam generator components will be maintained consistent with the

CLB under all design loading conditions throughout the period of extended operation, as

required by 10 CFR 54.21(a)(3). 

Staff Evaluation

In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information included in LRA

Section 3.1, including Tables 3.1-1 and 3.1-2, and LRA Appendices A and B to determine that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) of the steam generator components will be maintained consistent with the

CLB throughout the period of extended operation.

In LRA Tables 3.1-1 and 3.1-2, the applicant identifies the steam generator components within

the scope of the license renewal, their material groups, environments, associated aging effects,

and corresponding aging management programs. The intended functions of these components

are listed in LRA Table 2.3-7. 

In LRA Section 4.3, the applicant identifies metal fatigue as the only TLAA applicable to the

steam generator pressure boundary components. The staff’s evaluation of this TLAA is in

Section 4.3 of this SER.

Aging Effects:

The applicant has performed a review of industry experience, NRC generic communications,

and the VCSNS plant-specific operating experience related to the steam generator components

to provide reasonable assurance that the aging effects that require management for a specific
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material-environment combination are the only aging effects of concern for VCSNS steam

generators. 

The materials of construction for the steam generator components are specified in Table 5.2-8

of the UFSAR. The shell, pressure forgings (including the nozzles and tubesheet), and channel

head are fabricated of SA508, Class 3a, low-alloy steel. The channel head, which is in contact

with borated primary water, is clad with weld-deposited Type 309L/308L austenitic stainless

steel, and the tubesheet primary surfaces are weld clad with the Ni-Cr-Fe alloy

N06082/W86182. The nozzle safe ends are fabricated of forged stainless steel. The steam

generator tubes are fabricated of thermally treated Alloy 690 (SB163 procured to ASME Code

Case N-20-3), and the tube support plates are made of Type 405 ferritic stainless steel. The

steam generator closure studs are made of SA193, Grade B-7, low-alloy steel and the closure

nuts are made of SA194, Grade 7, low-alloy steel.

Review of Aging Effects on Steam Generator-Related Items in LRA Table 3.1-1

In LRA Table 3.1-1, the applicant identifies the following aging effects applicable to the steam

generator components requiring AMPs that are specified in the GALL report and are relied

upon for VCSNS license renewal:

• loss of material in the steam generator shell assembly due to pitting and crevice

corrosion

• crack initiation and growth in the steam generator tubes, repair sleeves, and plugs due

to primary water stress corrosion cracking (PWSCC), outer diameter stress corrosion

cracking (ODSCC), and/or intergranular attack (IGA)

• loss of material in the steam generator tubes, repair sleeves, and plugs due to wastage

and pitting corrosion and fretting and wear

• deformation of the steam generator tubes due to corrosion at the tube support plate

intersections

• loss of closure integrity for closure bolting

• loss of material in the external surfaces of carbon steel and low-alloy steel components

in the reactor coolant system pressure boundary due to boric acid corrosion

• crack initiation and growth in the steam generator upper and lower heads, tubesheets,

and primary nozzles and safe ends due to SCC 

• crack initiation and growth in the steam generator nozzle Alloy 82/182 welds exposed to

the chemically treated borated coolant due to PWSCC

The staff’s evaluation of the applicability of each of the above aging effects to the relevant

components is as follows:

In LRA Table 3.1-1, Item 2, the applicant addresses loss of material due to pitting and crevice

corrosion in the steam generator shell assembly. However, the applicant identifies cracking
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and not the loss of material due to pitting and crevice corrosion as the aging effect to be

managed. The applicant further states that NRC IN 90-04 contains only general indication that

pits on the surface served as crack initiation sites, and not that pitting corrosion resulted in

sufficient degradation to cause loss of component function. The staff finds that the applicant

provides insufficient basis to support its assertion that loss of material due to pitting and crevice

corrosion is not an applicable aging effect for the steam generator shell assembly. The staff’s

evaluation of these AMR results is presented in Section 3.1.2.2.2 of this SER.

In LRA Table 3.1-1, AMR Item 9, the applicant addresses possible crack initiation and growth

due to SCC and PWSCC in various stainless steel and nickel-alloy components. In the

discussion section for this AMR item, the applicant does not include steam generator instrument

lines in the component group for aging management. The staff issued RAI 3.1.2.4.7-1,

requesting the applicant to confirm whether instrument and drain lines in VCSNS steam

generators are made of Alloy 600 and addressed by this AMR item. The staff also requested

the applicant to provide information about whether Alloy 82/182 weld metal used in the nozzle

welds that are addressed by this AMR item. In its response to RAI 3.1.2.4.7-1, in a letter dated

June 12, 2003, the applicant states that at VCSNS only the core support pads and bottom head

penetrations are included in LRA Table 3.1-1, AMR Item 9. The steam generator instrument

and drain lines are not made of Alloy 600 material. In addition, the applicant states that the

primary side of the VCSNS steam generators does not have Alloy 600 or Alloy 82/182 weld

material exposed to borated water other than the cladding of the primary side of the tube sheet. 

The staff concludes that it is acceptable that the aging effect of crack initiation and growth due

to SCC and PWSCC are not applicable to the nozzles for the steam generator instruments and

drains because they are not made of Alloy 600 and do not have Alloy 82/182 weld materials. 

In LRA Table 3.1-1, AMR Item 15, the applicant addresses the potential aging effects of

cracking, loss of material, and deformation in steam generator tubes and plugs. The staff’s

evaluation of these aging effects and their management is presented in Section 3.1.2.2.15 of

this SER. The staff concluded that the applicant has adequately evaluated the management of

(1) crack initiation and growth due to PWSCC, ODSCC, or IGA, or (2) loss of material due to

wastage and pitting corrosion, (3) loss of material due to fretting and wear, or (4) deformation

(denting) due to corrosion of carbon steel tube support plate in the Steam generator tubes and

plugs, as recommended in the GALL Report.

In LRA Table 3.1-1, AMR Item 17, the applicant addresses ligament cracking of carbon steel

support plate due to corrosion. The applicant states that this aging effect is not an applicable

aging effect because the support plates at VCSNS steam generators are made of Type 405

stainless steel and not carbon steel. The staff finds this explanation acceptable because based

on industry experience, Type 405 stainless steel exposed to secondary side treated water is not

likely to be susceptible to corrosion and, therefore, will not likely to experience ligament

cracking. 

In LRA Table 3.1-1, AMR Item 21, the applicant addresses potential loss of material (wall

thinning) due to flow-assisted corrosion (FAC) for the steam generator steam and feedwater

nozzles and safe ends. The applicant states that this effect is not an applicable aging effect for

these components at VCSNS and aging management is therefore not required, but provides no

justification for this conclusion. The staff issued RAI 3.1.2.4.7-4, requesting the applicant to

provide the technical basis for determining that loss of material caused by FAC is not an

applicable aging effect for the steam generator nozzles and safe ends. In its response to RAI
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3.1.2.4.7-4, in a letter dated June 12, 2003, the applicant states that the main steam exiting the

steam generators is dry (less than 0.1% moisture), and dry steam is not a concern for flowaccelerated corrosion. In addition, according to the Westinghouse report, “Westinghouse Delta

75 Steam Generator Design and Fabrication information for the Virgil C. Summer Nuclear

Station," WCAP-13480, Rev. 1, October 1993, the main steam and feedwater nozzles are

fabricated from low-alloy steel and, therefore, not susceptible to FAC. Also there is no safe end

for feedwater nozzle at VCSNS. The staff accepts the applicant's conclusion that loss of

material due to FAC is not an applicable aging effect for the steam generator main steam

nozzle and safe end, and feedwater nozzle because these components are made of low alloy

steel and main steam exiting steam generator is dry. 

In LRA Table 3.1-1, AMR Item 22, the applicant states that for steam generator bolting, loss of

closure integrity rather than loss of preload or cracking is the aging effect requiring

management. The staff issued RAI 3.1.2.4.7-5, requesting the applicant to explain how does

the aging effect of loss of closure integrity in steam generator bolting differ from the effects of

loss of material, loss of preload, and cracking. The staff had issued similar RAIs (RAI

3.1.2.4.2-1 and RAI 3.1.2.4.6-7) for bolting closures for Class 1 piping and the pressurizer. In

its response to RAI 3.1.2.4.7-5, the applicant stated that loss of mechanical closure integrity

can result in failure of the mechanical joint and its evidenced by leakage rather than joint failure. 

The applicant further states that this failure of mechanical joint can be attributed to loss of bolt

preload, loss of bolting material by water, and cracking of high strength bolting material. 

Therefore, loss of closure integrity includes the effects of loss of preload, loss of material, and

cracking of bolting materials. The staff concludes that the applicant has identified appropriate

aging effect for the steam generator bolting and that management of loss of closure integrity

includes management of three additional aging effects: loss of material, loss of preload, and

cracking.

In LRA Table 3.1-1, AMR Item 32, the applicant identifies the aging effect of crack initiation and

growth due to SCC and PWSCC for the channel head divider plate in the VCSNS steam

generators. The staff issued RAI 3.1.2.4.7-6, requesting the applicant to confirm whether the

weld on the divider plate is an Alloy 82/182 weld. In its response to RAI 3.1.2.4.7-6, in a letter

dated June 12, 2003, the applicant states that the divider plate is welded with Alloy 82/182;

however, the final pass was made with Alloy 52/152 so the weld does not have Alloy 82/182

exposed to borated water. The applicant further states that VCSNS has no evidence of

cracking of the 52/152 welds since the installation of the replacement steam generators in the

1994 outage. The staff finds the applicant’s response acceptable because the absence of

cracking in these welds is consistent with the use of Alloy 52/152 weld metal for which industry

experience has not revealed any cracking. 

The aging effects identified in the LRA for the steam generator components in LRA Table 3.1-1

are consistent with GALL IV.D1, “Steam Generator (Recirculating).” The staff finds that the

aging effects were identified.

Review of Aging Effects on Steam Generator-Related Items in LRA Table 3.1-2

In LRA Table 3.1-2, the applicant identifies the following additional aging effects for steam

generator components exposed to secondary treated water. These aging effects are

considered to be different from or are not addressed in GALL but are identified as a result of

the applicant’s license renewal review.
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• loss of material in carbon steel components exposed to the treated secondary

water/steam environment due to crevice corrosion, general corrosion, pitting corrosion,

and galvanic corrosion 

• loss of material in various steam generator pressure boundary components due to

crevice corrosion and pitting corrosion

• loss of material in secondary-side thermal sleeves and the steam outlet nozzle flow

limiter due to crevice corrosion and pitting corrosion

• crack initiation and growth in secondary-side thermal sleeves and the steam outlet

nozzle flow limiter due to stress corrosion cracking and flaw growth at welds (Item 9)

• loss of material in the feedwater distribution pipe and fittings due to crevice and pitting

corrosion

• crack initiation and growth in the feedwater distribution pipe and fittings due to stress

corrosion cracking

• loss of material in stainless steel and nickel-based alloy components exposed to treated

secondary water due to crevice and pitting corrosion; crack initiation and growth in these

components due to SCC 

In LRA Table 3.1-2, AMR Item 2, the applicant lists primary side nozzle safe ends that are

made of austenitic stainless steel and exposed to an air-gas (moist air) environment. The

applicant states that no aging effect or mechanism is identified for these components, since

the ambient environment at VCSNS does not contain contaminants of sufficient concentration

to cause aging effects requiring management. The staff agrees with the applicant’s conclusion

that these materials are not expected to undergo any aging degradation in this environment.

In LRA Table 3.1-2, AMR Item 3, the applicant identifies loss of material as an applicable aging

effect for carbon steel components (other than shell) exposed to secondary treated water. In

addition, in LRA Table 3.1-2, AMR Items 8, 9, and 10, the applicant identifies loss of material

and cracking as aging effects for stainless steel and low alloy steel components exposed to

secondary treated water. The staff finds this identification of applicable aging effects

acceptable because it is consistent with the similar identification in GALL IV.D1. For example,

GALL Item IV.D1.1-c, identifies loss of material as an aging effect for carbon steel and low alloy

steel components exposed to secondary treated water.

In LRA Table 3.1-2, AMR Item 7, the applicant identifies loss of material due to pitting and

crevice corrosion as an aging effect for the primary side of manway cover insert plates made of

stainless steel and exposed to chemically treated borated coolant. The staff finds this

identification of loss of material as an aging effect acceptable because it is consistent with the

similar identification in GALL IV.D1.

 In LRA Table 3.1-2, AMR Item 11, the applicant identifies crack initiation and growth due to

stress corrosion cracking on the primary side of manway cover insert plates exposed to

chemically treated borated coolant. The staff finds this identification of cracking as an aging

effect acceptable because it is consistent with the similar identification in GALL IV.D1.
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The aging effects identified in the LRA for the steam generator components are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

As discussed in Section 3.1.2.4.7, the applicant identified five AMPs to manage the aging

effects associated with the steam generator components. These AMPS are the steam

generator management program, chemistry program, boric acid corrosion surveillances, inservice inspection plan, and the Alloy 600 aging management program.

The steam generator management program is an existing program credited with managing

cracking and loss of material in steam generator tubes and plugs. The applicant states that this

program is consistent with GALL AMP XI.M19, “Steam Generator Tube Integrity”. The staff has

evaluated this AMP and, pending satisfactory resolution of the related RAIs, found it to be

acceptable for managing the aging effects identified for the steam generator components. The

staff’s evaluation of this AMP is documented in Section 3.1.2.3.7 of this SER.

The chemistry program manages water quality that is compatible with the materials of

construction used in the Class 1 piping, steam generator components, and related components

in order to minimize loss of material and cracking. This program incorporates EPRI and

Institute of Nuclear Power Operations (INPO) guidelines, which reflect industry experience, and

the “lessons learned” from VCSNS and external industry operating experience. The staff’s

evaluation of this AMP is documented in Section 3.0.3.2 of this SER.

The boric acid corrosion surveillances program was developed by the applicant in response to

NRC Generic Letter 88-05. Inspections are performed to provide reasonable assurance that

borated water leakage from the reactor coolant pressure boundary does not lead to undetected

loss of material on the external surface of carbon steel or low alloy steel bolting or other

components. The staff’s evaluation of this AMP is documented in Section 3.0.3.1 of this SER.

The ISI plan manages aging effects of loss of material, cracking, and gross loss of preload for

the RCS Class 1 steam generator pressure-boundary components and bolting. The scope of

the ISI plan for these Class 1 components complies with the requirements of ASME Section XI,

Subsection IWB. Depending on the examination category, the methods of inspections may

include visual, surface and/or volumetric examination of weld locations susceptible to aging

degradation. Subsection IWB specifies either inspect for loss of material and cracking in the

Class 1 components, or inspect for indications of reactor coolant leakage which, in the case of

bolted connections, would be indicative of a loss of preload in the bolt. The staff’s evaluation of

this AMP is documented in Section 3.1.2.3.3 of this SER.

The Alloy 600 aging management program manages cracking in Alloy 600 cladding on the

primary side of the tubesheet exposed to chemically treated borated coolant. As mentioned in

Section 3.1.2.4.7, the primary side of the VCSNS steam generators does not have any other

Alloy 600 components or Alloy 82/182 welds. The staff's evaluation of this AMP is documented

in Section 3.1.2.3.1 of this SER.

Review of AMPs of Steam Generator-Related Items in LRA Table 3.1-1 
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In LRA Table 3.1-1, AMR Item 15, the applicant credits the steam generator management

program and the chemistry program for managing the following three aging effects for Alloy 690

tubes and plugs: crack initiation and growth due to PWSCC, ODSCC, and IGA; loss of material

due to wastage and pitting corrosion, and fretting and wear; and deformation due to corrosion

at tube support plate intersections of tubes and plugs. The staff has evaluated this AMR results

in Section 3.1.2.2.15 of this SER and concluded that the steam generator management

program and chemistry program will manage the aging effects adequately during the period of

extended operation.

In LRA Table 3.1-1, AMR Item 22, the applicant credits the in-service inspection plan for

managing loss of closure integrity of steam generator class 2 bolting. The staff issued RAI

3.1.2.4.7-5, requesting the applicant to explain how the management of loss of closure integrity

would ensure that loss of material, cracking, and loss of preload are managed. RAI 3.1.2.4.7-5,

further requested the applicant to confirm whether bolt retorquing is performed at VCSNS as a

part of its maintenance activities. In response to RAI 3.1.2.4.7-5, in a letter dated June 12,

2003, the applicant states that the bolts for steam generator closure are inspected following the

ASME Section XI inspection guidelines during each inspection interval. This inspection will

detect presence of loss of material and cracking and thus manage these aging effects. The

applicant further states that the bolted connections are disassembled for scheduled inspection

activities. Retorquing of the bolts to a proper preload during reassembly would ensure that the

loss of preload present prior to disassembly is removed. Thus retorquing of the bolts following

the inservice inspection manages loss of preload. The staff finds the applicant’s response

acceptable because the ISI plan will manage loss of closure integrity of steam generator bolting 

to ensures that loss of material, cracking, and loss of preload in steam generator closure bolts

are managed properly.

In LRA Table 3.1-1, AMR Item 26, the applicant credits the boric acid corrosion surveillances for

managing loss of material due to boric acid corrosion of external surfaces of carbon steel steam

generator pressure boundary components. The staff finds this acceptable because the boric

acid corrosion surveillances program has been evaluated in Section 3.0.3.1 of this SER and

has been found, pending on satisfactory resolution of the any related RAIs, to be effective for

the management of this aging effect in these components.

In LRA Table 3.1-1, AMR Item 32, the applicant credits the chemistry program in conjunction

with the in-service inspection plan and the Alloy 600 aging management program with

managing cracking due to SCC and PWSCC of lower heads, tubesheet, divider plate, and

primary nozzles and safe ends. The staff finds that the three programs credited by the

applicant will be adequate for managing cracking in the components identified because the

programs include mitigative program and condition monitoring programs. Also, these three

programs are evaluated by the staff in Section 3.0.3 of this SER and are found to be effective

for the management of this aging effect in these components. The staff issued RAI 3.1.2.4.7-

7c, requesting the applicant to confirm whether the in-service inspection plan includes

inspection of the weld between the divider plate and the tubesheet, since this region is

potentially susceptible to SCC and PWSCC. In response to RAI 3.1.2.4.7-7c, in a letter dated

June 12, 2003, the applicant confirmed that the inspection of the divider plate welds is included

in the ISI plan. The staff finds the response acceptable because the ISI plan and the chemistry

program will be adequate for managing cracking in the divider plate welds. 
3-143

On the basis of its review, the staff finds that the AMPs credited in the LRA for the steam

generator components will effectively manage or monitor the aging effects identified in the LRA.

Review of AMPs of Steam Generator-Related Items in LRA Table 3.1-2 

In LRA Table 3.1-2, AMR Item 3, the applicant discusses management of loss of material due

to crevice, general, pitting, and galvanic corrosion in various carbon steel secondary-side steam

generator components. These components include the manways and manway covers;

handholes and handhole covers; sludge collector opening and inspection ports and port covers;

secondary-side feedwater and emergency feedwater nozzles; blowdown, drain, level sample,

and wet layup taps; tube bundle wrapper, wrapper support and downcomer; and secondary side

of the tube plate. The applicant notes that these components are not specifically addressed in

GALL Chapter IV and states that the chemistry program provides adequate management for

these aging effects. The staff issued RAI 3.1.2.4.7-9, requesting the applicant to provide a

condition-monitoring program to verify the effectiveness of the chemistry program in mitigating

loss of material in these components. The staff also requested the applicant to confirm whether

these components were included in the 100% inspection of the steam generator secondary side

during Refueling Outage 12 as discussed in LRA Appendix B.1.10. In its response to RAI

3.1.2.4.7-9, in a letter dated June 12, 2003, the applicant refers to GALL AMP XI.M2, “Water

Chemistry,” which states: 

The water chemistry programs are generally effective in removing impurities from intermediate and high

flow areas. The GALL report identifies those circumstances in which the water chemistry program is to be

augmented to manage the effects of aging for license renewal. For example, the water chemistry program

may not be effective in low flow or stagnant flow areas. Accordingly, in certain cases as identified in the

GALL report, verification of the effectiveness of the chemistry control program is undertaken to ensure that

significant degradation is not occurring and the component intended function will be maintained during the

extended period of operation.

The applicant further states that VCSNS steam generator components do not have low flow or

stagnant areas to cause concern for the chemistry program not being effective. Therefore, the

staff accepts that the applicant’s chemistry program is effective in managing loss of material in

the VCSNS steam generator carbon steel components because it is consistent with GALL AMP

XI.M2, “Water Chemistry.” 

In RAI 3.1.2.2.2-1, the staff requested the applicant to identify all of the components inspected

as part of the 100% secondary side inspection performed during Refueling Outage 12. In its

response to RAI 3.1.2.2.2-1, the applicant described the steam generator secondary side

components that were inspected: sludge collector, feedwater and emergency feedwater

nozzles, outside surface of the drain tube and tube supports, shroud surfaces, blowdown piping

and supports, and secondary side of the tubesheet. The applicant states that these visual

inspections did not detect any sign of erosion, corrosion, or degradation. The staff concludes

that the inspection results confirm that the chemistry program is adequate for managing loss of

material in the carbon steel components addressed by LRA Table 3.1-2, AMR Item 3.

In LRA Table 3.1-2, AMR Items 7, 8, 11, and 13, the applicant credits the chemistry program for

managing loss of material in the following stainless steel and material components not

specifically addressed in GALL Chapter IV:
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• Crevice and pitting corrosion of stainless steel and nickel-based alloy channel head and

inlet/outlet nozzles (stainless steel clad), channel head divider plate, manway cover

insert plates (primary side), nozzle safe ends (primary side), inlet/outlet nozzles closure

ring and weld metal, and tubesheet (primary side)

• Crevice and pitting corrosion of secondary-side thermal sleeves and steam flow limiter

• SCC of manway covers insert plates (primary side)

• Crevice and pitting corrosion, SCC of tube support plates, anti-vibration bars, flow

distribution baffle 

The staff concludes that the chemistry program is acceptable for managing the loss of material

in stainless steel and nickel-based material components exposed to either chemically treated

borated coolant or secondary treated coolant because stainless steel and nickel-based

materials have good resistance to pitting and crevice corrosion.

In LRA Table 3.1-2, AMR Item 9, the applicant addresses crack initiation and growth due to

SCC and flaw growth in welds in various thermally treated Alloy 690 steam generator

components, including the secondary-side feedwater and emergency feedwater nozzle thermal

sleeves and the steam outlet nozzle flow limiter. The applicant notes that these components

are not specifically addressed in GALL Chapter IV and states that the chemistry program and

the in-service inspection plan with the management of these aging effects. However, the staff

notes that ASME Section XI, Article IWC-2000, Table IWC-2500-1, does not explicitly include

the attachment welds for these components. The staff issued RAI 3.1.2.4.7-11, requesting the

applicant to confirm whether the attachment welds for these components are included in the inservice inspection plan. 

In its response to RAI 3.1.2.4.7-11, in a letter dated June 12, 2003, the applicant states that it

credits only the chemistry program for managing cracking in these components. This response,

however, contradicts the AMR results presented in LRA Table 3.1-2, Item 9. This RAI was

further discussed with the applicant during the June 22, 2003, conference call. Based on the

conference call, the applicant clarified its response to RAI 3.1.2.4.7-11, by stating that both the

chemistry program and the ISI program manage cracking in thermally treated Alloy 690

components on the secondary side of the steam generators. In its additional response to RAI

3.1.2.4.7-11, in letter dated September 2, 2003, the applicant stated that the emergency

feedwater piping and the first section of the main feedwater distribution piping that are welded

to the steam generator nozzles act as thermal sleeves. The applicant also stated that its steam

generator management program includes a visual inspection of the main feedwater distribution

piping, emergency feedwater piping, and the steam outlet nozzle flow limiter. The applicant

stated further that LRA Table 3.1-2, Item 9, is incorrect by stating that the ISI program manages

cracking in these components. The staff finds the applicant’s response acceptable because

these components are being managed for the applicable aging effects under the steam

generator management program. 

In LRA Table 3.1-2, AMR Item 10, the applicant credits the chemistry program in conjunction

with the in-service inspection plan with managing loss of material due to crevice and pitting

corrosion and cracking due to SCC of feedwater distribution pipe and fittings that are fabricated

with alloy steel (chrome molybdenum). The staff was not clear about the type of inspection
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performed and was concerned about adequacy of this inspection for detecting loss of material

and cracking that may take place at the inside surface of the feedwater distribution system. 

The staff issued RAI 3.1.2.4.7-12, requesting the applicant to confirm whether these

components were included in the 100% inspection of the steam generator secondary side

during Refueling Outage 12. In its response to RAI 3.1.2.4.7-12, in a letter dated June 12,

2003, the applicant states that the feedwater distribution components were inspected during

Refueling Outage 12 and no abnormal indications were noted. The applicant also states that

the chemistry program alone is adequate for managing the aging effects in feedwater

distribution system pipe and fittings. This response, however, contradicts the AMR results

presented in LRA Table 3.1-2, Item 10. This RAI was further discussed with the applicant

during the June 22, 2003, conference call. Based on the conference call, the applicant clarified

its response to RAI 3.1.2.4.7-12, by stating that both the chemistry program and the ISI

program manage loss of material due to crevice and pitting corrosion and cracking due to SCC

of the feedwater distribution pipe and fittings. However, the staff indicated that the applicant

needs to confirm that the VCSNS ISI plan includes inspection of the feedwater distribution pipe

and fittings. 

In its additional response to RAI 3.1.2.4.7-11, in letter dated September 2, 2003, the applicant

stated that the steam generator management program includes a visual inspection of the

feedwater distribution pipe and fittings. The applicant stated further that LRA Table 3.1-2, Item

10, is incorrect by stating that the ISI program manages cracking in the feedwater distribution

piping. The staff finds the applicant’s response acceptable because the feedwater distribution

piping and fittings are being managed for the applicable aging effects under the steam

generator management program. 

In LRA Table 3.1-2, AMR Item 13, the applicant discusses loss of material due to crevice and

pitting corrosion and crack initiation and growth due to SCC in the tube support plates, antivibration bars, and flow-distribution baffle. These components are made of stainless steel or

nickel-based alloys. The applicant states that the chemistry program provides adequate

management for these aging effects, but does not provide a condition-monitoring program for

verifying the effectiveness of the chemistry program. The staff issued RAI 3.1.2.4.7-13,

requesting the applicant to submit technical basis showing adequacy of using the chemistry

program for managing the aging effects. In its response to RAI 3.1.2.4.7-13, in a letter dated

June 12, 2003, the applicant states that the accessible portions of these components were

inspected during Refueling Outage 12 and no abnormal indications were noted. The applicant

further states that use of the chemistry program is consistent with the operating experience

conducted at VCSNS. The applicant also states that these components do not have low flow or

stagnant areas. The staff finds the applicant’s response acceptable because the results of the

inspections performed during Refueling Outage 12 verify the effectiveness of the chemistry

program. 

On the basis of its review, the staff finds that the AMPs credited in the LRA for the steam

generator components will effectively manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent
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with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2 Engineered Safety Features Systems

This section addresses the aging management of the components of the engineered safety

features systems group. The systems that make up the ESF system group are described in the

following SER sections:

• chemical and volume control system (2.3.2.1)

• containment isolation system (2.3.2.2)

• hydrogen removal system (2.3.2.3)

• reactor building spray system (2.3.2.4)

• refueling water system (2.3.2.5)

• residual heat removal system (2.3.2.6)

• safety injection system (2.3.2.7)

As discussed in Section 3.0.1 of this SER, the components in each of these ESF systems are

included in one of two LRA tables. LRA Table 3.2-1 consists of ESF system components that

are evaluated in the GALL Report, and LRA Table 3.2-2 consists of ESF system components

that are different from those addressed in the GALL Report or not addressed in it.

3.2.1 Summary of Technical Information in the Application

In LRA Section 3.2, the applicant described its AMRs for the ESF systems group at VCSNS. 

The description of the systems that comprise the ESF systems group can be found in LRA

Section 2.3.2. The passive, long-lived components in these systems that are subject to an

AMR are identified in LRA Tables 2.3-8 through 2.3-17.

The applicant’s AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and discussions

with appropriate site personnel to identify aging effects that require management. These

reviews concluded that the aging effects requiring management based on VCSNS operating

experience were consistent with the aging effects identified in GALL.

The applicant’s review of industry operating experience included a review of operating

experience through 2002. The conclusions of this review were that the aging effects requiring

management based on industry operating experience were consistent with the aging effects

identified in GALL. The applicant’s ongoing review of plant-specific and industry-wide operating

experience is conducted in accordance with the VCSNS Operating Experience Program.

3.2.2 Staff Evaluation

In Section 3.2 of the LRA, the applicant described its AMR for the ESF systems. The staff

reviewed LRA Section 3.2 to determine whether the applicant had provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB throughout the period of extended

operation, in accordance with the requirements of 10 CFR 54.21(a)(3), for the ESF system
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components that are determined to be within the scope of license renewal and subject to an

AMR. The applicant referenced the GALL Report in its AMR. The staff has previously

evaluated the adequacy of the aging management of ESF system components for license

renewal, as documented in the GALL Report. Thus, the staff did not repeat its review of the

matters described in the GALL Report, except to ensure that the material presented in the LRA

was applicable, and to verify that the applicant had identified the appropriate programs as

described and evaluated in the GALL Report. The staff evaluated those aging management

issues recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the UFSAR

supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the ESF system components.

In LRA Section 3.2, the applicant provided brief descriptions of the ESF systems and

summarized the results of its AMR of the ESF systems at VCSNS.

Table 3.2-1 below provides a summary of the staff’s evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.2 that are addressed in the GALL

Report.

Table 3.2-1: Staff Evaluation for VCSNS Engineered Safety Features System Components in the GALL

Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

Piping, fittings, and

valves in emergency

core cooling system

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA Consistent with GALL.

GALL recommends

further evaluation. (See

Section 3.2.2.2.1

below.)

Piping, fittings,

pumps, and valves in

emergency core

cooling system

Loss of material due to

general corrosion

Water chemistry and

one-time inspection

N/A BWR

Components in

containment spray

(PWR only), standby

gas treatment (BWR

only), containment

isolation, and

emergency core

cooling systems

Loss of material due to

general corrosion

Plant-specific Inspections for

Mechanical

Components

Program;

Chemistry

Program

Consistent with GALL. 

GALL recommends

further evaluation. 

(See Section 3.2.2.2.2

below.)

Piping, fittings,

pumps, and valves in

emergency core

cooling system

Loss of material due to

pitting and crevice

corrosion

Water chemistry and

one-time inspection

N/A BWR

Components in

containment spray

(PWR only), standby

gas treatment (BWR

only), containment

isolation, and

emergency core

cooling systems

Loss of material due to

pitting and crevice

corrosion

Plant-specific Inspections for

Mechanical

Components

Program

Chemistry

Program

Consistent with GALL.

GALL recommends

further evaluation. (See

Section 3.2.2.2.3

below.)
Table 3.2-1: Staff Evaluation for VCSNS Engineered Safety Features System Components in the GALL

Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

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Containment

isolation valves and

associated piping

Loss of material due to

MIC

Plant-specific None Not applicable to

VCSNS. (See Section

3.2.2.2.4 below.)

Seals in standby gas

treatment system

Changes in properties

due to elastomer

degradation

Plant-specific N/A BWR

High pressure safety

injection (charging)

pump miniflow orifice

Loss of material due to

erosion 

Plant-specific None Not applicable to

VCSNS (See Section

3.2.2.2.5 below.)

External surface of

carbon steel

components 

Loss of material due to

general corrosion

Plant-specific Inspections for

Mechanical

Components

Program

Consistent with GALL.

GALL recommends

further evaluation (See

Section 3.2.2.2.6

below.)

Drywell and

suppression

chamber spray

system nozzles and

flow orifices

Plugging of nozzles

and flow orifices due to

general corrosion

Plant-specific N/A BWR

Piping and fittings of

CASS in emergency

core cooling system

Loss of fracture

toughness due to

thermal aging

embrittlement

Thermal aging

embrittlement CASS

None Not applicable to

VCSNS. (See Section

3.2.2.1 below.) 

Components

serviced by opencycle cooling system

Local loss of material

due to corrosion and/or

buildup of deposit due

to biofouling

Open-cycle cooling

water system

N/A Not applicable to the

ESF components at

VCSNS. (See Section

3.2.2.1 below.)

Components

serviced by closedcycle cooling system

Loss of material due to

general, pitting, and

crevice corrosion

Closed-cycle cooling

water system

Chemistry

Program

Consistent with GALL.

(See Section 3.2.2.1

below.) 

Emergency core

cooling system

valves and lines to

and from HPCI and

RCIC pump turbines

Wall thinning due to

FAC

Flow-accelerated

corrosion

N/A BWR

Pumps, valves,

piping, and fittings in

containment spray

and emergency core

cooling systems

Crack initiation and

growth due to SCC

Water chemistry Chemistry

Program

Consistent with GALL

(See Section 3.2.2.1

below.)

Pumps, valves,

piping, and fittings in

emergency core

cooling systems

Crack initiation and

growth due SCC and

IGSCC

Water chemistry and

BWR stress corrosion

cracking

N/A BWR

Carbon steel

components

Loss of material due to

boric acid corrosion

Boric acid corrosion Boric Acid

Corrosion

Surveillances

Program

Consistent with GALL. 

(See Section 3.2.2.1

below.)
Table 3.2-1: Staff Evaluation for VCSNS Engineered Safety Features System Components in the GALL

Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

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Closure bolting in

high pressure or high

temperature systems

Loss of material due to

general corrosion, loss

of preload due to stress

relaxation, and crack

initiation and growth

due to cyclic loading or

SCC

Bolting integrity Bolting Integrity

Program

Loss of mechanical

closure integrity is not

considered an aging

effect requiring evaluation for non-Class 1

component bolted

closures. The specific

bolting/fastener

materials of subject

component types were

not itemized 

separately, but were

treated as a “piecepart” of non-Class 1

components/

component type.

3.2.2.1 Aging Management Evaluations in the GALL Report That Are Relied On for License

Renewal, That Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these groups were bounded by the GALL evaluation. The staff also sampled component

groups to determine whether the applicant had properly identified those component groups in

GALL that were not applicable to its plant. The staff also identified several areas for which

additional information or clarification was needed. The staff’s evaluation of the applicant’s

responses to those RAIs is included in Section 3.2.2.4 of this SER. 

On the basis of its review of the inspection results, the staff has verified the applicant’s claim of

consistency with the GALL report. The staff finds 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).

3.2.2.2 Aging Management Evaluations in the GALL Report That Are Relied on for License

Renewal, For Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant’s

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups

during the review to determine whether the plant-specific components contained in these

groups were bounded by the GALL evaluation. 

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.
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3.2.2.2.1 Cumulative Fatigue Damage

The GALL Report identifies that 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). The staff reviewed the

evaluation of this TLAA in Section 4.3 of this SER, following the guidance in Section 4.3 of the

SRP-LR.

The applicant indicated that all TLAAs, including those for the Class 1 components of the ESF

systems, were evaluated in the RCS section of the LRA. The applicant discussed the TLAA in

Section 4.3 of the LRA, “Metal Fatigue.” This TLAA is evaluated in Section 4.3 of this SER.

3.2.2.2.2 Loss of Material Due to General Corrosion

Loss of material due to general corrosion could occur in the containment spray system header

and spray nozzle components and the external surfaces of PWR carbon steel components. The

GALL Report recommends further evaluation on a plant-specific basis to ensure that the aging

effect is adequately managed. The staff reviewed the applicant’s proposed programs to ensure

that an adequate program will be in place for the management of general corrosion of these

components.

The applicant indicated in LRA Table 3.2-1, Item 2, that the VCSNS containment spray system

is made of stainless steel, rather than carbon steel, and, therefore, is not covered by GALL. 

Four systems at VCSNS have been identified whose only license renewal function is to provide

containment isolation. These systems included the auxiliary coolant (closed loop)/CRDM

cooling water (AC), demineralized water—nuclear service (DN), reactor building leak rate

testing (LR), and nitrogen blanketing (NG). Among them, the AC, LR, and NG systems contain

carbon steel components that are in scope. The applicant stated that the Inspections for

Mechanical Components Program (LRA Appendix B.2.11) is credited for detecting and

managing the loss of material due to general corrosion on the external surfaces of carbon steel

components. The air-gas environments inside LR and NG components do not contain

contaminants of sufficient concentration to cause general corrosion severe enough to warrant

managing. The Chemistry Program (LRA Appendix B.1.4) is credited with providing aging

management of corrosion of the interior of AC system components. Consistent with the GALL

Report, this group contains carbon steel in ambient air and treated water environments. 

Additionally, compressed gas is also included in this group. The staff evaluation of the

Chemistry Program and the Inspections for Mechanical Components Program is documented in

Sections 3.0.3.2 and 3.0.3.7, respectively, of this SER.

The staff reviewed the applicant’s proposed programs and concludes that, based on the

program descriptions of LRA Appendix B.1.4 and Appendix B.2.11, general corrosion is not

occurring and the component intended functions will be maintained during the period of

extended operation. The staff verified that the applicant’s AMPs are sufficient to manage the

identified aging effect of loss of material due to general corrosion.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general corrosion, as

recommended in the GALL Report. Since the applicant’s AMR results are otherwise consistent

with the GALL report, the staff finds 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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3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion

Local loss of material from pitting and crevice corrosion could occur in containment spray

components, containment isolation valves and associated piping, and buried portions of the

refueling water tank external surface. The GALL Report recommends further evaluation to

ensure that the aging effect is adequately managed. The staff reviewed the applicant’s

proposed programs to ensure that an adequate program will be in place for the management of

local loss of material due to pitting and crevice corrosion of these components.

In LRA Table 3.2-1, Item 3, the applicant stated that this group contains the refueling water

storage tank and systems whose only license renewal function is to provide containment

isolation. The four systems identified to provide the containment isolation function are AC, DN,

LR and NG. The Inspections for Mechanical Components Program is credited for detecting and

managing the loss of material due to pitting, crevice, and galvanic corrosion on the surfaces of

carbon steel components. As in Section 3.2.2.2.2 of this SER, the Chemistry Program is

credited with providing aging management of corrosion of the interior of AC and DN system

components. The staff evaluation of the Chemistry Program and the Inspections for

Mechanical Components Program is documented in Sections 3.0.3.2 and 3.0.3.7, respectively,

of this SER. 

Based on its review of LRA Appendix B.1.4 and Appendix B.2.11, the staff finds that pitting and

crevice corrosion is not occurring and that the component intended functions will be maintained

during the period of extended operation. The staff verified that the applicant’s AMPs are

sufficient to manage the identified aging effect of loss of material due to pitting and crevice

corrosion.

In LRA Table 3.2-1, Item 3, the applicant stated that loss of material of the underside of the

RWST is not an aging effect requiring management because this stainless steel tank is not

buried. In RAI 3.2-1, the staff requested the applicant to discuss the potential corrosive

environments surrounding the tank bottom, and justify its determination that there are no aging

effects requiring management. By letter dated June 12, 2003, the applicant stated that the 1 in.

stainless steel RWST bottom at VCSNS sits on an outdoor raised concrete foundation that

ensures that the tank bottom is not subjected to flowing water. The applicant stated that

VCSNS is located well inland and does not see salt or other corrosive materials in the air. The

stainless steel tank bottom is in a low temperature (less than 140 F) environment similar to

stainless steel embedded in concrete. This environment has been determined not to have

aging effects requiring management. Based on the environments presented by the applicant

and the general industry experience, the staff finds the applicant’s AMR evaluation to be

acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the local loss of material due to pitting and crevice corrosion,

as recommended in the GALL Report. Since the applicant’s AMR results are otherwise

consistent with the GALL report, the staff finds 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).

3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced Corrosion
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Local loss of material due to MIC could occur in 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. The staff reviewed the applicant’s proposed programs to ensure that an adequate

program will be in place for the management of local loss of material due to MIC of the

containment isolation barriers.

In LRA Table 3.2-1, Item 4, the applicant stated that MIC is not a valid aging mechanism for the

material/environment combination represented by the containment isolation valves and

associated piping. The applicant stated that this aging mechanism is not applicable since the

four systems (AC, DN, LR, NG) which provide containment isolation are not subject to wetting

from raw water. In RAI 3.2-2, the staff requested the applicant to provide details of the physical

environments that are associated with the containment isolation valves and associated piping,

for each of the four systems, and justify that these components are not susceptible to loss of

material due to MIC. By letter dated June 12, 2003, the applicant stated that, with the exception

of the reactor building equipment hatch, the reactor building penetrations at VCSNS are located

indoors. The containment isolation systems contain either treated water or air/gas. AC is a

treated water cooling water system. DN contains demineralized water. LR and NG contain

air/gas. The in-scope portions of these systems are in a sheltered environment and are not

exposed to rain or raw water. Therefore, loss of material due to MIC is not a valid aging effect

for the in-scope portion of these systems. The staff finds the applicant’s response to be

adequate in justifying that MIC is not a valid aging mechanism for the above containment

isolation components. Therefore, no AMP is required. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of material due to MIC, as recommended in the GALL

Report. Since the applicant’s AMR results are otherwise consistent with the GALL report, the

staff finds 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).

3.2.2.2.5 Local Loss of Material Due to Erosion

Local loss of material due to erosion could occur in the high pressure safety injection pump

miniflow orifice. This aging mechanism and effect will apply only to pumps that are normally

used as charging pumps in the chemical and volume control systems. The GALL Report

recommends further evaluation to ensure that the aging effect is adequately managed for these

components. The staff reviewed the applicant’s proposed programs to ensure that an adequate

program will be in place to manage this aging effect.

The identified GALL item for high pressure safety injection (charging) pump mini flow orifices

recommends a plant-specific evaluation of the credited program. The applicant stated in LRA

Table 3.2-1, Item 5, that VCSNS considers this aging effect/mechanism a design problem, and

does not have an identified AMP for the erosion of mini flow orifices. In RAI 3.2-4, the staff

requested the applicant to elaborate on this stated design problem. By letter dated June 12,

2003, the applicant stated that the VCSNS high pressure safety injection pump (charging

pump) mini flow orifices are made of stainless steel stock with a drilled hole approximately

12 in. long. The applicant stated that this design will be capable of preventing erosion from

becoming an aging concern that requires evaluation for the orifices. Based on the plantspecific design of the high pressure safety injection (charging) pump mini flow orifices, the staff
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finds the orifices not to be susceptible to significant loss of material due to erosion. Therefore,

no AMP is required. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of material due to erosion, as recommended in the GALL

Report. Since the applicant’s AMR results are otherwise consistent with the GALL report, the

staff finds 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).

3.2.2.2.6 Loss of Material Due to General Corrosion

Loss of material due to general corrosion could occur in the external surfaces of carbon steel

pipes and fittings, primary containment penetrations, and valve bodies of the containment

penetrations and system interface system. This component type is only found in Table 2 of

GALL (NUREG-1801, Volume 1). It is not found in Table 3.2-1 of The SRP-LR (NUREG-1800). 

The GALL Report recommends further evaluation on a plant-specific basis to ensure that loss

of material is adequately managed for these components. The staff reviewed the applicant’s

proposed programs to ensure that an adequate program will be in place for the management of

general corrosion of these components.

In LRA Table 3.2-1, Item 6, the applicant stated that for the external surface of carbon steel

components at VCSNS, the AMR results are consistent with GALL in material, environment,

aging effect, and credited program. In addition to carbon steel, VCSNS has included cast iron

in this group. The applicant credited the Inspections for Mechanical Components Program

(Appendix B.2.11) for managing the aging effect of loss of material due to general corrosion for

the above carbon steel components. The staff evaluation of this AMP is documented in Section

3.0.3.7 of this SER.

The staff reviewed the applicant’s Inspections for Mechanical Components Program to ensure

that corrosion is not occurring and that the component intended function will be maintained

during the period of extended operation. The staff verified that the applicant’s AMP is sufficient

to manage the identified aging effect of loss of material due to general corrosion. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of material due to general corrosion, as recommended in

the GALL Report. Since the applicant’s AMR results are otherwise consistent with the GALL

report, the staff finds 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).

3.2.2.3 Aging Management Programs for Engineered Safety Features Systems Components

In SER Section 3.2.2.1, the staff evaluated the applicant’s conformance with the aging

management recommended by GALL for ESF systems. In SER Section 3.2.2.2, the staff

reviewed the applicant’s evaluation of the issues for which GALL recommends further

evaluation. In this SER section, the staff presents its evaluation of the programs used by the

applicant to manage the aging of the component groups within the ESF systems.

The applicant credits five AMPs to manage the aging effects associated with components in the

ESF systems. All five AMPs are credited to manage aging for components in other system
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groups (common AMPs). The staff’s evaluation of the common AMPs that are credited with

managing aging in ESF system components is provided in Section 3.0.3 of this SER. The

common AMPs credited for ESF components are as follows:

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Chemistry Program (3.0.3.2)

• Above Ground Tank Inspection Program (3.0.3.5)

• Inspection for Mechanical Components Program (3.0.3.7)

• Heat Exchanger Inspections Program (3.0.3.8)

There are no AMPs that are specific to ESF systems.

3.2.2.4 Aging Management Review of Plant-Specific Engineered Safety Features Systems

Components

In this section of the SER, the staff presents its review of the applicant’s AMR for specific

components within the ESF systems. To perform its evaluation, the staff reviewed the

components listed in LRA Tables 2.3-8 through 2.3-17 to determine whether the applicant had

properly identified the applicable aging effects and the AMPs needed to adequately manage

these aging effects. This portion of the staff’s review involved identification of the aging effects

for each ESF component, ensuring that each aging effect was evaluated in the appropriate LRA

AMR Table in Section 3, and that management of the aging effect was captured in the

appropriate AMP. The results of the staff’s review are provided in the sections that follow. 

3.2.2.4.1 Chemical and Volume Control System

Summary of Technical Information in the Application

The description of the chemical and volume control system can be found in Section 2.3.2.1 of

this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-8. The components, aging effects, and AMPs are provided in LRA

Tables 3.2-1 and 3.2-2.

Aging Effects:

Components of the chemical and volume control system are described in LRA Section 2.3.2.1

as being within the scope of license renewal and subject to an AMR. Table 2.3-8 of the LRA

lists individual components of the system, including agitators and mixers, demineralizers, filters,

flexible couplings, gearboxes, heat exchanger (channel head), heat exchangers (shell), heat

exchanger (tubes), heat exchanger (tubesheet), instrumentation (pressure retaining only), oil

reservoir, orifices, pipe, pumps (bearing houses), pump (casing only), tanks, tube and tube

fittings, and valves (body only).

Stainless steel components are identified as being subject to loss of material due to crevice

corrosion, pitting corrosion, and cracking due to SCC in borated or treated water environments. 

No aging effects are identified for stainless steel components in sheltered, reactor building,

ventilation, or lube oil environments. 
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Carbon steel components are identified as being subject to loss of material due to boric acid

corrosion (aggressive chemical attack) in sheltered or reactor building environments. Carbon

steel components are identified as being subject to loss of material due to general corrosion in

sheltered or reactor building environments. Carbon steel components are identified as being

subject to loss of material due to crevice, galvanic, general, and pitting corrosion in treated

water environments. No aging effects are identified for carbon steel components in lube oil

environments. 

Cast iron components are identified as being subject to loss of material due to general

corrosion in sheltered environments. Cast iron components are identified as being subject to

loss of material due to boric acid corrosion (aggressive chemical attack) in sheltered

environments. No aging effects are identified for cast iron components in lube oil

environments.

Copper-nickel components are identified as being subject to loss of material due to crevice,

pitting, and galvanic corrosion, and erosion-corrosion. Copper components are identified as

being subject to loss of material due to boric acid corrosion (aggressive chemical attack) in

sheltered environments. No aging effects are identified for copper or copper-nickel

components in lube oil environments.

No aging effects are identified for glass components in lube oil or sheltered environments.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the chemical and volume control

system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Inspection for Mechanical Components Program

• Heat Exchanger Inspections Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant states that

the effects of aging associated with the components of the chemical and volume control system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3-8, 3.2-1, and 3.2-2 for the chemical and

volume control system. During its review, the staff determined that additional information was

needed.

In LRA Table 3.2-2, Item 1, the applicant stated that sheltered environments do not contain

contaminants of sufficient concentration to cause aging effects requiring management. In RAI

3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management. By letter dated June 12, 2003, the applicant stated that
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VCSNS is located well inland and is in an area where forestry is the prime commercial activity. 

VCSNS does not see salt or other corrosive materials in the air from agriculture or industry. 

Samples of ground water and rainwater show chloride and sulfate concentrations less than

10 parts per million (ppm). Based on this insignificant concentration of chloride and sulfate in

the air environment, and the fact that industry experiences identified no aging effects requiring

management for the external surface of stainless steel components in a gas environment, the

staff finds the applicant’s evaluation presented in LRA Table 3.2-2, Item 1, to be acceptable. 

In RAI 3.2-4, the staff requested the applicant to provide its plant-specific design information of

the high pressure safety injection pump mini flow orifice, included in LRA Table 3.2-1, Item 5,

and the procedure in place to resolve the design problem involving loss of material due to

erosion. The staff’s discussion of this RAI and its resolution by the applicant is provided in

Section 3.2.2.2.5 of this SER.

In LRA Table B-1, the applicant stated that the Bolting Integrity Program of GALL (XI.M18) is

not credited for aging management. In LRA Tables 2.3-8 through 2.3-17, the applicant did not

list closure bolting for the ESF systems as a separate component type requiring AMR review.

Also, in Table 3.2-1, Item 12, the applicant stated that loss of mechanical closure integrity is not

considered an aging effect requiring evaluation for non-Class 1 component bolted closures. 

The applicant further stated that the bolting/fasteners within the scope of license renewal were

not itemized as a separate non-Class 1 component/component type. Rather, the bolting was

treated as a subcomponent/subpart of non-Class 1 components/component types. In RAI 3.2-

6, the staff requested the applicant to provide the basis for not considering loss of mechanical

closure integrity an aging effect, and to discuss the plant-specific AMR of closure bolting, in

reference to the intent of GALL XI.M18, “Bolting Integrity.” By letter dated June 12, 2003, the

applicant stated that, for all non-Class 1 bolted closures (i.e., pressure retaining) of

components/component types subject to AMR, the design of critical closure joint bolting

involves enough redundancy to ensure joint integrity. Therefore, no aging effects unique to

bolting, over the components being joined/closed, require evaluation for license renewal, as

discussed below. 

The applicant stated that mechanical components within the scope of license renewal, both

Class 1 and non-Class 1, contain bolted closures that are necessary for the pressure boundary

of the components being joined/closed. These bolted closures, which are composed of two

mating surfaces, a gasket, and a fastener set, form an integral part of the pressure-retaining

boundary of the components. Additionally, the bolted closure is exposed to the same

environment(s) as the components in the plant areas where the closure is located (process fluid

for internal mating surface and ambient conditions else). As such, the bolted closure (including

fastener set) was considered to be a subcomponent of the components/component types within

the scope of license renewal and, except as clarified, did not require evaluation separate from

the component. 

The applicant stated that loss of mechanical closure integrity, which can result in failure of the

mechanical joint, is evidenced by leakage rather than joint failure, and can be attributed to one

or more of the following effects:

• loss of bolt preload (embedment, cyclic load embedment, gasket creep, etc.)

• loss of bolting material (from general and/or boric acid corrosion) 

• reduction of bolting material fracture toughness 
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• cracking of high-strength bolting material (SCC)

The applicant stated that for non-Class 1 bolted closures, loss of preload was considered to be

the result of inadequate design or improper assembly (i.e., event-driven) that is not related to

aging and that would manifest itself during the current operating term and be corrected prior to

the period of extended operation. Thus, the mechanisms associated with loss of bolting preload are not a license renewal concern for non-Class 1 components/component types. 

It is recognized that loss of bolting material could ultimately result in the loss of a component’s

pressure boundary integrity and, thus, requires evaluation for license renewal. The applicant

stated, however, that loss of material is an aging effect requiring license renewal evaluation for

carbon and alloy steel components/component types subject to AMR. As such, no evaluation,

separate from the subject components/component types of which bolted closures are a part, is

necessary and, for carbon and alloy steel components/component types, the AMPs credited for

managing external general corrosion will also inherently address their fasteners. 

The applicant stated that loss of material due to boric acid wastage (aggressive chemical

attack) is the most common aging effect that has been observed in the industry for ferrite

fasteners. In the concentrations used in PWR systems, boric acid is a relatively weak acid. 

However, under wetting and drying conditions, such as a result of leakage, boric acid may

concentrate in slurry forming a saturated solution. Stainless steel fasteners have been shown

not to be susceptible to loss of material due to boric acid wastage, however. The appropriate

program/activities credited for management of the external aging of carbon and low-alloy steel

in locations susceptible to leaking borated water will also address carbon and low-alloy steel

fasteners in that location. Additionally, the applicant noted that AMPs credited for addressing

boric acid wastage will also inherently address any general corrosion concerns for carbon or

low-alloy steel bolting of stainless steel components/component types.

The applicant stated that reduction of fracture toughness of bolting material due to

thermal/neutron effects is a license renewal concern for the fasteners of components because

of elevated system operating temperatures and proximity to the reactor vessel beltline region. 

This is applicable to bolting of some Class 1 components and is addressed in the application. 

Reduction of fracture toughness for non-Class 1 bolting material is not a license renewal aging

effect requiring management for the fasteners of components.

Regarding the SCC of bolting materials, the applicant stated that, although there have been a

few instances of cracking of bolting in the industry due to SCC, these have been attributed to

high yield strength materials and contaminants, such as the use of lubricants containing MoS2 . 

VCSNS does not use lubricants containing MoS2 and, in general, environmental conditions that

could lead to SCC of bolting are not expected to occur in non-Class 1 components. For

quenched and tempered low-alloy steels used for closure bolting (e.g., ASTM A193 Grade B7),

material susceptibility to SCC is minimized by having a lower yield strength. EPRI Report NP5769 (Volume I, page 11-5) indicates that SCC should not be a concern for closure bolting in

nuclear power plant applications if the specified yield strength is below 150 ksi. The

specification for the fabrication of nuclear piping specifies alloy steel ASTM A193, Grade B7

bolts/studs and ASTM A194, Grade 2H nuts, which have minimum yield strengths below 150 ksi

(105 ksi). In addition to the use of appropriate material as stated above, sound maintenance

bolt torquing practices can control bolting material stresses and help reduce the potential for

SCC to occur. The applicant stated that a review of industry failure databases and NRC
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generic communications supports the fact that proper material selection, proper maintenance

and torquing procedures, and removal of contaminants from lubricants have been effective in

eliminating the potential for SCC of bolting materials. Therefore, SCC of bolting materials is not

an aging effect requiring evaluation for license renewal for non-Class 1 components/component

types.

The staff has reviewed the applicant’s response as presented in its letter of June 12, 2003, and

finds that the applicant has adequately addressed all the issues raised by the staff in RAI 3.2-6.

Specifically, the staff finds that the applicant has adequately explained that the aging

effects/mechanisms of the bolted closure can be evaluated as a part of the aging effects/

mechanisms of the components to which it connects because of the similarity of the exposed

environments. The applicant also adequately explained that loss of mechanical closure integrity

is not an aging effect requiring evaluation for non-Class 1 component bolted closures because

the creditable attributes which could potentially lead to joint leakage (such as loss of bolt

preload, loss of bolting material, reduction of bolting material fracture toughness, and cracking

of high-strength bolting material (SCC)) are not considered aging effects/ mechanisms requiring

evaluation for license renewal for non-Class 1 components/component types of ESF systems. 

Based on the above, the staff finds the applicant’s response to be acceptable. 

The aging effects identified in the LRA for the components in the chemical and volume control

system are consistent with industry operating experience for the materials and environments

listed. The staff finds that all the plausible aging effects were identified and that the aging

effects listed are appropriate for the combination of materials and environment specified.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the chemical and

volume control system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Inspections for Mechanical Components Program

• Heat Exchanger Inspections Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, 3.0.3.7, and 3.0.3.8, respectively, of this SER.

In LRA Table 3.3-1, Item 8, relative to stainless steel heat exchangers in the chemical and

volume control system, the applicant stated that the Water Chemistry Program is credited for

managing the aging effect of crack initiation and growth due to SCC. The applicant stated that

the Chemistry Program has been in effect since initial plant startup and has proven effective in

maintaining system chemistry and in detecting abnormal conditions. A review of the operating

experience also confirms its effectiveness in managing aging effects. The applicant stated,

therefore, that a verification program, as recommended by GALL, is not warranted for these

components/component types. The staff finds the applicant’s statement to be acceptable. This

determination is based on the successful operating experience of these heat exchangers, the
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effectiveness of the Chemistry Program in maintaining system chemistry (such as oxygen,

chlorides, fluorides, and/or sulfates), and the fact that heat exchangers in the chemical and

volume control system are always in a fluid-solid (filled and vented) condition during normal

operation. Therefore, loss of material and cracking need not be considered as aging effects

requiring management due to the corrosive impacts of alternate wetting and drying for stainless

steel components exposed to borated water and treated water environments. 

After evaluating the applicant’s AMR for each of the components in the chemical and volume

control system, the staff evaluated the AMPs listed above to determine if they are appropriate

for managing the identified aging effects. For those components identified in Table 3.2-1 of the

LRA, the staff verified that the applicant credited the AMP recommended by the GALL Report. 

For the components identified in LRA Table 3.2-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

of the chemical and volume control system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2.2.4.2 Containment Isolation System

Summary of Technical Information in the Application

The description of the containment isolation system can be found in Section 2.3.2.2 of this

SER. Four systems at VCSNS have been identified whose only mechanical license renewal

function is to provide containment isolation. These four systems include the following:

• auxiliary coolant (closed loop)/CRDM cooling water system 

• demineralized water—nuclear service system 

• reactor building leak rate testing system 

• nitrogen blanketing system 

 

The passive, long-lived components in the containment isolation system that are subject to an

AMR are identified in LRA Tables 2.3-9 through 2.3-12. The components, aging effects, and

AMPs are provided in LRA Tables 3.2-1 and 3.2-2.

Aging Effects:

Components of the containment isolation system are described in LRA Section 2.3.2.2 as being

within the scope of licence renewal and subject to an AMR. Tables 2.3-9 through 2.3-12 of the

LRA list individual components of the system including pipe and valves (body only).
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Stainless steel components are identified as being subject to loss of material due to crevice and

pitting corrosion in treated water environments. No aging effects are identified for stainless

steel components in reactor building or sheltered environments.

Carbon steel components are identified as being subject to loss of material due to general

corrosion in reactor building or sheltered environments. Carbon steel components are identified

as being subject to loss of material due to crevice, galvanic, general, and pitting corrosion in

treated water environments. Carbon steel components are identified as being subject to loss of

material due to boric acid corrosion (aggressive chemical attack) in reactor or sheltered

environments. No aging effects are identified for carbon steel components in air-gas (dry) or

ventilation environments.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the containment isolation system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program 

• Inspections for Mechanical Components Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the containment isolation system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3.9 through 2.3.12, 3.2-1, and 3.2-2 for the

containment isolation system. During its review, the staff determined that additional information

was needed.

In RAI 3.2-1, the staff requested the applicant to discuss the potential corrosive environments

surrounding the RWST bottom, as stated in LRA Table 3.2-1, Item 3, and justify its

determination that there are no aging effects requiring management. The staff discussion of

this RAI and its resolution by the applicant is provided in Section 3.2.2.2.3 of this SER.

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1 of this SER.

The aging effects identified in the LRA for the components in the containment isolation system

are consistent with industry operating experience for the materials and environments listed. 

The staff finds that all the plausible aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Program:
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The applicant credited the following AMPs for managing the aging effects in the containment

isolation system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program 

• Inspections for Mechanical Components Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, and 3.0.3.7, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the containment isolation

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects. For those components identified in Table 3.2-1 of the

LRA, the staff verified that the applicant credited the AMP recommended by the GALL Report. 

For the components identified in LRA Table 3.2-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

of the containment isolation system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2.2.4.3 Hydrogen Removal — Post Accident System

Summary of Technical Information in the Application

The description of the hydrogen removal—post accident system can be found in Section 2.3.2.3

of this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-13. The components, aging effects, and AMPs are provided in LRA

Tables 3.2-1 and 3.2-2.

Aging Effects:

Components of the hydrogen removal — post accident system are described in LRA Section

2.3.2.3 as being within the scope of license renewal and subject to an AMR. Table 2.3-13 of

the LRA lists individual components of the system including hydrogen recombiners (electric),

pipe, tubing, and valves (body only).

Carbon steel components are identified as being subject to loss of material due to general

corrosion in sheltered or reactor building environments. Carbon steel components are identified
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as being subject to loss of material due to boric acid corrosion (aggressive chemical attack) in

reactor building or sheltered environments. No aging effects are identified for carbon steel

components in air-gas (dry) environments. 

No aging effects are identified for stainless steel components in reactor building, sheltered, or

air-gas (dry) environments. No aging effects are identified for nickel-based alloys (Inconel 600

and Incoloy 800) in reactor building environments. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the hydrogen removal—post

accident system:

• Boric Acid Corrosion Surveillances Program

• Inspections for Mechanical Components Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the hydrogen removal—post

accident system will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3.13, 3.2-1, and 3.2-2 for the hydrogen

removal—post accident system. During its review, the staff determined that additional

information was needed.

In RAI 3.2-1, the staff requested the applicant to discuss the potential corrosive environments

surrounding the RWST bottom, as stated in LRA Table 3.2-1, Item 3, and justify its

determination that there are no aging effects requiring management. The staff’s discussion of

this RAI and its resolution by the applicant is provided in Section 3.2.2.2.3 of this SER.

In RAI 3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management, as stated in LRA Table 3.2-2, Item 1. The staff’s

discussion of this RAI and its resolution by the applicant is provided in Section 3.2.2.4.1 of this

SER. 

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1 of this SER.

The aging effects identified in the LRA for the components in the hydrogen removal—post

accident system are consistent with industry operating experience for the materials and

environments listed. The staff finds that all the plausible aging effects were identified and that
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the aging effects listed are appropriate for the combination of materials and environments

specified.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the hydrogen

removal—post accident system:

• Boric Acid Corrosion Surveillances Program

• Inspections for Mechanical Components Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1 and 3.0.3.7, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the hydrogen

removal—post accident system, the staff evaluated the AMPs listed above to determine if they

are appropriate for managing the identified aging effects. For those components identified in

Table 3.2-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report. For the components identified in LRA Table 3.2-2, the staff verified that the

applicant credited an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the hydrogen

removal — post accident system components will effectively manage or monitor the aging

effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2.2.4.4 Reactor Building Spray System

Summary of Technical Information in the Application

The description of the reactor building spray system can be found in Section 2.3.2.4 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-14. The components, aging effects, and AMPs are provided in LRA

Tables 3.2-1 and 3.2-2.

Aging Effects:

Components of the reactor building spray system are described in LRA Section 2.3.2.4 as being

within the scope of licence renewal and subject to an AMR. Table 2.3-14 of the LRA lists
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individual components of the system including orifices, pipe, pumps (casing only), spray

nozzles, tank, tube and tube fitting, and valves (body only).

Stainless steel components are identified as being subject to loss of material due to crevice and

pitting corrosion and cracking due to SCC in borated or treated water environments. No aging

effects are identified for stainless steel components in reactor building, sheltered, ventilation, or

yard environments. 

Carbon steel components are identified as being subject to loss of material due to general

corrosion in sheltered environments. Carbon steel components are identified as being subject

to loss of material due to boric acid corrosion (aggressive chemical attack) in sheltered

environments. Carbon steel components are identified as being subject to loss of material due

to general corrosion in yard environments. Carbon steel components are identified as being

subject to loss of material due to crevice, galvanic, general, and pitting corrosion in treated

water environments. No aging effects are identified for carbon steel components in air-gas

environments.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the reactor building spray system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Above Ground Tank Inspection Program

• Inspections for Mechanical Components Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the reactor building spray system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3-14, 3.2-1, and 3.2-2 for the reactor

building spray system. During its review, the staff determined that additional information was

needed.

In RAI 3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management, as stated in LRA Table 3.2-2, Item 1. The staff’s

discussion of this RAI and its resolution by the applicant is provided in Section 3.2.2.4.1 of this

SER.

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1 of this SER.
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The aging effects identified in the LRA for the components in the reactor building spray system

are consistent with industry operating experience for the materials and environments listed. 

The staff finds that all the plausible aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified. 

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the reactor building

spray system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program 

• Above Ground Tank Inspection Program

• Inspections for Mechanical Components Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, 3.0.3.5, and 3.0.3.7, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the reactor building spray

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects. For those components identified in Table 3.2-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report. 

For the components identified in LRA Table 3.2-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

of the reactor building spray system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2.2.4.5 Refueling Water System

Summary of Technical Information in the Application

The description of the refueling water system can be found in Section 2.3.2.5 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-15. The components, aging effects, and AMPs are provided in LRA Tables 3.2-1 and

3.2-2.

Aging Effects:
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Components of the refueling water system are described in LRA Section 2.3.2.5 as being within

the scope of licence renewal and subject to an AMR. Table 2.3-15 of the LRA lists individual

components of the system, including pipe and tanks. 

Stainless steel components or components with stainless steel cladding are identified as being

subject to crack initiation and growth due to SCC in a treated water environment. The stainless

steel RWST (including attached piping) is identified as being subject to loss of material due to

crevice and pitting corrosion and cracking due to the corrosive impacts of alternate wetting and

drying in treated water environments. No aging effects are identified for stainless steel

components in air-gas environments. 

Aging Management Programs:

The following AMPs are utilized to manage the aging effects in the refueling water system:

• Chemistry Program

• Above Ground Tank Inspection Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant states that

the effects of aging associated with the components of the refueling water system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3-15, 3.2-1, and 3.2-2 for the refueling

water system. During its review, the staff determined that additional information was needed.

In RAI 3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management, as stated in LRA Table 3.2-2, Item 1. The staff’s

discussion of this RAI and its resolution by the applicant is provided in Section 3.2.2.4.1 of this

SER.

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1.2 of this SER.

The aging effects identified in the LRA for the components in the refueling water system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:
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The applicant credited the following AMPs for managing the aging effects in the refueling water

system:

• Chemistry Program 

• Above Ground Tank Inspection Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections 

3.0.3.2 and 3.0.3.5, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the refueling water system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.2-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP

that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

of the refueling water system will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.2.2.4.6 Residual Heat Removal System

Summary of Technical Information in the Application

The description of the residual heat removal system can be found in Section 2.3.2.6 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-16. The components, aging effects, and AMPs are provided in LRA

Tables 3.2-1 and 3.2-2.

Aging Effects:

Components of the residual heat removal system are described in LRA Section 2.3.2.6 as being

within the scope of license renewal and subject to an AMR. Table 2.3-16 of the LRA lists

individual components of the system including heat exchangers (channel head), heat

exchangers (shell), heat exchangers (tubes), heat exchangers (tubesheet), orifices, pipe,

pumps (casing only), tube and tube fitting, and valves (body only). 

Stainless steel components are identified as being subject to loss of material due to crevice and

pitting corrosion and cracking due to SCC in borated water environments. Stainless steel
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components are identified as being subject to loss of material due to crevice and pitting

corrosion in treated water environments. No aging effects are identified for stainless steel

components in sheltered or reactor building environments.

Carbon steel components are identified as being subject to loss of material due to general

corrosion in sheltered environments. Carbon steel components are identified as being subject

to loss of material due to boric acid corrosion (aggressive chemical attack) in an environment

with dripping of chemically treated borated water. Carbon steel components are identified as

being subject to loss of material due to crevice, galvanic, general and pitting corrosion in

treated water environments. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the residual heat removal system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Inspections for Mechanical Components Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant states that

the effects of aging associated with the components of the residual heat removal system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in LRA Tables 2.3-16, 3.2-1, and 3.2-2 for the residual heat

removal system. During its review, the staff determined that additional information was needed.

In RAI 3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management, as stated in LRA Table 3.2-2, Item 1. The staff’s

discussion of this RAI and its resolution by the applicant is provided in Section 3.2.2.4.1 of this

SER.

In LRA Table 3.2-1, Item 9, the applicant stated that, for components serviced by the closedcycle cooling system, the Chemistry Program (LRA Appendix B.1.4) has proven effective in

maintaining the system’s chemistry and detecting abnormal conditions. The applicant also

stated that a review of operating experience confirms the effectiveness of the Chemistry

Program to manage aging effects when continued into the period of extended operation. The

applicant, therefore, concluded that a verification program, such as a one-time inspection, is not

warranted for the components in this component group. In RAI 3.2-5, the staff requested the

applicant to justify that, under all circumstances, the Chemistry Program will be sufficient to

manage the aging effects associated with the components. By letter dated June 12, 2003, the

applicant stated that LRA Table 3.2-1, Item 9, includes only the residual heat removal (RHR)

heat exchanger and the RHR pump seal cooler. Both of these components have reactor

coolant cooled by the component cooling system. The applicant stated that review of the

VCSNS operating experience reviews have not found a reason to require a one time inspection
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of these stainless steel RHR components in a borated water (RCS) environment. In addition,

the applicant stated that the treated water environment of these components contains corrosion

inhibitors whose function is to form a passivated layer that prohibits corrosion from forming. 

The applicant stated, therefore, that it is not necessary to schedule one-time inspections for the

RHR heat exchangers and RHR seal coolers. The staff finds that applicant’s response

adequately justifies the effectiveness of the Chemistry Program. This determination is based

on the successful operating experience of these RHR components, the GALL guidance that the

effects of pitting and crevice corrosion on stainless steel components are not significant in

chemically treated borated water (GALL Section VII.E1), and the use of corrosion inhibitors

which prohibits the occurrence of corrosion on these RHR components. 

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1 of this SER.

The aging effects identified in the LRA for the components in the residual heat removal system

are consistent with industry operating experience for the materials and environments listed. 

The staff finds that all the plausible aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the residual heat

removal system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Inspections for Mechanical Components Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, and 3.0.3.7, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the residual heat removal

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects. For those components identified in Table 3.2-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report. 

For the components identified in LRA Table 3.2-2, the staff verified that the applicant credited

an AMP that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

of the residual heat removal system will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions
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On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3). 

3.2.2.4.7 Safety Injection System

Summary of Technical Information in the Application

The description of the safety injection system can be found in Section 2.3.2.7 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-17. The components, aging effects, and AMPs are provided in LRA Tables 3.2-1 and

3.2-2.

Aging Effects:

Components of the safety injection system are described in LRA Section 2.3.2.7 as being within

the scope of license renewal and subject to an AMR. Table 2.3-17 of the LRA lists individual

components of the system including orifices, pipe, tanks, tube and tube fittings, and valves

(body only). 

Stainless steel components are identified as being subject to crevice and pitting corrosion and

SCC in borated water environments. No aging effects are identified for stainless steel

components in reactor building, sheltered, air-gas, or demineralized/deaerated water (i.e.,

treated water with absence of oxygen) environments. 

Carbon steel components are identified as being subject to loss of material due to general

corrosion in sheltered or reactor building environments. Carbon steel components are identified

as being subject to loss of material due to boric acid corrosion (aggressive chemical attack) in

sheltered or reactor building environments. No aging effects are identified for carbon steel

components in air-gas (dry) environments.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the safety injection system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program

• Inspections for Mechanical Components Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the safety injection system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:
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The staff reviewed the information in LRA Tables 2.3-17, 3.2-1, and 3.2-2 for the safety

injection system. During its review, the staff determined that additional information was

needed.

In RAI 3.2-3, the staff requested the applicant to provide the basis, for all potential sheltered

environments in the ESF systems, that stainless steel components are not susceptible to any

aging effects requiring management, as stated in LRA Table 3.2-2, Item 1. The staff’s

discussion of this RAI and its resolution by the applicant is provided in Section 3.2.2.4.1 of this

SER.

In RAI 3.2-6, the staff requested the applicant to provide the basis for not considering loss of

mechanical closure integrity an aging effect (as stated in LRA Table 3.2-1, Item 12), and to

discuss the plant-specific AMR of closure bolting, in reference to the intent of GALL XI.M18,

“Bolting Integrity.” The staff’s discussion of this RAI and its resolution by the applicant is

provided in Section 3.2.2.4.1 of this SER.

The aging effects identified in the LRA for the components in the safety injection system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the safety injection

system:

• Boric Acid Corrosion Surveillances Program

• Chemistry Program 

• Inspections for Mechanical Components Program

These AMPs are credited for managing the aging effects of several components in other

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, and 3.0.3.7, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the safety injection system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects. For those components identified in Table 3.2-1 of the LRA, the staff

verified that the applicant credited the AMPs recommended by the GALL Report. For the

components identified in LRA Table 3.2-2, the staff verified that the applicant credited an AMP

that is appropriate for the identified aging effects.

On the basis of its review, the staff finds that AMPs credited in the LRA for the components of

the safety injection system will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions
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On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section addresses the aging management of the components of the auxiliary systems

group. The systems that make up the auxiliary systems group are described in the following

SER Sections:

 air handling and local ventilation and cooling systems (2.3.3.1)

 boron recycle system (2.3.3.2)

 building services (2.3.3.3)

 chilled water system (2.3.3.4)

 circulating water system (2.3.3.5)

 component cooling water system (2.3.3.6)

 diesel generator services system (2.3.3.7)

 fire service system (2.3.3.8)

 fuel handling system (2.3.3.9)

 gaseous waste processing system (2.3.3.10)

 industrial cooler system (2.3.3.11)

 instrument air supply system (2.3.3.12)

 leak detection system (2.3.3.13)

 liquid waste processing system (2.3.3.14)

 nuclear and non-nuclear plant drains (2.3.3.15)

 nuclear sampling system (2.3.3.16)

 radiation monitoring system (2.3.3.17)

 reactor makeup water supply system (2.3.3.18)

 roof drains system (2.3.3.19)

 station service air system (2.3.3.20)

 service water system (2.3.3.21)

 spent fuel cooling system (2.3.3.22)

 thermal regeneration system (2.3.3.23)

As discussed in Section 3.0.1 of this SER, the components in each of these auxiliary systems

are included in one of two LRA tables. LRA Table 3.3-1 consists of the auxiliary system

components that are evaluated in the GALL Report and relied on for license renewal, and LRA

Table 3.3-2 consists of the auxiliary system components that are different from, or not

addressed in, the GALL Report and that are relied on for license renewal.

3.3.1 Summary of Technical Information in the Application

In LRA Section 3.3, the applicant described its AMRs for the auxiliary systems group at VCSNS. 

The description of the systems that comprise the auxiliary systems group can be found in LRA

Section 3.3. 
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The passive, long-lived components in these systems that are subject to an AMR are identified

in LRA Tables 2.3.-18 through 2.3.-37.

The applicant’s AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition reports and to

discussions with appropriate site personnel to identify aging effects that require management. 

These reviews concluded that the aging effects requiring management based on the VCSNS

operating experience were consistent with aging effects identified in GALL.

The applicant’s review of industry operating experience included a review of operating

experience through 2001. The results of this review concluded that aging effects requiring

management based on industry operating experience were consistent with aging effects

identified in GALL.

The applicant’s ongoing review of plant-specific and industry-wide operating experience is

conducted in accordance with the VCSNS Operating Experience Program.

3.3.2 Staff Evaluation

In Section 3.3 of the LRA, the applicant described its AMR for the auxiliary systems at VCSNS. 

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB throughout the period of extended

operation, in accordance with the requirements of 10 CFR 54.21(a)(3), for the auxiliary system

components that are determined to be within the scope of license renewal and subject to an

AMR. 

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of auxiliary system components for license renewal as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

applicable, and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the FSAR

supplement to ensure that it provided an adequate description of the programs credited with

managing aging for the auxiliary system components.

In LRA Section 3.3, the applicant provided brief descriptions of the auxiliary systems and

summarized the results of its AMR of the auxiliary systems at VCSNS. 

Table 3.3-1 below provides a summary of the staff’s evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.3 that are addressed in the GALL

Report.
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Table 3.3-1: Staff Evaluation Table for VCSNS Auxiliary System Components Evaluated in the GALL Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

Components in spent

fuel pool cooling and

cleanup

Loss of material due to

general, pitting, and

crevice corrosion

Water Chemistry and

One-Time Inspection

Chemistry Program Consistent with GALL.

GALL recommends

further evaluation.

(See Section 3.3.2.2.1

below.)

Linings in spent fuel

pool cooling and

cleanup system; seals

and collars in

ventilation systems

Hardening; cracking

and loss of strength

due to elastomer

degradation; loss of

material due to wear 

Plant specific Inspections for

Mechanical

Components

Program

Consistent with GALL.

GALL recommends

further evaluation.

(See Section 3.3.2.2.2

below.)

Components in load

handling, chemical

and volume control

system (PWR), and

reactor water cleanup

and shutdown cooling

systems (older BWR)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with 

10 CFR 54.21(c)

Time-Limiting

Aging Analysis 

GALL recommends

further evaluation.

(See Section 3.3.2.2.3

below.)

Heat exchangers in

reactor water cleanup

system (BWR); high

pressure pumps in

chemical and volume

control system (PWR)

Crack initiation and

growth to SCC or

cracking

Plant-specific Chemistry Program These components

are scoped under

ESF system. (See

Section 3.3.2.2.4

below.)

Components in

ventilation systems,

diesel fuel oil system,

and emergency diesel

generator systems;

external surfaces of

carbon steel

components

Loss of material due to

general, pitting, and

crevice corrosion and

MIC

Plant-specific Maintenance Rule

Structures

Program,

Preventive

Maintenance

Activities—

Ventilation

Systems

Inspections, Diesel

Generator Systems

Inspection,

Inspections for

Mechanical

Components

Program

Consistent with GALL.

GALL recommends

further evaluation.

(See Section 3.3.2.2.5

below.)

Components in

reactor coolant pump

oil collection system

of fire protection

Loss of material due to

galvanic, general,

pitting, and crevice

corrosion

Fire Protection One-Time

Inspection

Consistent with GALL. 

(See Section 3.3.2.4.8

below.)

Diesel fuel oil tanks in

diesel fuel oil system

and emergency diesel

generator system

Loss of material due to

general, pitting, and

crevice corrosion, MIC,

and biofouling

Fuel Oil Chemistry Chemistry Program Exceptions taken to

GALL on performing

one-time inspections

to verify the

effectiveness of the

Chemistry Program

under the CLB.

Piping, pump casing,

and valve body and

bonnets in shutdown

cooling system (older

BWR) 

Loss of material due to

pitting and crevice

corrosion

Water Chemistry and

One-Time Inspection

N/A BWR
Table 3.3-1: Staff Evaluation Table for VCSNS Auxiliary System Components Evaluated in the GALL Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

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Heat exchangers in

chemical and volume

control system

Crack initiation and

growth due to SCC and

cyclic loading

Water Chemistry and a

plant-specific

verification program

Chemistry Program These components

are scoped under

ESF system. (See

Section 3.3.2.2.8

below.)

Neutron absorbing

sheets in spent fuel

storage racks

Reduction of neutron

absorbing capacity and

loss of material due to

general corrosion

(Boral, boron steel)

Plant-specific N/A These components

are scoped under

structures and are

addressed in Section

3.5.2.4.2 of this SER. 

New fuel rack

assembly

Loss of material due to

general, pitting, and

crevice corrosion

Structures Monitoring N/A The applicant has

determined that the

new fuel rack

assembly at VCSNS

does not perform an

intended function and

is not within scope of

license renewal.

Spent fuel storage

racks and valves in

spent fuel pool

cooling and cleanup 

Crack initiation and

growth due to stress

corrosion cracking

Water Chemistry Chemistry Program Consistent with GALL

(See Section 3.3.2.1

below.)

Neutron absorbing

sheets in spent fuel

storage racks

Reduction of neutron

absorbing capacity due

to Boraflex degradation

Boraflex Monitoring N/A These components

are scoped under

structures and are

addressed in Section

3.5.2.4.2 of this SER.

Closure bolting and

external surfaces of

carbon steel and lowalloy steel

components

Loss of material due to

boric acid

Boric Acid Corrosion Boric Acid

Corrosion

Surveillances

Program

Consistent with GALL. 

(See Section 3.3.2.1

below.)

Components in or

serviced by closedcycle cooling water

system

Loss of material due to

general, pitting, and

MIC

Closed-Cycle Cooling

Water System

Chemistry Program Consistent with GALL. 

(See Section 3.3.2.1

below.)

Cranes, including

bridge and trolleys

and rail system, in

load handling systems

Loss of material due to

general corrosion and

wear

Inspection of Overhead

Heavy Load and Light

Load Handling systems

Materials Handling

System Inspection

Program;

Maintenance Rule

Structures

Program

These components

are scoped under

structures and are

addressed in Sections

3.5.2.4.1 and

3.5.2.4.2 of this SER.

Components in or

serviced by opencycle cooling water

systems

Loss of material due to

general, pitting, crevice,

and galvanic corrosion,

MIC, and biofouling;

build up of deposit due

to biofouling

Open-Cycle Cooling

Water System

Service Water

System Reliability

and In-service

Testing Program 

Consistent with GALL. 

(See Section 3.3.2.1

below.)
Table 3.3-1: Staff Evaluation Table for VCSNS Auxiliary System Components Evaluated in the GALL Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

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Buried piping and

fittings

Loss of material due to

general, pitting, and

crevice corrosion and

MIC

Buried Piping and

Tanks Surveillance 

or 

Buried Piping and

Tanks Inspection

Buried Piping and

Tanks Inspection

Program

Consistent with GALL.

(See Section 3.3.2.1

below.)

GALL recommends

further evaluation

Components in

compressed air

system 

Loss of material due to

general and pitting

corrosion

Compressed Air

Monitoring

Service Air System

Inspection

Consistent with GALL. 

(See Section 3.3.2.1

below.)

Components (doors

and barrier

penetration seals) and

concrete structures in

fire protection

Loss of material due to

wear; hardening and

shrinkage due to

weathering

Fire Protection Fire Protection

Program

Exceptions taken to

GALL on fire door

inspections at a

frequency of every 6

months under the

CLB, rather than the

bi-monthly frequency

recommended in

GALL. Concrete

structures and

penetration seals

consistent with GALL.

(See Section 3.0.3.3)

Components in waterbased fire protectionLoss of material due to

general, pitting, crevice,

and galvanic corrosion,

MIC, and biofouling

Fire Water System Fire Protection

Program

Consistent with

GALL/ISG. (See

Section 3.0.3.3

below.)

Components in diesel

fire system 

Loss of material due to

galvanic, general,

pitting, and crevice

corrosion

Fire Protection and

Fuel Oil Chemistry

Fire Protection

Program

Components/compon

ent type AMR results

for diesel fuel oil of

the fire service

system is included

with the diesel fuel oil

supply portions in

separate section of

Table 3.3-1 of the

LRA. As such,

NUREG-1801 items

within this group are

not considered

applicable to VCSNS. 

The

component/componen

t type AMR of diesel

driven fire pump are

included in the

appropriate portion of

Table 3.3-1 of the

LRA.
Table 3.3-1: Staff Evaluation Table for VCSNS Auxiliary System Components Evaluated in the GALL Report

Component Group Aging

Effect/Mechanism

AMP in GALL Report AMP in LRA Staff Evaluation

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Tanks in diesel fuel oil

system

Loss of material due to

general, pitting, and

crevice corrosion

Above Ground Carbon

Steel Tanks

N/A The applicant

indicated that the

corresponding fuel oil

storage tanks at

VCSNS are located

underground.

Closure bolting Loss of material due to

general corrosion;

crack initiation and

growth due to cyclic

loading and SCC

Bolting Integrity N/A The applicant has

determined that nonClass 1 closure

bolting is considered

to be a piece-part of

the components/

component types as a

whole at VCSNS.

Therefore, a bolting

integrity program is

not credited for aging

management.

Components in

contact with sodium

pentaborate solution

in standby liquid

control system (BWR)

Crack initiation and

growth due to SCC 

Water Chemistry N/A BWR

Components in

reactor water cleanup

system

Crack initiation and

growth due to SCC and

IGSCC

Reactor Water Cleanup

System Inspection 

N/A BWR

Components in

shutdown cooling

system (older BWR)

Crack initiation and

growth due to SCC

BWR Stress Corrosion

Cracking and Water

Chemistry

N/A BWR

Components in

shutdown cooling

system (older BWR)

Loss of material due to

pitting and crevice

corrosion and MIC

Closed-Cycle Cooling

Water System

N/A BWR

Components

(aluminum bronze,

brass, cast iron, cast

steel) in open-cycle

and closed-cycle

cooling water systems

and ultimate heat sink

Loss of material due to

selective leaching

Selective Leaching of

Materials

Heat Exchanger

Inspections

Program

Consistent with GALL. 

(See Section 3.3.2.1

below.)

Fire barriers, walls,

ceilings, and floors in

fire protection

Concrete cracking and

spalling due to freezethaw, aggressive

chemical attack, and

reaction with

aggregates; loss of

material due to

corrosion of embedded

steel

Fire Protection and

Structures Monitoring 

Fire Protection Consistent with GALL. 

(See Section 3.0.3.3

below.)

The staff’s review of the auxiliary systems for the VCSNS LRA is contained within four sections

of this SER. Section 3.3.2.1 is the staff review of components in the auxiliary systems that the

applicant has indicated are consistent with GALL and do not require further evaluation. Section

3.3.2.2 is the staff review of components in the auxiliary systems that the applicant has

indicated are consistent with GALL and for which GALL recommends further evaluation.
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Section 3.3.2.3 is the staff evaluation of AMPs that are specific to the auxiliary systems group. 

Section 3.3.2.4 contains an evaluation of the adequacy of aging management for components

in each system in the auxiliary systems group and includes an evaluation of components in the

auxiliary systems that the applicant indicates are not in GALL. 

3.3.2.1 Aging Management Evaluations in the GALL Report That Are Relied On for License

Renewal, That Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plant. For the AMRs of those component groups

(in LRA Table 3.3-1) which the applicant claimed to be at least partially consistent with GALL,

and for which no further evaluations are recommended, the staff evaluated the applicant’s

conformance with the aging management recommended by GALL for the auxiliary systems. 

Review results of the evaluation, for which additional information is further required from the

applicant, are discussed in Sections 3.3.2.4 and 3.3.2.5 of this SER, these sections document

the staff’s review of the applicant’s AMR for specific components within the auxiliary systems.

On the basis of its review of the inspection results, the staff has verified the applicant’s claim of

consistency with GALL report. The staff finds 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). 

3.3.2.2 Aging Management Evaluations in the GALL Report That Are Relied On for License

Renewal, For Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant’s

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation. 

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections.

3.3.2.2.1 Loss of Material Due to General, Pitting, and Crevice Corrosion

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, while loss of material due to pitting and crevice corrosion could occur in

the filter housing, valve bodies, and nozzles of the ion exchanger in the spent fuel pool cooling

and cleanup system. The Water Chemistry Program relies on monitoring and control of reactor

water chemistry based on EPRI guidelines TR-105714 for primary water chemistry in PWRs,

and TR-102134 for secondary water chemistry in PWRs, to manage the effects of loss of
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material from general, pitting, or crevice corrosion. However, high concentrations of impurities

at crevices and locations of stagnant flow conditions could cause general, pitting, or crevice

corrosion. Therefore, verification of the effectiveness of the Chemistry Control Program should

be performed to ensure that corrosion is not occurring. 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 components intended function will be maintained during the period of

extended operation.

The staff reviewed the applicant’s proposed program to ensure that corrosion is not occurring

and that the component intended functions will be maintained during the period of extended

operation. If the applicant proposed a one-time inspection of select components at susceptible

locations to ensure that corrosion is not occurring, the staff verified that the applicant’s selection

of susceptible locations is based on severity of conditions, time of service, and lowest design

margin. The staff also verified that the proposed inspection would be performed using

techniques similar to ASME Code and ASTM standards, including visual, ultrasonic, and

surface techniques.

For components listed in the “SF” system of the VCSNS Database AMR Query Table, the

applicant credited the Chemistry Program (B.1.4) for managing loss of material due to crevice,

galvanic, general, and pitting corrosion of the carbon steel heat exchanger shell component in

the spent fuel cooling system exposed to treated water environment. Control of water

chemistry may not preclude corrosion at locations of stagnant flows or crevices. It may be

necessary to perform one-time inspection at susceptible locations for verification of the

effectiveness of the Chemistry program. By letter dated March 28, 2003, the staff requested, in

RAI B.1.4-1, the applicant to address the concern pertaining to the effectiveness of the

Chemistry Program. The staff’s evaluation of this issue is documented in Section 3.0.3.2 of this

SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general, pitting, and crevice

corrosion, as recommended in the GALL Report. Since the applicant’s AMR results are other

wise consistent with the GALL report, the staff finds 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).

3.3.2.2.2 Hardening and Cracking or Loss of Strength Due to Elastomer Degradation or 

Loss of Material Due to Wear

The GALL Report recommends further evaluation of programs to manage the hardening and

cracking due to elastomer degradation of valves in the spent fuel pool cooling and cleanup

system. The GALL Report also recommends further evaluation of programs to manage the

hardening and loss of strength due to elastomer degradation of the collars and seals of the duct

and of the elastomer seals of the filters in the control room area, auxiliary and radwaste area,

and primary containment heating and ventilation system, as well as the collars and seals of the

duct in the diesel generator building ventilation system. The GALL Report also recommends

further evaluation of programs to manage the loss of material due to wear of the collars and
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seals of the ducts in the ventilation systems. The staff reviewed the applicant’s proposed

programs to ensure that an adequate program will be in place for the management of these

aging effects.

The applicant did not identify any elastomer component in the spent fuel cooling system at

VCSNS. In the VCSNS LRA (Table 3.3-1), elastomer-based components in air or gas (indoor)

are associated with the aging effects of hardening, cracking, and loss of strength due to

elastomer degradation. The applicant has identified the AMP B.2.11, Inspections for

Mechanical Components Program, to manage these aging effects. This AMP is evaluated in

Section 3.0.3.7 of this SER. The staff finds that the Inspection for Mechanical Components

Program can effectively manage the aging effects of elastomers for the above components that

are applicable to VCSNS. The applicant also adequately addressed the aging effect of loss of

material due to wear in its response to RAI 3.3.2.4.7-1 in Section 3.3.2.4.7 of this SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of hardening and cracking or loss of strength due to elastomer

degradation or loss of material due to wear, as recommended in the GALL Report. Since the

applicant’s AMR results are other wise consistent with the GALL report, the staff finds 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).

3.3.2.2.3 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in

accordance with 10 CFR 54.21(c)(1). The staff reviewed the evaluation of this TLAA in Section

4.3 of this SER, following the guidance in Section 4.3 of the SRP-LR.

3.3.2.2.4 Crack Initiation and Growth Due to Cracking or Stress-Corrosion Cracking

The GALL Report recommends further evaluation of programs to manage crack initiation and

growth due to cracking of the high pressure pump in the chemical and volume control system

(CVCS). The staff reviewed the applicant’s proposed program to ensure that an adequate

program will be in place for the management of this aging effect.

In the VCSNS LRA, the CVCS is scoped under ESF systems. The staff’s evaluation of the ESF

systems is documented in Section 3.2.2.4.1 of this SER.

3.3.2.2.5 Loss of Material Due to General, Microbiologically Influenced, Pitting, and Crevice

Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general, pitting, and crevice corrosion of (1) the piping and filter housing and supports in

the control room area, the auxiliary and radwaste area, and the primary containment heating

and ventilation systems, (2) the piping of the diesel generator building ventilation system, and

(3) the aboveground piping and fittings, valves, and pumps in the diesel fuel oil system and the

diesel engine starting air, combustion air intake, and combustion air exhaust subsystems in the

emergency diesel generator system. The GALL Report also recommends further evaluation of

programs to manage the loss of material due to general, pitting, and crevice corrosion and MIC
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of the duct fittings, access doors, closure bolts, equipment frames, and housing of the duct due

to (1) pitting and crevice corrosion of the heating/cooling coils of the air handler heating/cooling,

and (2) general corrosion of the external surfaces of all carbon steel SCs, including bolting

exposed to operating temperatures less than 212 o

F in the ventilation systems. The staff

reviewed the applicant’s proposed program to ensure that an adequate program will be in place

for the management of these aging effects.

For components in this component/commodity group, the plant specific Inspections for

Mechanical Components AMP is used to detect and manage the applicable aging effects,

including loss of material due to general and pitting corrosion and cracking on external surfaces

of mechanical components. The Maintenance Rule Structures Program is used to detect and

manage MIC caused by ground water intrusion at penetrations below elevation 425 ft. The

Preventive Maintenance Activities—Ventilation Systems Inspections AMP is a plant- specific

condition monitoring program that will in part detect and manage loss of material due to general

corrosion for ventilation system components exposed to a ventilation environment. The Diesel

Generator Systems Inspection AMP is used to detect and manage internal general corrosion in

susceptible components exposed to moist air and exhaust, such as expansion joints, piping,

and tanks. The applicant stated that the Diesel Generator Systems Inspection AMP, B.2.2, will

be enhanced to include the mufflers and exhaust piping. 

The Inspections for Mechanical Components AMP, the Maintenance Rule Structures Program,

the Preventive Maintenance Activities—Ventilation Systems Inspections AMP, and the Diesel

Generator Inspection AMP are evaluated in Sections 3.0.3.7, 3.3.0.4, 3.3.2.3.3, and 3.3.3.2.3.4

of this SER, respectively. The staff finds that these programs can effectively manage the aging

effects for external and internal surfaces of the applicable components for the auxiliary

systems.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general, pitting, and crevice

corrosion, as recommended in the GALL Report. Since the applicant’s AMR results are other

wise consistent with the GALL report, the staff finds 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).

3.3.2.2.6 Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general, galvanic, pitting, and crevice corrosion of tanks, piping, valve bodies, and tubing

in the RCP oil collection system in fire protection systems. 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 degradation is not occurring and that the component’s intended function will be

maintained during the period of extended operation. The staff reviewed the applicant’s

proposed program to ensure that corrosion is not occurring and that the component’s intended

function will be maintained during the period of extended operation (B.1.5 - Fire Protection

Program-Mechanical, GALL AMP XI.M.27) (see staff audit report dated October 9, 2003).
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On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general, galvanic, pitting, and

crevice corrosion, as recommended in the GALL Report. Since the applicant’s AMR results are

other wise consistent with the GALL report, the staff finds 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).

3.3.2.2.7 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion and Biofouling

The GALL Report recommends further evaluation of programs to manage loss of material due

to general, pitting, and crevice corrosion and MIC and due to biofouling of the internal surface

of tanks in the diesel fuel oil system, as well as general, pitting, crevice, and MIC of the tanks of

the diesel engine fuel oil system in the emergency diesel generator system. The Fuel Oil

Chemistry Program relies on monitoring and control of fuel oil contamination, in accordance

with the guidelines of ASTM Standards D4057, D1796, D2709, and D2276, to manage loss of 

material due to corrosion or biofouling. Corrosion or biofouling may occur at locations where

contaminants accumulate. Verification of the effectiveness of the Fuel Oil Chemistry Program

should be performed to ensure that corrosion/biofouling is not occurring and that the

component’s intended function will be maintained during the period of extended operation.

The staff reviewed the applicant’s proposed program to ensure that corrosion/biofouling is not

occurring and that the component intended function will be maintained during the period of

extended operation. If the applicant proposed a one-time inspection of select components at

susceptible locations to ensure that corrosion/biofouling is not occurring, the staff verified that

the applicant’s selection of susceptible locations is based on severity of conditions, time of

service, and lowest design margin. The staff also verified that the proposed inspection would

be performed using techniques similar to ASME Code and ASTM standards, including visual,

ultrasonic, and surface techniques.

In GALL, carbon steel components in fuel oil, and water (as contaminant) are associated with 

the aging effect of loss of material from general, pitting, crevice corrosion, MIC, and biofouling. 

The relevant AMPs include GALL XI.M30, “Fuel Oil Chemistry,” and GALL XI.M32, “One-Time

Inspection.” In the VCSNS LRA (Table 3.3-1), carbon steel components in a fuel oil

environment are associated with the aging effect of loss of material from general, pitting,

crevice corrosion MIC, and galvanic corrosion. The applicant credited the Chemistry Program,

AMP B1.4, to manage these aging effects. For the components of the diesel generator services

system, the applicant also credited the Chemistry Program to manage the aging effects. The

Chemistry Program is consistent with GALL XI.M30, a “Fuel Oil Chemistry” AMP, but does not

include a one-time inspection. It should be noted that the GALL Report recommends further

evaluation for detection of aging effects and a one-time inspection program for verifying the

effectiveness of fuel oil chemistry control. By letter dated March 28, 2003, the staff requested,

in RAI B.1.4-1, the applicant to address the concern pertaining to the effectiveness of the

Chemistry Program. The staff’s evaluation of this issue is documented in Section 3.0.3.2 of this

SER.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the loss of material due to general, pitting, crevice, MIC, and
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biofouling, as recommended in the GALL Report. Since the applicant’s AMR results are

otherwise consistent with the GALL report, the staff finds 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).

3.3.2.2.8 Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading

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, as well as in the channel head and access cover, tubesheet, and tubes of the

letdown heat exchanger in the CVCS. The Water Chemistry Program relies on monitoring and

control of water chemistry, based on the guidelines of TR-105714 for primary water chemistry

to manage the effects of crack initiation and growth due to SCC and cyclic loading. The GALL

Report recommends further evaluation to manage crack initiation and growth from SCC and

cyclic loading for this system to verify the effectiveness of the Water Chemistry Program. The

staff reviewed the applicant’s proposed program to ensure that cracking is not occurring and

that the component intended function will be maintained during the period of extended

operation. A one-time inspection of select components at susceptible locations is an acceptable

method to ensure that crack initiation and growth are not occurring and that the component

intended functions will be maintained during the period of extended operation. If the applicant

proposed a one-time inspection of select components at susceptible locations to ensure that

corrosion is not occurring, the staff verified that the applicant’s selection of susceptible locations

is based on severity of conditions, time of service, and lowest design margin. The staff also

verified that the proposed inspection would be performed using techniques similar to ASME

Code and ASTM standards, including visual, ultrasonic, and surface techniques.

In the VCSNS LRA, the CVCS is scoped under the ESF systems. The staff’s evaluation of the

ESF systems is documented in Section 3.2.2.4.1 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of crack initiation and growth due to stress-corrosion cracking and cyclic

loading, as recommended in the GALL report. Since the applicant’s AMR results are otherwise

consistent with the GALL report, the staff finds 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).

3.3.2.2.9 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

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. The GALL Report

recommends further evaluation of programs to manage these aging effects. The staff reviewed

the applicant’s proposed program to ensure that an adequate program will be in place for the

management of these aging effects. 

In the VCSNS LRA, the spent fuel storage rack is scoped under structures. The staff’s

evaluation of the structures is documented in Section 3.5.2.4.2.2 of this SER.
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On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of reduction of neutron-absorbing capacity and loss of material due to

general corrosion, as recommended in the GALL report. Since the applicant’s AMR results are

other wise consistent with the GALL report, the staff finds 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).

3.3.2.2.10 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion

Loss of material due to general, pitting, and crevice corrosion and MIC could occur in the

underground piping and fittings in the open-cycle cooling water system (service water system)

and in the diesel fuel oil system. The Buried Piping and Tanks Inspection Program relies on

industry practice, frequency of pipe excavation, and operating experience to manage the effects

of loss of material from general, pitting, and crevice corrosion and MIC. The staff reviewed the

effectiveness of the Buried Piping and Tanks Inspection Program, including its inspection

frequency and operating experience, to ensure that loss of material is not occurring and that the

component intended function will be maintained during the period of extended operation.

The applicant credited the Buried Piping and Tanks Inspection AMP, B.2.10, to manage the

above aging effects that are applicable to the auxiliary systems. By letter dated March 28,

2003, the staff requested, in RAI B.2.10-1, the applicant to address the concern pertaining to

the adequacy of the Buried Piping and Tanks Inspection Program. The staff’s evaluation of this

issue is documented in Section 3.0.3.2 of this SER.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of loss of material due to general, pitting, crevice, and microbiologically

influenced corrosion, as recommended in the GALL report. Since the applicant’s AMR results

are other wise consistent with the GALL report, the staff finds 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).

3.3.2.3 Aging Management Programs for Auxiliary Systems Components

In SER Sections 3.3.2.1 and 3.3.2.2, the staff determined that the applicant’s AMRs and

associated AMPs, will adequately manage component aging in the auxiliary systems. The staff

then reviewed specific components in the auxiliary systems to ensure that they were properly

evaluated in the applicant’s AMR.

To perform its evaluation, the staff reviewed the components listed in LRA Sections 2.3.3.1

through 2.3.3.23 and Tables 2.3-18, through 2.3-37 as well as in the tables entitled, “Virgil C. 

Summer Nuclear Station Database AMR Query” and “Virgil C. Summer Nuclear Station

Database AMR Query Notes in the supplement to determine whether the applicant had properly

identified the applicable AMRs and AMPs needed to adequately manage the aging effects for

the components. This portion of the staff review involved identification of the aging effects for

each component, ensuring that each aging effect was evaluated using the appropriate AMR in
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Section 3, and that management of the aging effect was captured in the appropriate AMP. The

results of the staff’s review are provided below. 

The staff also reviewed the FSAR supplement for the AMPs credited with managing aging in

reactor system components to determine whether the program description adequately

describes the program.

The applicant credits 16 AMPs to manage the aging effects associated with components in the

auxiliary systems. Eight of the AMPs are credited to manage aging for components in other

system groups (common AMPs) while eight AMPs are credited to manage aging only for

auxiliary system components. The staff’s evaluation of the common AMPs credited with

managing aging in auxiliary system components is provided in Section 3.0.3 of this SER. The

common AMPs include the following:

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Chemistry Program (3.0.3.2)

• Fire Protection Program (3.0.3.3)

• Maintenance Rule Structures Programs (3.0.3.4)

• Above Ground Tank Inspection Program (3.0.3.5)

• Buried Piping and Tanks Inspection Program (3.0.3.6)

• Inspections for Mechanical Components Programs (3.0.3.7)

• Heat Exchanger Inspections Program (3.0.3.8)

 

The staff’s evaluation of the eight auxiliary systems AMPs are provided here:

3.3.2.3.1 Service Water System Reliability and In-Service Testing Program

Summary of Technical Information in the Application

The applicant’s Service Water System Reliability and In-Service Testing Program is discussed

in LRA Section B.1.9, “Service Water System Reliability and Inservice Testing.” The applicant

stated that the program is consistent with GALL AMP XI.M20, “Open-Cycle Cooling Water

System,” with no exceptions or enhancements specified in the LRA. The LRA credits this inservice testing program with managing the effects of aging for components in raw water

environments at VCSNS. In Section B.1.9 and FSAR supplement 18.2.33 of the LRA, the

applicant described the Service Water System Reliability and In-Service Testing Program as an

existing AMP that manages cracking, fouling, and loss of material for susceptible materials

located in systems containing raw water from the service water pond. More specifically, the

Service Water System Reliability and In-Service Testing Program is credited with managing the

following aging effects during the period of extended operation:

• loss of material due to general, pitting, and crevice corrosion and MIC

• particulate fouling and loss of material due to erosion of susceptible components or

component types

• fouling due to biological materials
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The applicant credited its Service Water System Reliability and In-Service Testing Program for

managing cracking, fouling, and loss of material in the air handling and local ventilation and

cooling systems, chilled water system component cooling water system, diesel generator

services system, and service water system.

The applicant stated in the LRA Operating Experience, Section B.1.9.1, “the application of

measured corrosion rates had been demonstrated to supply adequate information on the rate of

loss of material to predict when replacement of components might be necessary.” The

applicant further stated that, based on operating experience, the performance testing on raw

water heat exchangers furnishes adequate predictive modeling for fouling of heat transfer

surfaces to prevent loss of intended function. The applicant also stated that its Service Water

System Reliability and In-Service Testing Program is capable of detecting pinhole leaks in the

service water system prior to loss of function. The applicant confirmed that periodic visual

inspections of the service water system piping are conducted to monitor the extent of cracking,

fouling, and loss of material. The heat transfer capabilities of heat exchangers serviced by the

service water system are also evaluated to detect the presence of fouling.

Applicant letter RC.02.0159 dated September 12, 2002 submitted a revised description of the

B.1.9 AMP to include non-nuclear safety related components that were not initially included in

the scope of the license renewal, but that meet the refined 10 CFR 54.4 (a)(2) criteria.

In Section B.1.9 of the LRA, the applicant concluded that the Service Water System Reliability

and In-Service Testing Program has been demonstrated to be capable of managing the effects

of aging for components in raw water environments. The applicant also concluded that the

Service Water System Reliability and In-Service Testing Program provides reasonable

assurance that the aging effect will be managed such that the components subject to AMR will

continue to perform their intended functions consistent with the CLB for the extended period of

operation.

In Attachment 1 to letter dated September 12, 2002, the applicant stated that a reevaluation of

each attribute of the service water system reliability, and In-Service testing program confirms

that the program, as described, provides reasonable assurance that loss of material will be

managed during the period of extended operation. 

Staff Evaluation

In LRA Section B.1.9, “Service Water System Reliability and In-Service Testing,” the applicant

described its program to managing the effects of aging for components in raw water

environments within the scope of license renewal. The LRA states that this program is

consistent with GALL AMP XI.M20, “Open-Cycle Cooling Water System.” The staff confirmed

the applicant’s claim of consistency during the license renewal AMP audit. The staff reviewed

the summary description of the program in the FSAR supplement (Section 18.2.33 of Appendix

A to the LRA).

The staff identified that the applicant mentioned the requirements of NRC GL 89-13, “Service

Water System Problems Affecting Safety-Related Equipment,” in discussing the related

closed-cycle cooling water system (LRA Table 3.3-3, AMR Item 14) and the Underwater

Inspection Program (LRA Section B.1.23). Although the applicant made no mention of either GL

89-13 or its Supplement 1 with reference to the service water system, it has stated in LRA
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Section B.1.9 that the AMP is consistent with GALL AMP XI.M20, “Open-Cycle Cooling Water

System,” which uses GL 89-13 as a major reference. Thus, the staff understands that the

applicant is following all of the specific requirements of these generic letters for this system with

respect to the following:

• surveillance and control of biofouling

• test program to verify heat transfer capabilities

• routine inspection and maintenance program to ensure that corrosion, erosion,

protective coating failure, silting, and biofouling cannot degrade the performance of

safety-related systems served by this system

• system walkdown inspection to ensure compliance with the licensing basis

• review of maintenance, operating, and training practices and procedures

The staff reviewed the LRA Criteria 2 Supplement to determine whether the applicant has

demonstrated that the Service Water System Reliability and In-Service Testing Program will

adequately manage the applicable aging effects for the components that credit the program

throughout the period of continued operation, as required by 10 CFR 54.21(a)(3). The staff

finds that the applicant has demonstrated that there is reasonable assurance that the credited

program will ensure that loss of material in non-nuclear safety related components in the

service water system will be detected and corrected for the period of extended operation.

Section 18.2.33 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Service Water System Reliability and In-Service Testing Program at VCSNS. The staff

reviewed the FSAR supplement and found that the description of the service water system

reliability and in-service testing program is consistent with Section B.1.9 of the LRA. The staff

finds that the information contained in the FSAR supplement presents an adequate summary of

the program activities, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.3.2 Material Handling System Inspection Program

Summary of Technical Information in the Application

The applicant’s Material Handling System Inspection Program is discussed in LRA Section

B.1.19, “Material Handling System Inspection Program.” The applicant stated that the program
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is consistent with GALL XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related

to Refueling) Handling Systems,” for the bridge and trolley structural members and rails with the

following clarifications related to the Scope and the Parameters Monitored and Inspected

program elements.

 

[Scope] The polar crane girders and brackets are addressed under the Maintenance Rule

Structures Program and wear on the crane rails has been determined not to require aging

management for the VCSNS cranes.

[Parameters Monitored and Inspected] The number and magnitude of lifts made by the cranes

are addressed as a TLAA under Section 4.7.2 of the VCSNS LRA.

The LRA credits this program with managing loss of material for crane rails, rail supports, and

structural supports at VCSNS. In Section B.1.19 of Appendix B to the LRA, the applicant

claimed that the Material Handling System Inspection Program has been demonstrated to be

capable of managing loss of material for crane rails, rail supports, and structural supports. The

applicant further stated that the Material Handling System Inspection Program has been in

effect for many years at VCSNS and includes nuclear safety-related and quality-related

(seismically restrained) material handling system components. Material handling systems steel

support structures (rails, runways, monorails, girders, jib cranes, seismic restraints, and

associated connections) are inspected in accordance with the guidance provided by the ANSI

standards. The applicant stated that inspections are implemented in the course of routine

maintenance (FSAR Supplement 18.2.23). 

The applicant stated that industry’s operating experience for the material handling system was

reviewed in association with the Maintenance Rule. The applicant stated that through

monitoring the effectiveness of maintenance at nuclear power plants, there has been no

corrosion-related degradation that has impaired the cranes.

In Section B.1.19 of the LRA, the applicant concluded that the Material Handling System

Inspection Program has been demonstrated to be capable of managing loss of material for

crane rails, rail supports, and structural supports. The Material Handling System Inspection

Program provides reasonable assurance that the aging effects will be managed such that the

components subject to AMR will continue to perform their intended functions consistent with the

CLB. 

Staff Evaluation

In LRA Section B.1.19, “Material Handling System Inspection Program,” the applicant described

its AMP to manage aging of the material handing system. The LRA stated that this AMP is

consistent with the GALL AMP XI.M23, “Inspection of Overhead Heavy Loads and Light Loads

(Related to Refueling) Handling Systems,” for the bridge and trolley structural members and

rails with the following clarifications related to the Scope and the Parameters Monitored and

Inspected program elements. The staff confirmed the applicant’s claim of consistency during

the license renewal audit conducted on July 16-17, 2003. 

[Scope] The polar crane girders and brackets are addressed under the Maintenance Rule

Structures Program and wear on the crane rails has been determined not to require aging

management for the VCSNS cranes.
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[Parameters Monitored and Inspected] The number and magnitude of lifts made by the cranes

are addressed as a TLAA under Section 4.7.2 of the VCSNS LRA.

The inclusion of the information discussed above causes changes in some attributes of the

GALL AMP XI.M23, “Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems.” Therefore, the staff reviewed this AMP against only those attributes of the

applicant’s program which deviate from the attributes of the GALL program, using the guidance

in BTP RLSB-1 in Appendix A of the SRP-LR. The staff also reviewed the FSAR supplement to

determine whether it provides an adequate description of the program.

Under scope, the AMP identifies a clarification that the polar crane girders and brackets are

managed under the Maintenance Rule Structures Program. Only components in the auxiliary

systems are managed by this AMP. The applicant stated (LRA Table 3.3-1, AMR Item 15) that

loss of material in steel rails and girders will be managed by the Material Handling System

Inspection Program, while the Maintenance Rule Structures Program (LRA, Appendix B.1.18) is

responsible for managing the aging of structures and structural components. The applicant

stated that these aging effects, including loss of material due to corrosion, cracking, and

change in material properties, are detected by visual inspection of external surfaces (LRA,

Table 3.3-1, AMR Item 15). Also under scope, the AMP identifies a clarification related to wear

on the crane rails; wear on the crane rails has been determined not to require aging

management for the VCSNS cranes. The applicant further states in AMR Item 15 that wear is

movement of a material in relation to another material in contact with the first; wear can occur

during the performance of active functions. The applicant stated that according to the License

Renewal Rule [10 CFR 54.21(a)(1)(i)], SCs subject to an AMR must perform their intended

functions without moving parts or without a change in configuration or properties. The applicant

concluded that, as such, loss of material due to wear is not an aging effect requiring further

evaluation for license renewal, and is only considered a consequence of frequent or rough

usage. 

As described in the GALL Report Item VII.B.2-a and AMP XI.M23, loss of material due to wear

on crane rails falls within the scope of license renewal, because the crane rails are passive,

long-lived components and loss of material due to wear caused by active components is an

applicable aging effect. By letter dated March 28, 2003, the staff requested, in RAI B.1.19-1,

that the applicant justify its conclusion that loss of material due to wear does not require aging

management for VCSNS cranes. In its response dated June 12, 2003, the applicant stated that

LRA AMP B.1.19 identified that wear on crane rails has been determined not to require aging

management for VCSNS cranes, referencing TR00170-003 (Section 6.9) which asserts that

wear of crane rails due to rolling or sliding wheels is not expected in any measurable amount,

due to infrequent crane use. The applicant further stated that although “wear” is not considered

an applicable aging mechanism at VCSNS, the Material Handling System Inspection Program is

capable of detecting loss of material on crane rails from corrosion and/or wear. Accordingly, the

applicant stated that plant procedures do include inspection of rails for “abnormal wear” as part

of the AMP.

The staff noted that TR00170-003 (Section 6.9, “Summary of Aging Effect Evaluations Different

From Those Described in the GALL Report”) only claimed that “wear of crane rails due to rolling

or sliding wheels is not expected in any measurable amount due to the infrequent crane use.

Review of past inspection reports at VCSNS indicates that those cranes within the license

renewal scope are in good working condition.” Considering the reported age-related failure to a
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bridge guide roller bearing, the staff is concerned that wear on crane rails is possible and

should be considered an aging effect. During a telecommunication on July 14, 2003 the

applicant explained that the bearing failure was in an active component and that structural

components are not in the scope of this program. The applicant agreed that inspection for wear

was included in plant procedures and that it would be managed. By letter dated September 2,

2003, the applicant stated that VCSNS plant procedures currently require inspection of crane

rails for abnormal wear and that such procedures would remain in effect for the period of

extended operation. This response also identified that the frequency of these inspections is

every 18 months and/or prior to use. Considering that wear of the crane rails will be effectively

managed for the period of extended operation, the staff finds that the applicant’s response

satisfactorily addresses the staff’s concerns and RAI B.1.19-1 is considered closed.

The staff noted that the LRA is not clear which cranes are covered by this AMP. The only

reference to this AMP is in AMR Table 3.3-1, Item 15; however, there are no LRA Section 2

tables that refer to this AMR item. By letter dated March 28, 2003, the staff requested, in RAI

B.1.19-2, that the applicant clarify which cranes use the Material Handling System Inspection

Program. In its response dated June 12, 2003, the applicant stated that a detailed discussion of

the Material Handling System Inspection Program AMR is contained in TR00170-003, Section

7.13, including identification of all VCSNS cranes that are within the license renewal scope. The

staff noted, following review of the document, that TR00170-003 (Section 7.13, “Material

Handling System Inspection Program”), cited above by the applicant, comprehensively

describes the AMR of the cranes and clarifies which cranes use the Material Handling System

Inspection Program. Therefore, the staff considers the applicant’s response to be acceptable

and RAI B.1.19-2 is considered closed.

The applicant identified a clarification concerning parameters monitored and inspected. The

number of lifts made by the cranes is addressed as a TLAA under Section 4.7.2 of the

application. The staff identified that the correct reference should be to Section 4.7.3, which is

addressed under Section 4.7.5 of the SER.

Section 18.2.23 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Material Handling System Inspection Program at VCSNS. The staff reviewed the FSAR

supplement and found that the description of the Material Handling System Inspection Program

is consistent with Section B.1.19 of the LRA. The staff finds that the information contained in

the FSAR supplement presents an adequate summary of the program activities as required by

10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.3.3 Preventive Maintenance Activities—Ventilation Systems Inspections
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Summary of Technical Information in the Application

The applicant’s Preventive Maintenance Activities—Ventilation Systems Inspections Program is

discussed in LRA Section B.1.26, “Preventive Maintenance Activities—Ventilation Systems

Inspections Program.” The LRA credits this preventive inspections program with managing loss

of material and fouling in susceptible components in the air handling, local ventilation, and

component cooling systems at VCSNS that are exposed internally to moist air. 

The applicant claimed that the Preventive Maintenance Activities—Ventilation Systems

Inspections Program is a plant-specific condition monitoring program that will manage the

following:

• loss of material due to boric acid corrosion, galvanic corrosion, and general corrosion in

carbon steel, galvanized steel, and copper components

• fouling due to particulates in aluminum, copper, and copper-nickel heat exchanger

components 

Components in the air handling, local ventilation, and components cooling systems for the

following structures and areas are monitored by this AMP—control building, auxiliary and

radwaste area, fuel handling building, turbine building, engineering safety features, intermediate

building, miscellaneous building, and reactor building. The applicant verifies (FSAR

Supplement 18.2.25) that routine maintenance inspections are conducted which include

detection of age-related degradation.

In Section B.1.26 of the LRA, the applicant concluded that the Preventive Maintenance

Activities—Ventilation Systems Inspections Program has been demonstrated to be capable of

detecting and managing the effects of aging for components exposed to a ventilation

environment. The Preventive Maintenance Activities—Ventilation Systems Inspections Program

provides reasonable assurance that the aging effects will be managed such that the

components subject to AMR will continue to perform their intended functions consistent with the

CLB during the period of extended operation. 

Staff Evaluation

In LRA Section B.1.26, “Preventive Maintenance Activities—Ventilation Systems Inspections

Program,” the applicant described its AMP to manage loss of material and fouling in susceptible

components in the air handling, local ventilation, and component cooling systems at VCSNS

that are exposed internally to moist air. The LRA states that this is a new, plant-specific AMP;

therefore, the staff reviewed the program using the guidance in BTP RLSB-1 in Appendix A of

the SRP-LR. The staff’s evaluation focused on management of aging effects through

incorporation of the following 10 elements from RLSB-1—program scope, preventive actions,

parameters monitored or inspected, detection of aging effects, monitoring and trending,

acceptance criteria, corrective actions, confirmation process, administrative controls, and

operating experience. The applicant indicated that the corrective actions, confirmation process,

and administrative controls for license renewal are in accordance with the site-controlled Quality

Assurance Program. The staff’s evaluation of the applicant’s Quality Assurance Program is

provided separately in Section 3.0.4 of this SER; the evaluation of the remaining seven
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elements is provided below. The staff also reviewed the FSAR supplement to determine

whether it provides an adequate description of the program.

[Program Scope] The applicant stated that this AMP is applicable to specified systems and

components exposed to a ventilation environment. The staff finds that the systems and

components monitored by the Preventive Maintenance Activities—Ventilation Systems

Inspections Program, as listed in Section B.1.26 of the LRA, are within the scope of license

renewal as identified in Section 2.3 of the LRA. The staff identified that crevice corrosion and

MIC are not addressed in this AMP. SRP-LR Section 3.3.2.2.5 identifies crevice corrosion and

MIC as aging mechanisms for ductwork and other components in ventilation systems. The

resolution of the concern related to MIC in ductwork is addressed in the response to RAI

B.2.11-1 and in Section 3.3.2.2.5 of this SER. The scope is acceptable to the staff because it

includes those components that rely on the program for aging management.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need for

preventive actions in this AMP because it is a condition monitoring program. 

[Parameters Monitored or Inspected] The applicant stated that this program inspects exposed

components for visible evidence of corrosion that indicate possible loss of material, and

accumulation of dust and particulates on fins and tubes that indicate possible fouling. The staff

finds the above visible inspection parameters acceptable because they are directly related to

the degradation of carbon steel components and the fouling of heat exchanger components.

Visual inspections are effective in detecting such conditions.

[Detection of Aging Effects] The applicant stated that the program will detect the presence and

extent of the aging effects (loss of material due to boric acid corrosion, galvanic corrosion, and

general corrosion and fouling due to particulates in the ventilation system) prior to a loss of

component intended function. The staff finds that these inspection techniques are sufficient to

provide reasonable assurance that the aging effects for the components addressed by the

Preventive Maintenance Activities—Ventilation Systems Inspections Program will be detected

before the loss of intended function. 

[Monitoring and Trending] The applicant stated “routine periodic visual inspections are

conducted...in order to detect age-related degradation and to initiate corrective actions as

necessary.” By letter dated March 28, 2003, the staff requested, in RAI B.1.26-1, the applicant

to specify the frequency of these periodic inspections and how the inspection frequency is

determined. In its response dated June 12, 2003, the applicant stated that the Preventive

Maintenance Activities—Ventilation Systems Inspections Program is the license renewal name

for the diverse preventive maintenance activity already being routinely performed on

components that can be credited for managing aging during the period of extended operation.

The applicant further stated that the preventive maintenance performed on the component

cooling water pump motor cooling coils is conducted on 10-year intervals. The applicant also

stated that the preventive maintenance performed on the fan coils for air-handling units is

conducted on semiannual intervals. Preventive maintenance on the reactor building cooling

units (RBCUs) is conducted at intervals less than 5 years. The staff is concerned that inspection

intervals must be established to detect degradation prior to loss of the component function, and

inspections performed at intervals greater than 5 years are not consistent with GL 89-13.

During a telecommunication with the applicant on July 14, 2003, the staff requested further
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information to establish how the inspection frequency is determined. By letter dated September

2, 2003, the applicant identified that the preventive maintenance frequency for the component

cooling water pump motor cooling coils and air-handling units is based on vendor

recommendations. This response also clarified that the inspection of the RBCUs is in addition to

the performance testing required by Generic Letter 89-13 that is performed under the Service

Water System Reliability and In-Service Testing Program. The staff finds that the applicant’s

response satisfactorily addresses the staff’s concerns and RAI B.1.26-1 is considered closed. 

The applicant stated that for the RBCUs, an engineering procedure requires recording of

temperature monitoring data annually, or at least once per refueling cycle. Although

temperatures are trended for the RBCUs, Element 3, Parameters Monitored or Inspected and

Element 4, Detection of Aging Effects, discuss visual inspections and do not mention

temperature monitoring. By letter dated March 28, 2003, the staff requested, in RAI B.1.26-2,

the applicant to clarify how the temperature measurements are used in this program. In its

response dated June 12, 2003, the applicant stated that the preventive maintenance performed

on the RBCUs includes visually inspecting inlet and outlet coil faces as a step in performance

testing. The applicant further stated that performance testing involves trending temperatures

for the RBCUs. The response did not address how the trended temperatures are used, how

the information from visual inspections is used, and how inaccessible areas are inspected. 

During a telecommunication with the applicant on July 14, 2003, the staff requested written

information to address this concern. By letter dated September 2, 2003, the applicant clarified

that temperature monitoring of the RBCUs is not performed under this program, but is

performed as a step in the performance testing of service water heat exchangers which is a

commitment to GL 89-13 performed under the Service Water System Reliability and In-Service

Testing Program. This response also identified that the preventive maintenance program

performed on the RBCUs includes visually inspecting coil exteriors and drain pans for

cleanliness and signs of degradation and corrosion. In this letter, the applicant further states

that, because the ventilation air would encounter the outermost tubes before encountering the

innermost tubes, it is expected that the outermost tubes of the bundle would experience as

much or more contaminants than the innermost tubes. The staff finds that the applicant’s

response satisfactorily addresses the staff’s concerns and RAI B.1.26-2 is considered closed.

[Acceptance Criteria] The applicant stated that the acceptance criterion is no unacceptable loss

of material or fouling of subject components that could result in a loss of the component

intended functions as determined by engineering evaluation. The applicant stated that

engineering procedure contains specific acceptance criteria for the RBCUs. The staff finds that

these acceptance criteria are adequate to ensure that the component intended functions are

maintained under all CLB design conditions during the period of extended operation.

[Operating Experience] The applicant verified that a review of work histories for the past 10

years revealed that no age-related degradation had been detected for the subject components. 

The staff finds that the applicant’s operating experience indicates that the Preventive

Maintenance Activities—Ventilation Systems Inspections Program has effectively maintained

the integrity of the components and the effects of aging will be adequately managed during the

period of extended operation. 

Section 18.2.25 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Preventive Maintenance Activities—Ventilation Systems Inspections Program at VCSNS. The

staff reviewed the FSAR supplement and found that the description of the Preventive
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Maintenance Activities—Ventilation Systems Inspections Program is consistent with Section

B.1.26 of the LRA. The staff finds that the information contained in the FSAR supplement

presents an adequate summary of the program activities, as required by 10 CFR 54.21(d).

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.3.2.3.4 Diesel Generator Systems Inspection Program

Summary of Technical Information in the Application

The applicant’s Diesel Generator Systems Inspection Program is discussed in LRA Section

B.2.2, “Diesel Generator Systems Inspection.” The applicant stated that this is a new program

and therefore summarized the program in terms of the 10-element program described in BTP

Appendix A-1 of the SRP-LR. The LRA credits this inspection at VCSNS with managing loss of

material in diesel generator components due to general corrosion and/or the corrosive impacts

of alternate wetting and drying in air-gas environments. The applicant stated that this new onetime inspection will detect and characterize loss of material due to general corrosion and the

corrosive impacts of alternate wetting and drying in air-gas environments. The Diesel

Generator Systems Inspection Program will determine if aging management is required for

certain carbon steel diesel generator support system components during the period of extended

operation. This inspection will use suitable examination techniques at the most susceptible

(sample) locations (FSAR Supplement 18.2.13). The applicant stated that the Diesel Generator

Systems Inspection Program will be consistent with GALL AMP XI.M32, “One-Time Inspection,”

and that the one-time inspection will be performed prior to the period of extended operation.

In Section B.2.2 of the LRA, the applicant concluded that implementation of the Diesel

Generator Systems Inspection Program will either verify that there are no aging effects

requiring management for the subject components, or ensure that appropriate corrective

actions will be taken so that the component intended functions will be maintained during the

period of extended operations. 

Staff Evaluation

The staff reviewed the information in Section B.2.2 of Appendix B to the LRA, the applicant’s

response to the staff’s RAI, and the summary descriptions of the program in the FSAR

supplement (Section 18.2.13 of Appendix A to the LRA). Since the applicant claimed

consistency with GALL AMP XI.M32, this AMP was cross-referenced in the staff’s review. The

10 program elements in this GALL AMP for one-time inspection supply detailed programmatic

characteristics and criteria that the staff considers necessary to verify the absence of aging

effects and the effectiveness of the AMP. Therefore, the staff reviewed the program using the

guidance in BTP RLSB-1 in Appendix A of the SRP-LR. The staff’s evaluation focused on

managing aging effects through incorporation of the following 10 elements from RLSB-1—
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program scope, preventive actions, parameters monitored or inspected, detection of aging

effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process,

administrative controls, and operating experience. The applicant indicated that the corrective

actions, confirmation process, and administrative controls for license renewal are in accordance

with the site-controlled Quality Assurance Program. The staff’s evaluation of the applicant’s

Quality Assurance Program is provided separately in Section 3.0.4 of this SER; and the

evaluation of the remaining seven elements is provided below. The staff also reviewed the

FSAR supplement to determine whether it provides an adequate description of the program.

[Program Scope] The applicant stated that this AMP is applicable to the following components 

in the diesel generator services system—carbon steel expansion joints normally exposed to

moist air which are exposed to exhaust air during engine operation, and carbon steel tanks and

associated tubing components exposed to starting and control air. These components of

concern are exposed to air-gas internal environments. The staff finds that the SCs monitored by

the Diesel Generator Systems Inspection Program, as listed in Section B.2.2 of the LRA, are

within the scope of license renewal, as identified in Section 2.3 of the LRA. The scope is

acceptable to the staff because it includes those components that rely on the program for aging

management.

By letter dated March 28, 2003, the staff requested, in RAI B.2.2-1, further information about

the program scope. Since the plant operating experience should supply information on

degradation due to loss of material caused by general corrosion and alternate wetting and

drying, the staff asked the applicant to clarify the operating experience and identify any

experience of degraded system conditions within the program scope. In its response dated

June 12, 2003, the applicant stated that operating experience, both site-specific and industrywide, was researched to identify the possible aging effects for various material environment

combinations; the resulting information is retained at VCSNS. The applicant confirmed that

operating experience at VCSNS for the components managed by this program revealed no

history of degradation for the internal surfaces, and that this one-time inspection was developed

because it was determined that the aging effects were possible, and not because they were

found at VCSNS. In a telecommunication with the applicant on July 14, 2003, the staff

requested confirmation from the applicant, based on the response to RAI 3.3.2.4.7-3, that the

scope of this program will be revised to include mufflers and exhaust piping. By letter dated

September 2, 2003, the applicant identified that the inspections of carbon steel components

exposed to exhaust gases will include exhaust expansion joints, exhaust piping, associated

exhaust tubing, and mufflers. By letter dated September 2, 2003, the applicant provided a

revised FSAR supplement to revise the summary of Section 18.2.13, to include exhaust air

components. The staff finds that the applicant’s response satisfactorily addresses the staff’s

concerns and RAI B.2.2-1 is considered closed.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need for

preventive actions in this AMP.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness and/or visible evidence of corrosion, including pitting and

discoloration, to indicate possible loss of material for the carbon steel components. The staff

finds these parameters acceptable because they are directly related to the degradation of

carbon steel components in the diesel generator systems.
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[Detection of Aging Effects] The applicant stated that the AMP will use a combination of proven

volumetric and/or visual examination techniques on a sample population of the subject

components to be determined by engineering evaluation. A sample of carbon steel components

most susceptible to aging effects from alternate wetting and drying in a moist air and exhaust

air environment (such as expansion joints, the starting air tanks, mufflers and exhaust piping)

have been selected as representative for such testing. The applicant further stated that results

of the inspection will be applied to the remainder of the components within the scope of the

inspection activity. The AMP will detect the presence and extent of any loss of material due to

general corrosion and the corrosive impacts of alternative wetting and drying for the subject

components prior to loss of their intended functions. 

The staff finds that these inspection techniques are sufficient to provide reasonable assurance

that the aging effect for the components addressed by the Diesel Generator Systems

Inspection Program will be detected before a component has lost its intended function. The use

of one-time inspection is appropriate for inspections where degradation is possible, but is not

expected on the basis of plant-specific and industry operating experience. This one-time

inspection provides for additional inspections should the corrective action process require

additional information to characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the Diesel

Generator Systems Inspection Program to trend inspection results. This is a one-time program

used to determine if further actions are required. The staff did not identify the need for

monitoring and trending for this AMP.

[Acceptance Criteria] The applicant stated that the acceptance criterion is no unacceptable loss

of material of the subject components that could result in a loss of the component intended

functions, as determined by engineering evaluation. The staff considers this engineering

evaluation to be adequate to assure that the intended functions for components in the Diesel

Generator Systems Inspection Programs are maintained under all CLB design conditions during

the period of extended operation.

[Operating Experience] The applicant stated that the Diesel Generator Systems Inspection

Program is a new one-time inspection for which there is no operating experience. By letter

dated March 28, 2003, the staff requested, in RAI B.2.2-1, to identify any experience of

degraded system conditions within the program scope based on the plant operating experience

on degradation due to loss of material caused by general corrosion and alternate wetting and

drying. In its response dated June 12, 2003, the applicant stated that operating experience,

both site-specific and industry-wide, was researched to identify the possible aging effects for

various material/environment combinations; the resulting information is retained at VCSNS. The

applicant confirmed that operating experience at VCSNS, for the components managed by this

program, revealed no history of degradation for the internal surfaces, and that this one-time

inspection was developed because it was determined that the aging effects were possible, and

not because they were found at VCSNS. The staff finds that the applicant’s operating

experience indicates that the effects of aging will be adequately managed during the period of

extended operation.

Section 18.2.13 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Diesel Generator Systems Inspection Program at VCSNS. The staff reviewed the FSAR

supplement and found that the description of the Diesel Generator Systems Inspection Program
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is consistent with Section B.2.2 of the LRA. The staff finds that the information contained in the

FSAR supplement presents an adequate summary of the program activities, as required by 10

CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.3.5 Liquid Waste System Inspection Program

Summary of Technical Information in the Application

The applicant’s Liquid Waste System Inspection Program is discussed in LRA Section B.2.3, 

“Liquid Waste System Inspection.” The applicant stated that this is a new program and

therefore summarized the program in terms of the 10-element program described in BTP

Appendix A-1 of the SRP-LR. The LRA credits this inspection with detecting and characterizing

loss of material due to crevice and pitting corrosion and cracking due to SCC in unmonitored

and uncontrolled borated water environments at VCSNS. The applicant stated that this new

one-time inspection will detect and characterize loss of material due to crevice and pitting

corrosion and cracking due to SCC in systems and components exposed to unmonitored and

uncontrolled borated water environments. This one-time inspection activity will determine if

aging management is required for certain stainless steel pipe, valves, and heat exchanger

components during the period of extended operation. The Liquid Waste System Inspection

Program will use a combination of volumetric and visual examination techniques at the most

susceptible (sample) locations (FSAR Supplement 18.2.21). The applicant stated that this

inspection will be consistent with GALL AMP XI.M32, “One-Time Inspection.”

In Section B.2.3 of the LRA, the applicant concluded that implementation of the Liquid Waste

System Inspection Program will either verify that there are no aging effects requiring

management for the subject components, or ensure that appropriate corrective actions will be

taken so that the component intended functions will be maintained during the period of

extended operations.

Staff Evaluation

In LRA Section B.2.3, “Liquid Waste System Inspection,” the applicant described its AMP to

manage loss of material due to crevice and pitting corrosion and cracking due to SCC in

unmonitored and uncontrolled borated water environments. Since the applicant claimed

consistency with GALL AMP XI.M32, this AMP was cross-referenced in the staff’s review. The

10 program elements in this GALL AMP for one-time inspection supply detailed programmatic

characteristics and criteria that the staff considers necessary to provide additional assurance

that either aging is not occurring, or the evidence of aging is so insignificant that an AMP is not
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warranted. The Liquid Waste System Inspection is a one-time inspection program with

commitments to follow-up actions based on engineering evaluation of inspection results.

The staff reviewed the program using the guidance in BTP RLSB-1 in Appendix A of the SRPLR. The staff’s evaluation focused on management of aging effects through incorporation of the

following 10 elements from RLSB-1—program scope, preventive actions, parameters monitored

or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

actions, confirmation process, administrative controls, and operating experience. The applicant

indicated that the corrective actions, confirmation process, and administrative controls for

license renewal are in accordance with the site-controlled Quality Assurance Program. The

staff’s evaluation of the applicant’s Quality Assurance Program is provided separately in

Section 3.0.4 of this SER, and the evaluation of the remaining seven elements is provided

below. The staff also reviewed the FSAR supplement to determine whether it provides an

adequate description of the program.

[Program Scope] The applicant stated in the LRA that this AMP is applicable to stainless steel

components exposed to unmonitored and uncontrolled borated water in nuclear plant drains

(ND) and liquid waste processing (WL) systems. Applicant letter RC-02-0159 dated September

12, 2003 submitted a supplement to include components which meet 10 CFR 54.4(a)(2). Table

1, item 3 of this submittal added systems LD, LW, MD, NB, WD and WX to the scope managed

by the liquid waste system inspection. Applicant letter dated September 24, 2003 submitted a

new scope for AMP B.2.3 which includes these additional systems. In this letter the applicant

stated that no revision is required for the FSAR summary description provided in the LRA

Section 18.2.21. The staff finds that the systems and components monitored by the Liquid

Waste System Inspection Program, as listed in letter dated September 12, 2002, are within the

scope of license renewal as identified in Section 2.3 of the LRA and supplemented by letter

dated September 24, 2003. The scope is acceptable to the staff because it includes those

components that rely on the program for aging management.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need for

preventive actions in this AMP.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness as a measure of loss of material and visual evidence of

loss of material, material, cracking or other age-related degradation. The staff finds the above

parameters acceptable because they are directly related to the degradation of stainless steel

components exposed to an unmonitored and uncontrolled borated water environment in the

aforementioned systems.

[Detection of Aging Effects] The applicant stated that the AMP will use a combination of proven

volumetric and visual examination techniques on a sample population of the subject

components to be determined by engineering evaluation. The applicant further states that

results of the inspection will be applied to the remainder of the components within the scope of

the inspection activity. The sample population will consist of susceptible locations within the

boundaries of either of the two affected containment penetrations, as well as the internal tube

surfaces of the affected heat exchangers. 
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The staff finds that these inspection techniques are sufficient to provide reasonable assurance

that the aging effects for the components will be detected before a loss of intended function.

The use of a one-time inspection is appropriate for inspections where degradation is possible,

but is not expected on the basis of plant-specific and industry operating experience. This onetime inspection provides for additional inspections should the corrective action process require

additional information to characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the Liquid

Waste System Inspection Program to trend inspection results. This is a one-time program used

to determine if further actions are required. The staff did not identify the need for monitoring

and trending in this AMP.

[Acceptance Criteria] The applicant stated that the acceptance criterion is no unacceptable loss

of material or cracking of the subject components that could result in a loss of the component

intended functions, as determined by engineering evaluation. The staff considers this

engineering evaluation to be adequate to assure that the intended functions for components in

the Liquid Waste System Inspection Program are maintained under all CLB design conditions

during the period of extended operation.

[Operating Experience] The applicant stated that the Liquid Waste System Inspection Program

is a new one-time inspection for which there is no operating experience. By letter dated March

28, 2003, the staff expressed concern, in RAI B.2.3-1, about the adequacy of the AMP because

(1) the components are exposed to unmonitored and uncontrolled borated water, (2) the system

is used frequently, (3) this is a new program with no operating experience, (4) there is a

potential for high concentrations of impurities in the water, and (5) the condition of the system is

unknown. The staff asked the applicant to justify the use of a one-time inspection for the liquid

waste system components. In its response dated June 12, 2003, the applicant stated that

operating experience, both site-specific and industry-wide, was researched to identify the

possible aging effects for various material environment combinations; the resulting information

is retained at VCSNS. The applicant verified that operating experience at VCSNS for the

components managed by this program revealed no history of degradation for the internal

surfaces. The applicant stated that this one-time inspection was developed because it was

determined that the aging effects were possible, and not because they were found at VCSNS.

Since the applicant verified its analysis of relevant site-specific and industry-wide operating

experience showing no relevant problems, the applicant’s response satisfactorily addresses the

staff’s concerns and RAI B.2.3-1 is considered closed. By letter dated March 28, 2003, the staff

stated, in RAI B.2.3-2, that plant operating experience with this system should reflect any agerelated degradation and requested the applicant to clarify the operating experience with this

system. The staff asked the applicant to present operating history on the occurrence of crevice,

pitting, and stress corrosion cracking in the ND system and the WL system to justify the use of

a one-time inspection for the liquid waste system components. In its response dated June 12,

2003, the applicant stated that site-specific and industry-wide operating experience was

researched to identify the possible aging effects for various material and environment

combinations and elaborated on management of the stainless steel components in the ND and

WL systems. 

The SS ND System components managed by the Liquid Waste System Inspection function as pressure

boundary for a containment penetration, used for the transfer of water out of the reactor building sump and the

incore instrumentation sump. These sumps contain leakage only from high purity systems located inside the
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reactor building; components are leak tested under 10CFR50 Appendix J. Operating experience at VCSNS for

the ND components managed by this program reveals no history of degradation for the internal surfaces.

The SS WL System components managed by the Liquid Waste System Inspection function as pressure

boundary for a containment penetration or as pressure boundary with the component cooling (CC) system. The

WL components that function as pressure boundary for containment isolation are leak tested under 10CFR50

Appendix J. The contents of the reactor coolant drain tank (RCDT) are transferred through this containment

penetration. Because of the purity of the systems that are the sources of the water to the RCDT, the water in

the RCDT is recyclable reactor grade water. Operating experience at VCSNS for these WL components

managed by this program reveals no history of degradation for the internal surfaces. The WL components that

function as pressure boundary for the CC system are the tubes for the RCDT heat exchanger and the tubes

for the waste evaporator (WE, which is seldom used at VCSNS) concentrates sample cooler. Operating

experience at VCSNS for these WL components managed by this program reveals no history of degradation

for the internal surfaces.

Since the applicant verified in its response that the operating history at VCSNS reveals no

history of degradation for internal surfaces of either the ND or the WL systems, the applicant

satisfactorily addressed the staff’s concerns and RAI B.2.3-2 is considered closed. 

Applicant letter dated September 24, 2003 stated that supplement added components are not

required to maintain the pressure boundary integrity to meet their license renewal intended

function. This is acceptable to the staff on the basis that the intended license renewal function

to satisfy 10 CFR 54.4(a)(2) is limited to maintaining structural integrity. 

Section 18.2.21 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Liquid Waste System Inspection Program at VCSNS. The staff reviewed the FSAR supplement

and found that the description of the Liquid Waste System Inspection Program is consistent

with Section B.2.3 of the LRA. The staff finds that the information contained in the FSAR

supplement presents an adequate summary of the program activities as required by 10 CFR

54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.3.6 Reactor Building Cooling Unit Inspection Program

Summary of Technical Information in the Application

The applicant’s Reactor Building Cooling Unit Inspection Program is discussed in LRA Section

B.2.5, “Reactor Building Cooling Unit Inspection.” The applicant stated that this is a new

program and therefore summarized the program in terms of the 10-element program as

described in BTP Appendix A-1 of the SRP-LR. The LRA credits this inspection with detecting

and characterizing loss of material due to crevice and pitting corrosion and cracking due to SCC
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at VCSNS resulting from exposure to an unmonitored and uncontrolled borated water

environment. The applicant stated that this one-time inspection will detect and characterize loss

of material due to crevice and pitting corrosion and cracking due to SCC resulting from

exposure to an unmonitored and uncontrolled borated water environment. The borated water

environment results from condensation out of the reactor building atmosphere, onto the RBCU

cooling coils, and then into the associated drain lines. The Reactor Building Cooling Unit

Inspection Program will use volumetric and/or visual examination techniques at the most

susceptible (sample) locations in the RBCU drain lines (FSAR Supplement 18.2.26). The

applicant stated that the Reactor Building Cooling Unit Inspection Program will be consistent

with AMP XI.M32, “One-Time Inspection”, in the GALL Report. The applicant also states that

this one-time inspection will be performed prior to the period of extended operation. 

In Section B.2.5 of the LRA, the applicant concluded that implementation of the Reactor

Building Cooling Unit Inspection Program will either verify that there are no aging effects

requiring management for the subject components or appropriate corrective actions will be

taken so that the component intended functions will be ensured during the period of extended

operations.

Staff Evaluation

In LRA Section B.2.5, “Reactor Building Cooling Unit Inspection,” the applicant described its

AMP to manage loss of material due to crevice and pitting corrosion and cracking due to SCC

at VCSNS resulting from exposure to an unmonitored and uncontrolled borated water

environment. Since the applicant stated that AMP B.2.5 is a new one-time inspection consistent

with GALL AMP XI.M32, the staff focused its evaluation on how this VCSNS AMP detects and

characterizes loss of material and cracking. The staff’s evaluation of this program, which

follows, is on the basis of the 10-element program as described in BTP Appendix A-1 of the

SRP-LR. The 10 program elements in the GALL AMP XI.M32 for one-time inspection supply

detailed programmatic characteristics and criteria that the staff considers necessary to provide

additional assurance that either aging is not occurring or the evidence of aging is so

insignificant that an AMP is not warranted. 

The staff reviewed the program using the guidance in BTP RLSB-1 in Appendix A of the SRPLR. The staff’s evaluation focused on management of aging effects through incorporation of the

following 10 elements from RLSB-1— program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience. The

applicant indicated that the corrective actions, confirmation process, and administrative controls

for license renewal are in accordance with the site-controlled Quality Assurance Program. The

staff’s evaluation of the applicant’s Quality Assurance Program is provided separately in

Section 3.0.4 of this SER, and the evaluation of the remaining seven elements is provided

below. The staff also reviewed the FSAR Supplement to determine whether it provides an

adequate description of the program.

[Program Scope] The applicant stated that this AMP is applicable to stainless steel pipe

exposed to an unmonitored borated water environment in the RBCU drain lines that are part of

the VCSNS roof drain system. The staff finds that the systems and components monitored by

the Reactor Building Cooling Unit Inspection Program, as listed in Section B.2.5 of the LRA, are

within the scope of license renewal as identified in Section 2.3 of the LRA. The scope is
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acceptable to the staff because it includes those components that rely on the program for aging

management.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need for

such preventive actions in this AMP.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness as a measure of loss of material, and visual evidence of

loss of material, cracking, or other age-related degradation. By letter dated March 28, 2003, the

staff requested, in RAI B.2.5-1, that the applicant explain how visual inspection can supply

information about cracking at the inside surface of piping. In its response dated June 12, 2003,

the applicant stated that visual inspections will be performed for the area below the coils and

that if any age-related degradation is detected, then volumetric examinations will be performed

on the piping. Since the applicant demonstrated how volumetric examinations supplement

visual inspections as needed in the monitoring process, the applicant’s response satisfactorily

addresses the staff’s concerns and RAI B.2.5-1 is considered closed. 

[Detection of Aging Effects] The applicant stated that the AMP will use a combination of proven

volumetric and visual examination techniques at sample locations in the drain lines determined

by engineering evaluation to be most susceptible to the applicable aging effects. If no

parameters are known that would distinguish the susceptible locations, sample locations will be

selected based on accessibility and radiological concerns and the results will be applied to the

associated piping. The applicant further stated that this inspection will detect the presence and

extent of any loss of material and cracking prior to a loss of component intended function. The

staff finds that these inspection techniques are sufficient to provide reasonable assurance that

the aging effects for the components managed by the Reactor Building Cooling Unit Inspection

Program will be detected and evaluated before a component has lost its intended function. The

use of one-time inspection is appropriate for inspections where degradation is possible, but is

not expected on the basis of plant-specific and industry operating experience. This one-time

inspection provides for additional inspections should the corrective action process require

additional information to characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the

Reactor Building Cooling Unit Inspection to trend inspection results. This is a one-time program

used to determine if further actions are required. By letter dated March 28, 2003, the staff

noted, in RAI B.2.5-2, that the ability to evaluate the appropriateness of techniques and timing

of one-time inspection improves with the accumulation of plant-specific and industry-wide

experience. The staff requested that the applicant address the changes that may be made in

monitoring and trending (considering that certain components, although stainless steel, are

exposed to an unmonitored borated water environment) in response to the discovery of boric

acid-induced corrosion of the Davis-Besse vessel. The staff requested that the applicant clarify

how, when inspection results reveal degraded conditions (even from a different system),

additional inspections addressed in Element 7, Corrective Actions, form the basis for future

monitoring and trending actions. Finally, the staff asked the applicant to identify to what extent

the Boric Acid Corrosion Surveillances AMP is integrated with the Reactor Building Cooling Unit

Inspection Program.
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In its response dated June 12, 2003, the applicant stated there is no action to trend the

inspection results because it is a one-time inspection; the objective of such inspections is to

determine if further actions are required. The applicant noted that Element 7, Corrective

Actions, addresses additional inspections should degradation be detected. As part of its

response, the applicant stated that since RBCUs have the potential to concentrate

contaminants from the reactor building atmosphere, the water environment is designated as

being unmonitored. The applicant stated that a search of industry operating experience

revealed an instance of boric acid crystallization in RBCU drain piping; therefore, VCSNS has

conservatively deemed the environment to be unmonitored borated water. This drain piping is

not pressurized nor will it experience much flow (less than 1 gallon per minute (gpm)) except

under accident conditions. Because there is a potential for aging effects for stainless steel in

this unmonitored borated water environment, the applicant stated that VCSNS would conduct a

one-time inspection prior to the end of the current operating term. 

According to GL 88-05, stainless steel and nickel-based alloys are not susceptible to boric acid

corrosion; therefore, boric acid corrosion is not considered an aging effect for RBCU drains.

The applicant noted that the aging effects for carbon steel components of the ventilation

environment of the RBCUs are managed by the Preventive Maintenance Activities —

Ventilation Systems Inspections Program. The staff was concerned that the RBCU inspection

might not be integrated with the Boric Acid Corrosion Surveillances Program and that inspection

results showing boric acid corrosion or crystals might not be considered in the Boric Acid

Corrosion Surveillances AMP. During a telecommunication July 14, 2003, the applicant

identified that the RBCU inspection was not integrated with the Boric Acid Corrosion

Surveillances Program. The staff requested further clarification to determine if the RBCUs are

also inspected as part of the Boric Acid Corrosion Surveillances Program. If not, the applicant

needed to explain how the results from the RBCU and ventilation systems inspection are

considered in the Boric Acid Corrosion Program. By letter dated September 2, 2003, the

applicant clarified that the scope of the Reactor Building Cooling Unit Inspection is only the

stainless steel drain lines of the RBCUs and other AMPs manage other components associated

with the RBCUs. Considering that Engineering reviews the inspection results, it is reasonable to

expect that the root cause for boric acid corrosion in the drain lines would be adequately

evaluated without the need to integrate the Reactor Building Unit Cooling Unit Inspection with

the Boric Acid Corrosion Surveillances. Therefore, the staff finds that the applicant’s response

satisfactorily addresses the staff’s concerns and RAI B.2.5-2 is considered closed.

[Acceptance Criteria] The applicant stated that the acceptance criteria are no unacceptable

loss of material or cracking of the subject components that could result in a loss of the

component intended function(s), as determined by engineering evaluation. The staff considers

this engineering evaluation to be adequate to assure that the intended functions for

components in the Reactor Building Cooling Unit Inspection are maintained under all CLB

design conditions during the period of extended operation.

[Operating Experience] The applicant stated that the Reactor Building Cooling Unit Inspection

Program is a new one-time inspection for which there is no operating experience. By letter

dated March 28, 2003, the staff requested, in RAI B.2.5-3, that the applicant present operating

experience relative to leaks or degradation in the RBCU drain piping and drain pan, noting the

absence or presence or any leaks or degradation. In its response dated June 12, 2003, the

applicant stated that operating experience, both site-specific and industry-wide, was researched

to identify the possible aging effects for various combinations of material and environment. The
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applicant stated that industry operating experience revealed an instance of detecting boric acid

crystallization in RBCU drain piping; therefore, this one-time inspection was developed because

it was determined that the aging effects were possible, and not because they were found at

VCSNS. Lastly, the applicant verified that the RBCU stainless steel drain piping at VCSNS

experienced no leaks or degradation. Since the applicant verified in its response that the

VCSNS operating history reveals no history of leaks or degradation of stainless steel drain

piping in the RBCUs, the staff’s request was satisfactorily met and RAI B.2.5-3, is considered

closed. 

Section 18.2.26 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Reactor Building Cooling Unit Inspection Program at VCSNS. The staff reviewed the FSAR

Supplement and found that the description of the Reactor Building Cooling Unit Inspection

Program is consistent with Section B.2.5 of the LRA. The staff finds that the information

contained in the FSAR Supplement presents an adequate summary of the program activities as

required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.3.7 Service Air System Inspection Program

Summary of Technical Information in the Application

The applicant’s Service Air System Inspection Program is discussed in LRA Section B.2.6, 

“Service Air System Inspection.” The applicant stated that this is a new program and therefore

summarizes the program in terms of the 10-element program as described in BTP RLSB-1 in

Appendix A of the SRP-LR. The LRA credits this inspection with detecting and characterizing

loss of material due to general corrosion in carbon steel pipe, tubing and valve body

components in the service air, building services, and instrument air systems that are exposed

internally to moist air at VCSNS. The applicant stated that this new one-time inspection activity

will detect and characterize loss of material due to general corrosion resulting from exposure to

an internal moist air environment. The Service Air System Inspection Program will use a

combination of volumetric and visual examination techniques at the most susceptible (sample)

locations (FSAR Supplement 18.2.30). The applicant stated that the Service Air System

Inspection Program will be consistent with AMP XI.M32, “One-Time Inspection” in the GALL

Report. The applicant also stated that this one-time inspection will be performed prior to the

period of extended operation. 

In Section B.2.6 of the LRA, the applicant states that the Service Air System Inspection

Program will either verify that there is no aging effect requiring management for the subject
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components, or ensure that appropriate corrective actions will be taken so that the component

intended functions will be maintained during the period of extended operation. 

Staff Evaluation

In LRA Section B.2.6, “Service Air System Inspection,” the applicant described its AMP to

manage loss of material due to general corrosion in carbon steel pipe, tubing and valve body

components in the service air (SA), building services (BS), and instrument air (IA) systems that

are exposed internally to moist air at VCSNS. Since the applicant stated that AMP B.2.6 is a

new one-time inspection consistent with GALL AMP XI.M32, the staff’s evaluation of this

program, which follows, is on the basis of the 10-element program as described in BTP

Appendix A of the SRP-LR. The 10 program elements in this GALL AMP XI.M32 for one-time

inspection supply detailed programmatic characteristics and criteria that the staff considers

necessary to provide additional assurance that either aging is not occurring, or the evidence of

aging is so insignificant that an AMP is not warranted. 

The staff reviewed the program using the guidance in BTP RLSB-1 in Appendix A of the SRPLR. The staff’s evaluation focused on managing aging effects through incorporation of the

following 10 elements from RLSB-1— program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience. The

applicant indicated that the corrective actions, confirmation process, and administrative controls

for license renewal are in accordance with the site-controlled Quality Assurance Program. The

staff’s evaluation of the applicant’s Quality Assurance Program is provided separately in

Section 3.0.4 of this SER; the evaluation of the remaining seven elements is provided below.

The staff also reviewed the FSAR Supplement to determine whether it provides an adequate

description of the program.

[Program Scope] The applicant stated that this AMP is applicable to carbon steel pipe, tubing,

and valve body components exposed to an internal moist air environment that perform the

function of maintaining pressure boundary for containment integrity in the following locations:

• service air system components in the supply line to the reactor building where the line

penetrates the containment

• service air and building services systems components used for the leak testing of the

personnel hatch, equipment hatch, and emergency personnel hatch seals

• building services system components used to supply emergency air to the personnel

hatch and emergency personnel hatch

• instrument air system components in the air intake piping upstream of the instrument air

dryers where the piping penetrates the containment 

The staff finds that the systems and components monitored by the Service Air System

Inspection Program, as listed above and in Section B.2.6 of the LRA, are within the scope of

license renewal as identified in Section 2.3 of the LRA. The scope is acceptable to the staff

because it includes those components that rely on the program for aging management.
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[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effect or to mitigate aging degradation. By letter dated March 28, 2003, the

staff noted, in RAI B.2.6-1, that accepted industry guidance and the GALL Report recommend

preventive monitoring of system air quality to ensure that oil, water, rust, dirt, and other

contaminants are kept within specified limits. Air quality should be maintained because

instruments and components may not function properly if the air is contaminated, and the

presence of oil or contaminants in the air can impact the rate and types of aging degradation.

The staff requested the applicant to describe the monitoring of air quality as it relates to

corrosion and degradation of the steel components within the scope of this program. 

In its response dated June 12, 2003, the applicant stated that the Service Air System Inspection

Program concerns specific components that are not pertinent to the quality of air supplied to

safety-related equipment. These components concern the pressure boundary function of

specific containment penetrations, containment hatch testing, and emergency air supply to the

personnel hatches. The internal environment for these components is assumed to be ambient

moist air (not dried by an air dryer). The applicant stated that the Service Air System Inspection

Program is a one-time inspection to verify that aging degradation has not occurred in some

specific, safety-related portions (containment integrity) of the SA, IA, and BS systems that are

not designed or required to be in a dry air environment. Since the applicant demonstrated how

the air quality was maintained appropriate to the systems and components within the

governance of this AMP, the staff’s request was deemed to be satisfactorily answered and RAI

B.2.6-1, is considered closed.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness as a measure of loss of material and visual evidence of

loss of material, cracking, or other age-related degradation. The staff finds the above

parameters acceptable because they are directly related to the degradation of carbon steel

components exposed to moist air-gas environments in the aforementioned systems.

[Detection of Aging Effects] The applicant stated that the AMP will use a combination of proven

volumetric and visual examination techniques to inspect for general corrosion at selected

sample locations to be determined by engineering evaluation. The applicant further stated that

this inspection will detect the presence and extent of any loss of material and cracking prior to a

loss of component intended function. 

The staff finds that these inspection techniques are sufficient to provide reasonable assurance

that the aging effect for the components will be detected before the loss of its intended function. 

The use of a one-time inspection is appropriate for inspections where degradation is possible,

but is not expected on the basis of plant-specific and industry operating experience. This onetime inspection provides for additional inspections should the corrective action process require

additional information to characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the

Service Air System Inspection Program to trend inspection results. This is a one-time inspection

used to determine if further actions are required. The staff did not identify the need for

monitoring and trending in this AMP.

[Acceptance Criteria] The applicant stated that the acceptance criterion is no unacceptable loss

of material or cracking of the subject components that could result in a loss of the component
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intended function, as determined by engineering evaluation. The staff considers this

engineering evaluation to be adequate to assure that the intended functions for components in

the Service Air System Inspection Program are maintained under all CLB design conditions

during the period of extended operation.

[Operating Experience] The applicant stated that the Service Air System Inspection Program is

a new one-time inspection for which there is no operating experience. By letter dated March 28,

2003, the staff requested, in RAI B.2.6-2, that the applicant discuss the operating experience

with the SA system, BS system, or IA system as it relates to aging degradation of these

systems. Specifically, the applicant was requested to describe operating experience related to

leaks or degradation in the service air system (re: GL 88-14) and to verify the presence or

absence of such leaks or degradation.

 In its response dated June 12, 2003, the applicant stated that the Service Air System

Inspection Program concerns specific components that are not pertinent to the quality of air

supplied to safety-related equipment and, therefore, not pertinent to the concerns of NRC GL

88-14. The applicant stated that this one-time inspection is used to verify that aging degradation

has not occurred in some specific safety-related portions (containment integrity) of the SA

system, the IA system, and the BS system that are not designed for nor required to be in, a dry

air environment. The applicant stated that the carbon steel SA and IA system components that

are managed by this program, function as pressure boundaries for a containment penetration

and are leak tested under 10 CFR 50 Appendix J. Operating experience at VCSNS for the SA

and IA components managed by this program reveals no history of aging degradation for the

internal surfaces. The applicant also stated that the carbon steel BS system components that

are managed by this program are the hatch seal test blocks and the emergency air valves for

the hatches. Operating experience at VCSNS for the BS components managed by this program

reveals no history of aging degradation for the internal surfaces. Since the applicant verified in

its response that the VCSNS operating history reveals no history of leaks or degradation in

internal surfaces of managed components in the SA system, the IA system, or the BS system,

the staff’s question was deemed to be satisfactorily answered and RAI B.2.6-2, is considered

closed. 

Section 18.2.30 of Appendix A to the LRA contains the applicant’s FSAR Supplement for the

Service Air System Inspection Program at VCSNS. The staff reviewed the FSAR Supplement

and found that the description of the Service Air System Inspection Program is consistent with

Section B.2.6 of the LRA. The staff finds that the information contained in the FSAR

Supplement presents an adequate summary of the program activities, as required by 

10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).
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3.3.2.3.8 Waste Gas System Inspection Program

Summary of Technical Information in the Application

The applicant’s Waste Gas System Inspection Program is discussed in LRA Section B.2.8, 

“Waste Gas System Inspection.” The applicant stated that this is a new program and therefore

summarized the program in terms of the 10-element program as described in BTP Appendix A

of the SRP-LR. The LRA credits this inspection with managing loss of material due to crevice

and pitting corrosion and cracking due to SCC in unmonitored and uncontrolled treated water,

and cracking due to SCC in gas environments at the VCSNS. The applicant stated that this

one-time inspection activity will determine if aging management is required for certain stainless

steel components of the gaseous waste processing system. This inspection will detect and

characterize loss of material due to crevice and pitting corrosion in portions of the system

exposed to unmonitored and uncontrolled treated water, and cracking due to SCC in portions of

the system containing gas, as well as those containing untreated and unmonitored water. The

Waste Gas System Inspection Program will use a combination of volumetric and visual

examination techniques at the most susceptible (sample) locations (FSAR supplement 18.2.39).

The applicant stated that the Waste Gas System Inspection will be consistent with AMP XI.M32,

“One-Time Inspection”, in the GALL Report. The applicant also stated that this one-time

inspection will be performed prior to the period of extended operation.

In Section B.2.8 of the LRA, the applicant concluded that the Waste Gas System Inspection

Program will either verify that there are no aging effects requiring management for the subject

components, or ensure that appropriate corrective actions will be taken so that the component

intended functions will be maintained during the period of extended operations.

Staff Evaluation

In LRA Section B.2.8, “Waste Gas System Inspection,” the applicant described its AMP to

manage loss of material due to crevice and pitting corrosion and cracking due to SCC in

unmonitored and uncontrolled treated water, and cracking due to SCC in gas environments at

the VCSNS. Since The applicant stated that AMP B.2.8 is a new one-time inspection consistent

with GALL AMP XI.M32, the staff’s evaluation of this program, which follows, is on the basis of

the 10-element program described in BTP Appendix A of the SRP-LR. The 10 program

elements in this GALL AMP for one-time inspection supply detailed programmatic

characteristics and criteria that the staff considers necessary to provide additional assurance

that either aging is not occurring, or the evidence of aging is so insignificant that an AMP is not

warranted. 

The staff reviewed the program using the guidance in BTP RLSB-1 in Appendix A of the SRPLR. The staff’s evaluation focused on management of aging effects through incorporation of the

following 10 elements from RLSB-1— program scope, preventive actions, parameters

monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria,

corrective actions, confirmation process, administrative controls, and operating experience. The

applicant indicated that the corrective actions, confirmation process, and administrative controls

for license renewal are in accordance with the site-controlled Quality Assurance Program. The

staff’s evaluation of the applicant’s Quality Assurance Program is provided separately in

Section 3.0.4 of this SER; the evaluation of the remaining seven elements is provided below.
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The staff also reviewed the FSAR Supplement to determine whether it provides an adequate

description of the program.

[Program Scope] The applicant stated that this AMP is applicable to the following gaseous

waste processing system components — stainless steel pipe and valve bodies exposed to an

unmonitored and uncontrolled treated water environment, and stainless steel tube coils and

manifolds in the hydrogen recombiner cooler condenser exposed to a gas environment.

Further, the applicant stated that the unmonitored and uncontrolled treated water environment

consists of condensation that forms within the waste gas decay tanks and is periodically

pumped to the volume control tank in the CVCS. The applicant stated that the gas environment

is mostly nitrogen, with trace amounts of hydrogen, oxygen, and fission product gases and

water vapor from the recombination of hydrogen and oxygen. The staff finds that the

components monitored by the Waste Gas System Inspection Program, as listed above and in

Section B.2.8 of the LRA, are within the scope of license renewal as identified in Section 2.3 of

the LRA. The scope is acceptable to the staff because it includes those components that rely

on the program for aging management.

[Preventive Actions] The applicant stated that no actions are taken as part of this program to

prevent the aging effects or to mitigate aging degradation. The staff did not identify the need for

preventive actions in this AMP.

[Parameters Monitored or Inspected] The applicant stated that the parameters inspected as

part of this AMP include wall thickness as a measure of loss of material, and visual evidence of

loss of material, cracking, or other age-related degradation. The staff finds the above

parameters acceptable because they are directly related to the degradation of stainless steel

components exposed to unmonitored and uncontrolled treated water or gas environments in the

abovementioned systems.

[Detection of Aging Effects] The applicant stated that the AMP will use a combination of proven

volumetric and visual examination techniques to inspect for general corrosion at selected

sample locations to be determined by engineering evaluation. The applicant further stated that

results of the inspection will be applied to the remainder of the components within the scope of

the inspection activity. The applicant further stated that the sample population should consist of

at least one susceptible location in the stainless steel waste gas decay tank drain piping

(preferably at a low point), and at least one susceptible location in the stainless steel tube-side

inlet piping to the hydrogen recombiner cooler condenser. 

The staff finds that these inspection techniques are sufficient to provide assurance that the

aging effects for the components managed by the Waste Gas System Inspection will be

detected before a component has lost its intended function. The use of a one-time inspection is

appropriate for inspections where degradation is possible, but is not expected on the basis of

plant-specific and industry operating experience. This one-time inspection provides for

additional inspections should the corrective action process require additional information to

characterize the aging effects.

[Monitoring and Trending] The applicant stated that no actions are taken as a part of the Waste

Gas System Inspection Program to trend inspection results. This is a one-time inspection used

to determine if further actions are required. The staff did not identify the need for monitoring

and trending in this AMP.
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[Acceptance Criteria] The applicant stated that the acceptance criterion is no unacceptable loss

of material or cracking of the subject components that could result in a loss of the component

intended function, as determined by engineering evaluation. The staff considers this

engineering evaluation to be adequate to assure that the intended functions for components in

the Waste Gas System Inspection Program are maintained under all CLB design conditions

during the period of extended operation.

[Operating Experience] The applicant stated that the Waste Gas System Inspection Program is

a new one-time inspection for which there is no operating experience. By letter dated March 28,

2003, the staff requested, in RAI B.2.8-1, that the applicant discuss the operating experience

with the gaseous waste processing system as it relates of aging degradation of these systems.

In its response dated June 12, 2003, the applicant stated that the operating experience, both

site-specific and industry-wide, was researched to identify the possible aging effects for various

material-environment combinations; the results are retained at VCSNS. This one-time Waste

Gas System Inspection Program was developed because it was determined that the aging

effects were possible, and not because they were found at VCSNS. The applicant further

stated that portions of the waste gas (WG) system managed by the Waste Gas Systems

Inspection Program are in scope because they are pressure boundaries for the component

cooling water (CC) system and the chemical and volume control (CS) system. The recombiner

heat exchangers are in scope for license renewal because the tube coils and tube manifolds

form a pressure boundary with the CC system, which is the cooling medium for the heat

exchangers. 

The applicant verified that VCSNS operating experience for the heat exchanger components

managed by this program reveals no history of aging degradation for the internal surfaces. The

applicant stated that WG valves and piping, managed by the Waste Gas System Inspection

Program and allowing the transfer of condensation formed in the waste gas decay tanks to the

volume control tank of the CS system, are in scope for license renewal because they form a

pressure boundary with the CC System. The applicant finally verified that VCSNS operating

experience for these components managed by the Waste Gas System Inspection Program

reveals no history of aging degradation for the internal surfaces. Since the applicant

demonstrated in its response that the VCSNS operating history reveals no history of aging

degradation for the components managed by the Waste Gas System Inspection Program, the

staff’s request was deemed to be satisfactorily met and RAI B.2.8-1, is considered closed. 

Section 18.2.39 of Appendix A to the LRA contains the applicant’s FSAR Supplement for the

Waste Gas System Inspection Program at VCSNS. The staff reviewed the FSAR Supplement

and found that the description of the Waste Gas System Inspection Program is consistent with

Section B.2.8 of the LRA. The staff finds that the information contained in the FSAR

Supplement presents an adequate summary of the program activities, as required by 10 CFR

54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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
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operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4 Aging Management Review of Plant-Specific Auxiliary Systems Components 

The following sections provide the results of the staff’s evaluation of the adequacy of aging

management for components in each of the auxiliary systems.

3.3.2.4.1 Air Handling And Local Ventilation and Cooling Systems

Summary of Technical Information in the Application

The description of the air handling and local ventilation and cooling systems can be found in

Section 2.3.3.1 of this SER. The passive, long-lived components in this system that are subject

to an AMR are identified in LRA Table 2.3-18. The components, aging effects, and AMPs are

provided in LRA Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the air handling and local ventilation and cooling systems are described in

Section 2.3.3.1 of the LRA as being within the scope of license renewal, and subject to an

AMR. Tables 2.3-18, 3.3-1 and 3.3-2 of the LRA and tables entitled “Virgil C. Summer Nuclear

Station Database AMR Query, " list individual components of the system including air handling

units; plenums; cooling coils, including fins, headers, tubes, and tubesheets; ductwork,

including fan and plenum housings; flexible connections; exhaust air relief heads; mechanical

expansion joints, including expansion boots and retaining rings; heating coils; pipe; tube and

tube fittings; and valves bodies. 

Carbon steel components are subject to the aging effects of loss of material due to pitting,

crevice, galvanic, and general corrosion and cracking due to SCC of internal surfaces from the

treated water environment. Internal surfaces of carbon steel are also subject to loss of material

from crevice corrosion, erosion, galvanic corrosion, general corrosion, MIC, pitting corrosion,

and heat exchanger fouling from biological materials and particulates due to exposure to raw

water. External surfaces of carbon steel and galvanized steel are also subject to the aging

effect of loss of material from exposure to sheltered (due to boric acid corrosion) and ventilation

environments (due to general corrosion for carbon steel). However, ductwork made from

galvanized steel exposed to the ventilation or yard environment experiences no aging effects. 

Stainless steel components are subject to the aging effect of loss of material from MIC due to

exposure to a sheltered environment. Exposure of internal or external surfaces of stainless

steel components to a reactor building or ventilation environment has no aging effect. Copper

components are subject to the aging effects of heat exchanger fouling from particulates and

loss of material from crevice corrosion, erosion-corrosion, galvanic corrosion, and pitting

corrosion due to exposure to raw and treated water environments. Components made of

copper exposed to a reactor building and ventilation environment experience the aging effects

of heat exchanger fouling due to particulates and loss of material from boric acid and galvanic

corrosion. Exposure of hypalon and rubber components to a reactor building environment is

subject to the aging effect of cracking from thermal and radiation embrittlement. The exposure

of neoprene components to a sheltered environment is also subject to the aging effect of
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cracking from thermal and radiation embrittlement. Exposure of hypalon, rubber, and neoprene

components to a ventilation air environment results in aging effects. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the air handling and local ventilation

and cooling systems:

 Chemistry Program (B.1.4)

 Boric Acid Corrosion Surveillances Program (B.1.2)

 Service Water System Reliability and In-Service Testing Program (B.1.9)

 Preventive Maintenance Activities — Ventilation Systems Inspections (B.1.26)

 Inspections for Mechanical Components Program (B.2.11)

 Maintenance Rule Structures Program (B.1.18)

 Heat Exchanger Inspections Program (B.2.12)

A description of these AMPs is provided in Appendix B of the LRA. The applicant concluded

that the effects of aging associated with the components of the air handling and local ventilation

and cooling systems will be adequately managed by these AMPs during the period of extended

operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.1 and Tables 2.3-18, 3.3-1, and 3.3-2 in the

LRA, as well as in the supplementary table and notes, entitled “Virgil C. Summer Nuclear

Station Database AMR Query.” During its review, the staff determined that additional

information was needed. 

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of the

applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is characterized as

resolved.

For components in this system listed in the supplemental table and notes, entitled “Virgil C. 

Summer Nuclear Station Database AMR Query,” the applicant indicated that galvanized steel

ductwork in a "yard" environment has no identified aging effects and does not require an AMP.

The staff finds that this conclusion may not be justified because of factors associated with

corrosive agents in the local environment and rainfall. By letter dated March 28, 2003, the staff

requested, in RAI 3.3.2.4.1-1, the applicant to provide justification for the conclusion that

galvanized steel ductwork in a "yard" environment has no identified aging effects.

In its response dated June 12, 2003, the applicant stated that VCSNS is located well inland and

is located in an area where forestry is the primary commercial activity. VCSNS does not see salt

or other corrosive materials in the air from agriculture or industry. Crevice and pitting corrosion

are not considered to be aging effects for external surfaces because the ambient environment
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does not contain contaminants of sufficient quantity to concentrate on external surfaces such

that pitting or crevice corrosion would occur. Rainwater analyses reveal a concentration of less

than 10 ppm for chlorides and sulfates.

The applicant further stated that zinc is used because of its corrosion resistance in an external

environment and by its galvanic protection of the base metal when the coating is damaged. The

components in question are the air exhaust heads located on the roofs of the control building

and the intermediate building. Because of the relative lack of traffic and activity in these areas,

damage to the zinc coating is not expected beyond small nicks, which are protected by the selfhealing properties of the zinc coating. General corrosion of galvanized steel is not an aging

mechanism because the ambient temperature in the area where these components are located

is less than 140 oF.

On the basis of its review, the staff finds the applicant’s response to RAI 3.3.2.4.1-1 acceptable

because (1) VCSNS does not see salt or other corrosive materials in the air from agriculture or

industry, (2) rainwater analyses reveal a concentration of less than 10 ppm for chlorides and

sulfates, and (3) the ambient temperature in the area where these components are located is

less than 140 o

F.

For components in this system list in the supplemental table and notes, entitled “Virgil C. 

Summer Nuclear Station Database AMR Query,” the applicant stated that carbon steel cooling

coil headers in a treated water environment are subject to SCC. However, no AMP has been

provided to address this aging effect. By letter dated March 28, 2003, the staff requested, in

RAI 3.3.2.4.1-2, the applicant to explain why no AMP has been provided to address this aging

effect.

In its response dated June 13, 2003, the applicant stated that according to industry references,

SCC of carbon and low-alloy steel components is not considered to be an applicable aging

mechanism in a treated water environment. Industry data do not exhibit widespread incidence

of SCC in low-strength carbon steels; however, there was a reported case suspected to be

nitrate-induced SCC of carbon steel in a treated water system. VCSNS has conservatively listed

SCC as a possible aging mechanism in certain closed systems where nitrites are added as a

corrosion inhibiter. In these closed systems, there is no other pathway for the introduction of

contaminants beyond the corrosion products of the system itself. Nitrites are added as a

corrosion inhibitor by the Chemistry Program at levels within EPRI guidelines; therefore,

VCSNS maintains that the Chemistry Program adequately manages SCC of carbon steel

components in a treated water environment.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the Chemistry Program will be used to manage SCC of

carbon steel components in a treated water environment. However, the staff questioned

whether a one-time inspection is used to verify the effectiveness of the Chemistry Program. The

staff notes that the response to RAI 3.3.2.4.4-1 clarified that a one-time inspection will be

conducted in low-flow areas of various closed, treated water systems to demonstrate the

effectiveness of the Chemistry Program.

In its response dated September 2, 2003, the applicant stated that VCSNS has conservatively

listed SCC as a possible aging mechanism in certain closed systems where nitrites are added

as a corrosion inhibiter. Nitrites do not cause SCC of carbon and low-alloy steel components;
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however, nitrites can convert to nitrates in the presence of microorganisms. Nitrate levels in

these systems are typically in the range of 300 ppm. According to EPRI guidelines, nitrateinduced SCC occurs at levels above 10,000 ppm. In these closed systems, there is no other

pathway for the introduction of contaminants beyond the corrosion products of the system itself.

Nitrites are added as a corrosion inhibiter by the Chemistry Program at levels within EPRI

guidelines; therefore, VCSNS maintains that the Chemistry Program adequately manages SCC

of carbon steel components in a treated water environment. The applicant also stated that onetime inspections will be performed in low-flow areas prior to the period of extended operation to

verify the effectiveness of the Chemistry Program to manage aging in the various chemistry

regimes within the scope for license renewal. 

On the basis of its review, the staff finds the applicant’s response acceptable because that the

applicant has committed to performing one-time inspections in low-flow areas prior to the period

of extended operation to verify the effectiveness of the Chemistry Program to manage aging in

the various chemistry regimes within the scope for license renewal. 

The aging effects identified in the LRA for the components in the air handling and local

ventilation and cooling systems are consistent with industry operating experience for the

materials and environments listed. The staff finds that all the plausible aging effects were

identified and that the aging effects listed are appropriate for the combination of materials and

environments specified.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the air handling

and local ventilation and cooling systems:

• Chemistry Program (3.0.3.2)

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Service Water System Reliability and In-Service Testing Program (3.3.2.3.1)

• Preventive Maintenance Activities — Ventilation Systems Inspections Program

(3.3.2.3.3)

• Inspections for Mechanical Components Program (3.0.3.7)

• Maintenance Rule Structures Program (3.0.3.4)

• Heat Exchanger Inspections Program (3.0.3.8)

The Chemistry Program, Boric Acid Corrosion Surveillances Program, Inspections for

Mechanical Components Program, Maintenance Rule Structures Program, and Heat Exchanger

Inspections Program are credited with managing the aging effects of several components in

different structures and systems and are, therefore, considered common AMPs. The staff has

evaluated these common AMPs and has found them to be acceptable for managing the aging

effects identified for this system. The staff’s evaluation of these AMPs is documented in

Sections 3.0.3.1, 3.0.3.2 , 3.0.3.4, 3.0.3.7, and 3.0.3.8 of this SER.

The staff evaluated the system-specific AMPs of Service Water System Reliability and InService Testing Program and Preventive Maintenance Activities — Ventilation Systems

Inspections Program and finds them to be acceptable for managing the aging effects identified

for this system. The staff’s evaluation of these AMPs is documented in Sections 3.3.2.3.1 and

3.3.2.3.3 of this SER.
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After evaluating the applicant’s AMR for each of the components in the air handling and local

ventilation and cooling systems, the staff evaluated the AMPs listed above to determine if they

are appropriate for managing the identified aging effects for this system. For those components

identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the AMPs credited in the LRA for the components

in the air handling and local ventilation and cooling systems will effectively manage or monitor

the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.3.2.4.2 Boron Recycle System 

Summary of Technical Information in the Application

The description of the boron recycle system can be found in Section 2.3.3.2 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-19. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and

3.3-2. 

Aging Effects:

Components of the boron recycle system are described in Section 2.3.3.2 of the LRA as being

within the scope of license renewal and subject to an AMR. Tables 2.3-19, 3.3-1, and 3.3-2 of

the LRA, and the supplementary table and notes, entitled “Virgil C. Summer Nuclear Station

Database AMR Query,” list system components and component group. 

The component groups in this category of the boron recycle system listed by the applicant in

the VCSNS LRA include condensers (XEV0008-CN1, XEV0008-CN2) recycle evaporatorchannel head; condensers (XEV0008-CN1, XEV0008-CN2) recycle evaporator-channel head

(Nozzles); condensers (XEV0008-CN1, XEV0008-CN2) recycle evaporator-tubes; condensers

(XEV0008-CN1, XEV0008-CN2) recycle evaporator-tubesheet; heat exchanger (XEV0008-

HE2) recycle evaporator-shell; heat exchanger (XEV0008-HE2) recycle evaporator-shell

(Nozzles); heat exchanger (XEV0008-HE2), recycle evaporator-tubes; heat exchanger

(XEV0008-HE2) recycle evaporator-tubesheet; heat exchanger (XHE0021) recycle evaporate

concentrates sample-manifolds; heat exchanger (XHE0021) recycle evaporate concentrates

sample-shell; heat exchanger (XHE0021) recycle evaporate concentrates sample-tubes; and

valves (body only). 

Carbon steel and stainless steel components exposed to borated water, treated water, or

sheltered environments are subject to the aging effects of loss of material from general (for

carbon steel only), pitting, and crevice corrosion, boric acid corrosion, and galvanic corrosion
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(for carbon steel only) and cracking from SCC (for stainless steel only). Stainless steel

components exposed to a sheltered environment in the boron recycle system experience no

aging effects. Carbon steel exposed to a sheltered environment may experience loss of

material due to general corrosion.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the boron recycle system:

• Chemistry Program (B.1.4) 

• Boric Acid Corrosion Surveillances Program (B.1.2)

• Inspections for Mechanical Components (B.2.11)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the boron recycle system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.2 and Tables 2.3-19, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station Database AMR Query”

and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in the supplement and

finds the applicant’s identification of the applicable aging effects of carbon steel and stainless

steel components acceptable. The applicant’s conclusion that the stainless steel valves (body

only) in the sheltered environment experience no aging effects is also acceptable. 

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the boron recycle

system:

• Chemistry Program (3.0.3.2) 

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Inspections for Mechanical Components (3.0.3.7)

The Chemistry Program and the Boric Acid Corrosion Surveillances Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff has evaluated these common AMPs and has

found them to be acceptable for managing the aging effects identified for this system. The

staff’s evaluation of these AMPs is documented in Sections 3.0.3.1 and 3.0.3.2, respectively, of

this SER.

After evaluating the applicant’s AMR for each of the components in the boron recycle system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report. 
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For the components identified in LRA Table 3.3-2 , the staff verified that the applicant credited

AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the boron

recycle system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.3 Building Services System

Summary of Technical Information in the Application

The description of the building services system can be found in Section 2.3.3.3 of this SER. 

The passive, long-lived components in this system that are subject to an AMR are identified in

LRA Table 2.3-20. The components, aging effects, and AMPs are provided in LRA Tables 3.3-

1 and 3.3-2. 

Aging Effects:

Components in the building services system are described in Section 2.3.3.3 of the LRA as

being within the scope of license renewal and subject to an AMR. Tables 2.3-20, 3.3-1, and

3.3-2 of the LRA, and the supplementary table and notes, entitled Virgil C. Summer Nuclear

Station Database AMR Query,” list system components and component group. 

The component groups in this category in the building services system listed by the applicant in

the VCSNS LRA include pipe and fittings, tube and tube fittings, and valves (body only). The

applicant stated that the stainless steel components exposed to air-gas, reactor building,

ventilation, and sheltered environments in building services experience no aging effect. Carbon

steel components in the air-gas and sheltered environments are subject to the aging effects of

loss of material due to galvanic corrosion and general corrosion. Carbon steel components

exposed to a sheltered environment are subject to the aging effect of loss of material due to

boric acid corrosion. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the building services system:

• Boric Acid Corrosion Surveillances Program (B.1.2)
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 Service Air System Inspection Program (B.2.6)

 Inspections for Mechanical Components Program (B.2.11)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the building services system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.3 and Tables 2.3-20, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled Virgil C. Summer Nuclear Station Database AMR Query”

and Virgil C. Summer Nuclear Station Database AMR Query Notes” in the supplement. During

its review, the staff found that additional information was needed.

In the LRA Table 3.3-2, Item 11, the applicant stated that no aging effect was identified for the

stainless steel piping and fittings in the air-gas environment. However, in the AMR Query

Notes, A-BS-c,” the applicant stated the following:

“Loss of material due to corrosive impacts of alternate wetting and drying are aging effects for stainless steel

exposed to a ventilation environment, and subject to alternate wetting and drying that may concentrate

contaminates. A review of the Air-Gas System Screening Report [TR00160-006], Attachment I and associated

references determined that there are stainless steel components within the license renewal evaluation

boundaries of the BS system, which are exposed to alternative wetting and drying in the ventilation

environment. Therefore, loss of materials and cracking due to corrosive impacts of alternative wetting and

drying are not aging effects requiring management of stainless steel components/component types of the BS

system exposed to the ventilation environment.”

By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.3-1, the applicant to clarify,

with justification, the above quoted statements in LRA Table 3.3-2, Item 11 and the AMR Query

Notes “A-BS-c.”

In its response dated June 12, 2003, the applicant stated that Notes A-BS-c” are incorrect and

that there are no stainless steel components within the license renewal evaluation boundaries

of the building services system.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has clarified that Notes A-BS-c” are incorrect and that there are no stainless steel

components within the license renewal evaluation boundaries of the building services system. 

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the building

services system:

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

 Service Air System Inspection Program (3.3.2.3.7)

 Inspections for Mechanical Components Program (3.0.3.7)
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The Boric Acid Corrosion Surveillances and the Inspections for Mechanical Components AMPs

are credited with managing the aging effects of several components in different structures and

systems and are, therefore, considered common AMPs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system. The staff’s evaluation of these AMPs is documented in Sections 3.0.3.1 and

3.0.3.7, respectively, of this SER.

The staff has evaluated the system-specific Service Air System Inspection AMP and has found

it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of this AMP is documented in Section 3.3.2.3.7 of this SER.

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.4 Chilled Water System

Summary of Technical Information in the Application

The description of the chilled water system can be found in Section 2.3.3.4 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-21. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and

3.3-2. 

Aging Effects:

Tables 2.3-21, 3.3-1, and 3.3-2 of the LRA and the table entitled Virgil C. Summer Nuclear

Station Database AMR Query,” in the supplement list individual components of the system

including pumps and pump casings, condenser shells, fins, tubes, tubesheets, water boxes,

evaporator shells, orifices, pipe and fittings, tube and tube fittings, valve bodies, compressor

housings, flow control chambers, eductor pumps, lubrication system eductors, filters, purge

units, tanks, and sight glasses.

Carbon steel components are subject to the aging effects of loss of material due to crevice

corrosion, galvanic corrosion, general corrosion, and pitting corrosion and cracking of internal

surfaces due to SCC from a treated water environment. Internal surfaces of carbon steel are

also subject to loss of material due to galvanic corrosion, general corrosion, MIC, and pitting

corrosion, and heat exchanger fouling from particulates and biological materials due to

exposure to raw water. External surfaces of carbon steel are also subject to the aging effect of

loss of material due to galvanic corrosion, general corrosion, and pitting corrosion from

exposure to sheltered and yard environments. Exposure of internal or external carbon steel

surfaces to oil environments has no aging effects. Internal surfaces of stainless steel
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components are subject to the aging effect of loss of material from crevice corrosion and pitting

corrosion due to exposure to a treated water environment. Exposure of internal or external

surfaces of stainless steel components to a sheltered or oil environment has no aging effect. 

Cast iron external surfaces exposed to sheltered environments are subject to the aging effect of

loss of material from galvanic corrosion, general corrosion, and pitting corrosion. Exposure of

internal or external surfaces of cast iron or copper components to an air or dry gas environment

has no aging effect. Internal surfaces of copper components are subject to the aging effects of

heat exchanger fouling from particulates, and biological materials, and loss of material due to

crevice corrosion, erosion, MIC, and pitting corrosion from exposure to raw and treated water

environments. Exposure of glass components to an air, dry gas, or sheltered environment

results in no aging effects. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the chilled water system:

 Chemistry Program (B.1.4)

 Inspections for Mechanical Components Program ( B.2.11)

 Service Water System Reliability and In-Service Testing Program (B.1.9)

 Above Ground Tank Inspection Program (B.2.1)

 Heat Exchanger Inspections Program (B.2.12)

 Maintenance Rule Structures Program (B.1.18)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the chilled water system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.4 and Tables 2.3-21, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled “Virgil C. Summer Nuclear Station Database AMR Query”

and “Virgil C. Summer Nuclear Station Database AMR Query Notes” in the supplement. During

its review, the staff determined that additional information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

LRA Table 3.3-2, Item 19 credits the Above Ground Tank Inspection Program (B.2.1), and the

Chemistry Program (B.1.4), for managing loss of material and cracking of the internal surfaces

of the chilled water expansion tanks (XTK0174A/B) during the period of extended operation. 

The staff identified a concern that this inspection may not be adequate to detect significant tank

degradation in inaccessible locations, such as tank bottom surfaces. By letter dated March 28,

2003, the staff requested, in RAI 3.3.2.4.4-1, the applicant to provide assurance that significant
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tank degradation in inaccessible locations, such as tank bottom surfaces, is adequately

managed.

In its response by letter dated June 12, 2003, the applicant provided the following clarification.

The Above Ground Tank Inspection Program manages the internal surfaces of tanks. This

program inspects the tanks at the liquid/air-gas interface where degradation is more likely to be

found due to alternate wetting and drying which causes contaminants to concentrate. The

Chemistry Program has proven effective in managing aging effects in the treated water

environment. The applicant further stated that prior to the period of extended operation, onetime inspections will be conducted in low-flow areas of various closed, treated water systems to

demonstrate the effectiveness of the Chemistry Program.

On the basis of its review, the staff finds that the applicant’s response to RAI 3.3.2.4.4-1, is 

acceptable because, prior to the period of extended operation, one-time inspections will be

conducted in low-flow areas of various closed, treated water systems to demonstrate the

effectiveness of the Chemistry Program. All issues associated with RAI 3.3.2.4.4-1, are

considered resolved.

LRA Table 3.3-1, Item 5 credits the Inspections of Mechanical Components Program (B.2.11)

for managing loss of material of the external surfaces of the carbon steel chilled water

expansion tanks (XTK0174A/B) during the period of extended operation. The staff identified

that this conclusion does not appear adequate to detect significant tank degradation in

inaccessible locations, such as under insulation or the external tank bottom surfaces. By letter

dated March 28, 2003, the staff requested, in RAI 3.3.2.4.4-2, the applicant to provide

assurance that significant tank degradation in the inaccessible locations of these tanks, such as

segments under insulation or the external tank bottom surfaces, are adequately managed.

In its response by letter dated June 12, 2003, the applicant provided the following clarification. 

External surfaces of tanks will be managed by the Inspections for Mechanical Components

Program. Tank foundations will be inspected by the Maintenance Rule Structures Program. 

The chilled water expansion tanks are elevated such that the tank bottoms are exposed. Also,

VCSNS operating experience has identified an instance of pitting of an insulated external

surface for the chilled water system; therefore, the Inspections for Mechanical Components

Program will involve removal of insulation from portions of the chilled water system.

On the basis of its review, the staff finds that the applicant’s response to RAI 3.3.2.4.4-2 is

acceptable because the chilled water expansion tanks are elevated such that the tank bottoms

are exposed, and that the Inspections for Mechanical Components Program will involve removal

of insulation from portions of the chilled water system. All issues associated with RAI

3.3.2.4.4-2, are considered resolved.

The table entitled, Virgil C. Summer Nuclear Station Database AMR Query,” states that carbon

steel components, such as pump casings, evaporator tubesheets, and water boxes, valve

bodies, pipe and fittings, and tanks in a treated water environment are subject to SCC. The

staff finds that the Chemistry Program may not be adequate to manage this aging effect

because it does not contain a one-time inspection of these components at susceptible locations

to verify the absence of cracking and the effectiveness of the Chemistry Program. By letter

dated March 28, 2003, the staff requested, in RAI 3.3.2.4.4-3, the applicant to justify the

absence of an inspection/verification activity for the Chemistry Program.
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In its response by letter dated June 12, 2003, the applicant stated that according to industry

references, SCC of carbon and low-alloy steel components is not considered to be an

applicable aging mechanism in a treated water environment. Industry data do not exhibit

widespread incidence of SCC in low-strength carbon steels; however, there was a reported

case suspected to be nitrate-induced SCC of carbon steel in a treated water system. VCSNS

has conservatively listed SCC as a possible aging mechanism in certain closed systems where

nitrites are added as a corrosion inhibitor. In these closed systems, there is no other pathway

for the introduction of contaminants beyond the corrosion products of the system itself. The

applicant stated that nitrites are added as a corrosion inhibitor by the Chemistry Program at

levels within EPRI guidelines; therefore, VCSNS maintains that the Chemistry Program

adequately manages SCC of carbon steel components in a treated water environment.

On the basis of its review of the above information, the staff further requested the applicant to

clarify whether any aging management activity is used to verify the absence of cracking and the

effectiveness of the Chemistry Program and if so, what AMP is used. Otherwise, the applicant

was requested to provide the justification for not verifying the effectiveness of the Chemistry

Program.

In its response by letter dated September 2, 2003, the applicant stated that VCSNS has

conservatively listed SCC as a possible aging mechanism in certain closed systems where

nitrites are added as a corrosion inhibitor. Nitrites do not cause SCC of carbon and low-alloy

steel components; however, nitrites can convert to nitrates in the presence of microorganisms. 

Nitrate levels in these systems are typically in the range of 300 ppm. According to EPRI

guidelines, nitrate-induced SCC occurs at levels above 10,000 ppm. In these closed systems,

there is no other pathway for the introduction of contaminants beyond the corrosion products of

the system itself. Nitrites are added as a corrosion inhibitor by the Chemistry Program at levels

within EPRI guidelines. In addition, the applicant stated that one-time inspections will be

performed in low-flow areas prior to the period of extended operation to verify the effectiveness

of the Chemistry Program to manage aging in the various chemistry regimes within the scope

for license renewal. 

On the basis of its review, the staff finds that the applicant’s response dated June 12, 2003, as

well as the applicant’s supplemental response dated September 2, 2003, acceptable because

the applicant has committed to perform one-time inspections in low-flow areas prior to the

period of extended operation to verify the effectiveness of the Chemistry Program to manage

aging in the various chemistry regimes within the scope for license renewal. All issues

associated with RAI 3.3.2.4.4-3, are considered resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the chilled water system SSCs to the environments described in Tables

2.3-21, 3.3-1, and 3.3-2 are consistent with industry experience for these combinations of

materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the chilled water system.

Aging Management Programs:
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The applicant credited the following AMPs for managing the aging effects in the chilled water

system:

 Chemistry Program (3.0.3.2)

 Inspections for Mechanical Components Program (3.0.3.7)

 Service Water System Reliability and In-Service Testing Program (3.3.2.3.1)

 Above Ground Tank Inspection Program (3.0.3.5)

 Heat Exchanger Inspection Program (3.3.0.8)

 Maintenance Rule Structures Program (3.0.3.4)

The Chemistry Program, Inspections for Mechanical Components Program, Above Ground

Tank Inspection Program, Heat Exchanger Inspections Program, and Maintenance Rule

Structures Program are credited with managing the aging effects of several components in

different structures and systems and are, therefore, considered common AMPs. The staff has

evaluated these common AMPs and found them to be acceptable for managing the aging

effects identified for this system. The staff’s evaluation of these AMPs is documented in

Sections 3.0.3.2, 3.0.3.4, 3.0.3.5, 3.0.3.7, and 3.3.0.8, respectively, of this SER. 

The staff has evaluated the system-specific Service Water System Reliability and In-Service

Testing Program and finds it to be acceptable for managing the aging effects identified for this

system. The staff’s evaluation of this AMP is documented in Section 3.3.2.3.1 of this SER.

After evaluating the applicant’s AMR for each of the components in the chilled water system,

the staff evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL Report. 

For the components identified in LRA Table 3.3-2, the staff verified that the applicant credited

AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the chilled

water system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.5 Circulating Water System

As described in Section 2.3.3.5 of the LRA, the applicant’s scoping and screening review

concluded that there are no mechanical components/component types required for the
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circulating water system to perform its system intended function; therefore, no AMR is required. 

The staff’s evaluation of the scoping and screening process is documented in Section 2.3.3.5 of

this SER.

3.3.2.4.6 Component Cooling Water System

Summary of Technical Information in the Application

The description of the sampling system can be found in Section 2.3.3.6 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-22. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and

3.3-2. 

Aging Effects:

Components of the component cooling system are described in Section 2.3.3.6 of the LRA as

being within the scope of license renewal and subject to an AMR. Tables 2.3-22, 3.3-1, and

3.3-2 of the LRA, and the supplementary table and notes, entitled “Virgil C. Summer Nuclear

Station Database AMR Query,” list individual components of the system including pipes, valve

bodies, flex hoses, heat exchangers, coolers, tanks, orifices, thermowells/piping, pump casings,

and tube/tube fittings. 

Stainless steel components are identified as being subject to heat exchanger fouling due to

particulates and biological materials (for raw water), cracking due to SCC, and loss of material

due to crevice corrosion (for treated water), erosion, MIC, and pitting corrosion (for treated

water) from exposure to the environments of raw water and treated water. Exposure of

stainless steel to sheltered and reactor building environments has no aging effects. Carbon

steel components are subject to the aging effect of loss of material due to galvanic corrosion,

general corrosion, pitting corrosion, and crevice corrosion from an environment of treated

water. Carbon steel can also experience the aging effects of loss of material due to crevice

corrosion, erosion, galvanic corrosion, general corrosion, MIC, and pitting corrosion, and heat

exchanger fouling due to particulates and biological materials from raw water. Carbon steel is

also subject to loss of material from external surfaces due to boric acid corrosion from exposure

to sheltered and reactor building environments. Exposure of carbon steel components to a

ventilation environment leads to the aging effect of loss of material from general corrosion. 

Copper-nickel exposed to a treated water environment is subject to the aging effects of heat

exchanger fouling from particulates and loss of material from crevice corrosion, galvanic

corrosion, and pitting corrosion. Exposure of carbon-nickel and aluminum components to a

ventilation environment leads to the aging effect of heat exchanger fouling from particulates. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the component cooling system:

 Chemistry Program (B.1.4)

 Boric Acid Corrosion Surveillances Program (B.1.2)

 Service Water System Reliability and In-Service Testing Program (B.1.9)

 Above Ground Tank Inspection Program (B.2.1)

 Heat Exchanger Inspections Program (B.2.12)
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 Maintenance Rule Structures Program (B.1.18)

 Preventive Maintenance Activities—Ventilation Systems Inspections Program (B.1.26)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the component cooling system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.6 and Tables 2.3-22, 3.3-1, and 3.3-2 in the

LRA, as well as in the supplementary table and notes, entitled Virgil C. Summer Nuclear

Station Database AMR Query.” During its review, the staff determined that additional

information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

Selective leaching is known to affect copper-nickel in aqueous environments with nickel being

the element removed. Preventive measure involves proper selection of an alloy/environment

combination. For copper-nickel components in a treated water environment, the applicant

stated in the supplementary table and notes, entitled Virgil C. Summer Nuclear Station

Database AMR Query,” that loss of material due to selective leaching was determined not to be

an aging effect for VCSNS. By letter dated March 28, 2003, the staff requested, in RAI

3.3.2.4.6-1, the applicant to provide the basis for this conclusion, including specific information

on materials composition and environmental conditions that enabled the applicant to have made

this determination.

In its response dated June 12, 2003, the applicant stated that selective leaching is an

applicable mechanism for copper alloys that do not contain inhibiting elements. In particular,

copper-zinc alloys containing greater than 15 percent zinc, copper-aluminum alloys containing

greater than 8 percent aluminum, yellow brass (30 percent zinc and 70 percent copper), and

muntz metal (40 percent zinc and 60 percent copper) are all susceptible to selective leaching. 

Copper-nickel does not fit these criteria and management is not needed in treated water, oil

(fuel in wetted locations), or air/gas (wetted locations) environments. Finally, the applicant

stated that in identifying aging effects for raw water environments, selective leaching was

attributed as an aging effect for copper-nickel in harsh raw water environments only; however,

VCSNS has no in-scope copper-nickel components in a raw water environment.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified selective leaching as an aging effect for copper-nickel in harsh

raw water environments only, and the applicant stated that VCSNS has no in-scope coppernickel components in a raw water environment. All issues associated with this RAI 3.3.2.4.6-1,

are considered resolved.
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For stainless steel components in a reactor building environment, the applicant stated that for

VCSNS no aging effects were determined to require aging management during the period of

extended operation. By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.6-2, 

the applicant to provide the basis for this conclusion. In particular, in view of the operational

experience described in IN 85-30, Microbiologically-Induced Corrosion of Containment Service

Water System,” the applicant was requested to explain why MIC is not an applicable aging

mechanism leading to loss of material as an aging effect in the VCSNS reactor building

environment. In addition, for stainless steel components in a sheltered environment, the

applicant stated that for VCSNS the aging effect of loss of material due to pitting and crevice

corrosion was determined not to require aging management. The applicant was requested to

provide the basis for its conclusion.

In its response dated June 12, 2003, the applicant provided the following clarification. IN 85-30

refers to MIC in internal environments; the reactor building environment concerns external

surfaces in the ambient environment of the reactor building. In addition, the applicant stated

that plant operating experience has identified the accumulation of microbiological organisms on

the external surfaces of some piping components at building wall penetrations as a result of

ground water intrusion effects. The structural design of the plant is such that any ground water

intrusion in the sheltered environment is directed to sumps and away from equipment within the

scope of license renewal. It is the residual presence of microbiological organisms that is of

concern for subject mechanical components.

The applicant further stated that the VCSNS FSAR identifies a ground water elevation of 420'

+/- 3'. Certain structures, such as the service water pumphouse, are potentially exposed to a

ground water level of 425'. As such, piping, process tubing, and ductwork component types

were conservatively considered to be susceptible to external MIC if they either enter a building

from outside or pass between buildings included in the sheltered environment below the 425'

elevation. Additionally, the susceptibility to external MIC was limited locally to the area of the

interface with the pertinent wall. For building fire seal penetrations in the sheltered

environment, the management of aging of the pertinent structural commodities precludes the

accumulation of the necessary microbiological organisms, and thus MIC, on interfacing

mechanical component types. The reactor building environment does not have the conditions

necessary for MIC to be found on external surfaces. Piping, process tubing, or ductwork that

penetrate the reactor building do not enter the building at locations where ground water is

found. 

VCSNS is located well inland and in an area where forestry is the prime commercial activity. 

VCSNS does not see salt or other corrosive materials in the air from agriculture or industry. 

Crevice and pitting corrosion are not considered to be aging effects for external surfaces

because the ambient environment does not contain contaminants of sufficient quantity to

concentrate on external surfaces such that pitting or crevice corrosion would occur. Finally, the

applicant stated that rainwater analyses reveal a concentration of less than 10 ppm for

chlorides and sulfates.

On the basis of its review, the staff finds the applicant’s response to RAI 3.3.2.4.6-2 acceptable

because the applicant has properly identified that the susceptibility to external MIC is limited

locally to the external surfaces of some piping components at building wall penetrations as a

result of ground water intrusion effects. Furthermore, the applicant stated that the ambient

environment does not contain contaminants of sufficient quantity to concentrate on external
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surfaces such that pitting or crevice corrosion would occur. However, the staff questioned

whether there are types of water other than ground water from intrusion (such as water from

condensation) present in the sheltered environment such that loss of material from MIC may

become an aging effect for the external surfaces of some of the applicable components of this

system. The applicant was requested to provide the justification, including operating

experience, for not considering MIC from other types of water.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain the nutrients necessary to promote external MIC in other types of water, such

as water from condensation, and that, because external MIC has not been found at locations

other than building penetrations, VCSNS does not specifically credit the Inspections for

Mechanical Components Program for aging management of this aging effect. However, the

applicant further stated that the Inspections for Mechanical Components Program will inspect

for any abnormalities on external surfaces. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain the nutrients

necessary to promote external MIC in other types of water, such as water from condensation,

and the applicant has committed to use the Inspections for Mechanical Components Program to

inspect for any abnormalities on external surfaces. All issues associated with this RAI

3.3.2.4.6-2, are considered resolved.

The applicant identified galvanic corrosion as an applicable aging effect for carbon steel

components in a treated water environment and the Chemistry Program as the applicable AMP. 

It should be noted that the likely material/locations determining galvanic corrosion rates depend

on which specific metal/alloy is used, how far apart the two dissimilar metals are on the galvanic

series chart, the electrolyte conductivity, geometric factors, and immersion time. Given these

factors, by letter dated March 28, 2003, the staff requested in RAI 3.3.2.4.6-3, the applicant to

provide the basis that the Chemistry Program is the applicable AMP for galvanic corrosion.

In its response dated June 12, 2003, the applicant stated that the Chemistry Program is

credited with maintaining a high purity environment that has low electrolyte conductivity by

maintaining chemistry within EPRI guidelines. The Chemistry Program has proven effective in

managing aging effects in the treated water environment as evidenced by the review of

operating history in response to GL 89-13. However, the applicant proposed to conduct, prior

to the period of extended operation, one-time inspections in low-flow areas of various closed,

treated water systems to demonstrate the effectiveness of the Chemistry Program.

On the basis of its review, the staff finds the applicant’s response acceptable because prior to

the period of extended operation, the applicant will conduct one-time inspections in low-flow

areas of various closed, treated water systems to demonstrate the effectiveness of the

Chemistry Program. All issues associated with this RAI 3.3.2.4.6-3, are considered resolved.

The applicant credited its Chemistry Program (which explicitly exempts the one-time inspection)

for managing the aging effects of loss of material and cracking for some subcomponents in

heat exchangers in several auxiliary systems (e.g., tubes in a heat exchanger in the component

cooling water system, page 31 of 413 of the database AMR query). By letter dated March 28,

2003, the staff requested , in RAI 3.3.2.4.6-4, the applicant to explain how the credited
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Chemistry Program alone will ensure the heat transfer function of the subcomponents in the

heat exchanger.

In its response dated June 12, 2003, the applicant stated that for closed, treated water systems,

such as the CC system, contaminants have no way of entering the system other than corrosion

of the system itself. Due to the continuous, turbulent flow through the shell of the CC heat

exchanger, corrosion products will not settle out on tubes. The Chemistry Program will manage

the conditions required for loss of material by maintaining chemistry within EPRI guidelines. 

The Chemistry Program has proven effective in managing aging effects in the treated water

environment, as evidenced by the review of operating history provided in response to GL 89-13.

However, the applicant proposed to conduct that prior to the period of extended operation, onetime inspections in low-flow areas of various closed, treated water systems to demonstrate the

effectiveness of the Chemistry Program.

On the basis of its review, the staff finds the applicant’s response acceptable because prior to

the period of extended operation, the applicant will conduct one-time inspections in low-flow

areas of various closed, treated water systems to demonstrate the effectiveness of the

Chemistry Program. All issues associated with this RAI 3.3.2.4.6-4, are considered resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the component cooling water system SSCs to the environments

described in Tables 2.3-22, 3.3-1, and 3.3-2 are consistent with industry experience for these

combinations of materials and environments. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the component cooling water system.

Aging Management Programs:

The applicant credits the following AMPs for managing the aging effects in the component

cooling water system:

 Chemistry Program (3.3.0.2)

 Boric Acid Corrosion Surveillances Program (3.3.0.1)

 Service Water System Reliability and In-Service Testing Program (3.3.2.3.1) 

 Above Ground Tank Inspection Program (3.3.0.5)

 Heat Exchanger Inspections Program (3.3.0.8)

 Maintenance Rule Structures Program (3.3.0.4)

 Preventive Maintenance Activities—Ventilation Systems Inspections Program (3.3.2.3.3) 

The Chemistry Program, Boric Acid Corrosion Surveillances Program, Above Ground Tank

Inspection Program, Heat Exchanger Inspections Program, and Maintenance Rule Structures

Program are credited with managing the aging effects of several components in different

structures and systems and are, therefore, considered common AMPs. The staff has evaluated

these common AMPs and found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.0.3.1, 3.0.3.2, 3.0.3.4, 3.0.3.5, and 3.0.3.8, respectively, of this SER. 
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The staff has evaluated the system-specific AMPs, Service Water System Reliability and InService Testing Program and Preventive Maintenance Activities—Ventilation Systems

Inspections Program, and has found them to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.3.2.3.1 and 3.3.2.3.3, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the Component Cooling

Water System, the staff evaluated the AMPs listed above to determine if they are appropriate

for managing the identified aging effects for this system. For those components identified in

Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the component

cooling water system. In addition, the staff finds the associated program descriptions in the

FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

The staff reviewed the information in Section 2.3.3.6 and Tables 2.3-22, 3.3-1, and 3.3-2, as

well as in the supplementary table and notes, entitled Virgil C. Summer Nuclear Station

Database AMR Query.” On the basis of its review and audit of the applicant’s program, the

staff finds that those portions of the program for which the applicant claims consistency with the

GALL program are consistent with the GALL program. Since the GALL program is acceptable

to the staff, 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). The staff also reviewed the

FSAR supplement for this AMP and finds that it provides an adequate summary description of

the program, as required by 10 CFR 54.21(d).

3.3.2.4.7 Diesel Generator Service Systems

Summary of Technical Information in the Application

The description of the diesel generator service systems can be found in Section 2.3.3.7 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-23. The components, aging effects, and AMPs are provided in LRA

Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the diesel generator service systems are described in Section 2.3.3.7 of the

LRA as being within the scope of license renewal and subject to AMR. Table 2.3-23, 3.3-1, and

3.3-2 of the LRA, and the supplementary table and notes, entitled Virgil C. Summer Nuclear

Station Database AMR Query,” list individual components of the system including expansion

joint (engine exhaust), filters (body only), flexible coupling, flexible hose heat exchangers

(channel head), heat exchangers (shell), heat exchangers (tubes), heat exchangers

(tubesheet), heaters (body only), mufflers, orifices, pipe and fittings, pumps (casing only),
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reservoir (air), reservoir (rocker), sight glass (body only), silencers, strainers (body only), tanks,

tube and tube fittings, turbocharger (casing only), and valves (body only).

An internal environment of alternating wet-dry, air-gas causes the aging effect of loss of

material from corrosive impacts in carbon steel components. 

An internal environment of raw water causes the aging effects of loss of material from crevice

and pitting corrosion, MIC, and erosion, and heat exchanger fouling from biological materials

and particulates in stainless steel and brass components. 

An internal environment of treated water causes the aging effect of loss of material from crevice

and pitting corrosion and cracking from SCC in carbon steel, stainless steel, and brass

components. For carbon steel components, the internal environment of treated water causes

the aging effect of loss of material from galvanic corrosion and general corrosion. An internal

environment of treated water causes the aging effect of loss of material from erosion or

erosion-corrosion for brass and stainless steel. The same internal environment of treated water

causes the aging effect of heat exchanger fouling due to particulates for brass components. An

internal environment of treated water also causes the aging effect of loss of material from

crevice corrosion, erosion-corrosion, galvanic corrosion, and pitting corrosion in copper

components. 

An internal environment of fuel oil causes the aging effect of loss of material from MIC for

copper, brass, and carbon steel components. For carbon steel components, an internal

environment of fuel oil also causes the aging effect of loss of material due to crevice and pitting

corrosion, galvanic corrosion, and general corrosion. No aging effect is identified for any

components exposed to an internal environment of dry air-gas.

Loss of material is identified as aging effect from MIC, crevice and pitting corrosion, galvanic

corrosion, and general corrosion for carbon steel components exposed to an underground

environment. Loss of material is identified as an aging effect from general and galvanic

corrosion for carbon steel and cast iron components exposed to a sheltered environment. No

aging effect is identified for stainless steel, brass, aluminum, and copper components exposed

to a sheltered environment. Loss of material is identified as an aging effect from general and

galvanic corrosion for carbon steel components exposed to a yard environment.

Cracking is identified as an aging effect from radiation and thermal embrittlement for rubber

components exposed to a sheltered environment.

No aging effect is identified for rubber components exposed to fuel oil or treated water

environments.

No aging effect is identified for aluminum components in either an air-gas or a sheltered

environment. No aging effect is identified for ductile iron components in an oil environment.

Loss of material due to general corrosion is identified as an aging effect for ductile components

in a sheltered environment.

Aging Management Programs:
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The following AMPs are utilized to manage aging effects in the diesel generator service

systems:

• Inspections for Mechanical Components Program (B.2.11)

• Diesel Generator Systems Inspection Program (B.2.2)

• Chemistry Program (B.1.4)

• Service Water System Reliability and In-Service Test Program (B.1.9)

• Buried piping and Tanks Inspection Program (B.2.10)

• Heat Exchanger Inspections Program (B.2.12)

A description of the AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the diesel generator service systems will

be adequately managed by the AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.7 and Tables 2.3-23, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station Database AMR Query”

and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in the supplement. 

During its review, the staff determined that additional information was needed. 

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

The applicant identified the flexible coupling in the diesel generator service systems as subject

to AMR. The applicant stated that component/component type AMR results for VCSNS are

consistent with NUREG-1801 in material and environment, and partially consistent in aging

effects. The VCSNS plant-specific program credited for managing aging effects is B.2.11,

Inspections for Mechanical Components Program. This AMP inspects component external

surfaces for signs of degradation. 

In the GALL Report, elastomer-based components in warm, moist air have the aging effects of

hardening, cracking, and loss of strength due to elastomer degradation. The associated AMP

is plant-specific. In the VCSNS LRA (Table 3.3-1), elastomer-based components in an air or

gas (indoor) environment have the aging effects of hardening, cracking, and loss of strength

due to elastomer degradation and the AMP credited is B.2.11, Inspections for Mechanical

Components Program.”

For flexible hose and flexible couplings included in LRA Table 2.3-23, the applicant identified

Table 3.3-1, Item 2, and Table 3.3-2, Item 26. LRA Table 3.3-1, Item 2 states that loss of

material due to wear is not considered an aging effect because mechanical components must

perform their license renewal intended functions without moving parts. Wear that occurs on

nonmoving components is considered to be caused by improper design and should be
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corrected by normal maintenance activities. The staff disagrees with the applicant’s

explanation that wear is caused by improper design in the nonmoving components. The staff

believes that wear of elastomer may be attributed to many conditions, such as relative

movement due to thermal expansion. By letter dated March 28, 2003, the staff requested, in

RAI 3.3.2.4.7-1, the applicant to provide the technical basis to justify why the aging effect of

loss of material due to wear is not applicable.

LRA Table 3.3-2, Item 26 states that internal surfaces of rubber components are not considered

to be susceptible to degradation in fluid environments due to lack of excessive temperatures

and to the change in material properties of elastomers being closely tied to external conditions,

such as ultraviolet radiation. Therefore, no aging management is required. In the same RAI

3.3.2.4.7-1, the staff requested the applicant to clarify what type of rubber is used and to

provide technical justification and operational history to demonstrate that the internal surfaces

for flexible hoses and other elastomers used in diesel generator services systems do not have

aging effects of hardening, cracking, loss of strength, and wear from exposure to the process

fluid.

In its response by letter dated June 12, 2003, the applicant stated that VCSNS maintains that

wear is not an aging effect and included the following basis. The diesel generators are

normally in standby for emergency use and are usually only started on a monthly frequency for

routine surveillance. Because of the keep-warm” systems for the lube oil and jacket water

systems in the diesel, elastomers in these diesel generator systems will not experience

extremes in temperatures; therefore, VCSNS considers that flexing of an elastomer due to

thermal expansion does not contribute to any significant degradation. However, VCSNS will

manage cracking due to radiation and thermal embrittlement through the Inspections for

Mechanical Components Program which will detect any significant degradation.

The applicant further stated that the material/environment combination for the elastomer

components in the diesel generator services system include rubber/lube oil, rubber/treated

water, and neoprene/air-gas. The rubber is Buna N rubber. According to Table 5-15 of

Corrosion Engineering,” Third Edition, Buna N rubber exhibits excellent resistance to oil and

good resistance to water absorption, but poor resistance to sunlight aging. Therefore, external

surfaces would show age-related degradation before the internal surfaces. The neoprene

conforms to ASTM SC 610AF. The neoprene component is in the inlet air piping, which is the

same environment as ambient air; therefore, external surface conditions would be indicative of

internal conditions. Thus, the applicant maintains that the Inspections for Mechanical

Components Program will adequately manage aging of these components during the period of

extended operation.

By letter dated July 29, 2003, the staff questioned if the internal environment for the flexible

neoprene hose may be more severe than the ambient environment of the diesel generator

building. The staff requested the applicant to clarify why the external surface conditions would

be indicative of internal conditions since external surfaces are exposed to ambient conditions in

the building which may not be equivalent to the exposure of internal surfaces to inlet air

conditions from out of doors. 

In the response dated September 2, 2003, the applicant stated that the neoprene component is

in the inlet air piping, which is essentially the same environment as ambient air. The ventilation

for the diesel generator rooms is supplied from outside air. It is neither conditioned nor filtered. 
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The inlet air that is supplied through the neoprene components is also supplied from outside air,

but is filtered. The applicant further stated that the diesel generators are normally in standby for

emergency use and are started on a monthly frequency for routine surveillance. For the vast

majority of the time, the internal environment for these neoprene components is stagnant,

filtered, ambient air; therefore, internal conditions would be no harsher than the external

conditions. External surface conditions of the neoprene components would be indicative of

internal conditions. Thus, VCSNS maintained that the Inspections for Mechanical Components

Program will adequately manage aging of these components during the period of extended

operation.

On the basis of its review, the staff finds the applicant’s initial response, together with the

applicant’s response to the staff’s comment, acceptable because (1) the applicant has properly

identified that because of the keep-warm” systems for the lube oil and jacket water systems in

the diesel, elastomers in these diesel generator systems will not experience extremes in

temperatures and flexing of an elastomer due to thermal expansion does not contribute to any

significant degradation (2) the applicant has clarified the type of rubber used and has

demonstrated that the Inspections for Mechanical Components Program will adequately

manage aging of these components during the period of extended operation and (3) the

applicant has properly identified that, for the majority of the time, the internal conditions would

be no harsher than the external conditions and that external surface conditions of the neoprene

components would, in general, be indicative of internal conditions. All issues in RAI 3.3.2.4.7-1,

are considered resolved.

No AMP has been identified for managing loss of material due to galvanic corrosion for any

applicable components in the diesel generator service systems. By letter dated March 28,

2003, the staff requested, in RAI 3.3.2.4.7-2, the applicant to provide the basis for not including

such an AMP.

In its response by letter dated June 12, 2003, the applicant stated that several programs

manage galvanic corrosion for various material/environment combinations in the diesel

generator service systems. These programs are the Chemistry Program, the Inspections for

Mechanical Components Program, the Buried Piping and Tanks Inspections Program, and the

Service Water System Reliability and In-Service Testing Program.

However, the staff identified that the likelihood and extent of galvanic corrosion depends on the

contact between different metals or alloys with relative separation of the contacting metal/alloys

on the galvanic potential chart, the electrolyte, immersion time, and geometrical factors. Many

of these factors are location-dependent. By letter dated July, 2003, the staff requested the

applicant to clarify whether, in using these AMPs to manage the galvanic corrosion, the

inspections are to be performed in areas with the highest likelihood of galvanic corrosion or are

to be performed on an opportunistic basis. The staff requested the applicant to provide

justifications for either case.

By letter dated September 2, 2003, the applicant stated that the Chemistry Program manages

galvanic corrosion for components in the treated water and fuel oil portions of the diesel

generator systems by maintaining high purity, thereby inhibiting the conductivity of the

electrolyte necessary for galvanic reactions. The applicant further stated that, although

galvanic corrosion normally does not occur in the absence of a completely wetted environment,
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the inspections for mechanical components will manage galvanic corrosion for external

surfaces of components by periodic inspections for any surface abnormalities. 

The applicant stated that the underground portions of the diesel generator systems (fuel oil) are

entirely carbon steel, therefore, there will be no galvanic reaction between components. The

only possible galvanic reaction would be between the buried components and the surrounding

soil; therefore, the buried components would all be equally susceptible. The Buried Piping and

Tanks Inspections Program manages galvanic corrosion for the underground portions of the

diesel generator systems through inspections performed on an opportunistic basis. Operating

experience for the diesel generator fuel oil storage tanks has shown negligible wall thinning.

Further, the applicant stated that the service water system cools the diesel generator heat

exchangers and the Service Water System Reliability and In-Service Testing Program will

manage galvanic corrosion of the service water side of these heat exchangers. The Service

Water System Reliability and In-Service Testing Program is the equivalent of the GALL OpenCycle Cooling Water System Program. 

On the basis of its review, the staff finds the applicant’s initial response, together with the

applicant’s response to the staff’s comment, acceptable because (1) the applicant has properly

identified that the Chemistry Program, the Inspections for Mechanical Components Program,

the Buried Piping and Tanks Inspections Program, and the Service Water System Reliability

and In-Service Testing Program manage galvanic corrosion for various material/environment

combinations in the diesel generator service systems, and (2) the applicant has properly

identified the specific ways in which these AMPs are used to manage the loss of materials due

to galvanic corrosion. The staff further identified that the operating experience, as stated in the

VCSNS LRA B.2.10, “Buried Piping and Tanks Inspections,” indicates that an ultrasonic

examination of the fuel oil storage tanks and associated piping was performed. Each tank was

inspected at 102 locations, evenly distributed over the entire surface area, and no significant

corrosion or age-related degradation was found. All issues in RAI 3.3.2.4.7-2 are considered

resolved.

LRA Table 3.3-2, Item 10 indicates that exhaust piping and mufflers are thick-walled

components and do not require aging management. The corrosion of carbon steel components

exposed to condensation and alternate wetting and drying, such as the mufflers and piping

used in the diesel exhaust, is affected by their orientation and the proper function of any

installed drain traps. By letter dated March 28, 2003, the staff requested in RAI 3.3.2.4.7-3, the

applicant to address the issue of whether the exhaust contains any corrosive contaminants,

such as sulfur, that may be corrosive to the material. The applicant was also asked to provide

the basis for not inspecting the interiors of silencers/mufflers and exhaust piping for localized

corrosion from sulfuric acid and condensation.

By letter dated June 12, 2003, the applicant stated that the mufflers and muffler exhaust piping

contain drain traps. The Diesel Generator Systems Inspections Program already includes

carbon steel expansion joints exposed to engine exhaust as components to be inspected. The

applicant further stated that the scope of the program will be revised to include the mufflers and

exhaust piping. The staff finds the applicant’s response to RAI 3.3.2.4.7-3, acceptable because

the applicant has committed to revise the scope of the program to include the mufflers and

exhaust piping. 
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On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the diesel generator service systems SSCs to the environments

described in LRA Tables 2.3-23, 3.3-1, and 3.3-2 are consistent with industry experience for

these combinations of materials and environments. Therefore, the staff finds that the applicant

has identified the appropriate aging effects for the materials and environments associated with

the components in the diesel generator service systems.

Aging Management Programs

The applicant credits the following AMPs for managing the aging effects in the diesel generator

service systems:

 Inspections for Mechanical Components Program (3.0.3.7)

 Diesel Generator Systems Inspection Program (3.3.2.3.4)

 Chemistry Program (3.0.3.2)

 Service Water System Reliability and In-Service Test Program (3.3.2.3.1)

 Buried Piping and Tanks Inspection Program (3.0.3.6)

• Heat Exchanger Inspections Program (3.0.3.8)

The Inspections for Mechanical Components Program, Chemistry Program, Buried Piping and

Tanks Inspection Program, and Heat Exchanger Inspections Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff has evaluated these common AMPs and found

them to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of these AMPs is documented in Sections 3.0.3.7, 3.0.3.2, 3.0.3.6, and 3.0.3.8,

respectively, of this SER. The use of one-time inspections for the verification of the

effectiveness of the Chemistry Program is also evaluated and documented in Section 3.0.3.2 of

this SER.

The staff has evaluated the system-specific AMPs Service Water System Reliability and InService Testing Program, and the Diesel Generator Systems Inspection Program and has

found them to be acceptable for managing the aging effects identified for this system. The

staff’s evaluation of these AMPs is documented in Sections 3.3.2.3.1 and 3.3.2.3.4,

respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the diesel generator service

systems, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the diesel

generator service systems. In addition, the staff finds the associated program descriptions in

the FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions
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On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.8 Fire Service System

Summary of Technical Information in the Application

The description of the fire service system can be found in Section 2.3.3.8 of this SER. The

passive, long-lived components of this system that are subject to an AMR are identified in LRA

Table 2.3-24. The components, aging effects, and AMPs are provided in LRA Tables 3.3-1 and

3.3-2. FSAR Section 9.5.1, “Fire Protection System,” provides additional information

concerning the interior/exterior fire protection system.

Aging Effects:

LRA Table 2.3-24 lists individual system components that are within the scope of license

renewal and subject to an AMR. These components include bolting, piping, tubing, fittings,

valves, nozzles, fire hydrant and pump casings, components in the water-based fire

suppression system, components in the CO2 fire suppression system, components in the diesel

fire system, doors, barrier penetration seals, and concrete structures (fire barrier walls, ceilings,

and floors).

The LRA identified that carbon steel, galvanized steel, cast iron, and copper in air are subject to

loss of material due to general external corrosion, and carbon steel and low-alloy steel in

dripping boric acid are subject to loss of material due to boric acid corrosion. The LRA also

identifies that stainless steel in treated water is subject to loss of material due to crevice and

pitting corrosion and cracking due to SCC. The LRA identifies that components in water-based

fire suppression systems are subject to loss of material due to general pitting, crevice, and

galvanic corrosion, MIC, and biofouling. Fire barriers, walls, ceilings, floors, doors, and

penetration seals are subject to loss of material due to water, hardening, and shrinkage caused

by weathering, concrete cracking, and spalling from freeze thaw, aggressive chemical attack,

and reaction with aggregates, and loss of material due to corrosion of embedded steel. 

Stainless steel in oil (reactor coolant pump oil collection system) is subject to loss of material

due to galvanic, general, pitting, and crevice corrosion. Buried piping and fittings are subject to

loss of material due to general, pitting, and crevice corrosion and MIC.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the fire service system:

• Boric Acid Corrosion Surveillances Program (B.1.2)

 Fire Protection Program (B.1.5)

 Structures Monitoring Program (B.1.18)
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 Buried Piping and Tanks Inspection Program (B.2.10)

 Inspections for Mechanical Components (B.2.11)

A description of these AMPs is provided in LRA Appendix B. The applicant indicated that the

effects of aging associated with the components of the fire protection system will be adequately

managed by these AMPs during the period of extended operation.

Staff Evaluation

The staff reviewed the applicant’s fire protection system in the LRA to determine whether the

applicant had demonstrated that the effects of aging for the fire protection system will be

adequately managed during the period of extended operation, as required by 10 CFR

54.21(a)(3). The staff's review was conducted in accordance with Section 3.3 of the SRP-LR

(NUREG-1800) and is described below.

Aging Effects:

The staff reviewed the information in LRA Tables 2.3.24, 3.3-1, and 3.3-2 for the fire protection

system. During its review, the staff determined that additional information was needed. By

letter dated March 28, 2003, in RAI 3.3.2.4.8-1(1), pertaining to the one-time inspection of the

components in the reactor coolant pump oil collection system, the staff questioned why these

components should not be inspected periodically for managing aging. 

In its response dated June 12, 2003, the applicant stated that NUREG-1801 recommends a

one-time inspection for the components of the reactor coolant pump oil collection system that

are composed of carbon steel, copper, and brass. The reactor coolant pump oil collection

system components at the plant are composed of stainless steel. The staff finds this response

reasonable and acceptable since none of the component types of the reactor coolant pump oil

collection system will collect water in low spots, all are subject to high ambient condition which

would cause evaporation of any moisture minimizing corrosion.

In RAI 3.3.2.4.8-1(2), the staff asked why Item 18 of LRA Table 3.3-2 does not identify any

aging effects or mechanism to be evaluated for the fire service system nozzles, piping, and fire

hydrants.

In its response dated June 12, 2003, the applicant stated that LRA Table 3.3-2 concerns

auxiliary system components identified in NUREG-1801. Item 18 of this table addresses

components that are normally in a standby mode where air is the predominant internal

environment. The plant’s external environments for these components are addressed in LRA

Table 3.3.1, Items 5 and 20. The staff reviewed Item 20 of LRA Table 3.3-1 which addresses

the AMPs for components in the water-based fire protection system. Therefore, the staff finds

the applicant’s response acceptable.

On the basis of its review of the information provided in the LRA and the additional information

in the applicant’s response to the staff’s RAIs, the staff finds that the aging effects identified for

the fire protection system components described in LRA Tables 2.3.24, 3.3-1, and 3.3-2 are

consistent with industry experience for these combinations of materials and environments. 

Therefore, the staff finds that the applicant has identified the appropriate aging effects for the

materials and environments associated with the components in the fire protection system.
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Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the fire service

systems:

• Boric Acid Corrosion Surveillances Program (B.1.2)

 Fire Protection Program (B.1.5)

 Structures Monitoring Program (B.1.18)

 Buried Piping and Tanks Inspections Program (B.2.10)

 Inspections for Mechanical Components (B.2.11)

These AMPs are credited for managing the aging effects of components in several structures

and systems that are considered as common AMPs. The staff has evaluated these common

AMPs and found them to be acceptable for managing the effects of the components in several

structures and systems and, therefore, are considered common AMPs. 

On the basis of its review of the information provided in the LRA, the staff concluded that the

above identified AMPs will effectively manage the aging effects of the fire protection system.

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with fire protection

system. 

Conclusion

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.9 Fuel Handling System 

Summary of Technical Information in the Application

The description of the fuel handling system can be found in Section 2.3.3.9 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-25. The components, aging effects, and AMPs are provided in LRA Table 3.3-2. 

Aging Effects:

Components of the fuel handling system are described in Section 2.3.3.9 of the LRA as being

within the scope of license renewal and subject to an AMR. Tables 2.3-25 and 3.3-2 of the

LRA, and the table entitled, Virgil C. Summer Nuclear Station Database AMR Query,” in the

supplement lists the system component which consists of fuel and transfer tubes. 
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The applicant identified no aging effects for the stainless steel and carbon steel components

that are embedded in concrete. In addition, the applicant identified no aging effects for the

stainless steel exposed to a sheltered or ventilation environment. 

Aging Management Programs:

The applicant identified no aging effects for the components of the fuel handling system. 

Therefore, no AMPs are required for this system. 

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.9 and Tables 2.3-25, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station Database AMR Query,”

and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in the supplement. 

During its review, the staff determined that additional information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

On the basis of its review of the information provided in the LRA, the staff finds that the

absence of aging effects that result from contact of the fuel handling system SSCs to the

environments described in Tables 2.3-23, 3.3-1, and 3.3-2 is consistent with industry

experience for these combinations of materials and environments and is, therefore, acceptable.

Aging Management Programs:

Based on the review of the information provided in the LRA, the staff concurs with the

applicant’s conclusion that no AMPs are required for the fuel handling system because there

are no applicable aging effects for the components of this system. 

Conclusions

On the basis of its review, the staff concludes that the applicant has justified that no AMPs are

required because there are no applicable aging effects for components in the fuel handling

system. In addition, there is reasonable assurance that the component intended functions will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.3.2.4.10 Gaseous Waste Processing System 

Summary of Technical Information in the Application
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The description of the gaseous waste processing system can be found in Section 2.3.3.10 of

this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-26. The components, aging effects, and AMPs are provided in LRA

Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the gaseous waste processing system are described in Section 2.3.3.10 of the

LRA as being within the scope of license renewal and subject to an AMR. Tables 2.3-26, 3.3-1,

and 3.3-2 of the LRA, and the table entitled, Virgil C. Summer Nuclear Station Database AMR

Query,” in the supplement list individual components of the system, including heat exchanger

shells, heat exchanger spiral baffles, heat exchanger tube coils, heat exchanger tube

manifolds, heat exchanger channel heads, heat exchanger tubes, heat exchanger tubesheets,

pipe and fittings, tube and tube fittings, and valve bodies.

Carbon steel components are subject to the aging effects of loss of material of internal surfaces

from exposure to a treated water environment due to crevice corrosion, galvanic corrosion,

general corrosion, and pitting corrosion. External surfaces of carbon steel are also subject to

an aging effect of loss of material due to boric acid corrosion from exposure to a sheltered

environment. Internal surfaces of stainless steel components are subject to the aging effects of

loss of material from crevice and pitting corrosion and cracking from SCC due to exposure to a

treated water environment. Internal or external surfaces of stainless steel components are also

subject to the aging effect of cracking from SCC due to exposure to an air-gas environment at

temperatures greater than 200 F. Exposure of internal or external surfaces of stainless steel

components to a sheltered environment or an air-gas environment at temperatures less than

200 F has no aging effect. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the gaseous waste processing

system:

 Chemistry Program (B.1.4)

 Inspections for Mechanical Components Program (B.2.11)

 Boric Acid Corrosion Surveillances Program (B.1.2)

 Waste Gas System Inspection Program (B.2.8)

 Maintenance Rule Structures Program (B.1.18)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the gaseous waste processing system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.10 and Tables 2.3-26, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station Database AMR Query,”
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and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in the supplement. 

During its review, the staff determined that additional information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

A common RAI (RAI 3.3-2) concerning aging mechanisms related to the aging effect of loss of

material in a sheltered environment for carbon steel components in the auxiliary systems is

related to components in the gaseous waste processing system. This issue is evaluated in

Section 3.3.2.5.2 of this SER.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the gaseous waste processing system SSCs to the environments

described in Tables 2.3-9, 3.3-1, and 3.3-2 are consistent with industry experience for these

combinations of materials and environments. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the gaseous waste processing system

Aging Management Program:

The applicant credited the following AMPs for managing the aging effects in the gaseous waste

processing systems:

 Chemistry Program (3.0.3.2)

 Boric Acid Corrosion Surveillances Program (3.0.3.1)

 Waste Gas System Inspection Program (3.3.2.3.8)

 Inspections for Mechanical Components Program (3.0.3.7)

 Maintenance Rule Structures Program (3.0.3.4)

The Chemistry Program, Boric Acid Corrosion Surveillances Program, Inspections for

Mechanical Components Program, and Maintenance Rule Structures Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff has evaluated these common AMPs and found

them to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of these AMPs is documented in Sections 3.0.3.2, 3.0.3.1, 3.0.3.7, and 3.0.3.4,

respectively, of the SER. 

The staff has evaluated the system-specific Waste Gas System Inspection AMP, and has found

it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of this AMP is documented in Section 3.3.2.3.8 of this SER.

After evaluating the applicant’s AMR for each of the components in the gaseous waste

processing system, the staff evaluated the AMPs listed above to determine if they are

appropriate for managing the identified aging effects for this system. For those components
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identified in Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs 

recommended by the GALL Report. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the gaseous

waste processing system. In addition, the staff finds the associated program descriptions in the

FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.11 Industrial Cooler System

As described in Section 2.3.3.11 of the LRA, the applicant’s scoping and screening review

concluded that there are no mechanical components/component types required for the

industrial cooler system to perform its system intended function; therefore, no AMR is required. 

The staff’s evaluation of the scoping and screening process is documented in Section 2.3.3.11

of this SER.

3.3.2.4.12 Instrument Air Supply System

Summary of Technical Information in the Application

The description of the instrument air supply system can be found in Section 2.3.3.12 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-27. The components, aging effects, and AMPs are provided in LRA

Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the instrument air supply system are described in Section 2.3.3.12 of the LRA

as being within the scope of license renewal and subject to AMR. Tables 2.3-27, 3.3-1, and

3.3-2 of the LRA, and the supplementary table and notes entitled, Virgil C. Summer Nuclear

Station Database AMR Query,” list individual components of the system including pipe, tanks,

tube and tube fittings, and valves (bodies only).

Loss of material due to general corrosion is identified as an aging effect for carbon steel

components exposed to an internal environment of moisture air-gas. No aging effect is

identified for stainless steel, aluminum, brass, and cast iron components exposed to an internal

environment of dry air-gas. Loss of material due to boric acid attack is identified as an aging
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effect for carbon steel, aluminum, brass, and cast iron components exposed to an external

environment of the reactor building or a sheltered environment. Loss of material due to MIC is

identified as an aging effect for stainless steel components exposed to an external environment

or sheltered environment.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the instrument air supply system:

 Maintenance Rule Structures Program (B.1.18)

 Boric Acid Corrosion Surveillances Program(B.1.2)

 Service Air Systems Inspection Program (B.2.6)

A description of the AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the instrument air supply system will be

adequately managed by the AMPs identified during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.12 and Tables 2.3-27, 3.3-1, and 3.3-2 in the

LRA as well as in the supplementary table and notes entitled, Virgil C. Summer Nuclear Station

Database AMR Query.” During its review, the staff determined that additional information was

needed. 

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

For the AMR of several components within the license renewal evaluation boundary of the

instrument air supply system, the applicant stated that these components are exposed to an oilfree, filtered, and dried compressed air (referred to as an air-gas environment), and loss of

material is not an aging effect requiring management during the period of extended operation. 

It should be noted that in the instrument air supply system, components that are located

upstream of the air dryers are generally exposed to a wet air-gas environment and, therefore,

may be subject to loss of material due to general and pitting corrosion. In addition, it is

reasonable to assume that components downstream of the dryers are exposed to a dry air-gas

environment. However, this may not be supported by operating experience. For example, NRC

IN 87-28, Air Systems Problems at U.S. Light Water Reactors,” states the following, A loss of

decay heat removal and significant primary system heat up at Palisades in 1978 and 1981 were

caused by water in the air system.” This experience implies that the air-gas system

downstream of the dryer may not be dry. On the basis of this industry experience, by letter

dated March 28, 2003, the staff requested, in RAI 3.3.2.4.12-1, the applicant to discuss its

plant-specific operating experience related to components that are exposed to an instrument air
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environment, and to provide a technical basis for not identifying loss of material as an aging

effect for these components.

In its response dated June 12, 2003, the applicant stated that NRC GL 88-14 addressed the

concerns of NRC IN 87-28. VCSNS responses to the recommendations of GL 88-14 resolved

concerns for the quality of air supplied to safety-related equipment. These responses can be

found in a letter from O.S. Bradham to the Document Control Desk, NRC, dated February 2,

1989, Response to Generic Letter 88-14.”

The applicant further stated that there are various carbon steel components of air systems that

experience an ambient, moist air environment that are in scope for license renewal. The

Service Air Systems Inspection Program manages the aging of these components. The

Service Air System Inspection Program concerns those components that are not pertinent to

the quality of air supplied to safety-related equipment and, therefore, are not pertinent to the

concerns of NRC GL 88-14. These components concern the pressure boundary function of

specific containment penetrations, containment hatch testing, and emergency air supply to the

personnel hatches. Finally, the applicant stated that ambient moist air (not dried by an air

dryer) is assumed to be the internal environment for these components.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has provided a reasonable technical basis for not identifying loss of material as an

aging effect for these components. All issues associated with RAI 3.3.2.4.12-1 are considered

resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAI, the staff finds that the aging effects that

result from contact of the instrument air supply system SSCs to the environments described in

Tables 2.3-27, 3.3-1, and 3.3-2 are consistent with industry experience for these combinations

of materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the instrument air supply system. 

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the instrument air

supply system:

 Maintenance Rule Structures Program (3.0.3.4)

 Boric Acid Corrosion Surveillances Program (3.0.3.1)

 Service Air Systems Inspection Program (3.3.2.3.7)

The Maintenance Rule Structures Program and the Boric Acid Corrosion Surveillances Program

are credited with managing the aging effects of several components in different structures and

systems and are, therefore, considered common AMPs. The staff has evaluated these common

AMPs and found them to be acceptable for managing the aging effects identified for this

system. The staff’s evaluation of these AMPs is documented in Sections 3.0.3.4 and 3.0.3.1,

respectively, of this SER.
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The staff has evaluated the system-specific Service Air Systems Inspection AMP and has found

it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of this AMP is documented in Section 3.3.2.3.7 of this SER.

After evaluating the applicant’s AMR for each of the components in the instrument air supply

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2 , the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the instrument

air supply system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.13 Leak Detection System

As described in Section 2.3.3.13 of the LRA, the applicant’s scoping and screening review

concluded that the portion of the leak detection system that is in scope for license renewal

contains active, nonpressure boundary components; therefore, no AMR is required.

3.3.2.4.14 Liquid Waste Processing System

Summary of Technical Information in the Application

The description of the liquid waste processing system can be found in Section 2.3.3.14 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-28. The components, aging effects, and AMPs are provided in LRA

Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components in the liquid waste processing system are described in Section 2.3.3.14 of the LRA

as being within the scope of license renewal and subject to an AMR. Tables 2.3-28, 3.3-1, and

3.3-2 of the LRA and the Virgil C. Summer Nuclear Station Database AMR Query Table in the

LRA supplement documents list individual components of the system. 
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The component groups in this category in the liquid waste processing system listed by the

applicant in the VCSNS LRA include condensers (XEV0029-CN1, XEV0029-CN2), waste

evaporator—channel heads; waste evaporator—tubes; waste evaporator—tubesheets; waste

evaporator—shell; heat exchanger (XEV0029-HE2), waste evaporator—shell; heat exchanger

(XHE0012), RC drain tank—shell; heat exchanger (XHE0022), waste evaporate concentrates

sample—shell; RC drain tank—tubes; RC drain tank—tubesheet; waste evaporate concentrates

sample—manifolds; heat exchanger (XHE0022), waste evaporate concentrates sample—tubes;

valves (body only); and pipe and fittings. 

Stainless steel components exposed to borated water are subject to the aging effects of loss of

material and cracking due to crevice corrosion, pitting corrosion, and SCC. Stainless steel and

carbon steel components exposed to a sheltered environment are subject to the aging effect of

loss of material due to MIC. Carbon steel components exposed to a reactor building

environment are subject to the aging effect of loss of material due to boric acid corrosion. 

Stainless steel and carbon steel components exposed to treated water are subject to the aging

effects of loss of material and cracking due to crevice, galvanic, general, and pitting corrosion,

and SCC. No aging effects are identified for stainless steel components exposed to air-gas,

reactor building, and ventilation environments. Carbon steel components exposed to air-gas

are identified as having no aging effects.

Aging Management Programs:

The following AMPs are credited to manage the aging effects in the liquid waste processing

system:

 Boric Acid Corrosion Surveillances Program (B.1.2)

 Chemistry Program (B.1.4)

 Maintenance Rule Structures Program (B.1.18)

 Liquid Waste System Inspection Program (B.2.3)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the liquid waste processing system will

be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information identified by the applicant for the components exposed to the

liquid waste processing system environments as described in Section 2.3.3.14, Tables 2.3-28,

3.3-,1 and 3.3-2 of the LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station

Database AMR Query,” and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in

the LRA supplement documents. During its review, the staff determined that additional

information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1,

pertaining to this issue of the plant-specific characteristics of the environment. The staff’s
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evaluation of the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is

characterized as resolved.

By letter dated March 28, 2003, the staff issued RAI 3.3-3, pertaining to this issue of the

susceptibility to aging effects for stainless steel components in an ambient environment. The

staff’s evaluation of the applicant’s response is documented in Section 3.3.2.5.3 of this SER

and is characterized as resolved.

In the LRA Table 3.3-1, Item 14 and the table entitled, Virgil C. Summer Nuclear Station

Database Query,” the applicant identified the aging effects on carbon steel and stainless steel

heat exchanger/condenser components in the liquid waste processing system that are exposed

to treated water and the corresponding AMP. The applicant further stated that the AMR results

for this group are consistent with GALL (VII.C2.2-a, C2.2.1) in material, environment, and aging

effects. The applicant also stated that the Chemistry Program is considered to provide

adequate management in lieu of the Closed-Cycle Cooling Water System Program that is

recommended for this group by GALL. It should be noted that the AMP, Closed-Cycle Cooling

Water System Program,” includes preventive measures, as well as surveillance testing and

inspection. By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.14-1, the

applicant to explain how the Chemistry Program alone (without one-time inspection to verify the

effectiveness of the Chemistry Program) is considered to provide adequate management of the

identified aging effects for these components.

In its response dated June 12, 2003, the applicant stated that the heat exchanger/condenser

components of the liquid waste processing system are in scope for license renewal because

they constitute a pressure boundary with the component cooling water system. The two

internal water environments for the in-scope liquid waste processing system components are

reactor grade, recyclable, borated water, and treated water. The Liquid Waste Systems

Inspections Program will manage aging of stainless steel components of the liquid waste

processing system exposed to borated water. The applicant further stated that the Chemistry

Program will manage aging of the stainless steel and carbon steel components of the liquid

waste processing system exposed to treated water. The Chemistry Program has proven

effective at managing aging degradation in the component cooling water system, as evidenced

by the review of operating history in response to GL 89-13. Finally, the applicant stated that

prior to the period of extended operation, one-time inspections will be conducted in low-flow

areas of various treated water systems to demonstrate the effectiveness of the Chemistry

Program.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has committed to conduct one-time inspections in low-flow areas of various treated

water systems to demonstrate the effectiveness of the Chemistry Program prior to the period of

extended operation.

The GALL Report identifies SCC aging effects for stainless steel components exposed to

treated water, and corresponding AMPs, and recommends further evaluations. In the table

entitled, Virgil C. Summer Nuclear Station Database Query,” the applicant stated that the aging

effects for the combination of those components/component types and environments are

consistent with GALL. However, the applicant also stated that further evaluations were not

recommended by GALL. By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.14-

2, the applicant to explain why the conclusion in the LRA is different from the GALL Report.
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In its response dated June 12, 2003, the applicant stated that all of the columns of Table 3.3-1

of the LRA, except for the last column, are NUREG-1801 listings. The last column is the

VCSNS response. NUREG-1801 states that, for this AMR item, if there were an adequate

closed-cycle cooling water system” program, then no further evaluation is recommended. In

the Discussion” column, VCSNS discusses the adequacy of the Chemistry Program in

managing aging instead of using a closed-cycle cooling water system program.

The applicant further stated that at VCSNS, cracking due to SCC is an aging effect for stainless

steel components in treated water environments (i.e., heat exchangers cooled by the

component cooling water system). The Chemistry Program has proven effective at managing

aging degradation in the component cooling water System as evidenced by the review of

operating history in response to GL 89-13. Finally, the applicant stated that prior to the period

of extended operation, one-time inspections will be conducted in low-flow areas of various

treated water systems to demonstrate the effectiveness of the Chemistry Program.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified the basis of the difference between GALL and the LRA. In

addition, prior to the period of extended operation, the applicant has committed to conduct onetime inspections in low-flow areas of various treated water systems to demonstrate the

effectiveness of the Chemistry Program.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the liquid waste processing system SSCs to the environments described

in LRA Tables 2.3-9, 3.3-1, and 3.3-2 are consistent with industry experience for these

combinations of materials and environments. Therefore, the staff finds that the applicant has

identified the appropriate aging effects for the materials and environments associated with the

components in the liquid waste processing system.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the liquid waste

processing system:

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Chemistry Program (3.0.3.2)

• Maintenance Rule Structures Program (3.0.3.4)

• Liquid Waste System Inspection Program (3.3.2.3.14)

• Inspections for Mechanical Components (3.0.3.7)

The Boric Acid Corrosion Surveillances Program, the Chemistry Program, and Maintenance

Rule Structures Program are credited with managing the aging effects of several components in

different structures and systems and are, therefore, considered common AMPs. The staff has

evaluated these common AMPs and has found them to be acceptable for managing the aging

effects identified for this system. The staff’s evaluation of these AMPs is documented in

Sections 3.0.3.1, 3.0.3.2, and 3.0.3.4, respectively, of this SER.
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The staff has evaluated the system-specific Liquid Waste System Inspection AMP and has

found it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of this AMP is documented in Section 3.3.2.3.14 of this SER.

After evaluating the applicant’s AMR for each of the components in the liquid waste processing

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2 , the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with liquid waste

processing system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions:

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.15 Nuclear and Nonnuclear Plant Drains System

Summary of Technical Information in the Application

The description of the nuclear and nonnuclear plant drains can be found in Section 2.3.3.15 of

this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-29. The components, aging effects, and aging management

programs are provided in the LRA Table 3.3-2. 

Aging Effects:

The components in this group category described in Section 2.3.3.15 of the LRA are identified

as being within the scope of license renewal and subject to an AMR. Tables 2.3-29 and 3.3-2

of the LRA, and the table entitled, Virgil C. Summer Nuclear Station Database AMR Query,” in

the LRA supplement documents list individual components of the system. 

The component groups of nuclear plant drains listed by the applicant in the VCSNS LRA

include valves (body only) and pipe and fittings. Stainless steel components exposed to

borated water are identified as subject to loss of material due to crevice corrosion, pitting

corrosion, and cracking from SCC. Stainless steel components exposed to sheltered, reactor

building, ventilation, and embedded in concrete environments are identified as having no aging

effects.
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The applicant identified the intended function of the nonnuclear plant drains system to be

providing the circulating water pump trip function to prevent flooding in the control and

intermediate buildings. This is an active function. Therefore, the components in the nonnuclear plant drains are identified as not requiring aging management. 

Aging Management Programs:

The following AMP is utilized to manage aging effects in the nuclear and nonnuclear plant

drains:

 Liquid Waste System Inspection Program (B.2.3)

A description of this AMP is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the nuclear plant drains will be

adequately managed by this AMP during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the aging effects identified by the applicant for the components exposed to

the environments of the nuclear and nonnuclear plant drains, as described in Section 2.3.3.15,

Tables 2.3-29, and 3.3-2 of the LRA, as well as in the tables entitled, Virgil C. Summer Nuclear

Station Database AMR Query,” and Virgil C. Summer Nuclear Station Database AMR Query

Notes,” in the LRA supplement documents. During its review, the staff determined that

additional information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

A common RAI (RAI 3.3-3), concerning the susceptibility to aging effects for stainless steel

components in an ambient environment in the auxiliary systems is related to components of the

nuclear and nonnuclear plant drains. RAI 3.3-3, and the applicant’s response, is evaluated in

Section 3.3.2.5.3 of this SER.

RAI B.2.3-1 is also relevant to the components of the nuclear and nonnuclear plant drains

system. This RAI, together with the evaluation of applicant’s response, is documented in

Section 3.3.2.3.5 of this SER.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the nuclear and nonnuclear plant drains SSCs to the environments

described in LRA Tables 2.3-29, 3.3-1, and 3.3-2 are consistent with industry experience for

these combinations of materials and environments. Therefore, the staff finds that the applicant
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has identified the appropriate aging effects for the materials and environments associated with

the components in the nuclear and nonnuclear plant drains.

Aging Management Programs:

The applicant credited the following AMP for managing the aging effects in the nuclear and

nonnuclear plant drains:

 Liquid Waste System Inspection Program (3.3.2.3.5)

The staff has evaluated the system-specific Liquid Waste System Inspection (AMP) and has

found it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of this AMP is documented in Section 3.3.2.3.5 of this SER.

The response to RAI B.2.3-1, for the Liquid Waste System Inspection Program clarified that the

contents of the sumps contain leakage from high purity systems, and that the stainless steel

containment penetrations managed by the AMP are also leak tested under 10 CFR Part 50

Appendix J. This RAI response also stated that operating experience at VCSNS for the nuclear

drain system components managed by the program reveals no history of degradation for the

internal surfaces.

After evaluating the applicant’s AMR for each of the components in the nuclear and nonnuclear

plant drains, the staff evaluated the AMP listed above to determine if it is appropriate for

managing the identified aging effects for this system. For the components identified in LRA

Table 3.3-2, the staff verified that the applicant credited AMPs that are appropriate for the

identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the nuclear and 

nonnuclear plant drains. In addition, the staff finds the associated program descriptions in the

FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.16 Nuclear Sampling System

Summary of Technical Information in the Application

The description of the nuclear sampling system can be found in Section 2.3.3.16 of this SER. 

The passive, long-lived components in this system that are subject to an AMR are identified in
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LRA Table 2.3-30. The components, aging effects, and AMPs are provided in LRA Tables 3.3-

1 and 3.3-2. 

Aging Effects:

Components of the nuclear sampling system are described in Section 2.3.3.16 of the LRA as

being within the scope of license renewal and subject to AMR. Table 2.3-30, 3.3-1, and 3.3-2 of

the LRA, and the supplementary table and notes entitled, Virgil C. Summer Nuclear Station

Database AMR Query,” list individual components of the system including heat exchanger (shell

and tubes), pipe, pumps (casing only), tanks, tube and tube fittings, and valves (bodies only).

Loss of material is identified as an aging effect due to pitting, crevice, galvanic, and general

corrosion for carbon steel components exposed to an internal environment of treated water.

Loss of material from pitting and crevice corrosion, corrosion impact from alternate wetting and

drying (for stainless steel), and cracking from SCC are identified as aging effects for stainless

steel and nickel-based alloy components exposed to an internal environment of treated water.

Loss of material is identified as an aging effect from pitting and crevice corrosion and cracking

from SCC (for nickel-based alloy) for stainless steel and nickel-based alloy components

exposed to an internal environment of borated water.

Loss of material is identified as an aging effect from general corrosion (for carbon steel) and

MIC (for stainless steel) for carbon steel and stainless steel components exposed to an external

sheltered environment. No aging effect is identified for stainless steel components exposed to

an external ventilation environment. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the nuclear sampling system:

 Inspections for Mechanical Components Program (B.2.11)

 Chemistry Program (B.1.4)

 Above Ground Tank Inspection Program (B.2.1)

• Maintenance Rule Structures Program (B.1.18)

A description of the AMP is provided in Appendix B of the LRA. The applicant indicated that the

effects of aging associated with the components of the nuclear sampling system will be

adequately managed by the identified AMPs during the period of extended operation.

Staff Evaluation

Aging Effect:

The staff reviewed the information in Section 2.3.3.16 and Tables 2.3-30, 3.3-1, and 3.3-2 in the

LRA, as well as in the supplementary table and notes entitled, Virgil C. Summer Nuclear

Station Database AMR Query.” During its review, the staff determined that additional

information was needed. 

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these
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environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1,

pertaining to this issue of the plant-specific characteristics of the environment. The staff’s

evaluation of the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is

characterized as resolved.

For carbon steel components exposed to external environments of moist air, such as reactor

building or sheltered, the GALL Report identifies that loss of material is an aging effect that is

caused by general, pitting, and crevice corrosion and MIC. The VCSNS LRA identifies loss of

material as an aging effect due to general corrosion only. By letter dated March 28, 2003, the

staff requested, in RAI 3.3.2.4.16-1, the applicant to justify why pitting or crevice corrosion or

MIC does not occur for the carbon steel components exposed to external environments of moist

air, such as reactor building or sheltered. If an insignificant concentration of contaminants is

part of the technical basis, the staff also requested the applicant to provide the acceptance

criterion used and the verification/inspection activities performed to justify its conclusion.

In its response dated June 12, 2003, the applicant stated that plant operating experience has

identified the accumulation of microbiological organisms on the external surfaces of some

piping components at building wall penetrations as a result of ground water intrusion effects. 

The structural design of the plant is such that any ground water intrusion in the sheltered

environment is directed to sumps and away from equipment within the scope of license

renewal. It is the residual presence of microbiological organisms that is of concern for subject

mechanical components.

The applicant further stated that the VCSNS FSAR identifies a ground water elevation of 420'

+/- 3'. Certain structures, such as the service water pumphouse, are potentially exposed to a

ground water level of 425'. As such, piping, process tubing, and ductwork component types

were conservatively considered to be susceptible to external MIC if they either enter a building

from outside or pass between buildings included in the sheltered environment below the 425'

elevation. Additionally, the susceptibility to external MIC was limited locally to the area of the

interface with the pertinent wall. For building fire seal penetrations in the sheltered

environment, the management of aging of the pertinent structural commodities precludes the

accumulation of the necessary microbiological organisms, and thus MIC, on interfacing

mechanical component types. 

Therefore, the applicant indicated that loss of material due to MIC has been identified as an

aging effect requiring system-specific evaluation in sheltered environments for piping, process

tubing, and ductwork that pass between pertinent buildings through a nonfire seal penetration

or which enter the building from outside below the 425' elevation. 

The applicant further stated that building penetrations are inspected as part of the Maintenance

Rule Structures Program (Application Section B.1.18). The VCSNS Corrective Action Program

would disposition any ground water in-leakage and resulting degradation. 

VCSNS is located well inland and in an area where forestry is the prime commercial activity. 

VCSNS does not see salt or other corrosive materials in the air from agriculture or industry. 

Crevice and pitting corrosion are not considered to be aging effects for external surfaces

because the ambient environment does not contain contaminants of sufficient quantity to

concentrate on external surfaces such that pitting or crevice corrosion would occur. Rainwater

analyses reveal a concentration of less than 10 ppm for chlorides and sulfates.
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Finally, the applicant stated that general corrosion of external surfaces of the nuclear sampling 

system will be managed by the Inspections for Mechanical Components Program this program

will consist of a visual inspection of surfaces for any degradation or abnormality.

On the basis of its review, the staff finds that the applicant’s response is acceptable because

(1) the applicant has properly identified that the susceptibility to external MIC is limited locally to

the area of the interface with the pertinent wall, (2) plant operating experience has identified the

accumulation of microbiological organisms on the external surfaces of some piping components

at building wall penetrations as a result of ground water intrusion effects, and (3) the ambient

environment does not contain contaminants of sufficient quantity to concentrate on external

surfaces such that pitting or crevice corrosion would occur. However, the staff questioned

whether there are types of water other than ground water from intrusion (such as water from

condensation) present in the sheltered environment such that loss of material from MIC may

become an aging effect for the external surfaces of some of the applicable components of this

system. The applicant was also requested to provide the justification, including operating

experience, for not considering MIC from other types of water.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain the nutrients necessary to promote external MIC in other types of water, such

as water from condensation. In addition, because external MIC has not been found at locations

other than at building penetrations, VCSNS does not specifically credit the Inspections for

Mechanical Components Program for aging management for this aging effect. However, the

applicant further stated that the Inspections for Mechanical Components Program will inspect

for any abnormalities on external surfaces. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain the nutrients

necessary to promote external MIC in other types of water, such as water from condensation. 

In addition, the applicant has committed to use the Inspections for Mechanical Components

Program to inspect for any abnormalities on external surfaces. All issues associated with this 

RAI 3.3.2.4.16-1 are considered resolved.

The nuclear sampling system contains borated water. However, the VCSNS B.1.2 Boric Acid

Corrosion Surveillance AMP is not mentioned in the database AMR query table of the nuclear

sampling system. By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.16-2, the

applicant to address how the loss of material from boric acid corrosion due to borated water

leakage is managed for the components of the nuclear sampling system or to provide the basis

for why this is not an applicable aging effect.

In its response dated June 12, 2003, the applicant stated that VCSNS considers boric acid

corrosion to be an aging mechanism for carbon steel components in the nuclear sampling

system. The applicant further stated that the Boric Acid Corrosion Surveillances Program will

manage this aging mechanism. Table 2.3-30 of Section 2.3.3.16, Nuclear Sampling System,”

of the application refers to Table 3.3-1, Item 13 in which the Boric Acid Corrosion Surveillances

Program is discussed.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified boric acid corrosion to be an aging mechanism for carbon steel

components in the nuclear sampling system. Furthermore, the Boric Acid Corrosion
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Surveillances Program will manage this aging mechanism. All issues associated with RAI

3.3.2.4.16-2 are considered resolved. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the nuclear sampling system SSCs to the environments described in LRA

Tables 2.3-9, 3.3-1, and 3.3-2 are consistent with industry experience for these combinations of

materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the nuclear sampling system.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the nuclear

sampling system:

 Inspections for Mechanical Components Program (3.0.3.7)

 Chemistry Program (3.0.3.2)

 Above Ground Tank Inspection Program (3.0.3.5)

 Maintenance Rule Structures Program (3.0.3.4)

The Inspections for Mechanical Components Program, Chemistry Program, Above Ground

Tank Inspection Program, and Maintenance Rule Structures Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff has evaluated these common AMPs and found

them to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of these AMPs is documented in Sections 3.0.3.7, 3.0.3.2, 3.0.3.5, and 3.0.3.4,

respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the nuclear sampling

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the nuclear

sampling system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement
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for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.17 Radiation Monitoring System 

Summary of Technical Information in the Application

The description of the radiation monitoring system can be found in Section 2.3.3.17 of this SER. 

The passive, long-lived components in this system that are subject to an AMR are identified in

LRA Table 2.3-31. The components, aging effects, and AMPs are provided in LRA Tables 3.3-

1 and 3.3-2. 

Aging Effects:

Components of the radiation monitoring system are described in Section 2.3.3.17 of the LRA as

being within the scope of license renewal and subject to an AMR. Tables 2.3-31, 3.3-1, and

3.3-2 of the LRA, and the table entitled, Virgil C. Summer Nuclear Station Database AMR

Query,” in the supplement list individual components of the system including pressure retaining

instrumentation, pipe and fittings, tanks, tube and tube fittings, and valve bodies. 

Stainless steel components are subject to the aging effect of loss of material of internal

surfaces due to crevice and pitting corrosion from a treated or a borated water environment.

External surfaces of stainless steel pipe and fittings are also subject to the aging effect of loss

of material due to MIC from exposure to a sheltered environment. Exposure of other stainless

steel components to a sheltered environment has no aging effect.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the radiation monitoring system:

 Chemistry Program (B.1.4)

 Maintenance Rule Structures Program (B.1.18)

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the radiation monitoring system will be

adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.10 and Tables 2.3-31, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled, Virgil C. Summer Nuclear Station Database AMR Query,”

and Virgil C. Summer Nuclear Station Database AMR Query Notes,” in the supplement. 

During its review, the staff determined that additional information was needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining
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to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

The table, entitled Virgil C. Summer Nuclear Station Database AMR Query,” states that, for

stainless steel pipe and fittings in a sheltered environment, the loss of material due to MIC can

be managed for the period of extended operation by the applicant’s Maintenance Rule

Structures Program (B.1.18). The applicant also stated that exposure of other stainless steel

components, such as pressure retaining instrumentation, tanks, tube and tube fittings, and

valve bodies, to the same sheltered environment has no aging effect. By letter dated March 28,

2003, the staff requested, in RAI 3.3.2.4.17-1, the applicant to address and clarify this

inconsistency.

In its response dated June 12, 2003, the applicant stated that plant operating experience has

identified the accumulation of microbiological organisms on the external surfaces of some

piping components at building wall penetrations as a result of ground water intrusion effects. 

The structural design of the plant is such that any ground water intrusion in the sheltered

environment is directed to sumps and away from equipment within the scope of license

renewal. It is the residual presence of microbiological organisms that is of concern for subject

mechanical components.

The applicant further stated that the VCSNS FSAR identifies a ground water elevation of 420'

+/- 3'. Certain structures, such as the service water pumphouse, are potentially exposed to a

ground water level of 425'. As such, piping, process tubing, and ductwork component types

were conservatively considered to be susceptible to external MIC if they either enter a building

from outside or pass between buildings included in the sheltered environment below the 425'

elevation. Additionally, the susceptibility to external MIC was limited locally to the area of the

interface with the pertinent wall. For building fire seal penetrations in the sheltered

environment, the management of aging of the pertinent structural commodities precludes the

accumulation of the necessary microbiological organisms, and thus MIC, on interfacing

mechanical component types. 

The applicant indicated that loss of material due to MIC has been identified as an aging effect

requiring system-specific evaluation in sheltered environments for piping, process tubing, and

ductwork that pass between pertinent buildings through a nonfire seal penetration or which

enter the building from outside below the 425' elevation.

The applicant further stated that during the integrated plant assessment for VCSNS it was

deemed to be expeditious and conservative to assume that any plant system located in a

sheltered environment was susceptible to MIC. This precluded the need to physically walk

down or evaluate each system for this mechanism. As time permitted, systems would be

evaluated or walked down to determine if indeed they were susceptible to MIC. If time did not

permit, the assumption was conservative because the Maintenance Rule Structures Program

looks at all walls and penetrations, and, therefore manages aging for any system at the

susceptible locations. Finally, the applicant stated that, although listed in the LRA as an aging

mechanism for stainless steel pipe in the radiation monitoring system, the portions of the

radiation monitoring system in scope for license renewal are, in fact, not in locations where they

would be susceptible to MIC. 
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On the basis of its review, the staff finds the applicant’s response acceptable because that the

applicant has properly identified that the susceptibility to external MIC is limited locally to the

area of the interface with the pertinent wall where the accumulation of microbiological

organisms on the external surfaces of some piping components at building wall penetrations

results from ground water intrusion effects. Further, the portions of the radiation monitoring

system in scope for license renewal are, in fact, not in locations where they would be

susceptible to MIC. However, the staff questioned whether there are types of water other than

ground water from intrusion (such as water from condensation) present in the sheltered

environment such that loss of material from MIC may become an aging effect for the external

surfaces of some of the applicable components of this system. The applicant was requested to

provide the justification, including operating experience, for not considering MIC from other

types of water.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain the nutrients necessary to promote external MIC in other types of water, such

as water from condensation. In addition, because external MIC has not been found at locations

other than at building penetrations, VCSNS does not specifically credit the Inspections for

Mechanical Components Program for aging management for this aging effect. However, the

applicant further stated that the Inspections for Mechanical Components Program will inspect

for any abnormalities on external surfaces. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain the nutrients

necessary to promote external MIC in other types of water, such as water from condensation,

and the applicant has committed to use the Inspections for Mechanical Components Program to

inspect for any abnormalities on external surfaces. All issues in RAI 3.3.2.4.17-1 are

considered resolved.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the radiation

monitoring system:

 Chemistry Program (3.0.3.2)

 Maintenance Rule Structures Program (3.0.3.4)

The Chemistry Program and the Maintenance Rule Structures Program are credited with

managing the aging effects of several components in different structures and systems and are,

therefore, considered common AMPs. The staff has evaluated these common AMPs and has

found them to be acceptable for managing the aging effects identified for this system. The

staff’s evaluation of these AMPs is documented in Sections 3.0.3.2 and 3.0.3.4, respectively, of

this SER.

After evaluating the applicant’s AMR for each of the components in the radiation monitoring

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 
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On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the radiation

monitoring system. In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.18 Reactor Makeup Water Supply System 

Summary of Technical Information in the Application

The description of the reactor makeup water supply system can be found in Section 2.3.3.18 of

this SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-32. The components, aging effects, and AMPs are provided in LRA

Table 3.3-2. 

Aging Effects:

The reactor makeup water supply system is described in Section 2.3.3.18 of the LRA as being

within the scope of license renewal and subject to an AMR. Tables 2.3-32 and 3.3-2 of the

LRA, and the supplementary table and notes entitled, Virgil C. Summer Nuclear Station

Database AMR Query,” list individual components of the system including orifices, pipe and

fittings, pump casings, tanks, tube and tube fittings, and valve bodies.

Stainless steel components are subject to the aging effects of loss of material due to crevice

corrosion, pitting corrosion, and corrosive impacts of alternate wetting and drying, and cracking

of internal surfaces due to SCC from a treated water environment. External surfaces of

stainless steel pipe and fittings are also subject to the aging effect of loss of material due to

MIC from exposure to a sheltered environment. Exposure of other stainless steel components

to a sheltered, yard, or ventilation environment has no aging effect.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the reactor makeup water supply

system:

 Chemistry Program (B.1.4)

 Maintenance Rule Structures Program (B.1.18)

 Above Ground Tank Inspection Program (B.2.1)
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A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the reactor makeup water supply system

will be adequately managed by these AMPs during the period of extended operation.

Staff Evaluation

Aging Effect:

The staff reviewed the information in Section 2.3.3.18 and Tables 2.3-32 and 3.3-2 in the LRA,

as well as in the supplementary table and notes entitled, Virgil C. Summer Nuclear Station

Database AMR Query.” During its review, the staff determined that additional information was

needed.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant-specific characteristics of the environment. The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER and is characterized as

resolved.

In the table entitled, Virgil C. Summer Nuclear Station Database AMR Query,” the applicant

stated that for stainless steel pipe and fittings in a sheltered environment, the loss of material

due to MIC can be managed for the period of extended operation by the applicant’s

Maintenance Rule Structures Program (B.1.18). The applicant also stated that exposure of

other stainless steel components, such as orifices, pump casings, tube and tube fittings, and

valve bodies, to the same sheltered environment has no aging effect. By letter dated March 28,

2003, the staff requested, in RAI 3.3.2.4.18-1, the applicant to clarify this inconsistency.

In its response dated June 12, 2003, the applicant stated that plant operating experience has

identified the accumulation of microbiological organisms on the external surfaces of some

piping components at building wall penetrations as a result of ground water intrusion effects. 

The structural design of the plant is such that any ground water intrusion in the sheltered

environment is directed to sumps and away from equipment within the scope of license

renewal. It is the residual presence of microbiological organisms that is of concern for subject

mechanical components.

The applicant further stated that the VCSNS FSAR identifies a ground water elevation of 420'

+/- 3'. Certain structures, such as the service water pumphouse, are potentially exposed to a

ground water level of 425'. As such, piping, process tubing, and ductwork component types

were conservatively considered to be susceptible to external MIC if they either enter a building

from outside or pass between buildings included in the sheltered environment below the 425'

elevation. Additionally, the susceptibility to external MIC was limited locally to the area of the

interface with the pertinent wall. For building fire seal penetrations in the sheltered

environment, the management of aging of the pertinent structural commodities precludes the

accumulation of the necessary microbiological organisms, and thus MIC, on interfacing

mechanical component types.

The applicant indicated that therefore, loss of material due to MIC has been identified as an

aging effect requiring system-specific evaluation in sheltered environments for piping, process
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tubing, and ductwork that pass between pertinent buildings through a nonfire seal penetration

or which enter the building from outside below the 425’ elevation.

Finally, the applicant stated that, for the reactor makeup water supply system, only piping

penetrates buildings, therefore, only piping is susceptible to MIC.

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the susceptibility to external MIC is limited locally to the

area of the interface with the pertinent wall where the accumulation of microbiological

organisms on the external surfaces of some piping components at building wall penetrations

results from ground water intrusion effects. Further, for the reactor makeup water supply

system, only piping penetrates buildings; therefore, only piping is susceptible to MIC. However, 

the staff questioned whether there are types of water other than ground water from intrusion

(such as water from condensation) present in the sheltered environment such that loss of

material from MIC may become an aging effect for the external surfaces of some of the

applicable components of this system. The applicant was also requested to provide the

justification, including operating experience, for not considering MIC from other types of water.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain the nutrients necessary to promote external MIC in other types of water, such

as water from condensation. In addition, because external MIC has not been found at locations

other than at building penetrations, VCSNS does not specifically credit the Inspections for

Mechanical Components Program for aging management for this aging effect. However, the

applicant further stated that the Inspections for Mechanical Components Program will inspect

for any abnormalities on external surfaces. 

On the basis of its review, the staff finds the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain the nutrients

necessary to promote external MIC in other types of water, such as water from condensation,

and the applicant has committed to use the Inspections for Mechanical Components Program to

inspect for any abnormalities on external surfaces. All issues associated with this RAI

3.3.2.4.18-1, are considered resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the reactor makeup water supply system SSCs to the environments

described in LRA Tables 2.3-9, 3.3-1, and 3.3-2 are consistent with industry experience for

these combinations of materials and environments. Therefore, the staff finds that the applicant

has identified the appropriate aging effects for the materials and environments associated with

the components in the reactor makeup water supply system.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the reactor

makeup water supply system:

 Chemistry Program (3.0.3.2)

 Maintenance Rule Structures Program (3.0.3.4)

 Above Ground Tank Inspection Program (3.0.3.5)
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The Chemistry Program, Maintenance Rule Structures Program, and Above Ground Tank

Inspection Program are credited with managing the aging effects of several components in

different structures and systems and are, therefore, considered common AMPs. The staff has

evaluated these common AMPs and has found them to be acceptable for managing the aging

effects identified for this system. The staff’s evaluation of these AMPs is documented in

Sections 3.0.3.2, 3.0.3.4, and 3.0.3.5, respectively, of this SER.

After evaluating the applicant’s AMR for each of the components in the reactor makeup water

supply system, the staff evaluated the AMPs listed above to determine if they are appropriate

for managing the identified aging effects for this system. For those components identified in

Table 3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by

the GALL Report. For the components identified in LRA Table 3.3-2, the staff verified that the

applicant credited AMPs that are appropriate for the identified aging effects. 

On the basis of its review, the staff finds that the applicant has credited the appropriate AMPs

to manage the aging effects for the materials and environments associated with the reactor

makeup water supply system. In addition, the staff finds the associated program descriptions in

the FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.3.2.4.19 Roof Drains System 

Summary of Technical Information in the Application

The description of the roof drains system can be found in Section 2.3.3.19 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA

Table 2.3-33. The components, aging effects, and AMPs are provided in LRA Table 3.3-2. 

Aging Effects:

Components and the component group of the roof drains system are described in Section

2.3.3.19 of the LRA as being within the scope of license renewal and subject to an AMR. 

Tables 2.3-33 and 3.3-2 of the LRA and the table entitled, Virgil C. Summer Nuclear Station

Database AMR Query,” in the supplement list system components and component groups. 

The component groups in the roof drains system listed by the applicant in the VCSNS LRA

include pipe and fittings. The applicant stated that stainless steel components exposed to

borated water (condensate quality water with traces of boric acid) are subject to the aging

effects of loss of material due to crevice corrosion, pitting corrosion, and cracking from SCC. 
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Stainless steel components of this system experience no aging effects while in a reactor

building environment.

Aging Management Programs:

The following AMP is utilized to manage aging effects in the roof drains system:

 Reactor Building Cooling Unit Inspection Program (B.2.5)

A description of this AMP is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the roof drains system will be

adequately managed by this AMP during the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.19 and Tables 2.3-33 and 3.3-2 in the LRA,

as well as in the tables entitled “Virgil C. Summer Nuclear Station Database AMR Query” and

“Virgil C. Summer Nuclear Station Database AMR Query Notes” in the supplement. During its

review, the staff found that additional information was needed to complete its review.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1,

pertaining to this issue of the plant-specific characteristics of the environment. The staff’s

evaluation of the applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is

characterized as resolved.

A general RAI (RAI 3.3-3), which is applicable to the roof drains system on the susceptibility to

aging effects for stainless steel components in ambient environment has been raised by the

staff. The details of the RAI, the applicant’s response and the staff’s evaluation is described in

Section 3.3.2.5 General AMR Issues. By letter dated March 28, 2003, the staff issued RAI 3.3-

3, pertaining to this issue of the susceptibility to aging effects for stainless steel components in

ambient environment. The staff’s evaluation of the applicant’s response is documented in

Section 3.3.2.5.3 of this SER.

RAI B.2.5-2, on the AMP Reactor Building Cooling Unit Inspection (B.2.5) concerning boric acid

corrosion has also been raised by the staff. The details of the RAI, the applicant’s response

and the staff’s evaluation is documented in Section 3.3.2.3.6 of this SER. 

Aging Management Programs:

The applicant credited the following AMP for managing the aging effects in the roof drains

system:

 Reactor Building Cooling Unit Inspection (Section 3.3.2.3.6)
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The staff has evaluated this AMP and has found it to be acceptable for managing the aging

effects identified for this system. The staff’s evaluation of this AMP is documented in Section

3.3.2.3.6 of the SER. 

After evaluating the applicant’s AMR for each of the components in the roof drains system , the

staff evaluated the AMP listed above to determine if it is appropriate for managing the identified

aging effects for this system. For the components identified in LRA Table 3.3-2, the staff

verified that the applicant credited the aging management program that is appropriate for the

identified aging effects. 

In the table entitled “Virgil C. Summer Nuclear Station Database AMR Query”, the applicant

stated that stainless steel piping and fitting component of the roof drains system is subjected to

the aging effect of cracking from stress corrosion cracking in a borated water environment. 

LRA Table 3.3-2 Item 22 identifies that the stainless steel drain lines are less than 140 F and

are not susceptible to SCC but are susceptible to crevice or pitting corrosion. AMP B.2.5 is

actually credited with managing SCC in addition to crevice and pitting corrosion which is

acceptable to the staff.

On the basis of its review, the staff finds the applicant has credited the appropriate AMP to

manage the aging effects for the materials and environments associated with the roof drains

system . In addition, the staff finds the associated program description in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and AMPs credited for managing the aging effects, for components in the roof

drains system, such that there is reasonable assurance that the component 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 FSAR Supplement program descriptions and concludes

that the FSAR Supplement provides an adequate program description of the AMP credited for

managing aging in the roof drains system as required by 10 CFR 54.21(d).

3.3.2.4.20 Station Service Air System 

Summary of Technical Information in the Application

The description of the station service air system can be found in Section 2.3.3.20 of this SER. 

The passive, long-lived components in this system that are subject to an AMR are identified in

LRA Table 2.3-34. The components, aging effects, and aging management programs are

provided in LRA Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components and component group of the station service air system are described in Section

2.3.3.20 of the submittal as being within the scope of license renewal and subject to an AMR. 

Tables 2.3-34, 3.3-1, and 3.3-2 of the LRA and the table entitled Virgil C. Summer Nuclear
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Station Database AMR Query in the supplement list system components and components

group. 

The component groups in this category in the station service air system listed by the applicant

in the VCSNS LRA include pipe and fittings, tube and tube fittings, and valves (body only). The

applicant states that carbon steel components exposed to air-gas, reactor building, and

sheltered environments are subject to aging effect of loss of material due to general corrosion. 

Stainless steel components of this system experience no aging effects while in air-gas, reactor

building, and sheltered environments.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the station service air system :

 Boric Acid Corrosion Surveillances (B.1.2)

 Service Air System Inspection (B.2.6)

 Inspections for Mechanical Components (B.2.11)

A description of these aging management programs is provided in Appendix B of the LRA. The

applicant states that the effect of aging associated with the components of the station service

air system will be adequately managed by these aging management programs during the

period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.20 and Tables 2.3-34, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled Virgil C. Summer Nuclear Station Database AMR Query

and Virgil C. Summer Nuclear Station Database AMR Query Notes in the supplement. During

its review, the staff found that additional information was needed to complete its review.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant- specific characteristics of the environment . The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is characterized

as resolved.

By letter dated March 28, 2003, the staff issued RAI 3.3-3, pertaining to this issue of the

susceptibility to aging effects for stainless steel components in ambient environment. The

staff’s evaluation of the applicant’s response is documented in Section 3.3.2.5.3 of this SER

and is characterized as resolved.

Normally station service air system may contain elastomer materials in hose connection seals,

duct seals, flexible collars between ducts and fans, rubber boots, etc. For some plant designs,

elastomer components are used as vibration isolators to prevent transmission of vibration and

dynamic loading to the rest of the system. The aging effects on those elastomer components

are hardening and loss of material. However, no elastomer component associated with the
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station service air system was listed in the LRA. By letter dated March 28, 2003, the staff

requested , in RAI 3.3.2.4.20-1, the applicant to clarify whether there are elastomer

components present in the Station Service Air System and if so, address the management of

the aging effects of hardening and loss of material on the elastomer components.

In its response dated June 13, 2003, the applicant stated that there are no elastomer

components in the portions of the station service air system that are in scope for license

renewal.

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has clarified that there are no elastomer components in the portions of the station

service air system that are in scope for license renewal.

Loss of material due to boric acid corrosion for components adjacent to a source of borated

water is an aging effect for carbon steel components. In the VCSNS Database AMR Query

table, the applicant identified some carbon steel components in the reactor building and

sheltered environments are subject to such an aging effect and some are not. By letter dated

March 28, 2003, the staff requested , in RAI 3.3.2.4.20-2, the applicant to explain why different

conclusions are attained for components with the same material/environment combination. 

In its response dated June 13, 2003, the applicant stated that for license renewal

considerations, a “sheltered” environment is considered to be the ambient conditions inside

certain support buildings. These support buildings include the auxiliary (AB), control (CB),

intermediate (IB), fuel handling (FHB), diesel generator (DB), service (SB), and turbine (TB)

buildings. A “sheltered” environment also includes the fire pump house (FPH), and service

water pump house (SWPH). There are some sheltered environments that do not house

systems that contain borated water; therefore, in these particular sheltered environments boric

acid corrosion is not an aging mechanism; however, VCSNS does consider boric acid corrosion

as an aging mechanism for the station service air system components in scope for license

renewal. Finally the applicant stated that Table 2.3-34 of the LRA Section 2.3.3.20, station

service air system, refers to Table 3.3-1, Item 13, where the Boric Acid Corrosion Surveillances

Program is discussed.

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has properly identified that there are some sheltered environments that do not house

systems that contain borated water; therefore, in these particular sheltered environments boric

acid corrosion is not an aging mechanism and hence this justifies why different conclusions are

attained for components with the same material/environment combination. 

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the station service air system SSCs to the environments described in

Tables 2.3-9, 3.3-1 and 3.3-2 are consistent with industry experience for these combinations of

materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the station service air system .

Aging Management Programs:
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The applicant credited the following AMP for managing the aging effects in the station service

air system :

 Boric Acid Corrosion Surveillances (3.0.3.1)

 Service Air System Inspection (3.3.2.3.7)

 Inspections for Mechanical Components (3.0.3.7)

The Boric Acid Corrosion Surveillances, and Inspections for Mechanical Components AMPs are

credited for managing the aging effects of several components in different structures and

systems and are, therefore, considered common aging management programs. The staff has

evaluated these common AMPs and found them to be acceptable for managing the aging

effects identified for this system. These common AMPs are evaluated in Sections 3.0.3.1 and

3.0.3.7 of this SER.

The staff has evaluated the system-specific AMP Service Air System Inspection and has found

it to be acceptable for managing the aging effects identified for this system. The staff’s

evaluation of these AMPs is documented in Sections 3.3.2.3.7 of this SER.

After evaluating the applicant’s AMR for each of the components in the station service air

system , the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL report. For the components identified in LRA Table 3.3-2 , the staff verified that the

applicant credited aging management programs that is appropriate for the identified aging

effects. 

On the basis of its review, the staff finds the applicant has credited the appropriate AMPs to

manage the aging effects for the materials and environments associated with the station

service air system . In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and AMPs credited for managing the aging effects, for components in the station

service air system , such that there is reasonable assurance that the component 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 FSAR Supplement program descriptions and concludes

that the FSAR Supplement provides an adequate program description of the AMPs credited for

managing aging in the station service air system to satisfy 10 CFR 54.21(d).

3.3.2.4.21 Service Water System 

Summary of Technical Information in the Application

The description of the service water system can be found in Section 2.3.3.21 of this SER. The

passive, long-lived components in this system that are subject to an AMR are identified in LRA
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Table 2.3-35. The components, aging effects, and aging management programs are provided

in LRA Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components and component group of the service water system are described in Section

2.3.3.21 of the submittal as being within the scope of license renewal and subject to an AMR. 

Tables 2.3-35, 3.3-1, and 3.3-2 of the LRA and the table entitled Virgil C. Summer Nuclear

Station Database AMR Query in the supplement list system components and components

group. 

The component types in this category in the service water system listed by the applicant in the

VCSNS LRA include couplings, (coolers, motor bearings), (expansion joints, mechanical,

piping), (expansion joints, mechanical, bellows), orifices, pipe, (thermowells, piping), pipe and

fittings, pumps (casing only), trash racks, (traveling screens, cloth screen), (traveling screens,

screen frames), tube and tube fittings, and valves (body only). The applicant stated that carbon

steel, stainless steel, and copper components of this system exposed to raw water environment

are subject to the aging effects of loss of material from crevice, general, galvanic, pitting and 

micro biologically influenced corrosion, and erosion, and heat exchanger fouling from biological

materials and particulates. Carbon steel components in underground, reactor building, and

sheltered environments are subjected to loss of materials from general, galvanic, pitting and 

MIC as well as crevice, and boric acid corrosion (for the reactor building, and sheltered

environments only). There are no aging effects for carbon steel components in embedded

environment. The applicant stated that stainless steel components in the reactor building, and

sheltered environments have no aging effects except for tube and tube fittings in some

sheltered environment for the aging effect of loss of material from MIC is identified. Copper

components also has no aging effect in oil environment.

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the service water system :

 Service Water System Reliability and In-Service Testing Program (B.1.9)

 Boric Acid Corrosion Surveillances (B.1.2)

 Buried Piping and Tanks Inspection (B.2.10)

 Maintenance Rule Structures Program (B.1.18)

 Inspections for Mechanical Components (B.2.11)

A description of these aging management programs is provided in Appendix B of the LRA. The

applicant states that the effect of aging associated with the components of the service water

system will be adequately managed by these aging management programs during the period of

extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.21 and Tables 2.3-35, 3.3-1, and 3.3-2 in the

LRA, as well as in the tables entitled Virgil C. Summer Nuclear Station Database AMR Query
3-269

and Virgil C. Summer Nuclear Station Database AMR Query Notes in the supplement. During

its review, the staff found that additional information was needed to complete its review.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1, pertaining

to this issue of the plant- specific characteristics of the environment . The staff’s evaluation of

the applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is characterized

as resolved.

The applicant stated in the VCSNS Database AMR Query Table that galvanic corrosion is one

of the applicable aging mechanism that give rise to the aging effect of loss of materials. The

component group affected in this category for the service water system includes carbon steel

couplings, and pipe and fittings in an underground environment. The Buried Piping and Tanks

Inspection is stated as the applicable AMP. The applicant further stated that this AMP will be

consistent with XI.M34, Buried Piping and Tanks Inspection, as identified in NUREG -1801 prior

to the period of extended operation. It should be noted that the likelihood and extent of

galvanic corrosion depends on the relative position of the contacting metal/alloys on the

galvanic potential chart, the electrolyte, immersion time and geometrical factors and many of

these factors are location-dependent. By letter dated March 28, 2003, the staff requested , in

RAI 3.3.2.4.21-1, the applicant to clarify whether the buried piping and tanks inspections are to

be performed in areas with the highest likelihood on galvanic corrosion or are to be performed

on an opportunistic basis and to provide justifications for either case.

In its response dated June 13, 2003, the applicant stated that the buried portions of the Service

Water (SW) System are all carbon steel; therefore, the only possible galvanic reaction would be

between the wrapped/coated piping components and the soil. All buried SW components are

therefore equally susceptible and the opportunistic basis of the Buried Piping and Tanks

Inspection is sufficient. VCSNS coats and wraps underground components in accordance with

site procedures, which are based on accepted industry standard AWWA C-203, 1973. Finally

the applicant stated that operating experience for the Diesel Generator Fuel Oil Storage Tanks

revealed that negligible wall thinning had occurred thereby verifying that the techniques of

coating and wrapping are effective.

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has properly identified that the only possible galvanic reaction would be between the

wrapped/coated piping components and the soil and that all buried SW components are

therefore equally susceptible and the opportunistic basis of the Buried Piping and Tanks

Inspection is sufficient.

For carbon steel component in the sheltered and reactor building environments of VCSNS loss

of materials from aging mechanisms other than boric acid corrosion (such as general corrosion,

galvanic corrosion) may be an applicable aging effect. By letter dated March 28, 2003, the staff

requested, in RAI 3.3.2.4.21-2, the applicant to identify the applicable aging effects and the

associated AMPs or to provide the technical basis to justify no other applicable aging effects for

these components. 

In its response dated June 13, 2003, the applicant stated that for carbon steel components in

the sheltered and reactor building environments, the Inspections for Mechanical Components
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will manage loss of material from galvanic and general corrosion. There are locations in

sheltered environments where carbon steel components are susceptible to MIC. The applicant

further stated that loss of material due to MIC is managed for these susceptible components by

the Maintenance Rule Structures Program.

On the basis of its review, the staff finds that the applicant’s response concerning MIC is

acceptable because that the applicant has properly identified that the AMPs Inspections for

Mechanical Components will manage loss of material from galvanic and general corrosion and

that the Maintenance Rule Structures Program will manage MIC. However, the staff noted that

the likelihood and extent of galvanic corrosion depends on the contact between different metals

or alloys with relative separation of the contacting metal/alloys on the galvanic potential chart,

the electrolyte, immersion time and geometrical factors. Many of these factors are locationdependent. The staff therefore, requested the applicant to clarify whether in using the AMP

Inspections for Mechanical Components to manage the galvanic corrosion the inspection is to

be performed in areas with the highest likelihood on galvanic corrosion or are to be performed

on an opportunistic basis. The applicant is requested to provide justifications for either case.

In its response dated September 2, 2003, the applicant stated that although galvanic corrosion

normally does not occur in the absence of a completely wetted environment, the Inspections for

Mechanical Components will manage galvanic corrosion for external surfaces of components by

periodic inspections for any surface abnormalities.

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has committed to use the Inspections for Mechanical Components to manage

galvanic corrosion for external surfaces of components by periodic inspections for any surface

abnormalities. All issues in RAI 3.3.2.4.21-2, are considered resolved.

The staff noted that the Query Notes (A-SW-f) states that "loss of material due to MIC is an

aging effect for stainless steel components, and is a potential problem in sheltered

environments where contamination from untreated water or soil may have introduced bacteria. 

VCSNS operating experience has identified the accumulation of microbiological organisms on

the external surfaces of some piping components at building wall penetrations as a result of

groundwater intrusion effects. The VCSNS AMR has conservatively considered all piping,

process tubing and ductwork component types to be susceptible to external MIC if they either

enter a building from the outside or pass between buildings included in the sheltered

environment below the 425' elevation. Loss of material due to MIC is only an aging effect

requiring management for the stainless steel process tubing which passes between buildings

below the 425' elevation." 

In the VCSNS Database AMR Query table, the applicant identified no aging effect for stainless

steel expansion joints, mechanical -bellows, orifices, valves (body only) or pipe and fittings

(thermowells) in a sheltered environment. The staff also noted that the applicant identified loss

of materials from MIC as an applicable aging effect for stainless steel tube and tube fittings in a

sheltered environment. By letter dated March 28, 2003, the staff requested, in RAI 3.3.2.4.21-

3, the applicant to clarify the applicability of the discussion in VCSNS Database AMR Query

Notes (A-SW-f) quoted above, and to justify the different conclusion for the identified

components. In particular, the applicant was requested to clarify which components mentioned

above are above or below the 425' elevation and provide the basis for not including MIC as an

applicable aging mechanism for the aging effect of loss of materials. 
3-271

The applicant also does not identify any aging effect for stainless steel tube and tube fittings,

valves (body only) in the reactor building environment. The staff requested the applicant to

provide justification for this omission and, if insignificant concentration of contaminants is part of

the justification, to provide the acceptance criterion and the verification/inspection activities on

susceptible locations to justify the conclusion.

In its response dated June 13, 2003, the applicant stated that the susceptibility to external MIC

is limited locally to the area of the interface with the pertinent wall where groundwater inleakage can occur. Only piping, process tubing, and ductwork component types pass through

building penetrations. For the stainless steel components of the service water (SW) system,

only process tubing can meet these criteria in sheltered environments.

The applicant further stated that VCSNS is located well inland and is located in an area where

forestry is the primary commercial activity. VCSNS does not see salt or other corrosive

materials in the air from agriculture or industry. Rainwater analyses reveal a concentration of

less than 10 ppm for chlorides and sulfates. Because the ambient environment at VCSNS is

not considered to be a corrosive environment, stress corrosion cracking, crevice corrosion, and

pitting corrosion are not considered to be aging mechanisms to be managed for external

surfaces of stainless steel components. There are no locations in the reactor building where

stainless steel components of the SW system are exposed to groundwater in-leakage;

therefore, these components are not susceptible to MIC. Finally the applicant stated that this is

consistent with the operating experience reviews conducted at VCSNS.

On the basis of its review, the staff finds that the applicant’s response acceptable because that

the applicant has properly identified that the susceptibility to external MIC is limited locally to the

area of the interface with the pertinent wall where groundwater in-leakage can occur and that

only piping, process tubing, and ductwork component types pass through building penetrations. 

For the stainless steel components of the SW system, only process tubing can meet these

criteria in sheltered environments. The applicant also properly clarified that the ambient

environment at VCSNS is not considered to be a corrosive environment. However, the staff

questioned whether there are other types of water (such as water from condensation) other

than ground water from intrusion present in the sheltered environment such that loss of material

from MIC may become an applicable aging effect for the external surfaces of some of the

applicable components of this system. The applicant was requested to provide the justification

for not considering MIC from other types of water, including operating experience.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation and that because external MIC has not been found at locations other

than at building penetrations, VCSNS does not specifically credit the Inspections for Mechanical

Components for aging management for this aging effect; however, the applicant further stated

that the Inspections for Mechanical Components will inspect for any abnormalities on external

surfaces. 

On the basis of its review, the staff finds that the applicant’s response acceptable because that

the applicant has properly identified that the ambient environment does not contain nutrients

necessary to promote external MIC in other types of water, such as water from condensation

and that the applicant has committed to use the Inspections for Mechanical Components
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program to inspect for any abnormalities on external surfaces. All issues in RAI 3.3.2.4.21-3,

are considered resolved

The applicant identifies no applicable aging effect for carbon steel components in an embedded

environment. The applicant is requested to provide the specification for the embedded

environment. If this environment involves concrete, corrosion of carbon steel components

embedded in concrete through carbonation etc., is commonly known degradation process. By

letter dated March 28, 2003, the staff requested , in RAI 3.3.2.4.21-4, the applicant to provide

the basis for the concluding that no applicable aging effect exists for carbon steel components

in this particular embedded environment.

In its response dated June 13, 2003, the applicant stated that corrosion of embedded steel is

not significant if the concrete has a low water-to-cement ratio, low permeability, and designed in

accordance with ACI standards (ACI-318 or ACI-349, depending on the building). Finally the

applicant stated that the design and construction of structures at VCSNS meet these criteria;

therefore, the applicant concluded that corrosion of embedded steel is not an aging effect

requiring management at VCSNS.

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has properly identified that the design and construction of structures at VCSNS meet

the criteria of low water-to-cement ratio, low permeability, and designed in accordance with ACI

standards (ACI-318 or ACI-349, depending on the building).

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the SW system SSCs to the environments described in Tables 2.3-9, 3.3-

1 and 3.3-2 are consistent with industry experience for these combinations of materials and

environments. Therefore, the staff finds that the applicant has identified the appropriate aging

effects for the materials and environments associated with the components in the service water

system.

Aging Management Programs

The applicant credited the following AMP for managing the aging effects in the SW system:

• Service Water System Reliability and In-Service Testing Program (Section 3.3.2.3.1)

• Boric Acid Corrosion Surveillances (Section 3.0.3.1)

• Buried Piping and Tanks Inspection (Section 3.0.3.6)

• Maintenance Rule Structures Program (Section 3.0.3.4)

• Inspections for Mechanical Components (Section 3.0.3.7)

The Boric Acid Corrosion Surveillances, Buried Piping and Tanks Inspection, Maintenance Rule

Structures Program, and Inspections for Mechanical Components AMPs are credited for

managing the aging effects of several components in different structures and systems and are,

therefore, considered common aging management programs. The staff has evaluated these

common AMPs and has found them to be acceptable for managing the aging effects identified

for this system. The staff’s review of the common aging management programs is documented

in Section 3.0.3.1, 3.0.3.6, 3.0.3.4, and 3.0.3.7 of this SER. 
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The staff has evaluated the system-specific AMPs Service Water System Reliability and InService Testing Program and has found it to be acceptable for managing the aging effects

identified for this system. The staff’s evaluation of these AMPs is documented in Sections

3.3.2.3.1 of this SER.

After evaluating the applicant’s AMR for each of the components in the SW system, the staff

evaluated the AMPs listed above to determine if they are appropriate for managing the

identified aging effects for this system. For those components identified in Table 3.3-1 of the

LRA, the staff verified that the applicant credited the AMPs recommended by the GALL report. 

For the components identified in LRA Table 3.3-2 , the staff verified that the applicant credited

aging management programs that is appropriate for the identified aging effects. 

On the basis of its review, the staff finds the applicant has credited the appropriate AMPs to

manage the aging effects for the materials and environments associated with the SW system . 

In addition, the staff finds the associated program descriptions in the FSAR Supplement to be

acceptable to satisfy 10 CFR 54.21(d).. 

Conclusions

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and AMPs credited for managing the aging effects, for components in the SW

system, such that there is reasonable assurance that the component 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 FSAR Supplement program descriptions and concludes

that the FSAR Supplement provides an adequate program description of the AMPs credited for

managing aging in the SW system to satisfy 10 CFR 54.21(d).

3.3.2.4.22 Spent Fuel Cooling System

Summary of Technical Information in the Application

The description of the spent fuel cooling system can be found in Section 2.3.3.22 of this SER. 

The passive, long-lived components in this system that are subject to an AMR are identified in

LRA Table 2.3-36. The components, aging effects, and aging management programs are

provided in LRA Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the spent fuel cooling system are described in Section 2.3.3.22 of the submittal

as being within the scope of license renewal, and subject to AMR. Table 2.3-36, 3.3-1 and

3.3-2, of the LRA and the supplementary table and notes, entitled “Virgil C. Summer Nuclear

Station Database AMR Query,” list individual components of the system including heat

exchangers (channel head), heat exchangers (shell), heat exchangers ( tubes), heat

exchangers (tubesheet), orifices, pipe pumps (casing only,) tube and tube fittings, and valves

(body only).
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Loss of material is identified as aging effect for carbon steel and stainless steel components

exposed to internal environment of treated water. Loss of material and cracking are identified

as aging effects for stainless steel refueling water storage tank (RWST) exposed to internal

environment of borated water due to alternate wet and dry at borated water surface. Loss of

material due to crevice and pitting corrosion is identified as aging effects for stainless steel

components exposed to internal environment of borated water other than RWST. No aging

effect is identified for stainless steel components exposed to internal ventilation (i.e., moisture

air) environment. Cracking is not identified as an aging effect for components exposed to

borated water or treated water because the system is normally operated well below 140 F. 

Loss of material due to boric acid corrosion is identified as aging effect for carbon steel

components exposed to sheltered environment. Loss of material due to micro biologically

influenced corrosion is identified as an aging effect for vulnerable stainless steel components

including pipe and tubing exposed to sheltered environment. Loss of material due to micro

biologically influenced corrosion is not identified as aging effect for stainless steel components

other than pipe and tubing exposed to sheltered environment. No aging effect is identified for

stainless steel components exposed to yard environment.

. 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the spent fuel cooling system:

 Chemistry program (B.1.4)

 Boric Acid Corrosion Surveillance (B.1.2)

 Maintenance Rule Structures Program (B.1.18)

 Above Ground Tank Inspection (B.2.1)

A description of the aging management program is provided in Appendix B of the LRA. The

applicant states that the effect of aging associated with the components of the spent fuel

cooling system will be adequately managed by the aging management program during the

period of extended operation.

Staff Evaluation

Aging Effect:

The staff reviewed the information in Section 2.3.3.22 and Tables 2.3-36, 3.3-1 and 3.3-2 in the

LRA; as well as in the supplementary table and notes, entitled “Virgil C. Summer Nuclear

Station Database AMR Query.” The applicant has stated that cracking is not identified as an

aging effect for components exposed to borated water or treated water because the system is

normally operated well below 140F. The staff agrees that cracking is not an aging effect for

spent fuel cooling system components exposed to borated water or treated water because

temperature of the borated water or treated water is below 140F. Below 140F, stress

corrosion cracking is not an aging effect requiring aging management. 

However, during its review, the staff determined that additional information was needed to

complete its review. 

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1,
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pertaining to this issue of the plant- specific characteristics of the environment . The staff’s

evaluation of the applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is

characterized as resolved. 

On page 211 of the VCSNS Database AMR Query Notes, the applicant states that loss of

material due to MIC is identified as an aging effect for vulnerable stainless steel components

including pipe and tubing of the spent fuel cooling system exposed to sheltered environment. 

However, loss of material due to MIC is not identified by the applicant as an aging effect for

stainless steel components other than pipe and tubing. By letter dated March 28, 2003, the

staff requested , in RAI 3.3.2.4.22-1, to provide justification as to why loss of material due to

MIC is identified as an aging effect only for stainless steel pipe and tubing components and not

for other stainless steel components such as heat exchangers, orifices, pumps, and valves. 

In its response dated June 13, 2003, the applicant stated that the susceptibility to external MIC

is limited locally to the area of the interface with the pertinent wall where groundwater inleakage can occur. Only piping, process tubing, and ductwork component types pass through

building penetrations. Finally the applicant stated that for the stainless steel components of the

spent fuel cooling system, only pipe and pipe fitting components meet these criteria.

On the basis of its review, the staff finds that the applicant’s response acceptable because that

the applicant has properly identified that the susceptibility to external MIC is limited locally to the

area of the interface with the pertinent wall where groundwater in-leakage can occur and that

for the stainless steel components of the boron thermal regeneration system, only pipe and

pipe fitting components meet these criteria. However, the staff questioned whether there are

other types of water (such as water from condensation) other than ground water from intrusion

present in the sheltered environment such that loss of material from MIC may become an

applicable aging effect for the external surfaces of some of the applicable components of this

system. The applicant was requested to provide the justification for not considering MIC from

other types of water, including operating experience.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation and that because external MIC has not been found at locations other

than at building penetrations, VCSNS does not specifically credit the Inspections for Mechanical

Components for aging management for this aging effect; however, the applicant further stated

that the Inspections for Mechanical Components will inspect for any abnormalities on external

surfaces. 

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain nutrients

necessary to promote external MIC in other types of water, such as water from condensation

and that the applicant has committed to use the Inspections for Mechanical Components

program to inspect for any abnormalities on external surfaces. All issues associated with this 

RAI 3.3.2.4.22-1, are considered resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the spent fuel cooling system SSCs to the environments described in

Tables 2.3-36, 3.3-1 and 3.3-2 are consistent with industry experience for these combinations
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of materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the spent fuel cooling system.

Aging Management Programs:

The applicant credited the following aging management programs are credited for managing

the aging effects in the spent fuel cooling system.

 Chemistry Program (Section 3.0.3.2) 

 Boric Acid Corrosion Surveillance (Section 3.0.3.1)

 Maintenance Rule Structures Program (Section 3.0.3.4,)

 Above Ground Tank Inspection (Section 3.0.3.5) 

The Chemistry program, Boric Acid Corrosion Surveillance, Maintenance Rule Structures

Program, and Above Ground Tank Inspection Program are credited with managing the aging

effects of several components in different structures and systems and are, therefore,

considered common aging management programs. The staff has evaluated these common

AMPs and found them to be acceptable for managing the aging effects identified for this

system. The staff’s evaluation of these AMPs is documented in Section 3.0.3.2, 3.0.3.1,

3.0.3.4, and 3.0.3.5 of this SER.

After evaluating the applicant’s AMR for each of the components in the spent fuel cooling

system , the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL report. For the components identified in LRA Table 3.3-2 , the staff verified that the

applicant credited aging management programs that is appropriate for the identified aging

effects. 

On the basis of its review, the staff finds the applicant has credited the appropriate AMPs to

manage the aging effects for the materials and environments associated with spent fuel cooling

system . In addition, the staff finds the associated program descriptions in the FSAR

Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusion

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and AMPs credited for managing the aging effects, for components in the spent

fuel cooling system , such that there is reasonable assurance that the component 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 FSAR Supplement program descriptions and concludes

that the FSAR Supplement provides an spent fuel cooling system water system to satisfy 10

CFR 54.21(d).

3.3.2.4.23 Thermal Regeneration System 
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Summary of Technical Information in the Application

The description of the thermal regeneration system can be found in Section 2.3.3.23 of this

SER. The passive, long-lived components in this system that are subject to an AMR are

identified in LRA Table 2.3-37. The components, aging effects, and aging management

programs are provided in LRA Tables 3.3-1 and 3.3-2. 

Aging Effects:

Components of the Thermal Regeneration System are described in Section 2.3.3.23 of the

submittal as being within the scope of license renewal and subject to an AMR. Tables 2.3-37,

3.3-1, and 3.3-2 of the LRA and the supplementary table and notes, entitled “Virgil C. Summer

Nuclear Station Database AMR Query,” list system components and component group. 

The component groups in this category in the thermal regeneration system listed by the

applicant in the VCSNS LRA include demineralizers(XDM0007A/B/C/D); heat exchanger

(XHE0001), moderating – channel head; heat exchanger (XHE0001), moderating –shell; heat

exchanger (XHE0008), letdown chiller – channel head; heat exchanger (XHE0015), letdown

reheat – shell; heat exchanger (XHE0015), letdown reheat – tubes; heat exchanger (XHE0015),

letdown reheat – tubesheet(s); orifices (IFE00385); pipe and fittings; tube and tube fittings; and

valves (body Only). The applicant states that the stainless steel components, except pipe and

pipe fittings, exposed to ventilation and sheltered environments in Thermal Regeneration

System experience no aging effects. Stainless steel pipe and pipe fittings of the thermal

regeneration system in the sheltered environment are identified as subject to aging effect of

loss of material due to micro biologically induced corrosion (MIC). 

Aging Management Programs:

The following AMPs are utilized to manage aging effects in the thermal regeneration system :

 Chemistry Program (B.1.4)

 Maintenance Rule Structures Program (B.1.18)

A description of these aging management programs is provided in Appendix B of the LRA. The

applicant states that the effect of aging associated with the components of the thermal

regeneration system will be adequately managed by these aging management programs during

the period of extended operation.

Staff Evaluation

Aging Effects:

The staff reviewed the information in Section 2.3.3.23 and Tables 2.3-37, 3.3-1, and 3.3-2 in the

LRA, as well as in the supplementary table and notes, entitled “Virgil C. Summer Nuclear

Station Database AMR Query.” During its review, the staff found that additional information was

needed to complete its review.

Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these
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environments in the LRA. By letter dated March 28, 2003, the staff issued RAI 3.3-1,

pertaining to this issue of the plant- specific characteristics of the environment . The staff’s

evaluation of the applicant’s response is documented in Section 3.3.2.5.1 of this SER, and is

characterized as resolved.

In the VCSNS Database AMR Query table on the thermal regeneration system, the applicant

identified only the stainless steel pipe and fittings in the sheltered environment are subject to

aging effect of loss of material due to MIC. The rest of the stainless steel components in the

same environment in this system are identified by the applicant as not subject to loss of

material due to MIC. By letter dated March 28, 2003, the staff requested , in RAI 3.3.2.4.23-1,

the applicant to explain why the conclusions are different for the same combination of material

and environment.

In its response dated June 13, 2003, the applicant stated that the susceptibility to external MIC

is limited locally to the area of the interface with the pertinent wall where groundwater inleakage can occur. Only piping, process tubing, and ductwork component types pass through

building penetrations. The applicant concluded that for the stainless steel components of the

boron thermal regeneration system, only pipe and pipe fitting components meet these criteria.

On the basis of its review, the staff finds that the applicant’s response acceptable because that

the applicant has properly identified that the susceptibility to external MIC is limited locally to the

area of the interface with the pertinent wall where groundwater in-leakage can occur, and that

for the stainless steel components of the boron thermal regeneration system, only pipe and

pipe fitting components meet these criteria. However, the staff questioned whether there are

other types of water (such as water from condensation) other than ground water from intrusion

present in the sheltered environment such that loss of material from MIC may become an

applicable aging effect for the external surfaces of some of the applicable components of this

system. The applicant was requested to provide the justification for not considering MIC from

other types of water, including operating experience.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation and that because external MIC has not been found at locations other

than at building penetrations, VCSNS does not specifically credit the Inspections for Mechanical

Components for aging management for this aging effect; however, the applicant further stated

that the Inspections for Mechanical Components will inspect for any abnormalities on external

surfaces. 

On the basis of its review, the staff finds that the applicant’s response acceptable because the

applicant has properly identified that the ambient environment does not contain nutrients

necessary to promote external MIC in other types of water, such as water from condensation

and that the applicant has committed to use the Inspections for Mechanical Components

program to inspect for any abnormalities on external surfaces. All issues associated with this 

RAI 3.3.2.4.23-1, are considered resolved.

On the basis of its review of the information provided in the LRA and the additional information

included in the applicant’s response to the above RAIs, the staff finds that the aging effects that

result from contact of the thermal regeneration system SSCs to the environments described in

Tables 2.3-37, 3.3-1 and 3.3-2 are consistent with industry experience for these combinations
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of materials and environments. Therefore, the staff finds that the applicant has identified the

appropriate aging effects for the materials and environments associated with the components in

the thermal regeneration system.

Aging Management Programs:

The applicant credited the following AMPs for managing the aging effects in the thermal

regeneration system:

 Chemistry Program (Section 3.0.3.2)

 Maintenance Rule Structures Program (Section 3.0.3.4)

These AMPs are credited for managing the aging effects of components in several structures

and systems and, therefore, are considered common AMPs. The staff has evaluated these

common AMPs and found them to be acceptable for managing the aging effects identified for

this system. These common AMPs are evaluated in Sections 3.0.3.2, and 3.0.3.4 of this SER. 

After evaluating the applicant’s AMR for each of the components in the thermal regeneration

system, the staff evaluated the AMPs listed above to determine if they are appropriate for

managing the identified aging effects for this system. For those components identified in Table

3.3-1 of the LRA, the staff verified that the applicant credited the AMPs recommended by the

GALL report. For the components identified in LRA Table 3.3-2 , the staff verified that the

applicant credited aging management programs that is appropriate for the identified aging

effects. 

On the basis of its review, the staff finds the applicant has credited the appropriate AMPs to

manage the aging effects for the materials and environments associated with thermal

regeneration system. In addition, the staff finds the associated program descriptions in the

FSAR Supplement to be acceptable to satisfy 10 CFR 54.21(d).

Conclusions

On the basis of its review, the staff concludes that the applicant has adequately identified the

aging effects, and AMPs credited for managing the aging effects, for components in thermal

regeneration system, such that there is reasonable assurance that the component 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 FSAR Supplement program descriptions and concludes

that the FSAR Supplement provides an adequate program description of the AMPs credited for

managing aging in the thermal regeneration system to satisfy 10 CFR 54.21(d).

3.3.2.5 General AMR Issues

This section discusses the staff’s evaluation of general AMR issues that are applicable to

components in several auxiliary systems included in Section 3.3 of the LRA.

3.3.2.5.1 Plant Specific Environment Characteristics 
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Numerous tables included in the application list the component material and environment to

which the component is exposed. However, the applicant did not provide a description of these

environments in the LRA. It should be noted that the aging effect depends on the component

material as well as the plant specific environment characteristics. A description of the specific

information (such as ranges of temperature, humidity, and/or compositions etc.) related to the

plant specific environment characteristics considered in the VCSNS LRA will provide the

necessary environment information for the staff to perform its AMR of the components of the

auxiliary systems as well as other systems in the VCSNS. By letter dated March 28, 2003, the

staff requested, in RAI 3.3-1, the applicant to provide a description of the environments

included in the LRA. 

In its response dated June 12, 2003, the applicant stated that the internal environments for

subject components, also known as the process and/or service environment, were determined

by reviewing the appropriate design and operating documentation, including system design

basis documents, flow diagrams, vendor technical manuals, procedures, lesson plans, etc. 

General temperature ranges were not established, thus temperatures for internal environments

are system specific. When performing AMR’s, the temperature ranges were determined on a

system-specific basis from the normal system operating ranges found on the 302 series system

flow diagrams (P&ID) and are contained in the body of technical work, which is available for

inspection. VCSNS is generally consistent in its internal environments with other stations and

with the environments described in NUREG-1801. Internal environments for license renewal

mechanical consideration for VCSNS include:

 Air-Gas (including vacuum, compressed air, compressed gases, and exhaust gases),

 Borated Water (chemically treated borated water),

 Oil (such as fuel oil, lubricating oil, synthetic oil),

 Raw Water (water taken directly from a lake, reservoir or other open external source),

 Treated Water (including filtered and chemically treated water, condensate quality

water, as well as steam),

 Ventilation (includes ambient building air that is contained and/or processed through

ductwork, and other ventilation equipment)

The applicant further stated that the following external environments are those to which the

external portions of subject components are exposed due to the equipment location, and,

therefore, require evaluation for license renewal considerations:

 Reactor Building,

 Sheltered,

 Yard,

 Underground,

 Embedded (includes significant portions of components/component types embedded in

concrete and not simply portions passing through building walls).

The applicant clarified that for license renewal considerations, a “Sheltered” environment is

considered to be the ambient conditions inside certain support buildings. These support

buildings include the Auxiliary (AB), Control (CB), Intermediate (IB), Fuel Handling (FHB),

Diesel Generator (DB), Service (SB), and Turbine (TB) Buildings. A “Sheltered” environment

also includes the Fire Pump House (FPH), and Service Water Pump House (SWPH).
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The ambient environment for the Reactor Building and Sheltered environments are not

considered to be humidity controlled. The design average maximum temperature for buildings

at VCSNS is 120 F.

VCSNS is located well inland and is located in an area where forestry is the primary commercial

activity. VCSNS does not see salt or other corrosive materials in the air from agriculture or

industry. Finally the applicant stated that rainwater analyses reveal a concentration of less than

10 ppm for chlorides and sulfates.

On the basis of its review, the staff finds the applicant’s response adequate and acceptable

because that the applicant has properly identified the plant-specific environment and that

VCSNS does not see salt or other corrosive materials in the air from agriculture or industry. All

issues associated with this RAI 3.3-1, are considered resolved. 

3.3.2.5.2 Carbon Steel Components in Sheltered Environment 

This general AMR issue concerns aging mechanisms related to the aging effect of loss of

materials in sheltered environment for carbon steel components in the auxiliary systems

described below.

For carbon steel components exposed to external environments of moist air such as sheltered

environment, the GALL report identified loss of material due to general, pitting, crevice

corrosion and MIC as an aging effect. But for carbon steel components in the Gaseous Waste

Processing System the applicant stated, in the table entitled “Virgil C. Summer Nuclear Station

Database AMR Query” that for carbon steel in a sheltered environment, the aging effect of loss

of material is due only to general corrosion. However, in the AMR Query Note A-W.G.-C, the

applicant stated that MIC is also an applicable aging effect for carbon steel in a sheltered

environment. The applicant is requested to clarify this discrepancy. Also for carbon steel

components in the Instrument Air Supply System no aging effect is identified by the applicant

for carbon steel components exposed to sheltered environment. The applicant is requested to

justify why loss of material due to general, pitting, crevice corrosion or MIC is not an applicable

aging effect for the carbon steel components exposed to sheltered environment. 

By letter dated March 28, 2003, the staff requested, in RAI 3.3-2, the applicant to provide a

clarification of the issues highlighted above on the aging mechanisms related to the aging effect

of loss of materials in sheltered environment for carbon steel components in the auxiliary

systems discussed above.

In its response dated June 12, 2003, the applicant stated that plant operating experience has

identified the accumulation of microbiological organisms on the external surfaces of some

piping components at building wall penetrations as a result of groundwater intrusion effects. 

The structural design of the plant is such that any groundwater intrusion in the sheltered

environment is directed to sumps and away from equipment within the scope of license

renewal. It is the residual presence of microbiological organisms that is of concern for subject

mechanical components.

The applicant further stated that the VCSNS Final Safety Analysis Report [FSAR] identifies a

groundwater elevation of 420' +/- 3'. Certain structures, such as the Service Water

Pumphouse, are potentially exposed to a ground water level of 425'. As such, piping, process
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tubing, and ductwork component types were conservatively considered to be susceptible to

external MIC if they either enter a building from outside or pass between buildings included in

the sheltered environment below the 425’ elevation. Additionally, the susceptibility to external

MIC was limited locally to the area of the interface with the pertinent wall. For building fire seal

penetrations in the sheltered environment, the management of aging of the pertinent structural

commodities precludes the accumulation of the necessary microbiological organisms, and thus

MIC, on interfacing mechanical component types.

Therefore, the applicant concluded that loss of material due to MIC has been identified as an

aging effect requiring system specific evaluation in sheltered environments for piping, process

tubing, and ductwork that pass between pertinent buildings through a non fire seal penetration

or enters the building from outside below the 425’ elevation. The applicant also stated that the

building penetrations are inspected as part of the Maintenance Rule Structures Program

(Application Section B.1.18). The VCSNS Corrective Action Program would be used in the

disposition of any groundwater in-leakage and resulting degradation.

Moreover, the applicant stated that crevice and pitting corrosion are not considered to be aging

effects for external surfaces because the ambient environment does contain contaminants of

sufficient quantity to concentrate on external surfaces such that pitting or crevice corrosion

would occur. Rainwater analyses reveal a concentration of less than 10 ppm for chlorides and

sulfates. Finally, the applicant stated that general corrosion is an aging effect for external

surfaces in sheltered environments and that it is managed by the Inspections for Mechanical

Components.

On the basis of its review of the above information, the staff requested the applicant to clarify

whether there are other types of water (such as water from condensation) other than ground

water from intrusion present in the sheltered environment such that loss of material from MIC

may become an applicable aging effect for the external surfaces of some of the applicable

components of this system. The applicant was also requested to provide the justification for not

considering MIC from other types of water, including operating experience.

In its response dated September 2,2003, the applicant stated that the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation and that because external MIC has not been found at locations other

than at building penetrations, VCSNS does not specifically credit the Inspections for Mechanical

Components for aging management for this aging effect; however, the applicant further stated

that the Inspections for Mechanical Components will inspect for any abnormalities on external

surfaces. 

On the basis of its review, the staff finds the applicant’s response adequate and acceptable 

because the applicant has demonstrated that 1) loss of material due to MIC has been identified

as an aging effect requiring system specific evaluation in sheltered environments for piping,

process tubing, and ductwork that pass between pertinent buildings through a non fire seal

penetration or enters the building from outside below the 425' elevation, 2) the ambient

environment does not contain contaminants of sufficient quantity to concentrate on external

surfaces such that pitting or crevice corrosion would occur, and 3) the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation. In addition, the applicant will use the Inspections for Mechanical
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Components program to inspect for any abnormalities on external surfaces. All issues

associated with this RAI 3.3-2, are resolved.

3.3.2.5.3 Stainless Steel Components in Sheltered Environment 

This general AMR issue concerns the susceptibility to aging effects for stainless steel

components in ambient environment in the auxiliary systems described below.

Stainless steel components in ambient environment may be subject to aging effect of loss of

material due to pitting, crevice corrosion and MIC. In the VCSNS Database AMR Query table,

the applicant identified no aging effects for stainless steel pipe and fittings, tube and tube

fittings, and valves (body only) in the reactor building and sheltered environments because of

the presence of insignificant concentration of contaminants in these environments. The

applicant is requested to provide the basis for determining significant concentration of

contaminants and the verification/inspection activities on susceptible locations to justify this

basis. These issues are applicable to stainless steel components in ambient environment in the

Liquid Waste Processing System, Nuclear & Non-nuclear Plant Drains, Roof Drains System,

and the Station Service Air System.

By letter dated March 28, 2003, the staff requested, in RAI 3.3-3, the applicant to provide a

clarification of the issues highlighted above on the aging mechanisms related to the aging effect

of loss of materials in sheltered environment for stainless steel components in the auxiliary

systems discussed above.

In its response dated June 13, 2003, the applicant stated that plant operating experience has

identified the accumulation of microbiological organisms on the external surfaces of some

piping components at building wall penetrations as a result of groundwater intrusion effects. 

The structural design of the plant is such that any groundwater intrusion in the sheltered

environment is directed to sumps and away from equipment within the scope of license

renewal. It is the residual presence of microbiological organisms that is of concern for subject

mechanical components.

The applicant further stated that the VCSNS Final Safety Analysis Report [FSAR] identifies a

groundwater elevation of 420’ +/- 3’. Certain structures, such as the service water pumphouse,

are potentially exposed to a ground water level of 425’. As such, piping, process tubing, and

ductwork component types were conservatively considered to be susceptible to external MIC if

they either enter a building from outside or pass between buildings included in the sheltered

environment below the 425’ elevation. Additionally, the susceptibility to external MIC was

limited locally to the area of the interface with the pertinent wall. For building fire seal

penetrations in the sheltered environment, the management of aging of the pertinent structural

commodities precludes the accumulation of the necessary microbiological organisms, and thus

MIC, on interfacing mechanical component types.

Therefore, the applicant concluded that loss of material due to MIC has been identified as an

aging effect requiring system specific evaluation in sheltered environments for piping, process

tubing, and ductwork that pass between pertinent buildings through a non fire seal penetration

or enters the building from outside below the 425’ elevation.
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In addition, the applicant stated that building penetrations are inspected as part of the

Maintenance Rule Structures Program (Application Section B.1.18). The VCSNS Corrective

Actions Program would disposition any groundwater in-leakage and resulting degradation. 

VCSNS is located well inland and is located in an area where forestry is the prime commercial

activity. VCSNS does not see salt or other corrosive materials in the air from agriculture or

industry. Crevice and pitting corrosion are not considered to be aging effects for external

surfaces because the ambient environment does not contain contaminants of sufficient quantity

to concentrate on external surfaces such that pitting or crevice corrosion would occur. Finally,

the applicant stated that rainwater analyses reveal a concentration of less than 10 ppm for

chlorides and sulfates.

On the basis of its review of the above information, the staff requested the applicant to clarify

whether there are other types of water (such as water from condensation) other than ground

water from intrusion present in the sheltered environment such that loss of material from MIC

may become an applicable aging effect for the external surfaces of some of the applicable

components of this system. The applicant was also requested to provide the justification for not

considering MIC from other types of water, including operating experience.

In its response dated September 2, 2003, the applicant stated that the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation and that because external MIC has not been found at locations other

than at building penetrations, VCSNS does not specifically credit the Inspections for Mechanical

Components for aging management for this aging effect; however, the applicant further stated

that the Inspections for Mechanical Components will inspect for any abnormalities on external

surfaces. 

On the basis of its review, the staff finds the applicant’s response adequate and acceptable 

because the applicant has demonstrated that 1) loss of material due to MIC has been identified

as an aging effect requiring system specific evaluation in sheltered environments for piping,

process tubing, and ductwork that pass between pertinent buildings through a non fire seal

penetration or enters the building from outside below the 425' elevation, 2) the ambient

environment does not contain contaminants of sufficient quantity to concentrate on external

surfaces such that pitting or crevice corrosion would occur, and 3) the ambient environment

does not contain nutrients necessary to promote external MIC in other types of water, such as

water from condensation. In addition, the applicant will use the Inspections for Mechanical

Components program to inspect for any abnormalities on external surfaces. All issues

associated with this RAI 3.3-3, are considered resolved.

3.4 Steam and Power Conversion Systems

This section addresses the aging management of the components of the steam and power

conversion (SPC) systems group. The systems that make up the SPC systems group are

described in the following SER sections: 

• auxiliary boiler steam and feedwater (2.3.4.1)

• condensate (2.3.4.2)

• emergency feedwater (2.3.4.3)

• extraction steam (2.3.4.4)
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• feedwater (2.3.4.5)

• gland sealing steam (2.3.4.6)

• main steam (2.3.4.7)

• main steam dump (2.3.4.8)

• main turbine and turbine accessories (2.3.4.9)

• turbine cycle sampling (2.3.4.10)

• steam generator blowdown (2.3.4.11)

• electro-hydraulic control (2.3.4.12)

As discussed in Section 3.0.1 of this SER, the components requiring aging management in

each of these SPC systems are included in one of two LRA tables. LRA Table 3.4-1 consists of

SPC systems components that are evaluated in the GALL Report, as well as SPC systems

components that were not evaluated in the GALL Report, but which the applicant has

determined can be managed using a GALL AMR and associated AMP. LRA Table 3.4-2

consists of SPC systems components that are not evaluated in the GALL Report.

3.4.1 Summary of Technical Information in the Application

In LRA Section 3.4, the applicant described its AMRs for the SPC systems group at VCSNS.

The description of the systems that comprise the SPC systems group can be found in LRA

Section 2.3.4. The passive, long-lived components in these systems that are subject to an

AMR are identified in LRA Tables 2.3-38, 2.3-39, 2.3-40, 2.3-41, 2.3-42, 2.3-43, 2.3-44, 2.3-45,

2.3-46, and 2.3-47.

The applicant’s AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of its Corrective Action Program,

licensee event reports, and Maintenance Rule Data Base, as well as interviews with systems

engineers. An evaluation of industry operating experience published since the effective date of

the GALL Report was performed to identify any additional aging effect requiring management. 

The results of these reviews concluded that no aging effects requiring management were

identified beyond those identified using the AMR methodology described in Section 3.4.2.1 of

the LRA. The applicant’s ongoing review of plant-specific and industry-wide operating

experience is conducted in accordance with the plant’s Operating Experience Program.

3.4.2 Staff Evaluation

In Section 3.4 of the LRA, the applicant described its AMR for the SPC systems at VCSNS. 

The staff reviewed Section 3.4 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging will be adequately managed so that the

intended functions will be maintained consistent with the CLB throughout the period of extended

operation, in accordance with the requirements of 10 CFR 54.21(a)(3), for the SPC systems

components that are determined to be within the scope of license renewal and subject to an

AMR.

The systems that make up the SPC systems group are (1) auxiliary boiler steam and feedwater,

(2) condensate, (3) emergency feedwater, (4) extraction steam, (5) feedwater, (6) gland sealing

steam, (7) main steam, (8) main steam dump, (9) main turbine and turbine accessories,

(10) turbine cycle sampling, (11) steam generator blowdown, and (12) electro-hydraulic control.
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The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of SPC systems components for license renewal as

documented in the GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

applicable and to verify that the applicant had identified the appropriate programs as described

and evaluated in the GALL Report. The staff evaluated those aging management issues

recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report.

Table 3.4-1 below provides a summary of 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 VCSNS Steam and Power Conversion Systems Components Evaluated in

the GALL Report

Component Group Aging

Effect/Mechanism

 AMP in GALL Report AMP in LRA Staff

Evaluation

(1) Piping and fittings in

main feedwater line,

steam line, and AFW

piping (PWR only)

Cumulative fatigue

damage

TLAA, evaluated in

accordance with

10 CFR 54.21(c)

TLAA in LRA

Section 4.3 

GALL

recommends

further

evaluation 

(See staff

evaluation in

Section

3.4.2.2.1).

(2) Piping and fittings,

valve bodies and

bonnets, pump

casings, tanks, tubes,

tubesheets, channel

head and shell (except

main steam system)

Loss of material due to

general (carbon steel

only), pitting, and crevice

corrosion

Water Chemistry and

One-Time Inspection

Chemistry Program

(includes one-time

inspection)

GALL

recommends

further

evaluation (See

staff evaluation

in Section

3.4.2.2.2). 

(3) AFW piping Loss of material due to

general, pitting, and

crevice corrosion, MIC,

and biofouling

Plant-specific Service Water

System Reliability

and In-Service

Testing Program

GALL

recommends

further

evaluation 

(See staff

evaluation in

Section

3.4.2.2.3).

(4) Oil coolers in AFW

system (lubricating oil

side possibly

contaminated with

water)

Loss of material due to

general (carbon steel

only), pitting, and crevice

corrosion and MIC

Plant-specific Chemistry Program GALL

recommends

further

evaluation. 

(See staff

evaluation in

Section

3.4.2.2.5).
Table 3.4-1: Staff Evaluation for VCSNS Steam and Power Conversion Systems Components Evaluated in

the GALL Report

Component Group Aging

Effect/Mechanism

 AMP in GALL Report AMP in LRA Staff

Evaluation

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(5) External surface of

carbon steel

components

Loss of material due to

general corrosion

Plant-specific Inspection of

Mechanical

Components

Program and

Maintenance Rule

Structures Program

GALL

recommends

further

evaluation 

(See staff

evaluation in

Section

3.4.2.2.4).

(6) Carbon steel piping

and valve bodies

Wall thinning due to FAC Flow-accelerated

corrosion

Flow-Accelerated

Corrosion

Monitoring Program

Consistent with

GALL (See

staff evaluation

in Section

3.4.2.1).

(7) Carbon steel piping

and valve bodies in

main steam system

Loss of material due to

pitting and crevice

corrosion

Water chemistry Chemistry Program Consistent with

GALL (See

staff evaluation

in Section

3.4.2.1).

(8) Closure bolting in

high-pressure or hightemperature systems

Loss of material due to

general corrosion; crack

initiation and growth due

to cyclic loading and/or

SCC 

Bolting Integrity Inspection of

Mechanical

Components

Program

The Inspection

of Mechanical

Components

Program

manages aging

effects for SPC

Systems

bolting (See

staff evaluation

in Section

3.0.3.7).

(9) Heat exchangers

and

coolers/condensers

serviced by open-cycle

cooling water

Loss of material due to

general (carbon steel

only), pitting, and crevice

corrosion, MIC, and

biofouling; buildup of

deposit due to biofouling

Open-Cycle Cooling

Water System

Not applicable Open-cycle

cooling water

system as

described by

NUREG-1801

is not used in

any SPC

systems at

VCSNS.

(10) Heat exchangers

and

coolers/condensers

serviced by closedcycle cooling water

Loss of material due to

general (carbon steel

only), pitting, and crevice

corrosion

Closed-Cycle Cooling

Water System

Not applicable Closed-cycle

cooling water

system as

described by

NUREG-1801

is not used in

any SPC

systems at

VCSNS.
Table 3.4-1: Staff Evaluation for VCSNS Steam and Power Conversion Systems Components Evaluated in

the GALL Report

Component Group Aging

Effect/Mechanism

 AMP in GALL Report AMP in LRA Staff

Evaluation

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(11) External surface of

above ground

condensate storage

tank 

Loss of material due to

general (carbon steel

only), pitting, and crevice

corrosion

Above-Ground Carbon

Steel Tanks

Inspections for

Mechanical

Components

See staff

evaluation in

Section

3.4.2.4.2.

(12) External surface of

buried condensate

storage tank and AFW

piping

Loss of material due to

general, pitting, and

crevice corrosion and

MIC

Buried Piping and Tanks

Surveillance 

or

Buried Piping and Tanks

Inspection

Buried Piping and

Tanks Inspection

Program

GALL

recommends

further

evaluation 

(See staff

evaluation in

Section

3.4.2.2.5).

(13) External surface of

carbon steel

components

Loss of material due to

boric acid corrosion

Boric Acid Corrosion Boric Acid

Corrosion

Surveillances

Program

Consistent with

GALL (See

staff evaluation

in Section

3.4.2.1).

3.4.2.1 Aging Management Evaluations in the GALL Report That Are Relied On For License

Renewal That Do Not Require Further Evaluation

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with GALL, and for which the GALL Report does not recommend further evaluation,

the staff sampled components in these groups to determine whether the plant-specific

components contained in these GALL Report component groups were bounded by the GALL

evaluation. The staff also sampled component groups to determine whether the applicant had

properly identified those component groups in the GALL Report that were not applicable to its

plant. The staff also identified three areas where additional information or clarification was

needed. The staff’s evaluation of the applicant’s responses to those RAIs is included in

Sections 3.4.2.4.2 (RAI 3.4-13), 3.4.2.4.3 (RAI 3.4-12), and 3.4.2.4.13 (RAI 3.4-10) of this SER.

Table 3.4-1 of this SER contains a summary of the AMPs for SPC systems evaluated in

Chapter VIII of the GALL Report. The GALL Report identifies specific component, material,

environment, and aging effect/mechanism combinations that are managed by the GALL Report

AMPs; therefore, VCSNS AMPs that are consistent with the GALL Report are only applicable to

these specific material, environment, and aging effect/mechanism combinations. In addition to

those component, material, environment, and aging effect/mechanism identified in the GALL

Report, the applicant identified the following materials and aging mechanisms as being

managed by the VCSNS AMPs that are consistent with the GALL Report AMPs:

• In Table 3.4-1, Item 6 of the SER, the applicant identified low-alloy steel components

as being managed for wall thinning by the Flow-Accelerated Corrosion Program.
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• In Table 3.4-1, Item 7 of the SER, the applicant identified the aging mechanisms of

general corrosion and galvanic corrosion as being managed for loss of material by the

Chemistry Program.

• In Table 3.4-1, Item 13 of the SER, the applicant identified cast iron as being managed

for loss of material by the Boric Acid Corrosion Surveillances Program.

The staff finds the materials and aging mechanisms identified above as being adequately

managed by GALL Report AMPs; therefore the staff finds that the applicant’s aging

management of these materials and aging mechanisms is acceptable.

On the basis of its review, the staff has verified the applicant’s claim of consistency with the

GALL report. The staff finds 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).

3.4.2.2 Aging Management Evaluations in the GALL Report That Are Relied On For License

Renewal For Which GALL Recommends Further Evaluation 

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with GALL, and for which the GALL Report recommends further evaluation, the

staff reviewed the applicant’s evaluation to determine whether it adequately addressed the

issues for which the GALL Report recommended further evaluation. In addition, the staff

sampled components in these groups during the review to determine whether the plant-specific

components contained in these GALL Report component groups were bounded by the GALL

evaluation. 

The GALL Report indicates that further evaluation should be performed for the aging effects

discussed in the following sections:

3.4.2.2.1 Cumulative Fatigue Damage

Fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in

accordance with 10 CFR 54.21(c)(1). The staff reviewed the evaluation of this TLAA in Section

4.3 of this SER, following the guidance in Section 4.3 of the SRP-LR. The staff issued RAI

3.4-2 and RAI 3.4-3, to clarify aging management of SPC systems components for fatigue.

In Tables 2.3-38 through 2.3-47 of the LRA, the applicant does not identify any SPC systems

components that are managed for cumulative fatigue. The GALL Report recommends aging

management of cumulative fatigue for piping and fittings in the main steam, feedwater, and

emergency feedwater systems. The staff issued RAI 3.4-2, requesting the applicant to explain

why Tables 2.3-38 thru 2.3-47 do not identify any SPC systems components that are managed

for cumulative fatigue.

In its response by letter dated June 12, 2003, the applicant stated that cumulative fatigue is

considered to be a TLAA. It is discussed in Section 4 of the LRA entitled, Time-Limiting Aging

Analysis.” The staff finds the applicant’s response to RAI 3.4-2, reasonable and acceptable

because it explains that fatigue for SPC systems is discussed in Section 4 of the LRA.
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In Table 3.4-1, Item 1 of the LRA, the applicant identified aging management for cumulative

fatigue damage for piping and fitting in the main feedwater line, the steam line, and for AFW

piping. In the discussion” column for this item, the LRA states, see Section 4.3.2 [of the LRA]

for the TLAA discussion of Class 2 and 3 piping.” The discussion” column does not state if the

applicant's TLAA is consistent with the GALL Report TLAA program. For the SPC systems

piping, the GALL Report recommends an evaluation of allowable stress levels based on the

number of anticipated thermal cycles, as described in SRP-LR, Section 4.3.1.1.2. The staff

issued RAI 3.4-3, requesting the applicant to explain if thermal cycle evaluation is performed as

described in SRP-LR, Section 4.3.1.1.2, for the main feedwater line, the steam line, and for

AFW piping, and if the applicant's TLAA program is consistent with the GALL Report. If the

programs were not consistent, the applicant was requested to explain any differences.

In its response by letter dated June 12, 2003, the applicant stated that for the non-Class 1

components, VCSNS utilized the method described in Section 4.3.1.1.2 of SRP-LR to evaluate

fatigue in the SPC systems as a TLAA. The methodology used at VCSNS includes any system

or portion of system with operating temperatures greater than 220 F. The flow diagrams of

non-Class 1 systems in scope for license renewal were reviewed for operating temperatures. 

The screened-in portions of these systems meeting the temperature threshold were further

reviewed to determine the frequency with which the thermal cycles occurred. The in-scope

SPC systems that meet the temperature threshold include the auxiliary boiler steam and

feedwater system, the steam generator blowdown system, the extraction steam system, the

feedwater system, the main steam dump system, the main steam system, and the turbine cycle

sampling system. For all of these SPC systems, the number of thermal cycles is related to the

heat-up and cool-down of the plant (steam and primary), which ideally occurs once a cycle (18

months). The applicant indicated that if the cycling is conservatively assumed to occur once a

month for 60 years, then the total thermal cycles would only be 720, which is approximately

one-tenth of the allowed 7000 cycles.

The staff finds the applicant’s response to RAI 3.4-2, reasonable and acceptable because it

explains that fatigue for SPC systems is evaluated by VCSNS in accordance with Section

4.3.1.1.2 of SRP-LR.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The SRP-LR recommends further evaluation of programs to manage loss of material due to

general, pitting, and crevice corrosion of 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 crevice

and pitting corrosion for stainless steel tanks and heat exchanger/cooler tubes. The GALL

Report Water Chemistry Program relies on monitoring and control of water chemistry based on

the guidelines in EPRI TR-102134, “PWR Secondary Water Chemistry Guideline—Revision 3,”

May 1993, for secondary water chemistry in PWRs, to manage the effect of loss of material due

to general (carbon steel only), pitting, or crevice corrosion. However, corrosion may occur at

locations of stagnant flow conditions. Therefore, the GALL Report recommends that the

effectiveness of the applicant’s Chemistry Program be verified to ensure that corrosion is not

occurring.

In Table 3.4-1, Item 2 of the LRA, the applicant stated that various components will be

managed for the aging effect of loss of material due to general (carbon steel only), pitting, and
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crevice corrosion using the applicant’s Chemistry Program. However, the applicant did not

believe that a one-time inspection was warranted to verify that corrosion was not occurring for

components in this group, except for the condensate storage tank. The LRA further states that

a review of operating experience confirms the effectiveness of the Chemistry Program for

treated water to manage aging effects when continued into the period of extended operation. 

The GALL Report recommends that a one-time inspection be performed to address concerns

for the potential long incubation period for certain aging effects on SCs. There are cases where

either (1) an aging effect is not expected to occur, but there are insufficient data to completely

rule it out, or (2) an aging effect is expected to progress very slowly. For these cases, there

needs to be confirmation that either the aging effect is indeed not occurring, or the aging effect

is occurring so slowly as not to affect the component or structure intended function. 

A one-time inspection of select components and susceptible locations is an acceptable method

to ensure that corrosion is not occurring and that the components intended function will be

maintained during the period of extended operation. The one-time inspection should be

performed late in the current operating period to ensure that the aging effects will not affect the

component intended function during the period of extended operation. The staff issued RAI

3.4-4, requesting the applicant to explain how operating experience will confirm that these aging

effects will not occur during the period of extended operation or to commit to performing a

one-time inspection of components based on the severity of conditions, time of service, and

lowest design margin as recommended by the GALL Report AMP, XI.M32, One-Time

Inspection.” This RAI also applies to the valves in Table 3.4-2, Item 5. The GALL Report does

not recommend a one-time inspection for main steam system piping. Therefore, a one-time

inspection is not necessary to verify the effectiveness of the Water Chemistry Program for the

main steam system components listed in LRA Table 2.3-44.

In its response by letters dated June 12, 2003 and September 2, 2003, the applicant stated that

one-time inspections will be performed in low flow areas prior to the period of extended

operation to verify the effectiveness of the Chemistry Program to manage aging in various

chemistry regimes of systems within the scope for license renewal. These one-time inspections

will be part of the Chemistry Program as described by license renewal. For the applicable SPC

systems, the chemistry regimes are found in the feedwater (FW) system, the condensate (CO)

system, and the emergency feedwater (EF) system. The FW, CO, and EF systems have the

same chemistry regime; therefore, results from an inspection on one system should be

representative of the other systems. Engineering personnel will perform visual examinations in

low flow areas. Engineering personnel familiar with the system and the system operating

history will determine these inspection sites. Any abnormality found by these inspections will be

determined by engineering evaluation and addressed in the Corrective Action Program. Quality

Control personnel would perform further inspections required by the Corrective Action Program. 

Qualifications of the Quality Control inspectors are in accordance with ASME Section XI as

described in paragraph IWA-2300.

The staff finds the applicant’s response to RAI 3.4-4, reasonable and acceptable because it

provides an explanation that one-time inspections will be adequately performed to verify the

effectiveness of the Chemistry Program.

In Table 3.4-1, Item 2 of the LRA, the applicant identified the following differences between the

GALL Report Water Chemistry Program and the VCSNS Chemistry Program and has proposed

the Chemistry Program as the AMP for managing these additional aging effects, materials, and

components: 
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• The VCSNS Above Ground Tank Inspections program will perform inspections of the

condensate storage tank interior to verify the effectiveness of the Chemistry Program

and to manage the corrosive effects of alternate wetting and drying.

• In addition to the aging mechanisms identified in the GALL Report, VCSNS credits the

Chemistry Program for managing galvanic corrosion, SCC.

• In addition to the materials identified in the GALL Report, VCSNS credits the Chemistry

Program for managing aging effects for low-alloy steel and nickel based metal. 

• In addition to the components identified in the GALL Report, VCSNS includes similar

components from the nuclear sampling system in a treated water environment.

The staff finds the components, materials, and aging mechanisms identified above as being

adequately managed by the VCSNS Chemistry Program; therefore the staff finds that the

applicant’s aging management of these components, materials, and aging mechanisms is

acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of the loss of material due to general, pitting, and crevice corrosion for

components in the SPC systems, as recommended in the GALL Report. Since the applicant’s

AMR results are otherwise consistent with the GALL report, the staff finds 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).

3.4.2.2.3 Loss of Material Due to General, Pitting, and Crevice Corrosion, Microbiologically

Influenced Corrosion, and Biofouling

The SRP-LR recommends further evaluation of programs to manage loss of material due to

general corrosion, pitting, and crevice corrosion, MIC, and biofouling for carbon steel piping and

fittings for untreated water from the backup water supply in the emergency feedwater system. 

The staff reviewed the applicant’s proposed program to ensure that an adequate program will

be in place for the management of this aging effect.

Loss of material due to general corrosion, 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 emergency feedwater system. In Table 3.4-1, Item 3 of the LRA, the applicant does not

identify aging management of raw water exposure to AFW piping. In the discussion” column,

the LRA states that:

AFW piping at VCSNS is not exposed to untreated water. The service water system provides emergency

backup to the emergency feedwater system through automatic isolation valves that normally provide

boundary isolation between the treated water of the emergency feedwater system and the untreated water

of the service water system. 

The staff issued RAI 3.4-6, requesting verification that the AFW piping has not been exposed to

raw water. If any portion of the emergency feedwater system requires aging management due
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to exposure to raw water, the applicant was requested to list the components and describe how

aging will be managed.

In its response by letter dated June 12, 2003, the applicant stated that although there are

automatic isolation valves that isolate the service water system from the emergency feedwater

system, there is a section of emergency feedwater system piping (carbon steel) downstream of

these automatic isolation valves that is filled from the service water system. Therefore, a

portion of the emergency feedwater system is indeed exposed to a raw water environment. 

This piping is inspected under the activities described by the Service Water System Reliability

and In-Service Testing Program and will continue to effectively manage the aging effects for

this section of piping for the period of extended operation.

The staff finds the applicant’s response to RAI 3.4-6, reasonable and acceptable because it

provides an explanation that a section of the emergency feedwater system piping exposed to a

raw water environment is managed for aging effects by the Service Water System Reliability

and In-Service Testing Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated the AMR

results involving management of the loss of material due to general corrosion, pitting and

crevice corrosion, MIC, and biofouling for emergency feedwater system components exposed

to a raw water environment, as recommended in the GALL Report. Since the applicant’s AMR

results are otherwise consistent with the GALL report, the staff finds 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).

3.4.2.2.4 Loss of Material Due to General Corrosion

The GALL Report recommends further evaluation of programs to manage loss of material due

to general corrosion for external surfaces of all carbon SCs, including closure bolting, exposed

to operating temperatures less than 212 F. Such corrosion may be due to air, moisture, or

humidity. The applicant credits the Inspections of Mechanical Components Program to manage

corrosion in ambient, moist air for loss of material due to general corrosion and galvanic

corrosion. The applicant credits the Maintenance Rule Structures Program to manage loss of

material due to MIC on external surfaces in contact with ground water. The staff reviewed the

applicant’s Inspections of Mechanical Components Program in Section 3.0.3.7 of this SER and

the Maintenance Rule Structures Program in Section 3.0.3.4 of this SER to ensure that these

programs adequately manage this aging effect.

In addition to carbon steel components identified in Table 3.4-1 of the LRA, the applicant

included low-alloy steel and cast iron components to be managed for loss of material on

external surfaces by the Inspections of Mechanical Components Program and the Maintenance

Rule Structures Program. The staff considers it acceptable for the applicant to credit these

programs to manage low-alloy steel and cast iron components for loss of material on external

surfaces.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of the loss of material due to general corrosion for components in the

SPC systems, as recommended in the GALL Report. Since the applicant’s AMR results are
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otherwise consistent with the GALL report, the staff finds 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).

3.4.2.2.5 Loss of Material Due to General, Pitting, and Crevice Corrosion and Microbiologically

Influenced Corrosion

The GALL Report recommends further evaluation of programs to manage the loss of material

due to general corrosion (carbon steel only), pitting and crevice corrosion, and MIC for stainless

steel and carbon steel shells, tubes, and tubesheets within the bearing oil coolers (for steam

turbine pumps) in the emergency feedwater system. Such corrosion may be due to water

contamination that affects the quality of the lubricating oil in the bearing oil coolers. The staff

reviewed the applicant’s proposed program to ensure that an adequate program will be in place

for the management of the aging effect. 

In Table 3.4-1, Item 4 of the LRA, the applicant stated that aging management review for the

AFW system pump lubricating oil coolers determined that water and contaminates will not

intrude into the oil environments for these components. The staff's position is that an

environment of lubricating oil contaminated with water may cause loss of material of carbon or

stainless steel heat exchanger components due to general corrosion (carbon steel only), pitting,

and crevice corrosion, and MIC. Therefore, the AFW system pump lubricating oil coolers have

the potential of being contaminated with water. The staff issued RAI 3.4-7, requesting the

applicant to explain why water and contaminates will not intrude into the oil environments for

these heat exchangers and why oil samples are not credited to ensure water does not

contaminate the lube oil. This RAI also applies to the heat exchangers in Table 3.4-2, Item 3.

In its response by letters dated June 12, 2003 and September 2, 2003, the applicant stated that

the turbine driven emergency feedwater pump oil cooler is cooled by emergency feedwater

from the discharge of the pump, such that the oil is cooled only when the pump is running. The

oil temperature is therefore at ambient temperature when the pump is in its normal standby

condition. Because the oil is always at or above (when the pump is running) ambient

temperature, moisture does not condense out of the oil to pool in the reservoir. A review of the

operating history for this reservoir reveals no degradation. This line of reasoning is proven by

the history of the charging/safety injection pump oil reservoirs. When cooling was supplied

continuously to the reservoir coolers, water was regularly found in the oil. When this was

changed so that cooling was supplied only when the pump was running and stopped when the

pump was in standby, water was no longer found in the reservoir. To verify water is not

accumulating in the coolers, the applicant stated that the Chemistry Program at VCSNS

samples the lubricating oil of the turbine driven emergency feedwater pump on a regularly

scheduled basis. The maximum limit for water is 0.1%. The results of these samples are

typically less than .01%. The maximum concentration found was 0.02%. These concentrations

are considered to be trace amounts; therefore, water will not pool on any surfaces. Any

unexpected loss of material would be identified by the oil analysis program.

The staff finds the applicant’s response to RAI 3.4-7 reasonable and acceptable because it

provides an explanation that loss of material due to water contamination is adequately

managed for the lube oil side of the turbine driven emergency feedwater pump oil cooler.
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On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of the loss of material due to general, pitting, and crevice corrosion, and

MIC for AFW system oil coolers in the SPC systems, as recommended in the GALL Report. 

Since the applicant’s AMR results are other wise consistent with the GALL report, the staff finds

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).

The GALL Report recommends further evaluation of programs to manage loss of material due

to general corrosion, pitting and crevice corrosion, and MIC of underground piping and fittings

in the emergency feedwater system and underground condensate storage tank in the

condensate system. In LRA Table 3.4-1, Item 12, the applicant stated that the condensate

storage tank is above ground; however, there is underground piping in the emergency

feedwater system. VCSNS credits the Buried Piping and Tanks Inspection Program for

managing the aging for the underground AFW piping. The Buried Piping and Tanks inspection

Program relies on industry practice, frequency of pipe excavation, and operating experience to

manage the effects of loss of material from general corrosion, pitting and crevice corrosion, and

MIC. See Section 3.0.3.6 of this SER for the staff evaluation of the Buried Piping and Tanks

Inspection Program.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of the loss of material due to general, pitting, and crevice corrosion and

MIC for buried AFW components in the SPC systems, as recommended in the GALL Report. 

Since the applicant’s AMR results are otherwise consistent with the GALL report, the staff finds

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).

3.4.2.3 Aging Management Programs for Steam and Power Conversion Systems Components

In SER Section 3.4.2.1, the staff evaluated the applicant’s conformance with the aging

management recommended by the GALL Report for the SPC systems. In SER Section 3.4.2.2,

the staff reviewed the applicant’s evaluation of the issues for which the GALL Report

recommends further evaluation. In this SER section, the staff presents its evaluation of the

programs used by the applicant to manage the aging of the components in the SPC systems.

The applicant credits 10 AMPs to manage the aging effects associated with components in the

SPC systems. Two of the AMPs are credited with managing aging for components in the SPC

systems groups (plant-specific AMPs). Eight of the AMPs are credited with managing aging for

components in other system groups (common AMPs). The staff’s evaluation of the plantspecific AMPs credited with managing aging in SPC systems components is provided in

Sections 3.4.2.3.1 and 3.4.2.3.2 of this SER. The staff’s evaluation of the common AMPs

credited with managing aging in SPC systems components is provided in Section 3.0.3 of this

SER. The plant-specific and common AMPs are listed below:

• Flow-Accelerated Corrosion Monitoring Program (plant-specific) (3.4.2.3.1)

• Preventive Maintenance Activities — Terry Turbine Program (plant-specific) (3.4.2.3.2)

• Boric Acid Corrosion Surveillances Program (3.0.3.1)

• Chemistry Program (3.0.3.2)
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• Maintenance Rule Structures Program (3.0.3.4)

• Above Ground Tank Inspections Program (3.0.3.5)

• Buried Pipe and Tanks Inspection Program (3.0.3.6)

• Inspections for Mechanical Components Program (3.0.3.7)

• Heat Exchanger Inspections Program (3.0.3.8)

• Service Water System Reliability and In-Service Testing Program (3.3.2.3.1)

On the basis of its review, the staff finds that the applicant has properly identified the applicable

aging effects and AMPs for the components in the SPC systems at VCSNS, and that the

components in the VCSNS SPC systems were correctly evaluated in the applicant’s AMR and

will be adequately managed during the period of extended operation.

3.4.2.3.1 Flow-Accelerated Corrosion Monitoring Program

The Flow-Accelerated Corrosion (FAC) Monitoring Program is described in Section B.1.6 of

Appendix B to the LRA. The LRA credits the Flow-Accelerated Corrosion Monitoring Program

with detecting and managing loss of material in components susceptible to FAC in the steam

and power conversion system extractive steam, feedwater, gland seal steam, main steam, main

steam dump, and steam generator blowdown systems at the VCSNS. The staff reviewed the

LRA to determine whether the applicant had demonstrated that the Flow-Accelerated Corrosion

Monitoring Program will adequately manage the applicable aging effects for the components

that credit this program during the period of extended operation, as required by 10 CFR

54.21(a)(3).

Summary of Technical Information in the Application

The applicant’s Flow-Accelerated Corrosion Monitoring Program is discussed in LRA Section

B.1.6, “Flow-Accelerated Corrosion Monitoring Program.” The applicant states that the

program is consistent with GALL AMP XI.M17, “Flow-Accelerated Corrosion,” with no

exceptions or enhancements specified in the LRA. The LRA credits the FAC Monitoring

Program with detecting and managing loss of material in components susceptible to flowaccelerated corrosion in the steam and power conversion system (SPCS) extractive steam,

feedwater, gland seal steam, main steam, main steam dump, and steam generator blowdown

systems. In the FSAR supplement 18.2.17 of the LRA, the applicant stated that this program is

intended to manage FAC by combining the following elements: NUREG guidelines, predictive

analysis, inspections, industry experience, station information gathering and communication,

engineering judgment, and long-term mitigative strategies to reduce wall thinning due to FAC.

The applicant also stated that, after industry experience indicated that feedwater heaters may

be subject to flow-accelerated corrosion, VCSNS conducted an inspection of feedwater heaters

that revealed some degradation of the pressure boundary. The repair of the subject feedwater

heater was accomplished in accordance with the requirements of the applicable code. Some

degradation of the feedwater piping was also found downstream of the feedwater regulating

valves and has subsequently replaced. The applicant reviewed the refueling summary reports

for each refueling outage since RF-8 in 1994 and concluded that the FAC Monitoring Program

at VCSNS is a mature, reliable FAC monitoring program. 

By letter dated September 12, 2002, SCE&G supplemented the license renewal application for

VCSNS. The letter provided the results of the additional reviews based on the NRC staff
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positions on scoping of seismic II/I piping systems in letters dated December 3, 2001, and

March 15, 2002. As a result, VCSNS added several additional SSCs into the scope of license

renewal, and expanded the scope of several aging management programs including the FAC

Monitoring Program. The staff’s evaluation is provided below.

Staff Evaluation

In LRA Section B.1.6, the applicant describes FAC Program as an existing aging management

program that is consistent with GALL AMP XI.M17, “Flow-Accelerated Corrosion.” The

applicant’s claim of consistency with the GALL report was reviewed and verified during an AMR

audit conducted on July 16 - 17, 2003. Based on the consistency of this program with the

GALL report, the staff focused its review on the operating history program element supporting

the effectiveness of this program.

[Operating Experience] The applicant stated that the need for inspections is determined by a

calculation performed in accordance with engineering procedures. In addition, components

exhibiting extensive degradation during a cycle are replaced with more FAC-resistant materials. 

As described in GALL AMP XI.M17, the EPRI document, NSAC-202L-R2, “Recommendations

for an Effective Flow-Accelerated Corrosion Program,” recommends the use of a predictive

method for determining the rate at which component degradation is occurring due to FAC. The

NRC staff notes that CHECWORKSTM or a similar predictive code should be used to predict

component degradation in the systems susceptible to FAC. The systems susceptible to FAC

are indicated by specific plant data, including material, hydrodynamic, and operating conditions. 

By letter dated March 28, 2003, the staff requested, in RAI B.1.6-1, the applicant to discuss the

“calculation performed in accordance with engineering procedures” used to determine

inspection locations and frequency. Specifically, the staff requested information about the

methods used at VCSNS for predicting component degradation by FAC and how these

predictive methods are used to determine the need and frequency of inspections.

In its response dated June 12, 2003, the applicant stated that the Flow-Accelerated Corrosion

Monitoring Program is consistent with the basic guidelines and recommendations contained in

EPRI NSAC-202L-R2. The applicant further stated that inspection frequency varies for each

location depending on the trending of inspection results, analytical model review, changes in

operating or chemistry conditions, pertinent industry operating experience, plant operating

experience, and engineering judgment. The most probable locations of significant wall thinning

are given the highest priority with respect to scheduling inspections during each outage; this

provides sufficient lead time should any corrective action be deemed necessary.

The staff finds that the applicant appropriately applied a predictive code, such as

CHECWORKSTM, that uses the implementation guidance of NSAC-202L-R2 to satisfy the

criteria specified in 10 CFR Part 50, Appendix B, for development of procedures and control of

special processes. Based on the use of the predictive code and its results in the planned

inspections, the staff finds that the applicant’s response demonstrates effective use of

predictive and confirmatory methods; therefore, RAI B.1.6-1 is considered closed.

An effective FAC program, as described in GALL AMP XI.M17, consists of (1) an analysis to

determine critical locations, (2) limited baseline inspections to determine the extent of thinning

at these locations, and (3) follow-up inspections to confirm the predictions, or repairing or

replacing components as necessary. By letter dated March 28, 2003, the staff requested, in
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RAIs B.1.6-2 and B.1.6-3, the applicant to list those systems, within the program’s scope, most

susceptible to FAC. The staff also requested a sample list of components susceptible to FAC

with each component’s initial, current, and future predicted wall thicknesses, to demonstrate the

effectiveness of the Flow-Accelerated Corrosion Monitoring Program. In its response dated

June 12, 2003, the applicant stated that the Flow-Accelerated Corrosion Monitoring Program

will detect loss of material due to FAC prior to the loss of component intended function. The

applicant referenced the October 1992 NRC Inspection Report 50-395/92-20, which stated,

The licensee has established an effective program to maintain high energy carbon steel piping

systems within acceptable wall thickness limits.” The staff finds that while the referenced

inspection report affords some assurance of the effectiveness of the Flow-Accelerated

Corrosion Monitoring Program, the report did not supply the information sought by the staff. 

Therefore, the staff requested a list of those systems, within the program scope, and the

components most susceptible to FAC, in addition to the initial, current, and future predicted wall

thicknesses, to demonstrate the effectiveness of the Flow-Accelerated Corrosion Monitoring

Program.

In subsequent correspondence dated September 2, 2003, the applicant discussed the

integration of prediction and inspection inherent in its FAC program. The applicant stated the

system most susceptible to FAC at VCSNS is the extraction steam system. This conclusion has

been confirmed by the applicant’s predictive model and the as-found ultrasonic data for many

components. The predictive model of record (CHECWORKSTM) represents an analysis tool

used by the applicant in the selection of problem areas. This model also aids in the inspection

scheduling process. Over time, the applicant determined that model predictions with as-found

ultrasonic data have returned reasonable agreement. The applicant provided an example of

the predicted vs. measured wear comparisons for components in the extraction steam system

summarized below.

0 50 100 150 200 250 300

0

50

100

150

200

250

300

+50%

-50%

Measured Wear (mils)

Predicted Wear (mils)

Comparison of Wear Predictions

EX HP Turb to Htr 1 LCF = 0.376

Current Component Replaced Component

Figure 1: Wear Degradation of Components in the Extraction Steam System: 

Theory vs. Actual

Data shown above reflects as-found data populated since power up-rate in 1996.

The applicant stated that based on the predictive model, deviations on wear plots should be

within ± 50 percent. The above plot shows a fairly well-calibrated extraction steam analysis

line. The line correction factor (LCF) of 0.376 indicates that the model is slightly, yet

conservatively, over-predicting wear. As can be seen from the plot above, the applicant
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observed generally good agreement between predicted and measured wear. The applicant

also stated that “programmatic elements that are designed to complement the predictive model,

and guard against unexpected problems include: 1) a graded approach to wear classification, 2)

a sample expansion set point thickness, and 3) a mandatory calculated remaining service life,

wear rate, and projected thickness for each inspected component, separate from the predictive

model.”

The applicant provided an example of the most susceptible components. The heater vent

piping components were identified and coded as being “equipment out of norm” in the

Corrective Action Program during RF-13 in 2002, and slated for future follow-up. This

identification occurred through the procedure of grading current as-found measured wear as

insignificant, significant, excessive, and failure. The wear classification entry point for initiating

a Condition Evaluation Report is set at the excessive level.

The applicant created a set point” thickness to serve as a threshold or trigger” value to

perform expanded sample inspections. The threshold value represents thinning beyond the

significant classification into the excessive classification; however, it signals the halfway point

margin to protect the code allowable thickness value. 

The applicant stated that the inspection data for each component will be evaluated to determine

wear, wear rate, projected thickness at next refueling outage, service life and re-inspection

interval, wear classification, and sample expansion requirements. The applicant indicated that

the evaluation of the above items is necessary in determining planned re-inspection intervals,

planned replacements, and predictive model calibration input.

The applicant has presented a combination of reasonable agreement between the predicted

thickness and the as-found thickness as determined by ultrasonic data. In addition, the

procedure’s classification system for the as-found condition includes preventive measures to

replace a component prior to compromising the component’s design thickness. The staff finds

that the applicant has satisfactorily demonstrated the effectiveness of the Flow-Accelerated

Corrosion Monitoring Program in predicting the wall thicknesses of susceptible components by

verifying the FAC code predictions with the measured thicknesses, and by having procedures to

ensure appropriate management. Therefore, the staff finds the applicant’s response adequate

and RAI B.1.6-2 and B.1.6-3 are considered closed.

The staff reviewed the criteria 2 supplemental information in Section B.1.6, “Flow-Accelerated

Corrosion Monitoring Program,” in which the applicant stated that this program is applicable to

systems, or portions of system, that meet the susceptibility criteria and is not dependent on a

safety classification. The applicant concluded that this AMP is also applicable to components

which meet the 10 CFR 54.4(a)(2) criteria and are susceptible to flow-accelerated corrosion

(FAC). In addition, the applicant concluded that this AMP provides reasonable assurance that

FAC will be managed such that spatial interactions will not result in adverse impact to the

performance of safety-related functions consistent with the CLB during the period of extended

operation.

The staff concurs with the applicant’s conclusions because this AMP includes analysis to

determine critical locations for FAC occurrence independent of its safety classification,

inspections to determine the extent of thinning at these locations, and additional inspections to

confirm the predictions, or repairing or replacing components as necessary. 
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Section 18.2.17 of Appendix A to the LRA provided the applicant FSAR supplement for the

Flow-Accelerated Corrosion Monitoring Program at VCSNS. The staff reviewed the FSAR

supplement and finds the summary description of the Flow-Accelerated Corrosion Monitoring

Program consistent with Section B.1.6 of the LRA. The staff finds that the information

contained in the FSAR supplement presents an adequate summary of the program activities as

required by 10 CFR 54.21(d).

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.4.2.3.2 Preventive Maintenance Activities — Terry Turbine Program

Summary of Technical Information in the Application

The applicant’s Preventive Maintenance Activities — Terry Turbine Program is discussed in

LRA Section B.1.25, Preventive Maintenance Activities—Terry Turbine.” This AMP is not

consistent with a GALL AMP. The LRA credits this preventive maintenance program with

managing aging in the turbine casing and components at the VCSNS exposed to an air

environment, with periodic exposures to steam. The preventive maintenance detects and

assesses the condition of carbon steel components affected by aging, which may cause loss of

material due to general corrosion. In Section B.1.25 of the LRA, the applicant described its

preventive maintenance for the Terry Turbine as an existing AMP that manages loss of material

due to general corrosion of carbon steel exposed to ambient, moist air and periodic exposure to

steam.

The applicant stated that the Preventive Maintenance Activities — Terry Turbine AMP is a

condition monitoring program composed of controlled plant procedures. In the LRA, this AMP

is applied only to the main steam system in the steam and power conversion systems. The

components monitored (LRA Table 3.4-2, Item 4) include the emergency feedwater pump

turbine (casing only), valve (body only) and the emergency feedwater pump turbine governor

valve. The applicant stated that the purpose of the Preventive Maintenance Activities—Terry

Turbine AMP is to manage loss of material in carbon steel due to general corrosion of the

turbine casing and associated components. These components are normally exposed to

ambient conditions with periodic exposure to steam, allowing moisture to accumulate. Routine

maintenance and inspections are conducted, which include detection of age-related

degradation and initiation of corrective actions as necessary (LRA Appendix A, Section

18.2.41). 

In Section B.1.25 of the LRA, the applicant indicated that the Preventive Maintenance

Activities—Terry Turbine Program has been demonstrated to be capable of detecting and

managing loss of material in carbon steel components of the Terry Turbine. The Preventive
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Maintenance Activities—Terry Turbine Program provides reasonable assurance that the aging

effects will be managed such that the components subject to AMR will continue to perform their

intended functions consistent with the CLB for the period of extended operation.

Staff Evaluation

In LRA Section B.1.25, Preventive Maintenance Activities — Terry Turbine Program,” the

applicant described its AMP to manage aging in the turbine casing and components at the

VCSNS exposed to an air environment, with periodic exposures to steam. The staff reviewed

the program using the guidance in BTP RLSB-1 in Appendix A of the SRP-LR. The staff’s

evaluation focused on the management of aging effects through incorporation of the following

10 elements from BTP RLSB-1—program scope, preventive actions, parameters monitored or

inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective

actions, confirmation process, administrative controls, and operating experience. The applicant

indicated that the corrective actions, confirmation process, and administrative controls for

license renewal are in accordance with the site-controlled Quality Assurance Program. The

staff’s evaluation of the applicant’s Quality Assurance Program is provided separately in

Section 3.0.4 of this SER; the evaluation of the remaining seven elements is provided below. 

The staff also reviewed the FSAR supplement to determine whether it provides an adequate

description of the program.

[Program Scope] The applicant stated that this AMP is applicable to the turbine casing and 

components exposed to an air environment, with periodic exposure to steam. The staff finds

that the systems and components monitored by the Preventive Maintenance Activities—Terry

Turbine Program, as listed in Section B.1.25 of the LRA, are within the scope of license

renewal, as identified in Section 2.3 of the LRA. The scope is acceptable to the staff because it

includes those components that rely on the program for aging management. 

[Preventive Actions] The applicant stated that no actions are taken as part of the Preventive

Maintenance Activities—Terry Turbine Program to prevent the aging effect (loss of material) or

to mitigate aging degradation. The staff did not identify the need for preventive actions in this

AMP. 

[Parameters Monitored or Inspected] The Preventive Maintenance Activities—Terry Turbine

Program inspects the turbine casing and exposed components for visible evidence of corrosion

on internal surfaces that indicating potential loss of material. The staff finds the above

parameters acceptable because they are directly related to the degradation of carbon steel

components. In addition, visual inspections are effective in detecting such conditions.

[Detection of Aging Effects] The applicant stated that the managed aging effect (loss of

material) is identified by visual inspection prior to a loss of component intended function. The

applicant stated that the presence and extent of the aging effect on internal surfaces will be

detected. This aging effect is loss of material due to general corrosion. The staff finds that

these inspection techniques are sufficient to provide reasonable assurance that the aging effect

for the components addressed by the Preventive Maintenance Activities—Terry Turbine

Program will be detected before the loss of intended function. 

[Monitoring and Trending] The applicant stated that routine periodic visual inspections are

conducted in order to detect age-related degradation and to initiate corrective actions as
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necessary.” By letter dated March 28, 2003, the staff requested, in RAI B.1.25-1, the applicant

to specify the frequency of these periodic inspections or how the inspection frequency is

determined. In its response dated June 12, 2003, the applicant stated that the Preventive

Maintenance Activities—Terry Turbine Program is the license renewal name for the preventive

maintenance activity already being routinely performed on the component that can be credited

for managing aging during the period of extended operation. The applicant further stated that

the activity that inspects the Terry Turbine (turbine-driven emergency feedwater pump) is

performed every third refueling outage (4.5 years). The staff subsequently learned that the

VCSNS Engineering Services Technical Report TROO160-020 Program/Activity Evaluation for

License Renewal (Revision 0; October 2002) supplied further background on how routine the

periodic examinations actually were. The document states on page 2 of 3 in Attachment XXV

that the turbine inspection is performed using procedure SMP-300.015 on a 3 RF schedule (4.5

years). The inspection was last performed in October of 1997 (RF-10). The next inspection was

scheduled for May of 2002 (RF-13), but was delayed until October of 2003 (RF-14). The staff is

concerned that exceeding the identified inspection interval may not be acceptable in detecting

aging effects prior to loss of component function. During a telecommunication on July 14,

2003, the applicant identified that the inspection interval was based on vendor

recommendations. By letter dated September 2, 2003, the applicant confirmed that the

inspection interval is based on a vendor recommended interval of 5 years, but EPRI/NMAC

guide, TR-105874, recommends an interval of three or four refueling cycles, a typical time of 6

to 8 years. The staff finds that the applicant’s response satisfactorily addresses the staff’s

concerns and RAI B.1.25-1 is considered closed. 

[Acceptance Criteria] The applicant stated that the acceptance criterion is “no unacceptable

visible indication of loss of material.” The applicant further verifies that indications of loss of

material are evaluated by engineering to determine if the condition could result in a loss of the

component intended function(s). The staff finds that this acceptance criterion is adequate to

ensure that the component intended function(s) are maintained under all CLB design conditions

during the period of extended operation.

[Operating Experience] The applicant stated that a review of work histories for the past 10

years revealed that no age-related degradation had been detected for the subject components. 

The staff finds that the applicant’s operating experience indicates that this AMP has effectively

maintained the integrity of the components, and the effects of aging will be adequately

managed during the period of extended operation.

In summary, based on this review, the staff concludes that the Preventive Maintenance

Activities—Terry Turbine AMP is consistent with the requirements of the 10 elements of the

BTP RLSB-1 in Appendix A of the SRP-LR. The staff verified that the components, as

identified in Section 2 of the LRA, to which the Preventive Maintenance Activities—Terry

Turbine Program applies, are commensurate with the intent of the GALL Program.

Section 18.2.41 of Appendix A to the LRA contains the applicant’s FSAR supplement for the

Preventive Maintenance Activities—Terry Turbine Program at VCSNS. The staff reviewed the

FSAR supplement and found that the description of the Preventive Maintenance

Activities—Terry Turbine Program is consistent with Section B.1.25 of the LRA. The staff finds

that, pending clarifications as a result of issues identified in the AMR inspection, the information

contained in the FSAR supplement presents an adequate summary of the program activities, as

required by 10 CFR 54.21(d).
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Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.4.2.4 Aging Management Review of Plant-Specific Steam and Power Conversion Systems

Components

The following sections provide the results of the staff’s evaluation of the adequacy of aging

management for SPC systems components.

3.4.2.4.1 Auxiliary Boiler Steam and Feedwater System

Summary of Technical Information in the Application

The AMR results for the auxiliary boiler steam and feedwater system are presented in Tables

3.4-1 and 3.4-2 of the LRA. The applicant used the GALL Report format to present its AMR of

auxiliary boiler steam and feedwater system components in LRA Table 3.4-1. In LRA Table

3.4-2, the applicant identified the component group designation along with its (1) material,

(2) environment, (3) aging effects, and (4) AMPs.

As described in Section 2.3.4.1, the auxiliary boiler steam and feedwater system provides

steam to various plant equipment as required during all modes of plant operation. This system

is nonnuclear safety-related. The mechanical license renewal function of this system is to

isolate the section of AS piping supplying the auxiliary building in order to prevent a high energy

fluid piping rupture from affecting nuclear safety-related equipment in the auxiliary building.

Aging Effects:

LRA Tables 3.4-1and 3.4-2 identify the following applicable aging effects for the auxiliary boiler

steam and feedwater system:

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• loss of material due to pitting and crevice corrosion of carbon steel components in a

steam environment

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

• crevice corrosion, pitting corrosion, and stress-corrosion cracking of stainless steel

components in a treated water environment
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• loss of material due to general, pitting, and crevice corrosion and MIC of carbon steel

components in soil and ground water environments

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the auxiliary boiler steam and

feedwater system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Boric Acid Corrosion Surveillances Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the auxiliary boiler steam and feedwater

system will be adequately managed by these AMPs such that there is reasonable assurance

that the intended functions will be maintained consistent with the CLB during the period of

extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the auxiliary boiler

steam and feedwater system components have been properly identified and will be adequately

managed during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

auxiliary boiler steam and feedwater system components at VCSNS. The staff’s evaluation

includes a review of the aging effects considered and the basis for the applicant’s elimination of

certain aging effects. In addition, the staff has evaluated the appropriateness of the AMPs that

are credited for managing the identified aging effects for the auxiliary boiler steam and

feedwater system components.

Aging Effects:

The component groups identified in LRA Table 2.3.38 for the auxiliary boiler steam and

feedwater system are pipe and valves. The staff reviewed the aging effects identified in LRA

Tables 3.4-1 and 3.4-2 for these component groups and finds the applicant properly identified

the aging effects for these component groups. The aging effects are listed in SER Section

3.4.2.4.1.

The aging effects identified in the LRA for the auxiliary boiler steam and feedwater system are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:
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The following AMPs are utilized to manage aging effects to the auxiliary boiler steam and

feedwater system.

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Boric Acid Corrosion Surveillances Program

Each of the above AMPs is credited with managing the aging of several components in different

structures and systems and are, therefore, considered common AMPs. The staff review of the

common AMPs is in Section 3.0.3 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the auxiliary

boiler steam and feedwater system components will effectively manage or monitor the aging

effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.2 Condensate System

Summary of Technical Information in the Application

The AMR results for the condensate system are presented in Tables 3.4-1 and 3.4-2 of the

LRA. The applicant used the GALL Report format to present its AMR of condensate system

components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the component

group designation along with its (1) material, (2) environment, (3) aging effects, and (4) AMPs.

As described in Section 2.3.4.2, the condensate system is designed to pump exhaust steam

from the main condenser hotwell through the low pressure feedwater heaters to maintain

deaerator storage tank level for anticipated operating conditions. It also serves as a source of

cooling water for the steam packing condenser and steam generator blowdown heat exchanger,

and provides sealing water for various vacuum valves and feedwater pump seals.

Except for the CST, the condensate system is nonnuclear, safety-related. The CST is safetyrelated since it is the primary inventory source for the emergency feedwater system. Makeup

water to the CST is demineralized water, admitted through the condenser and condenser

storage subsystem.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the condensate

system:
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• loss of material due to general (carbon steel only), pitting, and crevice corrosion of

carbon and stainless steel components in treated water and steam environments

• loss of material due to general (carbon steel only), pitting, and crevice corrosion in sun,

weather, humidity, and moisture environments

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the condensate system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the condensate system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the condensate

system components have been properly identified and will be adequately managed during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

condensate system components at VCSNS. The staff’s evaluation includes a review of the

aging effects considered and the basis for the applicant’s elimination of certain aging effects. In

addition, the staff has evaluated the appropriateness of the AMPs that are credited for

managing the identified aging effects for the condensate system components.

Aging Effects:

The component group identified in LRA Table 2.3.26 for the condensate system is the

condensate storage tank.

In Table 3.4-1, Item 11 of the LRA, the applicant stated that the Inspections of Mechanical

Components Program is used to monitor the external surfaces of the aboveground CST for loss

of material. For tanks supported on earthen or concrete foundations, corrosion may occur at

inaccessible locations, such as the tank bottom. The staff issued RAI 3.4-13, requesting the

applicant to explain if the bottom of the CST is located on an earthen or concrete foundation,

and if so, to provide justification for not managing aging effects on the exterior, bottom portion

of the tank.

In its response by letters dated June 12, 2003, and September 2, 2003, the applicant stated

that the below grade foundation of the CST is comprised of a 4 foot thick slab of reinforced
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concrete, the top of which is 1 foot below grade. A reinforced concrete, circular ringwall that is

2 feet high and 21⁄2 feet thick connects to this slab and extends from the top of the slab to 1 foot

above grade. The CST attaches to the top of this ringwall by a base ring flange, which is

anchored to the ringwall by anchor bolts. All voids between the ringwall and base ring are

grouted. The outer edge of the base ring is coated with cold plastic coal tar pitch flashing

compound. Inside this ringwall, the CST sits on a clean, dry sand bed (as originally poured),

which extends from the top of the foundation slab to the top of the ringwall. There are four

small ringwall drains penetrating the ringwall 1 foot below grade. These drains are semicircular

in shape with a 3-inch radius and are filled with clean, crushed stone to retain the sand within

the ringwall. Because of the grouting and flashing at the base ring, water intrusion to the tank

bottom is not expected to occur at the base ring; however, if it did occur, any water intrusion

would seep through the sand to the ringwall drains, therefore, water would not pool at the

bottom external surface of the tank. The four ringwall drains also allow movement of water to

and from the sand contained by the ringwall. In the unlikely event that the ground outside of the

ringwall becomes moisture saturated for an extended period of time, the sand inside the

ringwall could only saturate to grade level. The 1 foot of sand from grade level to the bottom of

the tank would remain dry. Because the external surface of the bottom of the CST remains dry,

it should experience no aging effects requiring management; however, should the tank bottom

experience any moisture it is unlikely that the tank would experience any significant

degradation. Carbon steel exposed to the ambient, moist air environment is not expected to

experience significant corrosion rates. The ASM Handbook, Volume 13, Corrosion, page 531,

graphically depicts the atmospheric corrosion versus time rate for structural steel in an industrial

setting. Structural carbon steel loses approximately 1 mil per year for the first ten years,

followed by a rate of approximately 0.3 mils per year for the next 50 years. For a sixty-year

plant life, this yields a total material loss of approximately 25 mils (10 mils for the first ten years

plus 15 mils for the remaining fifty years). The slowing of the corrosion rate is due to the metal

producing a protective oxide layer, which protects the surface. Because the ambient

environment at VCSNS does not contain contaminants of sufficient quantity to concentrate on

external surfaces and because the tanks are grouted to their foundations, it is reasonable to

assume that tank bottoms will not experience wall thickness losses beyond 25 mils during the

60-year plant life.

As a verification of the applicant’s response that the CST bottom would remain dry and should

experience no aging effects requiring management, the staff performed an AMR inspection of

the CST. The results of the staff’s inspection can be found in Inspection Report 50-395/03-08,

dated September 29, 2003. A summary of the inspection results is presented below:

The team noted that there were no inspections planned for monitoring loss of material due to potential galvanic

or general corrosion of the bottom of the Condensate Storage Tank (CST) although this tank was located

outdoors. The tank is exposed to rain and water accumulation and appeared to be in contact with the ground.

The team verified the applicant’s response to RAI 3.4-13 which stated that the design of the CST foundation

prevented the establishment of a galvanic cell with the ground and induced drainage to prevent water

accumulation at the tank bottom. The CST as-built foundation drawings indicate that the tank is mounted on

a four foot thick concrete pad and with a two foot high concrete ringwall. The space between the pad and the

tank bottom contains clean sand and drainage pipes have been installed to prevent accumulation of water

under the tank. The tank bottom, at the 436 foot elevation, was eleven feet above the ground water elevation

of 425 feet. Loss of material of the tank bottom would be at the same rate as the tank sides, which are

exposed to a moist air ambient environment, and such a rate would not be a concern for the period of

extended operation. The tank exterior is within the scope of the Mechanical Components Inspection Program.
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Based on the AMR inspection results, the staff finds the applicant’s response to RAI 3.4-13,

reasonable and acceptable because it provides an explanation that the CST bottom is not in

direct contact with earthen or concrete structures, and by design, the bottom will remain dry and

is not susceptible to establishment of a galvanic cell.

The aging effects identified in the LRA for the condensate system components are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the condensate system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

Each of the above AMPs is credited with managing the aging of several components in different

structures and systems and are, therefore, considered common AMPs. The staff review of the

common AMPs is presented in Section 3.0.3 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the condensate

system components will effectively manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.3 Emergency Feedwater System

Summary of Technical Information in the Application

The AMR results for the emergency feedwater system are presented in Tables 3.4-1 and 3.4-2

of the LRA. The applicant used the GALL Report format to present its AMR of emergency

feedwater system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified

the component group designation along with its (1) material, (2) environment, (3) aging effects,

and (4) AMPs.

As described in Section 2.3.4.3, the emergency feedwater system is designed to deliver

sufficient feedwater to the steam generators for cool down subsequent to a loss of normal

feedwater supply (i.e., when the main feedwater system is not available) and during an

anticipated transient without scram (ATWS) event. The emergency feedwater system operates

in conjunction with the main steam dump system, if available, or the main power relief valves

and safety valves, to remove thermal energy from the steam generators. The emergency

feedwater system is also used to supply feedwater to the steam generators during testing,
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startup, shutdown, and layup operations. During normal plant operation, the system is in a

standby condition, with the system controls set for automatic operation.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the emergency

feedwater system:

• loss of material due to general (carbon steel only), pitting, and crevice corrosion of

carbon and stainless steel components in treated water and steam environments

• loss of material due to general (carbon steel only), pitting, and crevice corrosion, MIC,

and biofouling of carbon steel components in a raw water environment

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• loss of material due to general (carbon steel only), pitting, and crevice corrosion in sun,

weather, humidity, and moisture environments

• loss of material due to general, pitting, and crevice corrosion and MIC of carbon steel

components in soil and ground water environments

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

• boric acid corrosion and aggressive chemical attack of aluminum and brass

components in an ambient, moist air environment

• crevice corrosion, galvanic corrosion, pitting corrosion, selective leaching, and stresscorrosion cracking of brass components in a treated water environment

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the emergency feedwater system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Buried Pipe and Tanks Inspection Program

• Boric Acid Corrosion Surveillances Program

• Service Water System Reliability and In-Service Testing Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the emergency feedwater system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation
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In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the emergency

feedwater system components have been properly identified and will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

emergency feedwater system components at VCSNS. The staff’s evaluation includes a review

of the aging effects considered and the basis for the applicant’s elimination of certain aging

effects. In addition, the staff has evaluated the appropriateness of the AMPs that are credited

for managing the identified aging effects for the emergency feedwater system components.

Aging Effects:

The component groups identified in LRA Table 2.3.40 for the emergency feedwater system are

(1) filter, (2) heat exchanger shell, (3) heat exchanger tubes, (4) orifices, (5) pipe, (6) pump

(casing only), (7) strainers, (8) tank (reservoir), (9) thermowells and piping, (10) tube and tube

fittings, and (11) valves. The staff reviewed the aging effects identified in LRA Tables 3.4-1 and

3.4-2 for these component groups and finds the applicant properly identified the aging effects

for these component groups. The aging effects are listed in SER Section 3.4.2.4.2.

The aging effects identified in the LRA for the emergency feedwater system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the emergency feedwater system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Buried Pipe and Tanks Inspection Program

• Boric Acid Corrosion Surveillances Program

• Service Water System Reliability and In-Service Testing Program

Each of the above AMPs is credited with managing the aging of several components in different

structures and systems and are, therefore, considered common AMPs. The staff review of the

common AMPs is presented in Sections 3.0.3 and 3.3.2.3.1 of this SER.

The GALL Report recommends that heat exchanger internals exposed to raw or treated water

be managed for loss of material by the Open-Cycle and Closed-Cycle Cooling Water System

AMPs. In Table 3.4-1, Items 9 and 10 of the LRA, the LRA states that the Open-Cycle and

Closed-Cycle Cooling Water System AMPs, as described in NUREG-1801, are not used in any

steam and power conversion systems at VCSNS. The staff issued RAI 3.4-12, requesting the

applicant to explain if there any steam and power conversion systems heat exchangers at
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VCSNS exposed to raw or treated water that require AMR. If so, the applicant was requested

to identify the heat exchangers, the aging effects, and how the aging effects are managed.

In its response by letter dated June 12, 2003, the applicant stated that the turbine driven

emergency feedwater pump oil cooler is the only SPC systems heat exchanger in scope for

license renewal. The internal surfaces of the brass tubes are exposed to the treated water

environment of the emergency feedwater system, which is the cooling medium. The possible

aging mechanisms for this material-environment combination are crevice corrosion, galvanic

corrosion, pitting corrosion, selective leaching, and SCC. In Table 3.4-2, Item 6 of the LRA, the

applicant credited the Chemistry Program and the Heat Exchanger Inspections Program for

managing aging of the tubes in the treated water environment.

The staff finds the applicant’s response to RAI 3.4-12, reasonable and acceptable because it

provides an explanation that the turbine driven emergency feedwater pump oil cooler is

managed for aging in a treated water environment.

In Table 3.4-1, Item 12 of the LRA, the applicant stated that there is underground piping in the

emergency feedwater system. The Buried Pipe and Tanks Inspection Program will manage the

aging effects for this underground piping. Table 2.3-40 of the LRA, for the emergency

feedwater system, only identifies orifices as subject to aging management by the Buried Pipe

and Tanks Inspection Program. The staff issued RAI 3.4-14, requesting the applicant to

explain why the emergency feedwater system piping in Table 2.3-40 does not refer to the

Buried Pipe and Tanks Inspection Program and how the underground piping in the emergency

feedwater system is managed for aging.

In its response by letter dated June 12, 2003, the applicant stated that Table 2.3-40 of the LRA

should have included reference to Table 3.4-1, Item 12 in the AMR results for pipe. Table

3.4-1, Item 12, states that the Buried Pipe and Tanks Inspection Program is the credited

program to manage aging for underground piping in the emergency feedwater system. 

The staff finds the applicant’s response to RAI 3.4-14, reasonable and acceptable because it

provides an explanation that the underground emergency feedwater system piping is managed

against aging effects by the Buried Pipe and Tanks Inspection Program.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the emergency

feedwater system components will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.4 Extraction Steam System

Summary of Technical Information in the Application
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The AMR results for the extraction steam system are presented in Tables 3.4-1 and 3.4-2 of the

LRA. The applicant used the GALL Report format to present its AMR of extraction steam

system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the

component group designation along with its (1) material, (2) environment, (3) aging effects, and

(4) AMPs.

As described in Section 2.3.4.4, the extraction steam system supplies steam for heating the

condensate and feedwater and for maintaining the auxiliary boilers in a hot standby condition. 

The mechanical license renewal function of this system is to provide a means of main steam

isolation (when used in conjunction with components from various other systems) for a steam

line break coincident with failure of a main steam isolation valve.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the extraction

steam system:

• loss of material due to general (carbon steel only), pitting, and crevice corrosion of

carbon and stainless steel components in treated water and steam environments

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the extraction steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the extraction steam system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the extraction
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steam system components have been properly identified and will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

extraction steam system components at VCSNS. The staff’s evaluation includes a review of the

aging effects considered and the basis for the applicant’s elimination of certain aging effects. In

addition, the staff has evaluated the appropriateness of the AMPs that are credited for

managing the identified aging effects for the extraction steam system components.

Aging Effects:

The component groups identified in LRA Table 2.3.41 for the extraction steam system are

piping and valve bodies. The staff reviewed the aging effects identified in LRA Tables 3.4-1

and 3.4-2 for these component groups and finds the applicant properly identified the aging

effects for these component groups. The aging effects are listed in SER Section 3.4.2.4.4.

The aging effects identified in the LRA for the extraction steam system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the extraction steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

Each of the above AMPs (except the Flow-Accelerated Corrosion Monitoring AMP) is credited

with managing the aging of several components in different structures and systems and are,

therefore, considered common AMPs. The staff review of the common AMPs is presented in

Section 3.0.3 of this SER. The Flow-Accelerated Corrosion Monitoring Program is credited with

managing aging effects in the SPC systems only and is, therefore, considered a plant-specific

AMP. Staff review of the Flow-Accelerated Corrosion Monitoring Program is described in

Section 3.4.2.3.1 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the extraction

steam system components will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).
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3.4.2.4.5 Feedwater System

Summary of Technical Information in the Application

The AMR results for the feedwater system are presented in Tables 3.4-1 and 3.4-2 of the LRA. 

The applicant used the GALL Report format to present its AMR of feedwater system

components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the component

group designation along with its (1) material, (2) environment, (3) aging effects, and (4) AMPs.

As described in Section 2.3.4.5, the feedwater system is designed to pump feedwater from the

deaerator storage tank through two stages of high pressure heaters to the steam generators. 

The operation of this system ensures that the required amount of heated and deaerated water

is available to maintain an adequate steam generator water level during normal plant operation

and transients. The nuclear portion of the feedwater system conveys feedwater from the nonnuclear portion of the feedwater system (located within the turbine building) to the steam

generators and includes the containment isolation valves.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the feedwater

system:

• loss of material due to general (carbon steel only), pitting, and crevice corrosion of

carbon and stainless steel components in treated water and steam environments

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the feedwater system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the feedwater system will be adequately

managed by these AMPs such that there is reasonable assurance that the intended functions

will be maintained consistent with the CLB during the period of extended operation.
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Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the feedwater

system components have been properly identified and will be adequately managed during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

feedwater system components at VCSNS. The staff’s evaluation includes a review of the aging

effects considered and the basis for the applicant’s elimination of certain aging effects. In

addition, the staff has evaluated the appropriateness of the AMPs that are credited for

managing the identified aging effects for the feedwater system components.

Aging Effects:

The component groups identified in LRA Table 2.3.42 for the feedwater system are flow venturi, 

pipe, tube and tube fittings, and valves. The staff reviewed the aging effects identified in LRA

Tables 3.4-1 and 3.4-2 for these component groups and finds the applicant properly identified

the aging effects for these component groups. The aging effects are listed in SER Section

3.4.2.4.5.

The aging effects identified in the LRA for the feedwater system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the feedwater system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

Each of the above AMPs (except the Flow-Accelerated Corrosion Monitoring AMP) is credited

with managing the aging of several components in different structures and systems and are,

therefore, considered common AMPs. The staff review of the common AMPs is presented in

Section 3.0.3 of this SER. The Flow-Accelerated Corrosion Monitoring Program is credited with

managing aging effects in the SPC systems only and is, therefore, considered a plant-specific

AMP. Staff review of the Flow-Accelerated Corrosion Monitoring Program is described in

Section 3.4.2.3.1 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the feedwater

system components will effectively manage or monitor the aging effects identified in the LRA.
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Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.6 Gland Sealing Steam System

Summary of Technical Information in the Application

The AMR results for the gland sealing steam system are presented in Tables 3.4-1 and 3.4-2 of

the LRA. The applicant used the GALL Report format to present its AMR of gland sealing

steam system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the

component group designation along with its (1) material, (2) environment, (3) aging effects, and

(4) AMPs.

As described in Section 2.3.4.6, the gland sealing steam system is designed to provide steam

to the main turbine and feedwater pump turbine shaft seals in order to prevent air leakage into

and/or steam leakage out of the turbine casings. Sealing steam is normally supplied to the

gland sealing steam system from the main steam system under all load conditions, but may be

provided by the auxiliary boiler through the auxiliary steam system. The mechanical license

renewal function of this system is to provide a means of main steam isolation (when used in

conjunction with components from various other system) for a steam line break coincident with

failure of a main steam isolation valve.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the gland sealing

steam system:

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments

• loss of material due to pitting and crevice corrosion of carbon steel components in a

steam environment

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the gland sealing steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program
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A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the gland sealing steam system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the gland sealing

steam system components have been properly identified and will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

gland sealing steam system components at VCSNS. The staff’s evaluation includes a review of

the aging effects considered and the basis for the applicant’s elimination of certain aging

effects. In addition, the staff has evaluated the appropriateness of the AMPs that are credited

for managing the identified aging effects for the gland sealing steam system components.

Aging Effects:

The component groups identified in LRA Table 2.3.43 for the gland sealing steam system are

pipe and valves. The staff reviewed the aging effects identified in LRA Tables 3.4-1 and 3.4-2

for these component groups and finds the applicant properly identified the aging effects for

these component groups. The aging effects are listed in SER Section 3.4.2.4.6.

The aging effects identified in the LRA for the gland sealing steam system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the gland sealing steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

Each of the above AMPs (except the Flow Accelerated Corrosion AMP) are credited with

managing the aging of several components in different structures and systems and are,

therefore, considered common AMPs. The staff review of the common AMPs is presented in

Section 3.0.3 of this SER. The Flow Accelerated Corrosion AMP is credited with managing

aging effects in the SPC systems only and is, therefore considered a plant-specific AMP. Staff

review of the Flow Accelerated Corrosion AMP is in Section 3.4.2.3.1 of this SER.
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On the basis of its review, the staff finds that the AMPs credited in the LRA for the gland sealing

steam system components will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.7 Main Steam System

Summary of Technical Information in the Application

The AMR results for the main steam system are presented in Tables 3.4-1 and 3.4-2 of the

LRA. The applicant used the GALL Report format to present its AMR of main steam system

components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the component

group designation along with its (1) material, (2) environment, (3) aging effects, and (4) AMPs .

As described in Section 2.3.4.7, the main steam system conveys saturated steam from the

three steam generators to the turbine-generator. Main steam is also supplied, through branch

lines, to the (1) feedwater pump drive turbines, (2) emergency feedwater pump turbines,

(3) moisture separator reheaters, (4) auxiliary steam system, (5) deaerating feedwater heater,

and (6) steam dumps to the condenser and atmosphere.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the main steam

system:

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments

• loss of material due to pitting and crevice corrosion of carbon steel components in a

steam environment

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

• general corrosion of carbon steel components in an ambient, moist air environment

• crevice corrosion, pitting corrosion, and stress-corrosion cracking of stainless steel

components in a treated water environment

Aging Management Programs:
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The following AMPs are utilized to manage aging effects to the main steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

• Preventive Maintenance Activities — Terry Turbine Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the main steam system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the main steam

system components have been properly identified and will be adequately managed during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

main steam system components at VCSNS. The staff’s evaluation includes a review of the

aging effects considered and the basis for the applicant’s elimination of certain aging effects. In

addition, the staff has evaluated the appropriateness of the AMPs that are credited for

managing the identified aging effects for the main steam system components.

Aging Effects:

The component groups identified in Table 2.3.44 for the main steam system are pump turbine,

pipe, valves, and steam traps. The staff reviewed the aging effects identified in LRA Tables

3.4-1 and 3.4-2 for these component groups and finds the applicant properly identified the

aging effects for these component groups. The aging effects are listed in SER Section

3.4.2.4.7.

The aging effects identified in the LRA for the main steam system are consistent with industry

operating experience for the materials and environments listed. The staff finds that all the

plausible aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the main steam system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program
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• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

• Preventive Maintenance Activities—Terry Turbine Program

Each of the above AMPs (except the Flow-Accelerated Corrosion Monitoring and Preventive

Maintenance Activities — Terry Turbine AMPs) is credited with managing the aging of several

components in different structures and systems and are, therefore, considered common AMPs. 

The staff review of the common AMPs is presented in Section 3.0.3 of this SER. The FlowAccelerated Corrosion Monitoring and Preventive Maintenance Activities — Terry Turbine

AMPs are credited with managing aging effects in the SPC systems only and are, therefore,

considered plant-specific AMPs. The staff review of the Flow-Accelerated Corrosion Monitoring

Program is presented in Section 3.4.2.3.1 of this SER and the staff review of the Preventive

Maintenance Activities — Terry Turbine Program is discussed in Section 3.4.2.3.2 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the main steam

system components will effectively manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.8 Main Steam Dump System

Summary of Technical Information in the Application

The AMR results for the main steam dump system are presented in Tables 3.4-1 and 3.4-2 of

the LRA. The applicant used the GALL Report format to present its AMR of main steam dump

system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified the

component group designation along with its (1) material, (2) environment, (3) aging effects, and

(4) AMPs.

As described in Section 2.3.4.8, the main steam dump system is capable of following a large

turbine-generator load reduction without reactor trip through actuation of the main steam dump

system. This system bypasses main steam to the main condenser and/or to the atmosphere. 

Steam dump valves permit unit operation at turbine loads lower than the minimum power

setting (15 percent reactor power) of the nuclear steam supply system (NSSS) automatic

control. In addition, the steam dump valves permit reduction of turbine-generator load at a rate

greater than the 5 percent per minute maximum rate of load reduction for the NSSS.

The mechanical license renewal function of this system is to provide a means of main steam

isolation (when used in conjunction with components from various other systems) for a steam

line break coincident with failure of a main steam isolation valve.

Aging Effects:
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LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the main steam

dump system:

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments

• loss of material due to pitting and crevice corrosion of carbon steel components in a

steam environment

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the main steam dump system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the main steam dump system will be

adequately managed by these AMPs such that there is reasonable assurance that the intended

functions will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the Main steam

dump system components have been properly identified and will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

main steam dump system components at VCSNS. The staff’s evaluation includes a review of

the aging effects considered and the basis for the applicant’s elimination of certain aging

effects. In addition, the staff has evaluated the appropriateness of the AMPs that are credited

for managing the identified aging effects for the main steam dump system components.

Aging Effects:

The component groups identified in LRA Table 2.3.45 for the main steam dump system are

pipe, tube and tube fittings, and valves. The staff reviewed the aging effects identified in LRA
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Tables 3.4-1 and 3.4-2 for these component groups and finds the applicant properly identified

the aging effects for these component groups. The aging effects are listed in SER Section

3.4.2.4.8.

The aging effects identified in the LRA for the main steam dump system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the main steam dump system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

Each of the above AMPs (except the Flow-Accelerated Corrosion Monitoring AMP) is credited

with managing the aging of several components in different structures and systems and are,

therefore, considered common AMPs. The staff review of the common AMPs is presented in

Section 3.0.3 of this SER. The Flow-Accelerated Corrosion Monitoring Program is credited with

managing aging effects in the SPC systems only and is, therefore, considered a plant-specific

AMP. Staff review of the Flow-Accelerated Corrosion Monitoring Program is discussed in

Section 3.4.2.3.1 of this SER.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the main steam

dump system components will effectively manage or monitor the aging effects identified in the

LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.9 Main Turbine and Turbine Accessories Systems

As described in Section 2.3.4.9, the main turbine system receives steam from the steam

generators and converts steam energy into mechanical energy for the main generator. The

turbine accessories system supplies high pressure bearing lift oil to the turbine and generator

bearings to lift the shaft slightly and reduce the torque requirements on the turning gear. These

two systems provide a turbine trip signal that has a license renewal function of providing a

means of main steam isolation (when used in conjunction with components from various other

systems) for a steam line break coincident with failure of a main steam isolation valve. 
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The applicant’s screening review concluded that the main turbine and turbine accessories

systems do not perform any intended functions for license renewal; therefore, none of the main

turbine and turbine accessories systems components are subject to an AMR.

Staff review of the scoping and screening process in LRA Section 2.3.4.9 concluded that no

main turbine and turbine accessories systems components are subject to an AMR.

3.4.2.4.10 Turbine Cycle Sampling System

Summary of Technical Information in the Application

The AMR results for the turbine cycle sampling system are presented in Tables 3.4-1 and 3.4-2

of the LRA. The applicant used the GALL Report format to present its AMR of turbine cycle

sampling system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant identified

the component group designation along with its (1) material, (2) environment, (3) aging effects,

and (4) AMPs.

As described in Section 2.3.4.10, the turbine cycle sampling system provides sampling of

secondary system fluids from locations such as the main condenser hotwell, deaerator,

feedwater booster pumps, high pressure heater drains, emergency feedwater pumps, and main

steam system. The mechanical license renewal function of the system is to provide a means of

main steam isolation (when used in conjunction with components from various other systems)

for a steam line break coincident with failure of a main steam isolation valve.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the turbine cycle

sampling system:

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments

• loss of material due to pitting and crevice corrosion of carbon steel components in a

steam environment

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the turbine cycle sampling system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the turbine cycle sampling system will

be adequately managed by these AMPs such that there is reasonable assurance that the

intended functions will be maintained consistent with the CLB during the period of extended

operation.
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Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the turbine cycle

sampling system components have been properly identified and will be adequately managed

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

turbine cycle sampling system components at VCSNS. The staff’s evaluation includes a review

of the aging effects considered and the basis for the applicant’s elimination of certain aging

effects. In addition, the staff has evaluated the appropriateness of the AMPs that are credited

for managing the identified aging effects for the turbine cycle sampling system components.

Aging Effects:

The component groups identified in LRA Table 2.3.46 for the turbine cycle sampling system are 

pipe and valves. The staff reviewed the aging effects identified in LRA Tables 3.4-1 and 3.4-2

for these component groups and finds the applicant properly identified the aging effects for

these component groups. The aging effects are listed in SER Section 3.4.2.4.10.

The aging effects identified in the LRA for the turbine cycle sampling system are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for

the combination of materials and environments specified.

Aging Management Programs:

The following AMPs are utilized to manage aging effects to the turbine cycle sampling system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

Each of the above AMPs is credited with managing the aging of several components in different

structures and systems and are, therefore, considered common AMPs. The staff review of the

common AMPs is presented in Section 3.0.3 of this SER.

In Section 2.3.4.10 of the LRA, the applicant listed turbine cycle sampling system components

subject to AMR. However, Section 3.4.1, which lists VCSNS steam and power conversion

systems, does not include the turbine cycle sampling system. The staff issued RAI 3.4-1,

requesting the applicant to explain the basis for not including the turbine cycle sampling system

in the list of steam and power conversion systems.

In its response by letter dated June 12, 2003, the applicant stated that Section 3.4.1 of the LRA

should indeed list the turbine cycle sampling system as a steam and power conversion system. 

Table 2.3-46 of the LRA for the turbine cycle sampling system refers to Table 3.4-1, Items 5
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and 7 of the LRA, which discusses the AMR results for the turbine cycle sampling system

components in scope for license renewal.

The staff finds the applicant’s response to RAI 3.4-1, reasonable and acceptable because it

provides an explanation that aging management of the turbine cycle sampling system is

included in the steam and power conversion systems.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the turbine cycle

sampling system components will effectively manage or monitor the aging effects identified in

the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.11 Steam Generator Blowdown System

Summary of Technical Information in the Application

The AMR results for the steam generator blowdown system are presented in Tables 3.4-1 and

3.4-2 of the LRA. The applicant used the GALL Report format to present its AMR of steam

generator blowdown system components in LRA Table 3.4-1. In LRA Table 3.4-2, the applicant

identified the component group designation along with its (1) material, (2) environment,

(3) aging effects, and (4) AMPs.

As described in Section 2.3.4.11, the steam generator blowdown system continuously purges

the steam generators of concentrated impurities, thereby maintaining secondary side steam

generator water chemistry. This system is nonnuclear, safety-related except for the portion

inside the reactor building, up to and including the containment isolation valves.

Aging Effects:

LRA Tables 3.4-1 and 3.4-2 identify the following applicable aging effects for the steam

generator blowdown system:

• loss of material due to general (carbon steel only), pitting, and crevice corrosion of

carbon and stainless steel components in treated water and steam environments 

• loss of material due to general corrosion of carbon and low-alloy steel components

(external surfaces) in air, moisture, and humidity environments 

• wall thinning due to flow-accelerated corrosion of carbon steel components in steam

and treated water environments 

• loss of material due to boric acid corrosion of carbon steel components (external

surfaces) in air, leaking, and dripping chemically treated borated water environments 
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Aging Management Programs:

The following AMPs are utilized to manage aging effects to the steam generator blowdown

system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

A description of these AMPs is provided in Appendix B of the LRA. The applicant indicated that

the effects of aging associated with the components of the steam generator blowdown system

will be adequately managed by these AMPs such that there is reasonable assurance that the

intended functions will be maintained consistent with the CLB during the period of extended

operation.

Staff Evaluation

In addition to Section 3.4 of the LRA, the staff reviewed the pertinent information provided in

Section 2.3.4, Steam and Power Conversion Systems,” and the applicable AMP descriptions

provided in Appendix B of the LRA to determine whether the aging effects for the steam

generator blowdown system components have been properly identified and will be adequately

managed during the period of extended operation, as required by 10 CFR 54.21(a)(3).

This section of the SER provides the staff’s evaluation of the applicant’s AMR for the aging

effects and the appropriateness of the programs credited for the aging management of the

steam generator blowdown system components at VCSNS. The staff’s evaluation includes a

review of the aging effects considered and the basis for the applicant’s elimination of certain

aging effects. In addition, the staff has evaluated the appropriateness of the AMPs that are

credited for managing the identified aging effects for the steam generator blowdown system

components.

Aging Effects:

The component groups identified in LRA Table 2.3.47 for the steam generator blowdown

system are pipe and valves. The staff reviewed the aging effects identified in LRA Tables 3.4-1

and 3.4-2 for these component groups and finds the applicant properly identified the aging

effects for these component groups. The aging effects are listed in SER Section 3.4.2.4.11.

The aging effects identified in the LRA for the steam generator blowdown system are consistent

with industry operating experience for the materials and environments listed. The staff finds

that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:
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The following AMPs are utilized to manage aging effects to the steam generator blowdown

system:

• Chemistry Program

• Inspections for Mechanical Components Program

• Maintenance Rule Structures Program

• Flow-Accelerated Corrosion Monitoring Program

• Boric Acid Corrosion Surveillances Program

Each of the above AMPs (except the Flow-Accelerated Corrosion Monitoring AMP) is credited

with managing the aging of several components in different structures and systems and are,

therefore, considered common AMPs. The staff review of the common AMPs is presented in

Section 3.0.3 of this SER. The Flow-Accelerated Corrosion Monitoring Program is credited with

managing aging effects in the SPC systems only and is, therefore, considered a plant-specific

AMP. Staff review of the Flow-Accelerated Corrosion Monitoring Program is discussed in

Section 3.4.2.3.1 of this SER.

In Table 2.3-47 of the LRA, the applicant did not include the blowdown system heat exchangers

as requiring aging management. These heat exchangers are identified as within the scope of

license renewal on the applicant’s Drawing D-302-771. The staff issued RAI 3.4-5, requesting

the applicant to explain why these heat exchangers are not included in Table 2.3-47 of the LRA

and to describe the aging management for these heat exchangers.

In its response by letter dated June 12, 2003, the applicant stated that the heat exchangers

shown on Drawing D-302-771 are not the steam generator blowdown system heat exchangers. 

They are the steam generator blowdown sample coolers. These coolers are in the nuclear

sampling system and aging management for these coolers is discussed in Section 2.3.3.16 and

Table 2.3-30 of the LRA. 

The staff finds the applicant’s response to RAI 3.4-5, reasonable and acceptable because it

provides an explanation that aging management of the steam generator blowdown sample

coolers are included in the nuclear sampling system discussed in Section 2.3.3.16 and Table

2.3-30 of the LRA.

On the basis of its review, the staff finds that the AMPs credited in the LRA for the steam

generator blowdown system components will effectively manage or monitor the aging effects

identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.4.2.4.12 Electro-Hydraulic Control System

As described in Section 2.3.4.12, the electro-hydraulic control system actuates and controls the

steam valves. This system is completely separated from the bearing oil supply. During normal
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plant operation, reactor power is controlled to match turbine load as measured by turbine first

stage pressure. The turbine electro-hydraulic control system establishes the desired turbine

steady-state load. This system provides turbine trip signals that have license renewal functions

of ATWS mitigation and main steam isolation (when used in conjunction with components from

various other systems) for a steam line break coincident with failure of a main steam isolation

valve.

The applicant’s screening review concluded that the electro-hydraulic control system does not

perform any intended functions for license renewal. Therefore, none of the electro-hydraulic

control system components are subject to an AMR.

Staff review of the scoping and screening process in LRA Section 2.3.4.12 concluded that no

electro-hydraulic control system components are subject to an AMR.

3.4.2.4.13 Generic RAI Issues

RAI 3.4-9

In Tables 2.3.38 through 2.3.47 of the LRA, the applicant identifies valves (body only)” in the

component” column. The GALL Report recommends that the aging effects identified in these

tables, except for wall thinning due to FAC, are applicable to both the valve body and bonnet. 

The staff issued RAI 3.4-9, requesting the applicant to explain why the valve bonnets are not

affected by these aging effects or to provide aging management for the bonnets.

In its response by letter dated June 12, 2003, the applicant stated that the choice of words,

“valves (body only)” comes from 10 CFR 54.21(a)(1)(a)(1)(i). As defined in the body of

technical work for the IPA (available on site for inspection) “valves (body only)” refers to body

and bonnet.

The staff finds the applicant’s response to RAI 3.4-9, reasonable and acceptable because it

provides an explanation that valve bonnets are included as part of the valve body.

RAI 3.4-10

In Table 3.4-1, Item 6 of the LRA, the applicant stated in the discussion” column of the FlowAccelerated Corrosion Monitoring Program that the component/component type AMR results for

VCSNS are consistent with the GALL Report in material, environment, aging effects, and

program. In the GALL Report, aging management for FAC is specified for all steam and power

conversion systems piping, fitting, pump casings, and valve bodies. In Tables 2.3-38 and

2.3-40, the LRA does not identify aging management for FAC for piping, fitting, pump casings,

and valve bodies in the auxiliary boiler and feedwater system and the emergency feedwater

system. Also, in Table 2.3-44, the LRA does not identify aging management for FAC for the

main steam system pump turbine (casing only). The staff issued RAI 3.4-10, requesting the

applicant to explain why the LRA states it is consistent with the GALL Report but does not

include the above components in the Flow-Accelerated Corrosion Monitoring Program.

In its response by letter dated June 12, 2003, the applicant stated that EPRI considers that FAC

is not an aging effect requiring evaluation in systems that are either highly oxygenated,

superheated, single-phase flow below 200 °F, or operated less than 2 percent of the time. The
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portion of the auxiliary boiler and feedwater system in scope for license renewal only supplies

steam to the evaporators and to the boric acid batch add tank. The evaporators are rarely used

and the batch add tank rarely requires steam. Steam flows less than 2 percent of the time in

this line. Therefore, loss of material due to FAC is not an aging effect requiring management

for the auxiliary boiler and feedwater system. The process fluid of the emergency feedwater

system is less than 200 °F; therefore, loss of material due to FAC is not an aging effect

requiring management for the emergency feedwater system. The component identified in

Table 2.3-44 of the LRA as the main steam system pump turbine (casing only) is the turbine

driven emergency feedwater pump casing. This pump is operated less than 2 percent of the

time. Therefore, loss of material due to FAC is not an aging effect requiring management for

the turbine driven emergency feedwater pump casing. 

The staff finds the applicant’s response to RAI 3.4-10, reasonable and acceptable because it

provides an explanation why the above components are not managed for loss of material due to

FAC.

RAI 3.4-15

The GALL Report recommends a one-time inspection to verify the effectiveness of the Water

Chemistry Program for all components except those in the main steam system. The staff

issued RAI 3.4-15, requesting the applicant to explain why a one-time inspection is not

performed to verify the effectiveness of the Chemistry Program for auxiliary boiler steam and

feedwater system components in Table 2.3-38, gland sealing steam system components in

Table 2.3-43, main steam dump system components in Table 2.3-45, and turbine cycle

sampling system components in Table 2.3-46.

In its response by letter dated June 12, 2003, the applicant stated that the only license renewal

function of the gland sealing, main steam dump, and turbine cycle sampling systems is to

provide a means of main steam isolation (when used in conjunction with components from

various other systems) for a steam line break coincident with failure of the main steam isolation

valve. The components of these systems provide this function in the main steam system

environment; therefore, a one-time inspection is not required. The portion of the auxiliary boiler

and feedwater system in scope for license renewal supplies steam to the evaporators and the

boric acid batch add tank in the auxiliary building. The normal supply for this steam is from the

reheat steam system through a desuperheating valve which converts superheated steam to a

high quality saturated steam for use in these components. Thus, the steam originates from the

main steam system, passes through the high pressure turbine generator, then through the

moisture separator reheater where moisture is removed and the steam is superheated for use

in the low pressure turbines. A portion of the steam leaving the moisture separator reheater is

converted by the desuperheater to saturated steam for use in the evaporators and the boric

acid batch add tank. Because the steam originates as high purity steam in the main steam

system and is further reheated in the moisture separator reheaters, the environment of the inscope portion of the auxiliary boiler and feedwater system should be considered as pure as the

environment of the main steam system; therefore, a one-time inspection is not required. 

The staff finds the applicant’s response to RAI 3.4-15, reasonable and acceptable because it

provides an explanation that the above components are located in a main steam environment;

therefore a one-time inspection is not required to verify the effectiveness of the Chemistry

Program.
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3.5 Containment, Structures, and Component Supports

This section addresses the aging management of the containment, structures, and component

supports. The structures that make up this group are described in the following LRA sections: 

• Reactor Building (Containment and Internal Structures) (2.4.1)

• Auxiliary Building (2.4.2.1)

• Control Building (2.4.2.2)

• Diesel Generator Building (2.4.2.3)

• Fuel Handling Building (2.4.2.4)

• Intermediate Building (2.4.2.5)

• Turbine Building (2.4.2.6)

• Service Water Pumphouse (2.4.2.7.1)

• Service Water Intake and Discharge Structures (2.4.2.7.2)

• Condensate Storage Tank Foundation—Yard Structure (2.4.2.8.1)

• Fire Service Pumphouse—Yard Structure (2.4.2.8.2)

• Electrical Manhole MH-2—Yard Structure (2.4.2.8.3)

• Earthen Embankments (North Berm, Service Water Pond Dams) (2.4.2.8.4)

• Electrical Substation and Transformer Area—Yard Structures (2.4.2.8.5)

The applicant did not address component supports as a separate structural group, but as 

structural component types within each of the structures listed above. LRA Section 3.5.1.11

describes the Class 1 component supports. With this exception, there is no specific description

of component supports.

LRA Table 2.4-1 presents a listing of the intended functions applicable to containment,

structures, and structural components. For each of the structures in the license renewal scope, 

LRA Tables 2.4-2 through 2.4-14 list the applicable structural component types, the applicable

intended function(s), and a reference to the AMR results that are summarized in LRA Section

3.5, Tables 3.5-1 and 3.5-2. 

LRA Table 3.5-1 duplicates NUREG-1800 Table 3.5-1, with an added “Discussion” column. 

The discussion column summarizes the results of the applicant’s plant-specific AMR for the

structures and structural components that are generically evaluated in the GALL Report. LRA

Table 3.5-2 covers plant-specific structures and structural components that are different from or

not addressed in the GALL Report, but are relied on for license renewal by the applicant. The

discussion column summarizes the results of the applicant’s plant-specific AMR for these

structures and structural components. 

3.5.1 Summary of Technical Information in the Application

3.5.1.1 Description of Containment, Structures, and Component Supports

LRA Section 3.5.1 contains brief descriptions of the containment, structures, and component

supports subject to AMR. These descriptions are consistent with, but not identical to, the

descriptions in LRA Sections 2.4.1 and 2.4.2. In two cases, additional descriptive information is

included in LRA Section 3.5.1, and augments the descriptions in LRA Section 2.4. 
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LRA Section 3.5.1.2 describes the auxiliary building. There are some differences when

compared to the description in LRA Section 2.4.2.1. The text of LRA Section 3.5.1.2 is as

follows:

The Auxiliary Building superstructure is a reinforced concrete shear wall (box type) structure containing five

main floor levels above the foundation and extending up to elevation 485’-0" (designated as the roof). Above

this level is another story composed primarily of a metal clad structural steel braced frame, but with limited

areas continuing the reinforced concrete construction employed below. The foundation is comprised of a

reinforced concrete structural mat which is supported on fill concrete down to competent bedrock. A

waterproofing membrane is provided between the structural mat concrete and fill concrete because of the

depth of the foundation below the ground water table.

This description includes additional detail about the structure above elevation 485’-0", and also

indicates that the bottom of the foundation is below the groundwater table.

LRA Section 3.5.1.11 describes the Class 1 component supports. This section has no

counterpart in LRA Section 2.4. The text of LRA Section 3.5.1.11 is as follows:

Class 1 Component Supports are those supports for major equipment and Class 1 piping that are subject to

aging management review including: Class 1 piping supports and major equipment supports (pressurizer base

flange and upper lateral supports; reactor vessel supports; steam generator vertical, lower lateral, and upper

lateral supports; and reactor coolant pump lateral and vertical support assemblies).

The passive, long-lived structural component types in these structures, that are subject to an

AMR, were previously identified in LRA Tables 2.4-2 through 2.4-14. Tables 2.4-2 through 2.4-

14 reference specific item numbers in LRA Tables 3.5-1 and 3.5-2. Tables 3.5-1 and 3.5-2

summarize the results of the applicant’s AMR for the containment, structures, and component

supports at VCSNS, and also identify the AMPs and activities that manage aging. Descriptions

of the AMPs and activities, including site-specific operating experience, are contained in LRA

Appendix B. 

3.5.1.2 Aging Management Review Methodology 

LRA Section 3.5.2 summarizes the applicant’s AMR methodology, and its review of site-specific

and industry operating experience. The applicant’s AMR of containment, structures, and

component supports considered the materials, environments, and stressors that are associated

with each structure, component, or commodity grouping under review. The methodology

follows the approach recommended in NEI 95-10 and is based on generic industry guidance for

determining aging effects for both mechanical and civil/structural components. The applicant

reviewed the guidance for applicability to the VCSNS materials of construction, and component

internal and external operating environments, and utilized it to identify aging effects for

components, structures, and commodities. The evaluation of materials and environment

combinations resulted in the identification of the aging effects; if the identified aging effects

adversely affect intended functions, then the aging effects require management for the

applicable components and commodities.

The applicant correlated aging effects that require management to AMPs. The AMR identified

one or more AMPs to be used to demonstrate that the effects of aging will be managed so that

the intended functions will be maintained consistent with the CLB for the period of extended

operation. The programs identified for managing the effects of aging were compared to those

listed in NUREG-1801 and evaluated for consistency with NUREG-1801 programs that are
3-332

relied on for license renewal. The results are documented and discussed in LRA Table 3.5-1,

using the format in the NRC SRP-LR (NUREG-1800). 

The staff’s preacceptance review of VCSNS LRA Section 3.5 identified a difficulty in tracking

the specific structural component types included in the VCSNS license renewal scope, as

delineated in LRA Tables 2.4-2 through 2.4-14, to the applicable aging effects requiring

management and to the AMPs credited for managing the aging effects. In response, the

applicant submitted Report TR00170-003, Revision 0, Attachment II: Aging Management

Review Results for Structures and Structural Components. Attachment II contains 10-column

formatted tables that identify each structural component type, its intended function(s), material,

environment, aging effect(s), AMP(s), consistency with the NUREG-1801 AMP(s), and

applicable notes. This supplementary submittal resolves the staff’s concern. 

3.5.1.3 Operating Experience Review

The applicant’s AMR in LRA Section 3.5.2 included an evaluation of site-specific and industry

operating experience. The site-specific evaluation included a review of (1) Corrective Action

Program, (2) license event reports, (3) Maintenance Rule Data Base, and (4) interviews with

systems engineers. The applicant stated that this review did not identify any additional aging

effects requiring management beyond those identified using the methods described in NEI 95-

10.

The applicant conducted a review of industry operating experience published since the effective

date of NUREG-1801, to identify any additional aging effects requiring management. This

review did not identify any additional aging effects requiring management beyond those

previously identified. 

The applicant’s ongoing review of plant-specific and industry-wide operating experience is

conducted in accordance with the plant Operating Experience Program.

The applicant has documented plant-specific operating experience primarily under the

“Operating Experience” attribute of the AMP evaluations in LRA Appendix B. Some operating

experience is also summarized in LRA Tables 3.5-1 and 3.5-2, in the “Discussion” column, and

in Report TR00170-003, Attachment II — Aging Management Review Results for Structures

and Structural Components, in the “Notes” column. The staff evaluation of plant-specific

operating experience is included in SER Section 3.5.2.3, Aging Management Programs.

3.5.2 Staff Evaluation

In Section 3.5 of the LRA, the applicant described its AMR for structures and structural

components at VCSNS. The staff reviewed LRA Section 3.5 to determine whether the applicant

has provided sufficient information to demonstrate that the effects of aging will be adequately

managed so that the intended functions will be maintained consistent with the CLB throughout

the period of extended operation, in accordance with the requirements of 10 CFR 54.21(a)(3),

for structures and structural components that are determined to be within the scope of license

renewal and subject to an AMR. 
3-333

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of structures and structural components for license

renewal as documented in the GALL Report. Thus, the staff did not repeat its review of the

matters described in the GALL Report, except to ensure that the material presented in the LRA

was applicable, and to verify that the applicant had identified the appropriate programs as

described and evaluated in the GALL Report. The staff evaluated those aging management

issues recommended for further evaluation in the GALL Report. The staff also reviewed aging

management information submitted by the applicant that was different from that in the GALL

Report or was not addressed in the GALL Report. Finally, the staff reviewed the FSAR

supplement to ensure that it provided an adequate description of the programs credited with

managing aging for structures and structural components.

In LRA Section 3.5, the applicant provided brief descriptions of the structures and structural

components and summarized the results of its AMR of the structures and structural

components at VCSNS.

Table 3.5-1 below provides a summary of the staff’s evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.5 that are addressed in the GALL

Report.

Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Common Components of All Types of PWR and BWR Containment

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

Penetration sleeves,

penetration bellows,

and dissimilar metal

welds

(LRA Table 3.5-1,

AMR Item 1)

Cumulative fatigue

damage (CLB fatigue

analysis exists)

TLAA evaluated in

accordance with 10

CFR 54.21(c)

TLAA (4.6) addresses

the flat plate closures

that comprise the 

containment pressure

boundary at

penetrations.

Penetration sleeves,

penetration bellows,

and dissimilar metal

welds are on the

outside of the

penetrations and are

not part of the

containment pressure

boundary.

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Cumulative Fatigue

Damage below).

Penetration sleeves,

bellows, and

dissimilar metal welds

(LRA Table 3.5-1,

AMR Item 2)

Cracking due to cyclic

loading, or crack

initiation and growth

due to SCC

Containment ISI

and containment

leak rate test

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16). 

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Cracking below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Common Components of All Types of PWR and BWR Containment

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

3-334

Penetration sleeves,

penetration bellows,

and dissimilar metal

welds

(LRA Table 3.5-1,

AMR Item 3)

Loss of material due to

corrosion

Containment ISI

and containment

leak rate test

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16).

Consistent with GALL.

(See Section 3.5.2.1

below).

Personnel airlock and

equipment hatch

(LRA Table 3.5-1,

AMR Item 4)

Loss of material due to

corrosion

Containment ISI

and Containment

leak rate test

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16). 

Consistent with GALL.

(See Section 3.5.2.1

below).

Personnel airlock and

equipment hatch

(LRA Table 3.5-1,

AMR Item 5)

Loss of leak tightness

in closed position due

to mechanical wear of

locks, hinges, and

closure mechanism

Containment leak

rate test and Plant

Technical

Specifications

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16); leak

tightness of hatches is

governed by VCSNS

Tech. Spec. 3/4.6.1. 

Consistent with GALL.

(See Section 3.5.2.1

below).

Seals, gaskets, and

moisture barriers

(LRA Table 3.5-1,

AMR Item 6)

Loss of sealant and

leakage through

containment due to

deterioration of joint

seals, gaskets, and

moisture barriers

Containment ISI

and Containment

leak rate test

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16);

Maintenance Rule

Structures Program

(App. B.1.18). 

Consistent with GALL.

(See Section 3.5.2.1

below).
3-335

Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report: 

PWR Concrete (Reinforced and Prestressed) and Steel Containment 

BWR Concrete (Mark II and III) and Steel (Mark I, II, and III) Containment

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

Concrete elements:

foundation, walls,

dome

(LRA Table 3.5-1,

AMR Item 7)

Aging of accessible and

inaccessible concrete

areas due to leaching

of calcium hydroxide,

aggressive chemical

attack, and corrosion of

embedded steel

Containment ISI 10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); Containment

ISI Program-IWE/IWL

(App. B.1.16). 

Plant-specific for

inaccessible areas:

groundwater and

reservoir chemistry

monitoring; inspect

below-grade concrete

when exposed; use

periodic inspection of

underwater concrete

structures as an

indicator. 

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Aging of Inaccessible

Concrete Areas

below).

Concrete elements:

foundation

(LRA Table 3.5-1,

AMR Item 8)

Cracks, distortion, and

increases in component

stress level due to

settlement

Structures

Monitoring

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); Containment

ISI Program-IWE/IWL

(App. B.1.16);

Maintenance Rule

Structures Program

(App. B.1.18). 

Consistent with GALL.

(See Section 3.5.2.2.1

Cracking, Distortion,

and Increase in

Component Stress

Level below).

Concrete elements:

foundation

(LRA Table 3.5-1,

AMR Item 9)

Reduction in foundation

strength due to erosion

of porous concrete

subfoundation

Structures

Monitoring

Not applicable.

VCSNS does not use

porous concrete and

does not have a

dewatering system. 

Consistent with GALL.

(See Section 3.5.2.2.1

Cracking, Distortion,

and Increase in

Component Stress

Level below).

Concrete elements:

foundation, dome,

and wall

(LRA Table 3.5-1,

AMR Item 10)

Reduction of strength

and modulus due to

elevated temperature

Plant-specific Not applicable.

VCSNS containment 

concrete is not

exposed to elevated

temperature.

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Reduction of Strength

and Modulus of

Concrete Structures

below).

Prestressed

containment: tendons

and anchorage

components

(LRA Table 3.5-1,

AMR Item 11)

Loss of prestress due

to relaxation, shrinkage,

creep, and elevated

temperature

TLAA evaluated in

accordance with 10

CFR 54.21(c)

TLAA per 10 CFR

54.3 (4.5); Tendon

Surveillance Program

(App.B.3.3);

Containment ISI

Program-IWE/IWL

(App. B.1.16).

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Loss of Prestress

below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report: 

PWR Concrete (Reinforced and Prestressed) and Steel Containment 

BWR Concrete (Mark II and III) and Steel (Mark I, II, and III) Containment

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

3-336

Steel elements: liner

plate, containment

shell

(LRA Table 3.5-1,

AMR Item 12)

Loss of material due to

corrosion in accessible

and inaccessible areas

Containment ISI and

Containment leak

rate test 

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); 10 CFR

Appendix J Leak Rate

Testing (App. B.1.12);

Containment ISI

Program-IWE/IWL

(App. B.1.16);

Containment Coating

Monitoring and

Maintenance Program

(App.B.1.15). 

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Loss of Material

below).

Steel elements: vent

header, drywell head,

torus, downcomers,

pool shell

Cumulative fatigue

damage (CLB fatigue

analysis exists)

TLAA evaluated in

accordance with 10

CFR 54.21(c)

Not applicable. BWR

Steel elements:

protected by coating

(LRA Table 3.5-1,

AMR Item 13)

Loss of material due to

corrosion in accessible

areas only

Protective coating

monitoring and

maintenance

10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); Containment

Coating Monitoring

and Maintenance

Program

(App.B.1.15);

Containment ISI

Program-IWE/IWL

(App. B.1.16);

Maintenance Rule

Structures Program

(App. B.1.18). 

Consistent with GALL.

(See Section 3.5.2.1

below).

Prestressed

containment: tendons

and anchorage

components

(LRA Table 3.5-1,

AMR Item 14)

Loss of material due to

corrosion of

prestressing tendons

and anchorage

components

Containment ISI Containment ISI

Program-IWE/IWL

(App. B.1.16); Tendon

Surveillance Program

(App.B.3.3)

Consistent with GALL.

(See Section 3.5.2.1

below).

Concrete elements:

foundation, dome,

and wall

(LRA Table 3.5-1,

AMR Item 15)

Scaling, cracking, and

spalling due to freezethaw; expansion and

cracking due to

reaction with aggregate

Containment ISI 10 CFR Appendix J

General Visual

Inspection (App.

B.1.11); Containment

ISI Program-IWE/IWL

(App. B.1.16);

Maintenance Rule

Structures Program

(App. B.1.18).

Consistent with GALL.

(See Section 3.5.2.1

below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report: 

PWR Concrete (Reinforced and Prestressed) and Steel Containment 

BWR Concrete (Mark II and III) and Steel (Mark I, II, and III) Containment

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

3-337

Steel elements: vent

line bellows, vent

headers, downcomers

Cracking due to cyclic

loads or crack initiation

and growth due to SCC

Containment ISI and

Containment leak

rate test

Not applicable. BWR

Steel elements:

suppression chamber

liner

Crack initiation and

growth due to SCC 

Containment ISI and

Containment leak

rate test

Not applicable. BWR

Steel elements:

drywell head and

downcomer pipes

Fretting and lock up

due to wear

Containment ISI Not Applicable BWR

Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Class I Structures

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

All groups except

Group 6: accessible

interior/exterior

concrete & steel

components

(LRA Table 3.5-1,

AMR Item 16)

All types of aging

effects

Structures

Monitoring

Containment Coating

Monitoring and

Maintenance Program

(App.B.1.15);

Containment ISI

Program-IWE/IWL

(App. B.1.16);

Maintenance Rule

Structures Program

(App. B.1.18).

Consistent with GALL.

(See Section 3.5.2.2.2

below).

Groups 1-3, 5, 7-9:

inaccessible concrete

components, such as

exterior walls below

grade and foundation 

(LRA Table 3.5-1,

AMR Item 17) 

Aging of inaccessible

concrete areas due to

aggressive chemical

attack and corrosion of

embedded steel

Plant-specific Plant-specific:

groundwater and

reservoir chemistry

monitoring; inspect

below-grade concrete

when exposed; use

periodic inspection of

underwater concrete

structures as an

indicator. 

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.2

below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Class I Structures

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

3-338

Group 6: all

accessible/inaccessibl

e concrete, steel and

earthen components

(LRA Table 3.5-1,

AMR Item 18)

All types of aging

effects, including loss

of material due to

abrasion, cavitation,

and corrosion

Inspection of WaterControl Structures or

FERC/US Army

Corps of Engineers

dam inspections and

maintenance

Maintenance Rule

Structures Program

(App. B.1.18); Service

Water Pond Dam

Inspection Program

(App. B.1.21); Service

Water Structures

Survey Monitoring

Program (App.

B.1.22); Underwater

Inspection Program

(SWIS and SWPH)

(App. B.1.23);

Consistent with GALL.

(See Section 3.5.2.1

below).

Group 5: liners 

(LRA Table 3.5-1,

AMR Item 19)

Crack initiation and

growth from SCC and

loss of material due to

crevice corrosion

Water Chemistry

Program and

Monitoring of spent

fuel pool water level

Chemistry Program

(App. B.1.4);

Maintenance Rule

Structures Program

(App. B.1.18); Tech.

Spec. 3/4.7.10

requires verification of

pool water level on a

continuous basis.

Consistent with GALL.

(See Section 3.5.2.1

below).

Group 1-3, 5, 6: all

masonry block walls

(LRA Table 3.5-1,

AMR Item 20)

Crack due to restraint,

shrinkage, creep, and

aggressive environment

Masonry Wall Maintenance Rule

Structures Program

(App. B.1.18).

Consistent with GALL.

(See Section 3.5.2.1

below).

Group 1-3, 5, 7-9:

foundation

(LRA Table 3.5-1,

AMR Item 21)

Cracks, distortion, and

increases in component

stress level due to

settlement

Structures

Monitoring 

Maintenance Rule

Structures Program

(App. B.1.18)

Consistent with GALL.

(See Section 

3.5.2.2.1 Cracking,

Distortion, and

Increase in

Component Stress

Level below).

Group 1-3, 5-9:

foundation

(LRA Table 3.5-1,

AMR Item 22)

Reduction in foundation

strength due to erosion

of porous concrete

subfoundation

Structures

Monitoring 

Not applicable.

VCSNS does not use

porous concrete and

does not have a

dewatering system.

Consistent with GALL.

(See Section 3.5.2.2.1

Cracking, Distortion,

and Increase in

Component Stress

Level below).

Group 1-5: concrete

(LRA Table 3.5-1,

AMR Item 23)

Reduction of strength

and modulus due to

elevated temperature

Plant-specific Not applicable.

VCSNS Class I

structures concrete is

not exposed to

elevated temperature.

Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.1

Reduction of Strength

and Modulus of

Concrete Structures

below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Class I Structures

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

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Groups 7, 8: liners

(LRA Table 3.5-1,

AMR Item 24)

Crack initiation and

growth due to SCC;

Loss of material due to

crevice corrosion

Plant-specific Concrete tanks are

not used at VCSNS;

applicant states that

aging effect is not

applicable to VCSNS

steel tanks. In the

mechanical systems

AMR, Above Ground

Tank Inspection (App.

B.2.1) is credited for

one-time inspection of

carbon steel and

stainless steel tank

internal surfaces. 

GALL recommends

further evaluation.

(See Section 3.5.2.4

below).

Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Component Supports

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

All Groups: 

support members:

anchor bolts, concrete

surrounding anchor

bolts, welds, grout

pad, bolted

connections, etc.

(LRA Table 3.5-1,

AMR Item 25)

Aging of component

support 

Structures

Monitoring

Maintenance Rule

Structures Program

(App. B.1.18); 10 CFR

Appendix J General

Visual Inspection

(App. B.1.11). 

Consistent with GALL.

(See Section 3.5.2.2.3

below).

Groups B1.1, B1.2,

and B1.3: 

support members:

anchor bolts, welds

(LRA Table 3.5-1,

AMR Item 26)

Cumulative fatigue

damage (CLB fatigue

analysis exists)

TLAA evaluated in

accordance with 10

CFR 54.21(c)

Not applicable Consistent with GALL.

GALL recommends

further evaluation. 

(See Section 3.5.2.2.3

below). 

All Groups: support

members: anchor

bolts, welds

(LRA Table 3.5-1,

AMR Item 27)

Loss of material due to

boric acid corrosion

Boric acid corrosion Boric Acid

Surveillances (App.

B.1.2); Maintenance

Rule Structures

Program (App.

B.1.18); 10 CFR

Appendix J General

Visual Inspection

(App. B.1.11)

Consistent with GALL.

(See Section 3.5.2.1

below).
Table 3.5-1 Staff Evaluation for V.C. Summer Structures and Structural Components in the GALL Report:

Component Supports

Component Group Aging

Effect/Mechanism

AMP in GALL

Report 

AMP in LRA Staff Evaluation

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Groups B1.1, B1.2,

and B1.3: support

members: anchor

bolts, welds, spring

hangers, guides,

stops, and vibration

isolators

(LRA Table 3.5-1,

AMR Item 28)

Loss of material due to

environmental

corrosion; loss of

mechanical function

due to corrosion,

distortion, dirt,

overload, etc.

ISI Maintenance Rule

Structures Program

(App. B.1.18); 10 CFR

Appendix J General

Visual Inspection

(App. B.1.11); ASME

Section XI ISI

Program-IWF (App.

B.1.13)

Consistent with GALL.

(See Section 3.5.2.1

below).

Group B1.1: high

strength low-alloy

bolts

(LRA Table 3.5-1,

AMR Item 29)

Crack initiation and

growth due to SCC

Bolting integrity ASME Section XI ISI

Program-IWF (App.

B.1.13);

Applicant justified that

this aging effect is not

applicable to VCSNS.

Not consistent with

GALL. (See Section

3.5.2.4 below).

The staff’s review of the VCSNS structural components is contained within four sections of this

SER. Section 3.5.2.1 is the staff review of structures and structural components that the

applicant indicates are consistent with GALL and for which GALL does not require further

evaluation. Section 3.5.2.2 is the staff review of structures and structural components that the

applicant indicates are consistent with GALL and for which GALL recommends further

evaluation. Section 3.5.2.3 is the staff evaluation of the AMPs that are specific to the aging

management of structural components. Section 3.5.2.4 contains an evaluation of the adequacy

of aging management for components in each structure and includes an evaluation of

structures and structural components that the applicant indicates are not in GALL.

3.5.2.1 Aging Management Evaluations in the GALL Report That Are Relied On For License

Renewal That Do Not Require Further Evaluation

Table 3.5-1 indicates that all except one of the LRA Table 3.5-1 AMR items for which GALL

does not require further evaluation were found to be consistent with GALL. The staff reached

these conclusions after review of the applicant’s RAI responses. The exception is AMR Item

29, related to SCC of high-strength bolting for component supports. While not consistent with

GALL, the staff accepts the applicant’s AMR, which concluded that this aging effect is not

applicable to VCSNS. The staff’s evaluation of this issue is in SER Section 3.5.2.3.3. 

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plant. The staff also identified several areas

where additional information or clarification was needed. The staff’s evaluation of applicant’s

responses to those RAI’s is included in Sections 3.5.2.2, 3.5.2.3, and 3.5.2.4 of this SER.
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On the basis of its review, the staff has verified the applicant’s claim of consistency with the

GALL report. The staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.5.2.2 Aging Management Evaluations in the GALL Report That Are Relied On For License

Renewal For Which GALL Recommends Further Evaluation

For component groups evaluated in the GALL Report for which the applicant has claimed

consistency with GALL, and for which the GALL Report recommends further evaluation, the

staff reviewed the applicant’s evaluation to determine whether it adequately addressed the

issues for which GALL recommended further evaluation. In addition, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. 

The Gall Report indicates that further evaluation should be performed for the items described in

the following sections:

3.5.2.2.1 Containment

Aging of Inaccessible Concrete Areas

As stated in the SRP-LR, the GALL Report recommends further evaluation to manage the

aging effects for containment concrete components located in inaccessible areas, if the aging

mechanisms of (1) leaching of calcium hydroxide, (2) aggressive chemical attack, or (3)

corrosion of embedded steel are significant. Possible aging effects for containment concrete

structural components due to these three aging mechanisms are cracking, change in material

properties, and loss of material.

The AMP recommended by the GALL Report for managing the above aging effects for

containment concrete components in accessible portions of the containment structures is the

ASME Section XI, Subsection IWL (XI.S2) Program. The staff’s evaluation of the applicant’s

ASME Section XI, Subsection IWL AMP is in Section 3.5.2.3.6 of this SER.

Subsection IWL exempts from examination those portions of the concrete containment that are

inaccessible (e.g., foundation, below-grade exterior walls, concrete covered by liner). For

inaccessible portions of the containment structure, 10 CFR 50.55a(b)(2)(ix) requires that the

licensee evaluate the acceptability of inaccessible areas when conditions exist in accessible

areas that could indicate the presence of, or result in, degradation to inaccessible areas.

The applicant addressed the specific criteria defined in the GALL Report, regarding the need for

further evaluation to manage the potential aging of containment concrete structural components

in inaccessible areas in LRA Table 3.5-1. The GALL Report recommends further evaluation for

containment concrete in inaccessible areas if the aging mechanism’s (1) leaching of calcium

hydroxide, (2) aggressive chemical attack, or (3) corrosion of embedded steel are significant. 

In LRA Table 3.5-1, AMR item 7, the applicant stated that —
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The VCSNS containment structure is not exposed to flowing water and designed in accordance with ACI-318

and constructed in accordance with ACI-301 and ASTM Standards, which provide a good quality, dense, low

permeability concrete.

The water chemical analysis results confirm that the site groundwater is mildly acidic but considered to be nonaggressive.

Further, the applicant concluded that —

Inaccessible areas at VCSNS do not require a plant-specific aging management for leaching of calcium

hydroxide, aggressive chemical attack or corrosion of embedded steel.

The staff position is that inaccessible concrete components (i.e., below grade) require aging

management unless specific criteria defined in NUREG-1801, GALL Volume 2, are satisfied to

demonstrate a nonaggressive below-grade environment. As part of RAI 3.5-2, the staff

requested the following information:

(c) Submit a quantitative assessment of the below-grade environment, comparing it to the

specific criteria defined in GALL Volume 2.

(d) If it is nonaggressive, based on satisfaction of the specific criteria defined in GALL Volume

2, describe the groundwater monitoring program that will be implemented to verify that the

below-grade environment remains nonaggressive, including monitoring frequency and

consideration of seasonal fluctuations.

(e) If the below-grade environment does not satisfy the specific criteria defined in GALL Volume

2, describe in detail the plant-specific AMPs for inaccessible concrete components.

In its initial response to RAI 3.5-2, parts (c), (d), and (e), the applicant stated the following: 

(c) Section 6.1 (Table 6.1-3) of TR00170-003 provides the quantitative assessment of the below-grade

groundwater environment at VCSNS. These analyses results are based on samples taken in 2001 from three

(3) wells in the general vicinity of plant structures. [Note that prior sample analyses for chlorides, sulfates and

pH do not exist.] Groundwater chlorides (from all three wells) were determined to be < 10 ppm, which is well

within the GALL defined limits of < 500 ppm. Groundwater sulfates (from all three wells) were determined to

be < 10 ppm, which is well within the GALL defined limits of < 1500 ppm. Groundwater pH (from the three

wells) was determined to range from 4.8 to 5.3, which marginally exceeds the GALL defined limits of 5.5.

Based on these results, the VCSNS Application defines the site groundwater as non-aggressive, although

mildly acidic.

(d) Application Table 3.5-1, Item 17 specifies that periodic monitoring of the below-grade water chemistry will

be conducted during the period of extended operation to demonstrate that the below-grade environment is not

aggressive. VCSNS Engineering Services Procedure (Inspections for Maintenance Rule - Structures) will be

revised to include a chemical analysis of raw water (including groundwater) on a 5-year interval to coincide

with the Maintenance Rule Structures Inspections. [Note that seasonal fluctuations are not applicable at

VCSNS since the level of groundwater remains relatively constant due to the influence of Monticello

Reservoir.]

(e) Application Table 3.5-1, Items 7 and 16, discusses aging mechanisms and effects for inaccessible

concrete. Since the VCSNS below grade environment marginally exceeds the specific pH criteria defined in

GALL, the concrete design was further reviewed and determined to provide protection against aggressive

chemical attack. Since the below-grade structures are considered to be resistant to the mildly acidic

environment, plant specific aging management programs are not required for inaccessible concrete areas.
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The staff position is that any deviation from the specific criteria defined in GALL Volume 2

constitutes an aggressive environment, and aging management of inaccessible concrete is

necessary.

In its supplemental response to RAI 3.5-2, the applicant committed to a plant-specific program

to manage aging of inaccessible concrete:

The NRC Staff position is that the VCSNS groundwater is considered to be aggressive since it has a pH < 5.5.

In order to satisfy this concern, the following provisions will be incorporated as part of existing plant programs

and procedures:

1. The site excavation and backfill procedure will be revised to include a concrete surface inspection by

engineering personnel if soil is removed adjacent to any concrete structure surfaces to a depth greater

than 5 feet below nominal grade elevation.

2. As noted in response to RAI 3.5-2(d), chemical analysis of groundwater will be conducted on a 5-year

interval to coincide with the Maintenance Rule Structures Inspection Program. This analysis will also

include a water sample from the Service Water Pond.

3. Underwater diver’s inspections of the Service Water Intake Structure (tunnel) will continue as

described in response to RAI 3.5-26. These inspections will provide additional assurance of the

integrity of concrete structures exposed to below water conditions.

Since the applicant’s program is consistent with programs previously accepted by the staff to

address this issue, the staff finds it acceptable.

On the basis of its review, the staff finds that the applicant appropriately evaluated AMR results

involving management of aging of inaccessible concrete areas for containment, as

recommended in the GALL report. Since the applicant’s AMR results are otherwise consistent

with the GALL report, the staff finds 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).

Cracking, Distortion, and Increase in Component Stress Level Due to Settlement; Reduction of

Foundation Strength Due to Erosion of Porous Concrete Subfoundations, If Not Covered by

Structures Monitoring Program

As stated in the SRP-LR, for the containment foundation, the GALL Report recommends further

evaluation of the aging effects of (1) cracking due to settlement and (2) change in material

properties as manifested by a reduction of foundation strength due to erosion of the porous

concrete subfoundation, if these two effects are not covered by a structures monitoring AMP. 

In addition, the GALL Report recommends verification of the continued functionality of a

dewatering system during the license renewal period, if relied on by the applicant to lower the

site groundwater level.

The applicant addressed the above criteria defined in the GALL Report, regarding the need for

further evaluation to manage the potential aging of the containment foundation in LRA Table

3.5-1, AMR Items 8 and 9. 
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Under AMR Item 8, the applicant credits three AMPs, including its Maintenance Rule Structures

Program (B.1.18), to manage the aging effects due to settlement. However, the applicant also

stated —

The VCSNS containment foundation is constructed directly on competent bedrock and is not subject to

settlement; therefore, aging management is not required.

Under AMR item 9, the applicant stated —

The VCSNS containment foundation does not use porous concrete and is not subject to flowing water;

therefore, aging management is not required. 

The staff noted that in LRA Section 3.5.1.2, the applicant indicates that the foundation for the

auxiliary building extends below the groundwater level and is supported on fill concrete down to

competent bedrock. The applicant does not identify whether underdrain (dewatering) systems

are utilized at VCSNS for the auxiliary building or any other buildings in the license renewal

scope, and no intended functions have been identified for the fill concrete used under several of

the buildings included in the license renewal scope. In RAI 3.5-6, the staff requested the

applicant to submit the following information related to underdrain systems and fill concrete:

(a) Identify whether underdrain (dewatering) systems are utilized at VCSNS.

(b) If utilized, describe the specific applications; describe current monitoring and/or

maintenance activities that ensure proper functioning; discuss whether they perform an

intended function; and, as appropriate, submit an AMR, including identification of credited

AMPs.

(c) Describe the fill concrete, including its strength, thickness, underground profile, and

construction procedures. Also define the groundwater level with respect to the fill concrete

profile.

(d) Describe plant-specific operating experience concerning settlement of buildings resting on

fill concrete.

(e) Discuss whether fill concrete performs an intended function; and, as appropriate, submit an

AMR, including identification of credited AMPs.

In its response to RAI 3.5-6, the applicant stated the following:

(a) Underdrain (de-watering) systems are not used at VCSNS.

(b) Since underdrain (de-watering) systems are not used at VCSNS, there are no monitoring or maintenance

activities or functional requirements.

(c) Fill concrete (1500 psi minimum compressive strength at 28 days) was used as a leveling mat to construct

the structural foundations for the Reactor, Auxiliary and Control Buildings. The fill concrete design is not

porous, rather it just has a higher water-cement ratio than the higher strength structural foundation mixes of

3000 psi and greater. The fill concrete was placed directly on clean, competent bedrock, which has a design

allowable bearing capacity of 200 ksf (1389 psi). The fill concrete was placed in minimum 5’ lifts on an irregular

rock surface, with thickness varying from approximately 5’ to 50' (depending on varying elevations of rock

surface and structure foundations). The levels of fill concrete range from approximately elevation 344’ to 407’,

while the nominal groundwater elevation is at elevation 423’. [Refer to VCSNS FSAR Sections 2.5 and 3.8.]
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(d) There has been no operating experience at VCSNS concerning settlement of buildings resting on fill

concrete. The initial design of the fill concrete determined that post-construction settlement would be

practically nil, since only minimal settlement would occur from the initial construction loads.

(e) The fill concrete does not perform an intended function since it was designed to be equivalent to rock as

an underlying base, and is not evaluated under any aging management programs.

In its assessment of fill concrete, the staff evaluated the information provided in the LRA, the

applicant’s RAI responses, and the referenced FSAR sections, in order to reach a

determination whether the fill concrete should be in the license renewal scope and whether

aging management is required. Since the fill concrete was designed to be equivalent to rock as

an underlying base and has a bearing capacity comparable to the design allowable for the

bedrock, the staff concludes that, for the purpose of license renewal, the fill concrete can be

considered an extension of the bedrock. Therefore, it is outside the scope of license renewal.

Also, in part (b) to RAI 3.5-9, the staff requested the applicant to clarify LRA Table 3.5-1, AMR

Item 8. There is reference to three AMPs, even though the containment foundation is not

subject to settlement.

In its response to RAI 3.5-9 (b), the applicant stated the following:

As discussed in Application Table 3.5-1, Item 8, the VCSNS containment foundation is constructed directly

on fill concrete over competent bedrock and is not subject to settlement; therefore, aging management is not

required. [See response to RAI 3.5-6.] However, regardless if settlement is not considered as an applicable

aging mechanism, existing AMPs (10 CFR 50 Appendix J General Visual Inspection, Containment ISI Program

- IWE/IWL, and Maintenance Rule Structures Program) will still be used to look for concrete aging effects such

as cracks and distortion.

The staff concurs that in the unlikely event of containment foundation settlement, the identified

AMPs will be effective in detecting the applicable aging effects.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of cracking, distortion, and increase in component stress level

due to settlement and reduction of foundation strength due to erosion of porous concrete

subfoundations for containment components, as recommended in the GALL Report. Since the

applicant’s AMR results are other wise consistent with the GALL report, the staff finds 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).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature

As stated in the SRP-LR, for the containment structure, the GALL Report recommends further

evaluation to manage the aging effect change in material properties as manifested by a

reduction in strength and modulus, if any portion of the containment concrete exceeds the

temperature limit of 150 F. The GALL Report notes that the implementation of Subsection

IWL examinations and 10 CFR 50.55a would not be able to detect the reduction of concrete

strength and modulus due to elevated temperature, and also notes that no mandated aging

management exists for managing this aging effect.
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The GALL Report recommends that a plant-specific evaluation be performed if any portion of

the concrete containment components exceeds specified temperature limits (i.e., general

temperature 66 °C (150 °F) and local area temperature 93 °C (200 °F)). The staff verified that

the applicant’s discussion in the renewal application indicates that the affected PWR

containment components are not exposed to temperatures that exceed the above temperature

limits.

The applicant addressed the above criterion defined in the GALL Report, regarding the need for

further evaluation, in LRA Table 3.5-1, AMR Item 10. The applicant stated the following

regarding temperatures within the containment structure:

The VCSNS containment concrete elements are not exposed to temperatures which exceed the thresholds

for degradation; therefore, reduction of strength and modulus due to elevated temperatures are not aging

effects requiring management. 

This statement does not seem to be consistent with the information presented in Report

TR00170-003, Revision 0, Table 6.1-1, and the discussion on page 59 of the report. The table

indicates that there is one region (above the reactor head but below the operating floor

elevation 463') that has a maximum temperature of 157 °F. Page 59 of the report also

indicates that the CRDM is maintained at a temperature of less than or equal to 170 °F. The

report concludes that these temperatures are localized and do not exceed 200 °F. The report

follows with some additional discussion about elevated temperature concerns for three areas

inside the reactor building. Some design modifications were made to rearrange air flow in the

reactor building and tests were made in which the inspector identified no further problems. 

From the information presented, it is not clear to the staff which regions currently experience

temperatures above 150 °F, whether these are area temperatures or localized temperatures

around hot piping penetrations, and how aging effects due to elevated temperatures will be

managed. 

In RAI 3.5-12, the staff requested the following additional information:

(a) Explain the apparent inconsistency between LRA Table 3.5-1, AMR Item 10 and the

information in Report TR00170-003, Revision 0 (see above discussion).

(b) For all structures in the scope of license renewal, identify all regions that currently

experience temperatures in excess of 150 °F.

(c) If there are regions that currently experience temperatures in excess of 150 °F, indicate

whether these are area temperatures or localized temperatures around hot penetrations. 

(d) If any area temperatures exceed 150 °F and/or any localized temperatures exceed 200 °F,

how will change in material properties of concrete due to elevated temperatures be managed

during the period of extended operation?

In its response to RAI 3.5-12, the applicant stated the following:

(a) VCSNS does not believe that there is any inconsistency between Application Table 3.5-1, Item 10, and

TR00170-003, Table 6.1-1 and Section 6.4. The Application states that containment concrete elements are

not exposed to temperatures, which exceed the thresholds for degradation. These thresholds are consistent

with the guidance provided in GALL, which defines elevated temperatures as greater than 150 o

F general and
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200 oF local (GALL II.A1.1-h). Specifically: Table 6.1-1 of TR00170-003 lists a maximum temperature of 157 F

for the area above the reactor head but below operating floor elevation 463’ (which is an open area above the

vessel). This specific area above the head has no direct contact or support with concrete from the surrounding

primary shield walls. Therefore, the general area temperature for the concrete would actually be less than

157 o

F. Regardless, the reactor vessel should be considered as a large hot pipe within the penetration opening

of the massive primary shield walls, which would allow a local maximum temperature of 200 oF.

Section 6.4 of TR00170-003 states that the Control Rod Drive Mechanism (CRDM) is maintained at a

temperature less than or equal to 170 oF. The CRDM is supported by the reactor vessel head and extends

upwards in an area away from surrounding concrete of the primary shield walls. For the same reason as stated

above, these temperatures are considered to be localized and do not exceed the threshold value of 200 o

F.

(b) Temperatures for all structures in the scope of license renewal are identified in Table 6.1-1 and Section

6.4.1 of TR00170-003. Regions exceeding 150 o

F have been discussed in Response (a) above.

(c) As discussed above, these areas are considered to be localized temperatures.

(d) Since these temperatures fall within the industry accepted thresholds, there are no changes in material

properties of concrete expected; therefore, aging management is not required.

Since the two areas inside containment that experience temperatures above the 150 F limit

(157 o

F, 170 oF) are localized and not in direct contact with concrete, the staff concurs with the

applicant’s conclusion that further evaluation, as recommended by the GALL Report, is not

required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of the reduction of strength and modulus of concrete structures

due to elevated temperature for containment components, as recommended in the GALL

Report. Since the applicant’s AMR results are other wise consistent with the GALL report, the

staff finds 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).

Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or Liner

Plate

As stated in the SRP-LR, the GALL Report recommends further evaluation to manage the

aging effect of loss of material due to corrosion for the embedded containment liner, if corrosion

of the embedded liner is significant. The AMP recommended by the GALL Report for managing

loss of material for accessible steel elements within the containment structure is the ASME

Section XI, Subsection IWE (XI.S1) Program. The staff’s evaluation of the applicant’s ASME

Section XI, Subsection IWE AMP is in Section 3.5.2.3.6 of this SER.

Subsection IWE exempts from examination portions of the containments that are inaccessible,

such as embedded or inaccessible portions of steel liners and steel containment shells, piping,

and valves penetrating or attaching to the containment. To cover inaccessible areas, 10 CFR

50.55a(b)(2)(ix) requires that the licensee evaluate the acceptability of inaccessible areas when

conditions exist in accessible areas that could indicate the presence of, or result in, degradation

to inaccessible areas.

The applicant addressed the above criterion defined in the GALL Report, regarding the need for

further evaluation to manage the potential aging of the embedded containment liner, in LRA
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Table 3.5-1, AMR Item 12. Regarding the potential for significant corrosion of the embedded

steel containment liner, the applicant stated the following:

Corrosion for inaccessible areas (embedded containment liner) is not significant because:

Concrete meeting the requirements of ACI 318 or 349 and the guidance of 201.2R was used for the

containment concrete in contact with the embedded containment liner.

The concrete is monitored under Maintenance Rule Structures Program and IWL to ensure that it is

free of penetrating cracks.

The moisture barrier is monitored under IWE for aging degradation.

Borated water leakage in the containment structure is not a common occurrence and is monitored

under the aging management program Boric Acid Corrosion Surveillances (App. B.1.2).

The staff noted that the plant-specific operating experience does not necessarily support this

conclusion. LRA Appendix B.1.12.1 indicates that rust was identified on the reactor building

liner plate adjacent to the moisture barrier and the moisture barrier had degraded. Therefore, it

is not evident that loss of material due to corrosion in inaccessible areas of the containment

liner is not significant at VCSNS. It is also unclear to the staff why the nonconformance

discussed in LRA Appendix B.1.12.1 was identified by the Appendix J Leak Rate Testing

program (B.1.12), and not by the Appendix J General Visual Inspection Program (B.1.11)

and/or the Containment ISI Program—IWE/IWL (B.1.16). 

In RAI 3.5-13, the staff requested the following additional information:

(a) What inspections have been conducted to assess the condition of the liner embedded in

the concrete base?

(b) Confirm that the nonconformance discussed in LRA Appendix B.1.12.1 was detected prior

to the implementation of the B.1.16 AMP. If not, explain why this nonconformance was not

detected under the B.1.16 aging management program.

(c) Explain why this nonconformance was not detected under the B.1.11 AMP.

(d) Clarify the scope of and interaction between all three AMPs (B.1.11, B.1.12, and B.1.16).

(e) The rust on the liner plate and the degraded moisture barrier could indicate the presence of

or result in degradation in the inaccessible areas of the containment liner. Discuss how the

acceptability of the inaccessible areas of the containment liner was evaluated as a result of this

nonconformance.

(f) Since this type of degradation has already occurred, what is the technical basis for

concluding that it could not occur again?

(g) Clarify whether the supplemental requirements of 10 CFR 50.55a for inaccessible areas are

credited for license renewal aging management of the inaccessible liner plate. 

In its response to RAI 3.5-13, the applicant stated the following:
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(a) Application Section B.1.12.1 states: “A non-conformance (NCN) was documented for rust found on the

Reactor Building liner plate adjacent to the moisture barrier and for a degraded moisture barrier. The

disposition was to clean up the rust on the Reactor Building liner plate adjacent to the moisture barrier and

to replace affected portions of the moisture barrier. Visual examination and ultrasonic tests demonstrated that

the liner plate had not degraded. The evaluation concluded that the condition was normal surface life exposure

and was not aging related.” ---A more in-depth inspection of the liner was not warranted as a result of this

NCN, since the liner was found to have an insignificant reduction in thickness in the areas of observed rusting.

[Note that additional inspections of inaccessible areas would have been warranted if any significant liner

degradation had been found in these accessible areas.] Future inspections of the moisture barrier and

adjacent liner will be conducted under the Containment ISI Program - IWE/IWL (B.1.16).

(b) The observed liner rusting and degradation of the moisture barrier was identified in 1999 during outage

walkdowns by engineering and QC personnel. Such walkdowns have been conducted for many years and

preceded the implementation of the Containment ISI Program - IWE/IWL. Inspection of the moisture barrier

is now part of the Containment ISI Program - IWE/IWL. The NCN is discussed in Application Section B.1.12

(Appendix J Leak Rate Testing Program) since the other major containment inspection programs were not

conducted during that particular outage.

(c) This NCN was identified during normal outage walkdowns and not detected under the 10 CFR 50 Appendix

J General Visual Inspections (B.1.11) since they were not required during the 1999 outage. The last prior

General Visual Inspection was conducted in 1997. [See Response d) below.]

(d) The 10 CFR 50 Appendix J General Visual Inspection (B.1.11) is conducted two times in the 10 year period

preceding the Type A ILRT. The 10 CFR 50 Appendix J Leak Rate Tests (B.1.12) (Type A, B, C) are

conducted in accordance with established frequencies per regulation. The Containment ISI Program -

IWE/IWL (B.1.16) was initiated in 2000 and will be conducted on a 5-year frequency.

(e) No further inspections of the liner were warranted as a result of this NCN, since the liner was found to have

an insignificant reduction in thickness in the areas of observed rusting. UT examinations were conducted at

various locations around containment in areas where rusting was observed, along with a control area not

showing rust. The moisture barrier was removed in these areas, the rust/paint was mechanically cleaned, and

UT examinations were made at floor level and several inches into the annulus gap. The UT examinations

showed no significant loss of liner thickness when compared to the design thickness, with results well within

the ± 10% fabrication tolerance of the liner. Consistent with the current provisions of ASME Section XI -

IWE/IWL, additional inspections of inaccessible areas would have been warranted if any significant liner

degradation had been found in these accessible areas.

(f) The moisture barrier is an elastomer, which is subject to degradation (splitting, separation, etc.) over time;

therefore, this type of degradation could occur again. The current AMPs (Containment ISI Program - IWE/IWL

and Maintenance Rule Structures Program) have proven effective in managing the condition of the moisture

barrier in order to preclude any significant degradation of the liner.

(g) The supplemental requirements of 10 CFR 50.55a for inaccessible areas are credited for license renewal

aging management of the inaccessible liner plate. [Note that additional inspections of inaccessible areas will

be warranted if any significant liner degradation is found in adjacent accessible areas during future

inspections.]

Since the applicant’s inspection did not find significant corrosion in the inaccessible portion of

the containment liner plate, and since the applicant credits its ASME Section XI, Subsection

IWE AMP for managing loss of material for the accessible portion of the containment liner plate,

the staff finds the applicant’s response to RAI 3.5.1-13, to be acceptable. As required by 10

CFR 50.55a(b)(2)(ix), the applicant will inspect the inaccessible portions of the containment

liner plates, if significant corrosion of the accessible portions of the liner plate is observed.

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of loss of material due to corrosion in inaccessible areas of steel

containment shell or liner plate for containment components, as recommended in the GALL
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Report. Since the applicant’s AMR results are other wise consistent with the GALL report, the

staff finds 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).

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature

As stated in the SRP-LR, the GALL Report identifies loss of prestress due to relaxation,

shrinkage, creep, and elevated temperature for prestressed containment tendons and

anchorage components as a TLAA to be performed for the period of extended operation. 

The applicant addressed loss of prestress due to relaxation, shrinkage, creep, and elevated

temperature for prestressed containment tendons and anchorage components in LRA Table

3.5-1, AMR Item 11. The applicant stated the following: 

VCSNS aging management programs Containment ISI Program - IWE/IWL (App. B.1.16) and Tendon

Surveillance Program (App. B.3.3) are consistent with those reviewed and approved in NUREG-1801.

VCSNS Containment tendons have been determined to be a TLAA in accordance with 10 CFR 54.3. Refer

to Section 4.5. 

The staff notes that the applicant’s Tendon Surveillance Program (B.3.3) is consistent with 

GALL X.S1, for implementing TLAA option (iii) of 10 CFR54.21(c)(1). The staff’s evaluation of

this AMP is in Section 3.5.2.3.12 of this SER. The staff’s evaluation of this TLAA is in Section

4.5 of this SER.

Cumulative Fatigue Damage

As stated in the SRP-LR, the GALL Report identifies cumulative fatigue damage of penetration

sleeves, penetration bellows, and dissimilar metal welds as a TLAA, if a CLB fatigue analysis

exists. If applicable, the TLAA must be updated to include the period of extended operation.

The applicant addressed this TLAA in LRA Table 3.5-1, AMR Item 1. The applicant stated the

following:

VCSNS does not evaluate fatigue for penetration sleeves, bellows or dissimilar metal welds; therefore, a TLAA

evaluation is not applicable.

Penetration sleeves meet the requirements of ASME section III, comply with GDC-51, and behave in a nonbrittle manner.

Penetration bellows are used in hot penetrations at VCSNS but do not provide containment isolation since they

are located within the penetration on the exterior side of containment, Hot penetrations are sealed on the

inside of containment by a flat plate welded to both the penetration sleeve and process pipe (similar to cold

penetrations), thus providing containment isolation without the use of a resilient seal.

Dissimilar metal welds are materials and not components. VCSNS penetration sleeves and process pipes use

similar (SA) materials.

Since containment isolation is accomplished by the flat plate closures, in RAI 3.5-9, part (a), the

staff requested the applicant to submit the following additional information about the design

basis for these closures:
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Describe how the design basis for the flat plate containment penetration closures considered

cyclic loading due to temperature/pressure transients. If a CLB fatigue analysis exists for the

flat plate penetration closures, has it been updated for a 60-year operating life? How will

cracking due to cyclic loading be managed for the period of extended operation?

In its response to RAI 3.5-9, part (a), the applicant stated the following:

(a) For containment penetration closures, the flat plate is basically no more than an extension of the

containment liner plate which connects to the penetration sleeve. The containment liner plate was reviewed

for fatigue analysis as originally calculated for 40 years. The calculation was subsequently revised to show

that fatigue analysis was acceptable for 60 years. Application Section 4.6.1 discusses the TLAA review for the

containment liner for which VCSNS utilized 10 CFR 54.21(c) (1) Option (ii) to demonstrate that liner fatigue

is adequately analyzed for the period of extended operation.

The applicant refers to the LRA Section 4.6.1 evaluation of the containment liner plate TLAA,

implying that it is also applicable to the flat plate closures. The staff’s evaluation of the TLAA

for the containment liner plate is in Section 4.6 of this SER. The acceptability of this TLAA for

the flat plate containment penetration closures was confirmed and discussed in Section 4.6 of

this SER.

Cracking due to Cyclic Loading and Stress-Corrosion Cracking

As stated in the SRP-LR, the GALL Report recommends further evaluation of the AMPs

credited to manage cracking of containment penetrations (including penetration sleeves,

penetration bellows, and dissimilar metal welds) due to cyclic loading or SCC for all types of

PWR containments. Containment ISI and leak rate testing may not be sufficient to detect

cracks induced by cyclic loading or SCC. The staff evaluated the applicant’s proposed

programs to verify that adequate inspection methods will be implemented to ensure that

cracking of containment penetrations is detected.

The applicant addressed cracking of containment penetrations in LRA Table 3.5-1, AMR Item 2.

Consistent with GALL, the applicant credits containment ISI and leak rate testing for managing

this aging effect. However, augmented inspection to detect cracks is not identified. The

applicant stated the following:

Stress Corrosion Cracking (SCC) requires a combination of a corrosive environment, susceptible materials,

and high tensile stresses,

(1) VCSNS penetration sleeves are not subject to high tensile stresses or aggressive chemicals during normal

operation, while similar metal welds are used between penetration sleeves and process pipes; therefore, SCC

is not an applicable aging effect requiring management. 

(2) VCSNS hot penetration bellows do not perform a pressure boundary function nor incorporate a flexible seal

assembly on the inboard side of containment. They do provide structural and/or functional support for process

piping on the outboard side of containment; therefore, in the unlikely event of SCC in the bellows, the intended

functions are not affected.

The staff noted that although the containment pressure boundary may not be affected, failure of

the bellows would appear to affect other intended functions. In addition, AMR Item 2 credits the

Appendix J General Visual Inspection Program, Appendix J Leak Rate Testing Program, and

Containment ISI Program—IWE-IWL as AMPs. These programs would appear to be applicable
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only to the welded flat plate closures that are part of the containment pressure boundary, and

not to the penetration bellows.

In RAI 3.5-16, the staff requested the following information:

(a) Explain why cracking of the stainless steel penetration bellows (and the associated

dissimilar metal welds) does not affect the bellows’ intended function to "provide structural

and/or functional support for process piping on the outboard side of containment."

(b) Identify the aging effects that are applicable to the penetration bellows (and the associated

dissimilar metal welds), and the AMPs that are credited to manage aging.

In its response to RAI 3.5-16, the applicant stated the following:

(a) Bellows on hot piping penetrations do not perform a pressure boundary function, but they do provide

structural and/or functional support (i.e., thermal and accident movement of the process pipe). In the unlikely

event that cracking of the stainless steel penetration bellows occurs, thermal and accident movement of the

process pipe would not be impaired and therefore will not diminish the bellows’ intended function. Loss of

Material and Cracking aging effects for penetration bellows have been screened out due to the plant specific

design and bellow protection features. Refer to Sections 6.2, 6.9, and 8.3 of TR00170-003 under Bellows.

(b) Stainless steel bellows are very compliant (flexible), therefore sustained high tensile stress does not exist.

However, cracking of the bellows due to SCC would not impair the intended function. All containment

penetrations are inspected (both inside and outside containment) as part of the Containment ISI Program -

IWE/IWL.

The staff finds the applicant’s response to RAI 3.5.1-16, to be acceptable, and concurs that the

function of the stainless steel bellows to allow free axial movement of the process piping is not

affected by cracking. Therefore, the staff concludes that cracking due to cyclic loading or SCC

is not an applicable aging effect for VCSNS and augmented inspection to detect cracking is not

necessary. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of cracking due to cyclic loading and SCC for containment

components, as recommended in the GALL Report. Since the applicant’s AMR results are

other wise consistent with the GALL report, the staff finds 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).

Conclusion

The staff has reviewed the applicant’s evaluation of the issues related to structural components

in containment for which the GALL Report recommends further evaluation. On the basis of its

review, the staff finds that the applicant has provided sufficient information to demonstrate that

the issues for which the GALL Report recommends further evaluation have been adequately

addressed, and that the subject aging effects will be adequately managed for the period of

extended operation.

3.5.2.2.2 Class I Structures
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Aging of Structures Not Covered by Structures Monitoring Program

As stated in the SRP-LR, the GALL Report recommends further evaluation for certain

structure/aging effect combinations, if they are not covered by the applicant’s Structures

Monitoring Program. This includes (1) scaling, cracking, and spalling, due to repeated freezethaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spalling and increase in porosity

and permeability due to leaching of calcium hydroxide and aggressive chemical attack for

Groups 1-5, 7-9 structures; (3) expansion and cracking due to reaction with aggregates for

Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of bond, and loss of material due to

corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks, distortion, and increase

in component stress level due to settlement for Groups 1-3, 5, 7-9 structures; (6) reduction of

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 structures; 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 that are not

covered by the applicant’s Structures Monitoring Program.

In LRA Table 3.5-1, AMR item 16, the applicant credited its Maintenance Rule Structures

Program, Containment Coating Monitoring and Maintenance Program, and Containment ISI

Program—IWE/IWL for general aging management of accessible areas of Class I structures.

However, the applicant also provided detailed technical justifications why concrete aging effects

are not significant for accessible areas, and why VCSNS does not require a plant-specific

program to manage aging of concrete in inaccessible areas. 

The staff requested additional information in RAIs 3.5-2, 3.5-9, part (e), and 3.5-11 related to

clarification of the applicant’s commitment to manage aging of accessible and inaccessible

concrete components of Class I structures. Based on the applicant’s responses to these RAIs,

the staff concludes that accessible and inaccessible concrete components of Class I structures

will be adequately managed, in accordance with the GALL Report. The staff’s detailed

evaluation of this issue is in Section 3.5.2.4 of this SER. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of aging of structures not covered by Structures Monitoring

Program for Class I structures, as recommended in the GALL Report. Since the applicant’s

AMR results are other wise consistent with the GALL report, the staff finds 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).

Aging Management of Inaccessible Areas

As stated in the SRP-LR, the GALL Report recommends further evaluation for aging of

inaccessible concrete areas, such as below-grade foundation and exterior walls exposed to

groundwater due to aggressive chemical attack, if an aggressive below-grade environment

exists. An aggressive below-grade environment could result in either cracking or loss of

material for concrete components subjected to such an environment. The GALL Report
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recommends that a plant-specific AMP be developed by the applicant, if an aggressive belowgrade environment exists.

The staff’s evaluation and resolution of this issue for containment also applies to Class I

structures, and is documented in Section 3.5.2.2.1 - Aging of Inaccessible Concrete Areas, of

this SER. 

Conclusion

The staff has reviewed the applicant’s evaluation of the issues related to structural components

in Class I structures for which the GALL Report recommends further evaluation. On the basis

of its review, the staff finds that the applicant has provided sufficient information to demonstrate

that the issues for which the GALL Report recommends further evaluation have been

adequately addressed, and that the subject aging effects will be adequately managed for the

period of extended operation.

3.5.2.2.3 Component Supports

Aging of Supports Not Covered by Structures Monitoring Program

As stated in the SRP-LR, the GALL report recommends further evaluation of certain component

support/aging effect combinations if they are not covered by the SRP. This includes (1)

reduction in concrete anchor capacity due to degradation of the surrounding concrete, for

Groups B1-B5 supports; (2) loss of material due to environmental corrosion, for Groups B2-B5

supports; and (3) reduction/loss of isolation function due to degradation of vibration isolation

elements, for Group B4 supports. Further evaluation is necessary only for the structure/aging

effect combinations, listed above, that are not covered by the applicant’s Structures Monitoring

Program.

In LRA Table 3.5-1, AMR item 25, the applicant credited its Maintenance Rule Structures

Program and its 10 CFR Part 50 Appendix J General Visual Inspection Program to manage

aging of component supports. The applicant also included a technical basis for concluding that

“cracking due to fatigue is not an aging effect requiring management for concrete components.”

This is consistent with the staff position. In RAI 3.5-9, part (f), the staff requested the applicant

to clarify which supports/aging effects are managed by each of the two credited programs.

In its response to RAI 3.5-9, part (f), the applicant stated the following:

(f) For Application Table 3.5-1, Item 25, the Maintenance Rule Structures Program applies to all

subcomponents for all structures (including containment), while the 10 CFR 50 Appendix J General Visual

Inspection is used only as a supplementary inspection program for containment. As noted in the

discussion for Item 25, cracking due to fatigue is not an aging effect requiring management for concrete

components. 

Since the applicant credited its Maintenance Rule Structures Program, as recommended by the

GALL Report, the staff finds that the applicant has adequately addressed this further evaluation

criterion. 
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On the basis of its review, the staff finds that the applicant has appropriately evaluated AMR

results involving management of aging of component supports, as recommended in the GALL

report. Since the applicant’s AMR results are other wise consistent with the GALL report, the

staff finds 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).

Cumulative Fatigue Damage Due to Cyclic Loading

As stated in the SRP-LR, the GALL Report identifies cumulative fatigue damage as a TLAA for

support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 component

supports, if a CLB fatigue analysis exists. In LRA Table 3.5-1, AMR Item 26, the applicant

stated that TLAA is not applicable since CLB fatigue analyses do not exist for these component

types at VCSNS. The staff finds this acceptable, on the basis that CLB fatigue analyses do not

exist.

Conclusion

The staff has reviewed the applicant’s evaluation of the issues related to structural components

in component supports for which the GALL Report recommends further evaluation. On the

basis of its review, the staff finds that the applicant has provided sufficient information to

demonstrate that the issues for which the GALL Report recommends further evaluation have

been adequately addressed, and that the subject aging effects will be adequately managed for

the period of extended operation.

3.5.2.3 Aging Management Programs for Containment, Structures, and Component Supports 

The applicant credits 16 AMPs to manage the aging effects associated with structures and

structural components. The location in this SER of the staff’s evaluation of each AMP is listed

below. The location of the description of each AMP in Appendix B of the LRA is shown in

parenthesis. 

 Boric Acid Corrosion Surveillances Program (B.1.2)(Section 3.0.3.1)

 Chemistry Program (B.1.4)(Section 3.0.3.2)

 Fire Protection Program (B.1.5)(Section 3.0.3.3)

 10 CFR 50 Appendix J General Visual Inspection Program (B.1.11)(Section 3.5.2.3.1)

 10 CFR 50 Appendix J Leak Rate Testing Program (B.1.12)(Section 3.5.2.3.2)

 ASME Section XI ISI Program - IWF (B.1.13)(Section 3.5.2.3.3)

 Battery Rack Inspection Program (B.1.14)(Section 3.5.2.3.4)

 Containment Coating Monitoring and Maintenance Program (B.1.15)(Section 3.5.2.3.5)

 Containment ISI Program—IWE/IWL (B.1.16)(Section 3.5.2.3.6)

 Flood Barrier Inspection Program (B.1.17)(Section 3.5.2.3.7)

 Maintenance Rule Structures Program (B.1.18)(Section 3.0.3.4)

 Pressure Door Inspection Program (B.1.20)(Section 3.5.2.3.8)

 Service Water Pond Dam Inspection Program (B.1.21)(Section 3.5.2.3.9)

 Service Water Structures Survey Monitoring Program (B.1.22)(Section 3.5.2.3.10)

 Underwater Inspection Program (SWIS and SWPH) (B.1.23)(Section 3.5.2.3.11)

 Tendon Surveillance Program (B.3.3)(Section 3.5.2.3.12 )
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The staff reviewed the applicant’s AMP descriptions to compare those AMPs for which the

applicant claimed consistency with those reviewed and approved in the GALL report. For those

AMPs that are not evaluated in GALL, the staff evaluated the AMP against the 10 program

elements (BTP RLSB-1 in Section A-1 of NUREG-1800 Appendix A). The staff also conducted

an audit of all credited AMPs on July 16–17, 2003, at VCSNS. 

Several VCSNS AMPs were described by the applicant as being consistent with GALL, but with

some deviation from GALL. These deviations are of two types— clarifications to GALL or

enhancements to GALL. In Appendix B of the LRA, the applicant states that a clarification is

provided for instances where the VCSNS program does not match specific details of a NUREG1801 program element but is still determined to be consistent. For each AMP that had one or

more of these deviations, the staff reviewed each deviation to determine (1) whether the

deviation is acceptable and (2) whether the AMP, as modified, would adequately manage the

aging effect(s) for which it is credited. 

The staff also reviewed the FSAR supplements for the AMPs credited with managing aging in

structures and structural components to determine whether the program description adequately

describes the program. The staff’s evaluation of the FSAR supplement for each AMP is

included in the SER for each AMP.

3.5.2.3.1 10 CFR Part 50 Appendix J General Visual Inspection Program

Summary of Technical Information in the Application

In LRA Section B.1.11, the applicant stated that the 10 CFR Part 50 Appendix J General Visual

Inspection Program is consistent with XI.S4, 10 CFR 50 Appendix J, as identified in NUREG1801.

The 10 CFR Part 50 Appendix J General Visual Inspection Program is included in the

discussion column of LRA Table 3.5-1 for a number of containment components and

component supports, but is not credited to manage aging effects for license renewal in Report

TR00170-003, Revision 0, Attachment II: Aging Management Review for Structures and

Structural Components.

No licensee event reports (LERs) were initiated subsequent to any general visual structural

examination of the containment system. There were no NCNs or CERs identified that resulted

from conditions related to aging mechanisms.

The applicant concluded that the 10 CFR Part 50 Appendix J General Visual Inspection

Program provides reasonable assurance that the aging effects for the containment liner,

associated moisture barriers, and the reactor building structure will be managed such that the

components subject to AMR will continue to perform their intended functions consistent with the

CLB for the period of extended operations.

Staff Evaluation

The applicant stated that 10 CFR Part 50 Appendix J General Visual Inspection Program is

consistent with XI.S4, 10 CFR Part 50 Appendix J, as identified in NUREG-1801. However, the

scope of GALL XI.S4 is for containment leak rate testing and not general visual inspection of
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containments. Inspection of containments is covered by GALL XI.S1 and XI.S2, which involve

ASME Section XI, Subsections IWE and IWL, respectively. The applicant stated in LRA

Section B.1.16 that the Containment ISI Program—IWE/IWL is consistent with GALL XI.S1 and

XI.S2. The 10 CFR Part 50 Appendix J General Visual Inspection Program is included in the

discussion column of LRA Table 3.5-1, but is not identified as a credited AMP in Report

TR00170-003, Revision 0, Attachment II: Aging Management Review for Structures and

Structural Components.

In RAI 3.5-20, the applicant was requested to provide additional information as to whether the

10 CFR Part 50 Appendix J General Visual Inspection Program is credited as an AMP for

license renewal. In response to RAI 3.5-20, the applicant stated the following:

(a) The 10 CFR 50 Appendix J General Visual Inspection is only one component of the total Appendix J

Program. Under Appendix J, a visual examination of accessible interior and exterior surfaces of the

containment system shall be conducted during two other refueling outages before the next Type A test if

the interval for the Type A test has been extended to 10 years, in order to allow for early uncovering of

evidence of structural deterioration. These inspections are conducted by Operations personnel and

provide additional inspections for aging management of the containment, thus being credited for license

renewal. This program is only used as a supplement, not substitute, for the Containment ISI Program -

IWE/IWL.

(b) There are no elements of containment inspection (IWE/IWL) which rely solely on the 10 CFR 50

Appendix J General Visual Inspection.

(c) The AMPs listed in Attachment II (Reactor Building) of TR00170-003 are the primary programs used to

manage aging. The 10 CFR 50 Appendix J General Visual Inspection is only used as supplemental

information and does not substitute for any of the programs identified.

On the basis that this program is supplementary to the Containment ISI Program—IWE/IWL

(B.1.16) and 10 CFR Part 50 Appendix J Leak Rate Testing Program (B.1.12), and is not

credited as a substitute for any of the requirements of these two programs, the staff accepts

this program without further evaluation see SER Sections 3.5.2.3.2 and 3.5.2.3.6 for the staff

evaluation of the Appendix J Leak Rate Testing and IWE/IWL Programs, respectively). 

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.5.2.3.2 10 CFR Part 50 Appendix J Leak Rate Testing Program

Summary of Technical Information in the Application

In LRA Section B.1.12, the applicant stated that the 10 CFR Part 50 Appendix J Leak Rate

Testing Program is consistent with XI.S4, 10 CFR Part 50 Appendix J, as identified in 
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NUREG-1801.

The 10 CFR 50 Appendix J Leak Rate Testing Program (B.1.12) is included in the discussion

column of LRA Table 3.5-1 and credited to manage aging effects for license renewal in Report

TR00170-003, Revision 0, Attachment II: Aging Management Review for Structures and

Structural Components for the following reactor building components:

 compressible joints and seals

 liner plate

 penetrations (mechanical and electrical)

 personnel airlock, escape airlock, and equipment hatch

This program is also credited to manage aging effects for license renewal for the liner plate

(RHR and spray system isolation valve chambers and guard pipes) in the auxiliary building.

Over three refueling cycles (most recently RF-10, RF-11, and RF-12), Type B penetrations

delineated in the station surveillance procedure were tested with satisfactory results. A

nonconformance was documented for rust found on the reactor building liner plate adjacent to

the moisture barrier and a degraded moisture barrier. The disposition was to cleanup the rust

on the reactor building liner plate adjacent to the moisture barrier and to replace affected

portions of the moisture barrier. Visual examination and ultrasonic tests demonstrated that the

liner plate had not degraded. The evaluation concluded that the condition was normal surface

life exposure and was not aging related.

The applicant concluded that the 10 CFR Part 50 Appendix J Leak Rate Testing Program

provides reasonable assurance that the aging effects for the components forming the

containment pressure boundary will be managed such that the components subject to AMR will

continue to perform their intended functions consistent with the CLB for the period of extended

operations.

Staff Evaluation

In LRA Section B.1.12, “10 CFR 50 Appendix J Leak Rate Testing” the applicant described its

AMP to manage aging for the components forming the containment pressure boundary. The

LRA stated that this AMP is consistent with GALL AMP XI.S4, “10 CFR 50 Appendix J” with no

deviations. The staff audit on July 16–17, 2003 confirmed the applicant’s claim of consistency.

The staff also reviewed the FSAR supplement to determine whether it provides an adequate

description of the program. 

The staff noted several inconsistencies between the FSAR supplement summary descriptions

of the AMPs in LRA Appendix A and the scope of the AMPs identified in LRA Appendix B as

“consistent with GALL.” In RAI 3.5-19, the staff requested the applicant to verify that the

complete scope of the aging management program, as described in NUREG-1801, GALL

Volume 2, is being credited to manage aging effects for license renewal. If this is not the case,

the applicant was requested to identify and document the justification for each exception. In

response to RAI 3.5-19, the applicant stated the following:

As stated in the Application, VCSNS maintains a 10 CFR 50 Appendix J Leak Rate Testing Program

(B.1.12) using Option B, which is consistent with GALL XI.S4 and RG 1.163.
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VCSNS does not believe that there are any further changes required for the Application Appendix A, since

only summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory

Guides are implicit in the development of each of these programs as described in Section 7 of TR00170-

003.

In LRA Section B.1.12.1 on operating experience, the applicant discussed a nonconformance 

that was documented for rust found on the reactor building liner plate adjacent to the moisture

barrier and a degraded moisture barrier. The disposition was to cleanup the rust on the reactor

building liner plate adjacent to the moisture barrier and to replace affected portions of the

moisture barrier. Visual examination and ultrasonic tests demonstrated that the liner plate had

not degraded. The evaluation concluded that the condition was normal surface life exposure

and was not aging related.

In RAI 3.5-13 parts (b), (c), and (d), the staff requested the applicant to provide additional

information as to why the nonconformance discussed in LRA Appendix B.1.12.1 was identified

by the Appendix J Leak Rate Testing Program (B.1.12), and not by the Appendix J General

Visual Inspection program (B.1.11) and/or the Containment ISI Program—IWE/IWL (B.1.16).

In response to RAI 3.5-13 parts (b), (c) and (d), the applicant stated the following:

(b) The observed liner rusting and degradation of the moisture barrier was identified in 1999 during outage

walkdowns by engineering and QC personnel. Such walkdowns have been conducted for many years and

preceded the implementation of the Containment ISI Program - IWE/IWL. Inspection of the moisture barrier

is now part of the Containment ISI Program - IWE/IWL. The NCN is discussed in Application Section B.1.12

(Appendix J Leak Rate Testing Program) since the other major containment inspection programs were not

conducted during that particular outage.

(c) This NCN was identified during normal outage walkdowns and not detected under the 10 CFR 50

Appendix J General Visual Inspections (B.1.11) since they were not required during the 1999 outage. The last

prior General Visual Inspection was conducted in 1997. [See Response d) below.]

(d) The 10 CFR 50 Appendix J General Visual Inspection (B.1.11) is conducted two times in the 10 year

period preceding the Type A ILRT. The 10 CFR 50 Appendix J Leak Rate Tests (B.1.12) (Type A, B, C) are

conducted in accordance with established frequencies per regulation. The Containment ISI Program -

IWE/IWL (B.1.16) was initiated in 2000 and will be conducted on a 5-year frequency.

The staff finds the applicant’s response to RAI 3.5-13 parts (b), (c), and (d) to be acceptable.

The applicant has adequately described the relationship between the three AMPs (B.1.11,

B.1.12, and B.1.16) and clearly explained why the above nonconformance was detected under

the Appendix J Leak Rate Testing program.

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).
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3.5.2.3.3 ASME Section XI ISI Program — IWF (B.1.13)

Summary of Technical Information in the Application

In LRA Section B.1.13, the applicant stated that the ASME Section XI ISI Program — IWF is

consistent with XI.S3, ASME Section XI, Subsection IWF, as identified in NUREG-1801 with the

following clarification:

• VCSNS uses 1989 Edition of ASME Section XI with no Addenda

The ASME Section XI ISI Program — IWF (B.1.13) is included in the discussion column of LRA

Table 3.5-1 and credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II: Aging Management Review for Structures and Structural

Components for the following components in the auxiliary, reactor and intermediate buildings:

 anchorage/embedments

 equipment component supports

 expansion anchors

 pipe supports

The program is also credited to manage aging effects for license renewal for pipe supports in

the control, diesel generator, fuel handling buildings and the service water pumphouse. In

addition, the program is also credited for expansion anchors in the fuel handling building. 

A review of ASME Class 1, 2, and 3 component support inspections for the past five years

identified one case where acceptance criteria was not met. The gap at the top of a pipe

support exceeded the acceptance criteria; however, this is not aging related. Two NCNs were

identified for instances of minor surface corrosion on supports and anchor bolting. The

intended functions were not affected and corrective actions were performed in accordance with

site procedures. No CERs were initiated subsequent to ASME Class 1, 2, and 3 component

support inspections.

The applicant concluded that the ASME Section XI ISI Program — IWF for Class 1, 2, and 3

component supports, and support anchorage, provides reasonable assurance that the aging

effects will be managed such that the components subject to AMR will continue to perform their

intended functions consistent with the CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.13, “ASME Section XI ISI Program — IWF,” the applicant described its AMP

to manage aging in ASME code supports. The LRA stated that this AMP is consistent with

GALL AMP XI.S3, “ASME Section XI, Subsection IWF” with the following clarification —

VCSNS uses the 1989 edition of ASME Section XI with no Addenda. The staff reviewed the

clarification to determine whether the AMP, with the clarification, is adequate to manage the

aging effects for which it is credited, and also reviewed the FSAR supplement to determine

whether it provides an adequate description of the revised program. The staff audit on 

July 16–17, 2003, confirmed the applicant’s claim of consistency. 
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The Introduction to Appendix B, Aging Management Programs and Activities, of the LRA states

that “clarification is provided for instances where the VCSNS program does not match specific

details of a NUREG-1801 program element but is still determined to be consistent.” For this

AMP, a clarification is provided; however, it was not clear how the VCSNS program does not

match the referenced GALL AMP. In RAI 3.5-18, the staff requested the applicant to explain

what is intended by the above stated clarification to the program and confirm that the program

is completely consistent with GALL.

In response to RAI 3.5-18, the applicant stated the following:

ASME Section XI ISI Program - IWF (Application B.1.13) --- The clarification is no more than a statement that

VCSNS uses the 1989 Edition of ASME Section XI Code with no Addenda. This is consistent with GALL XI.S3

which states that the evaluations cover the 1989 Edition through the 1995 edition with addenda through the

1996 Addenda, as approved in 10 CFR 50.55a. VCSNS has not attempted to reconcile code differences nor

requested approval for later editions.

The staff finds the applicant’s response to RAI 3.5-18, to be acceptable. The use of the 1989

Edition of the ASME Section XI Code with no Addenda is acceptable to the staff and consistent

with GALL XI.S3, “ASME Section XI, Subsection IWF.” 

The staff noted several inconsistencies between the FSAR supplement summary descriptions

of the AMPs in LRA Appendix A and the scope of the AMPs identified in LRA Appendix B as

“consistent with GALL.” Some examples of these inconsistencies are as follows.

(a) Section 18.2.5 of LRA Appendix A states that the ASME Section XI ISI Program — IWF

manages “loss of material,” while the parameters monitored under GALL XI.S3 are much

broader and include — corrosion, deformation, misalignment, improper clearances, improper

spring settings, damage to close tolerance machined or sliding surfaces, and missing,

detached, or loosened support items.

(b) Section 18.2.5 of LRA Appendix A states that the ASME Section XI ISI Program — IWF

manages cracking of high strength anchorage of ASME Class 1 component supports. Under

GALL XI.S3, the visual inspection would be expected to identify relatively large cracks. If

cracking of high strength anchorage needs to be managed, the staff would expect that the

applicant would credit a program consistent with GALL XI.M18, Bolting Integrity.

In RAI 3.5-19, the staff requested the applicant to verify that the complete scope of the AMP, as

described in NUREG-1801, GALL Volume 2, is being credited to manage aging effects for

license renewal. If this is not the case, the applicant was requested to identify and document

the justification for each exception. In response to RAI 3.5-19, the applicant stated the

following:

As stated in the Application, VCSNS maintains an ASME Section XI ISI Program - IWF (B.1.13), which is

consistent with GALL XI.S3 and 10 CFR 50.55a. This RAI concludes that Application Section 18.2.5 is

inconsistent by only monitoring loss of material and cracking. However, Section 18.2.5 represents only a very

general overview (summary) of program content, which is consistent with the guidelines of NEI 95-10. VCSNS

maintains an extensive IWF program in accordance with ASME Section XI, which evaluates all of the identified

aging effects, plus others not cited.
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VCSNS does not believe that there are any further changes required for the Application Appendix A, since only

summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory Guides

are implicit in the development of each of these programs as described in Section 7 of TR00170-003.

In LRA Section B.1.13.1, the applicant acknowledged that improperly heat-treated anchor bolts

are susceptible to SCC, based on industry operating experience, but states that ASTM A490

anchor bolt material used at VCSNS is properly heat-treated by conforming to ASTM

Specification A490 through a Certified Material Test Report, in accordance with station

specifications. In Report TR00170-003, Revision 0, Section 6.8.6, the applicant indicated that

SCC is unlikely at VCSNS for the reasons identified therein, but further states, “Regardless, the

examination requirements of ASME Section XI ISI Program - IWF manage loss of function and

cracking due to SCC for the Class 1 component supports that are exposed to the Reactor

Building environment.” However, IWF visual inspection would be expected to identify only

relatively large cracks, as noted in GALL XI.S3. If cracking of high-strength anchorage needs

to be managed, the staff would expect that the applicant would credit a program consistent with

GALL XI.M18, Bolting Integrity. Therefore, in RAI 3.5-21, the staff requested the applicant to

(1) identify all plant-specific applications of high strength bolting in Class I piping and

component supports; (2) specifically describe the plant-specific operating experience related to

SCC of high-strength bolting materials used in Class I piping and component supports; (3)

describe the plant-specific resolution of the generic safety issue related to bolting integrity,

including a description of any inspections/tests conducted as part of the resolution; and (4) if

cracking due to SCC is an applicable aging effect, describe the inspections, in addition to IWF

visual inspection, that will be credited to manage this aging effect.

In response to RAI 3.5-21, the applicant stated the following:

1) High strength bolting materials are used in various Class 1 piping and component supports which are

identified in Section 6.8 of TR00170-003.

2) There is no plant specific operating experience related to Stress Corrosion Cracking (SCC) of high strength

bolts at VCSNS.

3) VCSNS followed resolution of the generic safety issue as an EPRI member. EPRI Report NP-5769 states

that utilities with bolting materials with specified yield strengths greater than 150 ksi should review their

individual applications. A review and discussion on susceptibility of high strength bolting to SCC at VCSNS

is contained in TR00170-003 (Sections 6.8 and 7.3), concluding that SCC is unlikely; therefore, not considered

an applicable aging effect requiring management. Regardless, the examination requirements of ASME Section

XI (IWF) are in place to adequately manage loss of function and cracking due to SCC for the Class 1 supports

that are exposed to the Reactor Building environment.

4) The intent of the discussion in Application Section B.1.13.1 is that SCC is not considered an applicable

aging effect for VCSNS requiring management. See additional discussions in Section 6.8.5 of TR00170-003.

Regardless, the ASME Section XI ISI Program - IWF does exist in order to manage this aging effect. VCSNS

also maintains an IWA program in accordance with ASME Section XI, which evaluates corrosion effects.

As a result of discussions with the applicant regarding the above response, the applicant

provided the following supplemental response to RAI 3.5-21:

1) VCSNS followed resolution of the generic safety issue as an EPRI member and performed a review for

applicability of SCC. As discussed in TR00170-003 (Section 6.8.5), Class 1 component supports could be

susceptible to SCC if they meet all three conditional factors: high strength material, moist environment, and

high level of sustained tensile stress (particularly with improperly heat treated anchor bolts). However, SCC

is not considered as an applicable aging mechanism at VCSNS since high levels of sustained tensile stress

do not exist for high strength bolting:
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 ASTM A490 anchor bolt material was properly heat-treated by conforming to ASTM Specification A490

through a certified mill test report.

 Anchor bolts are tightened snug-tight as defined by AISC; therefore, for bolts greater than 1" in

diameter, a significant preload (in the order of 70% of ultimate strength) is not practical to develop.

 Anchor bolts do not have a high level of sustained tensile stress as evidenced by lower faulted

condition design loads due to elimination of dynamic effects subsequent to postulated High Energy

Line Break (HELB) of the reactor coolant system primary coolant piping.

2) The IWF inspection program is not used at VCSNS to evaluate for SCC of high strength bolts. The IWF

program was only mentioned since it is the primary inspection program for evaluating Class 1 supports,

thereby providing some level of visual (VT-3) inspection of the adjacent bolts. 

3) There has been no plant specific operating experience related to SCC of high strength bolts at VCSNS.

On the basis that (1) the necessary conditions for the development of SCC in high strength

bolts do not exist at VCSNS and (2) there has been no plant-specific operating experience

related to SCC of high strength bolts, the staff finds that augmented inspection for SCC of high

strength bolts used in Class 1 supports is not warranted; inspection of Class 1 supports to the

requirements of ASME Section XI, Subsection IWF is judged to be sufficient to manage aging

for the period of extended operation. 

Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds 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

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.5.2.3.4 Battery Rack Inspection Program

Summary of Technical Information in the Application

In LRA Section B.1.14, the applicant stated that the Battery Rack Inspection Program is a plantspecific program that is not addressed in GALL.

The Battery Rack Inspection Program (B.1.14) is included in the discussion column of LRA

Table 3.5-2 and credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II for battery racks in the intermediate building and yard structures (fire

service pumphouse).

Review of work orders for the past 5 years did not identify any instance where abnormal

deterioration of battery racks occurred. No NCNs or CERs were initiated subsequent to

inspections for battery racks.
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The applicant concluded that the Battery Rack Inspection Program provides reasonable

assurance that the aging effects for steel battery racks will be managed such that the

components subject to AMR will continue to perform their intended functions consistent with the

CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.14, “Battery Rack Inspection,” the applicant described its AMP to manage

aging in steel battery racks. This AMP is not addressed in GALL. The staff, therefore,

reviewed this AMP against the 10 program elements using the guidance in BTP RLSB-1 in

Appendix A of the SRP-LR. The staff also reviewed the FSAR supplement to determine

whether it provides an adequate description of the program.

In the introduction to LRA Appendix B, the applicant stated that the VCSNS Quality Assurance

Program implements the requirements of 10 CFR Part 50, Appendix B, and is consistent with

the summary in Section A.2 of NUREG-1800, “Standard Review Plan for Review of License

Renewal.” The applicant further stated that VCSNS will employ the corrective action and

document control programs to address the program elements of corrective action, confirmation

process, and administrative (document) controls for both safety-related and non-safety-related

SCs that require aging management during the period of extended operation. The staff’s

evaluation of the applicant’s Quality Assurance Program is discussed separately, and

generically evaluated in Section 3.0.4 of this SER. Thus, these three elements are not

discussed further in this section. The staff’s evaluation of the remaining seven elements is

discussed below.

[Program Scope] The scope of the Battery Rack Inspection Program includes the battery racks

for the electrical DC (ED) system (vital batteries) and the fire service (FS) system (diesel fire

service pump battery). The applicant states that the regulatory basis for inspecting battery

racks for the ED system is found in the VCSNS Technical Specifications Surveillance

Requirement 3.8.2.1, while the regulatory basis for inspecting battery racks for the FS system is

the commitment in the fire protection procedure. The staff finds the scope of the program

acceptable since it identifies the specific structural components for which the program is

credited for license renewal. 

[Preventive Actions] The applicant identified the Battery Rack Inspection Program as a

conditioning monitoring program. As such, there are no preventive actions, nor did the staff

identify a need for such actions.

[Parameters Monitored or Inspected] The applicant stated that specific examination guidelines

for the ED system and FS system battery racks are provided in IEEE-450. For the ED system

and FS system, battery racks are inspected for loss of material due to corrosion. The applicant

further stated that, although not credited for license renewal, the battery racks are also

inspected for physical damage. The applicant explained that “physical damage” refers to “manmade damage.” The staff considers the parameters monitored to be acceptable since they are

consistent with industry guidelines. 

[Detection of Aging Effects] The applicant stated that the Battery Rack Inspection Program

detects structural damage or degradation (including loss of material due to corrosion) prior to

loss of structure intended function. The staff considers the applicant’s approach to the
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detection of aging effects to be acceptable since it is aimed at detecting aging effects before

there is a loss of intended function. 

[Monitoring and Trending] For the ED system, a visual examination is performed

every 18 months in accordance with commitments in UFSAR Section 8.3.2.2.2 and Technical

Specifications Surveillance Requirement 4.8.2.1.c. For the fire service system, visual

examination is performed every 18 months in accordance with a commitment in the fire

protection procedure. The applicant stated that the results of 18-month battery rack inspections

are retained in sufficient detail to permit adequate confirmation of the inspection program. In

particular these records identify inspectors, results of the inspections, note discrepancies with

the cause, and prescribe corrective action. No actions are taken as part of this program to

trend inspection or test results. The staff finds the inspection frequency and procedures for

both systems to be acceptable. The surveillance procedure provides guidance when

abnormalities are observed and the VCSNS Corrective Action Program is utilized to provide

specific corrective and confirmatory actions. 

[Acceptance Criteria] For both the ED and FS systems, the acceptance criterion is “no visual

indication of loss of material due to corrosion,” as stated in a surveillance test procedure. The

staff finds this acceptance criterion acceptable for visual inspections.

[Operating Experience] As discussed in SER Section 3.5.2.3.4, the operating experience with

respect to battery racks has been good. The staff concludes that the Battery Rack Inspection

program should be an effective program for license renewal.

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.5.2.3.5 Containment Coating Monitoring and Maintenance Program

Summary of Technical Information in the Application

The applicant’s Containment Coating Monitoring and Maintenance Program is discussed in LRA

Section B.1.15, “Containment Coating Monitoring and Maintenance Program.” The LRA credits

this monitoring and maintenance program with maintaining the integrity of the protective

coatings related to station containment, other structures, and component supports. The

applicant stated that this program is consistent with the 10 program elements of GALL AMP

XI.S8, “Protective Coating and Maintenance,” with two clarifications. The first clarification is the

applicant’s determination of the program’s acceptability since it meets the minimum scoping

requirements of the GALL report (i.e., the program is based on RG 1.54). The second

clarification is the applicant’s alternate methodology, accepted by the NRC and documented in

Section 3A of the VCSNS FSAR, for meeting the requirements of RG 1.54. 
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The following structures contain commodities/components for which this AMP is credited with

managing the aging effect of loss of material due to coating degradation: reactor buildings,

auxiliary building structures, control building, diesel generator building, fuel handling building,

intermediate building, turbine building, and yard structures (including condensate storage tank

foundation, fire service pumphouse, electrical manhole MH-2, electrical substation and

transformer area).

In addition, the applicant stated that the Containment Coating Monitoring and Maintenance

Program has demonstrated its capability to maintain the integrity of the protective coatings

inside the reactor building. The applicant discussed the operating experience with coatings in

containment and the ASME Section XI, Subsections IWE and IWL inspections conducted in

2000. These inspections are considered the baseline examination since previous inspections

had not identified any significant problems. The IWE inspection revealed several areas of

containment liner coating degradation, and documented these conditions in the site’s

nonconformance program. Most of the areas identified in the inspection were reworked per civil

maintenance procedures. Those areas not repaired were judged to be of minimal significance;

thereby not impacting performance. The applicant stated that these unrepaired areas will be

monitored by periodic walkdown inspections at each outage and by augmented IWE

inspections for any changes in condition that may suggest a loss of integrity or function. 

The LRA cited NRC Generic Safety Issue 191, “Assessment of Debris Accumulation on PWR

Sump Performance,” but stated that the degradation of the coating is an issue under the current

licensing basis and not a TLAA issue. The issue is dealt with through the response to Generic

Letter (GL) 98-04, “Potential for Degradation of the Emergency Core Cooling System and the

Containment Spray System after a Loss-of-Coolant Accident Because of Construction and

Protective Coating Deficiencies and Foreign Material in Containment.” The applicant further

states that the monitoring and maintenance of Service Level I coatings conducted in

accordance with Regulatory Guide (RG) 1.54, “Service Level I, II, and III Protective Coatings

Applied to Nuclear Power Plants,” are effective for managing degradation and therefore,

provide an effective means to manage loss of material due to corrosion of carbon steel inside

containment. In its response to GL 98-04, the applicant stated that controls for the

procurement, application, and maintenance of Service Level I protective coatings are

implemented in a manner that is consistent with its licensing basis and regulatory requirements. 

The LRA states in FSAR supplement 18.2.11 that the periodic visual walkdown inspections

under this program are conducted from accessible floors, platforms, or other permanent

vantage points. The degree of inspection depends upon accessibility, environmental and

radiological conditions, and safety. In cases of inaccessibility, sampling approaches based on

plant-specific characteristics, industry-wide experience, and testing history are evaluated in lieu

of actual visual inspections. 

Staff Evaluation

In LRA Section B.1.15, “Containment Coating Monitoring and Maintenance Program,” the

applicant describes this monitoring and maintenance program for maintaining the integrity of

the protective coatings related to station containment, other structures, and component

supports. The LRA states that this program is consistent with GALL AMP XI.S8, “Protective

Coating and Maintenance.” The applicant’s claim of consistency with the GALL report was

reviewed and verified during an AMR audit conducted on July 16 - 17, 2003. Based on the
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consistency of this program with the GALL report, the staff focused its review on the operating

history program element supporting the effectiveness of this program.

[Operating History] The FSAR supplement for this program is described in Section 18.2.11 of

Appendix A to the LRA and states that, for inaccessible areas, sampling approaches based on

plant-specific characteristics, industry-wide experience, and testing history are evaluated in lieu

of actual visual inspections. By letter dated March 28, 2003, the staff requested, in RAI B.1.15-

1, the applicant to discuss the sampling procedures used to verify that the age-related

degradation of the containment coating will be effectively managed in accordance with the

current licensing basis during the extended period of operation. In addition, the staff requested

information on Element 4, “Detection of Aging Effects,” of the program in sufficient detail to

allow an adequate assessment of this element or a justification for its inapplicability. 

In its response dated June 12, 2003, the applicant stated that there are no specific “sampling

procedures” used at VCSNS. The inspection team member(s) must select specific inaccessible

areas for a closer inspection, or determine if visible accessible areas provide any indication that

additional inspections are required in adjacent inaccessible areas. The applicant stated that

this is consistent with inspection requirements of the Appendix J General Visual Inspection

(LRA Section B.1.11), Containment ISI Program - IWE/IWL (LRA Section B.1.16) and

Maintenance Rule Structures Program (LRA Section B.1.18). The requirements in these

programs provide effective aging management of coatings under the CLB and during the

extended period of operation. Pertinent to the detection of aging effects in Element 4, VCSNS:

(a) conducts coatings inspections at a minimum frequency of each refueling outage or during

other major maintenance outages; (b) ensures inspection team personnel are qualified; (c)

conducts general visual walkthrough inspections, inspects previously designated areas, and

inspects all coating in the vicinity of sumps and screens; and (d) documents the inspection

results via condition evaluation reports or non-conformances. Appropriate personnel have

inspected containment coatings at a minimum frequency of each refueling outage. Engineering

personnel have also participated in these inspections since about 1996. QC and Engineering

personnel conducted an extensive inspection of containment coatings in 2000, as part of the

Containment ISI Program - IWE/IWL (B.1.16) and Maintenance Rule Structures Program (LRA

B.1.18). Under the provisions of these programs, inspections are made of all accessible areas

using direct line of sight from permanent vantage points. The provisions also allow for random

inspections of inaccessible areas such as behind structural attachments, cable trays and

ductwork. These inspections identified several areas with coating deficiencies (failures) in

accessible areas that were documented and/or corrected/repaired. The applicant determined

that the operating experience presented no observations of coating deficiencies in any

inaccessible areas.

The staff finds that while this AMP does not implement specific sampling procedures, it does

include appropriate provisions to inspect inaccessible areas based on plant-specific operating

history and qualified personnel. The inspections included in this program are consistent with

the inspection process requirements of 10 CFR 50 Appendix J, ASME Section XI IWE/IWL, and

the maintenance rule. In addition, the completion of a baseline coatings inspection in 2000

resulted in repaired or documented deficiencies in coatings. Coating deficiencies continue to

be tracked and inspected as part of this AMP. The staff finds that these aspects of this AMP

demonstrate its effectiveness in managing age-related degradation of the coatings. With

respect to Element 4 for this AMP, the staff finds the applicant response consistent with the

intent of the detection of aging effects program element described in the GALL report because
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qualified personnel complete the inspections periodically and document the results. Therefore,

the staff considers RAI B.1.15-1 closed. 

Based on the satisfactory resolution of RAI B.1.15-1 and the operating history discussion

provided in the LRA, the staff finds the Containment Coating Monitoring and Maintenance

Program consistent with the intent of GALL AMP XI.S8.

Section 18.2.11 of Appendix A to the LRA describes the applicant’s FSAR supplement for the

Containment Coating Monitoring and Maintenance Program. The staff reviewed the summary

description and finds that the information provided in the FSAR supplement for the aging

management of systems and components discussed above is equivalent to the information in

the GALL report, noting the two clarifications discussed above, and therefore, provides an

adequate summary of the program activities as required by 10 CFR 54.21(d). 

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d). 

3.5.2.3.6 Containment Inservice Inspection Program — IWE/IWL 

Summary of Technical Information in the Application

In LRA Section B.1.16, the applicant stated that the Containment ISI Program — IWE/IWL is

consistent with XI.S1 ASME Section XI, Subsection IWE and XI.S2 ASME Section XI,

Subsection IWL, as identified in NUREG-1801 with the following clarification:

• VCSNS uses the 1992 Edition of ASME XI with 1992 Addenda

The Containment ISI Program — IWE/IWL (B.1.16) is included in the discussion column of LRA

Table 3.5-1 and credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II for the following components in the reactor building:

 liner plate

 penetrations (mechanical and electrical)

 personnel airlock, escape airlock, and equipment hatch

 reinforced concrete — beams, columns, floor slabs, walls

The program is also credited to manage aging effects for license renewal for the bellows and

liner plate (RHR and spray system isolation valve chambers and guard pipes) in the auxiliary

building.
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Examinations for the first period of first interval were performed during RF-12 with satisfactory

results. There were no LERs based on these examinations. NCNs and/or CERs were

originated and dispositioned for the following conditions identified during these examinations:

 Containment Liner Coating Degradation (NCN) — Several areas of top coat were

identified as degraded; however, the primer coat was intact with no signs of

deterioration. The affected areas were cleaned and re-coated. Two areas of top coat

in the dome were identified with initial signs of degradation. These areas have been

identified for augmented inspections during future refueling outages.

 RHR and Spray Guard Pipe (CER) — Groundwater leakage identified at penetrations

in the auxiliary building resulted in degradation (corrosion) of guard pipes. Subsequent

evaluations determined that the guard pipe wall thickness remained acceptable. These

areas have been identified for augmented inspections during future refueling outages.

 Concrete Leaching (CER) — Concrete leaching in the tendon access gallery has been

attributed to groundwater seepage through cracks and construction joints within the

surrounding fill concrete. One specific location was also identified with a minor

corrosion buildup on the outer wall. Chemical analysis has determined that the

groundwater is not aggressive. These areas have been identified for augmented

inspections during future refueling outages.

 Moisture Barrier (CER) — Minor cracking and separation of the moisture barrier was

identified at a few locations. These areas were repaired and/or replaced.

Augmented inspections were conducted during the April 2002 refueling outage for the above

conditions. Additional CERs were originated for follow-up repair and/or replacement.

The applicant concluded that the Containment ISI Program — IWE/IWL provides reasonable

assurance that the aging effects for the containment liner, associated moisture barriers, and the

Reactor Building structure will be managed such that the components subject to AMR will

continue to perform their intended functions consistent with the CLB for the period of extended

operations.

Staff Evaluation

In LRA Section B.1.16, “Containment ISI Program - IWE/IWL,” the applicant described its AMP

to manage aging in the containment liner, associated moisture barriers, and the reactor building

structure. The LRA stated that this AMP is consistent with GALL AMPs XI.S1, “ASME Section

XI, Subsection IWE,” and XI.S2, “ASME Section XI, Subsection IWL,” with the following

clarification — VCSNS uses the 1992 Edition of ASME XI with 1992 Addenda. The staff

reviewed the clarification to determine whether the AMP, with the clarification, remains

adequate to manage the aging effects for which it is credited, and also reviewed the FSAR

supplement to determine whether it provides an adequate description of the revised program.

The staff audit on July 16–17, 2003, confirmed the applicant’s claim of consistency.

The Introduction to Appendix B, Aging Management Programs and Activities, of the LRA states

that “clarification is provided for instances where the VCSNS program does not match specific

details of a NUREG-1801 program element but is still determined to be consistent.” For this
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management program, a clarification is provided; however, it was not clear how the VCSNS

program does not match the referenced GALL AMP. In RAI 3.5-18, the staff requested the

applicant to explain what is intended by the above stated clarification to the program and

confirm that the program is completely consistent with GALL.

In response to RAI 3.5-18, the applicant stated the following:

Containment ISI Program - IWE/IWL (Application B.1.16) --- The clarification is no more than a statement that

VCSNS uses the 1992 Edition of ASME Section XI Code with 1992 Addenda. This is consistent with GALL

XI.S2 which states that the evaluations cover both the 1992 Edition with the 1992 Addenda and the 1995

Edition with the 1996 Addenda, as approved in 10 CFR 50.55a. VCSNS has not attempted to reconcile code

differences nor requested approval for later editions.

The staff finds the applicant’s response to RAI 3.5-18, to be acceptable. The use of the 1992

Edition of ASME Section XI Code with 1992 Addenda is acceptable to the staff and consistent

with GALL AMPs XI.S1, “ASME Section XI, Subsection IWE,” and XI.S2, “ASME Section XI,

Subsection IWL.”

The staff noted several inconsistencies between the FSAR supplement summary descriptions

of the AMPs in LRA Appendix A and the scope of the AMPs identified in LRA Appendix B as

“consistent with GALL.” In RAI 3.5-19, the staff requested the applicant to verify that the

complete scope of the AMP, as described in NUREG-1801, GALL Volume 2, is being credited

to manage aging effects for license renewal. If this is not the case, the applicant was requested

to identify and document the justification for each exception. In response to RAI 3.5-19, the

applicant stated the following:

As stated in the Application, VCSNS maintains an ASME Section XI - IWE/IWL Program (B.1.16), which is

consistent with GALL XI.S1, XI.S2, and 10 CFR 50.55a. 

VCSNS does not believe that there are any further changes required for the Application Appendix A, since only

summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory Guides

are implicit in the development of each of these programs as described in Section 7 of TR00170-003.

Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the exceptions to the

GALL program and finds 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

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.5.2.3.7 Flood Barrier Inspection Program 

Summary of Technical Information in the Application

In LRA Section B.1.17, the applicant stated that the Flood Barrier Inspection Program is a plant

specific program that is not addressed in GALL. The applicant further stated that the VCSNS

Flood Barrier Inspection Program is identified for completeness since it contains individual
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components that have the unique function of mitigating the effects of internal flooding. All flood

barrier components are managed by either the Fire Protection Program or Maintenance Rule

Structures Program.

The Flood Barrier Inspection Program is included in the discussion column of LRA Table 3.5-2,

but is not credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II.

No LERs, NCNs or CERs were initiated for flood barriers (walls, curbs, equipment pedestals),

flood doors, and flood barrier penetration seals relevant to aging.

The applicant concluded that the Flood Barrier Inspection Program provides reasonable

assurance that the aging effects for flood barrier components will be managed such that the

components subject to AMR will continue to perform their intended functions consistent with the

CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.17, “Flood Barrier Inspection,” the applicant described its AMP to manage

aging in flood barrier components. This AMP is not addressed in GALL. Therefore, the staff

reviewed this AMP against the 10 program elements using the guidance in BTP RLSB-1 in

Appendix A of the SRP-LR. The staff also reviewed the FSAR supplement to determine

whether it provides an adequate description of the program.

In the introduction to LRA Appendix B, the applicant stated that the VCSNS Quality Assurance

Program implements the requirements of 10 CFR Part 50, Appendix B, and is consistent with

the summary in Section A.2 of NUREG-1800, “Standard Review Plan for Review of License

Renewal.” The applicant further stated that VCSNS will employ the corrective action and

document control programs to address the program elements of corrective action, confirmation

process, and administrative (document) controls for both safety-related and non-safety-related

SCs that require aging management during the period of extended operation. The staff’s

evaluation of the applicant’s Quality Assurance Program is discussed separately, and

generically evaluated in Section 3.0.4 of this SER. Thus, these three elements are not

discussed further in this section. The staff’s evaluation of the remaining seven elements is

discussed below.

[Program Scope] In LRA Section B.1.17, the applicant stated that nuclear safety-related flood

barriers are credited with mitigating the effects of internal flood. Nuclear safety-related flood

barriers include curbs at entrances to cubicles housing safety grade equipment as stated in

FSAR Section 6.3.2.2.7. Designated flood doors (watertight doors) are identified in plant

specifications and are listed on architectural drawings. Ten doors are designated as flood

doors (watertight doors). Penetrations requiring nuclear safety-related flood seals are specified

in design basis documents. Penetrations requiring nuclear safety-related flood seals are shown

on engineering drawings for the intermediate building, the control building, and the diesel

generator building. Eleven penetrations require nuclear safety related flood seals.

As a result of its review, the staff found that the Flood Barrier Inspection Program described in

LRA Section B.1.17 is included in the discussion column of LRA Table 3.5-2, but is not credited

to manage aging effects for license renewal in Report TR00170-003, Revision 0, Attachment II: 
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Aging Management Review Results for Structures and Structural Components. In RAI 3.5-22,

the staff requested that the applicant provide additional information on the scope of the

program. In response to RAI 3.5-22, the applicant stated the following:

(a) As noted in Application Section B.1.17, “The VCSNS Flood Barrier Inspection Program is identified for

completeness since it contains individual components that have the unique [sole] function of mitigating the

effects of internal flooding. All flood barrier components are managed by either the Fire Protection Program

or Maintenance Rule Structures Program.” Component types include: concrete curbs, designated water-tight

doors, and designated penetration seals. Flood barriers are located throughout the plant. See detailed

discussion on flood barriers in Section 7.11 of TR00170-003.

(b) There are currently no plant procedures written specifically for inspection of flood barriers. This program

was added for license renewal to specifically capture those elements that only serve a flood protection

function. There are many fire barriers (structures, doors, seals, etc.) that also serve as flood barriers and many

structural components that serve as flood barriers, all of which are covered by the Fire Protection Program and

Maintenance Rule Structures Program. Plant procedures for the Maintenance Rule Structures Program

(B.1.18) will be enhanced to include inspections for flood barrier seals in the Control, Intermediate, and Diesel

Generator Buildings in order to capture all flood barriers within the plant.

(c) Section 7.11 of TR00170-003 agrees with the Application that there are flood seals in the Intermediate

Building (IB). However, Attachment II (IB) of TR00170-003 and Application Table 2.4-7 (IB) do not list flood

barriers (similar to the CB and DGB). The VCSNS Drains/Sumps DBD (Section 3.8.5.4) identifies one (1) flood

barrier at the IB / TB interface. Therefore, flood barriers will be added as a line item to Attachment II (IB) of

TR00170-003.

Based on the additional information provided by the applicant, the staff finds the scope of the

program to be acceptable since it identifies the specific structural components for which the

program is credited for license renewal. The applicant also defined the relationship of this

program to the Fire Protection Program and the Maintenance Rule Structures Program and

committed to changes to the programs that are acceptable to the staff. 

[Preventive Actions] The applicant identified the Flood Barrier Inspection Program as a

condition monitoring program. As such, there are no preventive actions, nor did the staff

identify a need for such actions.

[Parameters Monitored or Inspected] The applicant stated that aging effects for flood barriers

are cracks, exposed reinforcing steel, corrosion, scaling, popouts, surface pitting, and spalling.

The applicant further stated that the aging effects for flood barrier penetration seals are similar

to aging effects for fire barrier penetration seals and include cracking, fraying, separation from

penetration, and through-wall holes. The staff finds the parameters monitored to be acceptable

since they are consistent with the potential aging effects that would be associated with the

structural components within the scope of the program. 

[Detection of Aging Effects] The applicant stated that the Flood Barrier Inspection Program

detects aging effects prior to loss of intended function. The staff considers the applicant’s

approach to the detection of aging effects to be acceptable since it is aimed at detecting aging

effects before there is a loss of intended function. 

[Monitoring and Trending] The applicant stated in LRA Section B.1.17 that visual examination

of nuclear safety related flood barrier penetration seals that are also fire barrier penetration

seals is performed once every 18 months as stated in surveillance test procedures. In

response to RAI 3.5-22, the applicant provided the following additional information regarding

the frequency of inspection of flood barriers:
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Flood barriers, which are not covered by the Fire Protection Program, are reviewed as part of the Maintenance

Rule Structures Program which is conducted on a 5-year frequency.

The staff finds the inspection frequency and procedures for the program to be acceptable. 

[Acceptance Criteria] The applicant stated that flood barrier and flood barrier penetration seal

examination acceptance criteria are provided in an engineering services procedure for flood

barriers that are not fire barriers. Acceptance criteria are no cracks, no exposed reinforcing

steel, no corrosion, no scaling, no popouts, no surface pitting, and no spalling. Flood barrier

penetration seal examination acceptance criteria are the same as for fire barrier penetration

seals and are provided in a technical requirements package. Acceptance criteria are provided

for indication of cracking, separation between surfaces at penetration, and no through-wall

holes. The staff finds the acceptance criteria acceptable for visual inspection.

[Operating Experience] As discussed in SER Section 3.5.2.3.7, the operating experience with

respect to flood barriers has been good. The staff concludes that the Flood Barrier Inspection

Program should be an effective program for license renewal.

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.5.2.3.8 Pressure Door Inspection Program

Summary of Technical Information in the Application

In LRA Section B.1.20, the applicant stated that the Pressure Door Inspection Program is a

plant-specific program that is not addressed in GALL. The applicant further stated that

pressure doors at VCSNS are used to separate critical equipment from high energy pipe

breaks, and are designed, procured, and installed to specific specifications.

The Pressure Door Inspection Program is included in the discussion column of LRA Table 3.5-

2, but is not credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II.

VCSNS has no failures or adverse trends for nuclear safety related or quality-related pressure

doors. An occurrence of steam propagation into sensitive rooms through fire doors was

identified. One door was replaced with a quality-related pressure resistant fire door, while a

quality-related pressure resistant door was added at another location. No NCNs or CERs were

initiated for pressure doors relevant to aging.

The applicant concluded that the Pressure Door Inspection Program provides reasonable

assurance that the aging effects for pressure doors will be managed such that the components
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subject to AMR will continue to perform their intended functions consistent with the CLB for the

period of extended operations.

Staff Evaluation

In LRA Section B.1.20, “Pressure Door Inspection Program,” the applicant described its AMP to

manage aging in pressure doors. This AMP is not addressed in GALL. Therefore, the staff

reviewed this AMP against the 10 program elements using the guidance in BTP RLSB-1 in

Appendix A to the SRP-LR. The staff also reviewed the FSAR supplement to determine

whether it provides an adequate description of the program.

In the introduction to LRA Appendix B, the applicant stated that the VCSNS Quality Assurance

Program implements the requirements of 10 CFR Part 50, Appendix B, and is consistent with

the summary in Section A.2 of NUREG-1800, “Standard Review Plan for Review of License

Renewal.” The applicant further stated that VCSNS will employ the Corrective Action and

Document Control Programs to address the program elements of corrective action, confirmation

process, and administrative (document) controls for both safety-related and non-safety-related

SCs that require aging management during the period of extended operation. The staff’s

evaluation of the applicant’s Quality Assurance Program is discussed separately, and

generically evaluated in Section 3.0.4 of this SER. Thus, these three elements are not

discussed further in this section. The staff’s evaluation of the remaining seven elements is

discussed below.

[Program Scope] The applicant stated in LRA Section B.1.20 that the need to maintain

pressure barriers (which also serve as fire barriers) is required by VCSNS technical

specification 4.7.6.e.3. There are 34 doors that are nuclear safety-related pressure resistant

doors. Thirteen doors are quality-related pressure doors. There are 47 doors that are rated as

pressure resistant.

As a result of its review, the staff found that the Pressure Door Inspection Program described in

LRA Section B.1.20 is included in the discussion column of LRA Table 3.5-2, but is not credited

to manage aging effects for license renewal in Report TR00170-003, Revision 0, Attachment II: 

Aging Management Review Results for Structures and Structural Components. In RAI 3.5-24,

the staff requested that the applicant provide additional information on the scope of this

program.

In response to RAI 3.5-24, the applicant stated the following:

(a) Pressure and Fire doors are located throughout the plant. Pressure doors, which also serve as Fire doors,

are inspected under the Fire Protection Program. Pressure doors which only serve a pressure function are

inspected under plant maintenance procedures for quality related pressure barrier / components. See

discussion in Section 7.14 of TR00170-003.

(b) Attachment II of TR00170-003 lists component types: “Flood, Pressure and Specialty Doors”, all of which

are in general inspected under the Maintenance Rule Structures Program. The RAI observation is correct that

either the Fire Protection Program or the Pressure Door Inspection Program (both of which will be added to

Attachment II of TR00170-003) inspects pressure doors in detail.
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Based on the additional information provided by the applicant, the staff finds the scope of the

program to be acceptable since it identifies the specific structural components for which the

program is credited for license renewal. 

[Preventive Actions] The applicant identified the Pressure Door Inspection Program as a

condition monitoring program. As such, there are no preventive actions, nor did the staff

identify a need for such actions.

[Parameters Monitored or Inspected] In LRA Section B.1.20, the applicant stated that

parameters monitored for pressure doors are loss of material of doors and door hardware. The

applicant also stated that excessive wear for door appurtenances, such as latches, gaskets,

hinges, sills, and closing devices, are additional attributes in the technical requirements

package, but are not credited for license renewal. However, LRA Appendix A, Section 18.2.24

states that pressure door inspection attributes include freedom of movement, function (closed

during normal plant operation), structural deterioration, and loss of door/door hardware

material.” In RAI 3.5-24, the staff requested that these inconsistencies be clarified.

In response to RAI 3.5-24, the applicant stated the following:

Application Section B.1.20 provides more explicit details related to inspection criteria (including excessive wear

of door appurtenances), while Appendix A Section 18.2.24 provides only a very generic description of the

program. The summary provided in Appendix A should not be interpreted as eliminating wear from inspections.

Consistent with NEI 95-10, VCSNS does not see the need to make these two sections read the same.

As a result of discussions with the applicant regarding the above response, the applicant

provided the following supplemental response to RAI 3.5-24 Part (c):

RAI 3.5-24(c) – The NRC Staff questioned the intent of statements made in Application Section B.1.20 under

“Parameters Monitored or Inspected” relative to “excessive wear” being credited for license renewal.

1) Excessive wear for door appurtenances (such as latches, gaskets, hinges, sills, and closing

devices) is an inspection attribute which is inherent within the VCSNS procedures. These hardware

components are included within the plant inspection procedures for fit, contact, closure and clearance,

which inherently provides acceptance relative to wear.

2) The statement [“but are not credited for license renewal”] at the end of Application Section B.1.20

(Parameters Monitored or Inspected) was originally intended to imply that loss of material due to wear

is not considered as an aging effect, but rather a consequence of frequent or rough use. Regardless,

as noted in 1) above, excessive wear is an inspection attribute inherently included within plant

inspection procedures.

The applicant’s supplemental response clarifies that inspection of door appurtenances for

excessive wear will be conducted during the period of extended operation. The staff finds this

to be acceptable.

 

[Detection of Aging Effects] The applicant stated that the pressure door inspection program

detects structural damage or degradation, including loss of material due to corrosion prior to

loss of intended function. The staff considers the applicant’s approach to the detection of aging

effects to be acceptable since it is aimed at detecting aging effects before there is a loss of

intended function. 
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[Monitoring and Trending] The applicant stated that aging effects for quality-related pressure

doors are detected by a visual examination of the door and frame and functional testing for

closure. Aging effects for nuclear safety related pressure doors are detected by visual

examination. No actions are taken as part of this program to trend inspections or test results.

The applicant further stated that the frequency of inspections performed since the

implementation of the technical specifications requirements in 1984 is acceptable based on

industry operating experience. A review of pressure door inspections confirms the

reasonableness and acceptability of this inspection frequency such that any degradation of a

door is detected prior to loss of function.

In response to RAI 3.5-24, the applicant provided the following information regarding the

frequency of inspection for pressure doors:

Pressure doors, which serve as Fire doors are inspected every 6 months, while Pressure doors, which only

serve a pressure function, are inspected every 18 months.

The staff finds the inspection frequency and procedures for pressure doors to be acceptable. If

the results of the visual inspection indicate that repairs are required, then specific repairs are

made in accordance with plant procedures. The pressure door inspections are implemented by

plant procedures and controlled by the SCE&G Quality Assurance Program.

[Acceptance Criteria] The applicant stated that quality-related pressure door acceptance

criteria is provided in technical requirement packages. Nuclear safety-related pressure door

acceptance criteria is provided in surveillance test procedures. Acceptance criteria for selfclosing doors are that hinges are intact with all screws tight, pins in good condition, and the

door closes. Acceptance criteria for double self-closing doors are that bolts are in good

condition, the astragal (metal molding strip) is in good condition, and the door closes. 

Automatic-closing doors are checked to be in good operating condition and the door closes. 

Acceptance criteria for hollow pressure doors are no holes and no damage in the skin of the

door or the frame. The staff finds the acceptance criteria to be acceptable.

[Operating Experience] As discussed in SER Section 3.5.2.3.8, the operating experience with

respect to pressure doors has been good. The staff concludes that the Pressure Door

Inspection Program should be an effective program for license renewal.

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.5.2.3.9 Service Water Pond Dam Inspection Program 

Summary of Technical Information in the Application
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In LRA Section B.1.21, the applicant stated that the Service Water Pond Dam Inspection

Program is consistent with XI.S7, RG 1.127 Inspection of Water-Control Structures Associated

With Nuclear Power Plants, as identified in NUREG-1801. The applicant further stated that 

certain enhancements will be incorporated into the Service Water Pond Dam Inspection

Program prior to the period of extended operation. In particular, North Dam piezometers will be

added to the scope with the following program attributes:

• [Parameters Monitored or Inspected] — water level

• [Monitoring and Trending] — inspections will be made every 5 years concurrent with

the RG 1.127 inspections

• [Acceptance Criteria] — nominal elevation of adjacent service water pond and

Monticello Reservoir

The Service Water Pond Inspection Program is included in the discussion column of LRA Table

3.5-2 and credited to manage aging effects for license renewal in Report TR00170-003,

Revision 0, Attachment II for the service water pond dams (North Dam, South Dam, East Dam,

and West Embankment).

During each inspection of the service water pond dams and West Embankment, a review of the

previous inspection's observations/recommendations is performed and the current status (such

as repairs implemented or continued monitoring) is documented. Previous abutment erosion

control modifications completed in 1989 significantly reduced earlier erosion problems overall,

as noted by inspections performed in 1990 and 1995. Additional grading of diversion

trenches/berms to direct rainwater away from the dams has further controlled erosion. There

are currently no erosion areas that have a direct impact on any of the earthen structures.

Weed, brush, and sapling growth are controlled via cutting or spraying of herbicides conducted

in accordance with plant procedures.

Structural calculations document the results of the survey monitoring data for the North and 

South Dam, and West Embankment. The calculations provide a review of the vertical and

horizontal displacements of the service water pond North Dam and South Dam since 1977. 

The calculations also provide a review of the vertical displacement of the West Embankment

since 1978 and the horizontal displacement of the West Embankment since 1983. For the

2000 survey, all vertical and horizontal displacements were within the acceptance criteria as

compared to the previous survey and found to be acceptable. Structural calculations also

provide a review of the slope survey of the West Embankment since 1983. For the 2000

survey, all of the measurements were within the acceptance criteria as compared to the

previous survey and found to be acceptable. No further evaluations were required and no

unusual trends were noted.

In addition to the 5-year inspection of the service water pond dams required by the NRC,

Federal Energy Regulatory Commission (FERC) conducted inspections of the service water

pond dams in February 1997, July 1999, and July 2001. The conclusions reached by these

inspections were that no significant conditions were observed that were considered detrimental

to the safety of the dams. The 1997 FERC dam safety inspection report recommended that

SCE&G visually inspect the Service Water Pond Dams and West Embankment annually and

test the accessible piezometers. The annual visual inspection is scheduled for the fall of each
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year. The first annual visual inspection and testing of the accessible piezometers was

conducted in November 1999. Three accessible piezometers located along the crest of the

North Dam were tested and found to be functional with acceptable results.

The applicant concluded that the Service Water Pond Dam Inspection Program has been

demonstrated to be capable of detecting and managing trends in movement and the effects of

aging for the service water dams. The applicant further concluded that the Service Water Pond

Dam Inspection Program provides reasonable assurance that the aging effects will be managed

such that the components subject to AMR will continue to perform their intended functions

consistent with the CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.21, “Service Water Pond Inspection Program,” the applicant described its

AMP to manage trends in movement and the effects of aging for the service water dams. The

LRA stated that this AMP is consistent with GALL AMP XI.S7, “RG 1.127 Inspection of WaterControl Structures Associated With Nuclear Power Plants,” with several enhancements

described in Section 3.5.2.3.9. The staff confirmed the applicant’s claim of consistency during

the AMR inspection. Furthermore, the staff reviewed the enhancements to determine whether

the AMP, with the enhancements, remains adequate to manage the aging effects for which it is

credited, and reviewed the FSAR supplement to determine whether it provides an adequate

description of the revised program. 

The staff noted several inconsistencies between the FSAR supplement summary descriptions

of the AMPs in LRA Appendix A and the scope of the AMPs identified in LRA Appendix B as

“consistent with GALL.” In RAI 3.5-19, the staff requested the applicant to verify that the

complete scope of the AMP, as described in NUREG-1801, GALL Volume 2, is being credited

to manage aging effects for license renewal. If this is not the case, the applicant was requested

to identify and document the justification for each exception. In response to RAI 3.5-19, the

applicant stated the following:

As stated in the Application, VCSNS maintains a Service Water Pond Dam Inspection Program (B.1.21), which

is consistent with GALL XI.S7 and RG 1.127. One enhancement to this program was identified during a

NRC/FERC inspection as identified in the Application and discussed in Section 7.15 of TR00170-003.

VCSNS does not believe that there are any further changes required for the Application Appendix A, since only

summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory Guides

are implicit in the development of each of these programs as described in Section 7 of TR00170-003.

LRA Section B.1.21 states that the Service Water Pond Dam Inspection Program is consistent

with GALL XI.S7 with several listed enhancements that will be incorporated into the program

prior to the period of extended operation. In RAI 3.5-25, the staff requested that the applicant

provide the following information regarding this program:

1. The commitment to incorporate the enhancements to this program discussed in LRA

Section B.1.21 should also be included in the FSAR supplement, Appendix A, Section

18.2.31. This section does not currently include such a commitment. Issues related to

the FSAR supplement are being addressed by the staff on a generic basis.
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2. The discussion in LRA Section B.1.21.1 on operating experience does not include the

East Dam. Please provide a discussion on the operating experience for the East Dam.

In response to RAI 3.5-25, the applicant stated the following:

(a) Consistent with NEI 95-10, VCSNS does not see the need to include these minor enhancements into the

very generic summary description of the Service Water Pond Dam Inspection Program (Application Section

18.2.31).

(b) The East Dam of the Service Water Pond (SWP) is the smallest and least critical (important) of the four

SWP dams since it primarily caps a natural high elevation ridge line along the east side of the pond. There

are no piezometers or alignment/survey monuments for this structure. The East Dam is inspected as part of

the Service Water Pond Dam Inspection Program. There are no operating experience issues associated with

this dam other than normal observations of minor erosion and weed growth at the edges of the riprap

protection.

The staff finds the applicant’s discussion on operating experience for the East Dam to be

acceptable. 

Conclusions

On the basis of its review and audit of the applicants program, the staff finds that those portions

of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. In addition, the staff has reviewed the enhancements to the

GALL program and finds 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

during the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also

reviewed the FSAR supplement for this AMP and finds that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.5.2.3.10 Service Water Structures Survey Monitoring Program

Summary of Technical Information in the Application

In LRA Section B.1.22, the applicant stated that the Service Water Structures Survey

Monitoring Program is a plant specific program that is not addressed in GALL. The applicant

further stated that survey monitoring is required for structures that are supported by earthen fill

material and that have exhibited the potential for settlement. Settlement is not considered

adverse unless it imposes stresses on structures that may exceed their design capacities. Initial

settlement of the service water pump house (SWPH) and the service water intake structure

(SWIS) was much more than the original preconstruction estimates. As a result, survey

monitoring of the SWPH, SWIS, electrical duct banks, and service water intake line “A” is

conducted to monitor any differential in vertical and horizontal displacement. This monitoring is

conducted to satisfy the requirements specified by operating license condition 2.C.5 and FSAR

Section 2.5.4.10.6.2.

The Service Water Structures Survey Monitoring Program is included in the discussion column

of LRA Table 3.5-2 and credited to manage aging effects for license renewal in Report

TR00170-003, Revision 0, Attachment II for the foundations and intake bays or canals for the

SWPH, SWIS, electrical duct banks, and service water intake line “A.”
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Initial settlement of the SWPH and SWIS was much more than the original preconstruction

estimates. The degree and manner of settlement caused cracking to occur in the SWIS, which

was subsequently repaired (grouted). A special settlement study was performed for the SWPH

and SWIS. There has been no significant settlement of the SWPH or SWIS since December

1978, subsequent to filling the service water pond in February 1978.

Since 1991, there have been two instances where movement of the SWPH exceeded the

acceptance criteria. The first instance was in February 1991; a resurvey was conducted in

March 1991 and it was determined that the initial survey data was in error. In the second

instance (July 1994), the acceptance criterion was minimally exceeded. Considering survey

process inaccuracy and seasonal fluctuations affecting data collection, the total differential was

not considered significant enough to warrant further evaluation. Survey results from 1977 to

the present are documented in structural calculations.

Survey monitoring for differential settlement (middle to ends) of the SWIS has been conducted

since February 1985. Between the July 1985 survey and February 1986 survey of the SWIS

there was a sudden increase in the recorded differential displacement for which no ready

explanation could be found. As a result of this sudden change, the survey monitoring

frequency was increased to monthly for a period of 8 months and the results showed the

differential movement remained steady. Consequently, the frequency of monitoring was

returned back to semiannually. No further significant increase in differential movement has

been recorded since February 1986 and the total settlement to date is within the acceptance

limit.

No significant differential settlement was expected between the SWPH and incoming buried

services, as these were intentionally laid and connected to the SWPH after the major initial

settlement during construction, and the effects of filling the service water pond in February 1978

had ceased. However, semiannual survey data are recorded and evaluated.

Settlement of the electrical duct banks is measured from inside the SWPH where the duct

banks terminate on the inside face of the west wall of the SWPH. Historically, gap

measurements have not undergone any significant changes since monitoring began, with any

differential measurements well within the established acceptance criteria. Survey results are

documented in structural calculations.

Service water intake line “A” settlement has been monitored since January 1983. Since then

there has been no appreciable movement or trend based on data reviews. However, there

have been three occasions, one each in 1996, 1999, and 2000, when the acceptance criteria

was minimally exceeded. These conditions are considered acceptable since the overall

measurements remain within the general bounds of the long-term trend of data. The applicant

states that these minor fluctuations may well be attributed to survey process imprecision,

seasonal changes between summer and winter surveys, or groundwater fluctuations. Survey

results are documented in structural calculations.

The applicant concluded that the Service Water Structures Survey Monitoring Program has

been demonstrated to be capable of detecting and managing trends in movement associated

with settlement of the service water structures. The applicant further concluded that the

Service Water Structures Survey Monitoring Program provides reasonable assurance that the
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aging effects will be managed such that the components subject to AMR will continue to

perform their intended functions consistent with the CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.22, “Service Water Structures Survey Monitoring Program,” the applicant

described its AMP to manage trends in movement associated with settlement of service water

structures. This AMP is not addressed in GALL. Therefore, the staff reviewed this AMP

against the 10 program elements using the guidance in BTP RLSB-1 in Appendix A to the SRPLR. The staff also reviewed the FSAR supplement to determine whether it provides an

adequate description of the program.

In the introduction to LRA Appendix B, the applicant stated that the VCSNS Quality Assurance

Program implements the requirements of 10 CFR Part 50, Appendix B, and is consistent with

the summary in Section A.2 of NUREG-1800, “Standard Review Plan for Review of License

Renewal.” The applicant further stated that VCSNS will employ the corrective action and

document control programs to address the program elements of corrective action, confirmation

process, and administrative (document) controls for both safety-related and non-safety-related

SCs that require aging management during the period of extended operation. The staff’s

evaluation of the applicant’s Quality Assurance Program is discussed separately, and

generically evaluated in Section 3.0.4 of this SER. Thus, these three elements are not

discussed further in this section. The staff’s evaluation of the remaining seven elements is

discussed below.

[Program Scope] The scope of the program includes survey monitoring of the SWPH, SWIS,

electrical duct banks, and service water intake line “A” in accordance with plant procedures. 

The staff finds the scope of the program to be acceptable since it identifies the specific

structures and structural components for which the program is credited for license renewal.

[Preventive Actions] The applicant identified the survey monitoring of the SWPH, SWIS,

electrical duct banks, and service water intake line “A” as a condition monitoring program. As

such, there are no preventive actions, nor did the staff identify a need for such actions.

[Parameters Monitored or Inspected] The applicant stated that survey monitoring is conducted

to detect any vertical and/or horizontal movement associated with settlement of the SWPH,

SWIS, electrical duct banks, and service water intake line “A”. The survey monitoring data are

reviewed by design engineering to ensure that settlements remain within established criteria. In

addition to survey monitoring, the structures are visually inspected in accordance with

engineering services procedures for the following:

• SWPH movement, alignment or sloughing, cracking, settlement, and structural

degradation,

• SWIS cracking (per underwater diver’s inspection),

• service water electrical duct bank differential movement and integrity of the expansion

joint material,
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• ground above service water intake line “A” is inspected for settlement, sloughing,

surface cracking, and erosion

The staff finds that the parameters monitored are acceptable and consistent with what would be

expected for a settlement monitoring program.

[Detection of Aging Effects] The applicant stated that attributes associated with aging for the

SWPH, SWIS, electrical duct banks, and service water intake line “A” are detected by the

survey monitoring. The survey results are reviewed and evaluated for trends in movement

associated with settlement that exceeds the acceptance criteria. This review, and the visual

inspection of the structures, will detect any adverse horizontal or vertical displacements prior to

the loss of structure intended functions. The staff finds the applicant’s approach to detection of

settlement effects to be acceptable since it is aimed at detecting such effects before there is a

loss of function. 

[Monitoring and Trending] Aging effects associated with settlement for the SWPH, SWIS,

electrical duct banks, and service water intake line “A” are detected by survey monitoring in

accordance with CLB requirements. Survey monitoring data are retained in sufficient detail to

permit adequate confirmation of the inspection program. The survey data reports and

reviews/evaluations are filed in structural calculations. In particular these records identify the

person(s) performing the survey, the structure/component and points surveyed, the person(s)

reviewing/evaluating the survey data, whether or not the results are acceptable, discrepancies

and their causes, and any corrective action(s) taken as a result. Trending is accomplished by

comparing the current survey data to the previous survey data and evaluating for trends in

movement that exceed the acceptance criteria. The staff finds the applicant’s approach

acceptable since it will continue to be in accordance with CLB requirements that have proven to

be acceptable as evidenced by plant operating experience, as discussed in SER Section

3.5.2.3.10.

[Acceptance Criteria] The acceptance criteria and guidelines for reviewing the survey

settlement data for the SWPH, SWIS, electrical duct banks, and service water intake line “A”

are specified in design engineering guidelines. Survey results are evaluated for adverse trends

in vertical displacement. The measurements are compared to the previous survey results and

to acceptance criteria defined in engineering guidelines. The SWIS is also monitored for

differential displacement between the middle and ends of the tunnel. If the acceptance criterion

for the differential displacement is reached or exceeded, further engineering evaluations are

required. The staff did not identify any need to modify the current acceptance criteria which are

based on current CLB requirements.

[Operating Experience] As discussed in SER Section 3.5.2.3.10, operating experience has

demonstrated that the Service Water Structures Survey Monitoring Program has been effective

in monitoring the potential for settlement of service water structures. The staff concludes that

this program should continue to be an effective program for license renewal.

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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
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required by 10 CFR 54.21(a)(3). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.5.2.3.11 Underwater Inspection Program (SWIS and SWPH) 

Summary of Technical Information in the Application

In LRA Section B.1.23, the applicant stated that the Underwater Inspection Program (SWIS and

SWPH) is a plant-specific program that is not addressed in GALL.

The Underwater Inspection Program (SWIS and SWPH) is included in the discussion column of

LRA Table 3.5-2 and credited to manage aging effects for license renewal in Report TR00170-

003, Revision 0, Attachment II for the following components of the SWIS and SWPH:

 intake bays or canals

 intake screens

 reinforced concrete — beams, columns, floor slabs, walls

VCSNS operating license condition 2.C.5.d requires SCE&G to perform an inspection of the

SWIS every 5 years to monitor and measure the cracks in the reinforced concrete tunnel, 

which originated due to settlement problems during construction.

Cracks in the SWIS (tunnel), which were identified during construction, were grouted with a

high strength epoxy grout in 1978 prior to filling the service water pond. Underwater

inspections were initiated in 1983 and have been performed every 5 years. The inspections of

1983 and 1988 identified very little change in the existing grouted and ungrouted cracks, along

with a few new hairline cracks. An improved method of marking old cracks was implemented

during 1988, with additional improvements made during the 1993 inspection, which allows

better distinction of old versus new ungrouted cracks.

The 1993 inspection also identified nine existing cracks that had widened and four cracks with a

maximum width greater than the minimum criteria. These cracks were evaluated and

documented in a structural calculation. The cracks were grouted in 1994 with a flexible

urethane grout in order to eliminate/reduce the potential for corrosion of the reinforcing steel.

No new cracks were identified during the 1998 inspection and all cracks that had any visible

gap were measured to be less than the minimum criteria. The 1998 inspection data for each

crack was compared to the results of the 1993 inspection to ensure consistency and no

significant differences were noted between the two inspection reports.

After filling the service water pond, visual inspection and cleaning of the SWIS and SWPH was

performed once each refueling cycle within the preventive maintenance program. In response

to GL 89-13, a new engineering procedure was developed to direct the SWIS and SWPH

inspections. A review of the inspection data for the past 5 years shows that no corrosion has

been discovered on the trash racks, foot section of each traveling screen, endbell of each

service water pump, and/or other submerged structural components. The location and density

of fouling accumulations (e.g., silt and clams) is recorded and subsequently removed by divers

using an eductor.
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The applicant concluded that the Underwater Inspection Program (SWIS and SWPH) has been

demonstrated to be capable of detecting and managing the effects of aging for concrete

components in fluid environments. The applicant further concluded that the Underwater

Inspection Program of the SWIS and SWPH provides reasonable assurance that the aging

effects will be managed such that the components subject to AMR will continue to perform their

intended functions consistent with the CLB for the period of extended operations.

Staff Evaluation

In LRA Section B.1.23, “Underwater Inspection Program (SWIS and SWPH),” the applicant

described its AMP to manage aging for concrete and steel components in fluid environments. 

This AMP is not addressed in GALL. Therefore, the staff reviewed this AMP against the 10

program elements using the guidance in BTP RLSB-1 in Appendix A to the SRP-LR. The staff

also reviewed the FSAR supplement to determine whether it provides an adequate description

of the program.

In the introduction to LRA Appendix B, the applicant stated that the VCSNS Quality Assurance

Program implements the requirements of 10 CFR Part 50, Appendix B, and is consistent with

the summary in Section A.2 of NUREG-1800, “Standard Review Plan for Review of License

Renewal.” The applicant further stated that VCSNS will employ the corrective action and

document control programs to address the program elements of corrective action, confirmation

process, and administrative (document) controls for both safety-related and non-safety-related

SCS that require aging management during the period of extended operation. The staff’s

evaluation of the applicant’s Quality Assurance Program is discussed separately, and

generically evaluated in Section 3.0.4 of this SER. Thus, these three elements are not

discussed further in this section. The staff’s evaluation of the remaining seven elements is

discussed below.

[Program Scope] The scope of the SWIS underwater inspection, conducted in accordance with

engineering services procedures, includes visual inspection of the interior length of the intake

tunnel, survey monitoring masts, trash racks, access ladder, and east end wing walls. The

scope of the SWPH underwater inspection, conducted in accordance with engineering services

procedures, includes a visual inspection of the intake tunnel, traveling screens/bays, and

service water pump bays. In response to RAI 3.5-26 parts (a) and (b), the applicant provided

the following additional information regarding the scope of the program:

(a) For the Service Water Pumphouse (SWPH) and Intake Structure (SWIS) at VCSNS, the primary

inspections for aging management are the Underwater Inspection Program (B.1.23) and the Maintenance Rule

Structures Program (B.1.18). These two programs provide a very detailed review and documentation of these

structures. The Service Water Pond Dam Inspection Program (B.1.21) also incorporates walkdowns of the

SWPH (at different frequencies) using the attributes of GALL XI.S7. Use of a statement that B.1.21 is

supplementary does not imply that program attributes have been omitted.

(b) The program attributes discussed in Application Section B.1.23 are primarily focused on the SWIS since

explicit inspection criteria have been incorporated as part of the CLB Operating License conditions for VCSNS.

Detailed Engineering Services inspection procedures and acceptance criteria have also been developed. The

diver’s inspection of the SWPH (controlled by Plant Support procedures) serves primarily as a maintenance

clean-up of the pump bays and screens, with instructions to look for any signs of degradation. 

The staff finds the scope of the program to be acceptable since it identifies the specific

structures and structural components for which the program is credited for license renewal. 
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The applicant’s response resolves the staff’s concern as to whether the Underwater Inspection

Program incorporates the attributes described in GALL XI.S7. The use of the Service Water

Pond Dam Inspection Program for supplementary review is acceptable since the applicant’s

response confirms that no attributes of GALL XI.S7 have been omitted. 

[Preventive Actions] The applicant identified the Underwater Inspection Program (SWIS and

SWPH) as a condition monitoring program. As such, there are no preventive actions, nor did

the staff identify a need for such actions.

[Parameters Monitored or Inspected] Guidelines for the underwater inspection of the SWIS and

SWPH are specified in engineering services procedures. The main reason for inspecting the

SWIS is to measure/monitor cracks (old and new) in the concrete structure that originated due

to earlier settlement. Additionally, a general inspection of the structure is made to document

the as-found condition, noting any unusual observations. The specific areas that are inspected

(and for which the condition is documented) are the access ladder, trash racks, survey

monitoring masts, and concrete wing walls at the intake end of the SWIS. Underwater

inspections of the SWIS and SWPH monitor corrosion and fouling within the service water

system. The SWIS and the SWPH forebay area, traveling screen bays, and service water

pump bays are inspected for fouling (clam and silt) accumulations. The density of the

accumulation is documented and subsequently removed. The submerged trash racks, traveling

screen components, service water pump components, and other structural components are

inspected for corrosion. Any corrosion observed is documented in the inspection report. The

staff finds the description of the parameters monitored to be acceptable and appropriate for an

underwater monitoring program.

[Detection of Aging Effects] The applicant stated that attributes associated with aging for the

SWIS and SWPH are detected by the underwater inspections. Additionally, survey monitoring

of the SWIS and SWPH will detect any horizontal or vertical movement associated with

settlement. In response to RAI 3.5-26 parts (c) and (e), the applicant provided the following

additional information regarding the detection of aging effects:

(c) The VCSNS procedures for inspection of the SWIS are focused on cracking within the concrete tunnel.

Divers are also instructed to look for any structural damage such as concrete spalls or pieces on the floor.

These are the primary “attributes associated with aging” which can be identified via diver inspections. The

divers recover all trash/debris in the tunnel such that if concrete pieces were recovered, engineering would

require additional inspections.

(e) As previously discussed, the diver’s inspection of the SWPH is primarily for clean up of the pump bay and

screen areas. The divers inspect for corrosion and fouling accumulations. Recovery of any unusual debris

(such as pieces of concrete) would lead to additional inspections.

The staff considers the applicant’s approach to the detection of aging effects to be acceptable

since it is aimed at detecting aging effects before there is a loss of intended function. 

[Monitoring and Trending] The applicant stated that the underwater inspection reports are

retained in sufficient detail to permit adequate confirmation of the inspection programs. The

SWIS inspection documentation and reviews/evaluations are filed in structural calculations. In

particular, these records include the subcontractor’s underwater inspection report, design

engineering review and evaluation of the results, comparison with previous inspection results,

and whether or not the results are acceptable. Discrepancies and their cause, and any
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corrective action resulting from these inspections, are also documented in the calculations. In

response to RAI 3.5-26 part (d), the applicant provided the following additional information:

(d) The detailed divers inspection of the SWIS occurs every five years, and includes an underwater inspection

of the SWPH. The underwater cleanup inspection of the SWPH bays and screens occurs every outage (18

months).

The staff finds the inspection frequency and procedures to be acceptable.

[Acceptance Criteria] The acceptance criteria for the underwater inspection of the SWIS is that

the inspection data are reviewed by engineering. Cracks (old and new) are documented and

mapped on an engineering procedure attachment. Crack width is measured using wire gauges

on a “Go – No/Go” basis by inserting the wire into the crack. The following additional

information concerning acceptance criteria is provided in TR00170-003:

Any changes in length or width to existing (old) cracks and any new cracks are reported by SCE&G to the NRC

in accordance with Operating License Condition 2.C.5.d.

The acceptance criteria for the underwater inspection of the SWIS and SWPH is that the diver’s inspection

data is reviewed by Plant Support Engineering. Any accumulation of biofouling (silt or clams) is removed.

Engineering evaluates any corrosion on the traveling screen components, service water pump components

or any other structural component that was noted on the inspection checklist. Any corrective action(s) based

on the results of this evaluation are initiated by engineering. 

The staff finds the acceptance criteria to be acceptable since they are based on CLB

requirements and the staff did not identify any need to modify the criteria for license renewal. 

[Operating Experience] As discussed in SER Section 3.5.2.3.11, operating experience has

demonstrated that the Underwater Inspection Program has been effective in managing the

effects of aging of underwater structural components associated with the SWIS and SWPH.

The staff concludes that this program should be an effective program for license renewal.

Conclusions

On the basis of its review of the applicant’s program, the staff finds 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). The staff also reviewed the FSAR supplement for this AMP

and finds that it provides an adequate summary description of the program, as required by

10 CFR 54.21(d).

3.5.2.3.12 Tendon Surveillance Program 

Summary of Technical Information in the Application

In LRA Section B.3.3, the applicant stated that the Tendon Surveillance Program is consistent

with X.S1, “Concrete Containment Tendon Prestress,” as identified in NUREG-1801.

The Tendon Surveillance Program is included in the discussion column of LRA Table 3.5-1 and

credited to manage aging effects for license renewal in Report TR00170-003, Revision 0,

Attachment II for the post-tensioning system of the reactor building.
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The test results from the first three surveillance’s (1982, 1983, 1985) indicated that the wire

relaxation force losses in the tendon system were greater than that which were predicted during

design. Consequently, in June 1988, the predicted wire relaxation force losses were increased

from 8.5 percent to 12.8 percent. The fourth period (10th year) tendon surveillance was

performed during January–April 1990. In addition, the vertical tendons were retensioned

because the previous surveillance data indicated that the vertical tendon forces would be below

the technical specifications minimum prior to the fifth period surveillance.

The surveillance reports for the past three surveillance periods [fourth (1990), fifth (1996), and

sixth (2000)] have each concluded that no abnormal degradation of the post-tensioning system

has occurred at VCSNS.

The applicant concluded that the Tendon Surveillance Program has been demonstrated to be

capable of maintaining the reactor building dome, vertical, and hoop tendons above the

minimum required prestressing forces. The applicant further concluded that the Tendon

Surveillance Program provides reasonable assurance that the aging effects will be managed

such that the components subject to AMR will continue to perform their intended functions

consistent with the CLB for the period of extended operation.

Staff Evaluation

In LRA Section B.3.3, “Tendon Surveillance Program,” the applicant described its AMP to

maintain the reactor building dome, vertical, and hoop tendons above the minimum required

prestressing forces. The LRA stated that this AMP is consistent with GALL AMP X.S1,

“Concrete Containment Tendon Prestress,” with no deviations. The staff also reviewed the

FSAR supplement to determine whether it provides an adequate description of the program.

The staff audit on July 16-17, 2003, confirmed the applicant’s claim of consistency. 

The staff noted several inconsistencies between the FSAR supplement summary descriptions

of the AMPs in LRA Appendix A and the scope of the AMPs identified in LRA Appendix B as

“consistent with GALL.” In RAI 3.5-19, the staff requested the applicant to verify that the

complete scope of the AMP, as described in NUREG-1801, GALL Volume 2, is being credited

to manage aging effects for license renewal. If this is not the case, the applicant was requested

to identify and document the justification for each exception. In response to RAI 3.5-19, the

applicant stated the following:

As stated in the Application, VCSNS maintains a Tendon Surveillance Program (B.3.3), which is consistent

with GALL X.S1, XI.S2, and 10 CFR 50.55a.

VCSNS does not believe that there are any further changes required for the Application Appendix A, since only

summary statements are recommended by NEI 95-10. Commitment to all Regulations and Regulatory Guides

are implicit in the development of each of these programs as described in Section 7 of TR00170-003.

In LRA Section B.3.3, the applicant stated that a review of the non-conformances written to

address programmatic and problematic deficiencies with the Tendon Surveillance Program

indicates that there have been no adverse trends associated with aging that are not inherent to

this type of post-tensioning system.

The applicant states that a nonconformance was identified to address the collection of water

due to in-leakage into the auxiliary building tendon sump area to a depth that submerged a
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tendon end cap. The water level in the pit was reduced to a level below the tendon end cap.

During RF-12 the tendon end cap was removed for inspection and no free water was found.

Grease samples (analyzed for entrained moisture) and the tendon components (inspected for

corrosion) were found to be acceptable. As a corrective action, operations added the auxiliary

building tendon sump area to their trend logs and will request facilities to drain the area if the

water level in the area approaches the level of the tendon end cover.

The staff has concerns about the long-term condition of the tendon anchorages if subjected to

additional episodes of water infiltration. Such environments could potentially degrade the

tendon anchorage system, including anchor components inside the end cap, the baseplate, and

reinforced concrete region around the anchors. In RAI 3.5-27, the staff requested the applicant

to (1) explain the relationship between the auxiliary building tendon sump area and the tendon

access gallery beneath the containment, (2) identify the type of tendon end caps (horizontal,

vertical) in the auxiliary building tendon sump area, (3) describe the plant-specific operating

experience related to leakage and/or flooding in the tendon access gallery, and identify whether

the tendon access gallery is also included in the operations “trend logs” to prevent excessive

water level, (4) indicate whether draining of the auxiliary building tendon sump area is credited

for management of aging of the tendon prestressing system, and (5) discuss why water is

allowed to remain in the auxiliary building tendon sump area and only drained if the water level

in the area approaches the level of the tendon end cover. In response to RAI 3.5-27, the

applicant stated the following:

1) The Tendon Access Gallery (TAG) runs 360o beneath the circular containment wall and only houses the

vertical tendon lower end caps. There is no structural connection of the TAG with the Auxiliary Building. The

VCSNS containment structure is designed with vertical, horizontal (hoop) and dome tendons, using a threebuttress system (spaced at 120o

) to anchor the horizontal tendons. One containment concrete buttress (308o

azimuth) is located adjacent to (and within) the Auxiliary Building, which extends into a lower pit area (providing

access to the lower horizontal tendon end caps).

2) As noted in Response 1), only horizontal tendon end caps are located within the Auxiliary Building sump

area.

3) There is no operating experience at VCSNS concerning flooding in the TAG. The TAG has experienced

continuing (since construction) groundwater in-leakage via cracks and construction joints along the outer wall;

however, this leakage is a very slow infiltration, which is easily accommodated by the sumps and drains. [The

TAG is a totally separate area within the plant and has drains, sumps and pumps to maintain the area

relatively dry.] The TAG has no operating experience of any significant water accumulation; therefore,

Operations trend logs are not required to prevent excessive water level accumulation.

4) Only one horizontal tendon (at the bottom of the 308o

 buttress) has been subjected to standing water;

therefore, the commitment for Operations to monitor this area has not been credited for managing aging of

the tendon prestressing system. Aging management will continue to be controlled via the Tendon Surveillance

Program.

5) This lower area at the 308o

 buttress was not originally intended to be a sump, but rather a recessed area

for access to the horizontal tendons, and does not have a drainage system installed (which would now be

extremely costly to install); therefore, monitoring and pumping are significantly more cost effective. The

Tendon Surveillance Program manages this particular problem without the cost of a plant modification.

The applicant’s response to RAI 3.5-27, resolves the staff’s concern about the AMP for the

tendon anchorages, since there has been no operating experience of any significant water

accumulation in the tendon access gallery of the containment. Based on current operating

experience, the staff accepts the applicant’s commitment for VCSNS operations to monitor the
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auxiliary building sump area and to drain the area if the water level in the area approaches the

level of the tendon end cover.

Conclusions

On the basis of its review and audit of the applicant’s program, the staff finds that those

portions of the program for which the applicant claims consistency with the GALL program are

consistent with the GALL program. Since the GALL program is acceptable to the staff, 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). The staff also reviewed the FSAR supplement

for this AMP and finds that it provides an adequate summary description of the program, as

required by 10 CFR 54.21(d).

3.5.2.4 Aging Management Review of Plant-Specific Structures and Structural Components

In this section of the SER, the staff presents its review of the applicant’s AMR for specific

structural components. To perform its evaluation, the staff reviewed the components listed in

LRA Tables 2.4-1 through 2.4-14. The staff also reviewed Report TR00170-003, Revision 0,

Attachment II: Aging Management Review Results for Structures and Structural Components.

Attachment II contains 10-column formatted tables that identify each structural component type,

its intended function(s), material, environment, aging effect(s), AMP(s), consistency with the

NUREG-1801 AMP(s), and applicable notes. The staff determined whether the applicant

properly identified the applicable aging effects and AMPs needed to adequately manage these

aging effects. This element of the staff’s review involved identification of the aging effects for

each component, and ensuring that the AMR for each component is appropriately identified in

the LRA Section 3 tables, and that an appropriate AMP is credited for management of the aging

effect. The results of the staff’s review are provided below.

The staff notes that the applicant did not create separate commodity groups (e.g., component

supports) for structural components common to most buildings/structures. Instead, component

supports and other common structural components are repeated under each building/structure

in Report TR00170-003, Revision 0, Attachment II. 

3.5.2.4.1 Reactor Building (Structure and Foundation, Containment Liner, Penetrations)

Summary of Technical Information in the Application

In the VCSNS LRA, the reactor building includes not only the containment structure and

foundation, containment liner, and penetrations, but also the containment internal structures. In

GALL, containment internal structures are included with Class I structures in Chapter III

because they are similar with respect to the aging management issues and credited programs.

To minimize repetition, the staff evaluation of the AMR for containment internal structures is

included in Section 3.5.2.4.2, “Other Building Structures.” This section of the SER only

addresses the structural components of the containment pressure boundary. 

LRA Section 2.4.1 provides a description of the VCSNS reactor building. The containment is a

prestressed concrete cylindrical structure with a domed roof and a carbon steel liner plate on

the inside surface. Vertical, hoop and dome tendons are used to precompress the concrete
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walls and dome. The AMR results for the containment structure are presented in LRA Table

3.5-1, AMR Items 1 through 15. Detailed documentation of the applicant’s AMR for the reactor

building is contained in Report TR00170-003, Revision 0, Attachment II, pages 37 through 46.

The materials of construction for the containment structure are carbon steel, stainless steel,

concrete, and elastomers. These materials are exposed to one or more of the following

environments — reactor building, indoor, outdoor, borated water, below-grade.

Aging Effects:

Report TR00170-003, Revision 0, Attachment II identifies the following aging effects for the

containment structure:

• cracking, loss of material, and change in material properties for concrete components

• cumulative fatigue, cracking, and loss of material for steel containment penetrations

• loss of material for carbon steel components

• loss of prestress and loss of material for containment tendons

• cracking and change in material properties for elastomers

Aging Management Programs:

Report TR00170-003, Revision 0, Attachment II credits the following AMPs with managing the

identified aging effects for the containment structure:

• Containment ISI Program — IWE/IWL

• 10 CFR 50 Appendix J Leak Rate Testing Program

• Maintenance Rule Structures Program

• Boric Acid Corrosion Surveillances Program

• Containment Coating Monitoring and Maintenance Program

• Tendon Surveillance Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging associated with the components in the containment structure will be adequately

managed by these AMPs such that there is reasonable assurance that the intended functions

will be maintained consistent with the CLB during the period of extended operation.

Staff Evaluation

The staff reviewed the information in Sections 2.4 and 3.5 of the LRA; Report TR00170-003,

Revision 0, Attachment II; the applicant’s responses to the staff’s RAIs; and the applicable AMP

descriptions in Appendix B of the LRA, to determine whether the applicant has demonstrated

that the aging effects associated with the components of the containment will be adequately

managed during the period of extended operation.

In the initial review of the applicant’s AMR for the containment structure, the staff identified

several issues in need of resolution. 

AMR items 7 and 15 of LRA Table 3.5-1 indicate that for the concrete containment structure

only certain aging effects require aging management. As an example, for accessible exterior
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concrete, only change in material properties due to leaching is identified as requiring aging

management. It is the staff position that ASME Section XI, Subsection IWL should be credited

for managing loss of material, cracking, and change in material properties for the concrete

containment structure; and that inaccessible concrete (i.e., below grade) also requires aging

management unless specific criteria defined in NUREG-1801 GALL Volume 2 are satisfied, to

demonstrate a nonaggressive below-grade environment.

In RAI 3.5-2, parts (a), (c), (d), and (e), the staff requested the applicant to provide the following

additional information related to aging management of the containment concrete:

1. Verify that cracking, loss of material, and change in material properties will be

managed in accordance with NUREG-1801, XI.S2, ASME XI, Subsection IWL for all

accessible containment concrete components.

2. Submit a quantitative assessment of the below-grade environment, comparing it to the

specific criteria defined in GALL Volume 2.

3. If it is nonaggressive, based on satisfaction of the specific criteria defined in GALL

Volume 2, describe the Ground Water Monitoring Program that will be implemented to

verify that the below-grade environment remains non-aggressive, including monitoring

frequency and consideration of seasonal fluctuations.

4. If the below-grade environment does not satisfy the specific criteria defined in GALL

Volume 2, describe in detail the plant-specific AMPs for inaccessible concrete

components.

In its response to RAI 3.5-2, parts (a), (c), (d), and (e), the applicant stated the following:

Application Section 2.1.2.2.3 states: “ For concrete structures and structural components, VCSNS has used

the Part 54 Process, NUREG-1801, and industry guidelines to determine those specific aging effects that are

applicable and require aging management for the Extended Period of Operation (EPO). Recent positions by

the NRC Staff have determined that all aging effects for concrete are credible and should be managed under

the CLB programs for the EPO.” -- The issue of managing all versus specific concrete aging effects for

accessible areas is actually a moot point since the plant AMPs (Maintenance Rule Structures Program and

Containment ISI Program - IWE/IWL) look for any concrete degradation, regardless of mechanism or effect.

Therefore, the VCSNS AMPs are considered acceptable to evaluate aging of concrete elements of the

Containment and other Class 1 Structures (which is the intent of the NRC Staff position).

The three steel component types identified in Attachment II of TR00170-003 [anchorage,

anchorage/embedments (exposed surfaces), and embedments] are only related to aging effects for steel, and

not for concrete. All accessible concrete (including that surrounding the steel anchorages and embedments)

is accounted for under component type “Reinforced Concrete - Beams, Columns, Floor Slabs, Walls” which

is managed under the Maintenance Rule Structures Program and Containment ISI Program - IWE/IWL.

(a) Concrete aging effects (cracking, loss of material, and change in material properties) will be

managed at VCSNS in accordance with NUREG-1801, XI.S2, ASME XI, Subsection IWL (Application

Section B.1.16) for all accessible containment concrete components.

(b) Section 6.1 (Table 6.1-3) of TR00170-003 provides the quantitative assessment of the belowgrade groundwater environment at VCSNS. These analyses results are based on samples taken in

2001 from three (3) wells in the general vicinity of plant structures. [Note that prior sample analyses

for chlorides, sulfates and pH do not exist.] Groundwater chlorides (from all three wells) were

determined to be < 10 ppm, which is well within the GALL defined limits of < 500 ppm. Groundwater

sulfates (from all three wells) were determined to be < 10 ppm, which is well within the GALL defined
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limits of < 1500 ppm. Groundwater pH (from the three wells) was determined to range from 4.8 to 5.3,

which marginally exceeds the GALL defined limits of 5.5. Based on these results, the VCSNS

Application defines the site groundwater as non-aggressive, although mildly acidic.

[Supplemental response to RAI 3.5-2, part (c)]

The NRC Staff position is that the VCSNS groundwater is considered to be aggressive since it has a pH < 5.5.

In order to satisfy this concern, the following provisions will be incorporated as part of existing plant programs

and procedures:

1) The site excavation and backfill procedure will be revised to include a concrete surface inspection by

engineering personnel if soil is removed adjacent to any concrete structure surfaces at or below the nominal

groundwater elevation of 423’.

2) As noted in response to RAI 3.5-2(d), chemical analysis of groundwater will be conducted on a 5-year

interval to coincide with the Maintenance Rule Structures Inspection Program. This analysis will also include

a water sample from the Service Water Pond.

3) Underwater diver’s inspections of the Service Water Intake Structure (tunnel) will continue as described in

response to RAI 3.5-26. These inspections will provide additional assurance of the integrity of concrete

structures exposed to below water conditions.

[End of supplemental response]

(d) Application Table 3.5-1, Item 17. specifies that periodic monitoring of the below grade water chemistry will

be conducted during the period of extended operation to demonstrate that the below-grade environment is not

aggressive. VCSNS Engineering Services Procedure (Inspections for Maintenance Rule - Structures) will be

revised to include a chemical analysis of raw water (including groundwater) on a 5-year interval to coincide

with the Maintenance Rule Structures Inspections. [Note that seasonal fluctuations are not applicable at

VCSNS since the level of groundwater remains relatively constant due to the influence of Monticello

Reservoir.]

(e) Application Table 3.5-1, Items 7 and 16, discusses aging mechanisms and effects for inaccessible

concrete. Since the VCSNS below grade environment marginally exceeds the specific pH criteria defined in

GALL, the concrete design was further reviewed and determined to provide protection against aggressive

chemical attack. Since the below-grade structures are considered to be resistant to the mildly acidic

environment, plant specific aging management programs are not required for inaccessible concrete areas.

The staff finds the applicant’s response to RAI 3.5-2, pertaining to aging management of

concrete for the containment structure, to be acceptable because the applicant committed to

manage aging of accessible concrete under its IWL program, and also committed in its

supplemental response to part (c) of the RAI to a plant-specific program to manage aging of

inaccessible concrete. This is consistent with GALL.

Report TR00170-003, Revision 0, Attachment II does not list O-rings for the containment

airlocks and hatch or seals for fire/flood doors as separate components. Therefore, there is no

documented AMR. Since these components are passive and are typically replaced only upon

identification of a degraded condition, they require an AMR. In RAI 3.5-3, the staff requested

the applicant to submit its AMR for these components, including a description of the aging

management programs that will be relied upon to ensure there is no loss of intended function

during the period of extended operation.

In its response to RAI 3.5-3, the applicant stated the following:
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1) O-rings for the Containment equipment, personnel and escape hatches are generically included with

Reactor Building Component Type “Compressible Joints and Seals” (Elastomers) in Attachment II of TR00170-

003. The O-rings are inspected during each refueling outage for repair, replacement and/or lubrication, and

subsequently tested under 10CFR50 Appendix J (Leak Rate Testing) as discussed in Appendix B.1.12 of the

Application.

2) Fire/flood/pressure door seals or gaskets are subcomponents of the door and are not explicitly called out

in scoping and screening, similar to mounting hardware (threshold, latches, strike plates, hinges, sills, etc.).

Door gaskets are extruded closed cell sponge type, made of neoprene rubber or equal and conform to ASTM

D1056, Grade 2C1 (VCSNS Specification SP-631). As evaluated in TR00170-003 Section 6.6, neoprene

rubber’s resistance to oils, chemical, sunlight, weathering, aging, and ozone is outstanding. It retains its

properties at temperatures up to 250o

 F. No aging effects are expected. Although door gaskets were treated

as subcomponents, fire/flood/pressure doors are managed under the Maintenance Rule Structures Program

and Fire Protection Program as identified in Attachment II of TR00170-003. Detailed discussion on

fire/flood/pressure doors is contained in Sections 7.10.2, 7.11, and 7.14 of TR00170-003.

The staff finds the applicant’s response to RAI 3.5-3, to be acceptable, when considered

together with the applicant’s response to RAI 3.5-5, pertaining to technical specification 3/4.6.1. 

The applicant’s approach to managing aging of the containment personnel airlocks and

equipment hatch is consistent with GALL. 

In the "Aging Management Programs" column of the Report TR00170-003, Revision 0,

Attachment II Table, technical specification 3/4.6.1 is listed for the following component types in

the reactor building — personnel airlock, escape hatch, and equipment hatch. In the first part

of RAI 3.5-5, the staff requested the applicant to describe the objective, scope, and

implementation procedures for this technical specification, as it relates to aging management

for license renewal.

In the first part of its response to RAI 3.5-5, the applicant stated the following:

1) Attachment II (Reactor Building) of TR00170-003 lists Technical Specification 3/4.6.1 under AMPs for

personnel airlock, escape airlock, and equipment hatch. This Technical Specification covers Limiting

Conditions of Operation for Containment Air Locks, requiring periodic (6 month) tests of leakage rates.

Verification of leakage rates ensures functional integrity, thereby supplementing inspections conducted under

the Containment ISI Program - IWE/IWL and 10 CFR 50 Appendix J Leak Rate Testing. Type B LLRTs for

the primary containment hatches are performed in accordance with plant procedures as identified in Section

7.2 of TR00170-003.

The staff finds the applicant’s response to RAI 3.5-5, to be acceptable, when considered

together with the applicant’s response to RAI 3.5-3, pertaining to the containment airlocks and

equipment hatch. The applicant’s approach to managing aging of the containment personnel

airlocks and equipment hatch is consistent with GALL. 

LRA Section 3.5.1.1 indicates that the reactor building foundation mat bears on fill concrete that

extends to competent rock, and that a retaining wall, extending approximately one-quarter of

the way around the reactor building, protects the below-grade portions of the reactor building

wall from the subgrade. LRA Section 2.4.1 further indicates that the retaining wall protects the

below-grade portions of the reactor building wall from the subgrade and groundwater. The

groundwater at VCSNS has been identified as being mildly acidic but considered nonaggressive

in LRA Table 3.5-1. It is not clear to the staff whether the retaining wall serves an intended

function and is subject to an AMR. 
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In RAI 3.5-10, the staff requested the applicant to submit the following information related to the

retaining wall:

1. Describe in detail the primary function(s) for the retaining wall.

2. Discuss the consequences of its failure on structures and components that serve

intended functions.

3. If the retaining wall serves an intended function, submit the aging management review

for the retaining wall, including the aging management programs credited to manage

aging.

4. Otherwise, submit the technical basis for concluding that the retaining wall serves no

intended function.

In its response to RAI 3.5-10, the applicant stated the following:

(a) The retaining wall exists along the northeast quadrant of containment (between the Intermediate and Fuel

Handling Buildings) and separates the below grade portions of the containment wall from the subgrade. The

design function of this wall is to provide accessibility to the exterior concrete surface of the containment

structure (above the structural foundation level), primarily for access to the horizontal tendon buttress end

caps.

(b) Hypothetical failure of the retaining wall onto the containment wall and/or horizontal tendon end caps

would not result in any failures of the safety-related structures or components. The consequences of such

failure would be primarily economical for repair and replacement.

(c) There are no intended functions for the retaining wall as defined for license renewal. It is not intended to

provide shelter or protection, structural or functional support, or flood protection for safety-related equipment.

Therefore, aging management and aging management programs are not required. 

The staff finds the applicant’s response to RAI 3.5-10 to be acceptable on the basis that the

applicant considered intended functions for the retaining wall and adequately justified that it

does not serve any intended function for the purpose of license renewal. 

LRA Table 2.4-2 indicates that the AMR results for numerous component types in the reactor

building (such as containment liner plate, cable tray, conduit, electrical and instrument panels

and enclosures, fire doors, flood curbs, and HVAC duct supports) are presented in LRA Table

3.5-1, AMR Item 13. LRA Table 3.5-1, AMR Item 13 covers the component group, “Steel

elements; protected by coating," and lists four AMPs in the "Discussion" column. These are

10 CFR Part 50 Appendix J General Visual Inspection; Containment Coating Monitoring and

Maintenance Program; Containment ISI Program — IWE/IWL; and Maintenance Rule

Structures Program. Report TR00170-003, Revision 0, Attachment II only credits the Coating

Monitoring and Maintenance Program for aging management of the containment liner plate. It

is not apparent to the staff which AMPs are being credited for which components. 

In RAI 3.5-14, the staff requested the applicant to clarify the following items:

(1) Table 3.5-1, AMR Item 13 covers the component group, "Steel elements; protected by

coating." Are all components that reference AMR Item 13 protected by coatings, and

are the coatings managed by a Coating Monitoring and Maintenance Program?
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(2) For each of the component types covered under AMR item 13, identify which of the four

AMPs are credited for license renewal.

In its response to RAI 3.5-14, the applicant stated the following:

(a) Application Table 3.5-1, Item 13, includes all steel component types inside containment since this is the

only GALL item identified for this component category. In general, all of these components are covered by all

of the AMPs. The 10 CFR 50 Appendix J General Visual Inspection, Containment ISI Program - IWE/IWL, and

Maintenance Rule Structures Program all look for component degradation, and since most steel components

are painted, degradation of their protective coating provides an initial indication for more detailed inspections.

The Containment Coating Monitoring and Maintenance Program looks for coating degradation throughout

(regardless of specific component) and is therefore a subset of the other AMPs.

(b) The four (4) listed AMPs apply to all components in Application Table 3.5-1 (Item 13). AMPs are generic

programs that look for all types of degradation throughout and do not list individual components on a specific

checklist for a specific program.

The staff finds the applicant’s response to RAI 3.5-14 to be acceptable. This SRP-LR Table

3.5-1 entry was intended to be more restrictive than the applicant’s interpretation. The

applicant’s response provided the necessary clarification.

For the containment post-tensioning system, Report TR00170-003, Revision 0, Attachment II,

identifies loss of material and loss of prestress as the aging effects requiring management, and

the Tendon Surveillance Program as the applicable AMP. The match with GALL is specified as

“partial” However, LRA Table 3.5-1, AMR Items 14 and 11, respectively address the same

aging effects for the post-tensioning system, and identify the Containment ISI Program —

IWE/IWL and the Tendon Surveillance Program as the applicable AMPs. Both AMPs are

identified as consistent with GALL. In RAI 3.5-15, in order to clarify this apparent contradiction,

the staff requested the applicant to explain what is meant by a partial match in Report

TR00170-003, Revision 0, Attachment II, and to submit the technical basis for any deviations

from the GALL programs that manage aging of the post-tensioning system (i.e., GALL XI.S2

and X.S1).

In its response to RAI 3.5-15, the applicant stated the following:

1) VCSNS based its original Tendon Surveillance Program on proposed Revision 3 of Reg. Guide 1.35 dated

April 1979, although it was in a "proposed" status. The Guide remained in this status until July 1990 when the

finalized Revision 3 was issued. However, on April 28, 1989, the NRC accepted the VCSNS Tendon

Surveillance Program based on the proposed Revision 3 of Regulatory Guide 1.35. In March 1995, the NRC

issued a new rule, 10 CFR 50.55a, which invoked the requirements of the ASME Code, Section XI,

Subsections IWE and IWL, 1992 Edition and 1992 Addenda. The Reactor Building tendon prestress is

monitored and programmatically controlled under plant procedures and specifications as discussed in Section

7.17 of TR00170-003.

2) The “partial” match was selected in Report TR00170-003 due to the fact that the GALL credits the 1992

Edition with the 1992 Addenda and the 1995 Edition with the 1996 Addenda of ASME Code Section XI,

Subsection IWL for managing containment post-tensioning system. Whereas, the VCSNS Tendon

Surveillance Program was developed in accordance with the requirements of the 1992 Edition with the 1992

Addenda.

The staff finds the applicant’s response to RAI 3.5-15 to be acceptable because GALL credits

either the 1992 Edition with the 1992 Addenda or the 1995 Edition with the 1996 Addenda of
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ASME Code Section XI, Subsection IWL. Since the applicant’s program was developed in

accordance with the requirements of the 1992 Edition with the 1992 Addenda, it is consistent

with GALL.

For the personnel airlock, escape airlock, and equipment hatch, the staff considers that loss of

leak tightness in a closed position due to mechanical wear of locks, hinges, and closure

mechanisms is an applicable aging effect that needs to be managed. This is NUREG-1801,

Volume 2, and GALL Item Number II.A3.2-b. From the information provided on page 43 of

Report TR00170-003, Revision 0, Attachment II, it is not clear whether this aging effect will be

managed for license renewal. LRA Table 3.5-1, AMR item 5 indicates an apparent commitment

to manage this aging effect. However, the following statement is included in the "Discussion"

column — "Operation of hatches is governed by VCSNS Technical Specifications. Plant

operational experience has not identified any fretting or seal degradation. Locks, hinges, and

closure mechanisms are active components; therefore, mechanical wear is not considered an

aging effect.” 

In RAI 3.5-17, the staff requested the applicant to provide the following clarifications:

1. Verify that loss of leak tightness in a closed position, resulting from mechanical wear of

locks, hinges, and closure mechanisms, is an applicable aging effect requiring

management for the containment personnel airlock, escape airlock, and equipment

hatch.

2. Identify the aging management programs that are credited to manage this aging effect.

3. Indicate whether technical specification 3/4.6.1, which is referenced as an aging

management program for the personnel airlock, escape airlock, and equipment hatch

in Report TR00170-003, Revision 0, Attachment II, allows any deviations from the

requirements specified in GALL XI.S1, ASME Section XI, Subsection IWE. If so,

describe the deviations and provide the technical basis for concluding that the aging

management commitment is at least equal to the ASME Section XI, Subsection IWE

aging management program.

In its response to RAI 3.5-17, the applicant stated the following:

(a) As stated in Application Table 3.5-1, Item 5, VCSNS does not consider mechanical wear as an applicable

aging effect since locks, hinges and closure mechanisms are active components. However, leak tightness of

the airlocks and hatches (in the closed position) will be managed for License Renewal for the extended period

of operation via inspections conducted under maintenance surveillance activities, Containment ISI Program

IWE/IWL, 10 CFR 50 Appendix J General Visual Inspection, 10 CFR 50 Appendix J Leak Rate Testing and

Technical Specification 3/4.6.1 requirements.

(b) Technical Specification 3/4.6.1 does not allow any deviations from the requirements of the Containment

ISI Program - IWE/IWL. It conservatively supplements the requirements for operability.

The staff finds the applicant’s response to RAI 3.5-17 to be acceptable because the applicant

has clarified that its program to ensure leak tightness of the containment airlocks and hatch in

the closed position is consistent with GALL.
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The detailed staff reviews of the Maintenance Rule Structures Program, the Containment ISI

Program — IWE/IWL, the 10 CFR Part 50 Appendix J Leak Rate Testing Program, the Boric

Acid Corrosion Surveillances Program, the Containment Coating Monitoring and Maintenance

Program, and the Tendon Surveillance Program are in Sections 3.0.3.4, 3.5.2.3.6, 3.5.2.3.2,

3.0.3.1, 3.5.2.3.5, and 3.5.2.3.12 of this SER, respectively. 

Based on the applicant’s additional commitments to manage aging consistent with GALL, as

identified in the applicant’s responses to the RAIs, and review of the credited AMPs, the staff

finds the applicant’s AMR for the containment structure to be acceptable.

The aging effects identified for the reactor building (structure and foundation, containment liner,

penetrations) are consistent with industry operating experience for the materials and

environments listed. The staff finds that all the plausible aging effects were identified and that

the aging effects listed are appropriate for the combination of materials and environments

specified. On the basis of its review, the staff finds that the AMPs credited in the LRA for the

reactor building (structure and foundation, containment liner, penetrations) will effectively

manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.5.2.4.2 Other Building Structures (Auxiliary Building, Control Building, Diesel Generator

Building, Fuel Handling Building, Intermediate Building, Turbine Building,

Containment Internal Structures)

Summary of Technical Information in the Application

The applicant presented its AMR results for building structures other than containment, and for

structural components within the building structures, in LRA Table 3.5-1, AMR items 16 through

29 and LRA Table 3.3-1, AMR Items 9, 12, and 19. Plant-specific AMRs are presented in LRA

Table 3.5-2, AMR Items 1 through 6. Detailed documentation of the applicant’s AMR for

building structures and structural components is contained in Report TR00170-003, Revision 0,

Attachment II, pages 2 through 51. 

The staff notes that Report TR00170-003, Revision 0, Attachment II, page 34, identifies

“Neutron absorbing sheets - Boraflex” and a ‘Boraflex Monitoring Program.” However, in the

“Notes” column, the applicant indicates that Boraflex will be replaced with Boral. The

applicant’s AMR for Boral is presented in LRA Table 3.3-1, AMR Items 9 and 12; the applicant

did not identify any aging effects requiring management for license renewal.

A brief description of the other building structures is provided in LRA Section 2.4.2, “Other

Structures.” The materials of construction for the building structures and structural components

are carbon steel, stainless steel, concrete, elastomers, masonry block, drywall, Boral, and

styrofoam. These materials are exposed to one or more of the following environments —

outdoor, indoor, borated water, below-grade.
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Aging Effects:

Report TR00170-003, Revision 0, Attachment II identifies the following applicable aging effects

for other building structures and structural components:

• loss of material and MIC for carbon steel components

• change in material properties, cracking, and loss of material for concrete components

• cracking of masonry block

• cracking, shrinkage, and change in material properties for elastomers

• cumulative fatigue and cracking for stainless steel components

• degradation of styrofoam and drywall

Aging Management Programs:

Report TR00170-003, Revision 0, Attachment II credits the following AMPs with managing the

identified aging effects for other building structures and structural components:

• Chemistry Control Program

• Fire Protection Program

• Containment ISI Program — IWE/IWL

• 10 CFR Part 50 Appendix J Leak Rate Testing Program

• Maintenance Rule Structures Program

• Boric Acid Corrosion Surveillances Program

• Battery Rack Inspection Program

• ASME Section XI ISI Program — IWF

• Material Handling Systems Inspection Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging associated with other building structures and structural components will be

adequately managed by these AMPs such 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).

Staff Evaluation

The staff reviewed the information in Sections 2.4, 3.3, and 3.5 of the LRA; Report TR00170-

003, Revision 0, Attachment II; the applicant’s responses to the staff’s RAIs; and the applicable

AMP descriptions in Appendix B of the LRA, to determine whether the applicant has

demonstrated that the aging effects associated with the other building structures and structural

components will be adequately managed during the period of extended operation.

In the initial review of the applicant’s AMR for the other building structures and structural

components, the staff identified several issues in need of resolution. 

In Report TR00170-003, Revision 0, Attachment II: Aging Management Review Results for

Structures and Structural Components, cable trays, conduit, and electrical and instrument

panels and enclosures are identified as component types within most of the buildings and

structures. These components are identified as steel in an internal environment, except for the
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electrical substation and transformer area, where the environment is external. In all cases, no

aging effect requiring aging management is identified. 

The staff believes that these components located in the reactor, auxiliary, intermediate, and fuel

handling buildings are susceptible to boric acid corrosion and that these components located in

an external environment are susceptible to environmental corrosion. Therefore, in both cases

loss of material is an applicable aging effect requiring aging management. In RAI 3.5-1, the 

staff requested the applicant to identify and describe the AMPs, which will manage loss of

material for these components located in the reactor, auxiliary, intermediate, and fuel handling

buildings, and in an external environment.

In its response to RAI 3.5-1, the applicant stated the following:

1) Section 6.2 of TR00170-003 identifies electrical panels, cabinets, cable trays, etc. as being constructed

of factory baked painted steel or galvanized sheet metal, both of which do not have a tendency to age with

time due to general corrosion. VCSNS realized that these components are designed for outdoor service and

industry operating experience has not shown a case where aging effects caused a loss of intended function.

Therefore, these components in the Electrical Substation and Transformer Area were judged to have no

aging effects from general corrosion due to an external environment.

Even though corrosion is considered unlikely, Attachment II of TR00170-003 will be revised for the external

environment to include loss of material (for Cable Tray & Conduit and Electrical and Instrument Panels &

Enclosures) as an aging effect which is managed by the Maintenance Rule Structures Program.

2) The attributes of these materials (factory baked painted steel or galvanized sheet metal) were similarly

deemed to provide additional protection from boric acid corrosion and thus judged to have no aging effects.

However, Section 7.6 of TR00170-003, “Boric Acid Corrosion Surveillances” (Scope of Program) does

include these electrical components under Boric Acid Corrosion Surveillances for managing aging effects

(loss of material). Therefore, Attachment II of TR00170-003 will be revised for Reactor, Auxiliary,

Intermediate, and Fuel Handling Buildings to include loss of material (for Cable Tray & Conduit and

Electrical and Instrument Panels & Enclosures) as an aging effect which is managed by Boric Acid

Corrosion Surveillances and Maintenance Rule Structures Program.

The staff finds that the part of the applicant’s response to RAI 3.5-1, pertaining to a borated

environment, is acceptable because the applicant has committed to manage aging of cable

trays, conduit, and electrical and instrument panels and enclosures in a borated water

environment as part of the Boric Acid Corrosion Surveillances Program and the Maintenance

Rule Structures Program.

Many concrete component types in internal, external, and below-grade environments are

identified in Report TR00170-003, Revision 0, Attachment II as having no aging effects

requiring aging management. The specific component types are duct banks, equipment pads,

flood curbs, foundations, hatches, missile shields, reinforced concrete-beams, columns, floor

slabs, walls, roof slabs, sumps, caissons, piers, trenches, jet barriers and manholes. The staff

position is that all accessible concrete components that perform intended function require aging

management for loss of material, cracking, and change in material properties; and that

inaccessible concrete components (i.e., below grade) also require aging management unless

specific criteria defined in NUREG-1801 GALL Volume 2 are satisfied, to demonstrate a

nonaggressive below-grade environment.

Report TR00170-003, Revision 0, Attachment II also lists three steel components in a concrete

environment. These are anchorage, anchorage/embedments (exposed surfaces) and
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embedments. All are identified as having no aging effects requiring aging management. The

condition of the concrete surrounding anchorage and embedments may affect their load

capacity. GALL Volume 2, III.B, Item Numbers III.B1.1.4, III.B1.2.3, III.B2.2, III.B3.2, III.B4.3,

and III.B5.2 specifically identify the need for aging management of the concrete surrounding

expansion and grouted anchors, and grout pads for support base plates. The staff position is

that all accessible concrete requires aging management; this includes monitoring the condition

of concrete surrounding anchorages and embedments.

AMR Items 7 and 15 of LRA Table 3.5-1 indicate that for the concrete containment structure

only certain aging effects require aging management. As an example, for accessible exterior

concrete, only change in material properties due to leaching is identified as requiring aging

management. It is the staff position that ASME Section XI, Subsection IWL should be credited

for managing loss of material, cracking, and change in material properties for the concrete

containment structure; and that inaccessible concrete (i.e., below grade) also requires aging

management unless specific criteria defined in NUREG-1801 GALL Volume 2 are satisfied, to

demonstrate a nonaggressive below-grade environment.

In RAI 3.5-2, the staff requested the applicant to provide the following additional information:

(a) Verify that cracking, loss of material, and change in material properties will be

managed in accordance with NUREG-1801, XI.S2, ASME XI, Subsection IWL for all

accessible containment concrete components.

(b) Identify the aging management programs that will manage loss of material, cracking,

and change in material properties for all other concrete components in accessible

areas.

(c) Submit a quantitative assessment of the below-grade environment, comparing it to

the specific criteria defined in GALL Volume 2.

(d) If it is nonaggressive, based on satisfaction of the specific criteria defined in GALL

Volume 2, describe the Groundwater Monitoring Program that will be implemented to

verify that the below-grade environment remains nonaggressive, including monitoring

frequency and consideration of seasonal fluctuations.

(e) If the below-grade environment does not satisfy the specific criteria defined in GALL

Volume 2, describe in detail the plant-specific aging management programs for

inaccessible concrete components.

In its response to RAI 3.5-2, the applicant stated the following:

Application Section 2.1.2.2.3 states: “For concrete structures and structural components, VCSNS has used

the Part 54 Process, NUREG-1801, and industry guidelines to determine those specific aging effects that

are applicable and require aging management for the Extended Period of Operation (EPO). Recent positions

by the NRC Staff have determined that all aging effects for concrete are credible and should be managed

under the CLB programs for the EPO.” – The issue of managing all versus specific concrete aging effects

for accessible areas is actually a moot point since the plant AMPs (Maintenance Rule Structures Program

and Containment ISI Program - IWE/IWL) look for any concrete degradation, regardless of mechanism or

effect. Therefore, the VCSNS AMPs are considered acceptable to evaluate aging of concrete elements of

the Containment and other Class 1 Structures (which is the intent of the NRC Staff position).
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The three steel component types identified in Attachment II of TR00170-003 [anchorage,

anchorage/embedments (exposed surfaces), and embedments] are only related to aging effects for steel,

and not for concrete. All accessible concrete (including that surrounding the steel anchorages and

embedments) is accounted for under component type “Reinforced Concrete - Beams, Columns, Floor Slabs,

Walls” which is managed under the Maintenance Rule Structures Program and Containment ISI Program -

IWE/IWL.

(a) Concrete aging effects (cracking, loss of material, and change in material properties) will be

managed at VCSNS in accordance with NUREG-1801, XI.S2, ASME XI, Subsection IWL (Application

Section B.1.16) for all accessible containment concrete components.

(b) Concrete aging effects (cracking, loss of material, and change in material properties) will be

managed at VCSNS in accordance with the Maintenance Rule Structures Program (Application

Section B.1.18) for all other concrete components in accessible areas.

(c) Section 6.1 (Table 6.1-3) of TR00170-003 provides the quantitative assessment of the below-grade

groundwater environment at VCSNS. These analyses results are based on samples taken in 2001

from three (3) wells in the general vicinity of plant structures. [Note that prior sample analyses for

chlorides, sulfates and pH do not exist.] Groundwater chlorides (from all three wells) were determined

to be < 10 ppm, which is well within the GALL defined limits of < 500 ppm. Groundwater sulfates (from

all three wells) were determined to be < 10 ppm, which is well within the GALL defined limits of < 1500

ppm. Groundwater pH (from the three wells) was determined to range from 4.8 to 5.3, which marginally

exceeds the GALL defined limits of 5.5. Based on these results, the VCSNS Application defines the

site groundwater as non-aggressive, although mildly acidic.

[Supplemental response to RAI 3.5-2, part (c)]

The NRC Staff position is that the VCSNS groundwater is considered to be aggressive since it has a pH <

5.5. In order to satisfy this concern, the following provisions will be incorporated as part of existing plant

programs and procedures:

1) The site excavation and backfill procedure will be revised to include a concrete surface inspection by

engineering personnel if soil is removed adjacent to any concrete structure surfaces at or below the nominal

groundwater elevation of 423’.

2) As noted in response to RAI 3.5-2(d), chemical analysis of groundwater will be conducted on a 5-year

interval to coincide with the Maintenance Rule Structures Inspection Program. This analysis will also include

a water sample from the Service Water Pond.

3) Underwater diver’s inspections of the Service Water Intake Structure (tunnel) will continue as described

in response to RAI 3.5-26. These inspections will provide additional assurance of the integrity of concrete

structures exposed to below water conditions.

[End of supplemental response]

(d) Application Table 3.5-1, Item 17. specifies that periodic monitoring of the below grade water chemistry

will be conducted during the period of extended operation to demonstrate that the below-grade environment

is not aggressive. VCSNS Engineering Services Procedure (Inspections for Maintenance Rule - Structures)

will be revised to include a chemical analysis of raw water (including groundwater) on a 5-year interval to

coincide with the Maintenance Rule Structures Inspections. [Note that seasonal fluctuations are not

applicable at VCSNS since the level of groundwater remains relatively constant due to the influence of

Monticello Reservoir.]

(e) Application Table 3.5-1, Items 7 and 16, discusses aging mechanisms and effects for inaccessible

concrete. Since the VCSNS below grade environment marginally exceeds the specific pH criteria defined

in GALL, the concrete design was further reviewed and determined to provide protection against aggressive

chemical attack. Since the below-grade structures are considered to be resistant to the mildly acidic

environment, plant specific aging management programs are not required for inaccessible concrete areas.
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The staff finds the applicant’s response to RAI 3.5-2, pertaining to aging management of

concrete in the other building structures and structural components, to be acceptable because

the applicant has committed to manage aging of accessible concrete as part its Maintenance

Rule Structures Program, and has also committed in its supplemental response to part (c) of

the RAI to a plant-specific program to manage aging of inaccessible concrete. This is

consistent with GALL.

Report TR00170-003, Revision 0, Attachment II identifies loss of material as the only aging

effect requiring aging management for pipe supports located in the auxiliary building, control

building, intermediate building, diesel generator building, fuel handling building, reactor building,

and service water structures. The ASME Section XI ISI Program — IWF is identified as one of

the credited AMPs.

Attachment II indicates that this is a match with GALL. The staff notes that this is not a match

with GALL, because GALL Volume 2, III.B, Item Numbers III.B1.1.3 and III.B1.2.2 also identify

loss of mechanical function as an aging effect to be managed by IWF. In RAI 3.5-4, the staff

requested the applicant to verify (1) that loss of mechanical function is an applicable aging

effect for ASME class piping supports, and (2) that IWF is the applicable AMP, or submit a

detailed technical basis for excluding this aging effect and clearly identify this as a deviation

from GALL.

In its response RAI 3.5-4, the applicant stated the following:

Attachment II of TR00170-003 (for Component Type - Pipe Supports) refers to Section 6.9 for details on

service-induced cracking and loss of mechanical function aging effect. Section 6.9 of TR00170-003

identifies an exception to GALL III.B1.2.2-a, whereby “loss of mechanical function” is not an aging effect,

but rather a design issue. However, since the IWF program is capable of determining loss of mechanical

function, TR00170-003 will be revised accordingly to:

1) Identify loss of mechanical function as an applicable aging effect for ASME class piping supports,

and 2) Identify ASME Section XI, Subsection IWF as the applicable aging management program.

The staff finds the applicant’s commitment to manage loss of mechanical function as part of its

IWF program to be acceptable because it is consistent with GALL.

In the “Aging Management Programs” column of the Report TR00170-003, Revision 0,

Attachment II Table, technical specification 3/4.9.10 is listed for the following component types

in the fuel handling building — fuel transfer canal liner plate, spent fuel pool liner, and spent fuel

storage rack. In the second part of RAI 3.5-5, the staff requested the applicant to describe the

objective, scope, and implementation procedures for this technical specification, as it relates to

aging management for license renewal.

In the second part of its response to RAI 3.5-5, the applicant stated the following:

2) Attachment II (Fuel Handling Building) of TR00170-003 lists Technical Specification 3/4.9.10 under AMPs

for fuel transfer canal liner plate, Spent Fuel Pool liner, and spent fuel storage rack. This Technical

Specification covers Limiting Conditions for Operation for water level in the Spent Fuel Pool, requiring at

least 23 feet of water maintained over the top of irradiated fuel assemblies seated in the storage racks.

Verification of the water level in conjunction with the Chemistry Program ensures a constant level in the pool

and avoids continuous wetting/drying of steel components, thereby reducing aging effects. [Note that a

recent revision to the VCSNS Technical Specifications relocated these requirements to Section 3/4.7.10.]
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The staff finds that the applicant’s response to RAI 3.5-5 provides an adequate description of

the role of Technical Specification 3/4.9.10 (now 3/4.7.10) in monitoring the water level in the

spent fuel pool located in the fuel handling building. 

In LRA Table 3.5-1, AMR Item 19, the applicant credits the Chemistry Program (LRA Appendix

B.1.4) for aging management of the stainless steel spent fuel pool liner. The staff considers

verification of the effectiveness of a chemistry control program to be an integral element of

aging management. For the spent fuel pool, this is readily achieved by monitoring an existing

plant-specific, spent fuel pool leak detection system or by monitoring the spent fuel pool water

level for indications of leakage. In RAI 3.5-7, the staff requested the applicant to describe its

plant-specific operating experience concerning leaks in the spent fuel pool, including a

description of each occurrence, how it was detected, the determination of root cause, and how

it was remedied.

In its response to RAI 3.5-7, the applicant stated the following:

1) At VCSNS, there have been no leaks detected from the Spent Fuel Pool, thus, no operating experience.

2) A complete discussion related to the Chemistry Program controls for the Spent Fuel Pool is contained

in Section 7.7 of TR00170-003. Refer also to RAI 3.5-5 response on monitoring Spent Fuel Pool water level.

The staff finds the applicant’s response to RAI 3.5-7 to be acceptable. Monitoring of the spent

fuel pool water level has been addressed in the applicant’s response to RAI 3.5-5, discussed

above. 

The stainless steel spent fuel storage racks are immersed in the spent fuel pool. In the "Aging

Management Programs" column of the Report TR00170-003, Revision 0, Attachment II Table

for the fuel handling building, the same AMPs are listed for both the spent fuel pool liner and

the spent fuel storage racks. Since both are stainless steel and subjected to a borated water

environment, the staff’s evaluation of the applicant’s AMR for the spent fuel pool liner also

applies to the spent fuel storage racks. The staff notes that in the LRA, for the spent fuel

storage racks, the applicant references LRA Table 3.5-1, AMR items 16, 25, and 27. The

correct reference is AMR Item 19, in order to be consistent with Report TR00170-003, Revision

0, Attachment II.

LRA Table 3.5-2 is titled “Summary of Aging Management Programs for Station Containment,

Other Structures and Component Supports That are Different From or Not Addressed in

NUREG-1801 but are Relied on for License Renewal.” Ten AMR items are listed in the table. 

For each AMR item, the following information is provided in the table — component type,

material, environment, aging effect/mechanism, program activity, and discussion. 

The staff's review of LRA Table 3.5-2 identified the need for clarification and additional

information relating to a number of the AMR items. For all except one of these items, additional

pertinent information has either been requested in other RAIs or was located in Attachment II to

Report TR001700-003. The exception is LRA Table 3.5-2, AMR Item 4, "Lubrite Plates (Class

1 Pipe Hanger Supports)." It is identified as a lubricant material in an internal environment. No

aging effect/mechanism is identified, and consequently no AMP is identified. In the
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"Discussion" column, the applicant provided a brief summary of its AMR, which concluded that

lubrite plates "are not susceptible to aging effects requiring management." 

Aging management of lubrite plates for Class 1 piping supports is addressed in NUREG-1801,

GALL Volume 2, III.B, Item No. III.B1.1.3. ASME Section XI, Subsection IWF is identified as

the applicable AMP. In RAI 3.5-8, the staff requested the applicant to submit a detailed

technical basis to support its conclusion that lubrite plates do not require aging management, or

to credit its IWF AMP for aging management of lubrite plates, consistent with GALL.

In its response to RAI 3.5-8, the applicant stated the following:

An extensive review of Class 1, 2, 3 supports at VCSNS discovered only two (2) Class 1 pipe hanger

supports (both inside containment) which incorporated small lubrite slide plates (as discussed in Section

6.8 of TR00170-003). TR00170-003 also contains the technical basis supporting our basic conclusion that

lubrite plates do not require aging management. However, all Class 1, 2, 3 supports are inspected under

the ASME Section XI ISI Program - IWF (Application Section B.1.13), which provides an acceptable aging

management program for aging management of lubrite plates, consistent with the GALL.

The staff finds the applicant’s commitment to manage aging of lubrite plates as part of its IWF

program to be acceptable because it is consistent with GALL.

LRA Table 3.5-1 is titled "Summary of Aging Management Programs for Station Containment,

Other Structures and Component Supports Evaluated in NUREG-1801 that are relied on for

License Renewal." Twenty-nine AMR items are listed in the table. For each AMR item, the

following information is provided in the table — component group, aging effect/mechanism,

aging management program, further evaluation required, and discussion. This table is a

reproduction of NUREG-1800 Table 3.5-1, with an added "Discussion" column. LRA Table 3.5-

1 does not indicate that the applicant's AMRs are consistent with GALL. In the "Discussion"

column, the applicant refers to AMPs that are "consistent with those reviewed and approved in

NUREG-1801." For most of the AMR items, the aging management review is not consistent

with GALL. The staff's review of LRA Table 3.5-1 identified the need for clarification and

additional information relating to many of the AMR items. For many of these items, additional

pertinent information has either been requested in other RAIs or was located in Attachment II to

Report TR001700-003. As part of RAI 3.5-9, the staff requested the applicant to submit the

following additional information or clarifications related to other building structures and structural

components:

(a) For AMR Item 16, explain the reference to two AMPs that are only applicable to the

containment structure.

(b) For AMR Item 24, explain the following statement in the "Discussion" column, "Note

that the combinations of components, materials, and environments identified in

NUREG-1801 for Group 8 (Steel Tanks) are not applicable to VCSNS; therefore,

aging management is not required." Do any steel tanks have stainless steel liners? 

If so, how are SCC and crevice corrosion managed?

(c) For AMR Item 25, clarify which listed subcomponents are managed by each of the

two referenced AMPs. Also identify which, if any, of the subcomponents do not

require aging management, based on the plant-specific AMR.
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(d) For AMR item 28, explain why ASME Section XI, Subsection IWF is not credited for

aging management of the ASME class supports, consistent with GALL. How are the

two referenced AMPs implemented as a substitute for IWF? 

In its response to RAI 3.5-9, parts (d) through (g), the applicant stated the following:

(d) Consistent with GALL, Application Table 3.5-1, Item 16, is applicable to all Class 1 Structures (including

containment), except for Group 6 (water-control structures). Regardless of applicability of aging

mechanisms, the AMPs identified are used to look for all aging effects. Therefore, as noted in the RAI, the

two AMPs (Containment Coating Monitoring and Maintenance Program and Containment ISI Program –

IWE/IWL) are both specific to the containment structure. The Maintenance Rule Structures Program is

applicable to all Class 1 Structures, including containment.

(e) The basis of the note for steel tanks in Application Table 3.5-1, Item 24, is from a structural perspective

for inspections of exterior tank surfaces, foundations, and anchorages. Steel tanks at VCSNS do not have

stainless steel liners. However, SCC and crevice corrosion are monitored from a mechanical perspective,

with details contained in Application Sections B.2.1 and B.2.11.

(f) For Application Table 3.5-1, Item 25, the Maintenance Rule Structures Program applies to all

subcomponents for all structures (including containment), while the 10 CFR 50 Appendix J General Visual

Inspection is used only as a supplementary inspection program for containment. As noted in the discussion

for Item 25, cracking due to fatigue is not an aging effect requiring management for concrete components.

(g) Application Table 3.5-1, Item 28, should have credited the ASME Section XI ISI Program - IWF

(Application Section B.1.13) as the primary AMP for aging management of the ASME Class 1, 2, 3 supports.

The IWF AMP is credited in Attachment II of TR00170-003. The other two programs referenced are included

as supplementary programs for additional inspections and are not intended as a substitute for IWF.

The staff finds the applicant’s clarifications and additional information for parts (d), (f), and (g)

to be acceptable because they are consistent with GALL. The applicant’s response to part (e)

refers to AMPs related to mechanical systems, described in LRA Sections B.2.1 and B.2.11.

The results of the staff review of these AMPs are in Sections 3.0.3.5 and 3.0.3.7 of this SER. 

In Report TR00170-003, Revision 0, Attachment II, many structural components are identified

as not having any applicable aging effects and thereby no AMPs are specified in the "Aging

Management Programs" column. Most of these structural components are concrete, which the

staff has addressed in RAI 3.5-2. For several stainless steel components in the reactor building

(refueling canal liner plate, sump screens, and sumps), a statement in the "Notes" column

indicates that although no aging effects have been identified, the Maintenance Rule Structures

Program inspects these components. In RAI 3.5-11, the staff requested the applicant to explain

the intent of this statement. Is the Maintenance Rule Structures Program being credited to

manage aging of these components for license renewal?

In its response to RAI 3.5-11, the applicant stated the following:

Attachment II of TR00170-003 notes that there are no aging effects identified for stainless steel in air

environment. However, the Maintenance Rule Structures Program does provide a complete walkdown of

the interior of containment, focusing primarily on interior structural components (which does include refueling

canal, sumps and screens). Therefore, the Maintenance Rule Structures Program is credited for managing

aging of these components.

The staff finds the applicant’s response to RAI 3.5-11 to be acceptable. Crediting the

Maintenance Rule Structures Program to manage aging of these components is consistent with

the intent of GALL (i.e., to credit existing programs to the fullest extent). 
3-406

The applicant has identified that Boral will replace Boraflex as the neutron absorber in the spent

fuel storage racks. The applicant references LRA Table 3.3-1, AMR items 9 and 12. In the

“Discussion” column of AMR Item 9, the applicant asserts that Boral does not degrade as a

result of long-term exposure to radiation, and there are no aging effects applicable to Boral

neutron-absorbing sheets in the spent fuel storage racks of VCSNS. The potential aging

effects resulting from sustained irradiation of Boral were previously evaluated by the staff (BNLNUREG-25582, dated January 1979) and determined to be insignificant. Therefore, the staff

finds the applicant’s AMR conclusions to be acceptable.

The detailed staff reviews of the Maintenance Rule Structures Program, the Fire Protection

Program, the Material Handling Systems Inspection Program, the ASME Section XI ISI

Program — IWF, the Chemistry Control Program, the Containment ISI Program — IWE/IWL,

the 10 CFR Part 50 Appendix J Leak Rate Testing, the Boric Acid Corrosion Surveillances, and

the Battery Rack Inspection are in Sections 3.0.3.4, 3.0.3.3, 3.3.2.3.2, 3.5.2.3.3, 3.0.3.2,

3.5.2.3.6, 3.5.2.3.2, 3.0.3.1, and 3.5.2.3.4 of this SER, respectively.

Based on the applicant’s additional commitments to manage aging consistent with GALL, as

identified in the applicant’s responses to the RAIs and review of the credited AMPs, the staff

finds the applicant’s AMR for the other building structures and structural components to be

acceptable.

The aging effects identified in the LRA for the other building structures (auxiliary building,

control building, diesel generator building, fuel handling building, intermediate building, turbine

building, containment internal structures) are consistent with industry operating experience for

the materials and environments listed. The staff finds that all the plausible aging effects were

identified and that the aging effects listed are appropriate for the combination of materials and

environments specified. On the basis of its review, the staff finds that the AMPs credited in the

LRA for the other building structures (auxiliary building, control building, diesel generator

building, fuel handling building, intermediate building, turbine building, containment internal

structures) will effectively mange or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.5.2.4.3 Service Water Pump House, Intake and Discharge Structures

Summary of Technical Information in the Application

The applicant presented its AMR results for the service water pump house, intake and

discharge structures in LRA Table 3.5-1, AMR Items 18 and 25. Plant-specific AMRs are

presented in LRA Table 3.5-2, AMR Items 7 through 9. Detailed documentation of the

applicant’s AMR for the service water pump house, intake and discharge structures is contained

in Report TR00170-003, Revision 0, Attachment II, pages 52 through 57.
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A brief description of the service water pump house, intake and discharge structures is provided

in LRA Section 2.4.2, “Other Structures.” The materials of construction for the service water

pump house, intake and discharge structures are carbon steel, concrete, elastomers, drywall,

and styrofoam. These materials are exposed to one or more of the following environments —

outdoor, indoor, raw water, below-grade.

Aging Effects:

Report TR00170-003, Revision 0, Attachment II identifies the following applicable aging effects

for the service water pump house, intake and discharge structures:

• loss of material for carbon steel components

• change in material properties, cracking, and loss of material for concrete components

• cracking, shrinkage, and change in material properties for elastomers

• degradation of styrofoam and drywall

• settlement of concrete

Aging Management Programs:

Report TR00170-003, Revision 0, Attachment II credits the following AMPs with managing the

identified aging effects for the service water pump house, intake and discharge structures:

• Fire Protection Program

• Maintenance Rule Structures Program

• ASME Section XI ISI Program — IWF

• Underwater Inspection Program (SWIS and SWPH)

• Service Water Structures Survey Monitoring Program

• Material Handling Systems Inspection Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging associated with the service water pump house, intake and discharge structures 

will be adequately managed by these AMPs such 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).

Staff Evaluation

The staff reviewed the information in Sections 2.4 and 3.5 of the LRA; Report TR00170-003,

Revision 0, Attachment II; the applicant’s responses to the staff’s RAIs; and the applicable AMP

descriptions in Appendix B of the LRA, to determine whether the applicant has demonstrated

that the aging effects associated with the service water pump house, intake and discharge

structures will be adequately managed during the period of extended operation.

In the initial review of the applicant’s AMR for the service water pump house, intake and

discharge structures, the staff determined that the applicant has identified the appropriate

material and aging effects, and has credited appropriate AMPs to manage aging, except for the

lack of commitment to manage aging of accessible concrete. The applicant’s subsequent

commitment to credit its Maintenance Rule Structures Program to manage aging of concrete,
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as documented in Section 3.5.2.4.2.2 of this SER in the discussion of RAI 3.5-2, also applies to

the accessible concrete of the service water pump house, intake and discharge structures. 

The plant-specific Service Water Structures Survey Monitoring Program is credited for

monitoring settlement, and the plant-specific Underwater Inspection Program (SWIS and

SWPH) is credited for managing aging of underwater concrete. The detailed staff reviews of

the Maintenance Rule Structures Program, the Fire Protection Program, the Material Handling

Systems Inspection Program, the ASME Section XI ISI Program — IWF, the Underwater

Inspection Program (SWIS and SWPH), and the Service Water Structures Survey Monitoring

Program are in Sections 3.0.3.4, 3.0.3.3, 3.3.2.3.2, 3.5.2.3.3, 3.5.2.3.11, and 3.5.2.3.10 of this

SER, respectively. 

Based on this new commitment to manage aging of accessible concrete and the review of the

credited AMPs, the staff finds the applicant’s AMR for the service water pump house, intake

and discharge structures to be acceptable.

The aging effects identified in the LRA for the service water pump house, intake and discharge

structures are consistent with industry operating experience for the materials and environments

listed. The staff finds that all the plausible aging effects were identified and that the aging

effects listed are appropriate for the combination of materials and environments specified. On

the basis of its review, the staff finds that the AMPs credited for the LRA for the service water

pump house, intake and discharge structures will effectively manage or monitor the aging

effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.5.2.4.4 Yard Structures (Condensate Storage Tank Foundation, Fire Service Pumphouse, 

Electrical Manhole MH-2, Electrical Substation and Transformer Area)

Summary of Technical Information in the Application

The applicant presents its AMR results for yard structures in LRA Table 3.5-1, AMR Items 16

through 25. A plant-specific AMR is presented in LRA Table 3.5-2, AMR Item 1. Detailed

documentation of the applicant’s AMR for yard structures is contained in Report TR00170-003,

Revision 0, Attachment II, pages 58 through 68.

A brief description of the yard structures is provided in LRA Section 2.4.2, “Other Structures.”

The materials of construction for the yard structures are carbon steel, galvanized steel,

concrete, elastomers, and masonry block/brick. These materials are exposed to one or more of

the following environments — outdoor, indoor, below-grade.

Aging Effects:
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Report TR00170-003, Revision 0, Attachment II identifies the following applicable aging effects

for yard structures:

• loss of material for carbon steel and galvanized steel components

• change in material properties, cracking, and loss of material for concrete components

• cracking of masonry block/brick

• cracking and shrinkage for elastomers

Aging Management Programs:

Report TR00170-003, Revision 0, Attachment II credits the following AMPs with managing the

identified aging effects for yard structures:

• Fire Protection Program

• Maintenance Rule Structures Program

• Battery Rack Inspection Program

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging associated with yard structures will be adequately managed by these AMPs

such 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).

Staff Evaluation

The staff reviewed the information in Sections 2.4 and 3.5 of the LRA; Report TR00170-003,

Revision 0, Attachment II; the applicant’s responses to the staff’s RAIs; and the applicable AMP

descriptions in Appendix B of the LRA, to determine whether the applicant has demonstrated

that the aging effects associated with the yard structures will be adequately managed during

the period of extended operation.

In Report TR00170-003, Revision 0, Attachment II: Aging Management Review Results for

Structures and Structural Components, cable trays, conduit, and electrical and instrument

panels and enclosures are identified as component types within most of the buildings and

structures. These components are identified as steel in an internal environment, except for the

electrical substation and transformer area, where the environment is external. In all cases, no

aging effect requiring aging management is identified. 

The staff believes that these components located in the reactor, auxiliary, intermediate, and fuel

handling buildings are susceptible to boric acid corrosion and that these components located in

an external environment are susceptible to environmental corrosion. Therefore, in both cases,

loss of material is an applicable aging effect requiring aging management. In RAI 3.5-1, the

staff requested the applicant to identify and describe the AMPs, which will manage loss of

material for these components located in the reactor, auxiliary, intermediate, and fuel handling

buildings, and in an external environment.

In its response to RAI 3.5-1, the applicant stated the following:

1) Section 6.2 of TR00170-003 identifies electrical panels, cabinets, cable trays, etc. as being constructed

of factory baked painted steel or galvanized sheet metal, both of which do not have a tendency to age with
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time due to general corrosion. VCSNS realized that these components are designed for outdoor service and

industry operating experience has not shown a case where aging effects caused a loss of intended function.

Therefore, these components in the Electrical Substation and Transformer Area were judged to have no

aging effects from general corrosion due to an external environment.

Even though corrosion is considered unlikely, Attachment II of TR00170-003 will be revised for the external

environment to include loss of material (for Cable Tray & Conduit and Electrical and Instrument Panels &

Enclosures) as an aging effect which is managed by the Maintenance Rule Structures Program.

2) The attributes of these materials (factory baked painted steel or galvanized sheet metal) were similarly

deemed to provide additional protection from boric acid corrosion and thus judged to have no aging effects.

However, Section 7.6 of TR00170-003, “Boric Acid Corrosion Surveillances” (Scope of Program) does

include these electrical components under Boric Acid Corrosion Surveillances for managing aging effects

(loss of material). Therefore, Attachment II of TR00170-003 will be revised for Reactor, Auxiliary,

Intermediate, and Fuel Handling Buildings to include loss of material (for Cable Tray & Conduit and

Electrical and Instrument Panels & Enclosures) as an aging effect which is managed by Boric Acid

Corrosion Surveillances and Maintenance Rule Structures Program.

The staff finds that the part of the applicant’s response to RAI 3.5-1, pertaining to an external

environment is acceptable because the applicant has committed to manage aging of cable

trays, conduit, and electrical and instrument panels and enclosures in an external environment

as part of its Maintenance Rule Structures Program.

The applicant’s commitment to credit its Maintenance Rule Structures Program to manage

aging of concrete, as documented in Section 3.5.2.4.2 of this SER in the discussion of RAI 3.5-

2, also applies to the concrete foundations of the yard structures. 

The detailed staff reviews of the Maintenance Rule Structures Program, the Fire Protection

Program, and the Battery Rack Inspection are in Sections 3.0.3.4, 3.0.3.3, and 3.5.2.3.4 of this

SER, respectively. 

Based on these new commitments and review of the credited AMPs, the staff finds the

applicant’s AMR for yard structures to be acceptable.

The aging effects identified in the LRA for yard structures (condensate storage tank foundation,

fire service pumphouse, electrical manhole MH-2, electrical substation and transformer area)

are consistent with industry operating experience for the materials and environments listed. 

The staff finds that all the plausible aging effects were identified and that the aging effects listed

are appropriate for the combination of materials and environments specified. On the basis of its

review, the staff finds that the AMPs credited in the LRA for the yard structures will effectively

manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.5.2.4.5 Earthen Embankments

Summary of Technical Information in the Application
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The applicant presented its AMR results for earthen embankments in LRA Table 3.5-1, AMR

Item 18. The plant-specific AMR is presented in LRA Table 3.5-2, AMR Item 10. Detailed

documentation of the applicant’s AMR for earthen embankments is contained in Report

TR00170-003, Revision 0, Attachment II, page 69.

A brief description of the earthen embankments is provided in LRA Section 2.4.2, “Other

Structures.” The material is identified as “earthen” and the environments are raw water, belowgrade and external.

Aging Effects:

Report TR00170-003, Revision 0, Attachment II identifies the following applicable aging effects

for earthen embankments:

• loss of material/erosion

• cracking/settlement

Aging Management Programs:

Report TR00170-003, Revision 0, Attachment II credits the following AMPs with managing the

identified aging effects for earthen embankments:

• Maintenance Rule Structures Program

• Service Water Pond Dam Inspection Program (North Dam, South Dam, East Dam,

and West Embankment)

A description of these AMPs is provided in LRA Appendix B. The applicant concluded that the

effects of aging associated with earthen embankments will be adequately managed by these

AMPs such 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).

Staff Evaluation

The staff reviewed the information in Sections 2.4 and 3.5 of the LRA; Report TR00170-003,

Revision 0, Attachment II; and the applicable AMP descriptions in Appendix B of the LRA, to

determine whether the applicant has demonstrated that the aging effects associated with

earthen embankments will be adequately managed during the period of extended operation.

In the initial review of the applicant’s AMR for earthen embankments, the staff determined that

the applicant has identified the appropriate material and aging effects, and has credited

appropriate AMPs to manage aging. The staff did not issue any RAIs related to earthen

embankments. The detailed staff review of the Maintenance Rule Structures Program is in

Section 3.0.3.4 of this SER. The detailed staff review of the Service Water Pond Dam

Inspection Program is in Section 3.5.2.3.9 of this SER. 

The aging effects identified in the LRA for the earthen embankments are consistent with

industry operating experience for the materials and environments listed. The staff finds that all

the plausible aging effects were identified and that the aging effects listed are appropriate for
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the combination of materials and environments specified. On the basis of its review, the staff

finds that the AMPs credited in the LRA for the earthen embankments will effectively manage or

monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended functions will be maintained consistent

with the current licensing basis for the period of extended operation, as required by 10 CFR

54.21(a)(3).

3.6 Electrical and Instrumentation and Controls

The applicant described its AMR of electrical and instrumentation and controls components

requiring AMR in Section 3.6 of the LRA. The staff reviewed this section of the application to

determine whether the applicant has demonstrated that the effect of aging on the electrical and

instrumentation and controls components will be adequately managed during the period of

extended operation, as required by 10 CFR 54.2(a)(3).

3.6.1 Summary of Technical Information in the Application

The applicant has performed an AMR on the following electrical and I&C commodity groups:

 non-EQ insulated cables

 non-EQ connectors

 non-EQ spices

 non-EQ terminal blocks

 high voltage electrical switchyard bus

 high voltage transmission conductors and connections

 high voltage insulators

The AMR methodology for the electrical discipline for VCSNS is summarized in the following

points:

• evaluation of the electrical component commodity groups (subject to AMR) to identify

the organic materials subject to age-related degradation

• identification and evaluation of the 60-year service-limiting environmental parameters for

these organic materials

• identification and evaluation of the aging mechanisms and effects to determine which

require review

• identification and evaluation of the service conditions (i.e., the operating environments

and locations) for the electrical component commodity groups

• evaluation of the industry and plant-specific operating experience for the electrical

component commodity groups
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• aging management program evaluation (following NUREG-1801)

• demonstration of aging management

The review of the VCSNS electrical component commodity groups with respect to aging

mechanisms and effects was performed based upon the guidance of various industry

documents, primarily SAND 96-0344, "Aging Management Guideline for Commercial Nuclear

Power Plants — Electrical Cable and Terminations." This document provides detailed

materials analysis for cable and termination materials exposed to nuclear power plant

environments. It also provides guidance for performing AMRs pursuant to 10 CFR Part 54. 

The methodology used for the AMR of the electrical commodity groups employs the “Plant

Spaces” approach in which the plant is segregated into areas (or spaces) where common

bounding environmental parameters can be assigned. The VCSNS plant operating

environments are delineated as “Environmental Zones.” Each bounding environmental zone is

evaluated against the material of the commodity groups most susceptible to aging to determine

if the components will be able to maintain their intended function through the period of extended

operation. With respect to the electrical components, the environmental parameters of interest

are temperature, radiation, and moisture. 

The intended functions of the electrical component commodity groups under review are as

follows:

• to electrically connect or insulate two sections of an electrical circuit and/or to provide for

continuity or insulation of electrical circuits

• to provide a leak-tight barrier for containment isolation (this is evaluated in Section

2.4.1.3 of the LRA)

The applicant’s AMRs included an evaluation of plant-specific and industry operating

experience. The plant-specific evaluation included reviews of condition evaluation reports and

discussions with appropriate site personnel to identify aging effects that require management. 

These reviews concluded that no additional aging effects requiring management were identified

beyond those identified using the methods described in Section 3.6.2.1 of the LRA.

The applicant’s review of industry operating experience included an evaluation of industry

operating experience since the publication of NUREG-1801 to identify any additional aging

effects requiring management. No additional aging effects requiring management were

identified beyond those identified using the methods described in Section 3.6.2.1 of the LRA.

The applicant’s ongoing review of plant-specific and industry-wide experience is conducted in

accordance with the plant Operating Experience Program.

3.6.2 Staff Evaluation

In Section 3.6 of the LRA, the applicant describes its AMR for electrical and I&C systems at

VCSNS. The staff reviewed LRA Section 3.6 to determine whether the applicant has provided
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sufficient information to demonstrate that the effects of aging will be adequately managed so

that the intended functions will be maintained consistent with the CLB throughout the period of

extended operation, in accordance with the requirement of 10 CFR 54.21(a)(3), for electrical

and I&C system components that are determined to be within the scope of license renewal and

subject to an AMR.

The applicant referenced the GALL Report in its AMR. The staff has previously evaluated the

adequacy of the aging management of electrical and I&C system components for license

renewal as documented in GALL Report. Thus, the staff did not repeat its review of the matters

described in the GALL Report, except to ensure that the material presented in the LRA was

applicable, and to verify that the applicant had identified the appropriate program as described

and evaluated in the GALL Report. The staff also reviewed aging management information

submitted by the applicant that was different from that in the GALL Report or was not

addressed in the GALL Report. Finally, the staff reviewed the FSAR supplement to ensure that

it provided an adequate description of the programs credited with managing aging for the

electrical and I&C system components.

Table 3.6-1 below provides a summary of the staff’s evaluation of components, aging

effects/mechanisms, and AMPs listed in LRA Section 3.6 that are addressed in the GALL

Report.

Table 3.6-1: Staff Evaluation Table for VCSNS Electrical Components Evaluation in the GALL Report

Component Group Aging Effect/Mechanism AMP in GALL Report AMP in

LRA

Staff Evaluation

Electrical equipment subject

to 10 CFR 50.49 EQ

requirements

Degradation due to various

aging mechanisms

Environmental

qualification of

electrical components

B.3.1 TLAA, See

Section 4.4 of the

SER

Electrical cables and

connections not subject to 

10 CFR 50.49 EQ

requirements

Embrittlement, cracking,

melting, discoloration,

swelling, or loss of dielectric

strength leading to reduced

insulation resistance (IR);

electrical failure caused by

thermal/thermoxidative

degradation of organic;

radiolysis and photolysis

(ultraviolet [UV] sensitive

materials only) of organic;

radiation-induced oxidation;

moisture intrusion

Aging management

program for electrical

cables and

connections not

subject to

 10 CFR 50.49 EQ

requirements 

B.2.9 Not consistent

with GALL (See

Section 3.6.2.3.1

below.)

Electrical cables used in

instrumentation circuits not

subject to 10 CFR 50.49 EQ

requirement that are

sensitive to reduction in

conductor resistance

Embrittlement, cracking,

melting, discoloration,

swelling, or loss of dielectric

strength leading to reduced

IR; electrical failure caused by

thermal/thermoxidative

degradation of organic;

radiation-induced oxidation;

moisture intrusion 

Aging management

program for electrical

cables used in

instrumentation

circuits not subject to 

10 CFR 50.49 EQ

requirements

B.2.9 Non-GALL

program

(See Section

3.6.2.3.2 below.)
Table 3.6-1: Staff Evaluation Table for VCSNS Electrical Components Evaluation in the GALL Report

Component Group Aging Effect/Mechanism AMP in GALL Report AMP in

LRA

Staff Evaluation

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Inaccessible mediumvoltage (2 kV to 15 kV)

cables (e.g., installed in

conduit or direct buried) not

subject to 10 CFR 50.49 EQ

requirements

Formation of water trees,

localized damage leading to

electrical failure (breakdown

of insulation); water trees

caused by moisture intrusion

Aging management

for inaccessible

medium-voltage

cables not subject to

10 CFR 50.49 EQ

requirements

No AMP

required

See Section

3.6.2.3.3 below

Electrical connectors not

subject to 10 CFR 50.49

requirements that are

exposed to borated water

leakage

Corrosion of connector

contact surfaces caused by

intrusion of borated water

Boric acid corrosion B.1.2 Consistent with

GALL (See

Section 3.6.2.3

below.)

3.6.2.1 Aging Management Evaluation in the GALL Report That Are Relied On for License

Renewal That Do Not Require Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL does not recommend further evaluation, the staff sampled

components in these groups to determine whether the plant-specific components contained in

these GALL component groups were bounded by the GALL evaluation. The staff also sampled

component groups to determine whether the applicant had properly identified those component

groups in GALL that were not applicable to its plant. The staff also identified several areas

where additional information or clarification was needed. The staff's evaluation of applicant’s

responses to those RAIs are included in Sections 3.6.2.3.1, 3.6.2.3.2, and 3.6.2.3.3 of this

SER. 

On the basis of its review, the staff has verified the applicant’s claim of consistency with the

GALL Report. The staff finds 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 current licensing basis for the period of extended operation, as

required by 10 CFR 54.21(a)(3).

3.6.2.2 Aging Management Evaluations in the GALL Report That Are Relied On For License

Renewal For Which GALL Recommends Further Evaluation

For component groups evaluated in GALL for which the applicant has claimed consistency with

GALL, and for which GALL recommends further evaluation, the staff reviewed the applicant's

evaluation to determine whether it adequately addressed the issues for which GALL

recommended further evaluation. In addition, the staff sampled components in these groups to

determine whether the plant-specific components contained in these GALL component groups

were bounded by the GALL evaluation.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 
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Environment qualification is a TLAA as defined in 10 CFR 54.3. TLAAS are required to be

evaluated in accordance with 10 CFR 54.21(c)(1). The staff reviewed the evaluation of this

TLAA separately in Section 4.4 of this SER, following the guidance in Section 4.4 of the SRPLR.

3.6.2.3 Aging Management Programs for Electrical and Instrumentation and Controls

Components

In SER Section 3.6.2.1, the staff determined that the applicant’s AMRs and associated AMPs

will adequately manage component aging in electrical and I&C systems. The staff then

reviewed specific electrical and I&C components to ensure that they were properly evaluated in

the applicant’s AMR.

To perform this review, the staff reviewed the components listed in LRA Tables 2.5-1, 2.5-2,

and 2.5-3 to determine whether the applicant has properly identified the applicable AMRs and

AMPs needed to adequately manage the aging effects for the components. This portion of the

staff review involved identification of the aging effects for each component, ensuring that each

aging effect was evaluated using the appropriate AMR in Section 3, and that management of

the aging effect was captured in the appropriate AMP. The results of the staff’s review are

provided below.

The staff also reviewed the FSAR supplement for the AMPs credited with managing aging in

electrical and I&C system components to determine whether program descriptions adequately

describe the programs.

The applicant credits two AMPs to manage the aging effects associated with electrical and I&C

components. One of these AMPs is credited to mange aging for components in other system

group (common AMPs), while the other AMP is credited with managing aging only for electrical

and I&C components. The staff’s evaluation of the common AMP credited with managing aging

in electrical and I&C components is provided in Section 3.0.3 of this SER. The common AMP is

Boric Acid Corrosion Surveillance, SER Section 3.0.3.1.

The staff’s evaluation of the electrical and I&C component system AMP is provided here.

3.6.2.3.1 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Summary of Technical Information in the Application

Non-EQ Insulated Cables:

The applicant stated that non-EQ insulated cables include power cables, control cables, and

instrument cables. For VCSNS, the applicant defines these applications to be at the following

voltage levels:

• low voltage cables — 480 VAC, 240/120 VAC, 125 VDC (and less)

• medium voltage cables — 7.2 kV

• high voltage cables — greater than 7.2 kV (none in scope)
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In order to facilitate the review of the cables at VCSNS, the applicant places cables into two

categories — power cable and I&C cable. The power cable category includes all 7.2 kV cables

and the 480 VAC power cables. The I&C category includes the 480 VAC control cable, all

240/120 VAC cable, and all DC cables (125 VDC and less). Depending upon their application,

cables utilized as switchboard wire are placed into one of these two categories, typically as I&C

cable. The applicant indicated that VCSNS purchased nearly all of its electric power cable,

control cable, and instrument cable (with the exception of certain communication cables, cables

ordered for specific non-safety applications, and special cables ordered subsequently for

specific modifications) to 10 CFR 50.49 harsh EQ standards. 

The worst case cable insulation possible in application used in license renewal is polyethylene

with a 60 year service limiting temperature of 131 °F. The non-EQ insulated cables will be

subject to an AMP as described in Table 3.6.1.

Non-EQ Electrical Connectors:

The applicant stated that cable connections are used to connect the cable conductors with

other cables or with a variety of electrical devices (e.g., instruments, motors, etc.). The various

types of insulated cable connections (or terminations) are identified in the Cable Aging

Management Guideline (AMG). The Cable AMG describes the cable termination grouping as

follows:

• compression connectors

• fusion connectors

• plug-in/multi-pin connectors

The applicant reviewed a variety of plant documents to identify electrical connectors in use at

VCSNS, including procurement records, plant drawings, EQ binders, and plant maintenance

documents. This review provided reasonable assurance that all types of connectors have been

identified and that the bounding materials for the connectors at VCSNS have also been

identified. Connectors are included in the Non-EQ Insulated Cables and Connections

Inspection Program.

Non-EQ Electrical Splices:

The applicant stated that many of the splices at VCSNS are delineated in a calculation which

identifies all safety-related (Class 1E) 7.2 kV and 480V splices in the plant. The building of

material table for the electric cables lists common splice and tape materials ordered for VCSNS

during plant construction. The identification of VCSNS splices included a review of EQ

documentation, procurement records, and design basis documents. This review provided 

reasonable assurance that all splice types and materials applicable to VCSNS (which may be

subject to AMR) have been identified. Non-EQ splices are included in the Non-EQ Insulated

Cables and Connections Inspection Program.

Non-EQ Terminal Blocks:

A terminal block consists of an insulating base with fixed metallic points for landing wires

(conductors) or for connecting terminal rings (lugs). Terminal blocks are typically installed in an

enclosure such as a control board, motor control center (MCC) , motor, terminal box, or a
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panel. A complete list of the specific terminal blocks used at VCSNS does not exist in one file

or location; however, a review of the Bills of Material and other plant documents (EQ files, etc.)

for general electrical equipment revealed that the following suppliers have terminal blocks in

use at VCSNS — GE, Kulka, Marathon, States, and Weidmuller. From the Cable AMG, the

most common materials used in the insulating base are phenolic, melamine resin, and nylon. 

The material with the least thermal and radiation resistance is nylon. Because there is no

single document that lists all terminal block manufacturers, materials, and locations for VCSNS,

nylon was chosen as the bounding material for the evaluation of the terminal blocks, due to its

limited radiation resistance. By choosing nylon as the limiting material with respect to the plant

environmental conditions, there is reasonable assurance that the terminal blocks at VCSNS are

properly evaluated with respect to aging. Non-EQ terminal blocks are included, as appropriate,

in the Non-EQ Insulated Cables and Connections Inspection Program.

Staff Evaluation

Aging Effects:

In Table 3.6-1, the applicant identified embrittlement, cracking, melting, discoloration, swelling,

or loss of dielectric strength leading to reduced insulation resistance (IR), electrical failure

caused by thermal/thermoxidative degradation of organics, radiolysis and photolysis (ultraviolet

[UV] sensitive materials only) of organics, radiation-induced oxidation, and moisture intrusion

are the aging effects of cables and connections due to heat or radiation. The staff concurs with

the aging effects identified by the applicants. These aging effects are consistent with the aging

effects identified by the staff in the GALL Report. 

The aging effects identified in the LRA for the electrical cables and connections not subject to

10 CFR 50.49 environmental qualification requirements are consistent with industry operating

experience for the materials and environments listed. The staff finds that all the plausible aging

effects were identified and that the aging effects listed are appropriate for the combination of

materials and environments specified.

Aging Management Programs:

The applicant stated that the Non-EQ Insulated Cables and Connections Inspection Program is

consistent with GALL AMP XI.E1, “Electrical Cables and Connections Not Subject to 10 CFR

50.49 Environmental Qualification Requirements.” However, having evaluated the applicant’s 

Non-EQ Insulated Cables and Connections Inspection Program, the staff found that the

applicant’s AMP did not agree with the GALL XI.E1 AMP. The staff requested the applicant to 

explain how the applicant’s AMP is consistent with the GALL XI.E1 AMP (RAI 3.6-1). 

In a letter dated March 10, 2003, the NRC forwarded to the Nuclear Energy Institute (NEI) and

Union of Concerned Scientists an interim staff guidance (ISG)-5 on the identification and

treatment of electrical fuse holders for license renewal (ADAMS Accession Number

ML030690512). The staff position indicated that fuse holders should be scoped, screened, and

included in the AMR in the same manner as terminal blocks and other types of electrical

connections that are currently being treated in the process. This position only applies to fuse

holders that are not part of a larger assembly such as switchgear, power supplies, power

inverters, battery chargers, circuit boards, etc. Fuse holders in these types of active
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components would be considered to be piece parts of the larger assembly and not subject to an

AMR.

Operating experience as discussed in NUREG-1760 (Aging Assessment of Safety-Related

Fuses Used in Low- and Medium-Voltage Applications in Nuclear Power Plants) identified that

aging stressors such as vibration, thermal cycling, electrical transients, mechanical stress,

fatigue, corrosion, chemical contamination, or oxidation of the connections surfaces can result

in fuse holder failure. The staff requested the applicant to provide details of AMR for fuse

holders as discussed in the ISG-5 (RAI 3.6-5).

In response to the staff request, in a letter dated June 12, 2003, the applicant stated that

Section B 2.9 of the LRA has been revised to (1) clarify the consistency of the VCSNS AMP to

the XI.E1 program as identified in NUREG-1801, and (2) incorporate the AMP for fuse holders. 

Based upon the issuance of ISG-5, in-scope, non-EQ, passive fuse holders will be included

within the same commodity group as terminal blocks. This commodity is in the cables and

connections commodity group of NEI 95-10. Fuse holders will be specifically included in

scoping, screening, and AMR methodology, and will be handled in a manner consistent with

ISG-5. In addition to the visual inspection of in-scope, passive fuse holders on a 10-year

periodicity for indication of age related degradation, the metallic fuse clip portion of the inscope, passive fuse holders that are found to be susceptible to age-related degradation through

the AMR process, will receive a continuity check or will undergo thermography or other

appropriate test on a representative sample basis to assure that the metallic fuse flip is still

making a good connection. This will serve to give additional assurance that evidence of age

related degradation from fatigue, mechanical stress, vibration, chemical contamination, and

corrosion will be discovered prior to a loss of intended function. The staff found the applicant’s

response acceptable because it revised the VCSNS AMP to be consistent the GALL XI.E1

program, clarified the differences between the two AMPs, and included aging management for

the fuse holders.

The staff evaluated the revised B.2.9 AMP. The evaluation of the applicant’s AMP focused on

program elements rather than the details of specific plant procedures. To determine whether

the applicant AMP is adequate to manage the effect of aging so that the intended function will

be consistent with CLB for the period of extended operation, the staff evaluated the following

seven elements — (1) scope of program, (2) preventive action, (3) parameter monitored or

inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance criteria,

and (7) operating experience. The staff’s evaluation of the applicant’s corrective action,

confirmation process, and administrative controls is provided separately in Section 3.0.4 of the

SER.

[Program Scope] The specific non-EQ insulated cables and connections that will be included in

the AMP for VCSNS include accessible non-EQ insulated cables and connections, including

splices, terminal blocks, and fuse holders, that are found susceptible to potential degradation in

adverse thermal and radiological areas of the plant. Selection of the areas to be inspected shall

include considerations for circuits with potentially significant ohmic heating. While certain areas

of the intermediate and auxiliary buildings will be the focus, there will be flexibility to inspect

cables and connections in a variety of environmental zones, as determined by the responsible

electrical engineering group at VCSNS. The technical basis for the location selected will be

documented and will consider both thermally and radiologically adverse environments, as well

as considerations such as ohmic heating, vibration, mechanical stress for fuse clips, etc. 
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Passive, non-EQ fuse holders located outside of active devices that have been identified as

being susceptible to aging effects in the AMR will be considered within the scope of this

program. Equipment and components located inside an active device or panel are not within

the scope of this program. An active device is characterized as an assembly or enclosure

made up of parts or subcomponents built to perform a specific function. Examples of active

devices include switchgear, MCCs, power supplies, inverters, battery chargers, control panels,

and equipment racks. The staff considers the scope of the program acceptable because it

includes all cables and connections that are subject to potentially adverse localized

environments that can result in applicable aging effects on these cable and connections.

[Preventive Actions] No actions are taken as a part of the Non-EQ Insulated Cables and

Connections Inspection Program to prevent aging effects or to mitigate aging degradation, and

the staff did not identify the need for such actions. 

[Parameters Monitored or Inspected] The parameters to be inspected as a part of the Non-EQ

Insulated Cables and Connections Inspection Program include visual evidence of cable jacket

or connection surface abnormalities such as embrittlement, cracking, swelling, discoloration,

surface contamination, presence of standing water or moisture, or any other visible evidence of

age-related degradation, which may lead to loss of the intended function. The metallic fuse clip

portion of any in-scope, passive fuse holders found to be susceptible to aging effects will be

additionally monitored due to aging stressors such as vibration, thermal cycling, electrical

transients, mechanical stress, fatigue, corrosion, chemical contamination, or oxidation of the

connecting surfaces. In this AMP, thermography, contact resistance testing, or other

appropriate tests will be used to identify any existence of aging degradation for these fuse clips. 

These parameters will be monitored or inspected on a representative sample basis. The

technical basis for the sample selected will be documented. The staff found the approach

acceptable because visual inspection provides means for monitoring the applicable effects for

in-scope insulated cables and connections. Testing/thermography provides means for

monitoring the applicable aging effects for metallic portions of fuse holders. 

[Detection of Aging Effects] The Non-EQ Insulated Cables and Connections Inspection

Program, conducted in the thermally and radiologically severe areas of the plant containing inscope cables and connections will serve to detect degradation of cable and connections, which

could ultimately lead to electrical failure. During each inspection, visual evidence of jacket or

surface abnormalities such as embrittlement, cracking, swelling, discoloration, melting,

degradation of organics, radiation-induced oxidation, and moisture intrusion will be evaluated.

The inspection program will be initially performed prior to the period of extended operation and

then at 10-year intervals thereafter. Identified fuse holders within the scope of license renewal

that are located outside of an active device or panel and found to be potentially susceptible to

age related degradation will likewise be inspected/tested at least once every 10 years

commencing prior to the period of extended operation. The staff found that the inspection

technique for accessible non-EQ cables and connections is acceptable on the basis that (1) the

AMP is focused on detecting change in material properties of the conductor insulation, which is

the applicable aging effect when cables and connections are exposed to adverse, localized

environment and (2) testing will detect aging degradation of metallic portions of fuse holders. 

[Monitoring and Trending] Trending actions are not included as a part of this program because

the ability to trend inspection results is limited. Documentation of these inspections will be

available in subsequent inspections for comparison, review, and evaluation. Although not a
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requirement, test and inspection results that are trendable may provide additional information

on the rate of degradation. The staff found absence of trending acceptable because the ability

to trend inspection results is limited and the staff did not see a need for such activities. 

[Acceptance Criteria] The Non-EQ Insulated Cables and Connections Inspection Program

consists of visual inspections for degradation of cable and connections jackets and surfaces

due to aging. The accessible cables and connections are to be free from unacceptable visual

indications of surface anomalies, which suggest that conductor insulation or connection

degradation exists. Acceptance criteria are based on the cable and connection insulation

service life. The service life evaluation of the insulation material includes consideration of the

material’s mechanical and electrical properties and their performance in ambient environments

under plant operational conditions of temperature, radiation, and humidity, as well as ohmic

heating effects. The results of the Non-EQ Insulated Cables and Connections Inspection

Program will serve as input into the service life evaluation of the cable and connections. An

unacceptable inspection indication is defined as a noted condition or situation that, if left

unmanaged, could lead to a loss of the intended function. The acceptance criteria for each test

performed on the fuse clip portion of in-scope, passive, non-EQ fuse holders susceptible to

age-related degradation is defined by the specific type of test performed. The staff found

these acceptance criteria acceptable because they should ensure that the cables and

connections intended functions are maintained under all CLB design conditions for the period of

extended operation.

[Operating Experience] Industry experience has shown that adverse localized environments

caused by heat or radiation for electrical cables and connections may exist next to or above

(within 3 feet of) steam generators, pressurizer, or hot process pipes, such as feedwater lines.

These adverse localized environments have been found to cause degradation of the insulating

materials on electrical cables and connections that is visually observable, such as color

changes or surface cracking. These visual observations can be used as indicators of potential

degradation. The staff found that the proposed AMP will detect the adverse localized

environment caused by heat, radiation, or moisture of electrical cables and connections. 

FSAR Supplement: The applicant needs to provide a summary description of a revised non-EQ

cables and connections AMP as required by 10 CFR 54.21(d), to be added in the FSAR

supplement in Appendix A of the LRA. By letter dated September 2, 2003, the applicant

provided a summary description of the revised non-EQ cables and connections AMP in Section

18.2.18, Appendix A to the LRA. With this revision, the staff concludes that the FSAR

supplement provides an adequate summary of program activities as required by 10 CFR

54.21(d). 

On the basis of its review, the staff finds that the AMP credited in the LRA for the electrical

cables and connections not subject to 10 CFR 50.49 environmental qualification requirements

will effectively manage or monitor aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds 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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3.6.2.3.2 Electrical Cables and Connections Not Subject to 10 CFR50.49 Environmental

Qualification Requirement Used in Instrumentation Circuits

Summary of Technical Information in the Application

The applicant stated that the Non-EQ Insulated Cables and Connections Inspection Program

will be consistent with GALL Program XI.E2, "Electrical Cables Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits" and will have the

following clarification:

The calibration of instrumentation circuits as a means to detect age-related degradation of cable insulation as

identified in XI.E2 is not included in the VCSNS program. The visual inspection of instrument as well as power

and control cables is considered a better means to identify age-related degradation due to localized ambient

thermally and radiologically indued stress prior to loss of intended function. The cables addressed by XI.E2 are

therefore bounded by the XI.E1 cable AMP.

Staff Evaluation

The applicant stated that the calibration of instrumentation circuits as a means to detect agerelated degradation of cable insulation as identified in GALL Program XI.E2 is not included in

the VCSNS program. The visual inspection of instrument, as well as power and control, cables

is considered a better means to identify age-related degradation due to localized ambient

thermally and radiologically indued stress prior to loss of intended function. The cables

addressed by XI.E2 are therefore bounded by the XI.E1 cable AMP.

The staff is not convinced that aging of these cables will initially occur on the outer jacket

resulting in sufficient damage that visual inspection will be effective in detecting the degradation

before IR losses lead to a loss of its intended function, particularly if the cables are also

subjected to moisture. Therefore, the staff requested the applicant to provide a technical

justification that will demonstrate that visual inspection will be effective in detecting damage

before current leakage can affect instrument loop accuracy or propose an alternate aging

management activity (RAI 3.6-2). In response to the staff’s above concern, the applicant, in a

letter dated June 12, 2003, stated that VCSNS will establish a GALL-type program for relevant,

non-EQ, in-scope I&C cables with sensitive, low-level signals for the nuclear instrumentation

(NI) and radiation monitoring (RM) systems. The program will use the guidance of the GALL

program as well as considering the proposed changes to the GALL program as has recently

been presented to the NRC in meetings with the License Renewal Electrical Working Group

(LREWG). A description of this new program is considered consistent with NUREG-1801

Program XI.E2. For those relevant, non-EQ, in-scope I&C cables with sensitive, low-level

signals for which the cable is not specifically included in the loop calibration process, an

“Alternate XI.E2” program is being reviewed by the LREWG. It is the applicant’s intention to

consider implementation of an alternate program, when appropriate, after the industry finalizes

the approach. 

Aging Effects:

In Table 3.6-1, the applicant identified embrittlement, cracking, melting, discoloration, swelling,

or loss of dielectric strength leading to reduced IR, electrical failure caused by

thermal/thermoxidative degradation of organic, radiation-induced oxidation, and moisture
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intrusion. The staff agrees with the scope of the aging effects identified by the applicant. These

aging effects are consistent with the aging effects identified by the staff in the GALL Report.

The aging effects identified in the LRA for the electrical cables and connections not subject to

10 CFR 50.49 EQ requirements used in instrumentation circuits are consistent with industry

operating experience for the materials and environments listed. The staff finds all the plausible

aging effects were identified and that the aging effects listed are appropriate for the

combination of materials and environments specified.

Aging Management Programs:

The staff evaluated the proposed XI.E2 and alternate XI.E2 AMP. The evaluation of the

applicant’s AMP focused on program elements rather than the details of specific plant

procedures. To determine whether the applicant AMP is adequate to manage the effect of

aging so that the intended function will be consistent with CLB for the period of extended

operation, the staff evaluated the following seven elements — (1) scope of program, (2)

preventive action, (3) parameter monitored or inspected, (4) detection of aging effects, (5)

monitoring and trending, (6) acceptance criteria, and (7) operating experience. The staff’s

evaluation of the applicant’s corrective action, confirmation process, and administrative controls

is provided separately in Section 3.0.4 of the staff’s SER.

XI.E2 Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements

Used In Instrumentation Circuits

[Program Scope] This program applies to electrical cables used in circuits with sensitive, high

voltage, low-level signals. At VCSNS, this includes radiation monitoring and nuclear

instrumentation cables. The staff found the scope of the program acceptable because these

cables are part of the calibration program and are sensitive low-level signal, that are subject to

potentially adverse localized environments.

[Preventive Actions] No actions are taken as part of this program to prevent or mitigate aging

degradation and the staff did not identify the need for such actions.

[Parameters Monitored or Inspected] The parameters monitored are determined from the

specific calibrations or surveillances performed and are based on the specific instrumentation

circuit under surveillance or being calibrated, as documented in the calibration or surveillance

procedures. The staff found this approach to be acceptable because it provides a means for

monitoring the aging effects of the non-EQ electrical cables used in instrumentation circuits.

[Detection of Aging Effects] Review of calibration results or findings of surveillance programs

can provide indication of aging effects by monitoring key parameters and providing data based

on acceptance criteria related to instrumentation circuit performance. Reviews of results

obtained during normal calibrations or surveillances provide reasonable assurance that severe

aging degradation will be detected prior to loss of the cable’s intended function. The first

reviews for license renewal are to be completed before the period of extended operation and

every 10 years thereafter. All calibrations or surveillances that fail to meet acceptance criteria

will be reviewed at the time of surveillance. The staff found this to be acceptable because the

reviews of calibration or surveillance that fail to meet the acceptance criteria will provide
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reasonable assurance that age-related degradation of the cable will be detected prior to loss of

cable’s intended function. 

[Monitoring and Trending] Trending actions are not included as part of this program because

the ability to trend test results is dependent on the specific type of test chosen. Although not a

requirement, test results that are trendable provide additional information on the rate of

degradation. The staff found the absence of trending to be acceptable because the ability to

trend test results is dependent on the specific type of test chosen.

[Acceptance Criteria] Calibration results or findings of surveillances are to be within the

acceptance criteria, as set out in the calibration or surveillance procedures. The staff found the

acceptance criteria acceptable because surveillance activity as set out in the plant technical

specifications should ensure that the cable’s intended functions used in instrumentation circuits

are maintained under all CLB design conditions during the period of extended operation.

[Operating Experience] Changes in instrument calibration data can be caused by degradation

of the circuit cable and are a possible indication of potential electrical cable degradation. The

applicant did not address the operating experience at VCSNS or industry operating experience. 

The staff requested the applicant to address this element. The applicant responded, in a letter

dated September 2, 2003, that the VCSNS XI.E2 program is a new program for which there is

no operating experience. An examination of plant CERs since 1998 shows that there were two

cases of radiation monitor for ratemeter problems attributed to cable failures at the ratemeter in

the cabinet. One failure was due to moisture on the cable and the other failure was due to

proximity to an electrical field. These instances were not due to cable age-related causes. The

staff found the applicant’s response acceptable because it addresses the operating experience

attribute.

 

Alternate XI.E2 Non-EQ Electrical Cables Used in Instrumentation Circuits

[Program Scope] This program applies to electrical cables used in circuits with sensitive, high

voltage, low-level signals. At VCSNS, this includes radiation monitoring and nuclear

instrumentation cables. It was not clear to the staff which radiation monitoring and nuclear

instrumentation cables are included in the alternate XI.E2 program. The staff requested the

applicant to identify which cables will be included in the Alternate XI.E2 program. In response

to the staff request, in a letter dated September 2, 2003, the applicant stated that cables for

Victoreen steam line high range radiation monitor and for the source, intermediate, and power

range neutron detector, fall under the Alternate XI.E2 program. The staff finds that applicant’s

response acceptable because it identified the scope of cables used in the alternate XI.E2

program and these cables are not part of the calibration program. 

[Preventive Actions] No actions are taken as part of this program to prevent or mitigate aging

degradation and the staff did not identify the need for such actions.

[Parameters Monitored or Inspected] The parameters monitored include dielectric strength

caused by thermal/thermoxidative degradation of organics or radiation-induced oxidation

(radiolysis) of organics. The staff found this approach to be acceptable because loss of

dielectric strength will lead to reduced insulation resistance.
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[Detection of Aging Effects] Cables will be tested at least once every 10 years. Testing may

include insulation resistance tests, time domain reflectometry (TDR) tests, I/V testing, or other

testing judged to be effective in determining cable insulation condition. Following issuance of a

renewed operating license, the initial test will be completed before the end of the initial 40-year

license term. The staff found the testing methods acceptable because it provides reasonable

assurance that the aging degradation will be detected prior to loss of cable intended function. 

The staff was concerned about the 10 year testing frequency. The staff requested the applicant

to provide justification of why 10 year testing frequency is adequate to detect the aging effects

of cables used in instrumentation circuits. The applicant responded, in a letter dated

September 2, 2003, that the allowance for a 10-year frequency of testing in the Alternate XI.E2

program is supported by the fact that most of the applicable cable types were procured as

Class 1E harsh environment qualified. The instrumentation cables used for in-scope, high

voltage, low signal, non-EQ circuits as covered by the XI.E2 and Alternate XI.E2 programs that

were procured as harsh qualified are acceptable to use in the harsh EQ application. The

current qualified life of these cables is being upgraded to 60 years. This gives a reasonable

assurance that a 10-year testing frequency under the Alternate XI.E2 program is acceptable. 

Based on testing performed prior to the extended period on the more susceptible cables, the

specific frequency for future testing will be established. The current commitment is to perform

this testing on a frequency no greater than 10 years. The staff finds that testing of these cables

on a frequency no greater 10 years is acceptable because these cables were procured EQ

cables which are qualified to be used in harsh environments and will be qualified to 60-year life. 

[Monitoring and Trending] Trending actions are not included as part of this program because

the ability to trend test results is dependent on the specific type of test chosen. Although not a

requirement, test results that are trendable provide additional information on the rate of

degradation. The staff found absence of trending is acceptable because the ability to trend test

results is dependent on the specific type of test chosen.

[Acceptance Criteria] The acceptance criteria for each test is defined by the specific type of

test performed and the specific cable tested. The staff found the acceptance criteria

acceptable because the specific type of test performed should ensure that cable intended

functions used in instrumentation circuits are maintained under all CLB design conditions during

the period of extended operation.

[Operating Experience] Operating experience has shown that anomalies found during cable

testing can be caused by degradation of the instrumentation circuit cable and are a possible

indication of potential cable degradation. The staff found the applicant has addressed the

operating experience applicable for this item. 

FSAR Supplement: The staff reviewed the proposed Sections 18.2.43 and 18.2.44 for the

FSAR supplement (Appendix A to the LRA) and verified that the information provided in the

FSAR supplement for the aging management of systems and components discussed above is

equivalent to the information in NUREG-1800 and therefore provides an adequate summary of

program activities as required by 10 CFR 54.21(d). 

On the basis of its review, the staff finds that the AMP credited in the LRA for the electrical

cables and connections not subject to 10 CFR 50.49 EQ requirements used in instrumentation

circuits will effectively manage or monitor the aging effects identified in the LRA.
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Conclusions

On the basis of its review, the staff finds 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).

3.6.2.3.3 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements 

Summary of Technical Information in the Application

In Table 3.6-1 of the LRA, the applicant states that formation of water trees, localized damage

leading to electrical failure (breakdown of insulation) caused by moisture intrusion and water

trees are the aging effects/mechanisms of inaccessible medium-voltage cables. However, its

AMR for medium-voltage cables exposed to moisture and voltage stressors concluded that

aging management at VCSNS was not required. The applicant stated that no instance of

power cable failure at VCSNS due to moisture intrusion were found.

Staff Evaluation

Aging Effects:

In Table 3.6-1, the applicant identified formation of water trees, localized damage leading to

electrical failure (breakdown of insulation) caused by moisture intrusion and water trees as

aging effects. The staff agrees with the scope of the aging effects identified by the applicant. 

These aging effects are consistent with the aging effects identified by the staff in the GALL

Report.

The aging effects identified in the LRA for the inaccessible medium-voltage cables not subject

to 10 CFR 50.49 EQ requirements are consistent with industry operating experience for the

materials and environments listed. The staff finds all the plausible aging effects were identified

and that the aging effects listed are appropriate for the combination of materials and

environments specified.

Aging Management Programs:

Inaccessible medium-voltage cables (2 kV -15 kV) 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 is not designed, water treeing or a decrease in the

dielectric strength of the conductor insulation can occur. This can potentially lead to electrical

failure. The growth and propagation of water trees is somewhat unpredictable. The staff

requested the applicant to provide a description of an AMP that will be relied upon to manage

the aging effects of water treeing for inaccessible medium-voltage cables (RAI 3.6-3). 

In response to the staff’s request, in a letter dated June 12, 2003, the applicant stated that

water treeing phenomenon must be addressed when relevant in-scope medium voltage

underground cables are exposed to moisture together with significant voltage. VCSNS

recognizes the potential uncertainties involved with water treeing, even with ducts that are
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sloped to preclude moisture accumulation, and will create a program consistent with NUREG1801 Program XI.E3. Relevant cables are limited to that supplying 7.2kv to the service water

pump house motors via two underground ducts using Okonite ethylene propylene rubber (EPR)

cable with a Hypalon jacket. All other underground 7.2kv cables are either out of the license

renewal scope or are energized less than 25 percent of the time. The underground ducts for

the relevant cables are sloped to provide drainage. Cable and manhole inspections have

shown indications that the relevant cables have been exposed to moisture with significant

voltage. The VCSNS program described will result in a 10-year test interval by an appropriate

industry-approved testing method selected to validate the satisfactory condition of the cable

insulation and to give some assurance of the remaining life of the cable, while not damaging the

cable itself. The specific type of test performed will be determined prior to the initial test and

will be a proven test for detecting deterioration of the cable insulation system due to wetting. 

The 10-year interval will commence prior to the start of the period of extended operation. A

new program is consistent with the NUREG-1801 Program XI.E3. 

In this AMP, periodic actions are taken to prevent or minimize the possibility that cables may be

exposed to moisture, such as inspecting for water collection in cable manholes and conduit,

and draining water, as needed. In-scope, medium-voltage cables exposed to moisture and

significant voltage are tested to provide an indication of the condition of the conductor

insulation. The initial test performed will be determined prior to the period of extended

operation, and is to be a proven test for detecting deterioration of the insulation system due to

wetted conditions at the time the test is performed.

The staff found the applicant’s response to the staff’s request acceptable because the applicant

proposed an AMP to manage the effects of water tree for inaccessible medium-voltage cables

in order to provide reasonable assurance that the intended functions of these cables will be

maintained consistent with the CLB through the period of extended operation. 

The staff evaluated the proposed AMP. The evaluation of the applicant’s AMP focused on

program elements rather than the details of specific plant procedures. To determine whether

the applicant AMP adequate to manage the effect of aging so that the intended function will be

consistent with the CLB for the period of extended operation, the staff evaluated the following

seven elements — (1) program scope, (2) preventive action, (3) parameter monitored or

inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance criteria,

and (7) operating experience. The staff’s evaluation of the applicant’s corrective action,

confirmation process, and administrative controls is provided separately in Section 3.0.4 of the

staff’s SER.

[Program Scope] The specific non-EQ medium voltage insulated cables subject to moisture

and significant voltage that will be included in the AMP for VCSNS includes the two circuits

serving the service water pump motors. These circuits are inaccessible as they are routed in

underground duct, except at electrical manholes or where they exit the duct bank, and are

medium-voltage cables within the scope of license renewal that are potentially exposed to

moisture simultaneously with significant voltage. Moisture is defined as periodic exposures to

moisture that last more than a few days (e.g., cable in standing water). Periodic exposures to

moisture that last less than a few days (i.e., normal rain and drain) are not significant. 

Significant voltage exposure is defined as being subjected to system voltage for more than 25

percent of the time. The moisture and voltage exposures described as significant in these

definitions, which are based on operating experience and engineering judgment, are not
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significant for medium-voltage cables that are designed for these conditions (e.g., continuous

wetting and continuous energization is not significant for submarine cables). The staff found

the scope of the program acceptable because it includes inaccessible medium-voltage cables

within the scope of license renewal that are exposed to significant moisture with significant

voltage.

[Preventive Actions] Periodic actions are taken to prevent or minimize the possibility that cables

may be exposed to moisture, such as inspecting for water collection in cable manholes and

conduit, and draining water, as needed. Inaccessible medium-voltage cables, which are in the

license renewal scope and subject to potential moisture with significant voltage, are to be tested

in accordance with this program since operating experience conservatively indicates that the

potential exists for exposure to sufficiently prolonged moisture and voltage, which may induce

or contribute to this aging mechanism. The staff found it acceptable because in addition to

testing of the inaccessible medium-voltage cables that are exposed to significant moisture and

voltage, the applicant will periodically inspect for water collection in cable manholes and

conduit, and draining water, as needed. 

[Parameters Monitored or Inspected] In-scope, medium-voltage cables exposed to moisture

and significant voltage will be tested to provide an indication of the condition of the conductor

insulation. The specific type of test performed will be determined prior to the initial test, and is

to be a proven test for detecting deterioration of the insulation system due to wetting. This will

be a test that will not damage the cable itself. The staff found the approach acceptable

because the 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. 

[Detection of Aging Effects] In-scope, medium-voltage cables exposed to moisture and

significant voltage are tested at least once every 10 years. This is an adequate period to

preclude failures of the conductor insulation since experience has shown that aging degradation

is a slow process. A 10-year test frequency will provide two data points during a 20-year

period, which can be used to characterize the degradation rate. The first tests for license

renewal are to be completed before the period of extended operation. The staff believes, based

on current knowledge, that aging degradation of this cabling would be due to a slow acting

mechanism, and therefore, the applicant’s proposed test schedule is acceptable.

[Monitoring and Trending] Trending actions are not included as part of this program because

the ability to trend test results is dependent on the specific type of test chosen. Although not a

requirement, test results that are trendable provide additional information on the rate of

degradation. The staff finds that the absence of trending for testing is acceptable since the test

is performed every 10 years and the staff did not see a need for such activities.

[Acceptance Criteria] The acceptance criteria for each test is defined by the specific type of

test performed and the specific cable tested. The staff finds the above acceptance criteria

acceptable on the basis that they will follow current industry standard which, when

implemented, will ensure that the license renewal intended functions of the cables will be

maintained consistent with the CLB.

[Operating Experience] The AMP for Inaccessible Medium-Voltage Cables Not Subject To 10

CRF 50.49 Environmental Qualification Requirements is a new AMP for which there is no

operating experience. The relevant in-scope cables included in this program at VCSNS are
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7.2kv cables with EPR insulation and a Hypalon jacket. Operating experience has shown that

cross-linked polyethylene (XLPE) or high molecular weight polyethylene (HMWPE) insulation

materials are most susceptible to water tree formation. The formation and growth of water

trees varies directly with operating voltage. Treeing is much less prevalent in 4kV cables than

those operated at 13 or 33kV. Also, minimizing exposure to moisture minimizes the potential

for the development of water treeing. As additional operating experience is obtained both at

VCSNS and in the industry, lessons learned will be considered as proposed enhancements to

the program so that the effects of aging will continue to be adequately managed. The staff

finds operating experience acceptable because additional operating experience will be

satisfactorily incorporated into the development of this new program.

FSAR Supplement: The staff reviewed the proposed Sections 18.2.45 for the FSAR

supplement (Appendix A to the LRA) and verified that the information provided in the FSAR

supplement for the aging management of systems and components discussed above is

equivalent to the information in NUREG-1800 and therefore provides an adequate summary of

program activities, as required by 10 CFR 54.21(d). 

On the basis of its review, the staff finds that the AMP credited in the LRA for the inaccessible

medium-voltage cables not subject to 10 CFR 50.49 EQ requirements will effectively manage or

monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds 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).

3.6.2.4 Aging Management Review of Plant-Specific Electrical Components

The applicant describes its AMR of plant-specific electrical components in Sections 3.6.1.4,

3.6.1.6, 3.6.1.7, and 3.6.1.8 of the LRA. The staff reviewed these sections of the application to

determine whether the applicant has demonstrated that the effect of aging on the electrical

components will be adequately managed during the period of extended operation as required

by 10 CFR 54.21(a)(3).

3.6.2.4.1 Non-EQ Electrical Penetration Assemblies 

Summary of Technical Information in the Application

The applicant stated that electrical penetration assemblies are utilized to carry electrical circuits

through the reactor building containment wall while maintaining pressure-tight integrity. They

provide the electrical continuity of the circuit and the pressure boundary for containment

integrity. The scope of the review in this report applies only to the electrical function of the

penetration assemblies. The pressure-retaining function of the penetration assemblies is

addressed in Section 2.4 of this application for the reactor building. All the electrical

penetrations at VCSNS have been listed in the VCSNS EQ Program, whether or not they carry

Class 1E circuits. The non-Class 1E electrical penetrations are classified as category “B1, B2”

components with respect to EQ (i.e., they must not fail and prevent the accomplishment of a

safety-related function) and are administratively included in the EQ Program in order to credit
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the portion of the EQ testing which justifies the pressure-retaining function of the penetrations. 

VCSNS utilizes D.G. O’Brien electrical penetration for its non-Class 1E applications. The D.G.

O’Brien electrical penetration assemblies are subject to AMR. This review provides for their

identification and also for the listing of the organic materials found during the review. Because

there are D.G. O’Brien electrical penetration assemblies that are part of the VCSNS EQ

Program and have been evaluated in detail for that purpose, there is reasonable assurance that

all their organic materials have been identified and properly evaluated with respect to aging for

the non-EQ installations. An additional review has shown non-EQ electrical penetrations at

VCSNS to be located in areas inside and outside of the reactor building which have less severe

environments, that are clearly enveloped by material properties and for which aging testing and

evaluation has been done through the manufacturer. The non-EQ electrical penetrations at

VCSNS are not included in the Non-EQ Insulated Cables and Connections Inspection Program. 

The component type, material, environment, and aging effects are identified in Table 3.6-2 of

the LRA. The evaluation of the non-EQ electrical penetrations at VCSNS is further documented

in Table 3.6-2 Item 2 of the LRA.

Aging Effects:

The LRA identified the following aging effects for the non-EQ electrical penetrations:

• embrittlement

• cracking

• melting

• discoloration

• swelling

• loss of dielectric strength leading to reduced insulation resistance

• electrical failure caused by thermal/thermoxidative degradation of organic

• radiolysis and photolysis (ultraviolet sensitive materials only) of organic 

• radiation-induced oxidation

• moisture intrusion

Aging Management Programs:

No AMP is required for non-EQ electrical penetration. The applicant states that a review has

shown non-EQ electrical penetrations at VCSNS to be located in areas inside and outside of

the reactor building which have less severe environments, that are clearly enveloped by

material properties and for which aging testing and evaluation has been done through the

manufacturer. Non-EQ electrical penetrations at VCSNS are not included in the Non-EQ

Insulated Cables and Connections Inspection Program.

Staff Evaluation

This section provides the results of the staff’s evaluation of the applicant’s AMR for the aging

effects and the AMPs credited for managing the aging effects in non-EQ electrical penetrations

at VCSNS. The staff also reviewed the applicable FSAR supplement for the AMPs to ensure

that the program description adequately describe the AMPs.

Aging Effects and Aging Management Programs:
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The applicant identified embrittlement, cracking, melting, discoloration, swelling, loss of

dielectric strength leading to reduced insulation resistance, electrical failure caused by

thermal/thermoxidative degradation of organics, radiolysis and photolysis (ultraviolet sensitive

materials only) of organic, radiation-induced oxidation, and moisture intrusion are the aging

effects/mechanism of non-EQ electrical penetrations. The staff agrees with the scope of aging

effects identified by the applicant. These aging effects are consistent with the aging effects

identified by the staff in the GALL Report.

The applicant stated that its review has shown non-EQ electrical penetrations at VCSNS to be

located in areas inside and outside of the reactor building which have less severe

environments, that are clearly enveloped by material properties and aging testing and

evaluation done through the manufacturer. Non-EQ electrical penetrations at VCSNS are not

included in the Non-EQ Insulated Cables and Connections Inspection Program. 

The staff was not convinced that there are no aging effects for non-EQ electrical penetration

because these penetrations are located in a less severe environment and are covered by

evaluation done by manufacturer. In most areas within a nuclear power plant, the actual

ambient environments are less severe than the nominal plant environment. However, in a

limited number of localized areas, the actual environments may be more severe than the

nominal plant environment. Insulation materials used in non-EQ electrical penetration

assemblies may degrade more rapidly than expected in these adverse localized environments. 

The staff requested the applicant to provide a description of an AMP for non-EQ electrical

penetration exposed to localized environment caused by heat, radiation, or moisture, or provide

a technical justification of why an AMP is not necessary (RAI 3.6-4). 

In response to the staff’s request, in a letter dated June 12, 2003, the applicant stated that all

VCSNS electrical penetrations are included within the VCSNS Harsh EQ Program and meet the

requirements of 10 CFR 50.49. The non-Class 1E as well as the Class 1E electrical

penetrations are considered subject to a TLAA and will be reanalyzed for a 60-year life under

the EQ Program. All electrical penetrations have a definitive long-lived qualified life assigned

within the EQ database, “HARSH EQ Maintenance Manual”, the same as all harsh EQ related

equipment. Non-Class 1E electrical penetrations were previously conservatively listed as

requiring an AMR because of their non-Class 1E status [reference LRA 3.6.1.4]. The AMR is

not required as these electrical penetrations are to receive a TLAA for consideration of a 60-

year life. There will be no AMP for electrical penetrations as these electrical penetrations have

a qualified life that is administratively controlled within the EQ Program and are screened out in

54.21(a)(1)(ii). The staff finds the applicant’s response acceptable because all electrical

penetrations are included within the EQ Program and no AMR is required.

The aging effects identified in the LRA for the non-EQ electrical penetration assemblies are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Conclusions

On the basis of its review, the staff finds 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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3.6.2.4.2 High Voltage Electrical Switchyard Bus 

Summary of Technical Information in the Application

The applicant stated that high voltage (HV) electrical switchyard bus is uninsulated, unenclosed,

rigid electrical conductor used in switchyards and switching stations to connect two or more

elements of an electrical power circuit, such as active disconnect switches and passive

transmission conductors. The review of switchyard bus included the bus itself as well as the

hardware used to secure the bus to HV insulators. The in-scope switchyard bus at VCSNS is

constructed of aluminum tubing or copper rods, and supported on station post insulators with

aluminum cast fastening hardware. For the ambient environmental conditions at VCSNS, no

significant aging effects have been identified that would cause a loss of function for the

extended period of operation. The potential effects of surface oxidation and vibration are not

considered significant for the VCSNS installation. No AMP for HV electrical switchyard bus is

required. The components, material, environment, aging effects, and program activity are

provided in LRA Table 3.6-2.

Aging Effects:

The LRA identified change in material properties leading to increased resistance and heating

due to oxidation, and cracking due to vibration are the applicable aging effects for the HV

electrical switchyard bus.

Aging Management Programs:

The applicant stated that for the ambient environmental conditions at VCSNS, no significant

aging effects have been identified that would cause a loss of function for the extended period of

operation. The potential effects of surface oxidation and vibration are not considered significant

for the VCSNS installation. The AMP for HV electrical switchyard bus is not required.

Staff Evaluation

This section provides the results of the staff’s evaluation of the applicant’s AMR for the aging

effects and the AMPs credited for managing the aging effects in HV electrical switchyard bus. 

Aging Effects:

The applicant identified change in material properties leading to resistance and heating due to

oxidation, and cracking due to vibration are the applicable aging effects for the HV electrical

switchyard bus. The aging effects identified in the LRA for the HV electrical switchyard bus are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified.

Aging Management Programs:

The applicant stated that for the ambient environmental conditions at VCSNS, no significant

aging effects have been identified that would cause a loss of function for the extended period of

operation. The potential effects of surface oxidation and vibration are not considered significant
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for the VCSNS installation. The AMP for HV electrical switchyard bus is not required. The staff

requested the applicant to explain in detail why connection surface oxidation of HV electrical

switchyard bus are not considered significant aging mechanism at VCSNS (RAI 3.6-6). In

response to the staff’s request, in a letter dated June 12, 2003, the applicant stated that at

VCSNS, the switchyard bus is comprised of copper or 5” schedule 80 aluminum tube. Organic

materials are not involved. Connections to the switchyard bus are welded. Conductor

connections are generally of the compression bolted category. The switchyard bus is located in

the yard, which is the ambient environment of the plant. The temperature ranges from a

historic low of -4 F to a high of 108 F. The environment is periodically wet (from rainfall). 

The copper and aluminum materials do not experience any appreciable aging effects in this

environment, except for minor oxidation, which does not impact the ability of the switchyard bus

to perform its design function. In order to validate aging effects, a review of industry experience

was performed. This review included NRC generic communications, LERs, and NUREGs

related to switchyard bus. No documents involving switchyard bus were identified. VCSNS

operating experience was also reviewed to validate aging effects for switchyard bus and

connections. This review included condition evaluation reports (CER) and nonconformance

notices (NCN) for any documented instances of switchyard bus aging, in addition to interviews

with responsible substation department and VCSNS engineering and maintenance personnel. 

No instance of age-related problems with in-scope switchyard bus and connections due to

contaminants or oxidation was uncovered. The staff finds the applicant’s response acceptable

because copper and aluminum materials used in HV electrical switchyard bus do not

experience any significant aging effects in the environmental conditions at VCSNS that would

cause a loss of function for the extended period of operation.

On the basis of its review, the staff finds that an AMP is not required for the HV electrical

switchyard bus to manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds 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).

3.6.2.4.3 High Voltage Transmission Conductors and Connections

Summary of Technical Information in the Application

The applicant stated that transmission conductors are uninsulated, stranded electrical cables

used in switchyards, switching stations, and transmission lines to connect two or more elements

of an electrical power circuit, such as active disconnect switches, power circuit breakers, and

transformers to passive switchyard bus. The review of transmission conductors included the

transmission conductors and the hardware used to secure the conductors to a HV insulator or

to switchyard bus. Transmission conductors are supported by passive high-voltage strain or

suspension insulators. Transmission conductors and connection hardware at VCSNS are made

of aluminum reinforced with galvanized steel. For the ambient environmental conditions at

VCSNS, no significant aging effects related to conductor corrosion or wind loading vibration or

sway on connections have been identified that would cause a loss of function for the extended

period of operation. No AMP for HV transmission conductors and connections is required. 
3-434

Aging Effects:

The LRA identified loss of conductor strength due to corrosion and wear, or fatigue due to wind

loading vibration or sway are the aging effects of HV transmission conductors and connections.

Aging Management Program:

The applicant states that for the ambient environmental conditions at VCSNS, no significant

aging effects related to conductor corrosion or wind loading vibration or sway on connections

have been identified that would cause a loss of function for the extended period of operation. 

No AMP for HV transmission conductors and connections is required. 

Staff Evaluation

This section provides the results of the staff’s evaluation of the applicant’s AMR for the aging

effects and the AMPs credited for managing the aging effects in HV transmission conductors

and connections.

Aging Effects:

The aging effects for transmission line conductors is loss of conductor strength and vibration. 

The most prevalent mechanism contributing to loss of conductor strength of an aluminum

conductor steel reinforced (ACSR) transmission conductor is corrosion, which includes

corrosion of the steel core and aluminum strand pitting. For ACSR conductors, degradation

begins as a loss of zinc from the galvanized steel core wires. Corrosion rate depend largely on

air quality, which includes suspended particles chemistry, SO2 concentration in air, precipitation,

fog chemistry, and meteorological conditions. Transmission conductor vibration would be

caused by wind loading. Wind loading can cause a transmission line and insulators to vibrate. 

Transmission conductor vibration or sway could cause loss of material (wear) and fatigue. The

applicant stated that for the ambient environmental conditions at VCSNS, no significant aging

effects related to conductor corrosion, or wind loading vibration or sway on connections have

been identified that would cause a loss of function for the extended period of operation. No

AMP for HV transmission conductors and connections is required. The staff requested the

applicant to explain in detail why no aging effects related to conductor corrosion have been

identified that would cause a loss of function for the extended period of operation (RAI 3.6-7). 

The staff also requested the applicant to explain why no significant aging effects related to wind

loading vibration or sway on HV connections has been identified at VCSNS.

In response to the staff’s request, in a letter dated June 12, 2003, the applicant cited the

following from the EPRI 1003057, License Renewal Electrical Handbook, dated December

2001: 

Regarding HV transmission conductor strength, tests performed by Ontario Hydroelectric showed a 30% loss

of composite conductor strength of an 80-year-old ACSR conductor due to corrosion. There is a set percentage

of composite conductor strength established at which a transmission conductor is replaced. As illustrated below,

there is ample strength margin to maintain the transmission conductor intended function through the extended

period of operation.

The National Electrical Safety Code (NESC) requires that tension on installed conductors be a maximum of

60% of the ultimate conductor strength. The NESC also sets the maximum tension a conductor must be
3-435

designed to withstand under various load requirements, which includes consideration of ice, wind and

temperature. These requirements were reviewed concerning the specific conductors included in the AMR. The

conductors with the smallest ultimate strength margin (4/0 ACSR) will be used as an illustration. VCSNS is in

the medium loading zone; therefore, the Ontario Hydroelectric heavy loading zone study is conservative.

The ultimate strength and the NESC heavy load tension requirements of 4/0 ACSR are 8350 lbs. and 2761 lbs.

respectively. The margin between the NESC Heavy Load and the ultimate strength is 5589 lb.; i.e., there is a

67% of ultimate strength margin. The Ontario Hydroelectric study showed a 30% loss of composite conductor

strength in an 80-year-old conductor. In the case of the 4/0 ACSR transmission conductors, a 30% loss of

ultimate strength would mean that there would still be a 37% ultimate strength margin between what is required

by the NESC and the actual conductor strength. The 4/0 ACSR conductors have the lowest initial design margin

of any transmission conductors included in the AMR. This illustrates with reasonable assurance that

transmission conductors will have ample strength through the period of extended operation. Corrosion of ACSR

conductors is a very slow acting aging effect that is even slower for rural areas with generally less suspended

particles and SO2 concentrations in the air than urban areas. 

At VCSNS, the transmission conductors are constructed of ACSR material, either 795 kcmil or

1590 kcmil. The shield wire is 3/16” high strength steel. There are no organic materials

involved and no appreciable aging effects for the transmission conductors. The connections

used for these conductors likewise have no organic materials. There are no applicable aging

effects that could cause loss of the intended function of the transmission conductors for the

period of extended operation.

Regarding wind loading vibration and sway on HV connections, wind loading that can cause a

transmission line and insulators to vibrate is considered in the design and installation. Loss of

material (wear) and fatigue that could be caused by transmission conductor vibration or sway

are found not to be applicable aging effects in that they would not cause a loss of intended

function if left unmanaged for the extended period of operation.

In order to validate aging effects, a review of industry experience was performed. This review

included NRC generic communications, LERs, and NUREGs related to transmission

conductors. No documents involving transmission conductors were identified. 

VCSNS operating experience was also reviewed to validate aging effects for transmission

conductors. This review included CERs and NCNs for any documented instances of

transmission conductor aging, in addition to interviews with responsible substation department

and VCSNS engineering and maintenance personnel. No instance of aging-related problems

with transmission conductors was uncovered.

The aging effects identified in the LRA for the HV transmission conductors and connections are

consistent with industry operating experience for the materials and environments listed. The

staff finds that all the plausible aging effects were identified and that the aging effects listed are

appropriate for the combination of materials and environments specified. 

Aging Management Program:

On the basis of its review, the staff finds that an AMP is not required for the HV transmission

conductors and connections to manage or monitor the aging effects identified in the LRA.

Conclusions
3-436

On the basis of its review, the staff finds 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).

3.6.2.4.4 High Voltage Insulators

Summary of Technical Information in the Application

The applicant stated that HV switchyard post insulators, and strain or suspension insulators as

typically used on transmission towers, are insulating materials in a form designed to (a) support

a conductor physically and (b) separate the conductor electrically from another conductor or

object. The insulators evaluated for license renewal are those used to support and insulate HV

electrical components in switchyards, switching stations, and transmissions, such as

transmission conductors and switchyard bus. HV insulators serve as an intermediate support

between a supporting structure (such as a transmission tower or support pedestal) and the

switchyard bus or transmission conductor. Materials of construction include porcelain, metal

(insulator cap and pin) and cement to join the cap or pins to the porcelain. For the ambient

environmental conditions at VCSNS, no significant aging effects related to airborne

contaminants or mechanical wear have been identified that would cause a loss of function for

the extended period of operation. No AMP for HV insulators is required.

Aging Effects:

The LRA identified surface contamination or cracking due to airborne contaminants and loss of

material due to mechanical wear are the aging effects of HV insulators. 

Aging Management Programs:

No AMP for HV insulator is required. For the ambient environmental conditions at VCSNS, no

significant effects related to airborne contaminant or mechanical wear have been identified that

would cause a loss of function for the extended period of operation.

Staff Evaluation

This section provides the results of the staff’s evaluation of the applicant’s AMR for the aging

effects and the AMPs credited for managing the aging effects in HV insulators. The staff also

reviewed the applicable FSAR supplement for the AMPs to ensure that the program

descriptions adequately describe the AMPs.

Aging Effects:

The potential aging effects for insulator are as follows:

 surface contamination

 cracking

 loss of material due to wear 

Various airborne materials such as dust, salt, and industrial effluents can contaminate insulator

surfaces. A large buildup of contamination enables the conductor voltage to track along the
3-437

surface more easily and can lead to insulator flashover. Surface contamination can be a

problem in areas where there are greater concentrations of airborne particles such as near

facilities that discharge soot or near the sea coast where salt spray is prevalent. 

Porcelain is essentially a hardened, opaque glass. As with any glass, if subjected to enough

force it will crack or break. Cracks have also been known to occur with insulators when the

cement that binds the part together expands enough to crack the porcelain. This phenomenon

is known as cement growth. 

Mechanical wear is an aging effects for strain and suspension insulators in that they are subject

to movement. Movement of the insulators can be caused by wind blowing the supported

transmission conductor, causing it to swing from side to side. If this swing is frequent enough,

it could cause wear in the metal contact points of the insulator string and between an insulator

and the supporting hardware.

In LRA Table 3.6-2, the applicant identified that surface contamination or cracking due to

airborne contaminants and loss of material due to mechanical wear are the potential aging

effects of HV insulators. However, the applicant did not explain why, for the ambient

environmental conditions at VCSNS, no significant aging effects related to airborne

contaminants or mechanical wear have been identified that would cause a loss of function for

the extended period of operation and no AMP for HV insulators is required. The staff requested

the applicant to explain why no significant aging effects were identified at VCSNS (RAI 3.6-8). 

In response to the staff request, in a letter dated June 12, 2003, the applicant stated that from

the EPRI 1003057, License Renewal Electrical Handbook, dated December 2002, the potential

for contamination of insulators, the buildup of surface contamination is gradual and in most

areas such contamination is washed away by rain; the glazed insulator surface aids this

contamination removal. A large buildup of contamination enables the conductor voltage to track

along the surface more easily and can lead to insulator flashover. Surface contamination can

be a problem in areas where there are greater concentrations of airborne particles such as near

facilities that discharge soot or near the seacoast where salt spray is prevalent. VCSNS is

located in an area with moderate rainfall where airborne particle concentrations are

comparatively low; consequently, the rate of contamination buildup on the insulators is not

significant. At VCSNS, as in most areas of the SCE&G transmission system, contamination

buildup on insulators is not a problem due to rainfall periodically “washing” the insulators. 

Additionally, there is no nearby heavy industry or other producers of industrial effluents, which

could cause excessive contamination. There is no salt spray at VCSNS as the plant is over 100

miles from the ocean. Therefore, surface contamination is not an applicable aging effect for the

insulators in the service conditions they are exposed to at VCSNS.

 

Regarding HV porcelain insulator cracking, the most common cause for cracking or breaking of

an insulator is being struck by an object (e.g., a rock or bullet). Cracking and breaking caused

by physical damage is not an aging effect and is not subject to an AMR. Cracks have been

known to occur with insulators when the cement that binds the parts together expands enough

to crack the porcelain. This phenomenon, known as cement growth, occurs mainly because of

improper manufacturing processes or materials, which make the cement more susceptible to

moisture penetration, and the specific design and application of the insulator. The string

insulators susceptible to porcelain cracking caused by cement growth are isolated to bad

batches (specific known brands and manufacture dates) of string insulators used in strain

application. The post insulators most susceptible to this aging effect are multi-cone (post)
3-438

insulators used in cantilever applications. Research of NCNs and CERs within the VCSNS

database and discussions with the substation department personnel revealed no instance of

insulator cracking or failure related to cement growth at the VCSNS switchyard. Accordingly,

cracking due to cement growth is not an applicable aging effect for the HV switchyard insulators

in the service conditions they are exposed to at VCSNS. 

Regarding mechanical wear, although this mechanism is possible, experience has shown that

the transmission conductors do not normally swing and that when they do, due to a substantial

wind, do not continue to swing for very long once the wind has subsided. Wind loading that can

cause a transmission line and insulators to vibrate or sway is considered in the design and

installation. The loss of material due to wear concern will not cause a loss of intended function

of the insulators at VCSNS; therefore, loss of material due to wear is not an applicable aging

effect for insulators.

VCSNS operating experience was reviewed to validate aging effects for switchyard insulators. 

This review included CERs and NCNs for any documented instances of switchyard insulator

aging, in addition to interviews with responsible substation department and VCSNS engineering

and maintenance personnel. No instance of aging-related problems with in-scope switchyard

insulators due to contaminants, cracking, cement growth, or mechanical wear was uncovered. 

The aging effects identified in the LRA for HV insulators are consistent with industry operating

experience for the materials and environments listed. The staff finds that all the plausible aging

effects were identified and that the aging effects listed are appropriate for the combination of

materials and environments specified.

 

Aging Management Programs:

On the basis of its review, the staff finds that an AMP is not required for transmission insulators

to manage or monitor the aging effects identified in the LRA.

Conclusions

On the basis of its review, the staff finds 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 References

1. Sandia Contractor Report SAND 96-0344, Aging Management Guideline for Commercial

Nuclear Power Plant - Electrical Cable and Terminations, prepared by Ogden Environmental

and Energy Services, Inc., printed September 1996.

2. Aging and Life Extension of Major Light Water Reactor Components, edited by V.N. Shaw

and P.E. MacDonald, 1993, Elsevier Science Publishers.

3. Electric Power Research Institute Report, EPRI TR-103834-P1-2, Effects of Moisture on the

Life of Power Plant Cables, Part 1: Medium-Voltage Cables, Part 2: Low-Voltage Cables,
3-439

prepared by Ogden Environmental and Energy Services Company, Final Report, August

1994.

3.7 Conclusion for Aging Management

On the basis of its review of AMR results and AMPS, the staff concludes that actions have been

identified and have been or will be taken to manage the effects of aging during the period of

extended operation on the functionality of SCs subject to an AMR such that there is reasonable

assurance that the activities authorized by a renewed license will continue to be conducted in

accordance with the CLB, as required by 10 CFR 54.29(a).
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4-1

4 TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section addresses the identification of time-limited aging analyses (TLAAs). The applicant

discusses the TLAAs in the license renewal application (LRA), Sections 4.2 through 4.7. The

staff’s review of the TLAAs can be found in Sections 4.2 through 4.7 of this SER. 

The TLAAs are certain plant-specific safety analyses that are based on an explicitly assumed 

40-year plant life. Pursuant to Section 54.21(c)(1) of Title 10 of the Code of Federal (CFR), the

applicant for license renewal provides a list of TLAAs, as defined in 10 CFR 54.3. 

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 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

The applicant evaluated calculations for the Virgil C. Summer Nuclear Station (VCSNS) against

the six criteria specified in 10 CFR 54.3 to identify the TLAAs. The applicant indicated that

calculations which meet the six criteria were identified by searching the current licensing basis

(CLB), which includes the updated safety analysis report (UFSAR), Technical Specifications,

engineering calculations, technical reports, docketed licensing correspondence, and applicable

Westinghouse topical reports. The applicant listed the following TLAAs in Table 4.1-1 of the

LRA:

• reactor vessel neutron embrittlement; including upper shelf energy, pressurized thermal

shock, and pressure-temperature limits

• metal fatigue; including ASME Section III Class 1 components, and ASME Section III Class

2 and 3 piping 

• environmental qualification

• concrete containment tendon prestress analysis

• containment liner and penetration fatigue analysis

• reactor coolant pump flywheel

• leak-before-break analyses

• crane load cycle limit

• service water intake structure settlement
4-2

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that no exemptions granted under 10 CFR

50.12 that were based on a TLAA as defined in 10 CFR 54.3 were identified.

4.1.2 Staff Evaluation

In LRA Section 4.1, the applicant identified the TLAAs applicable to VCSNS and discussed

exemptions based on TLAAs. The staff reviewed the information to determine whether the

applicant provided adequate information to meet the requirements of 10 CFR 54.21(c)(1) and

10 CFR 54.21(c)(2).

As indicated by the applicant, TLAAs are defined in 10 CFR 54.3 as analyses that meet the

following six criteria:

• involve systems, structures, and components within the scope of license renewal, as

delineated in Section 54.4(a)

• consider the effects of aging

• involve time-limited assumptions defined by the current operating term, for example, 40

years

• were determined to be relevant by the licensee in making a safety determination

• involve conclusions or provide the basis for conclusions related to the capability of the

system, structure, and component to perform its intended functions, as delineated in

Section 54.4(b)

• are contained or incorporated by reference in the CLB

The applicant listed the TLAAs applicable to VCSNS in Table 4.1-1 of the LRA. Tables 4.1-2

and 4.1-3 in NUREG-1800 identify potential TLAAs determined from the review of other LRAs. 

In its request for additional information (RAI) 4.1-1, the staff requested that the applicant

discuss whether there are any calculations or analyses at VCSNS that address the topics listed

in Tables 4.1-2 and 4.1-3 of NUREG-1800 and were not included in Table 4.1-1 of the LRA.

In its response dated June 12, 2003, the applicant indicated that the following items listed in

NUREG-1800, potentially applicable to PWRs, were not addressed in Section 4.0 of the LRA:

• metal corrosion allowance

• inservice flaw growth analysis that demonstrates structural stability for 40 years

• inservice local metal containment corrosion analyses

• intergranular separation in the heat-affected zone (HAZ) of reactor vessel low-alloy steel

under austenitic stainless steel cladding, low-temperature overpressure protection (LTOP)

analyses
4-3

• flow-induced vibration endurance limit, transient cycle count assumptions, and ductility

reduction of fracture toughness for the reactor vessel internals

• containment penetration pressurization cycles

The applicant indicated that VCSNS does not have any calculations or analyses that evaluate

intergranular separation of the HAZ of reactor vessel low-alloy steel under austenitic stainless

steel cladding. The applicant indicated that this issue was addressed in response to RAI

3.1.2.2.7-1. The staff evaluation of this issue is contained in Section 3.1.2.2.7 of this safety

evaluation report (SER). The applicant also indicated that the LTOP analysis is performed

when vessel specimens are analyzed and the pressure temperature curves are revised. A

discussion of this topic is contained in Section 4.2 of this SER. The applicant indicated that

VCSNS does not have any calculations or analyses that address the remaining topics. The

staff review of the VCSNS FSAR Supplement did not identify any TLAAs related to these topics. 

On the basis of the preceding discussion, the staff finds the applicant’s response to RAI 4.1-1

acceptable.

4.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable list

of TLAAs as required by 10 CFR 54.21(c)(1), and has confirmed that no 10 CFR 50.12

exemptions have been granted on the basis of a TLAA, as required by 10 CFR 54.21(c)(2).

4.2 Reactor Vessel Neutron Embrittlement

In Section 4.2 of the LRA and Section 18.3.1 of Appendix A to the LRA, the applicant provides a

discussion of its evaluation of the effects of neutron irradiation on the integrity of the reactor

vessel. Specifically, the applicant has determined that the neutron embrittlement affects the

ability of the vessel to (a) maintain acceptable Charpy upper shelf energy values during the

period of extended operation, (b) resist failure during a pressurized thermal shock (PTS) event,

and (c) operate safely using guidance from calculated pressure-temperature (P-T) operating

limit curves.

The regulations governing reactor vessel integrity are contained in the following sections of

10 CFR Part 50:

• 10 CFR 50.60, “Acceptance Criteria for Fracture Prevention Measures for Light Water

Nuclear Power Reactors for Normal Operation,” which requires all light water reactors to

meet the fracture toughness, P-T limits, and material surveillance program requirements for

the reactor coolant boundary as set forth in Appendices G and H of 10 CFR 50.60.

• 10 CFR 50.61, “Fracture Toughness Requirements for Protection Against Pressurized

Thermal Shock Events,” which contains fracture toughness requirements for protection

against PTS.

The staff’s evaluation of the reactor vessel neutron embrittlement TLAAs is provided below.

4.2.1 Upper Shelf Energy
4-4

4.2.1.1 Summary of Technical Information in the Application

Appendix G to 10 CFR Part 50, “Fracture Toughness Requirements,” requires that reactor

vessel beltline materials must have an initial, pre-irradiated, Charpy Upper Shelf Energy (USE)

of no less than 75 ft-lbs. and must maintain a Charpy USE of no less than 50 ft-lbs. throughout

the life of the reactor vessel.

VCSNS calculated the beltline fluence for the determination of the decrease in Charpy USE due

to radiation embrittlement and thermal aging of the reactor vessel. VCSNS then calculated the

Charpy USE values for the beltline region materials using Regulatory Guide (RG) 1.99,

Revision 2, “Radiation Embrittlement of Reactor Vessel Materials.” In response to the U.S.

Nuclear Regulatory Commission's (NRC) Generic Letter 92-01, Revision 2, “Reactor Vessel

Structural Integrity,” Revision 1, VCSNS reported the end of current license 32 effective fullpower years (EFPYs) USE for the limiting beltline material to be 67.5 ft-lbs. for the intermediate

plate A9154-1. The response to NRC Generic Letter 92-01 was based upon examinations of

the first three VCSNS surveillance capsules.

VCSNS has two surveillance capsules remaining in the vessel. The applicant originally stated

that these capsules would be kept in the vessel until they receive sufficient additional exposure

to neutron fluence to provide data that correlates with the estimated fluence on the vessel at the

end of the extended period of operation. VCSNS would then withdraw these two capsules and

analyze one and place the other one in storage. As stated in Section 3.1.2.3.6 of this SER, by

letter dated November 5, 2003, the applicant indicated that it will leave one of the two remaining

capsules in the vessel for one additional cycle. During RF-15, VCSNS intends to remove the

last remaining capsule and place it in storage for possible future use. Also, the applicant

indicated that during RF-15, VCSNS intends to install alternative dosimetry to monitor vessel

fluence. The Charpy USE will then be recalculated for additional fast neutron fluence

corresponding to the end of the extended operating period. Therefore, as discussed above,

VCSNS is utilizing 10 CFR 54.21 (c)(1)(ii) to calculate the reactor pressure vessel (RPV)

Charpy USE to the end of the extended operating period.

4.2.1.2 Staff Evaluation

The staff reviewed the USE evaluations contained in Section 4.2.1 of the LRA and Section

18.3.1.1 of Appendix A to the LRA. The staff issued RAI 4.2.2.1-1, in which it requested that 

the applicant submit 60-year end-of-life (EOL) USE values for each of the beltline materials and

requested that the applicant address how surveillance capsule results were evaluated in its

determination of the USE values. In a letter dated June 12, 2003, in response to RAI 4.2.2.1-1,

the applicant indicated that (1) the EOL for VCSNS is 54 EFPY, and (2) the 54-EFPY fluence (E

> 1.0 MeV) values may be found in Table 6-14 of Westinghouse Commercial Atomic Power

report (WCAP-15101, “Analysis of Capsule W from the South Carolina Electric & Gas Company

V. C. Summer Unit 1 Reactor Vessel Radiation Surveillance Program,” dated September 1998.)

The WCAP report was attached to a letter from G. J. Taylor, South Carolina Electric & Gas Co.

(SCE&G), to NRC Document Control Desk, dated October 9, 1998. This WCAP report contains

the data from the test results of capsule W, which was removed after 10.8 EFPYs with a lead

factor of 3.40. The applicant states that the intermediate shell plate has 0.10 wt% Cu and is the

limiting plate material. The highest percent of copper in the weld material is 0.05 wt%. The

staff confirmed the data provided by the applicant by reviewing the data for the VCSNS reactor
4-5

vessel materials against the data in the NRC Reactor Vessel Integrity Database (RVID). The

staff determined that the intermediate shell plate, A9154-1, is the limiting plate material and its

Cu and Ni contents are 0.10 wt% and 0.51 wt%, respectively. The staff noted that the VCSNS

reactor vessel beltline materials have welds of only one heat, 4P4784, and their Cu and Ni

contents are 0.05 wt% and 0.91 wt%, respectively.

The surveillance plate has Charpy test results from longitudinally oriented specimens, but does

not have Charpy data from transversely oriented specimens. Therefore, to determine whether

the plate material is in compliance with 10 CFR Part 50, Appendix G, the staff and the applicant

must estimate the transverse properties from the longitudinal properties. The applicant states

that the unirradiated USE value for the limiting plate is 132 ft-lbs. in the longitudinal direction,

and 91 ft-lbs for the limiting weld material. The applicant also states that the unirradiated USE

value for the limiting plate in the transverse direction is 75 ft-lbs., which is 56.8 percent of the

USE value in the longitudinal direction. The staff estimated the unirradiated USE value for the

plate material in transverse direction according to the guidance provided in Section 5.3.2 of the

NRC report, “Standard Review Plan for the Review of Safety Analysis Reports for the Nuclear

Power Plants,” NUREG-0800, 1987. According to this NUREG report, the USE of the plate

specimens in the transverse direction is 65 percent of that in the longitudinal direction and,

therefore, is equal to 85.8 (0.65 x 132) ft-lbs., which is greater than the one reported by the

applicant. The staff finds the unirradiated USE value of 75 ft-lbs. for the limiting plate material

in the transverse direction acceptable for two reasons: (1) the unirradiated USE value is less

than the one estimated using the guidance provided in NUREG-0800 and (2) the ratio of

unirradiated USE value in the transverse to the longitudinal direction bounds the corresponding

ratio of the measured USE values for the irradiated surveillance specimens as discussed in the

next paragraph.

As reported in WCAP-15101, the measured USE at a fluence of 4.664E+19 n/cm2

 for the

limiting plate is 126 ft-lbs. in the longitudinal direction and 74 ft-lbs. in the transverse direction. 

In other words, the measured USE value in the transverse direction is 58.7 percent of the one

along the longitudinal direction. The measured USE at a fluence of 4.664E+19 n/cm2

 for the

limiting weld material is 87 ft-lbs. The staff made independent estimates of corresponding USE

values using the curves in Figure 2 of RG 1.99, Revision 2. The staff estimated that, at a

fluence of 4.664E+19 n/cm2

, the percentage drop in the USE value for the limiting plate and

weld materials is 16 percent. The corresponding USE value for the limiting plate is 111 (132 x

0.84) lbs. in the longitudinal direction, which is less than the measured value. The staff

estimate is based on an unirradiated USE of 84 ft-lbs, which is the value reported in the RVID.

Similarly, the estimated USE value for the limiting weld is 71 (84 x 0.84) ft. lbs., which is less

than the measured value. In other words, the estimated USE values, using RG 1.99, Revision

2 methodology, for both the limiting plate and weld materials are lower than the measured

values. Since the values using RG 1.99, Revision 2 are lower than the measured values, the

RG predicts conservative values.

The applicant provides the following information about the EOL USE values. The highest 54-

EFPY fluence value listed in Table 6-14 of the WCAP report is 6.40 x 1019 n/cm2

, which is the

calculated value at the vessel ID surface. The highest 54-EFPY fluence value at 1/4T is 4.29 x

1019 n/cm2

. Using curves in Figure 2 of RG 1.99, Rev. 2, the applicant estimates the predicted

decrease in USE to be 31 percent for the limiting beltline plate material with 0.10 wt% Cu and

EOL fluence of 6.40 x 1019 n/cm2

. This would reduce the USE for the limiting plate material

from the unirradiated values of 132 ft-lbs. in the longitudinal direction and 75 ft-lbs. in the
4-6

transverse direction to EOL values of 91 ft-lbs. and 51.75 ft-lbs., respectively. The applicant

uses 91 ft-lbs. as an unirradiated USE value for the weld material. This value is higher than the

one reported in the RVID (i.e., 84 ft-lbs.). For the weld material, the drop in USE reduces the

unirradiated value of 91 ft-lbs. to EOL value of 62 ft-lbs.

The staff performed independent calculations using the RVID data for estimating EOL USE

values for the limiting plate material and weld material. The staff independently verified, using

Figure 2 of RG 1.99, Revision 2, and the Cu composition values for the limiting beltline plate

and weld materials, that the estimated drop in USE values for the limiting plate and weld

materials is the same and equal to 29.5 percent. In determining the percentage drop, the staff

used the fluence at 1/4T. This is the applicable fluence because the fluence is taken at the 1/4T

depth that corresponds to the depth of the flaw assumed to exist for the USE evaluation. The

corresponding EOL USE values for the limiting plate material are 93 (132 x 0.705) ft-lbs. in the

longitudinal direction and 53 (75 x 0.705) ft-lbs. in the transverse direction. For the limiting weld

metal it is 59 (84 x 0.705) ft-lbs. Thus, the EOL USE values for the limiting plate material, as

calculated by the staff, are higher than those reported by the applicant, and are higher than 50

ft-lbs. The EOL USE value for the limiting weld, as calculated by the staff, is about 5 percent

lower than the one reported by the applicant, but is also higher than 50 ft-lbs. The staff finds

the EOL USE values for the VCSNS limiting plate and weld metals acceptable because they are

greater than 50 ft-lbs and, therefore, satisfy the Charpy USE requirements of 10 CFR 50, 

Appendix G at the end of the period of extended operation.

Pursuant to the requirements of 10 CFR 54.21(d), the applicant provided the FSAR Supplement

description of the upper-shelf-energy (USE) as part of the reactor vessel (RV) neutron

embrittlement TLAA in Section 18.3.1.1 of Appendix A, FSAR Chapter 18 of the LRA. The staff

noted that the applicant did not provide its calculation of the USE for the end of the period of

extended operation in the FSAR Supplement; therefore, the staff requested that the applicant

provide its projected calculation of the USE for the period of extended operation and indicate

where it is documented. By letter dated September 24, 2003, the applicant revised the FSAR

Supplement for Section 18.3.1.1 to indicate that the projected calculation of the USE for the

period of extended operation is documented in WCAP-15101, “Analysis of Capsule W for the

South Carolina Electric & Gas Company, V.C. Summer Unit 1 Reactor Vessel Radiation

Surveillance Program,” dated September 1998. 

4.2.1.3 Conclusions

On the basis of its review, the staff concludes 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 for the upper-shelf energy as part of the reactor vessel

neutron embrittlement TLAA. The staff also concludes that the FSAR Supplement contains an

appropriate summary description of the upper-shelf energy as part of the reactor vessel neutron

embrittlement TLAA evaluation for the period of extended operation, as discussed above. The

staff has reasonable assurance that the safety margins established and maintained during the

current operating term will be maintained during the period of extended operation, as required

by 10 CFR 54.21(c)(1)(ii).

4.2.2 Pressurized Thermal Shock
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4.2.2.1 Summary of Technical Information in the Application

10 CFR 50.61, “Fracture Toughness Requirements for Protection Against Pressurized Thermal

Shock Events,” includes fracture toughness requirements for protection against pressurized

thermal shock. The requirements include screening criteria for the maximum nil-ductility

reference temperature in the limiting beltline material (RTPTS). The RTPTS values must remain

below the screening criteria values of 270 °F for plates, forgings, and longitudinal welds, and

300 °F for circumferential welds.

The VCSNS RTPTS values for the current 40-year operating term were calculated in accordance

with the method of WCAP-15103. This method is consistent with Regulatory Guide 1.99,

Revision 2 and 10 CFR 50.61. The applicant reports that the calculated RTPTS values for all the

beltline materials in the VCSNS reactor vessel have end-of-life (32 EFPY) and extended life (48

EFPY) RTPTS values below the PTS screening criteria. The applicant states that the RTPTS

value will be recalculated when one of the two remaining VCSNS surveillance capsules is

removed from the vessel. As mentioned, the applicant intends to test at least one of the

capsules when the calculated fast fluence on the capsules meets or exceeds the calculated fast

fluence on the vessel wall at the end of the extended operating period. Therefore, VCSNS

elects to utilize 10 CFR 54.21(c)(1)(ii) to calculate the RTPTS data to the end of the extended

operating period.

4.2.2.2 Staff Evaluation

The staff reviewed the PTS evaluations contained in Section 4.2.2 of the LRA and Section

18.3.1.2 of Appendix A to the LRA. The method used by the applicant to calculate RTPTS is

acceptable because it is consistent with RG1.99, Revision 2 and 10 CFR 50.61. The staff

issued RAI 4.2.2.2-1 requesting that the applicant submit a table of the VCSNS 60-year EOL

RTPTS values for each of the beltline material along with its heat number, material ID, copper

and nickel values, chemistry factor, initial RTNDT, margin, EOL peak fluence, and fluence factor. 

The RAI also requested the applicant to discuss how surveillance capsule results were applied

in its determination of the RTPTS values. In response to RAI 4.2.2.2-1 in a letter dated June 12,

2003, the applicant refers to two WCAP reports attached to a letter from G. J. Taylor, SCE&G,

to NRC Document Control Desk, dated October 9, 1998. These reports included WCAP15101, “Analysis of Capsule W from the South Carolina Electric & Gas Company V. C. Summer

Unit 1 Reactor Vessel Radiation Surveillance Program,” September 1998, and WCAP-15103,

“Evaluation of Pressurized Thermal Shock for V. C. Summer Unit 1,” September 1998. These

two WCAP reports contain the data from the test results of capsule W that was removed after

10.8 EFPYs with a lead factor of 3.40. The applicant states that the intermediate shell plate

has 0.10 wt% Cu and is the limiting plate material. The highest percentage of copper in the

weld material is 0.05 wt%. The staff confirmed the data provided by the applicant by reviewing

the data for the VCSNS reactor vessel materials in the NRC RVID. The staff determined that

the intermediate shell plate, A9154-1, is the limiting plate material and its Cu and Ni contents

are 0.10 wt% and 0.51 wt%, respectively. The staff also determined that the VCSNS reactor

vessel beltline materials have welds of only one heat, 4P4784, and their Cu and Ni contents are

0.05 wt% and 0.91 wt%, respectively. Table 1 in WCAP-15103 provides the following data for

the initial, unirradiated, values of RTNDT for the limiting materials: 30 °F for plate A9154-1 and

-44 °F for weld 4P4784. The staff confirmed this data for the unirradiated RTNDT by reviewing

the corresponding data in RVID. WCAP-15101 presents somewhat different data for the initial,

unirradiated RTNDT: 28 °F for plate A9154-1, in the transverse direction, and -53 °F for weld
4-8

4P4784. In determining the RTPTS values, the applicant used the most limiting values;

therefore, the initial (unirradiated) RTNDT values used in calculating the RTPTS values are 30 F

and -44 F for the plate and weld, respectively. The staff found this acceptable because the

applicant used the most limiting values of the initial RTNDT value in determining the RTPTS

values.

WCAP-15101 presents the following results for the surveillance capsule W, the fourth capsule

removed from the VCSNS RPV. The capsule received an average neutron fluence (E>1.0

MeV) of 4.664E+19 n/cm2

 after 10.78 EFPYs of plant operation. This resulted in 30-ft-lbs

transition temperature increase (RTNDT) of 58 °F for plate A9154-1 in the transverse direction,

and 43 °F for weld 4P4784. The staff made independent estimates of the corresponding

RTNDT values using the chemistry factor from the tables in 10 CFR 50.61 and a neutron

fluence of 4.664E+19 n/cm2

. For plate A9154 with 0.10 wt% Cu and 0.51 wt% Ni, the chemistry

factor is 65 °F and the RTNDT is 94 °F. Similarly, for weld 4P4784 with 0.05 wt% Cu and 0.91

wt% Ni, the chemistry factor is 68 °F and the RTNDT is 98 °F. The comparison of measured

and estimated results shows that the measured results for RTNDT for the surveillance plate and

weld materials are smaller than the corresponding estimated values using Tables 1 and 2 of 10

CFR 50.61. Therefore, using the RG 1.99, Revision 2 methodology for calculating the

chemistry factor and the RTNDT is conservative.

The EOL for VCSNS is 54 EFPY. The highest 54-EFPY fluence value listed in Table 6-14 of

the WCAP report is 6.40 x 1019 n/cm2

, which is the calculated value at the vessel ID surface. 

For the margin term, M, the applicant uses 34 °F for the limiting plate material and 56 °F for the

limiting weld material. The staff finds these margin values acceptable because they are in

accordance with 10 CFR 50.61.

In determining the 54 EFPY RTPTS value for the limiting plate, the staff used the equation in 10

CFR 50.61 which is the sum of the initial RTNDT value (30 °F) and the RTNDT value (90°F) and

the margin term (34°F) which results with the RTPTS value of 158 °F. In using the same

equation, the staff independently calculated the RTPTS value of the weld, which is the sum of the

initial RTNDT value (-44 °F) and the RTNDT value (98 °F) and the margin term (56 °F) which

results with the RTPTS value of 110 °F. The staff compared its RTPTS values to those of the

applicant’s values and found the applicant’s values to be acceptable because they were

approximately the same as those calculated by the staff. The staff also finds the applicant’s

values of the RTPTS acceptable because the projected 54-EFPY RTPTS values satisfy the PTS

screening criteria of 10 CFR 50.61(b)(2) at the end of the period of extended operation.

Pursuant to the requirements of 10 CFR 54.21(d), the applicant provided the FSAR Supplement

description of the PTS as part of the reactor vessel neutron embrittlement TLAA in Section

18.3.1.2 of Appendix A, “FSAR Chapter 18,” to the LRA. The staff noted that the applicant did

not provide its calculation of the PTS for the end of the period of extended operation in the

FSAR Supplement; therefore, the staff requested that the applicant provide its projected

calculation of the PTS for the period of extended operation and indicate where it is documented. 

By letter dated September 24, 2003, the applicant revised the FSAR Supplement for Section

18.2.1.2 to indicate that the calculation of the PTS for the end of the period of extended

operation is documented in WCAP-15101, “Analysis of Capsule W for the South Carolina

Electric & Gas Company, V.C. Summer Unit 1 Reactor Vessel Radiation Surveillance Program,”

dated September 1998. 
4-9

4.2.2.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that, for the PTS as part of the reactor

vessel neutron embrittlement TLAA, the analyses will be projected to the end of the period of

extended operation. The staff also concludes that the FSAR Supplement contains an

appropriate summary description of the PTS as part of the reactor vessel neutron embrittlement

TLAA evaluation for the period of extended operation, as discussed above. The staff has

reasonable assurance that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by 10

CFR 54.21(c)(1)(ii).

4.2.3 Pressure-Temperature Limits

4.2.3.1 Summary of Technical Information in the Application

Section 4.2.3 of the LRA and Section 18.3.1.3 of Appendix A to the LRA addresses P-T limits

for the VCSNS vessel. The LRA describes how P-T curves are constructed. Beltline fluence is

one of the factors used to revise P-T limits for heatup and cooldown due to radiation

embrittlement of the reactor vessel. This input is based on calculations of an adjusted

reference temperature (ART) using methodology of RG 1.99, Rev. 2. This methodology is very

similar to that used to calculate the RTPTS value. However, the calculation of ART also

considers attenuation of the fast neutron fluence through the vessel wall to the depth of the

postulated flaw.

The calculated ART is refined in conjunction with the analysis of each successive surveillance

capsule. Allowable P-T curves are generated for steady state and each finite cooldown rate

specified, assuming a reference flaw at the inside surface of the most limiting reactor vessel

beltline material. A composite cooldown limit curve is constructed as the minimum of each of

these curves. Similarly, allowable P-T curves are generated for steady state and for each finite

heatup rate specified considering each of the worst-case reference flaw locations, either at the

vessel outside surface or inside surface.

The applicant states that current VCSNS heatup and cooldown curves are based on

calculations for the current 40-year period. VCSNS will revise the calculated value for ART and

associated P-T limits for heatup and cooldown when one of the two remaining surveillance

capsules is removed from the vessel. The applicant intends to remove at least one of the

capsules when the calculated fast fluence on the capsules meets or exceeds the calculated fast

fluence on the vessel wall at the end of the extended operating period. Therefore, VCSNS

elects to utilize 10 CFR 54.21(c)(1)(iii) to construct the P-T curves to the end of the extended

operating period.

4.2.3.2 Staff Evaluation

The staff reviewed the information in Section 4.2.3 of the LRA and Section 18.3.1.3 of Appendix

A to the LRA describing the general procedure for generating P-T curves for the reactor vessel

beltline materials through the period of extended operation. The applicant determines the ARTs
4-10

using methodology of RG 1.99, Revision 2. From the ART values, the applicant constructs P-T

limit curves applicable for 40 years of operation in accordance with the requirements of 10 CFR

50, Appendix G. The applicant states that the current VCSNS P-T curves are based on

calculations for current 40-year operating term.

The applicant will revise the calculated values of the ART and the associated P-T curves when

one of the two remaining surveillance capsules is removed from the vessel and analyzed. The

applicant intends to install alternative dosimetry to monitor vessel fluence (discussion of the

surveillance capsule program is provided in Section 3.1.2.3.6 of this SER), in order to obtain

data that correlates to estimated fluence on the vessel at the end of extended operation. The

Technical Specifications will be updated as required by 10 CFR Part 50. Therefore, the P-T

limit analyses will be projected for the period of extended operation. This is acceptable

because the staff will evaluate the recalculated ART values and associated P-T curves for the

VCSNS reactor vessel beltline materials in accordance with the P-T limits requirements of 10

CFR Part 50, Appendix G, when the applicant submits them for an approval pursuant to the

license amendment requirements of 10 CFR 50.90.

The applicant has not provided any information about the maximum allowable low-temperature

overpressure protection (LTOP) system power-operated relief valve (PORV) set points that are

applicable for current 40-year operating period. The staff issued RAI 4.2.2.3-1 requesting the

applicant to identify LTOP as part of the reactor vessel neutron embrittlement TLAA and commit

to develop LTOP values for the period of extended operation, as was done for the P-T limits. In

response to RAI 4.2.2.3-1, in a letter dated June 12, 2003, the applicant states that at VCSNS,

the LTOP analysis is part of the calculation that develops the heatup and cooldown curves from

analysis of the reactor vessel surveillance specimens. The applicant further states that the

LTOP analysis will be done as part of the recalculation of the P-T curves when one of the two

remaining surveillance capsules is removed from the vessel and analyzed. The staff finds this

response acceptable because the applicant will submit the LTOP analysis along with the

recalculated ART values and associated P-T curves as mentioned in the preceding paragraph

for staff approval.

Pursuant to the requirements of 10 CFR 54.21(d), the applicant provided the FSAR Supplement

description of the TLAA for the P-T limits in Section 18.3.1.3 of Appendix A, FSAR Chapter 18,

to the LRA. The applicant states that the P-T limit curves for the period of extended operation

will be constructed after the removal of the remaining two capsules. As indicated in Section

3.1.2.3.6, during RF-15, VCSNS will install alternative dosimetry to monitor the neutron fluence

in order to provide data that correlates to the estimated fluence on the vessel at the end of the

period of extended operation. The staff concludes that the FSAR Supplement contains an

appropriate summary description of the P-T limits as part of the reactor vessel neutron

embrittlement TLAA evaluation for the period of extended operation.

4.2.3.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii) that, the analyses will be projected to the

end of the period of extended operation for the P-T limits as part of the reactor vessel neutron

embrittlement TLAA. The staff also concludes that the FSAR Supplement contains an

appropriate summary description of the P-T limits as part of the reactor vessel neutron

embrittlement TLAA evaluation for the period of extended operation. Therefore, the staff has
4-11

reasonable assurance that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by

10 CFR 54.21(c)(1).

4.3 Metal Fatigue

A metal component subjected to cyclic loading at loads less than the static design load may fail

due to 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.

4.3.1 Summary of Technical Information in the Application

The reactor vessel and major reactor coolant system (RCS) components were designed to the

ASME Boiler and Pressure Vessel Code, Section III requirements for Class 1 components. 

The applicant indicated that Class 1 components have been designed using the transient cycle

assumptions in Table 5.2-2 of the FSAR. The applicant indicated that the VCSNS Inservice

Inspection Program involves monitoring of thermal transients. The applicant uses the Thermal

Fatigue Monitoring Program (TFMP) to track thermal transients. The TFMP is discussed in

Section B.3.2 of the LRA. The applicant indicated that enhancements to the program are

warranted to incorporate the new guidance in Electric Power Research Institute (EPRI) Report

MRP-47, “Materials Reliability Program Guidelines for Addressing Fatigue Environmental

Effects in a License Renewal Application.” The applicant made a commitment to revise the

TFMP to account for the effects of the reactor coolant environment, in accordance with

NUREG-1801, Section X.M.1, prior to the period of extended operation.

The applicant discussed the evaluation of ASME Class 2 and 3 and American National

Standards Institute (ANSI) B31.1 components in Section 4.3.2 of the LRA. ASME Class 2 and

3 and ANSI B31.1 require that a stress reduction factor be applied to the allowable thermal

bending stress range if the number of full range cycles exceeds 7,000. The applicant indicated

that most piping systems within the scope of license renewal are only subject to occasional

cyclic operation and, consequently, the analyses will remain valid during the period of extended

operation. However, the applicant did indicate that the RCS loop sampling line could exceed

the 7,000 cyclic limit during the period of extended operation. The applicant indicated that

either procedural controls would be implemented to assure the number of cycles remains below

the 7,000 cycle or the calculation would be revised to verify the acceptability of the number of

actual cycles. 

4.3.2 Staff Evaluation

As discussed in the previous section, components of the RCS at VCSNS were designed to the

Class 1 requirements of the ASME Code. These requirements contain explicit criteria for the

fatigue analysis of components. Consequently, the applicant identified the fatigue analysis of

these components as TLAAs. The staff reviewed the applicant’s evaluation of the RCS

components for compliance with the provisions of 10 CFR 54.21(c)(1).
4-12

The specific design criterion for fatigue analysis of RCS 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 resulting from each transient. The design criterion requires that

the CUF not exceed 1.0. The applicant indicated that the Thermal Fatigue Monitoring Program

monitors the design transients at VCSNS. In RAI 4.3-1, the staff requested that the applicant

provide the following information for each of the transients monitored at VCSNS:

• the current number of operating cycles and a description of the method used to determine

the number of the design transients from the plant operating history;

• the number of operating cycles estimated for 60 years of plant operation and a description

of the method used to estimate the number of cycles at 60 years; and

• a comparison of the thermal fatigue transients monitored with the transients listed in Table

5.2-2 of the FSAR, identification of any transients listed in the FSAR that are not monitored

by the VCSNS Thermal Fatigue Monitoring Program (TFMP) and explanation of why it is not

necessary to monitor these transients.

The applicant’s June 12, 2003, response indicated that critical components were monitored

using the Westinghouse program WESTEMS. The applicant uses WESTEMS to monitor

transient cycles for the following locations:

• reactor vessel inlet and outlet nozzles 

• reactor vessel shell

• reactor coolant loop hot and cold leg piping

• steam generator primary sides

• steam generator feedwater nozzles

• reactor coolant pump casings

• pressurizer upper shell

• pressurizer spray nozzle

• auxiliary spray piping

• letdown piping

• excess letdown piping

• safety injection piping

• safety injection accumulator piping

• residual heat removal piping

In addition, the applicant uses WESTEMS to monitor fatigue usage at the following locations:

• normal charging nozzle

• alternate charging nozzle

• pressurizer lower head

• pressurizer surge line reactor coolant loop nozzle locations

• pressurizer surge line nozzle locations

The applicant’s response also included its 2002 yearly review of cycle counts from WESTEMS. 

The applicant indicated that WESTEMS does not monitor hydrostatic tests. The hydrostatic

tests are monitored by a hand count and are included in the yearly review. The staff verified
4-13

that the monitored transients, provided in the 2002 yearly review, include the transients listed in

FSAR Supplement Table 5.2-2. The applicant’s evaluation indicated that a significant

percentage of the allowable cycles of feedwater cycling and auxiliary pressurizer spray cycles

had accumulated. However, the applicant indicated that the current rate of cycle accumulation

had slowed, and that it did not expect the fatigue limits for these components to be exceeded

during the period of extended operation. The applicant’s evaluation of the WESTEMS data for

those locations monitored for fatigue usage indicates that three components may exceed the

design basis fatigue usage factor during the period of extended operation. These components

are the charging nozzle, alternate charging nozzle and pressurizer surge line reactor coolant

loop nozzle. In accordance with the Thermal Fatigue Monitoring Program, the applicant must

take corrective actions prior to exceeding the fatigue usage limit for these components. 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 replace part of the component. 

The Westinghouse Owners Group issued topical report WCAP-14577, Revision 1-A, “Aging

Management for Reactor Internals,” to address the aging management of the reactor vessel

internals (RVI). The staff’s review of WCAP-14577, Rev. 1-A identified a number of issues that

should be addressed on a plant-specific basis. Renewal Applicant Action Item 11, specified in

WCAP-14577, Rev. 1-A, indicates that the fatigue TLAA of the RVI should be addressed on a

plant specific basis. In the LRA, SCE&G indicates that the VCSNS Inservice Inspection

Program involves monitoring of thermal transients. In RAI 4.3.1-2, the staff requested that the

applicant list the transients that contribute to the fatigue usage for each component listed in

Table 3-3 of WCAP-14577, Rev.1 1-A and discuss how the Inservice Inspection Program

monitors these transients.

The applicant’s June 12, 2003, response indicated that the code of record for the RVI is ASME

Section III, Class 2, which does not specify a fatigue analysis. The applicant further indicated

that VCSNS (AMP) B.2.4, Reactor Vessel Internal Inspection, will monitor the components

listed in WCAP-14577, Table 3-3. The staff’s review of the VCSNS FSAR Table 3.2-1

confirmed the applicant’s statement that the RVI is classified as ASME, Section III, Class 2. 

Therefore, the staff finds the applicant’s response acceptable. The staff review of the Reactor

Vessel Internal Inspection AMP is contained in Section 3.1.2.3.7 of this SER. 

The Westinghouse Owners Group issued topical report WCAP-14575-A, “Aging Management

Evaluation for Class 1 Piping and Associated Pressure Boundary Components,” to address

aging management of the RCS piping. Tables 3-2 through 3-16 of WCAP-14575-A list RCS

components where fatigue is considered significant. The staff review of WCAP-14575-A

identified a number of issues that should be addressed on a plant-specific basis. Renewal

Applicant Action Item 8 requests that the applicant address components labeled I-M and I-RA in

Tables 3-2 through 3-16 of WCAP-14575-A. In the LRA, SCE&G indicates that the VCSNS

Inservice Inspection (ISI) Program includes monitoring of thermal transients. In RAI 4.3.1-3, the

staff requested that the applicant discuss how the ISI Program addresses the components

labeled I-M and I-RA in Tables 3-2 through 3-16 of WCAP-14575-A.

The applicant’s June 12, 2003, response indicated that the VCSNS TFMP manages the thermal

fatigue of ASME Class 1 components. The staff review of the applicant’s response to RAI

4.3.1-1 indicated that the applicant’s TFMP monitors the design transients specified in the

FSAR Table 5.2-2. Therefore, the staff finds the applicant’s response acceptable.
4-14

The Westinghouse Owners Group has issued the generic topical report WCAP-14574-A to

address aging management of pressurizers. The staff’s review of WCAP-14574-A identified a

number of issues that should be addressed on a plant-specific basis. Renewal Applicant Action

Item 1 requests the applicant to demonstrate that the pressurizer subcomponent CUFs remain

below 1.0 for the period of extended operation. Table 2-10 of WCAP-14574-A indicates that

the ASME Section III Class 1 fatigue CUF criterion could be exceeded at several pressurizer

subcomponent locations during the period of extended operation. WCAP-14574-A also

identified recent unanticipated transients that were not considered in the original ASME Section

III Class 1 fatigue analyses, including inflow/outflow thermal transients. In RAI 4.3.1-4, the staff

requested that the applicant provide the following information:

• Confirm that the additional transients discussed in WCAP-14574-A, not considered in the

original design, have been addressed at VCSNS.

• Show the ASME Section III Class 1 CLB CUFs for the applicable sub-components of the

VCSNS pressurizer specified in Table 2-10 of WCAP-14574-A and the corresponding CUFs

for the extended period of operation.

• Discuss the impact of the environmental fatigue correlations provided in NUREG/CR-6583,

“Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy

Steels,” and NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design

Curves of Austenitic Stainless Steels,” on the above results.

The applicant’s June 12, 2003, response indicated that the fatigue data for the pressurizer

components was included in its response to RAI 4.3.1-1. As discussed previously, the fatigue

accumulation at the surge line indicates that the design fatigue usage limit may be exceeded

prior to the end of the period of extended operation. The applicant further indicated that

changes were made to the operating procedure to slow the fatigue accumulation on the

pressurizer surge nozzle. The applicant committed to perform a further evaluation of the

pressurizer surge line nozzle for the impact of environmental fatigue prior to the period of

extended operation. The staff finds the applicant’s commitment for further evaluation of the

surge nozzle acceptable. The applicant has not provided the CUFs for the subcomponents

listed in Table 2-10 of WCAP-14574-A or discussed the impact of the environmental fatigue

correlations on these subcomponents. Therefore, the staff concludes there is a possibility that

all components listed in Table 2-10 of WCAP-14574-A could exceed the fatigue usage limit

during the period of extended operation when environmental fatigue effects are considered. 

The staff review of previous LRAs of Westinghouse facilities has found that the pressurizer

surge line nozzle is the most limiting fatigue location for the pressurizer subcomponents.

The staff concludes that the pressurizer surge line nozzle is an acceptable sample component

location for assessing the impact of environmental fatigue on pressurizer components. The

applicant has committed to perform an evaluation of this component, including environmental

fatigue effects, prior to the period of extended operation. If the applicant’s evaluation of the

surge line nozzle for environmental effects indicates that additional actions are required to

manage its fatigue usage during the period of extended operation, then the applicant should

evaluate the remaining pressurizer components for the effects of environmental fatigue as part

of its corrective action. The staff notes that this position is consistent with the staff position

taken during the license renewal review of other facilities with Westinghouse pressurizers. 
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The applicant indicates that the Thermal Fatigue Monitoring Program will continue during the

period of extended operation and will assure that design cycle limits are not exceeded. The

applicant’s Thermal Fatigue Monitoring Program tracks transients and cycles of RCS

components that have explicit design transient cycles to assure that these components remain

within their design basis. Generic Safety Issue (GSI)-166, Adequacy of the Fatigue Life of

Metal Components,” raised concerns regarding the conservatism of the fatigue curves used in

the design of the RCS components. Although GSI-166 was resolved for the current 40-year

design life of operating components, the staff identified GSI-190, “Fatigue Evaluation of Metal

Components for 60-year Plant Life,” to address license renewal. The NRC closed GSI-190 in

December 1999, concluding:

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 mange the effects of aging, lead to the

conclusion that no generic regulatory action is required, and that GSI-190 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 breaks as

plants continue to operate. Thus, the staff concludes 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.

Section 4.3.1 of the LRA discusses the VCSNS Thermal Fatigue Monitoring Program. The

discussion indicated that the program is equivalent to the program described in Section X.M1 of

NUREG-1801. The discussion also indicated that the program will be enhanced to incorporate

new guidance in EPRI report, Materials Reliability Program Guidelines for Addressing Fatigue

Environmental Effects in a License Renewal Application (MRP-47).” EPRI MRP-47 was

submitted to the staff for review by Nuclear Energy Institute (NEI) by a letter dated July 31,

2001. By letter dated November 15, 2002, NEI requested that the staff place the review of

EPRI MRP-47 on hold. As a consequence, the staff has not endorsed the guidelines in EPRI

MRP-47. In order to meet the program described in NUREG-1801, the evaluation of the reactor

water environmental effects should address the fatigue sensitive component locations identified

in NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected

Nuclear Power Plant Components.” In RAI 4.3.1-5, the staff requested that the applicant

provide the following additional information regarding the evaluation of reactor water

environmental effects:

• Confirm that the environmental fatigue correlations contained in NUREG/CR-6583, “Effects

of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels,”

and NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue on Fatigue

Design Curves of Austenitic Stainless Steels,” will be used in the evaluation.

• Describe any enhancements to the Thermal Fatigue Monitoring Program resulting from the

guidance provided in EPRI Report MRP-47 and provide the technical justification for these

enhancements.

• Provide the design basis usage factors for each of the six component locations listed in

NUREG/CR-6260. Identify the transients that are significant contributors to the CUF at

these locations.
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In its June 12, 2003, response, the applicant committed to evaluate the environmental effects

on the components listed in NUREG/CR-6260 prior to the period of extended operation. The

applicant confirmed that the environmental fatigue correlations in NUREG/CR-6583 and

NUREG/CR-5704 will be used in the evaluations. Although the applicant indicated that

NUREG/CR-6260 locations applicable to VCSNS will be evaluated prior to the period of

extended operation, the applicant did not provide the design usage factors for these locations. 

Consequently, the staff concludes there is a possibility that all the applicable components listed

in NUREG/CR-6260 could exceed the fatigue usage limit during the period of extended

operation when environmental fatigue effects are considered. If the applicant’s evaluation

indicates that the fatigue usage limit for these components could be exceeded during the period

of extended operation, then the applicant must take appropriate corrective actions in

accordance with its Thermal Fatigue Monitoring Program. 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 replace part of the

component. In addition, since the Thermal Fatigue Monitoring Program monitors the fatigue

usage of a sample of critical components, the applicant’s corrective actions may involve the

evaluation of additional components for environmental fatigue effects.

The applicant is required to complete the TLAA evaluation prior to the period of extended

operation. Therefore, the staff finds the applicant’s commitment to evaluate the applicable

components listed in NUREG/CR-6260 as discussed in the preceding paragraph acceptable. 

Section 4.3.2 of the LRA addresses ASME Section III, Class 2 and 3 piping fatigue. The LRA

indicates that the post-accident and nuclear sampling systems at VCSNS could approach the

7,000 cycle limit during the period of extended operation. In RAI 4.3.2-1, the staff requested

that the applicant provide the material, the maximum calculated stress range, and the allowable

stress limit at the bounding location for each of these systems. 

The applicant’s June 12, 2003, response indicated that a specific stress analysis was not

performed for nuclear sampling system. The system was designed to criteria developed to

satisfy the ASME stress limits. The applicant reiterated its previous position that it would

administratively limit the use of the system such that the number of cycles will not exceed the

7,000 limit during the period of extended operation. 

The applicant provided an FSAR supplement description of the TFMP in Section A18.2.37 of

the LRA and FSAR supplement description of its TLAA evaluation for metal fatigue Section

18.3.2 of the LRA. By letter dated September 24, 2003, the applicant provided revised FSAR

supplement descriptions that included its commitments for further evaluation of environmental

fatigue and its commitment to administratively control the use of the nuclear sampling system. 

The staff finds that the applicant has provided an adequate description of the metal fatigue

TLAA in the FSAR supplement.

4.3.3 Conclusions

The staff has reviewed the applicant’s metal fatigue TLAA and concludes that the applicant’s

actions and commitments satisfy the requirements of 10 CFR 54.21(c)(1)(iii).
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The staff has also reviewed the FSAR Supplement for the TLAA and finds that the FSAR

Supplement contains an adequate description of the metal fatigue TLAA to satisfy 10 CFR

54.21(d).

4.4 Environmental Qualification of Electrical Equipment

The aging (or qualified life) analysis for electrical components, included as part of the

Environmental Qualification Program required by 10 CFR 50.49, that involve time-limited

assumptions as defined by the current operating term for the VCSNS (i.e., 40 years), meets the

10 CFR 54.3 definition for TLAA. The Environmental Qualification Program’s aging evaluation

for electrical components is thus considered a TLAA for license renewal. The Environmental

Qualification Program, together with other plant programs/processes, has been evaluated,

pursuant to 10 CFR 54.21(c)(1)(iii), to determine if they will adequately manage the effects of

aging on the intended function(s) of electrical components for the period of extended operation.

In LRA Section 4.4, “Environmental Qualification of Electrical Equipment,” the applicant

describes the technical bases and justification for why the VCSNS Environmental Qualification

Program, together with other plant programs/processes, adequately manages the effects of

aging on the intended function(s) of electrical components for the period of extended operation. 

The staff reviewed this section of the LRA to determine whether the applicant had

demonstrated that the effects of aging on the intended function(s) of electrical components will

be adequately managed, through the VCSNS Environmental Qualification Program, together

with other plant programs/processes, during the period of extended operation as required by 10

CFR 54.21(c)(1)(iii).

4.4.1 Summary of Technical Information in the Application

The NRC has established nuclear station environmental qualification (EQ) requirements in 10

CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49. As required by 10 CFR 50.49, an

Environmental Qualification Program must be established to demonstrate that certain electrical

components located in harsh plant environments (that is, those areas of the plant that could be

subject to the harsh environmental effects of a loss-of-coolant accident (LOCA), high energy

line breaks (HELBs) or post-LOCA radiation) are qualified to perform their safety function in

those harsh environments after the effects of inservice aging. This section also requires that

the effects of significant aging mechanisms be addressed as part of environmental qualification.

All operating plants must meet the requirements of 10 CFR 50.49 for certain electrical

components important to safety. This section defines the scope of components to be included.

It also requires the preparation and maintenance of a list of in-scope components, and requires

the preparation and maintenance of a qualification file that includes component performance

specifications, electrical characteristics and the environmental conditions to which the

components could be subjected. 10 CFR 50.49(e)(5) contains provisions for aging that require,

in part, consideration of all significant types of aging degradation that can affect component

functional capability. 10 CFR 50.49(e)(5) also requires replacement or refurbishment of

components not qualified for the current license term prior to the end of designated life, unless

additional life is established through ongoing qualification. Four methods of demonstrating

qualification for aging and accident conditions are established in 10 CFR 50.49(f). Sections 10

CFR 50.49(k) and (l) permits different qualification criteria to apply based on plant and
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component vintage. Supplemental EQ regulatory guidance for compliance with these different

qualification criteria is provided in the Division of Operating Reactors (DOR) Guidelines,

Guidelines for Evaluating Environmental Qualification of Class 1E Electrical Equipment in

Operating Reactors; NUREG-0588, Interim Staff Position on Environmental Qualification of

Safety-Related Electrical Equipment; and RG 1.89, Rev. 1, Environmental Qualification of

Certain Electric Equipment Important to Safety for Nuclear Power Plants. Compliance with 10

CFR 50.49 provides reasonable assurance that the component can perform its intended

functions during accident conditions after experiencing the effects of inservice aging.

Environmental Qualification Programs manage component thermal, radiation, and cyclical aging

through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods. As

required by 10 CFR 50.49, EQ components not qualified for the current license term are to be

refurbished, replaced, or have their qualification extended prior to reaching the aging limits

established in the evaluation. Aging evaluations for EQ components that specify a qualification

of at least 40 years are considered TLAAs for license renewal.

Under 10 CFR 54.21(c)(1)(iii), plant EQ programs, which implements the requirements of 10

CFR 50.49 (as further defined and clarified by the DOR Guidelines, NUREG-0588, and RG

1.89, Rev. 1), are viewed as an AMP for license renewal. Re-analysis of an aging evaluation to

extend the qualification of components under 10 CFR 50.49(e) is performed on a routine basis

as part of an EQ Program. Important attributes for the re-analysis of an aging evaluation

include analytical methods, data collection and reduction methods, the underlying assumptions,

the acceptance criteria, and corrective actions (if acceptance criteria are not met).

The re-analysis of an aging evaluation is normally performed to extend the qualification by

reducing excess conservatism incorporated in the prior evaluation. Re-analysis of an aging

evaluation to extend the qualification of a component is performed pursuant to 10 CFR 50.49(e)

as part of an EQ Program. While a component life limiting condition may be due to thermal,

radiation, or cyclical aging, the vast majority of component aging limits are based on thermal

conditions. Conservatism may exist in aging evaluation parameters, such as the assumed

ambient temperature of the component, an unrealistically low activation energy, or in the

application of a component (de-energized versus energized). The re-analysis of an aging

evaluation is documented according to the station’s Quality Assurance Program requirements,

which requires the verification of assumptions and conclusions. As already noted, important

attributes of a re-analysis include analytical methods, data collection and reduction methods,

underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are

not met). These attributes are discussed below.

Analytical Methods. The analytical methods used in the re-analysis of an aging evaluation are

the same as those applied in the prior analysis. The Arrhenius methodology is an acceptable

thermal model for reaction rate and thermal aging evaluation. The analytical method used for

radiation aging evaluations is to demonstrate qualification for the total integrated dose via test. 

The total integrated dose is the normal operational environmental dose plus the projected

accident dose. For license renewal, it is acceptable to establish a 60-year normal operational

radiation dose by taking the 40-year dose previously established and multiplying this value by

1.5. The result is added to the postulated accident dose to obtain a 60-year total integrated

dose. For cyclical aging evaluations, a similar methodology is acceptable. Other methods may

be justified on a case-by-case basis.
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Data Collection & Reduction Methods. Reducing excess conservatism in electrical component

service conditions (i.e., temperature, radiation, number of cycles) used in the prior evaluations

is the chief method used for re-analysis. Temperature data used in an aging analysis is

typically conservative and based on plant design temperatures. Actual plant operating

temperature data is typically less than design values. Actual plant operating data may be

obtained from temperature monitors specifically installed for EQ measurements, data taken by

operators during rounds, or other temperature monitors in place in the plant. 

Underlying Assumptions. EQ component aging evaluations typically contain sufficient

conservatism to account for most environmental changes, which occur as a result of plant

modifications and events. When unexpected adverse conditions are identified during

operational or maintenance activities, the affected EQ component(s) is (are) evaluated and

appropriate corrective actions are taken, which may include revisions to the qualification bases

and conclusions.

Acceptance Criteria and Corrective Action. The re-analysis of an aging evaluation could extend

the qualification of a subject component. If the qualification cannot be extended by re-analysis,

the component is to be refurbished, replaced, or requalified prior to the expiration of the current

qualification. The timing of the re-analysis must permit sufficient time to refurbish, replace, or

requalify the component if the re-analysis effort is unsuccessful.

In addition to these important attributes for re-analysis of the aging evaluation, the VCSNS

Environmental Qualification Program includes the attributes described below:

Environmental Qualification Program

[Scope] EQ Programs apply to certain electrical components that are important to safety and

could be exposed to harsh environment accident conditions, as defined in 10 CFR 50.49.

[Preventive Actions] 10 CFR 50.49 does not require actions that prevent aging effects. EQ

Program actions that could be viewed as preventive actions include (a) establishing the

component service condition tolerance and aging limits (for example, qualified life or condition

limit); and (b) where applicable, requiring specific installation, inspection, monitoring, or periodic

maintenance actions to maintain component aging effects within the bounds of the qualification

basis.

[Parameters Monitored or Inspected] EQ component qualified life is not based on condition or

performance monitoring. However, pursuant to RG 1.89, Rev. 1, such monitoring programs are

an acceptable basis to modify a qualified life through re-analysis. 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.

[Detection of Aging Effects] 10 CFR 50.49 does not require the detection of aging effects for

inservice components. 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.
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[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. EQ Program actions that could be viewed as monitoring include monitoring

how long qualified components have been installed. Monitoring or inspection of certain

environmental, condition, or component parameters may be used to ensure that a component is

within the bounds of its qualification basis, or as a means to modify the qualification.

[Acceptance Criteria] 10 CFR 50.49 acceptance criteria are that an inservice EQ component is

maintained within the bounds of its qualification basis, including (a) its established qualified life

and (b) continued qualification for the projected accident conditions. 10 CFR 50.49 requires

refurbishment, replacement, or requalification prior to exceeding the qualified life of each

installed device. When monitoring is used to modify a component qualified life, plant-specific

acceptance criteria are established based on applicable 10 CFR 50.49(f) qualification methods.

[Corrective Action] If an EQ component is found to be outside the bounds of its qualification

basis, corrective actions are implemented in accordance with the station’s corrective action

program. When unexpected adverse conditions are identified during operational or

maintenance activities that affect the environment of a qualified component, the affected EQ

component is evaluated and appropriate corrective actions are taken, which may include

changes to the qualification bases and conclusions. When an emerging industry aging issue is

identified that affects the qualification of an EQ component, the affected component is

evaluated and appropriate corrective actions are taken, which may include changes to the

qualification bases and conclusions. 

[Confirmation Process] Confirmatory actions, as needed, are implemented as part of the

station’s corrective action program, pursuant to 10 CFR Part 50, Appendix B.

[Administrative Controls] EQ Programs are implemented through the use of station policy,

directives, and procedures. EQ Programs will continue to comply with 10 CFR 50.49

throughout the renewal period, including development and maintenance of qualification

documentation demonstrating reasonable assurance that a component can perform required

functions during harsh accident conditions. EQ Program documents identify the applicable

environmental conditions for the component locations. EQ Program qualification files are

maintained at the plant site in an auditable form for the duration of the installed life of the

component. EQ Program documentation is controlled under the station’s quality assurance

program.

[Operating Experience] EQ programs include consideration of operating experience, both at

VCSNS and in the industry, to modify qualification bases and conclusions, including qualified

life. This operating experience includes data on specific components and materials, data on

aging limits, and new test data from manufacturers, industry groups, or the NRC. Compliance

with 10 CFR 50.49 provides reasonable assurance that components can perform their intended

functions during accident conditions after experiencing the effects of inservice aging.

Based on the above described attributes for re-analysis of the aging evaluation and EQ

Program review, the applicant concluded that their EQ Program is capable of maintaining the

qualification of components within the scope of 10 CFR 50.49. The EQ Program provides

reasonable assurance that the aging effects will be managed such that the components subject
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to aging management review will continue to perform their intended functions consistent with

the CLB for the period of extended operation.

4.4.2 Staff Evaluation

The staff reviewed the information in Section 4.4 of the LRA to determine whether the applicant

has demonstrated that the effects of aging on the intended function(s) of electrical components

will be adequately managed through their existing EQ Program, together with other plant

programs/processes, during the period of extended operation as required by 10 CFR

54.21(c)(1)(iii).

The applicant is required to have an EQ Program that meets the requirements of 10 CFR

50.49. The staff, therefore, agrees with the applicant’s conclusion that their EQ Program,

together with other plant programs/processes, will adequately manage the effects of aging on

the intended function(s) of electrical components for the period of extended operation. 

Generic Safety Issue -168, Environmental Qualification of Electrical Equipment

This GSI was developed to address environmental qualification of electrical equipment. By

letter from C. Grimes (NRC staff) to D. Walters (NEI), dated June 2, 1998, the staff issued the

following guidance to the industry:

 GSI-168 issues have not been identified to a point that a license renewal applicant can be

reasonably expected to address these issues, specifically at this time.

 An acceptable approach is to provide a technical rationale demonstrating that the CLB for

EQ will be maintained in the period of extended operation.

For the purpose of license renewal, there are three options for addressing issues associated

with a GSI, as discussed in the statement of considerations (SOC) accompanying the final rule,

60 FR 22484, May 8, 1995:

• If the issue is resolved before the renewal application is submitted, the applicant can incorporate the

resolution into the LRA.

• An applicant can submit a technical rationale that demonstrates that the CLB will be maintained until

some later point in the period of extended operation, at which time one or more reasonable options

would be available to adequately manage the effects of aging.

• An applicant can develop a plant-specific aging management that incorporates a resolution to the

aging issue.

Pursuant to the requirements of 10 CFR Part 50, the staff will evaluate the applicant’s

compliance to the resolution of GSI-168 after its issuance and prior to the extended period of

operation as part of 10 CFR 50.49. Resolution of GSI-168 pursuant to Part 50 meets the

requirement of 10 CFR 54.21(c)(1)(iii) and is therefore considered acceptable.

Data Collection and Reduction Methods
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With regard to the attribute, Data Collection and Reduction Methods, for re-analysis of the EQ

aging evaluation, Section X.E1 of NUREG-1801 states –

A representative number of temperature measurements are conservatively evaluated to establish the temperatures

used in an aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as

(a) directly applying the plant temperature data in the evaluation or (b) using the plant temperature data to

demonstrate conservatism when using plant design temperatures for an evaluation. Any changes to material

activation energy values as part of a re-analysis are to be justified on a plant-specific basis. Similar methods

of reducing excess conservatism in the component service conditions used in prior aging evaluations can be used

for radiation and cyclical aging.

By letter dated March 28, 2003, the staff requested, in RAI 4.4-4, that the applicant clarify the

extent to which the VCSNS EQ Program is consistent with this attribute. In its response dated

June 12, 2003, the applicant stated the following:

“The VCSNS EQ Program is fully consistent with this attribute contained within Section X.E1 of NUREG-1801.”

Based on this response, the staff concluded that any change to a component’s material

activation energy value, if it is determined to be a necessary part of re-analysis pursuant to 10

CFR 54.21(c)(1)(iii), will be justified. The staff, through the VCSNS EQ Program, together with

other plant programs/processes required by 10 CFR Part 50, will evaluate the applicant’s

justification for any change to a component’s material activation energy value. The staff has

concluded that the VCSNS EQ Program, together with other plant programs/processes required

by 10 CFR Part 50, will adequately manage a component’s aging during the period of extended

operation as required by 10 CFR 54.21(c)(1)(iii). Therefore, justification pursuant to the

requirements of 10 CFR Part 50 meets the requirements of 10 CFR 54.21(c)(1)(iii) and is

considered acceptable.

Environmental Qualification Program Aging Process

Section 4.4 (3d paragraph) of the LRA indicates that each of the EQ documentation binders

contains or references either a calculation of qualified life or an evaluation to justify a qualified

life. By letter dated March 28, 2003, the staff requested, in RAI 4.4-1, that the applicant

describe and justify the evaluation method utilized to justify a qualified life and to extend the

qualified life from 40 to 60 years when the analytical EQ re-analysis method using calculations

described in NUREG-1801 is not used. In its response dated June 12, 2003, the applicant

stated the following:

The Arrhenius methodology is the approved model used for calculating thermal qualified life of 10 CFR 50.49

equipment at VCSNS. As discussed in the LRA, Section 4.4.1.2, there may be some reduction of excess

conservatism in service conditions from previous evaluations when sufficient information is available; however,

the Arrhenius model is used in processing thermal qualified life determinations in accordance with approved

Engineering Services calculation procedures.

Based on this response, the staff concluded that the applicant intends to utilize the analytical

EQ re-analysis method using calculations described in NUREG-1801, for all cases, to justify

extending the qualified life from 40 to 60 years; however, an evaluation method may be utilized

if sufficient information is available to extend the qualified life from 40 to 60 years pursuant to

the requirements of 10 CFR 50.49. The staff, through the VCSNS EQ Program, together with

other plant programs/processes required by 10 CFR Part 50, will evaluate the applicant’s

evaluation method and information for justifying the qualified life extension. The staff has
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concluded that the VCSNS EQ Program, together with other plant programs/processes required

by 10 CFR Part 50, will adequately manage a component’s aging during the period of extended

operation as required by 10 CFR 54.21(c)(1)(iii). Therefore, utilization of an evaluation method

for extending qualified life pursuant to the requirements of 10 CFR Part 50 meets the

requirements of 10 CFR 54.21(c)(1)(iii) and is considered acceptable.

Electrical Penetration Assemblies

By letter dated March 28, 2003, the staff requested, in RAI 4.4-3, that the applicant explain why

(and to what extent) electrical penetration assemblies are not subject to aging (or qualified life)

requirements of 10 CFR 50.49. In its response dated June 12, 2003, the applicant stated the

following: 

All electrical penetrations are included within the VCSNS Harsh EQ Program and meet the requirements of 10 CFR

50.49. All VCSNS electrical penetrations are subject to a TLAA. Non-Class 1E electrical penetrations were

previously conservatively listed as requiring an aging management review because of their non-Class 1E status

[Reference LRA 3.6.1.4]. The Aging management review is not required as these electrical penetrations have a

qualified life that is administratively controlled within the EQ Program, are handled the same as class 1E

penetrations, and are screened out in 54.21(a)(1)(ii).

Although the non-1E electrical penetrations are covered within the EQ Program as a TLAA, the EQ Program does

not include the non-1E cables leading up to the electrical penetrations, the splices or connections inside and outside

the RB. These non-EQ components will be included in the Cables and Connections Aging Management Program.

Based on this response, the staff concluded that those portions of electrical penetration

assemblies included within the scope of VCSNS EQ Program are subject to a TLAA. 

Therefore, these portions will be adequately managed, through the VCSNS EQ Program,

together with other plant programs/processes, during the period of extended operation as

required by 10 CFR 54.21(c)(1)(iii) and are considered acceptable. Non-1E cable leading up to

the electrical penetrations and splices or connections inside and outside the reactor building are

not considered part of the assemblies and have not been included in the VCSNS EQ Program.

These are subject to an aging management review (AMR) as required by 10 CFR 54.21(a)(1). 

4.4.3 Conclusions

The staff has reviewed the information in Section 4.4 of the LRA. On the basis of this review,

the staff concludes that the applicant has demonstrated that the effects of aging on the

intended function(s) of electrical components, that meet the definition for TLAA as defined in 10

CFR 54.3, will be adequately managed during the period of extended operation as required by

10 CFR 54.21(c)(1)(iii). In addition, the staff concludes that the FSAR Supplement contains a

summary description of the programs and activities for the evaluation of TLAA for the period of

extended operation as required by 10 CFR 54.21(d).

4.5 Concrete Containment Tendon Prestress

The prestressing tendons in prestressed concrete containments lose their prestressing forces

with time due to creep and shrinkage of concrete, and relaxation of the prestressing steel. 

During the design phase, engineers estimate these losses to arrive at the end of operating life,

normally 40 years. The operating experiences with the trend of prestressing forces indicate

that the prestressing tendons can lose their prestressing forces at a rate higher than predicted
4-24

due to sustained high temperature. Thus, it is necessary to perform TLAAs for the period of

extended operation. The adequacy of the prestressing forces in prestressed concrete

containments is reviewed for the period of extended operation.

4.5.1 Summary of Technical Information in the Application

The VCSNS reactor building has a prestressed containment consisting of hoop and vertical

post-tensioned tendons in the shell wall and a three-way post-tensioned system in the dome.

Section 4.5 of the LRA indicates that the VCSNS Tendon Surveillance Program is based on the

proposed Rev. 3 of RG 1.35. Subsequently, RG 1.35, Rev. 3 was finalized. However, the LRA

states that the NRC accepted the VCSNS Tendon Surveillance Program based on the

proposed Rev. 3 of RG 1.35.

LRA Section 4.5 indicates that programmatic controls are used to ensure that the reactor

building tendons are capable of performing their design function. The LRA states that the

reactor building tendons are a TLAA, and VCSNS will utilize 10 CFR 54.21(c)(1)—Option (iii) to

demonstrate that the effects of aging on the intended function(s) will be adequately managed

for the period of extended operation. The LRA also states that Chapter X.S1, "Concrete

Containment Tendon Prestress", of NUREG-1801, applies to these facilities that adopt 10 CFR

54.21(c)(1)—Option (iii) for containment tendon prestress.

LRA Appendix B.3.3, Tendon Surveillance Program, states that the Tendon Surveillance

Program is consistent with X.S1, "Concrete Containment Tendon Prestress", in NUREG-1801. 

A brief history of the Tendon Surveillance Program is provided which describes when the

various tendon surveillance were performed and some of the significant observations. Several

important observations noted in Appendix B.3.3 and Section 4.5 of the LRA are: (1) tendon

wire relaxation force losses greater than predicted during design, (2) retensioning of vertical

tendons were required because the tendon forces would be below the technical specifications

minimum values prior to the following period surveillance, (3) VCSNS expects that future

retensioning will be needed before 60 years of operation, and (4) substantial amount of water

in-leakage into the auxiliary building tendon sump area has occurred.

4.5.2 Staff Evaluation

As reported in Appendix B.3.3.1 of the LRA, test results from the first three surveillances

indicated that the wire relaxation force losses in the tendon system were greater than the force

losses predicted during design (resulting in lower measured prestressing forces). Therefore, in

June 1988, the predicted wire relaxation force losses were increased from 8.5 percent to 12.5

percent. Then in the fourth period (10th year) tendon surveillance, the vertical tendons were

retensioned because the previous surveillance data indicated that the vertical tendon forces

would be below the technical specifications minimum prior to the fifth period surveillance. 

Although the fifth period (15th year) and sixth period (20th year) tendon surveillance have been

completed, no information was provided regarding the comparison of the measured tendon

forces to the predicted lower limit at the 15th and 20th year tendon surveillance. LRA Section

4.5 indicates that, based on trending data and results from previous surveillance, VCSNS does

not currently expect the tendons to provide adequate prestress for 60 years without future

retensioning of various members.
4-25

In order to make a reasonable assessment regarding the effectiveness of the TLAA, the staff

requested, in RAI 4.5-1, that the applicant provide the following information:

(a) Based on the measurements collected to date, provide the plots of the measured lift-off

forces and trend lines, along with the predicted lower limits and minimum required values for

the three sets of tendons (vertical, horizontal, and dome). These curves should reflect the past

retensioning of the tendons. Identify whether the guidance in Information Notice (IN) 99-10 is

implemented.

(b) Provide a brief discussion regarding the reason why the tendon wire relaxation values were

greater than those used in the design of the tendon system. Are there any unique

characteristics of the VCSNS tendons or containment design that would cause this to occur? If

known, describe operating experience at other plants where similar tendon behavior has

occurred.

In its response to RAI 4.5-1, the applicant stated –

(a) Plots of the measured lift-off forces and trend lines, along with the minimum required values for the three sets

of tendons (vertical, horizontal, and dome) are provided in Attachment XII. Guidance of IN 99-10 has also been

implemented at VCSNS.

(b) Based on elongation tests performed at Leheigh University for VCSNS tendon wire samples, it was found that

stress relaxation of the tendons was not linearly proportional to temperature as originally projected based on

manufacturer data. Therefore, stress relaxation was increased from 8.5% to 12.5% based on these tests. SCE&G

is not aware of any unique characteristics of the VCSNS tendons or containment design that

would cause this to occur, nor operating experience of similar behavior.

The staff review of the plots of the measured lift-off forces and trend lines, and the comparison

to the minimum required values for the vertical, horizontal, and dome tendons, demonstrate that

the approach being used is consistent with the TLAA AMP X.S1, Tendon Surveillance Program,

identified in NUREG-1801. On this basis, the TLAA for concrete containment tendon prestress

at VCSNS is in accordance with 10 CFR 54.21(c)(1)—Option (iii). Conformance to the guidance

of IN 99-10 has been confirmed by VCSNS.

A description was provided by VCSNS which explains why the tendon wire relaxation values,

greater than those used in design, occurred at VCSNS. Regardless of the cause, the staff

concludes that this aging effect will be adequately managed by implementation of the VCSNS

Tendon Surveillance Program. 

4.5.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation for the concrete

containment tendon prestress TLAA. Therefore the staff has reasonable assurance that the

safety margins established and maintained during the current operating term will be maintained

during the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii).

4.6 Containment (Reactor Building) Liner Plate, Metal Containment, and

Penetration Fatigue Analysis
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4.6.1 Containment (reactor building) Liner

4.6.1.1 Summary of Technical Information in the Application

The applicant stated that the reactor building liner at VCSNS provides an essentially leak-tight

membrane on the inside face of the prestressed concrete reactor building that is designed to

contain airborne radioactive particles and gases due to postulated accidents, such as a LOCA. 

The liner has been designed to remain within ASME Boiler and Pressure Vessels, Section III,

stress limits.

The reactor building liner was designed under ASME Section III, Subsection NE, 1974, with all

applicable addenda. The requirements for liner fatigue analysis were evaluated in accordance

with Paragraph NE-3131. The applicant performed the necessary comparisons and

calculations for 40-year operation and concluded that the liner met the criteria of NE-3222.4(d)

for exemption of fatigue analysis. This calculation was evaluated for 60-year operation, and the

applicant concluded that the liner also met the criteria of NE-3222.4(d) for the period of

extended operation. 

4.6.1.2 Staff Evaluation

The applicant stated that a fatigue analysis of the containment (reactor building) liner at VCSNS

was not required, because the plant met the requirements of ASME Code Section III, NE3222.4. The applicant provided the ASME Code calculation in support of its statement. The

staff confirmed that the calculation showed the ASME Code rules for exemption of the fatigue

analysis were satisfied. The staff notes that the applicant’s results are consistent with the

results of similar calculations reviewed by the staff for previous license renewal applications. 

Therefore, the staff finds that the applicant has demonstrated that the fatigue analysis of the

liner is valid for the period of extended operation, in accordance with 10 CFR 54.21 (c)(1).

4.6.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration that the containment liner stress TLAA has been projected to the end of the

period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii). The staff also

concludes that the FSAR Supplement contains an appropriate summary description of the

containment liner stress TLAA evaluation for the period of extended operation, as reflected in

the license condition. Therefore, the staff has reasonable assurance that the safety margins

established and maintained in the containment liner stress TLAA during the current operating

term will be maintained during the period of extended operation, as required by 10 CFR

54.21(c)(1).

4.6.2 Metal Containments

There are no plant-specific TLAAs for a metal containment at VCSNS, since this plant does not

have a metal containment structure.

4.6.3 Containment (Reactor Building) Isolation
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This section addresses isolation bellows fatigue, fracture toughness of the penetration

materials, and effects of radiation.

4.6.3.1 Containment (Reactor Building) Isolation Bellows

4.6.3.1.1 Summary of Technical Information in the Application

Based on FSAR Section 6.2.6.2.1.1, Piping Penetrations and Spares, the applicant stated that

cold piping penetrations are sealed inside and outside containment by flat plates, welded to

both the end of the penetration sleeve and the process pipe. These plates serve to isolate the

containment. Hot piping penetrations are also sealed inside containment by flat end plates,

welded to both the end of the penetration sleeve and the process pipe. On the outside, hot

penetrations are sealed by a single bellows, one end of which is attached to the penetration

sleeve and the other end is attached to the process pipe. Since these penetrations do not use

resilient or flexible seals, these penetrations do not require Type B leakage tests. The applicant

also stated that the fatigue analysis of the penetration bellows do not meet either Criterion 4 or

5 of 10 CFR 54.3 for plant-specific TLAA because they are not credited in a safety

determination and do not perform a containment isolation function. 

4.6.3.1.2 Staff Evaluation

The staff concurs with the applicant’s statement that the fatigue analysis of the bellows does

not meet the criteria in 10 CFR 54.3 for a TLAA, because the bellows are not credited in a

safety determination and do not perform a safety function. However, the applicant did not

provide information regarding the classification and fatigue analyses of the other parts of the

hot penetrations, such as liner plates, sleeves and end plates, which form part of the

containment pressure boundary.

In RAI 4.6.1, the staff requested that the applicant provide justification for not evaluating the

effects of hot process pipe thermal operating transients and other cyclic loads on potential

fatigue of the liner, the hot penetrations, and the process piping at these locations.

The applicant stated in his response that the piping going through the penetrations is classified

as Class 2 piping, analyzed under the rules of ASME Section III, Subsection NC, 1974. As

shown in the FSAR Supplement, the penetrations are classified as Class MC, analyzed under

the rules of ASME Section III, Subsection NE, 1974. In accordance with Subarticle NE-1120,

the penetrations are classified in accordance with the piping to which they are attached. The

penetrations, including the closure plates, were therefore designed and fabricated in

accordance with the requirements for Class 2 components of Subsection NC. 

For Class 2 piping, Subsection NC does not require an explicit fatigue analysis. Rather, the

fatigue due to full range thermal and mechanical cycling loads is accounted for implicitly in the

Class 2 design stress limits by the use of stress range reduction factors. At VCSNS, the

chosen factor (1.0) assumes that all Class 2 piping will be subjected to at most 7,000 full

thermal cycles of heat up and cool down from ambient to the pipe normal operating conditions.

This is considerably larger than the expected number of full heat up and cool down cycles

expected during the life of the plant, including the period of extended operation. 
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The applicant stated that the penetration sleeve forms a rigid anchor embedded within the

concrete containment walls, while the process pipe is welded to the sleeve through the flat 

plates. The welds were therefore effectively evaluated for fatigue based on the Class 2 rules

and found acceptable for 7,000 cycles. The sleeve is also welded to the liner through a 

thickened liner reinforcing plate. Since it rigidly embedded in the concrete shell, the effect of

hot service pipe thermal cycling on this weld is minimal. Per Section 3.8.1.1.2.2(1) of the FSAR

Supplement, the sleeve-liner weld falls within the jurisdiction of Subsection NE, and is therefore

evaluated for fatigue according to Subsection NE rules for the liner plates. The applicant

stated, in paragraph 4.6.1.1 of the LRA, that the operating conditions on the liner satisfied the

requirements for exemption of a fatigue analysis stated in NE-3222.4(d). The weld therefore

also meets the requirements for exemption of a fatigue analysis, in accordance with the staff

evaluation stated above in Section 4.6.1.2 of this safety evaluation. 

4.6.3.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration that the piping penetration flat plate fatigue TLAA has been projected to the end

of the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i). Therefore the

staff has reasonable assurance that the safety margins established and maintained in the

containment piping penetration fatigue TLAAs during the current operating term will be

maintained during the period of extended operation, as required by 10 CFR 54.21(c)(1)(i).

4.6.3.2 Containment (Reactor Building) Isolation - Fracture Toughness and Effects of Radiation

4.6.3.2.1 Summary of Technical Information in the Application

The applicant stated that the FSAR and the corresponding NRC SER NUREG-0717 include

statements regarding the life of materials used in the reactor building penetrations and the

fracture toughness of the containment pressure boundary. FSAR Supplement Section 6.2.4.5

states that the materials for containment isolation system components were selected to perform

their design function for 40 years based on an integrated radiation dose of 108

 rads. All

materials that come in contact with the reactor building spray solution are resistant to corrosion. 

 However, the statement that components would perform their design function for 40 years was

unsupported in that no analyses were identified that specifically calculated the design life. No

TLAAs were therefore identified for these components.

The applicant evaluated the statements in NUREG-0717, regarding the NRC assessment of the

ferritic materials used in the construction of the containment pressure boundary and its

components, and concluded that the NRC had determined that the ferritic materials meet the

appropriate requirements of the ASME Code, comply with GDC-51 “Fracture Prevention of

Containment Pressure Boundary,” and behave in a nonbrittle manner.

4.6.3.2.2 Staff Evaluation

The staff concurs with the applicant that this section does not meet the criteria for a TLAA,

since no analyses or calculations were identified that require revision for the time effects of

radiation on containment isolation components.

4.6.3.2.3 Conclusions
4-29

The analysis of the reactor building containment isolation for fracture toughness and the effects

of radiation do not meet the criteria stated in 10 CFR 54.3 for the definition of a TLAA, since no

analyses or calculations have been identified that require revision for the time effects of

radiation on containment isolation components.

4.7 Other Plant-Specific Time-Limited Aging Analyses

There are certain plant-specific safety analyses that may have been based on an explicitly

assumed 40-year plant life and, therefore, may be TLAAs. Pursuant to 10 CFR 54.21(c)(1), a

license renewal applicant is required to evaluate TLAAs, as defined in 10 CFR 54.3. License

renewal reviews focus on the period of extended operation. 

The applicant has identified four additional TLAAs for license renewal:

• reactor coolant pump flywheel

• leak-before-break analysis for resolution of USI A-2

• crane load cycle limit

• service water intake structure settlement

The staff’s evaluation of these TLAAs is provided below.

4.7.1 Reactor Coolant Pump Flywheel

4.7.1.1 Summary of Technical Information in the Application

Section 4.7.1 of the LRA and Section 18.3.6.3 of Appendix A to the LRA address the concerns

for fatigue crack initiation and growth in the VCSNS reactor coolant pump (RCP) flywheels. 

During normal operation, the RCP flywheel possesses sufficient kinetic energy to potentially

produce high-energy missiles in the unlikely event of failure. The aging effect of concern is

fatigue crack initiation in the flywheel bore keyway from stresses due to starting the motor. The

applicant states that WCAP-14535A, Topical Report of Reactor Coolant Pump Flywheel

Inspection Elimination, supports the elimination of RCP flywheel inspections, based on the

insignificant increase in probability of failure achieved by inspections over a 60-year service life,

the relatively robust nature of flywheels with respect to detectable flaws, and the likelihood that

disassembly and reassembly for continued inspections presented the largest risk of causing

flaws in the RCP flywheels. WCAP-14535A, which has been approved by the NRC, concludes

that the crack growth for the postulated flaw over 60 years of operation is acceptable.

4.7.1.2 Staff Evaluation

The staff-approved version of WCAP-14535, Topical Report of Reactor Coolant Pump

Flywheel Inspection Elimination,” was published as WCAP-14535A in November 1996. This

report also includes the staff’s RAIs and SER for WCAP-14535. The applicant states that

WCAP-14535A allows the elimination of RCP flywheel inspections. However, the information

presented in WCAP-15666, Extension of Reactor Coolant Pump Motor Flywheel Examination,”

Rev. 0, Non-Proprietary Class 3, July 2001, contradicts the applicant’s statement. According to

WCAP-15666, the staff’s SER, which is included in WCAP-14535A, does not allow total

elimination of inspections. In addition, the applicant states that WCAP-14535A supports the
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elimination of RCP flywheel inspections based on the insignificant increase in probability

achieved by inspections over a 60-year service life. However, according to WCAP-15666, the

staff has stated in the SER that it had not reviewed the risk assessment discussion presented in

WCAP-14535, but solely relied on the deterministic methodology to review the submittal.

The staff issued RAI 4.7.1-1, which requested the applicant discuss how WCAP-14535 is

applicable to the VCSNS RCP flywheel and confirm whether VCSNS has submitted for staff

review its assessment of the plant-specific applicability of WCAP-14535 for V.C. Summer. The

RAI also requested that the applicant identify the material used to fabricate the flywheel and

confirm whether the VCSNS flywheel belongs to a specific flywheel group as defined by WCAP14535.

In response to RAI 4.7.1-1, in a letter dated June 12, 2003, the applicant submitted the

following information. The applicant indicated that WCAP-14535A has not been previously

docketed by VCSNS. The generic report has been docketed by Westinghouse and it is

applicable to VCSNS. The VCSNS RCP flywheels are included in Group 3 of the WCAP

classification. The WCAP classification is according to the geometric and physical

characteristics of the flywheel including outer diameter, bore diameter, keyway radial length,

pump and motor inertia, and material. Also, the VCSNS RCP flywheels are fabricated with SA

533B material. According to the SER for WCAP-14535, Group 3 flywheels satisfy the ductile

fracture criterion, nonductile fracture criterion, and excessive deformation criterion of RG 1.14,

“Reactor Coolant Pump Flywheel Integrity,” 1971, Rev. 1, August 1975. VCSNS has

conservatively treated the RCP flywheel as a TLAA due to the fatigue issues of that component,

the WCAP, and previous applicants’ submittals.

The regulatory position of RG 1.14 concerning inservice inspection (ISI) calls for an in-place

ultrasonic volumetric examination of the areas of higher stress concentration at the bore and

keyway at approximately 3-year intervals, and a surface examination of all exposed surfaces

and complete ultrasonic volumetric examination at approximately 10-year intervals. Operating

power plants have been inspecting their flywheels for over 20 years, and no flaws have been

identified that affect flywheel integrity. Because of this inspection record and the concerns over

high inspection costs and personnel radiation exposure, WCAP-14535 was submitted to

demonstrate, through fracture mechanics analysis, that flywheel inspections can be eliminated

without impairing plant safety. However, the staff does not accept the elimination of flywheel

inspection. Instead, in the SER for WCAP-14535, the staff recommends that a licensee with

Group 3 flywheels should either conduct a qualified in-place Ultrasonic Testing (UT)

examination over the volume from the inner bore of the flywheel to the circle of one-half the

outer radius, or conduct a surface examination of exposed surfaces defined by the volume of

the disassembled flywheels once every 10 years. The applicant, in its response to RAI 4.7.1-1,

states that it does not intend to eliminate the current 10-year inspection through the license

renewal submittal. The staff finds the response acceptable because it is consistent with the

staff position concerning the ISI of reactor coolant pump flywheels.

WCAP-14535-A contains a fatigue crack growth analysis as part of the integrity evaluation for

the RCP flywheel. The estimated magnitude of fatigue crack growth during plant life was

conservatively calculated based on an assumed initial radial crack length of 10% through the

flywheel. The analysis assumed 6000 cycles of pump starts and stops for a 60-year plant life. 

Crack growth from postulated flaws in each flywheel was only a few mils. The existing analysis

is valid for the period of extended operation because reaching 6000 starts in 60 years would
4-31

require a pump start on average every 3.7 days, which is extremely conservative. Therefore,

the findings of this analysis, which has been recently approved by the NRC, indicated that the

crack growth for the postulated flaw over 60 years of operation is acceptable. The analysis in

WCAP-14535A is applicable for 60 years of operation in accordance with 10 CFR

54.21(c)(1)(ii). 

4.7.1.3 Conclusions

On the basis of its review, the staff concludes that the applicant has presented an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1), that, for the RCP flywheel TLAA, the analyses

will remain valid for the period of extended operation. The staff also concludes that the FSAR

Supplement contains an appropriate summary description of the reactor coolant pump flywheel

TLAA evaluation for the period of extended operation. Therefore, the staff has reasonable

assurance that the safety margins established and maintained during the current operating term

will be maintained during the period of extended operation, as required by 10 CFR

54.21(c)(1)(ii).

4.7.2 Leak-Before-Break Analysis

4.7.2.1 Summary of Technical Information in the Application

Section 4.7.2 of the LRA and Section 18.3.2.2 of Appendix A to the LRA address leak-beforebreak (LBB) analyses for the primary loop piping of the VCSNS RCS. Westinghouse tested

and analyzed crack growth with the goal of eliminating RCS primary loop pipe breaks from plant

design bases. The objective of the investigation was to determine whether a postulated crack,

causing a leak, will grow to become unstable and lead to a full circumferential break when

subjected to the worst possible combinations of plant loading, including the effects of safeshutdown earthquake. The detailed evaluation showed that the reactor coolant piping is not

subject to such unstable conditions under the worst combination of plant loading. The VCSNS

LBB analyses consider the thermal aging of the CASS material of the piping as well as the

fatigue transients that drive the flaw growth over the operating life of the plant. In a letter dated

January 11, 1993, the NRC approved the VCSNS LBB analysis. VCSNS has recently updated

its LBB analysis to account for the replacement of steam generator, power uprate, and the RCS

A-hot leg repair.

The VCSNS LBB analysis is based on stainless steel at 40 years and needs to be revised to

account for the period of extension. The applicant elects to utilize 10 CFR 54.21(c)(1)(ii) to

develop a revised LBB analysis for the period of extended operation.

4.7.2.2 Staff Evaluation

The applicant states that the current VCSNS LBB analysis is for 40 years of operation and

accounts for the replacement of steam generators, power uprate, and the RCS A-hot leg repair.

As a result of the VCSNS event in which primary water stress corrosion cracking (PWSCC) was

identified in an Inconel 82/182 main coolant loop-to-reactor pressure vessel weld, the NRC staff

has become concerned about the impact of PWSCC on licensee LBB evaluations.

NUREG-1061, Volume 3, Report of the U.S. Nuclear Regulatory Commission Piping Review

Committee, Evaluation of Potential for Pipe Breaks,” which addresses the general methodology
4-32

accepted by the NRC staff for demonstrating LBB behavior, stipulates that no active

degradation mechanism may be present in a line which is under consideration for LBB. Draft

Standard Review Plan 3.6.3, Leak-Before-Break Evaluation Procedures,” suggests that lines

with potentially active degradation mechanisms may be considered for LBB approval provided

that two mitigating actions/programs are in place to address the potential active degradation

mechanism.

The NRC considers the resolution of the impact of PWSCC on existing LBB evaluations to be a

10 CFR Part 50, operating reactor issue. The NRC staff has previously addressed this issue

with the industry’s PWR Materials Reliability Program (MRP) and received an interim report

from the MRP, “PWR Materials Reliability Program, Interim Alloy 600 Safety Assessment for

U.S. PWR Plants (MRP-44), Part 1: Alloy 82/182 Pipe Butt Welds,” dated April 2001, which

attempted to provide a technical basis for addressing this issue. The NRC expects to receive a

final version of the report, MRP-44, Part 1, from the MRP. Based on the information in the final

MRP report and any additional, relevant information available to the NRC staff, the NRC will

evaluate what actions or analyses, if any, may be required to confirm the continued applicability

of existing licensee LBB evaluations.

Regarding the VCSNS LRA, the staff issued RAI 4.7.2-1, which requested that the applicant 

provide a licensee commitment which states that for the period of extended operation of

VCSNS, it will implement actions or perform analyses, as deemed necessary by the NRC, to

confirm continued applicability of existing VCSNS LBB evaluations. These actions or analyses

will be consistent with those required to address the impact of PWSCC on existing LBB

evaluations under 10 CFR Part 50 considerations. The RAI also requested that the applicant

submit information about any mitigative actions (e.g., mechanical stress improvement) that may

have taken place at VCSNS since submittal of the LRA to manage PWSCC cracks in Alloy

82/182 piping welds and confirm whether the future VCSNS LBB analysis will account for these

mitigative actions. In response to RAI 4.7.2-1 in a letter dated June 12, 2003, the applicant

confirms that the commitments made by VCSNS in response to the PWSCC cracking of the

RCS piping will continue into the period of extended operation. The staff finds the applicant’s

response acceptable because the applicant will continue its commitments made in response to

PWSCC cracking of RCS piping into the period of extended operation. The applicant also

states that VCSNS has implemented mechanical stress improvement activities for the two hot

leg nozzle-to-piping welds that were not repaired. The information associated with this effort

was submitted to the NRC, and an SER dated October 1, 2002, from Karen R. Cotton to

Stephen A. Byrne was issued. As discussed in this SER, the staff reviewed an analytical

evaluation of applying the MSIP to the VCSNS reactor pressure vessel hot leg nozzle welds

and agreed with the licensee’s assertion that the driving force for the cracks has been either

removed or greatly reduced. In its response to RAI 4.7.2-1, the applicant also states that

because of the mechanical stress improvement activities, the LBB report did not need to be

revised. The staff finds this response acceptable because the application of MSIP has

eliminated or reduced the driving force for PWSCC cracks and, therefore, the applicant does

not need to revise its LBB report. The applicant elects to utilize 10 CFR 54.21(c)(1)(ii) to

develop in the future a revised LBB analysis for the period of extended operation. This is

acceptable because the revised LBB analysis will be submitted for the staff review and

approval.

4.7.2.3 Conclusions
4-33

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that, for the LBB TLAA, the LBB analyses

will be revised to the end of the period of extended operation. The staff also concludes that the

FSAR Supplement contains an appropriate summary description for the evaluation of LBB

TLAA for the period of extended operation, as reflected in the license condition. Therefore the

staff has reasonable assurance that the safety margins established and maintained during the

current operating term will be maintained during the period of extended operation, as required

by 10 CFR 54.21(c)(1).

4.7.3 Crane Load Cycle Limit

4.7.3.1 Summary of Technical Information in The Application

The applicant identified cranes and associated crane supports as TLAAs because they could

affect irradiated fuel during refueling operations. The following cranes meet the criterion.

• Reactor Building Polar Crane

• Spent Fuel Cask Handling Crane

• Fuel Handling Machine (Spent Fuel Pit Bridge and Hoist)

• Refueling Machine (Reactor Cavity Manipulator Crane)

The applicant states that the Crane Manufacturers Association of America (CMAA)

Specification No. 70 (CMAA 70) classifies these cranes as Class “A” cranes. CMAA 70 Class A

is defined in paragraph 2.2 as “cranes which may be used in installations such as powerhouses, public utilities, turbine rooms, motor rooms and transformer stations where precise

handling of equipment at low speeds with long idle periods between lifts are required. Capacity

loads may be handled for initial installation of equipment or infrequent maintenance.”

The current version of CMAA 70, Section 2.8, “Crane Service in Terms of Load Class and Load

Cycles” states that Class A Cranes should be designed for 20,000 to 100,000 load cycles. 

However, according to the applicant, the version of CMAA 70 in effect during VCSNS

construction lists 20,000 to 200,000 load cycles. Since the cranes listed above were designed

to the earlier CMAA 70 requirements according to the applicant, the higher load cycle limits

apply. Cranes and crane supports are considered a TLAA because they satisfy the six criteria

for a TLAA defined in 10 CFR 54.3.

The applicant states that the reactor building polar crane, including the bridge girders, end

trucks, and trolley, were originally designed for construction loads of 360 tons. A seismic

analysis was performed for the maximum, nonconstruction load of 150 tons. Since

construction, the polar crane was only used for capacity lifts during the VCSNS steam

generator replacement project. The steam generator lifts were rated capacity lifts of 354 tons. 

Lifts of the lower internals (135 tons), vessel head (125 tons), upper internals (52 tons), RCPs,

missile shields, and other routine refueling operation lifts are commonly done during an outage

and do not exceed the seismic load limit of 150 tons. According to the applicant, lifts of 150

tons or less do not qualify as capacity lifts since they are far less than the crane’s rated capacity

of 360 tons.
4-34

The applicant has provided an estimate of the projected number of lifts for the polar crane

during a 60-year period of operation. This estimate has been shown to be well within the CMAA

70 limit of 200,000 cycles. Therefore, the applicant concludes that the crane is adequately

analyzed and designed for fatigue through the term of extended operation.

The spent fuel cask handling crane is rated for 125 tons. The projected number of fuel cask

lifts for this crane also has been estimated by the applicant to be far less than 200,000 CMAA

70 limit over a 60-year period. Therefore, according to the applicant, the spent fuel cask

handling crane is adequate for the period of extended operation.

The fuel handling machines consist of a fuel handling machine (spent fuel pit bridge and hoist)

and refueling machine (reactor cavity manipulator crane).

The refueling machine and fuel handling machine lift load consist of the combination of a spent

fuel or new fuel assembly and handling tool. The maximum load weighs approximately 2500

pounds. The refueling machine crane is rated for 3000 pounds.

The fuel handling machine hoist is designed with a margin of two for lifts. The hoist capacity is

4000 pounds while the combined weight of the fuel assemble with a rod cluster control

assembly and the spent fuel assembly handling tool is approximately 2000 pounds. The fuel

handling machine structure is designed to commercial standards and also analyzed to the

requirements of Section III, Appendix XVII of the ASME Boiler and Pressure Vessel Code, and

has the margins included in the allowable stresses of the Code.

As with the other cranes discussed above, the applicant has provided an estimate to

demonstrate that the total number of loading cycles during 60 years of operation would be far

less than the originally designed 200,000 lift cycles based on the CMAA 70 requirements.

Therefore the applicant has elected to utilize 10 CFR 54.21(c)(1) – Option (i) to demonstrate

that the fuel handling machines and reactor building polar crane are adequately analyzed for

the period of extended operation.

4.7.3.2 Staff Evaluation

The method of review applicable to the crane cyclic load limit TLAA involves (1) reviewing the

existing 40-year design basis to determine the number of load cycles considered in the design

of each of the cranes in the scope of license renewal, and (2) developing 60-year projections

for load cycles for each of the cranes in the scope of license renewal and compare them to the

number of design cycles for 40 years.

Section 4.7.3.1 of the LRA addresses the reactor building polar crane. The LRA states that,

“The number of lifts was based on one lift for each replaced (old) D-3 steam generator and one

for each replacement (new) Delta 75 steam generator, which yields a total of six capacity lifts. 

Imposing an extremely conservative safety factor of five yields 30 lifts. Assuming a similar

number of lifts during initial construction yields an estimate of 60 lifts. In addition, the crane

lifted the reactor (330 tons) during construction.” The staff concurs with the applicant’s

estimate of 61 lifts and finds it to be less than the CMAA 70 limit of 200,000 cycles by several

orders of magnitude. Therefore, the staff finds that the reactor building polar crane was

adequately evaluated for the period of extended operation.
4-35

The projected number of fuel cask lifts for the spent fuel cask handling crane is based on the

assumption that 70 fuel bundles are replaced every 18 months for 60 years, in addition to the

original 157 bundles. It is also assumed that each bundle is loaded individually into separate

casks, and each cask lifted twice. This adds up to a total number of approximately 10,000 lifts. 

The staff concurs with the applicant’s assessment and finds it to be reasonable and

conservative. Since it is within the CMAA-70 limit for the crane by a wide margin, the staff finds

that the spent fuel cask handling crane has been adequately evaluated for the period of

extended operation.

The fuel handling cranes are assumed to perform 400 lifts each refueling cycle for each

machine. This consists of 70 loadings of new fuel assemblies, a full core offload of 157 fuel

assemblies, a full core reload of 157 fuel assemblies, and 16 miscellaneous fuel assembly

shuffles. With 40 refueling cycles in 60 years, this adds up to a total of approximately 16,000

cycles in 60 years. The staff finds the applicant’s estimate reasonable. The fuel handling

cranes were analyzed for up to 200,000 cycles of maximum load based on the crane

manufacturer’s calculations and CMAA Specification No. 70. Since a conservative estimate of

load cycles is far less than the design limit in CMAA 70 (as well as the 100,000 cycles limit in

the current version of CMAA 70), the staff finds that the fuel handling cranes were adequately

evaluated for the period of extended operation.

4.7.3.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1), that for the crane cycle load limit TLAA, the

analyses have been projected to the end of the period of extended operation. The staff also

concludes that the FSAR Supplement contains an appropriate summary description of the

metal fatigue TLAA evaluation for the period of extended operation, as reflected in the license

condition. Therefore the staff has reasonable assurance that the safety margins established

and maintained during the current operating term will be maintained during the period of

extended operation, as required by 10 CFR 54.21(c)(1).

4.7.4 Service Water Intake Structure Settlement

4.7.4.1 Summary of Technical Information in the Application

The service water intake structure (SWIS) at VCSNS is a reinforced rectangular box culvert

with two reinforced concrete wing walls at the intake end. The SWIS is mostly buried within the

west embankment and the portion that is not covered by soil is submerged within the service

water pond. The function of the SWIS is to draw water from the service pond into the service

water pumphouse (SWPH).

LRA Section 4.7.4 indicated that excessive nonuniform settlement of the intake structure

occurred during construction which caused considerable cracking. This settlement was

analyzed in a SWPH calculation, which was originally based on a plant design life of 40 years.

Since this issue meets all six criteria in 10 CFR 54.3, the applicant concluded that SWIS

settlement is a TLAA for VCSNS.
4-36

The LRA indicated that the VCSNS calculation was revised to account for the period of

extended operation (60 years). The applicant concluded that this revision demonstrated that

the expected settlement is acceptable for the period of extended operation. Therefore, VCSNS

incorporated Option (ii) to satisfy 10 CFR 54.21(c)(1) for the SWIS settlement.

4.7.4.2 Staff Evaluation

The staff concurs that SWIS settlement is a TLAA for VCSNS. In addition, the staff finds it

acceptable for the applicant to address SWIS settlement using Option (ii) of 10 CFR 54.21(c)(1)

by revising existing calculations to account for the period of extended operation to 60 years.

The staff notes that no description of the analytical methodology or summary of the results

utilized in the TLAA calculation have been provided in the LRA. During the AMR inspection

(August 18-22, 2003; IR 50-395/03-08, dated September 29, 2003), the staff reviewed

numerical calculation demonstrating that changing from a 40-year operating life to a 60-year

operating life has no impact on the conclusions reached in the original calculation, namely that

maximum predicted sublayer fill compaction will be about 2 inches. 

VCSNS has committed in the LRA to a Service Water Structures Survey Monitoring Program

and an Under Water Inspection Program (SWIS and SWPH). The Service Water Structures

Survey Monitoring Program is an AMP which monitors any vertical or horizontal movement

associated with settlement of the SWIS, SWPH, electrical duct banks, and service water intake

line “A.” The survey monitoring data is reviewed by VCSNS Design Engineering to ensure that

settlements remain within established criteria. The Underwater Inspection Program (SWIS and

SWPH) is an AMP which visually inspects the interior length of the intake tunnel, survey

monitoring masts, trash racks, access ladder and east end wing walls. The main reason for

inspecting the SWIS is to measure/monitor cracks (old and new) in the concrete structure that

originated due to earlier settlement. The staff evaluations of the Service Water Structures

Survey Monitoring Program and the Under water Inspection Program (SWIS and SWPH) as

AMPs are presented in SER Sections 3.5.2.3.10 and 3.5.2.3.11, respectively.

The staff considers the VCSNS Service Water Intake Structure Settlement TLAA performed in

accordance with Option (ii) of 10 CFR 54.21(c)(1) to be acceptable. 

4.7.4.3 Conclusions

On the basis of its review, the staff concludes that the applicant has provided an acceptable

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that, for the Service Water Intake Structure

Settlement TLAA, the analyses have been projected to the end of the period of extended

operation. The staff also concludes that the FSAR Supplement contains an appropriate

summary description of the Service Water Intake Structure Settlement TLAA evaluation for the

period of extended operation, as reflected in the license condition. Therefore, the staff has

reasonable assurance that the safety margins established and maintained during the current

operating term will be maintained during the period of extended operation, as required by 10

CFR 54.21(c)(1).

4.8 Conclusion for Time-Limited Aging Analyses
4-37

On the basis of its review of the TLAAs, the staff concludes that actions have been identified

and have been or will be taken with respect to TLAAs that have been identified to require review

under 10 CFR 54.21(c) such that there is reasonable assurance that the activities authorized by

a renewed license will continue to be conducted in accordance with the CLB, as required by 10

CFR 54.29(a).
4-38

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5-1

5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR

SAFEGUARDS

The Advisory Committee on Reactor Safeguards (ACRS) will review the 10 CFR Part 54 portion

of the V.C. Summer license renewal application. The ACRS Subcommittee on

Plant License Renewal will continue its detailed review of the LRA after this report is issued.

South Carolina Electric and Gas Company (SCE&G), and the staff will meet with the

subcommittee committee to discuss issues associated with the review of the LRA. After the

ACRS completes its review of the V.C. Summer LRA and SER, the full committee will issue a

report discussing the results of its review. This report will be included in an update to this SER.

The staff will address any issues and concerns identified in that report.
5-2

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6-1

6 CONCLUSIONS

The staff reviewed the V.C. Summer license renewal application in accordance with

Commission regulations and NUREG-1800, "Standard Review Plan for Review of License

Renewal Applications for Nuclear Power Plants," dated July, 2001. In accordance with 10 CFR

54.29, the staff identifies the standards for issuance of a renewed license.

On the basis of its evaluation of the application as discussed above, the staff has determined

that the requirements of 10 CFR 54.29 have been met. 

The staff notes the requirements of Subpart A of 10 CFR Part 51 are documented in NUREG1427, Draft Supplement 15, "Generic Environmental Impact Statement for License Renewal of

Nuclear Plants," dated July 2003.
6-2

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A-1

APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL

During the review of the VCSNS LRA by the NRC staff, the applicant made commitments

related to aging management programs (AMPs) to manage aging effects of structures,

systems, and components (SSCs) prior to the period of extended operation. The following table

lists these commitments, along with the implementation schedule and the source of the

commitment.
A-2

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A-3

Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

1 The applicability of the VCSNS QA Program applies equally to existing

programs as to new programs being developed for license renewal. Genericstatements regarding the applicability of the VCSNS QA Program will bemade to the FSAR Section 18.1 for all of the programs credited to manageaging effects for in-scope SSCs.

18.1, Introduction. Newtext to be added perRAI response.

Prior to the end ofthe current operatilicense term.

2 The Above Ground Tank Inspection will be consistent with XI.M32, OneTime Inspection, as identified in NUREG-1801. The Above Ground Tank

Inspection will be performed prior to the period of extended operation.

18.2.3, Above GroundTank Inspection

Prior to the end ofthe current operatilicense term.

3 The following enhancements will be incorporated into the Alloy 600 Aging

Management Program. Changes indicated by emerging regulatoryrequirements and developed by the industry groups will be implemented forthe applicable Attributes.

18.2.4, Alloy 600 AgingManagement Program

Prior to the end ofthe current operatilicense term.

4 For those systems outside of containment, VCSNS intends to enhance the

Surveillance Test Procedures already required by Technical Specificationsfor leakage of primary coolant sources outside containment. These leakageassessment tests are for the following systems: Boron Recycle, LiquidWaste, Nuclear Sampling, Chemical and Volume Control, Residual HeatRemoval, and RB Spray. In addition to these, VCS intends to enhance theleak tests performed for the SI Accumulators and the Spent Fuel PoolCooling. These test procedures will be enhanced to specify inspecting forboric acid crystallization on the system being tested and, when boric acid isfound, on surrounding systems. The enhancements to the procedures will benoted on the procedures and maintained as license renewal commitments.

18.2.7, Boric AcidCorrosion Surveillances

Prior to the end ofthe current operatilicense term.

5 The Buried Piping and Tanks Inspection will be consistent with XI.M34,

Buried Piping and Tanks Inspection, as identified in NUREG-1801.

18.2.9, Buried Pipingand Tanks Inspection

Prior to the end ofthe current operatilicense term.

6 Prior to the period of extended operation, one-time inspections will be

conducted In low flow areas of various treated water systems to demonstratethe effectiveness of the Chemistry Program for various material/environmentcombinations.

18.2.10, ChemistryProgram

Prior to the end ofthe current operatilicense term.

7 The Diesel Generator Systems Inspection will be consistent with XI.M32,

One-Time Inspection, as identified in NUREG-1801 prior to the period ofextended operation. The Diesel Generator Systems Inspection will beperformed prior to the period of extended operation.

18.2.13, DieselGenerator SystemsInspection

Prior to the end ofthe current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-4

8 The following enhancement will be incorporated into the Fire Protection

Program prior to the period of extended operations. Sprinklers will either bereplaced or representative samples will be submitted to a recognizedlaboratory for field service testing in accordance with NFPA code 25. Subsequent replacement or field service testing of representative sampleswill occur at 10-year intervals. 

18.2.15.1, Mechanical Prior to the end of

the current operatilicense term.

9 The following enhancement will be incorporated into the Fire Protection

Program prior to the period of extended operations. Ultrasonic testing ofrepresentative portions of above ground fire protection piping that areexposed to water but do not normally experience flow will be performedbefore the end of the current operating term. Ultrasonic testing of arepresentative sample of these stagnant sections of piping will be conductedat 10-year intervals thereafter.

18.2.15.1, Mechanical Prior to the end of

the current operatilicense term.

10 A one-time inspection of the Fire Service System will be performed to

determine if aging management is required for brass and cast ironcomponents during the period of extended operation. The inspection activitywill detect and characterize loss of material due to selective leaching. Thisinspection will use suitable hardness measurement techniques at the mostsusceptible (sample) locations.

18.2.15.1, Mechanical Prior to the end of

the current operatilicense term.

11 The Non-EQ Insulated Cables and Connections Inspection Program will be

consistent with XI.E1, Electrical Cables and Connections Not Subject to 10

CFR 50.49 Environmental Qualification Requirements, as identified in

NUREG-1801 prior to the period of extended operation. In addition to thevisual inspection of in-scope, passive fuse holders on a 10-year periodicityfor indication of age related degradation, the metallic fuse clip portion of thein-scope, passive fuse holders that are found to be susceptible to agerelated degradation, will receive a continuity check or will undergothermography or other appropriate test on a representative sample basis toassure the metallic fuse clip is still making a good connection.

18.2.18, Non-EQInsulated Cables andConnections InspectionProgram

Prior to the end ofthe current operatilicense term.

12 The Aging Management Programs for cracking of the Core Support Pads

and Bottom Head Penetrations include the Alloy 600 Aging ManagementProgram, Chemistry Program, as well as the In-Service (ISI) Plan. ISIinspections are done in accordance with the ASME code requirements. VCSNS is active in industry groups specifically EPRI and WOG. Newdevelopments will be reviewed and if deemed appropriate incorporated intothe aging management of the Core Support Pads and Bottom HeadPenetrations.

18.2.19, In-ServiceInspection (ISI) Plan

Prior to the end ofthe current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-5

13 Inspections for Mechanical Components will manage the relevant aging

effects for mechanical components constructed of carbon steel, low alloysteel, and other susceptible materials. These inspections will follow thesame frequency as Maintenance Rule Inspections (five years) and thebaseline inspection would occur within five years of obtaining the newlicense. Based upon the results of these inspections, or any new industryexperience, the frequency may increase.

18.2.20 Inspections forMechanicalComponents

Every five years wbaseline inspectionwithin five years oobtaining the newlicense

14 The Liquid Waste System Inspection will be consistent with XI.M32, OneTime Inspection, as identified in NUREG-1801 prior to the period of

extended operation. The Liquid Waste System Inspection will be performedprior to the period of extended operation.

18.2.21, Liquid WasteSystem Inspection

Prior to the end ofthe current operatilicense term.

15 The following enhancements will be incorporated into the Maintenance Rule

Structures Program prior to the period of extended operation. (1) - Futureinspections will add: North Berm, Electrical Manhole EMH-2 interiorinspection, Inaccessible Areas when exposed by excavation, Flood BarrierSeals for Control, Intermediate, and Diesel Generator Buildings, Portions ofthe power path from the power circuit breaker (PCB) in the substation to thesafety related buses, and Groundwater chemical analyses. (2) -Groundwater chemical analyses will include: pH, Sulfates and Chlorides. Groundwater chemical analyses will be used to monitor changes inaggressiveness of the below grade environment.

18.2.22, MaintenanceRule StructuresProgram

Prior to the end ofthe current operatilicense term.

16 The Reactor Building Cooling Unit Inspection will be consistent with XI.M32,

One-Time Inspection, as identified in NUREG-1801 prior to the period of

extended operation. The Reactor Building Cooling Unit Inspection will beperformed prior to the period of extended operation.

18.2.26, ReactorBuilding Cooling UnitInspection

Prior to the end ofthe current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-6

17 The Reactor Vessel Internals Inspection will be consistent with XI.M16, PWR

Vessel Internals, as identified in NUREG-1801. The program details have

not been developed. VCSNS will follow industry initiatives and will have theprogram in place prior to the period of extended operation.With respect to cracking due to SCC & IASCC, staff approvedrecommendations of the industry initiatives applicable to inspection of vesselinternals will be implemented. It is the intent of VCSNS to follow staffapproved industry initiatives for these inspections. With respect to IASCC, and loss of fracture toughness due to neutronirradiation embrittement of the RV interval components, VCSNS will followindustry initiatives develop a reactor vessel internals inspection programwhich will be in place prior to the period of extended operation. It is the intentof VCSNS to follow industry initiatives for this inspections. 

18.2.28, ReactorVessel InternalsInspection

Prior to the end ofthe current operatilicense term.

18 With respect to changes in dimensions due to void swelling, industry

activities (including WOG and EPRI) are under way to better characterize theeffect and, if necessary, to develop and qualify methods for detection andmanagement. These activities will be monitored by VCSNS andimplemented, as applicable. It is the intent of VCSNS to follow industryinitiatives for these inspections.

18.2.28, ReactorVessel InternalsInspection

Prior to the end ofthe current operatilicense term.

19 The following enhancement will be incorporated into the Reactor Vessel

Surveillance Program prior to the period of extended operation. Perform aone-time analysis to demonstrate that the materials in the inlet and outletnozzles and upper shell course will not become controlling during the periodof extended operations.

18.2.29, ReactorVessel SurveillanceProgram

Prior to the end ofthe current operatilicense term.

20 A program will be established at the end of RF-14 to ensure that the plant is

operated under conditions to which the surveillance capsules were exposedand the exposure conditions of the Reactor Vessel will be monitored toensure that they continue to be consistent with those used to project theeffects of embrittlement to the end of license. This program will besupplemented or revised by using alternative dosimetry during the period ofextended operation. 

18.2.29, ReactorVessel SurveillanceProgram

RF-15 

21 The Service Air System Inspection will be consistent with XI.M32, One-Time

Inspection, as identified in NUREG-1801. The Service Air System

Inspection will be performed prior to the period of extended operation.

18.2.30, Service AirSystem Inspection

Prior to the end ofthe current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-7

22 The following enhancements will be incorporated into the Service Water

Pond Dam Inspection Program. (1) - Scope - North Dam piezometers will beadded. (2) - Parameters Monitored / Inspected - Water level. (3) -Monitoring and Trending - Inspections will be made every 5-years concurrentwith the RG 1.127 inspections. (4) - Acceptance Criteria - Nominal elevationof adjacent Service Water Pond and Monticello Reservoir.

18.2.31, Service WaterPond Dam InspectionProgram

Prior to the end ofthe current operatilicense term.

23 The Small Bore Class 1 Piping Inspection will be consistent with XI.M32,

One-Time Inspection, as identified in NUREG-1801. The Small Bore Class 1

Piping Inspection will be scheduled at or near the end of the second periodof the fourth ISI interval.VCSNS will evaluate the small-bore class 1 piping with a methodology that isapproved by the Staff. The present approved methodology is to performdestructive examinations of small-bore piping. The approved method will beincorporated into the Small Bore Class 1 Piping Inspection.

18.2.34, Small BoreClass 1 PipingInspection

Before the end of tsecond period of thfourth ISI interval.

24 The Waste Gas System Inspection will be consistent with XI.M32, One-Time

Inspection, as identified in NUREG-1801. The Waste Gas SystemInspection will be performed prior to the period of extended operation.

18.2.39, Waste GasSystem Inspection

Prior to the end ofthe current operatilicense term.

25 The Heat Exchanger Inspections will be consistent with XI.M32, One-Time

Inspection, and XI.M33, Selective Leaching of Materials, as identified in

NUREG-1801. The Heat Exchanger Inspections will be performed prior tothe period of extended operation.

18.2.40, HeatExchanger Inspections

Prior to the end ofthe current operatilicense term.

26 The Area Based Inspections for Refined 10 CFR 54.4(a)(2) Criteria

Commodities is a new one-time inspection that will detect and characterizeloss of material due to general, crevice, and pitting corrosion resulting fromexposure to an unmonitored and uncontrolled water environment. The AreaBased Inspections for Refined 10 CFR 54.4(a)(2) Criteria commodities willbe performed prior to the period of extended operation.

18.2.42. Prior to the end of

the current operatilicense term.

27 This is a new program. A summary description of the X1.E2 GALL type

program was provided. In this program, calibration results on findings ofsurveillance testing programs will be used to identify the potential existenceof aging degradation. This program applies to the in-scope instrumentationcables that are included in the circuit during loop calibrations.

18.2.43. Prior to the end of

the current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-8

28 VCSNS will establish a GALL type program for relevant, non-EQ, in-scope

I&C cables with sensitive, low-level signals for the NI and RM systems. Implementation of an alternate program will be considered, whenappropriate, for low signal level NI and RM circuit cables without loopcalibrations, after the industry finalizes the approach. 

18.2.44. Prior to the end of

the current operatilicense term.

29 VCSNS recognizes the potential uncertainties involved with water treeing,

even with ducts that are sloped to preclude moisture accumulation, and willcreate a program consistent with NUREG-1801 section XI.E3. The VCSNSprogram described herein will result in a 10-year test interval by anappropriate industry approved testing method selected to validate thesatisfactory condition of the cable insulation and to give some assurance ofthe remaining life of the cable, while not damaging the cable itself. Thespecific type of test performed will be determined prior to the initial test. The10-year interval will commence prior to the start of the period of extendedoperation.

18.2.45. Prior to the end of

the current operatilicense term.

30 Additional analyses are required to calculate Charpy Upper-Shelf Energy for

the end of the period of extended operation. Following adequate capsuleexposure, a capsule will be withdrawn and analyzed. The Charpy UpperShelf Energy will be recalculated for additional fast neutron fluencecorresponding to the end of the extended operating period. The capsule willbe tested and will provide bounding data for the EOL fluence of 54 EFPY.

18.3.1.1, Upper-ShelfEnergy

Prior to the end ofthe current operatilicense term.

31 The pressure-temperature limit curves will be recalculated following the

removal of one of the remaining surveillance capsules from the vessel. Thesurveillance capsule will be removed when the calculated fast neutronfluence on the capsule meets or exceeds the calculated fast neutron fluenceon the vessel wall at the end of the period of extended operation. TheTechnical Specifications will be updated as required by 10 CFR 50.61. TheLTOP analysis will be done as part of this calculation revision.

18.3.1.3, PressureTemperature (P-T)Limits

Prior to the end ofthe current operatilicense term.
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-9

32 The VCSNS Thermal Fatigue Management Program will be revised by the

end of the current license term (40 years) to base future projections on 60years of operation and to account for environmental effects of the reactorcoolant environment on RCS components.For the NUREG/CR-6260 locations, VCSNS will evaluate the FatigueEnvironmental Effects prior to the period of extended operation. VCSNS willevaluate the fatigue usage for components with a methodology that Isapproved by the Staff. The present approved methodology Is to use thecorrelations contained In NUREG/CR-6583, for Carbon and Low-Alloy Steelsand NUREG/CR-5704, for Austenitic Stainless Steels. Component CUF willbe maintained below 1.0.

18.3.2.1, ASMESection III, Class 1

Prior to the end ofthe current operatilicense term.

33 The leak-before-break analyses are currently valid for 40 years. The

analyses require revision in order to demonstrate that the design is adequatefor the extended period of operation.

18.3.2.2, Leak-BeforeBreak Analyses Prior to the end of the current operati

license term.

34 [RC Loop ’B’ hot leg sampling portion of SS.] The present sampling method

seldom uses loop sampling. VCSNS will administratively limit of activities onthe "B" RCS loop sampling line in order to account for 60 years of plantoperation. 

18.3.2.3, ASMESection III, Class 2 and3 Piping Fatigue

Prior to the end ofthe current operatilicense term. 

35 Prior to the period of extended operation, the equipment subject to the

provisions of 10 CFR 50.49 will be re-evaluated for 60 years of installation. Components not meeting a 60 year qualified life will be replaced prior toexpiration of qualified life.

18.3.3, EnvironmentalQualification (EQ)

Prior to the end ofthe current operatilicense term.

36 As appropriate, station documents will be revised or established,

implemented, and maintained to cover the aging management programs andactivities described in Chapter 18.

Appendix A Prefix,FSAR Supplement

Varies by programand activity

37 At VCSNS, the Boraflex neutron absorbing sheets will be replaced with Boral

neutron absorbing sheets prior to the Refueling Outage 14 (September2003).

N/A - Agingmanagement is notrequired for the newcomponents.

Completed April2003
Appendix A - VCSNS Commitment List Associated with Renewal of the Operating License

No. Commitment

FSAR Supp. Location

(LRA App. A)

Implementation

Schedule 

A-10

38 VCSNS is developing a process which will be implemented to capture the

LRA methodology and guidance for use during the period of extendedoperation to satisfy the requirements of 10 CFR 54.35. Existing plantprograms and procedures (associated with aging management) will berevised and/or enhanced to identify those commitments (governed by thelicense / CLB) which cannot be altered without prior review against the LRAcriteria. New “one-time inspection” aging management programs will be

developed in accordance with the LRA, incorporating the commitmentprocess identified above.

N/A - Implementationactivity.

Prior to the end ofthe current operatilicense term.

39 Plant procedures which impact “control of facility changes”, including

modifications and documentation, will be reviewed to determine anacceptable screening review process against the 10 CFR 54 requirements toensure consistency with the LRA methodology and guidance.

N/A Prior to the end of

the current operatilicense term.

40 To support Items 38 and 39 above, a License Renewal DBD will be

developed as a guidance document which can be used for all future plantprocedure, documentation and modification changes to ensure consistencywith 10 CFR 54. 

N/A Prior to the end of

the current operatilicense term.

41 All Technical Reports, which have been developed to substantiate the LRA

submittal, are filed as permanent records and will be available for futurereference and/or update.

N/A Prior to the end of

the current operatilicense term.
B-1

APPENDIX B: CHRONOLOGY

This appendix provides a chronological listing of routine licensing correspondence between the

U.S. Nuclear Regulatory Commission (NRC) staff and South Carolina Electric & Gas Company

(SCE&G) and other correspondence regarding the NRC staff’s review of the Virgil C. Summer

Nuclear Station (VCSNS), for license renewal application (LRA) (Docket Nos. 50-395). 

August 6, 2002 In a letter (signed by S.A. Byrne), SCE&G submitted its LRA for

Virgil C. Summer Nuclear Station to the NRC.

August 20, 2002 In a letter (signed by G.A. Suber), NRC confirmed a telephone

conversation concerning the maintenance of reference material

for the Virgil C. Summer Nuclear Station LRA.

August 26, 2002 In a letter (signed by P. Kuo), NRC informed SCE&G that the

NRC received the Virgil C. Summer Nuclear Station license

renewal application on August 6, 2002, and enclosed a copy of

the notice related to the application that was sent to the Office of

Federal Register for publication.

August 27, 2002 NRC announced the availability of License Renewal Application

for the Virgil C. Summer Nuclear Station. 

September 12, 2002 In a letter, R. Auluck noticed a meeting to provide the NRC staff

an overview of the Virgil C. Summer Nuclear Station LRA, on

September 24, 2003.

September 12, 2002 In a letter SCE&G provided the NRC additional information on 

Section 2 of the Virgil C. Summer Nuclear Station, LRA.

September 27,2002 In a letter (signed by P. Kuo), the NRC informed the SCE&G that

the NRC staff had determinated that SCE&G had submitted

sufficient information that was complete and acceptable for

docketing, proposed review schedule, and opportunity for hearing.

October 23,2002 In a letter (signed by P. Kuo), the NRC informed of its intent to

prepare an Environmental Impact Statement and conduct the

scoping process for the LRA of VCSNS. 

October 24, 2002 In a meeting summary (signed by R. Auluck), NRC summarized

the September 24, 2002, meeting with SCE&G regarding the

VCSNS license renewal application.

November 27, 2002 NRC announced to hold a public meeting on December 11, 2002,

on Summer Nuclear Station License Renewal.
B-2

December 10, 2002 In a letter, R. Auluck announced a forthcoming meeting to discuss

the environmental scoping process for VCSNS License Renewal

Application, on December 11, 2003.

December 11, 2002 In a letter (signed by G. Sober), the NRC provided the handouts

for the meeting, which discuss the environmental scoping process

for the Virgil C. Summer Nuclear Station LRA.

December 12, 2002 In a letter (signed by R. Caruso), NRC requested additional

information (RAI) on Section 15.4.3.2.2 of the Virgil C. Summer

Nuclear Station LRA.

December 12, 2002 In a letter, R. Auluck announced a forthcoming meeting to discuss

staff’s review/draft questions on Section 3.5 of the VCSNS

License Renewal Application, on January 8, 2003.

December 23, 2002 In a letter (signed by R. Auluck), NRC provided the revision of the

schedule for the conduct of review of the VCSNS License

Renewal Application.

January 9, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs on VCSNS License Renewal. 

January 14, 2003 In a meeting summary (signed by G. Suber), NRC summarized

the December 11, 2002 public meeting with SCE&G, to support

review of VCSNS License Renewal Application. 

January 15, 2003 In a letter, R. Auluck announced a forthcoming meeting to

summarize the review of the VCSNS on-site information related to

the scoping and screening methodology used in developing the

VCSNS License Renewal Application, on January 31, 2003.

February 14, 2003 In a letter (signed by D. Thatcher), NRC requested additional

information (RAI) regarding the SCE&G license renewal of the

Virgil C. Summer Nuclear Station.

February 14, 2003 In a letter, R. Auluck announced a forthcoming meeting to discuss

staff’s draft questions on Sections 2.0, 3.1, 3.2, 3.4, and 4.0 of

the VCSNS License Renewal Application and related aging

management programs in Appendix B of the application, on

February 26, 2003.

February 21, 2003 In a letter, R. Auluck announced a forthcoming meeting to discuss

staff’s draft questions on Sections 3.3, 3.4, and Appendix B of the

VCSNS License Renewal Application, on March 5-6, 2003.
B-3

February 27, 2003 In a letter (signed by C.F. Holden), NRC requested additional

information (RAI) on Section 3.6 of the Virgil C. Summer Nuclear

Station LRA.

February 28, 2003 In a meeting summary (signed by R. Subbaratnam), NRC

summarized the January 8, 2003, meeting with SCE&G, to

discuss staff questions on Section 3.5 and 4.5 of the VCSNS

License Renewal Application. 

March 3, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on Section 2.4 “Scoping and Screening ResultsStructures” of the Virgil C. Summer Nuclear Station LRA.

March 4, 2003 NRC presented the Virgil C. Summer Nuclear Station Inspection

Plan for March1, 2003, to March 31, 2004, for the license renewal

March 4, 2003 In a letter (signed by S.A. Weerakkody), NRC requested

additional information (RAI) on Section 2.2, 2.3, 3.3.2, and

Appendix B.1.5 of the Virgil C. Summer Nuclear Station LRA.

March 5, 2003 In a letter (signed by A. Louise Lund), NRC requested additional

information (RAI) on materials related aging management

programs of the Virgil C. Summer Nuclear Station LRA.

March 5, 2003 In a letter (signed by S. Coffin), NRC requested additional

information (RAI) on the aging management of reactor vessel,

internals and reactor coolant system of the Virgil C. Summer

Nuclear Station LRA.

 March 6, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on Sections B1.9, B1.19, B1.25, B1.26, B 2.2,

B2.3, B2.5, B2.6, B2.8, B2.11, and B2.12 of the Virgil C.

Summer Nuclear Station LRA.

March 10, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on Section 3.5 of the Virgil C. Summer Nuclear

Station LRA.

March 11, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on Steam and Power Conversion System of the

Virgil C. Summer Nuclear Station LRA.

March 12, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on Engineered Safety Features System of the

Virgil C. Summer Nuclear Station LRA.
B-4

March 17, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) regarding the time limited aging analyses for the

Virgil C. Summer Nuclear Station LRA.

March 18, 2003 In a letter (signed by K.A. Manoly), NRC requested additional

information (RAI) on auxiliary system for the Virgil C. Summer

Nuclear Station LRA.

March 19, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs regarding Severe Accident Mitigation Alternatives

(SAMA) for the Virgil C. Summer Nuclear Station.

March 28, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) on Section 3.2, 3.3, 3.4, 3.5, and 4.0 and related

Appendix B sections of the Virgil C. Summer Nuclear Station LRA.

March 28, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) on Section 3.1, and related Appendix B sections

of the Virgil C. Summer Nuclear Station LRA.

March 28, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) on Section 2.4, 2.5, 3.6, and 4.0 and related

Appendix B sections of the Virgil C. Summer Nuclear Station LRA.

March 28, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) on Section 2.1, 2.2, 2.3, and 3.3 and related

Appendix B sections of the Virgil C. Summer Nuclear Station LRA.

April 2, 2003 In a letter (signed by M. Browne), NRC requested SCE&G to 

provide to NRC a copy of the modification to the Virgil C. Summer

Nuclear Station National Pollution Discharge Elimination System

(NPDES).

April 9, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) on Section 2.3 of the Virgil C. Summer Nuclear

Station LRA.

April 15, 2003 In a letter (signed by K. Cotton), NRC requested additional

information (RAI) regarding Engineered Safety Features Actuation

System Technical Specifications for the Virgil C. Summer Nuclear

Station.

April 25, 2003 In a letter (signed by C. Carpenter, V. McCree), NRC requested

SCE&G to provide the Virgil C. Summer Nuclear Station License

Renewal Plan.
B-5

May 2, 2003 In a letter, P. E. Fredrickson announced a forthcoming meeting to

present the results of the NRC’s first inspection of the VCSNS

License Renewal Program, on May 16, 2003.

May 9, 2003 In a meeting summary (signed by R. Subbaratnam), NRC

summarized the February 26-27, 2003 and March 5, 2003,

meetings with SCE&G, to discuss the staff’s draft request for

additional information on sections 2.0, 3.1, 3.2, 3.3, 3.4, 4.0 and

Appendix B of the VCSNS License Renewal Application.

May 19, 2003 In a meeting summary (signed by G. F. Suber), NRC summarized

the May 5, 2003, teleconference with SCE&G, to discuss and

clarify certain responses to the RAIs submitted to the NRC by

letter dated March 19, 2003.

May 21, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs regarding Severe Accident Mitigation Alternatives

(SAMAs) for the Virgil C. Summer Nuclear Station.

May 22, 2003 In a letter (signed by P. Kuo), NRC provided to SCE&G the aging

management program audit plan for Virgil C. Summer Nuclear

Station License Renewal.

June 2, 2003 In a letter (signed by R. Auluck), NRC requested additional

information (RAI) as a result of a scoping inspection conducted at

the Virgil C. Summer Nuclear Station during May 12-16, 2003.

June 12, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs for the review of the license renewal application of

the Virgil C. Summer Nuclear Station.

June 13, 2003 In a letter (signed by P. Kuo), NRC provided to SCE&G the Virgil

C. Summer Nuclear Station License Renewal review and the

National Prevention Act.

June 13, 2003 In a letter (signed by V. McCree), NRC provided to SCE&G its

scoping inspection report.

July 17, 2003 In a letter (signed by V. McCree), NRC announced a forthcoming

meeting to present the results of the second inspection of the

VCSNS License Renewal program on August 4-22, 2003.

July 31, 2003 NRC published a draft report for comments, "Generic

Environmental Impacts for License Renewal of Nuclear Plants"

regarding VCSNS.
B-6

July 31, 2003 In a letter (signed by S. Byrne), SCE&G provided to the NRC the

updated application for renewed operating license of the Virgil C.

Summer Nuclear Station.

August 11, 2003 In a telecommunication summary (signed by R. Subbaratnam),

NRC summarized the June 17, 2003, to July 31, 2003, telephone

conversations with SCE&G, to discuss related additional

clarification that the staff needed to complete its safety review of

the VCSNS License Renewal Application.

August 15, 2003 In a letter (signed by G. Suber), NRC announced a forthcoming

meeting on August 26, 2003, to discuss the draft supplemental

environmental impact statement for the VCSNS.

August 18, 2003 In a telecommunication summary (signed by R. Auluck), NRC

summarized the May 27, June 26 and August 7, 2003, telephone

conversations with SCE&G, to discuss applicant’s response to

various staff requests for additional information for the VCSNS

License Renewal Application Review.

September 2, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs for the review of the license renewal application of

the Virgil C. Summer Nuclear Station.

September 24, 2003 In a letter (signed by S. Byrne), SCE&G provided its response to

the NRC RAIs for the review of the license renewal application of

the Virgil C. Summer Nuclear Station.

September 29, 2003 In a letter (signed by V. McCree), NRC provided to SCE&G its

aging management review inspection report.

October 3, 2003 In a telecommunication summary (signed by R. Subbarantnam),

NRC summarized the September 2, 15, 16, 17, and 19, 2003,

telephone conversations with SCE&G, to discuss staff questions

on 10 CFR 54.4(a)(2) criteria and applicant’s responses to the

NRC RAIs for the review of the license renewal application of the

Virgil C. Summer Nuclear Station.

October 9, 2003 In a letter (signed by R. Auluck), NRC provided to SCE&G its

aging management program audit report.

November 5, 2003 In a letter (signed by S. Byrne), SCE&G provided comments on

the Safety Evaluation Report related to the License Renewal of

the Virgil C. Summer Nuclear Station.
C-1

APPENDIX C: REFERENCES

This appendix contains a listing of references used in the preparation of the Safety Evaluation

Report prepared during the review of the license renewal application for VCSNS, Docket

Number 50-395.

American Society of Mechanical Engineers (ASME)

ASME Boiler and Pressure Vessel Code, Section III, Subsection NB, Class 1 Components.

ASME Boiler and Pressure Vessel Code, Section III, Subsection NG, Core Support Structures.

ASME Boiler and Pressure Vessel Code, Section III, Class 2 and 3 Piping Failures.

ASME Boiler and Pressure Vessel Code, Section III, Subsection ND, Class 3 Rules for

Construction of Nuclear Power Plant Components. 

ASME Boiler and Pressure Vessel Code, Section XI, Rules for Inservice Inspection of Nuclear

Power Plant Components, 1992 Edition.

ASME Boiler and Pressure Vessel Code, Section XI, Rules for Inservice Inspection of Nuclear

Power Plant Components, 1989 Edition.

ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWB, Requirements for 

Class 1 Components of Light-Water Cooled Power Plants.

ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWC, Requirements for 

Class 2 Components of Light-Water Cooled Power Plants.

ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWE, Requirements for Class

MC and Metallic Liners of Class CC Components of Light-Water Cooled Power Plants.

ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWF, Requirements for Class

1, 2, 3, and MC Component Supports of Light Water Cooled Plants.

ASME Boiler and Pressure Vessel Code, Section XI, Appendix G, Fracture Toughness Criteria

for Protection Against Failure.

ASME Boiler and Pressure Vessel Code, Code Case N-481, Alternative Examination

Requirements for Cast Austenitic Pump Casings, Section XI, Division 1.

ANSI B30.16, Overhead Hoists (Underhung), American National Standard.

ANSI B30.2.0, Overhead and Gantry Cranes, Section 2-2, Safety Standards for Cableways,

Cranes, Derricks, Hoists, Hooks, Jacks, and Slings, American National Standard.

Department of Energy - National Laboratories
C-2

Sandia Contractor Report SAND96-0344, Aging Management Guideline for Commercial

Nuclear Power Plants - Electrical Cable and Terminations, Prepared by Ogden Environmental

and Energy Services, Inc., printed September 1996.

SAND 93-7069, Aging Management Guideline for Commercial Nuclear Power Plants - Motor

Control Centers, February 1994.

SAND 93-7027, Aging Management Guideline for Commercial Nuclear Power Plant - Electrical

Switchgear.

Electric Power Research Institute (EPRI) and Materials Reliability Program (MRP)

EPRI Report TR-105714, Volumes 1, Revision 4, and Volume 2, Revision 4 PWR Primary

Water Chemistry Guidelines, January 1999.

EPRI Report TR-102134, Revision 5, PWR Secondary Water Chemistry Guidelines, 

December 1999.

EPRI Report TR 107621, Revision 1, Steam Generator Examination Guidelines, 

September 1997.

EPRI Report NSAC-202L, Revision 2, Recommendations for an Effective Flow Accelerated

Corrosion Program, December 1998.

EPRI Report TR-103834-P1-2, Effects of Moisture on the Life of Power Plant Cables, Part 1:

Medium-Voltage Cables, Part 2: Low-Voltage Cables, prepared by Ogden Environmental and

Energy Services Company, Final Report, August 1994

EPRI Report TR-10003057, License Renewal Electrical Handbook, November 2001.

EPRI Report TR-107396, Closed Cooling Water Chemistry Guidelines, October 1997.

EPRI Report TR-109619, Guideline for the Management of Adverse Localized Equipment

Environment, June 1999.

EPRI Report TR-1003083, Materials Reliability Program Guidelines for Addressing Fatigue

Environmental Effects in a License Renewal Application (MRP-47), October 2001.

MRP Topical Report TP-1001491, Part 2, PWR Materials Reliability Program Interim Alloy 600

Safety Assessment for US Power Plants (MRP-44), May 2001.

Miscellaneous

Aging and Life Extension of Major Light Water Reactor Components, edited by V.N. Shah and

P.E. MacDonald, 1993, Elsevier Science Publishers.

American Concrete Institute, ACI 349.3, Evaluation of Existing Nuclear Safety-Related

Concrete Structures.
C-3

American Concrete Institute, ACI 224.1, Causes, Evaluation, and Repairs of Cracks in Concrete

Structures.

American Concrete Institute, ACI 201, Guide for Making a Condition Survey of Concrete in

Service.

NRC Inspection Procedure 62002, Inspection of Structure, Passive Components, and Civil

Engineering Features at Power Plants, December 1996.

NRC SECY 96-080, Issuance of Final Amendment to 10 CFR 50.55a to incorporate by

reference the ASME Boiler and Pressure Vessel Code (ASME CODE), Section XI, Division 1,

Subsection IWE and Subsection IWL, April 17, 1996.

Nuclear Energy Institute (NEI)

NEI 95-10, Revision 2, Industry Guideline for Implementing the Requirements of 10 CFR Part

54 - The License Renewal Rule, Nuclear Energy Institute, August 2000.

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

54 - The License Renewal Rule, Nuclear Energy Institute, March 2001.

NEI 97-06, Steam Generator Program Guidelines, 1997.

NEI 96-03, Industry Guideline for Monitoring Structures.

Nuclear Management and Resources Council (NUMARC)

Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light

Water Reactors, NUMARC Report Number 87-00, November 1987.

Pressurized Water Reactor Containment Structures License Renewal Industry Report,

NUMARC Report Number 90-01, Nuclear Management and Resources Council, Revision 1,

September 1991.

Class I Structures License Renewal Industry Report, NUMARC Report Number 90-06, Nuclear

Management and Resources Council, Revision 1, December 1991.

US Nuclear Regulatory Commission (NRC)

Bulletins (BL)

BL 88-09, Thimble Tube Thinning in Westinghouse Reactors, July 26, 1988.

BL 2001-001, Circumferential Cracking of Reactor Pressure Vessel Head Penetration Nozzles,

August 3, 2001.

BL 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure

Boundary Integrity, March 18, 2002.
C-4

BL 2002-02, Reactor Pressure Vessel Head and Vessel Head Penetration Nozzle Inspection

Programs.

BL 82-02, Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of

PWR Plants, June 2, 1982.

BL 88-11, Pressurizer Surge Line Thermal Statification, December 20, 1988.

Code of Federal Regulations ( 10 CFR)

10 CFR 50.36, Technical Specifications, U.S. Nuclear Regulatory Commission.

10 CFR 50.48, Fire Protection, U.S. Nuclear Regulatory Commission.

10 CFR 50.49, Environmental Qualification of Electric Equipment Important to Safety for

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

10 CFR 50.55a, Codes and Standards, U.S. Nuclear Regulatory Commission.

10 CFR 50.61, Fracture Toughness Requirements for Protection Against Pressurized Thermal

Shock Events, U.S. Nuclear Regulatory Commission.

10 CFR 50.62, Requirements for Reduction of Risk from Anticipated Transients without Scram

(ATWS) Events for Light-water-cooled Nuclear Power Plants, U.S. Nuclear Regulatory

Commission.

10 CFR 50.63, Loss of All Alternating Current Power, U.S. Nuclear Regulatory Commission

10 CFR 50.90, Application for Amendment of License or Construction Permit, U.S. Nuclear

Regulatory Commission.

10 CFR 50 Domestic Licensing of Production and Utilization Facilities, U.S. Nuclear Regulatory

Commission.

10 CFR Part 50, Appendix G, Fracture Toughness Requirements, U.S. Nuclear Regulatory

Commission.

10 CFR Part 50, Appendix H, Reactor Vessel Material Surveillance Program Requirements,

U.S. Nuclear Regulatory Commission.

10 CFR Part 51, Environmental Protection Regulation for Domestic Licensing and Related

Regulatory Functions, U.S. Nuclear Regulatory Commission.

10 CFR Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants,

U.S. Nuclear Regulatory Commission.

10 CFR 100, Reactor Site Criteria, U.S. Nuclear Regulatory Commission.
C-5

10 CFR Part 100, Appendix A, Seismic and Geological Siting Criteria for Nuclear Power Plants,

U.S. Nuclear Regulatory Commission.

29 CFR Chapter XVII, 1910.179, Overhead and Gantry Cranes, Occupational Safety and

Health Administration. 

Correspondence

Letter from C. I. Grimes (NRC) to D. J. Walters (NEI), License Renewal Issue No. 98-0030,

Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components, May 19, 2000.

Letter from W. T. Russell (NRC) to W. Rasin (NUMARC, [NEI]), Safety Evaluation for Potential

Reactor Vessel Head Adaptor Tube Cracking, November 19, 1993.

Letter from C. I. Grimes (NRC) to D. J. Walters (NEI), License Renewal Issue No. 98-0012,

Consumables, April 20, 1999.

Inspection Reports

V.C. Summer Nuclear Station - NRC Inspection Report No. 50-395/03-07, June 13, 2003.

V.C. Summer Nuclear Station - NRC Inspection Report No. 50-95

National Fire Codes 1979

National Fire Protection Association (NFPA), Standard for Installation of Centrifugal Fire

Pumps, June 1978.

National Fire Protection Association (NFPA), Standard for the Inspection, Testing, and

Maintenance of Water-Based Fire Protection Systems, 1998. 

Generic Letters (GL)

GL 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components In

PWR Plants, March 17, 1988.

GL 97-01, Degradation of Control Rod Drive Mechanism Nozzle and Other Vessel Closure 

Head Penetrations, April 1, 1997. 

GL 97-06, Degradation of Steam Generator Internals, December 30, 1997.

GL 89-13, Service Water System Problems Affecting Safety-Related Equipment, July 18, 1989.

GL 96-04, Boraflex Degradation in Spent Fuel Pool Storage Racks, June 26, 1996.

Information Notices (IN)

IN 87-44, Thimble Tube Thinning in Westinghouse Reactors, September 16, 1987.
C-6

IN 2001-05, Through-Wall Circumferential Cracking of Reactor Pressure Vessel Head Control

Rod Drive Mechanism Penetration Nozzles at Oconee Nuclear Station, Unit 3, April 30, 2001.

IN 87-49, Deficiencies in Outside Containment Flooding Protection, October 9, 1987.

IN 97-45, Supplement 1:Environmental Qualification Deficiency for Cables and Containment

Penetration Pigtails, February 17, 1998.

Technical Reports

NUREG/CR-1437, Supplement 15, Generic Environmental Impact Statement for License

Renewal of Nuclear Plants Regarding V.C. Summer Nuclear Station, July 2003.

NUREG/CR-1557, Summary of Technical Information and Agreements From Nuclear

Management and Resources Council Industry Reports Addressing License Renewal, October

1996.

NUREG-1611, Aging Management of Nuclear Power Plant Containments for License Renewal,

September 1997.

NUREG/CR-1723, Safety Evaluation Report Related to the License Renewal of Oconee

Nuclear Station, Unit 1, 2 and 3, March 2000.

NUREG/CR-1739, Analysis of Public Comment on the Improved License Renewal Guidance

Documents, July 2001. 

NUREG-1760, Aging Assessment of Safety-Related Fuses Used in Low- and Medium-Voltage

Applications in Nuclear Power Plants, May 2002.

NUREG/CR-1800, Standard Review Plan for Review of License Renewal Applications for

Nuclear Power Plants, July 2001.

NUREG/CR-1801, Generic Aging Lessons Learned (GALL) Report, July 2001.

NUREG/CR-4652, Report on Aging of Nuclear Power Plant Reinforced Concrete Structures.

NUREG/CR-4715, An Aging Assessment of Relay and Circuit Breakers and System

Interactions, June 1987.

NUREG/CR-5576, Survey of Boric Acid Corrosion of Carbon Steel Components in Nuclear

Plants, June 1990.

NUREG/CR-5704, Curves of Austenitic Stainless Steel, April 1999. 

NUREG/CR-6048, Pressurized-Water Reactor Internals Aging Degradation Study,

September 1993.

NUREG/CR-6177, Assessment of Thermal Embrittlement of Cast Stainless Steels.
C-7

NUREG/CR-6260, Application of NUREG/CR 5999 Interim Fatigue Curves to Selected Nuclear

Power Plant Components, March 1995.

NUREG/CR-6424, Report on Aging of Nuclear Power Plant Reinforced Concrete Structures, .

NUREG/CR-6583, Effects of LWR Coolant Environment on Fatigue Design Curves of Carbon

and Low Alloy Steel, March 1998. 

NUREG/CR-6679, Assessment of Age-Related Degradation of Structures and Passive

Components for U.S. Nuclear Power Plants, August 2000.

NUREG/CR-6754, Review of Industry Responses to NRC Generic Letter 97-06 on Degradation

of Steam Generator Internals, December 2001.

Regulatory Guides (RG)

RG 1.43, Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components, May 1973.

RG 1.44, Control of the Use of Sensitized Stainless Steel, May 1973.

RG 1.45, Reactor Coolant Pressure Boundary Leakage Detection Systems, May 1973.

RG 1.52, Design Testing and Maintenance Criteria for Post Accident Engineered-SafetyFeature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled

Nuclear Power Plants, July 1978.

RG 1.89, Environmental Qualification of Certain Electrical Equipment Important to Safety for

Nuclear Power Plant, June 1984. 

RG 1.99, Revision 2, Radiation Embrittlement of Reactor Pressure Vessel Materials, May 1988.

RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants, March

1978.

RG 1.147, Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, May

1999.

RG 1.155, Station Blackout, August 1988.

RG 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2,

March 1997.

RG 1.163, Performance-Based Containment Leak-Test Program, September 1995.

RG 1.188, Standard Format and Content for Applications to Renew Nuclear Power Plant

Operating Licenses, July 2001.
C-8

RG 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron

Fluence, March 2001.

Westinghouse Topical Reports (WCAP)

WCAP-10456, The Effects of Thermal Aging on Structural Integrity of Cast Stainless Steel

Piping for Westinghouse Nuclear Steam Supply Systems, November 1983. 

WCAP-12866, Bottom Mounted Instrumentation Flux Thimble Wear, 1991.

WCAP-14535A, Topical Report on Reactor Coolant Pump Flywheel Inspection Elimination,

November 1996.

WCAP-14574, License Renewal Evaluation: Aging Management Evaluation for Pressurizers.

WCAP-14574-A, License Renewal Application: Aging Management Evaluation for

Pressurizers, December 2000.

WCAP-14575-A, Aging Management Evaluation for Class 1 Piping and Associated Pressure

Boundary Components, August 1996.

WCAP-14577, Revision 1-A, License Renewal Application: Aging Management Evaluation for

Reactor Internals, March 2001.

WCAP-14901, Revision 0, Background and Methodology for Evaluation of Reactor Vessel

Closure Head Penetration Integrity for the Westinghouse Owners Group, July 1997.
D-1

APPENDIX D: PRINCIPAL CONTRIBUTORS

NAME RESPONSIBILITY

R. Auluck Sr. Project Manager

F. Akstulewicz Management Supervision

T. Chan Management Supervision

P. Y. Chen Technical Support

S. Coffin Management Supervision

K. Corp Program Support

K. Coyne Quality Assurance

Z. Cruz Technical Support 

B. Elliot Materials Engineering

J. Fair Mechanical Engineering

G. Georgiev Materials Engineering

J. Guo Plant Systems

A. Hodgdon Legal Counsel

N. Iqbal Fire Protection

D. Jeng Mechanical Engineering

R. Jenkins Management Supervision

S. Jones Plant Systems

C. Julian Region II Inspector

M. Khanna Materials Engineering

J. Knox Electrical Engineering

P.T. Kuo Management Supervision

C. Lauron Chemical Engineering

A. Lee Mechanical Engineering

S. Lee Management Supervision

M. Lemoncelli Legal Counsel

Y. Li Mechanical Engineering

L. Lund Management Supervision

J. Ma Mechanical Engineering

K. Manoly Management Supervision

M. Matrzman Civil Engineering

S. Mirando Reactor Systems

C. Munson Civil Engineering

D. Nguyen Electrical Engineering

Q. Nguyen Technical Support

K. Parcheski Chemical Engineering

R. Pettis Quality Assurance

J. Pulsipher Plant Systems

J. Rajan Civil Engineering

J. Raval Plant Systems

D. Shum Plant Systems

J. Strnisha Mechanical Engineering

R. Subbaratnam Project Manager

D. Terao Management Supervision

D. Thatcher Management Supervision
D-2

J. Tsao Materials Engineering

H. Wagage Plant Systems

H. Wang Civil Engineering

S. Weerakkady Management Supervision

C. Wu Mechanical Engineering

CONTRACTORS

Contractor Laboratory

J. Braverman Brookhaven National Laboratory

D. Diercks Argonne National Laboratory

C. Hofmayer Brookhaven National Laboratory

A. Hull Argonne National Laboratory

Z. Li Argonne National Laboratory

Y. Liu Argonne National Laboratory

D. Ma Argonne National Laboratory

R. Morante Brookhaven National Laboratory

D. Raske Argonne National Laboratory

V. Shah Argonne National Laboratory

S. Tam Argonne National Laboratory